L-06-065, 2005 Annual Report for Firstenergy Corp; Retrospective Premium Guarantee

2005 Annual Report for Firstenergy Corp; Retrospective Premium Guarantee

ML061090054
Person / Time
Site:	Beaver Valley, Davis Besse, Perry
Issue date:	04/06/2006
From:	Scilla R FirstEnergy Corp
To:	Dinitz I Office of Nuclear Reactor Regulation
References
BV-No. L-06-065, DB-Serial No.-3255, PY-CEI/NRR-2955L
Download: ML061090054 (89)

Text

p FArstEnergy. 76 South Main Street Akmron.

OhFin o.fj e Randy Scills 330-384-5202 Assisrani Treasurer Fsx: J3C-3zV-3_;,

April 6, 2006 PY-CEIINRR-2955L DB-Serial No.-3255 BV-No. L-06-065 Mr. Ira Dini tz U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Washington, D.C. 20555 Dear Mr. Dinitz; Re: Docket Nos. 50-346, 50-440, 50412, 50-334 Retrospective Premium Guarantee Enclosed you will find the 2005 FirstEnergy Corp.. Annual Report.. This is in addition to the 2006 Internal Cash Flow Projection sent February 17, 2006 and completes the requirements for the Retrospective Premium Guarantee.

Very truly yours, JA0o['

I' Contents 2 Message to Shareholders 6 Chairman's Message 6 Directors 8 Officers 9 Glossary of Terms 10 Management Reports 11 Report of Independent Registered Public Accounting Firm 12 Selected Financial Data 43 Management's A - .-

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(Dollars in millions, except per share amounts) 2005 2004 Total revenues $11,989 $12,060 Income before discontinued operations and cumulative effect of accounting change* $ 873 $ 896 Net income $ 861 $ 878 Basic earnings per common share:

Before discontinued operations and cumulative effect of accounting change $ 2.66 $ 2.74 After discontinued operations and cumulative effect of accounting change $ 2.62 $ 2.68 Diluted earnings per common share:

Before discontinued operations and cumulative effect of accounting change $ 2.65 $ 2.73 After discontinued operations and cumulative effect of accounting change $ 2.61 $ 2.67 Dividends paid per common share* $ 1.67 $ 1.50 Book value per common share $ 27.98 $ 26.20 Net cash from operations $ 2,220 $ 1,892

• The2005 and2004 discanbnuedoperatons are desaibedin Note 2(J) to the consohdatedfinandalstatements e 2005 accounting change isdescibedin Note 2(K.

1. A quartedy dividend of $0.45 was paid on March 1,2006, increasing the indicated annual dhddend rate to S1.80 pershare The following analysis reconciles basic earnings per share of common stock in 2005 and 2004 computed under generally accepted accounting principles (GAAP) to adjusted basic earnings per share excluding unusual items in both years (non-GAAP) *.

2005 2004 Adjusted basic earnings per share:

Basic earnings per share (GAAP) $2.62 $2.68 Cumulative effect of accounting change .09 -

Ohio/New Jersey income tax adjustments .19 -

EPA settlement .04 -

Davis-Besse DOJ penalty and NRC fines .10 -

JCP&L arbitration decision .03 -

JCP&L rate settlement (.05) -

Non-core asset sales/impairments (.02) .19 Davis-Besse extended outage impacts - .12 Class-action lawsuit settlement - .03 Other - .01 Adjusted basic earnings per share (non-GAAP*) $3.00 $3.03

• Generally a non-GAAPfinancialmeasure isa numeyical measure of ccompany's historical or future finandolperformance, financial position, or cash flows that eitherexcludes or includes amounts or issubject to adjustment that hove the effect of excluding or including amounts, that are not normafly excluded or included in the most diretty comparable measure calculated and presented inaccordance with accounting prnciples generall accepted in the United States, or GLW Forward-Looking Statements This annual report includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms 'anticipate,' 'potential' 'expect,' 'believe,' 'estimate' and similar words.Actual results may differ materially due to the speed and nature of increased competition and deregulation inthe electric utility industry, economic or weather conditions affecting future sales and margins, changes inmarkets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, the continued ability of our regulated utilities to collect transition and other charges or to recover increased transmission costs maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), the repeal of the Public Utility Holding CompanyAct of 1935 and the legal and regulatory changes resulting from the implementation of the Energy Policy Act of 2005, the uncertainty of the timing and amounts of the capital expenditures (including that such amounts could be higher than anticipated) or levels of emission reductions related to the settlement agreement resolving the New Source Review litigation, adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits fines or other enforcement actions and remedies) of governmental investigations and oversight, including by the Securities and Exchange Commission, the United States Attorneys Office, the Nuclear Regulatory Commission and the various state public utility commissions as disclosed in our Securities and Exchange Commission filings, generally, and with respect to the Davis-Besse Nuclear Power Station outage and heightened scrutiny at the Perry Nuclear Power Plant inparticular, the timing and outcome of future rate proceedings inPennsylvania, the continuing availability and operation of generating units, the ability of our generating units to continue to operate at, or near full capacity, our inability to accomplish or realize anticipated benefits from strategic goals (including employee workforce factors), the anticipated benefits from our voluntary pension plan contributions, our ability to improve electric commodity margins and to experience growth inthe distribution business, our ability to access the public securities and other capital markets and the cost of such capital, the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to theAugust 14, 2003 regional power outage, circumstances which may lead management to seek, or the Board of Directors to grant ineach case in its sole discretion, authority for the implementation of a shame repurchase program inthe future, the risks and other factors discussed from time to time in our Securities and Exchange Commission filings, and other similar factors. Dividends declared from time to time during any annual period may in aggregate vary from the indicated amounts due to circumstances considered by the Board at the time of the actual declarations. Also, a security rating should not be viewed as a recommendation to buy, sell or hold securities and it may be subject to revision or withdrawal at any time. We expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events or otherwise.

A A' I We made solid progress in 2005 and continued to position your Company for success in the years ahead.

Our key accomplishments included:

• Increasing our common stock dividend payment by 14.7 percent;

• Achieving an investment-grade credit rating from Standard & Poor's for all of our debt and completing our debt-reduction program;

• Producing record electricity output from our generating units;

• Enhancing our reliability and customer service; and

• Gaining approval for our Rate Certainty Plan in 6'Based on Ohio and for our generation asset transfer.

the Company's These and other accomplishments reflect our performance, your overall strategy, which is focused on reinvesting in our business and continuous improvement. For example, Board of Directors we are upgrading our transmission and distribution increased the system to improve service reliability; implementing new technologies and industry best practices to provide common stock more responsive customer service; increasing generating capacity and maximizing the efficient utilization of our dividend payment plants as we prepare for fully deregulated markets in Ohio and Pennsylvania; and maintaining an unwavering by 14.7 percent."5 focus on safety. These actions will help enhance the long-term value of your investment in FirstEnergy.

Solid Financial Results Our financial performance in 2005 was strong, particularly in the key areas of earnings, cash flow and debt reduction.

We produced four quarters of solid financial results, ending the year with basic earnings per share of $3.00 on a non-GAAP* basis, which reached the top of our 2005 guidance to the financial community of $2.85 to $3.00 per share. Net cash from operations increased to $2.2 billion - up from $1.9 billion in 2004. We also reduced our debt-to-capitalization ratio

to approximately 56 percent, bringing this We're also installing new technologies that will important metric to within our target range. In benefit customer service and system performance. For addition, we successfully completed the $4-billion example, our engineers developed a new storm-detec-debt-reduction program we started four years ago tion system to help safeguard distribution equipment and regained our investment-grade credit rating for during severe weather. The system automatically all of our debt. switches equipment during storms to protect key We delivered a total return to investors - components from lightning and high winds. As a pilot a measure of stock price appreciation plus reinvested project, we installed about 40 of these devices throughout dividends - of 28.5 percent in 2005. And, our five-year our service area, and expect to move forward with annualized total return ranks us 7th among the 64 full-scale implementation this year. These and other U.S. investor-owned electric utilities that comprise improvements are designed to reduce the frequency the Edison Electric Institute's (EEI) index. and duration of outages - as well as the number of The increase in our stock price during 2005 added customers affected when outages do occur.

more than $3 billion of value to shareholders. Our Additionally, we completed a major renovation performance led your Company to be named to the of our transmission system control center in Ohio, Forbes Platinum 400, also known as the list of and we are in the process of rebuilding and "America's Best Big Companies." consolidating distribution system control centers.

Based on the Company's performance, your Board Our commitment to customer service received of Directors increased the common stock dividend national recognition in February 2006, when we were payment by 14.7 percent. The Board also authorized named a recipient of EEI's Customer Service Award our subsidiaries to make a voluntary contribution for being ranked among the top five electric companies totaling $500 million to the pension plans in late by the country's leading retail chains.

2005. While the pension contribution is expected to On the generation front, we continued to optimize be accretive to earnings, it also increases the security the performance of our plants. We set a total production of future plan benefits and represents a major record of 80.2 million megawatt-hours (MWH),

investment in our employees and retirees. surpassing the previous record set in 2004 by nearly 4 million MWH. Our coal-based generation fleet led Operational Improvements the way with a record 49.9 million MWH, and our In 2005, we took steps to improve our customer nuclear fleet produced 28.7 million MWH.

service and reliability. We launched our Accelerated Our baseload fossil plants achieved a top-decile Reliability Improvement Program - a five-year, capacity factor for the year. And, Unit 2 at our

$600-million effort that involves replacing and 2,233-megawatt (MW) W. H. Sammis Plant reached upgrading equipment on our transmission and 1,017 days of continuous operation, setting a national distribution systems. These systemwide infrastructure record for any single-boiler turbine generating unit.

improvements will enhance overall reliability at our At our largest coal-based facility, the 2,410-MW utility companies well into the future. Bruce Mansfield Plant, we initiated a program to In addition to spending about $150 million in upgrade Unit l's turbine and scrubber system -

2005 on these types of improvements, we ordered boosting net demonstrated capacity by about 50 MW 431 new vehicles - part of a multiyear fleet upgrade while reducing emissions. Similar projects are slated of more than 1,500 new vehicles - to ensure that our for units 2 and 3 in the future. Together, these projects workforce has the equipment needed to get the job will provide enough capacity to increase the plant's done safely and efficiently. output by up to 900,000 MWH annually.

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Our nuclear fleet also made solid progress in an OSHA rate of 0.41 2005. Davis-Besse returned to the standard Nuclear incidents per 100 employees.

Regulatory Commission oversight process in July. We We are especially proud also closed an important chapter on the Davis-Besse of our employees at Toledo reactor head issue in January 2006, when we entered Edison, who worked the entire year with only one into a deferred prosecution agreement with the U.S. incident and achieved an OSHA rate of 0.26, a best-ever Attorney's Office and the U.S. Department ofJustice. rate for one of our operating companies.

We strengthened our nuclear management team and enhanced our fleet-management practices - steps Protecting the Environment designed to maintain a strong focus on nuclear safety As one of the nation's leading energy companies, and to achieve continued operational success. we are committed to help protect the environment As a result of our performance, the nuclear fleet while meeting our customers' need for safe, reliable garnered several awards and honors during the year. electricity. We're proud of the progress we've made in For example, Davis-Besse was recognized by the World this key area. In 2005, more than 60 percent of the Association of Nuclear Operators for achieving the electricity we produced came from our non-emitting lowest radiation exposure among all U.S. pressurized nuclear fleet and scrubber-equipped units at our water reactors. And recently, Beaver Valley was awarded Mansfield Plant.

the 2005 World Class ALARA Performance Award by In one of our most ambitious projects to further an international organization that tracks radiological reduce emissions, we have begun a multiyear installation exposure to employees at nuclear plants (ALARA is of state-of-the-art air quality control systems at our an acronym referring to keeping exposure as low as Sammis Plant. This five-year project will cost approxi-reasonably achievable). mately $1.5 billion and should allow for continued For the year, Beaver Valley and Davis-Besse use of this essential asset for many years.

operated at better than 90-percent capacity factors, Over the next five years, FirstEnergy also expects and our entire nuclear fleet averaged a 100-percent to spend approximately $50 million on efforts to reduce capacity factor during the months of June through greenhouse-gas (GHG) emissions, ranging from partici-December. Our fleet performance should further pation in the Global Roundtable on Climate Change, to benefit from the completion of a major steam partnerships with industry and government groups to generator and reactor vessel head replacement develop technologies for GHG reduction, carbon-dioxide this year at Beaver Valley Unit 1, the most substantial (CO2) capture and storage, and advanced generation.

construction project at this unit since it was built We're building on our leadership role in testing in the 1970s. We also expect to complete nuclear and developing environmental technologies. For plant capacity uprates between 2006 and 2009 that example, we plan to install an Electro-Catalytic would add up to 156 MW to our non-emitting Oxidation (ECOO) system, developed through our generating capacity. partnership with Powerspan Corp., at our Bay Shore Safety remains a top priority - both within our Plant in Oregon, Ohio. ECO, a multipollutant control nuclear fleet and across our organization. We continued technology for coal-based plants, is currently being our efforts to strengthen the safety culture at all our demonstrated at our R. E. Burger Plant. Design nuclear facilities. We also achieved a Companywide engineering on the $125-million Bay Shore ECO Occupational Safety and Health Administration system will begin this summer. Further development (OSHA) rate of 1.23 incidents per 100 employees in and testing will help determine whether ECO 2005, a 17-percent reduction compared with 2004, technology can be used to capture C02.

when our performance ranked just short of the top We plan to seek renewal of our licenses for nuclear decile in our industry. Our fossil fleet posted an OSHA and hydroelectric facilities. And, we have contracted rate of 0.96 incidents per 100 employees, a 90-percent to acquire additional wind power generation output, reduction from 2004, and our nuclear fleet recorded bringing the total we will have available to 360 MW.

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aWe set a total production record of 80.2 million And, it addresses corporate separation provisions of electric deregulation laws in both states.

megawatt-hours (MWH),

Addressing Our Workforce Needs surpassing the previous Over the next several years, we anticipate record set in 2004 by hiring thousands of new employees to offset expected attrition as a significant portion of our workforce nearly 4 million MWH.99 approaches retirement age. To support this process, we've established hiring goals for each business unit, expanded recruiting initiatives, and enhanced All of these strategic investments are designed to programs for introducing new employees to the support our environmental programs, and where Company. We're also focusing on ways to retain practical, increase generating capacity. our dedicated, hardworking veterans.

We also produced an Air Issues Report to share- In addition, we've developed a number of programs holders that provides a comprehensive assessment designed to help employees better understand our of our past environmental performance as well as key strategies and goals. These programs enhance our future risks and mitigation efforts. FirstEnergy is teamwork and provide employees with opportunities better positioned than many electricity providers to for personal development and advancement.

operate in a carbon-constrained environment because of our diverse generation mix. The report is available on Positioned for Success our Web site at www.firstenergycorp.com/environmental. Your Company built on the achievements of recent years and delivered on goals established for 2005. With Building on Our Momentum the ongoing efforts and expertise of our employees and We took an important step toward strengthening your continued support, I look forward to achieving our financial stability with the Rate Certainty Plan greater success in the years ahead.

(RCP), which essentially maintains current electricity prices in Ohio through 2008. Sincerely, The RCP enables us to collect certain fuel cost increases and to defer for future recovery certain other fuel and distribution-related expenses during the plan's term. While keeping electricity prices stable for our customers, the RCP provides us with more ANTHONY J. ALEXANDER predictable revenues. Presidentand Chief Executive Officer Also during the year, the New Jersey Board of Public Utilities approved settlement agreements involving March 20,2006 rate filings, which had a positive impact on earnings.

And, we intend to file a comprehensive rate proceeding during 2006 to address revenue requirements in

• This letter to shareholders contains a reference to non-GAAP basic earnings per share. This non-GAAP measure excludes amounts that Pennsylvania.

are included in the most directly comparable measure calculated and We also successfully completed an intra-system presented in accordance with accounting principles generally accepted transfer of both nuclear and non-nuclear generation in the United States (GAAP). A reconciliation of 2005 GAAP basic earnings per share of $2.62, to 2005 non-GMP basic earnings per assets from our Ohio companies and Penn Power share of $3.00, displaying the unusual items resulting in the difference to separate, wholly owned generating company between GAAP basic earnings per share and non-GAAP basic earnings subsidiaries. This transfer enhances our flexibility per share, can be found in the accompanying Managements Discussion as both Ohio and Pennsylvania move toward the and Analysis of Results of Operations and Financial Condition on page 13.

end of their respective market development periods.

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a t\.Xn behalf of your Board of the Corporate Governance I of Directors, I would like to Quotient developed by congratulate our management Institutional Shareholder Services.

and employees for another On a personal note, I join successful year. the Board in expressing our Based on the Company's appreciation to Robert N. Paul T. Addison, 59 strong operational and financial Pokelwaldt, PaulJ. Powers, and Retired, formerly Managing Director in performance, your Board voted Dr. Patricia K. Woolf, whose the Utilities Department of Salomon Smith Barney (Citigroup). Member, to increase the common stock terms as Directors will end with Audit and Finance Committees. Director dividend payment twice in 2005, the 2006 Annual Meeting. We of FirstEnergy Corp. since 2003.

for a total increase of 14.7 are indebted to them for their percent. With the dividend leadership and counsel during Anthony J. Alexander, 54 increases and stock appreciation, their combined 43 years of service President and Chief Executive Officer of your Company delivered a to your Board and Company. FirstEnergy Corp. Director of FirstEnergy very favorable total shareholder Also, we welcome back Corp. since 2002.

return of 28.5 percent last Robert B. "Yank" Heisler, Jr.,

year, approaching top-decile who was elected to the Board in Dr. Carol A. Cartwright, 64 performance among the February. Yank is chairman of President, Kent State University. Chair, 64 member companies that make KeyBank N.A., chief executive Corporate Governance Committee; Member, Compensation Committee.

up the Edison Electric Institute's officer of the McDonald Director of FirstEnergy Corp. since 1997 (EEI) index. We've been Financial Group, and executive and of Ohio Edison from 1992-1997.

a consistent performer in this vice president of KeyCorp. He key metric, producing a five-year previously served on your Board William T. Cottle, 60 annualized total shareholder between 1998 and 2004. Retired, formerly Chairman of the return of 14 percent, which Thank you for your trust Board, President and Chief Executive ranks us 7th in the EEI index. and confidence. Your Board Officer of STP Nuclear Operating Given our confidence in the will continue to work with Company. Chair, Nuclear Committee; Company's future prospects, we management to ensure that your Member, Corporate Governance also approved a third dividend interests remain well-represented. Committee. Director of FirstEnergy increase in November, which Corp. since 2003.

was paid to shareholders of Robert B. Heister, Jr., 57 record in March 2006. Taken Sincerely, Chairman of the Board of KeyBank together, these actions raised N.A., Chief Executive Officer of the the annual dividend from $1.50 McDonald Financial Group, and to $1.80 per share - a 20-percent Executive Vice President of KeyCorp.

increase since November 2004. Member, Compensation and Finance In the important area of Committees. Director of FirstEnergy corporate governance, your GEORGE M. SMART Corp. from 1998-2004 and since Board remained focused on Chairmanof the Board February 2006.

ensuring that we have the appropriate practices in place Russell W. Maier, 69 and that our Company maintains President and Chief Executive Officer the highest ethical standards. of Michigan Seamless Tube LLC.

Chair, Audit Committee; Member, Our corporate governance Compensation Committee. Director practices and policies continue of FirstEnergy Corp. since 1997 and to place us in the top quartile of Ohio Edison from 1995-1997.

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Paul T Addison Anthony J. Alexander Dr. Carol A. Cartwright William T Cottle Robert B. Heisler, Jr.

Ernest J. Novak, Jr., 61 Retired, formerly Managing Partner of _ _ Aw the Cleveland office of Ernst & Young Russell W. Maier Ernest J. Novak, Jr. Robert N.Pokelwaldt Paul J. Powers LLP. Member, Audit and Finance Committees. Director of FirstEnergy Corp. since 2004.

Robert N. Pokelwaldt, 69 Retired, formerly Chairman of the Board and Chief Executive Officer of YORK International Corporation. Catherine A. Rein Robert C. Savage George M. Smart Member, Audit and Finance Committees. Director of FirstEnergy Corp. since 2001 and of the former GPU, Inc., from 2000-2001.

Paul J. Powers, 71 George M. Smart, 60 Retired, formerly Chairman of the Non-executive Chairman of the Wes M. Taylor Jesse T. Williams, Sr.

Board and Chief Executive Officer FirstEnergy Board of Directors. Retired, of Commercial Intertech Corp. formerly President of Sonoco-Phoenix, Chair, Finance Committee, Member, Inc. Member, Audit and Corporate Compensation Committee. Director Governance Committees. Director of FirstEnergy Corp. since 1997 and of FirstEnergy Corp. since 1997 of Ohio Edison from 1992-1997. and of Ohio Edison from 1988-1997.

Catherine A. Rein, 63 Wes M. Taylor, 63 Senior Executive Vice President and Retired, formerly President of TXU Dr. Patricia K. Woolf Chief Administrative Officer of MetLife Generation. Member, Compensation Inc. Chair, Compensation Committee; and Nuclear Committees. Director of Member, Audit Committee. Director FirstEnergy Corp. since 2004.

of FirstEnergy Corp. since 2001 and of the former GPU, Inc., from 1989-2001. Jesse T.Williams, Sr., 66 Retired, formerly Vice President of Dr. Patricia K. Woolf, 71 Robert C. Savage, 68 Human Resources Policy, Employment Consultant, author, and former Lecturer Chairman of the Board of Savage & Practices and Systems of The Goodyear in the Department of Molecular Biology Associates, Inc. Member, Finance and Tire & Rubber Company. Member, at Princeton University. Member, Nuclear Committees. Director of Corporate Governance and Nuclear Corporate Governance and Nuclear FirstEnergy Corp. since 1997 and of the Committees. Director of FirstEnergy Committees. Director of FirstEnergy former Centerior Energy Corporation Corp. since 1997 and of Ohio Edison Corp. since 2001 and of the former from 1990-1997. from 1992-1997. GPU, Inc., from 1983-2001.

5 0 3 FirstEnergy Corp. FirstEnergy Bradford E Tobin FirstEnergy Service Company Vice Presidentand Regional Operations Anthony J.Alexander ChiefProcurementOfficer Management President and Anthony J.Alexander David W. Whitehead ChiefExecutive Officer Presidentand Vice President, James M. Murray Richard R.Grigg ChiefExecutive Officer CorporateSecretary and President, Ohio Operations Executive Vice Presidentand Richard R.Grigg ChiefEthics Officer Dennis M. Chack Chief OperatingOfficer Executive Vice Presidentand Ronald E. Seeholzer Regional President, Richard H. Marsh* Chief Operating Officer Assistant Controller The Cleveland Electric Senior Vice President Lynn M. Cavalier IlluminatingCompany and ChiefFinancialOfficer Senior Vice President FirstEnergy Trent A. Smith Leila L Vespoli* Mark T.Clark Regional President, Senior Vice President Solutions Corp. The Toledo Edison Company Senior Vice President and General Counsel Charles E.Jones Guy L Pipitone Steven E.Strah Harvey L Wagner* Senior Vice President President Regional President, Vice President, Controller Ohio Edison Company and ChiefAccounting Officer David C.Luff Charles D. Lasky Senior Vice President Vice President Douglas S. Elliott David W. Whitehead* President, CorporateSecretary Carole B.Snyder Alfred G. Roth Pennsylvania Operations Senior Vice President Vice President James . Pearson* Ronald P Lantzy Treasurer Thomas M. Welsh Donald R. Schneider Regional President, Senior Vice President Vice President Paulette R.Chatman* Metropolitan Edison Assistant Controller Tony C.Banks Arthur W. Yuan Company Vice President Vice President Jacqueline S.Cooper* John E. Paganie Assistant CorporateSecretary David M. Blank Regional President, Vice President PennsylvaniaElectric Jeffrey R.Kalata* FirstEnergy Nuclear Mary Beth Carroll Company Assistant Controller Operating Company Vice President Stephen E.Morgan Randy Scilla*

Thomas A. Clark Anthony J. Alexander President, Jersey Central Assistant Treasurer Vice President ChiefExecutive Officer Power & Light Company Edward J.Udovich* Donald M. Lynch Assistant CorporateSecretary Kathryn W. Dindo Gary R. Leldich Vice Presidentand Presidentand Regional President, Lisa S.Wilson* ChiefRisk Officer Jersey CentralPower ChiefNuclear Officer Assistant Controller & Light Company Ralph J. DiNicola Law W. Myers Vice President Executive Vice President

• Also holds a similar position Michael J. Dowling Joseph J. Hagan with FirstEnergyService Vice President Senior Vice Presidentand Company,FirstEnergy Solutions Corp. and Bradley S. Ewing Chief OperatingOfficer Vice President Danny L Pace FirstEnergyNuclear OperatingCompany. Bennett L Gaines Senior Vice President, Vice Presidentand Chief Engineering Information Offier Richard L Anderson Terrance G. Howson Vice President, Vice President Nuclear Operations Ali Jamshidi Jeannie M. Rinckel Vice President Vice President,Oversight Mark A. Julian Mark B. Bezilla Vice President Vice President, Thomas C.Navin Davis-Besse Vice President James H. Lash Daniel V. Steen Vice President, Beaver Valley Vice President L William Pearce Stanley F.Szwed Vice President, Perry Vice President a

Glossary of Terms The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:

ATSI American Transmission Systems, Inc., owns and operates transmission facilities FSP13-1 FASB Staff Position No. 13-1, 'Accounting for Rental Costs Incurred during the Avon Avon Energy Partners Holdings Construction Period' CEI TheCleveland Electric Illuminating Company, an Ohio electric utility operating FSP106-1 FASB Staff Position No. 106-1, 'Accounting and Disclosure Requirements Related subsidiary to the Medicare Prescription Drug, Improvement and Modernization Act of 2003' Centerior Centerior Energy Corporation, former parent of CEIand TE,which merged with FSP106-2 FASBStaff Position No.106-2, 'Accounting and Disclosure Requirements OEto form FirstEnergy on November 8, 1997. Related to the Medicare Prescription Drug, Improvement and Modernization CFC Centerior Funding Corporation, a wholly owned finance subsidiary of CEI Act of 2003' Companies OE,CEI,TE,Penn, JCP&L, Met-Ed and Penelec FSP115-1 FASB Staff Position No, 115-1 and FAS124-1, 'The Meaning of Other-Than EGSA Empresa Guaracachi S.A. and FAS124-1 Temporary Impairment and its Application to Certain Investments' Emdersa Empresa Distribuidora Electrica Regional S.A. FSP123(R) FASB Staff Position No. 123(R), 'Share-Based Payment' FENOC FirstEnergy Nuclear Operating Company, operates nuclear generating facilities GAAP Accounting Principles Generally Accepted in the United States FES FirstEnergy Solutions Corp., provides energy-related products and services GCAF Generation Charge Adjustment Factor FESC FirstEnergy Service Company, provides legal, financial, and other corporate GHG Greenhouse Gases support services HVAC Heating, Ventilation and Air-conditioning FGCO FirstEnergy Generation Corp., owns and operates non-nudear generating facilities IRS Internal Revenue Service FirstCom First Communications, LLC,provides local and long-distance telephone service KWH Kilowatt-hours FirstEnergy FirstEnergy Corp., a public utility holding company LOC Letter of Credit FSG FirstEnergy Facilities Services Group, LLC,the parent company of several Medicare Act Medicare Prescription Drug, Improvement and Modernization Act of 2003 heating, ventilation, air conditioning and energy management companies MEIUG Met-Ed Industrial Users Group GLEP Great Lakes Energy Partners, LLC.an oil and natural gas exploration and MISO Midwest Independent System Transmission Operator, Inc.

production venture Moody's Moody's Investors Service GPU GPU,Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with MOU Memorandum of Understanding FirstEnergy on November 7,2001 MTC Market Transition Charge GPUCapital GPUCapital, Inc., owned and operated electric distribution systems in foreign MW Megawatts countries NAAQS National Ambient Air Quality Standards GPUPower GPUPower, Inc., owned and operated generation facilities in foreign countries NERC North American Electric Reliability Council JCP&L Jersey Central Power & Light Company, a New Jersey electric utility operating NJBPU New Jersey Board of Public Utilities subsidiary NOAC Northwest Ohio Aggregation Coalition JCP&L Transition JCP&L Transition Funding LLC,a Delaware limited liability company and issuer NOV Notices of Violation of transition bonds NOx Nitrogen Oxide MARBEL MARBEL Energy Corporation, previously held FirstEnergy's interest in GLEP NRC Nuclear Regulatory Commission Met-Ed Metropolitan Edison Company, a Pennsylvania electric utility operating sub- NUG Non-Utility Generation sidiary NUGC Non-Utility Generation Clause MYR MYR Gmoup, Inc., a utility infrastructure construction service company OCA Office of Consumer Advocate NEO Northeast Ohio Natural Gas Corp., formerly a MARBEL subsidiary OCC Office of the Ohio Consumers' Counsel NGC FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities OCI Other Comprehensive Income OE Ohio Edison Company, an Ohio electric utility operating subsidiary OPAE Ohio Partners for Affordable Energy Ohio Companies CEI,OEand TE OPEB Other Post-Employment Benefits Penelec Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary OSBA Office of Small Business Advocate Penn Pennsylvania Power Company, a Pennsylvania electric utility operating OTS Office of Trial Staff subsidiary of OE PICA Penelec Industrial Customer Association PNBV PNBV Capital Trust, a special purpose entity created by OEin 1996 PJM PJM Interconnection L.L.C.

Shippingport Shippingport Capital Trust, a special purpose entity created by CEIand TEin 1997 PUR Provider of Last Resort TE TheToledo Edison Company, an Ohio electric utility operating subsidiary PPUC Pennsylvania Public Utility Commission TEBSA Termobarranquilla S.A.,Empresa de Servicios Publicos PRP Potentially Responsible Party PUCO Public Utilities Commission of Ohio PUHCA Public Utility Holding Company Act of 1935 The following abbreviations and acronyms RCP Rate Certainty Plan are used to identify frequently used terms in this report RFP Request for Proposal RSP Rate Stabilization Plan RTC Regulatory Transition Charge AEC Alternative Energy Credit RTO Regional Transmission Organization AU Administrative Law Judge S&P Standard & Poor's Ratings Service AOCL Accumulated Other Comprehensive Loss SBC Societal Benefits Charge APB Accounting Principles Board SEC U.S.Securities and Exchange Commission APB25 APBOpinion No. 25, 'Accounting for Stock Issued to Employees' SFAC Statement of Financial Accounting Concepts APB 29 APBOpinion No. 29, 'Accounting for Nonmonetary Transactions' SFAC 7 SFAC No. 7,'Using Cash Flow Information and Present Value in Accounting ARB Accounting Research Bulletin Measurements' ARB43 ARB No. 43, 'Restatement and Revision of Accounting Research Bulletins' SFAS Statement of Financial Accounting Standards ARO Asset Retirement Obligation SFAS71 SFAS Na 71, 'Accounting for the Effects of Certain Typesof Regulation' BGS Basic Generation Service SFAS 87 SFAS No. 87, 'Employers' Accounting for Pensions' CAIR Clean Air Interstate Rule SFAS101 SFAS No. 101,'Accounting for Discontinuation of Application of SFAS 71' CAL Confirmatory Action Letter SFAS 106 SFAS No. 106, 'Employers'Accounting for Postretirement Benefits Other Than CAMR Clean Air Mercury Rule Pensions' CAVR Clean Air Visibility Rule SFAS115 SFAS No. 115, 'Accounting for Certain Investments in Debt and Equity Securities' CAT Commercial Activity Tax SFAS123 SFAS No. 123, 'Accounting for Stock-Based Compensation' CO2 Carbon Dioxide SFAS123(R) SFAS No. 123(R), 'Share-Based Payment' CTC Competitive Transition Charge SFAS131 SFAS No. 131, 'Disciosures about Segments of an Enterprise and Related DOJ United States Department of Justice Information' DRA Division of Ratepayer Advocate SPAS 133 SPAS No. 133, 'Accounting for Derivative Instruments and Hedging Activities' ECAR East Central Area Reliability Coordination Agreement SFAS140 SFAS No. 140, 'Accounting for Transfers and Servicing of Financial Assets and EITF Emerging IssuesTaskForce Extinguishment of Liabilities' EITF03-1 EITFIssue No. 03-1, 'The Meaning of Other-Than-Temporary and Its SFAS 142 SFAS No. 142, 'Goodwill and Other Intangible Assets' Application to Certain Investments' SFAS 143 SFAS No. 143, 'Accounting for Asset Retirement Obligations' EITF04-13 EITFIssue No. 04-13, 'Accounting for Purchases and Sales of Inventory with SFAS 144 SFAS No. 144, 'Accounting for the Impairment or Disposal of Long-Lived Assets' the Same Counterparty' SFAS 150 SFAS No. 150, 'Accounting for Certain Financial Instruments with EITF99-19 EITFIssue No. 99-19, 'Reporting Revenue Gross as a Principal versus Net as Characteristics of Both Liabilities and Equity' an Agent' SFAS 151 SFAS No. 151, 'Inventory Costs - an amendment ofARB No. 43, Chapter 4' EPA Environmental Protection Agency SFAS 153 SFAS No. 153, 'Exchanges of Nonmonetary Assets - an amendment of APB EPACT Energy Policy Act of 2005 Opinion No. 29' ERO Electric Reliability Organization SFAS154 SFASNo. 154, 'Accounting Changes and Error Corrections - a replacement of FASB Financial Accounting Standards Board APB Opinion No. 20 and FASB Statement No. 3' FERC Federal Energy Regulatory Commission S02 Sulfur Dioxide FIN FASBInterpretation TBC Transition Bond Charge FIN46R FIN46 (revised December 2003), Consolidation of Variable Interest Entities' TMI-1 ThreeMile Island Unit 1 FIN47 FIN47, 'Accounting for Conditional Asset Retirement Obligations - an inter- TMI-2 Three Mile Island Unit 2 pretation of FASB Statement No. 143' VIE Variable Interest Entity FMB First Mortgage Bonds FirstEnergy Corp. 2005 9 FSP FASBStaff Position

Management Reports MANAGEMENT'S RESPONSIBILITY MANAGEMENT'S REPORT ON INTERNAL CONTROL FOR FINANCIAL STATEMENTS OVER FINANCIAL REPORTING The consolidated financial statements were prepared by Management is responsible for establishing and management who takes responsibility for their integrity and maintaining adequate internal control over financial reporting objectivity. The statements were prepared in conformity with as defined in Rule 13a-15(f) of the Securities Exchange Act accounting principles generally accepted in the United States of 1934. Using the criteria set forth by the Committee of and are consistent with other financial information appearing Sponsoring Organizations of the Treadway Commission elsewhere in this report. PricewaterhouseCoopers LLP, an in Internal Control- IntegratedFramework, management independent registered public accounting firm, has expressed conducted an evaluation of the effectiveness of the Company's an unqualified opinion on the Company's 2005 consolidated internal control over financial reporting under the supervision financial statements. of the chief executive officer and the chief financial officer.

FirstEnergy Corp.'s internal auditors, who are responsible Based on that evaluation, management concluded that the to the Audit Committee of FirstEnergy's Board of Directors, Company's internal control over financial reporting was review the results and performance of operating units within effective as of December 31, 2005. Management's assessment the Company for adequacy, effectiveness and reliability of of the effectiveness of the Company's internal control over accounting and reporting systems, as well as managerial and financial reporting, as of December 31, 2005, has been audited operating controls. by PricewaterhouseCoopers LLP, an independent registered FirstEnergy's Audit Committee consists of six public accounting firm, as stated in their report which appears independent directors whose duties include: consideration on page 11.

of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee's findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company's independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm's report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews management's programs to monitor compliance with the Company's policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held eight meetings in 2005.

10 FirstEnergy Corp. 2005

Report of Independent Registered Public Accounting Firm To the Stockholders and Board of Directors of FirstEnergy Corp.:

We have completed integrated audits of FirstEnergy Corp.s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

CONSOLIDATED FINANCIAL INTERNAL CONTROL OVER FINANCIAL REPORTING STATEMENTS Also, in our opinion, management's assessment, included in the accompanying In our opinion, the accompanying Management's Report on Internal Control Over Financial Reporting, that the consolidated balance sheets and the related Company maintained effective internal control over financial reporting as of 2005 consolidated statements of income, based on criteria established in Internal Control -IntegratedFramework issued by the capitalization, common stockholders' Committee of Sponsoring Organizations of the Treadway Commission (COSO), is equity, preferred stock, cash flows, and fairly stated, in all material respects, based on those criteria. Furthermore, in our taxes present fairly, in all material opinion, the Company maintained, in all material respects, effective internal control respects, the financial position of over financial reporting as of December 31, 2005, based on criteria established in FirstEnergy Corp. and its subsidiaries at Internal Control- IntegratedFramework issued by the COSO. The Company's man-December 31, 2005 and 2004, and the agement is responsible for maintaining effective internal control over financial results of their operations and their cash reporting and for its assessment of the effectiveness of internal control over finan-flows for each of the three years in the cial reporting. Our responsibility is to express opinions on management's assessment period ended December 31, 2005 in and on the effectiveness of the Company's internal control over financial reporting conformity with accounting principles based on our audit We conducted our audit of internal control over financial report-generally accepted in the United States of ing in accordance with the standards of the Public Company Accounting Oversight America. These financial statements are Board (United States). Those standards require that we plan and perform the audit the responsibility of the Company's man- to obtain reasonable assurance about whether effective internal control over finan-agement. Our responsibility is to express cial reporting was maintained in all material respects. An audit of internal control an opinion on these financial statements over financial reporting includes obtaining an understanding of internal control over based on our audits. We conducted our financial reporting, evaluating management's assessment, testing and evaluating the audits of these statements in accordance design and operating effectiveness of internal control, and performing such other with the standards of the Public procedures as we consider necessary in the circumstances. We believe that our audit Company Accounting Oversight Board provides a reasonable basis for our opinions.

(United States). Those standards require A company's internal control over financial reporting is a process designed to that we plan and perform the audit to provide reasonable assurance regarding the reliability of financial reporting and the obtain reasonable assurance about preparation of financial statements for external purposes in accordance with gener-whether the financial statements are free ally accepted accounting principles. A company's internal control over financial of material misstatement An audit of reporting includes those policies and procedures that (i) pertain to the maintenance financial statements includes examining, of records that, in reasonable detail, accurately and fairly reflect the transactions on a test basis, evidence supporting the and dispositions of the assets of the company; (ii) provide reasonable assurance amounts and disclosures in the financial that transactions are recorded as necessary to permit preparation of financial state-statements, assessing the accounting ments in accordance with generally accepted accounting principles, and that principles used and significant estimates receipts and expenditures of the company are being made only in accordance with made by management, and evaluating the authorizations of management and directors of the company; and (iii) provide rea-overall financial statement presentation. sonable assurance regarding prevention or timely detection of unauthorized We believe that our audits provide a acquisition, use, or disposition of the company's assets that could have a material reasonable basis for our opinion. effect on the financial statements.

As discussed in Note 2(K) and Note Because of its inherent limitations, internal control over financial reporting 12 to the consolidated financial state- may not prevent or detect misstatements. Also, projections of any evaluation of ments, the Company changed its method effectiveness to future periods are subject to the risk that controls may become of accounting for asset retirement inadequate because of changes in conditions, or that the degree of compliance with obligations as of January 1, 2003 and the policies or procedures may deteriorate.

conditional asset retirement obligations as of December 31, 2005. As discussed in Note 7 to the consolidated financial LL-,P statements, the Company changed its method of accounting for the consolida- PricewaterhouseCoopers LLP tion of variable interest entities as of Cleveland, Ohio December 31, 2003. February27,2006 FirstEnergy Corp. 2005 11

The following selected financial data should be read in conjunction with, and is qualified in its entirety by reference to, the sections entitled "Management's Discussion and Analysis of Results of Operations and Financial Condition" and with our con-solidated financial statements and the "Notes to Consolidated Financial Statements." Our Statements of Income are not necessarily indicative of future conditions or results of operations.

SELECTED FINANCIAL DATA an millions, except per share amounts)

For the Years Ended December 31, 2005 2004 2003 2002 2001 Revenues0)S $11,989 $12,060 $11,325 $11,169 $ 6,924 Income Before Discontinued Operations and Cumulative Effect of Accounting Changes $ 873 $ 896 $ 444 $ 613 $ 648 Net Income $ 861 $ 878 $ 423 $ 553 $ 646 Basic Earnings per Share of Common Stock:

Before Discontinued Operations and Cumulative Effect of Accounting Changes $ 2.66 $ 2.74 $ 1.46 $ 2.09 $ 2.82 After Discontinued Operations and Cumulative Effect of Accounting Changes $ 2.62 $ 2.68 $ 1.39 $ 1.89 $ 2.82 Diluted Earnings per Share of Common Stock:

Before Discontinued Operations and Cumulative Effect of Accounting Changes $ 2.65 $ 2.73 $ 1.46 $ 2.08 $ 2.81 After Discontinued Operations and Cumulative Effect of Accounting Changes $ 2.61 $ 2.67 $ 1.39 $ 1.88 $ 2.81 2

Dividends Declared per Share of Common Stock( ) $1.705 $1.9125 $ 1.50 S 1.50 $ 1.50 Total Assets $31,841 $31,035 $32,878 $34,366 $37,334 Capitalization as of December 31:

Common Stockholders' Equity $ 9,188 $ 8,590 $ 8,290 $ 7,051 $ 7,399 Preferred Stock:

Not Subject to Mandatory Redemption 184 335 335 335 480 Subject to Mandatory Redemption - - - 428 595 Long-Term Debt and Other Long-Term Obligations 8,155 10,013 9,789 10,872 12,865 Total Capitalization $17,527 $18,938 $18,414 $18,686 $21,339 Weighted Average Number of Basic Shares Outstanding 328 327 304 293 230 Weighted Average Number of Diluted Shares Outstanding 330 329 305 294 230 (v) Thereduction of 2005 revenues compared to 2004 reflects a change in reporting methodology for PJM market transactions (see Note 2(D)) that had no impoct on net income Exduding that reporting change, revenues in 2005 were $997 million higher than 2004.

(2) Dividends declared in 2005 include two quarterly payments of $04125 per share in 2005. one quarterly payment of $0.43 per share in 2005 and one quarterly payment of $0.45 per share payable in 2006 increasing the indicated annual dividend rate from $1.72 to $1.80 per share. Ddends declared in 2004 include four quarterly dividends of $0.375 per share paid in 2004 anda quarterly di&idend of S0.4125 per share declaredin 2004 and paid March 1,2005. Diidends declared in 2001, 2002 and 2003 indude four quarerey diidends of 50.575 per share PRICE RANGE OF COMMON STOCK The Common Stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol "FE" and is traded on other registered exchanges.

2005 2004 First Quarter High-Low $42.36 $37.70 $39.37 $35.24 Second Quarter High-Low $48.96 $40.75 $39.73 $36.73 Third Quarter High-Low $53.00 $47.46 $42.23 $37.04 Fourth Quarter High-Low $53.36 $45.78 $43.41 $38.35 Yearly High-Low $53.36 $37.70 $43.41 $35.24 fces are from httpl/finance yahoaocom.

HOLDERS OF COMMON STOCK There were 135,261 and 134,587 holders of 329,836,276 shares of FirstEnergy's Common Stock as of December 31, 2005 and January 31, 2006, respectively. Information regarding retained earnings available for payment of cash dividends is given in Note 11(A) to the consolidated financial statements.

12 FirstEnergy Corp. 2005

Management's Discussion and Analysis of Results of Operations and Financial Condition Forward-looking Statements. This discussion includesfor- EXECUTIVE

SUMMARY

ward-looking statements based on informationcurrently Earnings before unusual items on a Non-GAAP basis in availableto management. Such statements aresubject to certain 2005 were $984 million, or basic earnings before unusual items risks and uncertainties. These statements typically contain, but of $3.00 per share of common stock, compared to $991 million are not limited to, the terms "anticipate," "potential," "expect," (basic earnings of $3.03 per share) in 2004 and $736 million "believe, " "estimate" and similarwords. Actual results may differ (basic earnings of $2.42 per share) in 2003. On a GAAP basis, materiallydue to the speed and nature of increased competition net income was $861 million, or basic earnings of $2.62 per and deregulation in the electric utility industry economic or share of common stock in 2005 compared to $878 million weather conditions affectingfuture sales and margins, changes in (basic earnings of $2.68 per share) in 2004 and $423 million marketsfor energy services, changing energy and commodity (basic earnings of $1.39 per share) in 2003. The following market prices, replacementpower costs being higher than antici- Non-GAAP Reconciliation displays the unusual items resulting pated or inadequately hedged, the continued ability of our in the difference between GAAP and Non-GAAP earnings:

regulated utilities to collect transitionand other charges or to Non-GAAP Reconciliation recover increased transmissioncosts, maintenance costs being higher than anticipated, legislativeand regulatory changes 2005 2004 2003 (including revised environmental requirements), the repeal of Basic Basic Basic PUHCA and the legal and regulatorychanges resultingfrom the After-tax Earnings Aftertax Earnings After-tax Earnings Amount Per Share Amount Per Share Amount Per Share implementation of the EPAC7T the uncertaintyof the timing and amounts of the capitalexpenditures (including that such Earnings Before Unusual

!an ilions exreptper sharemounts) amounts could be higher than anticipated) or levels of emission Items (Non-GAAP) $984 $3.00 $991 $3.03 $736 $2.42 Cumulative effect reductionsrelated to the settlement agreementresolving the New of accounting changes (30) (0.09) 102 0.33 Source Review litigation,adverse regulatory or legal decisions I Ohio/New Jersey income tax adustments (63) (0.19) and outcomes (including, but not limited to, the revocation of nec- EPA se ement (14) (0.04)

Davis-Besse DOJ penalty essary licenses or operatingpermits, fines or otherenforcement and NRC fines (31) (0.10) actions and remedies) of governmental investigationsand over- JCP&L arbitration decision (10) (0.03)

JCP&L rate settlement 16 0.05 sight, including by the Securities and Exchange Commission, the Non-core asset sales/

United States Attorney's Office, the NuclearRegulatory impairments 9 0.02 (60) (0.19) (125) (0.41)

Davis-Besse extended Commission and the various state public utility commissions as outage impacts (38) (0.12) (170) (0.56)

Class-action lawsuit disclosed in our Securities and Exchange Commissionfilings, settlement (11) (0.03) generally, and with respect to the Davis-Besse Nuclear Power JCP&L disallowance (109) (0.36)

NRG settlement 99 0.33 Station outage and heightened scrutiny at the Perry Nuclear Discontinued international PowerPlant in particular,the continuing availability and opera- operations (101) (0.33)

Other (4) (0.01) (9) (0.03) tion ofgenerating units, the ability of ourgeneratingunits to Net Income (GAAP) $861 $2.62 $878 $2.68 $423 $1.39 continue to operateat, or nearfull capacity, our inability to accomplish or realize anticipatedbenefits from strategicgoals (including employee workforcefactors), the anticipatedbenefits The Non-GAAP measure above, earnings before unusual from our voluntary pension plan contributions, our ability to items, is not calculated in accordance with GAAP because it improve electric commodity margins and to experiencegrowth in excludes the impact of "unusual items." Unusual items reflect the distributionbusiness, our ability to access the public securities the impact on earnings of events that are not routine or for and other capital markets and the cost of such capital, the out- which we believe the financial impact will disappear or come, cost and other effects of present and potential legal and become immaterial within a near-term finite period. By administrativeproceedings and claims related to the August 14, removing the earnings effect of such issues that have been 2003 regionalpower outage, circumstances which may lead man- resolved or are expected to be resolved over the near term, our agement to seek, or the Board of Directorsto grant, in each case in management and investors can better measure our business its sole discretion, authorityfor the implementation of a share and earnings potential. In particular, the non-core asset sales repurchaseprogram in thefuture, the risks and otherfactors dis- item refers to a finite set of energy-related assets that had been cussedfrom time to time in our Securities and Exchange previously disclosed as held for sale, a substantial portion of Commissionfilings, and other similarfactors.Dividends which has already been sold. In addition, as Davis-Besse declaredfrom time to time during any annual period may in restarted in 2004, further impacts from its extended outage aggregatevaryfrom the indicated amounts due to circumstances are not expected. Similarly, the DOJ penalty and NRC fines consideredby the Board at the time of the actual declarations. in 2005 and further litigation settlements similar to the class Also, a credit ratingshould not be viewed as a recommendation to action settlements in 2004 are not reasonably expected over buy, sell or hold securities and may be revised or withdrawn by a the near term. Furthermore, we believe presenting normalized ratingagency at any time. We expressly disclaim any current earnings calculated in this manner provides useful information intention to updateangyforward-lookingstatements contained to investors in evaluating the ongoing results of our businesses herein as a result of new information,future events, or otherwise.

FirstEnergy Corp. 2005 13

over the longer term and assists investors in comparing our mented their existing RSP with an RCP designed to provide operating performance to the operating performance of others customers with more certain rate levels than otherwise avail-in the energy sector. able under the RSP during the plan period. On January 4, Sales and Production - KWH sales for 2005 were higher 2006, the PUCO approved the RCP filing with modifications.

than the previous year, driven primarily by strong sales to On January 10, 2006, the Ohio Companies filed a Motion for residential and commercial customers. An unseasonably Clarification of the PUCO order approving the RCP. On warmer summer and a colder fourth quarter in 2005 led to January 25, 2006, the PUCO issued an Entry on Rehearing our generating fleet producing a record 80.2 billion KWH, granting in part, and denying in part the Ohio Companies' compared to 76.4 billion KWH in 2004. Our non-nuclear fleet previous requests and clarifying related issues.

produced record output of 51.5 billion KWH and our nuclear S&P Ratings Upgrade - In October 2005, S&P raised its fleet produced 28.7 billion KWH. corporate credit rating of FirstEnergy and the Companies to Davis-Besse Issues - In January 2006, FENOC announced 'BBB' from 'BBB-' At the same time, S&P raised our senior that it had entered into a deferred prosecution agreement with unsecured ratings at the holding company to 'BBB-' from the U.S. Attorney's Office for the Northern District of Ohio and 'BB +' and each of the Companies by one notch above previous the Environmental Crimes Section of the Environment and ratings. S&P noted that the upgrade followed the continuation Natural Resources Division of the DOJ related to FENOC's of a good operating track record, specifically for the nuclear communications with the NRC during the fall of 2001 in con- fleet through the third quarter of 2005. S&P also stated that nection with the reactor head issue at the Davis-Besse Nuclear our rating reflects the benefits of supportive regulation, our Power Station. Under the agreement, the DOJ will refrain from low-cost base load generation fleet, low-risk transmission and seeking an indictment or otherwise initiating criminal prosecu- distribution operations and rate certainty in Ohio. Our ability tion of FENOC for all conduct related to the statement of facts to consistently generate free cash flow, good liquidity and an attached to the deferred prosecution agreement as long as improving financial profile were noted as strengths.

FENOC remains in compliance with the agreement. New Source Review Settlement - In March 2005, we FENOC agreed to pay a penalty of $28 million (which reached a settlement with the EPA, the DOJ, and the States of is not deductible for income tax purposes) that reduced our Connecticut, New Jersey and New York that resolved all issues earnings per share of common stock by $0.09 in 2005. As part related to various parties' actions against our W. H. Sammis of the deferred prosecution agreement entered into with the Plant in the pending New Source Review case. Under the DOJ, $4.35 million of that amount was directed to community agreement, which is in the form of a consent decree of the U.S.

service projects. In entering into this agreement, the United District Court, we will install environmental controls at the States acknowledged FENOC's extensive corrective actions at Sammis Plant, as well as some of our other power plants. We Davis-Besse, FENOC's cooperation during investigations by will also upgrade existing scrubber systems on Units 1, 2 and 3 the DOJ and the NRC, FENOC's pledge of continued coopera- of our Bruce Mansfield Plant. Projects at the Sammis Plant will tion in all related criminal and administrative investigations include equipment designed to reduce 95 % of SO2 emissions and proceedings, FENOC's acknowledgement of responsibility and 90 % of NOx emissions on the plant's two largest units.

for the behavior of its employees and its agreement to pay a Additionally, the plant's five smaller units will be fitted with monetary penalty. control equipment designed to reduce at least 50 % of S02 Pension Contribution - In December 2005, we made a and 70 % of NOx emissions. In total, additional environmental voluntary $500 million contribution to our pension plan. The controls are expected to be installed on nearly 5,500 MW of impact of the pension contribution is expected to be accretive our 7,400 MW coal-fired generating capacity. Construction to earnings and further increase security of future plan bene- began in 2005 and is expected to be completed by 2012.

fits. Since the contribution is deductible for tax purposes, the The estimated $1.5 billion investment in environmental after-tax cash impact was approximately $341 million in 2005. improvements agreed to under the settlement agreement We funded this payment through available short-term credit is consistent with assumptions reflected in our long-term facilities and anticipate repaying such borrowings during 2006 financial planning prior to settlement. Nearly all of the expen-through positive cash flow. ditures are expected to be capital additions and depreciated New Jersey Rate Matters -JCP&L filed a request in over a period of years. Additionally, we paid an $8.5 million December 2005 with the NJBPU for an increase in its NUGC, civil penalty to the DOJ and will contribute up to $25 million totaling $165 million, or approximately $4.08 per month for over five years to support environmentally beneficial projects a residential customer using 500 KWH of electricity. The as part of the settlement terms. This settlement penalty proposed 6.4% increase inJCP&L's total revenues is designed reduced our earnings per share of common stock by $0.03 to recover above-market costs associated with mandated in the second quarter of 2005.

long-term contracts between JCP&L and various NUGs. Dividends - The Board of Directors increased our Above-market NUG costs are deferred on our balance sheet quarterly dividend twice during 2005, representing a 9.1 %

as a regulatory asset. Revenues collected through the NUGC increase over the rate in effect at the beginning of the year.

reduce the regulatory asset and, therefore, the $165 million The first increase of 1.75 cents per share (a 4.2% increase) annual increase will not have an effect on net income due was declared on September 20. The second increase of 2 cents to deferral accounting. per share (a 4.7% increase) was declared on November 15 Ohio Rate Matters - On September 9, 2005, the Ohio and is payable March 1, 2006. As of December 31, 2005, our Companies filed an application with the PUCO that supple- quarterly dividend rate stood at $0.45 per share of common 14 FirstEnergy Corp. 2005

stock - an annual indicated dividend rate of $1.80 per share. our remaining non-core businesses. (See Note 16 to the consol-The amount and timing of all dividend declarations are idated financial statements.) The assets and revenues for the subject to the discretion of the Board of Directors and its other business operations are below the quantifiable threshold consideration of business conditions, results of operations, for separate disclosure as "reportable operating segments".

financial condition and other factors. We acquired international assets in our merger with GPU in November 2001. GPU Capital and its subsidiaries provided FIRSTENERGY'S BUSINESS electric distribution services in foreign countries (see Results FirstEnergy is a public utility holding company headquar- of Operations - Discontinued Operations). GPU Power and its tered in Akron, Ohio that operates primarily through two core subsidiaries also owned and operated generation facilities in business segments (see Results of Operations - Business foreign countries. As of January 30, 2004, all of our interna-Segments). tional operations had been divested because those operations were not aligned with our strategy.

Regulated Services transmits and distributes electrici-ty through our eight utility operating companies that STRATEGY collectively comprise the nation's fifth largest investor- We continue to pursue our goal of being a leading region-owned electric system, serving 4.5 million customers al supplier of energy and related services in the northeast within 36,100 square miles of Ohio, Pennsylvania and quadrant of the United States, where we see the best opportu-New Jersey. This business segment derives its revenue nities for growth. While we continue to build a strong regional principally from the delivery of electricity generated or presence, key elements of our strategy are in place and man-purchased by our Power Supply Management Services agement's focus continues to be on execution. We intend to segment in the states in which our utility subsidiaries continue providing competitively priced, high-quality products operate. The service areas of our utillities are summa- and value-added services - energy sales and services, energy rized below: delivery, power supply and supplemental services related to our core business.

Company Area Served Customers Served Our current focus includes: (1) minimizing unplanned OE Central and Northeastern Ohio 1,038,000 extended generation outages; (2) enhancing our system relia-Penn Western Pennsylvania 158,000 bility; (3) optimizing our generation portfolio; (4) effectively CEI Northeastern Ohio 763,000 managing commodity supplies and risks; (5) preserving and TE Northwestern Ohio 314,000 enhancing profit margins; (6) preserving and enhancing our credit profile and financial flexibility; and (7) enhancing the

,JCP&L Northern, Western and East skills and diversity of our workforce.

Central New Jersey 1,072,000 Met-Ed Eastern Pennsylvania 534,000 RISKS AND CHALLENGES Penelec Western Pennsylvania 588,000 In executing our strategy, we face a number of industry ATSI Servke areas of OE, Penn, CEIand TE and enterprise risks and challenges, including:

• Risks arising from the reliability of our power plants

• Power Supply Management Services supplies all of and transmission and distribution equipment; the electric power needs of our end-use customers

• Changes in commodity prices could adversely affect our through retail and wholesale arrangements, including profit margins; regulated retail sales to meet the PLR requirements of

• Nuclear generation involves risks that include uncer-our Ohio and Pennsylvania companies and competitive tainties relating to health and safety, additional capital retail sales to commercial and industrial businesses pri-costs, the adequacy of insurance coverage and nuclear marily in Ohio, Pennsylvania and Michigan. This plant decommissioning; business segment owns and operates our generating

• Regulatory changes in the electric industry could affect facilities and purchases electricity from the wholesale our competitive position and result in unrecoverable market to meet our sales obligations (See FirstEnergy costs adversely affecting our business and results of Intra-System Generation Asset Transfers below). The operations; segment's net income is primarily derived from electric

• We are exposed to operational, price and credit risks generation sales revenues less the related costs of elec-associated with selling and marketing products in the tricity generation, including purchased power, and net power markets that we do not always completely hedge transmission, congestion and ancillary costs charged by against; PJM and MISO to deliver energy to retail customers.

• Complex and changing government regulations could have a negative impact on our results of operations; Other operating segments provide a wide range of

• Costs of compliance with environmental laws are services, including heating, ventilation, air-conditioning, significant, and the cost of compliance with future refrigeration, electrical and facility control systems, high-environmental laws could adversely affect cash flow efficiency electrotechnologies and telecommunication services, and profitability; and previously included international operations that were divested in January 2004. We are in the process of divesting FirstEnergy Corp. 2005 15

• There are uncertainties relating to our participation legislation. Consistent with the restructuring plans, generation in the PJM and MISO Regional Transmission assets that had been owned by the Ohio Companies and Penn Organizations; were required to be separated from the regulated delivery busi-

• Weather conditions such as tornadoes, hurricanes, ice ness of those companies through transfer or sale to a separate storms and droughts, as well as seasonal temperature corporate entity. The transactions essentially completed the variations could have a negative impact on our results divestitures of owned assets contemplated by the restructuring of operations; plans by transferring the ownership interests to NGC and

• We are subject to financial performance risks related FGCO without impacting the operation of the plants. The to the economic cycles of the electric utility industry; transfers were intercompany transactions and, therefore, had

• The continuing availability and operation of generating no impact on our consolidated results.

units is dependent on retaining the necessary licenses, permits, and operating authority from governmental RECLASSIFICATIONS entities, including the NRC; As discussed in Notes 1 and 16 to the consolidated

• We face certain human resource risks associated with financial statements, certain prior year amounts have been the availability of trained and qualified labor to meet reclassified to conform to the current year presentation and our future staffing requirements; to reflect certain businesses divested in 2005 that have been

• Our risk management policies relating to energy and fuel classified as discontinued operations (see Note 2(J)). These prices, and counterparty credit are by their very nature reclassifications did not change previously reported earnings risk related, and we could suffer economic losses despite for 2004 and 2003.

such policies;

• Interest rates and/or a credit ratings downgrade could RESULTS OF OPERATIONS negatively affect our financing costs and our ability The financial results discussed below include revenues and to access capital; expenses from transactions among our business segments. A

• We must rely on cash from our subsidiaries; reconciliation of segment financial results is provided in Note

• We may ultimately incur liability in connection 16 to the consolidated financial statements. The FSG business with federal proceedings; and segment is included in "Other and Reconciling Adjustments"

• Acts of war or terrorism could negatively impact due to its immaterial impact on current period financial results, our business. but is presented separately in segment information provided in Note 16 to the consolidated financial statements. Net income FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS (loss) by major business segment was as follows:

On May 13, 2005, Penn, and on May 18, 2005, our Ohio Increase (Decrease)

Companies entered into certain agreements implementing a series of intra-system generation asset transfers that were 2005 vs 2004 ws 2005 2004 2003 2004 2003 completed in the fourth quarter of 2005. The asset transfers (inmnulbNs exceptper share amounts) resulted in the respective undivided ownership interests of Net Income (Loss) the Ohio Companies and Penn in our nuclear and non-nuclear By Business Segment Regulated services $1,046 $1,015 S1,164 $ 31 S(149) generation assets being owned by NGC and FGCO, respectively. Power supply management services 14 104 (320) (90) 424 The generating plant interests transferred do not include Other and reconciling adjustments' (199) (241) (421) 42 180 leasehold interests of CEI, OE and TE in certain of the plants Total $ 861 $ 878 S 423 $ (17) $455 that are currently subject to sale and leaseback arrangements Bask Earnings Per Share:

with non-affiliates. Income before discontinued On October 24, 2005, the Ohio Companies and Penn com- operations and cumulative effect of accounting changes $ 2.66 $ 2.74 $ 1.46 $(0.08) $1.28 pleted the intra-system transfer of non-nuclear generation assets Discontinued operations 0.05 (0.06) (0.40) 0.11 0.34 Cumulative effect of accounting to FGCO. Prior to the transfer, FGCO, as lessee under a Master changes (0.09) - 0.33 (0.09) (0.33)

Facility Lease with the Ohio Companies and Penn, leased, oper- Basic earnings per share $ 2.62 $ 2.68 $1.39 $(0.06) $1.29 ated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to Diluted Earnings Per Share:

Income before discontinued FGCO's purchase option under the Master Facility Lease. operations and cumulative efect of accounting changes S 2.65 S 2.73 S 1.46 5(0.08) $1.27 On December 16, 2005, the Ohio Companies and Penn Discontinued operations 0.05 (0.06) (0.40) 0.11 0.34 completed the intra-system transfer of their respective Cumulative effect of accounting changes (0.09) - 0.33 (0.09) (0.33) ownership interests in the nuclear generation assets to NGC through, in the case of OE and Penn, an asset spin-off in the Diluted earnings per share $ 2.61 $2.67 11.39 5(0.06) $1.28 form of a dividend and, in the case of CEI and TE, a sale at *Represents other operatng segments and eonciling items induding interest expense on holding company debt corporate rpprtsenvces revenues and ewenses and the impact ofthe new net book value. FENOC continues to operate and maintain Ohio tax kegisktb the nuclear generation assets.

These transactions were undertaken pursuant to the Summary of Results of Operations - 2005 Compared with 2004 Ohio Companies' and Penn's restructuring plans that were Financial results for our reportable major business approved by the PUCO and the PPUC, respectively, under segments in 2005 and 2004 were as follows:

applicable Ohio and Pennsylvania electric utility restructuring 16 FirstEnergy Corp. 2005

Power Power Supply other and Change Between Supply Other and Regulated Management Reconciling FirstEnergy 2005 and 2004 Regulated Management Reconciling FirstEnergy

.2005 Financial Results Services ServicesAdjustments Consolidated Financial Results Services Services Adjustments() Consolidated (Inminions) Increase (Decrease) (Inmillions)

Revenues: Revenues:

External  ; External Electric $4,915 $5,631 $ - $10,546 Electric $214 S(499) $- $(285)

Other 568 108 767 1,443 Other 78 34 102 214 Internal 270 - (270) - Internal (48) - 48 -

Total Revenues 5,753 5,739 497 11,989 Total Revenues 244 (465) 150 (71)

Expenses: Expenses:

Fuel and Purchased power - 4,011 - 4,011 Fuel and purchased power _ (458) (458)

Other operating expenses 1,757 1,479 489 3,725 Other operating expenses 155 77 119 351 Provision for depreciation 516 45 28 589 Provision for depreciation 3 10 (11) 2 Amortization of regulatory assets 1,281 - - 1,281 Amortization of regulatory assets 115 - - 115 Deferral of new regulatory assets (405) - - (405) Deferral of new regulatory assets (148) - - (148)

Goodwill impairment - - 9 9 Goodwill impairment - - (3) (3)

General taxes 602 91 20 713 General taxes 30 6 (1) 35 Total Expenses 3,751 5,626 546 9,923 Total Expenses 155 (365) 104 (106)

Operating Income (Loss) 2,002 113 (49) 2,066 Operating Income 89 (100) 46 35

Other Income (Expense): Other Income (Expense):

Investment income 218 - - 218 Investment income 13 - - 13 Interest expense (393) (55) (213) (661) Interest expense (32) (12) 54 10 Capitalized interest 18 1 - 19 Capitalized interest (1) (5) - (6)

Subsidiaries preferred stock Subsidiaries' preferred stock dividends (15) - - (15) dividends 6 - - 6 Total Other Income (Expense) (172) (54) (213) (439) Total Other Income (Expense) (14) (17) 54 23 Income taxes (benefit) 763 36 (45) 754 Income taxes 23 (36) 94 81 Income before discontinued Income before discontinued operations and cumulative operations and cumulative

• effect of accounting change 1,067 23 (217) 873 effect of accounting change 52 (81) 6 (23) i Discontinued operations - - 18 18 Discontinued operations - - 36 36 Cumulative effect of accounting Cumulative effect of accounting

• change (21) (9) - (30) change (21) (9) - (30)

IINet Income (Loss) $1,046 $ 14 $(199) S 861 Net Income $ 31 S (90) $42 S (17) to The ompact of the new Ohio tax legislaii on is inckuded with our odter opeatng segments and meconding Odfustments Power Supply Other and Regulated Management Recondling FrstEnergy Regulated Services - 2005 Compared with 2004 2004 Financial Results Services ServicesAustments Consolidated Net income increased by $31 million to $1.05 billion, (Inmilions) a 3.1% increase in 2005, compared to $1.02 billion in 2004, Revenues:

External primarily as a result of increased sales to customers.

Electric .1U1 )O,13U ) - IU,0Ol -

Other 490 74 665 1,229 i Internal 318 - (318) - Revenues-Total Revenues 5,509 6,204 347 12,060 Total rirvenues increased by $244 million in 2005 I . ._I I

.'- _ _ _1^ ,Or_r ar __X__

Expenses: compared to ZUU4, resulting trom the tollowing sources:

Fuel and purchased power - 4,469 - 4,469 Other operating expenses 1,602 1,402 370 3,374 Increase Provision for depredation 513 35 39 587 Revenues by Type of Service 2005 2004 (Decrease)

Amortization of regulatory assets 1,166 - - 1,166 Deferral of new regulatory assets (257) - - (257) On millions)

Goodwill impairment - - 12 12 Distribution services $4,915 $4,701 $214 General taxes 572 85 21 678 Transmission services 415 333 82 Lease revenue from affiliates 270 318 (48)

Total Expenses 3,596 5,991 442 10,029 i Other 153 157 (4)

Operating Income (Loss) 1,913 213 (95) 2,031 Total Revenues $5,753 $5,509 $244 Other Income (Expense):

Investment income 205 - - 205 Interest expense (361) (43) (267) (671)

Capralized interest 19 6 - 25 Subsidiaries' preferred stock Increases m distrbuton delveres by customer class dMdends (21) - _ (21) are summarized in the following table:

Total Other Income (Expense) (158) (37) (267) (462)

-. ElectricDistributionDeliveries Income taxes (benefit) 740 72 (139) 673 Residential 7,3%

Income before discontinued Commercial 4.8 operations and cumulative Industrial 2.0 effect of accounting change 1,015 104 (223) 896 Discontinued operations - - (18) (18) Total Distribution Deliveries 4,7%

Cumulative effect of accounting change - - - -

Net Income (Loss) $1,015 $ 104 $(241) $ 878 FirstEnergy Corp. 2005 17

Increased consumption offset in part by lower composite Other Income -

prices to customers resulted in higher distribution delivery Total other income (expense) decreased by $14 million in revenue. The following table summarizes major factors 2005 compared to 2004 due to the net effect of the following:

contributing to the $214 million increase in distribution

• Investment income increased approximately $13 million service revenue in 2005: in 2005 due primarily to realized gains on nuclear decommissioning trust investments.

Increase

• Interest expense was $32 million higher in 2005.

Sources of Change inDistribution Revenues (Decrease)

(anmilons)

Changes incustomer usage $264 Power Supply Management Services - 2005 Compared with 2004 Changes inprices: Net income for this segment decreased $90 million Rate changes -

Ohio shopping credit incentives (44) resulting in net income of $14 million for 2005 compared to JCP&L rate settlements 48 net income of $104 million in 2004. Lower generation gross Billing component reallocations (54) margin, higher nuclear operating costs and amounts recog-Net Increase inDistribution Revenues $214 nized for fines, penalties and obligations associated with the proceedings involving the W. H. Sammis Plant and the Distribution revenues benefited from unseasonably Davis-Besse Nuclear Power Station contributed to the warmer summer temperatures in 2005, compared to 2004, decrease in net income in 2005 when compared to 2004.

which increased air-conditioning loads of residential and com-mercial customers. While industrial deliveries also increased, Revenues -

that impact was more than offset by lower unit prices in that A decrease in wholesale electric revenues and purchased sector. Higher base rates from JCP&L's stipulated rate settle- power costs in 2005 compared to the prior year primarily ments were more than offset by additional credits provided to resulted from FES recording PJM sales and purchased power customers under the Ohio transition plan who shop for elec- transactions on an hourly net position basis beginning in the tricity from suppliers other than their local utility. first quarter of 2005 compared with recording each discrete Reallocation of billing components between distribution and transaction (on a gross basis) in 2004 (see PJM INTERCON-generation for certain Ohio industrial customers with special NECTION TRANSACTIONS discussed later). This change contracts also offset the higher base rates. Shopping credit had no impact on earnings and resulted from the dedication incentives do not affect current period earnings due to defer- of our Beaver Valley Power Station to PJM in January 2005.

ral of the incentives for future recovery from customers. Wholesale electric revenues and purchased power costs in Transmission revenues increased $82 million in 2005 2004 were each $1.1 billion higher due to recording those from 2004 due in part to increased loads resulting from transactions on a gross basis.

warmer summer weather and higher transmission usage Excluding the effect of the change in recording PJM prices. Lease revenue from affiliates decreased $48 million due wholesale transactions on a gross basis in 2004 ($1.1 billion),

to the intra-system generation asset transfers discussed above. electric generation revenues increased $569 million in 2005 compared to 2004 primarily resulting from a 3.5 % increase Expenses - in KWH sales from higher retail customer usage and a 14 %

Total operating expenses increased by $155 million average increase in unit prices in the wholesale market. The in 2005 compared to the prior year due to the following: increase in retail sales reduced energy available for sale to the wholesale market, resulting in a 2 % reduction in wholesale

• Other operating expenses increased by $155 million sales (before the PJM adjustment). Transmission revenues in 2005 compared to 2004 primarily due to higher increased $26 million in 2005 compared to 2004 due primarily transmission expenses resulting in part from increased to higher transmission system usage.

loads and higher transmission system usage charges;

• Additional amortization of regulatory assets of The change in reported revenues resulted from the following

$115 million, principally Ohio transition costs, which Increase Revenues by lype of Service 2005 2004 (Decrease) was due primarily to using the interest method to amortize regulatory assets; and (inmDA=ons)

Electric generation sales:

• General taxes increased by $30 million due to higher Retail $4,219 $3,795 $ 424 property taxes and increased KWH deliveries which Wholesale(') 1,412 1,267 145 increased the Ohio KWH tax and the Pennsylvania Total electric generation sales 5,631 5,062 569 Transmission 65 39 26 gross receipts tax. Other 43 35 8 Total 5,739 5,136 603 Partially offsetting these higher costs were additional defer- PJM adjustment - 1,068 (1,068) rals of regulatory assets of $148 million, primarily due to the Total Revenues $5,739 $6,204 S (465)

PUCO-approved deferral of MISO administrative costs, shop-

) Excluding 2004 effect ofrecording PJM Iransdions on agross basi:

ping incentive credits and related interest on those deferrals.

The following table summarizes the price and volume factors contributing to increased sales revenue from retail and wholesale customers:

18 FirstEnergy Corp. 2005

Increase costs. Higher transmission costs due primarily to increased Source of Change in Electric Generation Sales (Decrease) loads and higher transmission system usage charges further On milions) increased other operating costs in 2005. The higher costs this Retail:

Effect of 5.2% increase incustomer usage W $228 year were partially offset by lower fossil generation costs that Change Inprices 196 resulted primarily from emission allowance transactions and 424 reduced maintenance outages in 2005. Also offsetting the cost i Wholesale: increases were lower intersegment lease expenses due to the Effect of 2.3% reduction incustomer usage0 ) (28) intra-system generation asset transfer.

Change inprices 173 145 Income taxes -

Net Increase inElectric Generation Sales $569 Income taxes decreased as a result of lower taxable

) Dereose of 465Q6 ioduding te effec ofthe PJMoausbnent income, partially offset by the impact of the $28 million penalty related to the Davis-Besse reactor head issue that Expenses - was not deductible for income tax purposes.

Excluding the effect of the $1.1 billion of PJM purchased power costs recorded on a gross basis in 2004, total operating Other - 2005 Compared with 2004 expenses increased by $703 million in 2005 compared to FirstEnergy's financial results from other operating seg-2004. Higher fuel and purchased power costs contributed ments and reconciling adjustments, including interest expense

$610 million of the increase, resulting from higher fuel on holding company debt, corporate support services revenues costs of $308 million and increased purchased power costs and expenses and the impacts of the new Ohio tax legislation of $302 million. Factors contributing to the higher costs are (discussed below) all contributed to a $42 million increase in summarized in the following table: net income compared to 2004. The increase was partially due to the absence this year of goodwill impairments at FSG of i -Increase Source of Change In Fuel and Purchased Power (Decrease) $25 million (included in discontinued operations in 2004) and the 2004 class action lawsuit settlement as well as gains (in milions)

I Fuel: on the sale of assets ($17 million) in 2005 compared to net Change due to increased unit costs S 254 losses on the sale of assets ($6 million) in 2004, partially Change due to volume consumed 54 offset by a goodwill impairment at MYR of $9 million in 308 2005 not present in 2004.

Purchased Power: On June 30, 2005, tax legislation was enacted in the Change due to increased unit costs 360 Change due to volume purchased (55) State of Ohio that created a new CAT tax, which is based Increase incosts deferred (3) on qualifying "taxable gross receipts" that does not consider 302 any expenses or costs incurred to generate such receipts, Total Increase 610 except for items such as cash discounts, returns and PJM adjustment (1,068) allowances, and bad debts. The CAT tax was effective July 1, Net Decrease inFuel and Purchased Power Costs $ (458) 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out Our generation fleet established a record output of 80.2 over a five-year period at a rate of 20 % annually, beginning billion KWH in 2005. As a result, increased coal consumption with the year ended 2005, and the personal property tax is and the related cost of emission allowances combined to phased-out over a four-year period at a rate of approximately increase fossil fuel expense. Higher coal costs resulted from 25 % annually, beginning with the year ended 2005. During increased market purchases, higher contract coal prices and the phase-out period the Ohio income-based franchise tax will increased transportation costs. Emission allowance costs be computed consistent with the prior law, except that the tax increased primarily from higher prices. To a lesser extent, liability as computed will be multiplied by 80 % in 2005; 60 %

fuel expense increased due to higher costs associated with the in 2006; 40 % in 2007 and 20 % in 2008 to determine the increase in generation from the fossil units relative to nuclear actual liability, thereby eliminating the current income-based generation. Fossil generation output increased 11 % in 2005 franchise tax over a five-year period. As a result of the new and nuclear output decreased by 4 %, compared to 2004, tax structure, all net deferred tax benefits that are not expect-due to the nuclear refueling outages discussed below. ed to reverse during the five-year phase-in period have been Other operating costs increased $77 million in 2005 com- written off as ofJune 30, 2005. The impact on income taxes pared to 2004. Non-fuel nuclear costs were higher in 2005 due associated with the required adjustment to net deferred taxes to refueling outages at Perry Unit 1 (including an unplanned for 2005 was an additional tax expense of approximately $52 extension) and Beaver Valley Unit 2 and a scheduled 23-day million, which was partially offset by the initial phase-out of mid-cycle inspection outage at the Davis-Besse Plant. There the Ohio income-based franchise tax, which reduced income was only one refueling outage in 2004. Fines and penalties taxes by approximately $6 million in 2005. See Note 9 to the related to the Davis-Besse reactor head issue (approximately Consolidated Financial Statements.

$31.5 million) and the EPA settlement related to the W.H.

Sammis Plant ($18.5 million) also contributed to the higher FirstEnergy Corp. 2005 19

CUMULATIVE EFFECT OF ACCOUNTING CHANGE Power Supply Other and Results in 2005 include an after-tax charge of $30 million Regulated Management Reconciling FirstEnergy recorded upon the adoption of FIN 47 in December 2005. We 2003 Financial Results ServicesServicesAdjustments Consolidated identified applicable legal obligations as defined under the anmilins)

Revenues:

new standard at our active and retired generating units and External retired plants (retained by the regulated utilities), substation Electric $4,787 $5,418 $ - $10,205 Other 281 69 770 1,120 control rooms, service center buildings, line shops and office Internal 319 - (319) -

buildings, identifying asbestos as the primary conditional Total Revenues 5,387 5,487 451 11,325 ARO. We recorded a conditional ARO liability of $57 million Expenses:

(including accumulated accretion for the period from the date Fuel and purchased power - 4,159 - 4,159 the liability was incurred to the date of adoption), an asset Other operating 1,442 1,723 475 3,640 Claim settlement (168) - - (168) retirement cost of $16 million (recorded as part of the carry- Provision for depredation 538 29 37 604 Amortization of regulatory assets 1,079 - - 1,079 ing amount of the related long-lived asset), and accumulated Deferral of new regulatory assets (194) - - (194) depreciation of $12 million. We charged regulatory liabilities Goodwill impairment - - 91 91 General taxes 540 74 24 638 for $5 million upon adoption of FIN 47 for the transition Total Expenses 3,237 5,985 627 9,849 amounts related to establishing the ARO for asbestos removal from substation control rooms and service center buildings for Operating Income (Loss) 2,150 (498) (176) 1,476 Other Income (Expense):

OE, Penn, CEI, TE and JCP&L. The remaining cumulative Investment income 185 - - 185 effect adjustment for unrecognized depreciation and accretion Interest expense (473) (51) (275) (799)

Capitalized interest 22 7 3 32 of $48 million was charged to income ($30 million, net of Subsidiaries preferred stock dividends (42) - - (42) tax), or $0.09 per share of common stock for the year ended December 31, 2005. (See Note 12.) Total Other Income (Expense) (308) (44) (272) (624)

Income taxes (benefit) 779 (222) (149) 408 Summary of Results of Operations - 2004 compared with 2003 Income before discontinued Financial results for our major business segments for operations and cumulative effect of accounting change 1,063 (320) (299) 444 2004 and 2003 were as follows: Discontinued operations - - (123) (123)

Cumulative effect of accounting Power change 101 - 1 102 SupplyOther and $1,164 S (320) S(421) S 423 RegulatedManagementRecondilingFrstEnergy Net Income (Loss) 2004 Financial Results ServicesServices Adjustment Consolidated On miron) power Revenues: Change Between Supply Other and External 2004 and 2003 Regulated Management Reconciling FirstEnergy Electric $4,701 $6,130 $ - $10,831 Finandial Results Services ServicesAdjustment Consolidated Other 490 74 665 1,229 Internal 318 - (318) -

Inaease (Decrease) On milons)

Revenues:

Total Revenues 5,509 6,204 347 12,060 External Expenses: Electric $ (86) $712 $ - $626 Other 209 5 (105) 109 Fuel and purchased power - 4,469 - 4,469 Internal (1) - 1 -

Other operating 1,602 1,402 370 3,374 Provision for depreciation 513 35 39 587 Total Revenues 122 717 (104) 735 Amortization of regulatory assets 1,166 - - 1,166 Deferral of new regulatory assets (257) - - (257) Expenses:

Goodwill impairment - - 12 12 Fuel and purchased power - 310 - 310 General taxes 572 85 21 678 Other operating 160 (321) (105) (266)

Claim settlement 168 - - 168 Total Expenses 3,596 5,991 442 10,029 Provision for depreciation (25) 6 2 (17)

Amortization of regulatory assets 87 - - 87 Operating Income (Loss) 1,913 213 (95) 2,031 Deferral of new regulatory assets (63) - - (63)

Other Income (Expense): Goodwill impairment - - (79) (79)

Investment income 205 - - 205 (361) (43) (267) (671) General taxes 32 11 (3) 40 Interest expense Capitalized interest 19 6 - 25 Total Expenses 359 6 (185) 180 Subsidiaries' preferred stock dividends (21) - - (21) Operating Income (237) 711 81 555 (158) (37) (267) (462) Other Income (Expense):

Total Other Income (Expense) Investment income 20 - - 20 673 Interest expense 112 8 8 128 Income taxes (benefit) 740 72 (139) Capitalized interest (3) (1) (3) (7)

Income before discontinued Subsidiaries' preferred stock dividends 21 - - 21 operations and cumulative Total Other Income (Expense) 150 7 5 162 effect of accounting change 1,015 104 (223) 896 Discontinued operations - - (18) (18) Income taxes (benefit) (39) 294 10 265 Cumulative effect of accounting change - - - -

Income before discontinued operations and cumulative Net Income (Loss) $1,015 S 104 $(241) $ 878 effect of accounting change (48) 424 76 452 Discontinued operations - - 105 105 Cumulative effect of accounting (

change "°" - (1) (102)

Net Income S(149) $424 $180 $455 20 FirstEnergy Corp. 2005

Regulated Services - 2004 Compared with 2003 the fact that 2004 revenues reflected transactions with MISO, Net income decreased $149 million to $1.02 billion in which began operations in December 2003.

2004, from $1.16 billion in 2003. Income before discontinued operations and the cumulative effect of an accounting change Expenses -

decreased $48 million reflecting the absence in 2004 of the Total operating expenses increased by $359 million in earnings benefit of the 2003 settlement of our claim against 2004 compared to 2003 due to the following:

NRG for the terminated sale of four fossil plants (which resulted in a $168 million gain), partially offset by lower

• Other operating expenses increased $160 million due to interest charges during 2004 due to debt and preferred stock higher transmission expenses of $238 million related to redemption and refinancing activities. the assumption of additional transmission activity from FES discussed above. These higher costs were partially Revenues - offset by lower energy delivery expenses due to reduced Total revenues increased by $122 million in 2004 com- storm restoration costs in 2004, a higher level of con-pared to 2003, resulting from the following sources: struction activities in 2004 compared to a higher level of maintenance activities in the prior year and distribution Increase reliability expenses incurred in the third quarter of 2003; Revenues by Type of Service 2004 2003 (Decrease)

• Additional amortization of regulatory assets of $87 (n milions)

Distribution services $4,701 $4,787 $(86) million, principally from higher Ohio transition plan Transmission services 333 76 257 amortization and a change in amortization resulting Lease revenue from affiliates 318 319 (1)

Other 157 205 (48) from the July 2003 JCP&L rate decision; Total Revenues $5,509 $5,387 $122

• An aggregate increase in Ohio property tax expense and other state taxes of $32 million; and

• The absence in 2004 of the $168 million claim Increases in distribution deliveries by customer class are settlement of our claim against NRG discussed above.

summarized in the following table:

Partially offsetting these higher costs were additional iElectric Distribution Deliveries deferrals of regulatory assets of $63 million, due principally Residential 2.0% to Ohio shopping incentives, and lower depreciation expense Commercial 2.6 Industrial 0.6 of $25 million principally due to the reduced depreciation

, Total Distribution Deliveries 1.6x rates effective in August 2003 in connection with the JCP&L rate case decision. The $48 million decrease in other revenue reflects lower revenues from accounts receivable financing, Lower prices partially offset by higher customer con- JCP&L transition bond securitization and utility property rentals.

sumption and increased shopping incentive deferrals resulted in lower distribution delivery revenues. The following table Other Income -

summarizes major factors contributing to the $86 million Total other income (expense) increased by $150 million decrease in distribution services revenue in 2004: in 2004 compared to 2003 due to the following:

Increase

• Investment income increased approximately $20 million Sources of Change in Distribution Revenues (Decrease) in 2004 due primarily to higher realized gains on (7nminimns)

Changes in customer usage S 82 nuclear decommissioning trust investments.

Changes inprices:

• Lower interest charges of $130 million resulted from Rate changes -

Ohio shopping credit incentives (53) debt and preferred stock redemptions and refinancing JCP&L rate increase 17 Billing component reallocations (132) activities and pollution control note repricings.

Net Decrease in Distribution Revenues $(86)

Power Supply Management Services - 2004 Compared with 2003 Net income for this segment increased by $424 million Lower prices resulted from higher customer shopping to $104 million in 2004 compared to a net loss of $320 million credit incentives, partially offset by higher base rates at in 2003. An improved gross generation margin and lower JCP&L. Energy demand increased in all three retail customer nuclear and fossil operating costs contributed to this increase.

groups, but the milder weather in 2004 moderated the energy needs of residential and commercial customers. The increased Revenues -

shopping incentives provided to customers under the Ohio The change in reported segment revenues resulted transition plan are deferred for future recovery and do not from the following:

affect current period earnings.

Transmission revenues increased by $257 million in 2004 compared to 2003 due in part to the June 2004 amendments to power supply agreements with FES where Met-Ed and Penelec assumed certain transmission activity from FES and FirstEnergy Corp. 2005 21

Increase Increase Revenues by Type of Service 2004 2003 (Decrease) Source of Change in Fuel and Purchased Power (Decrease)

(Inmillions) (inmihions)

Electric generation sales: Fuel:

Retail $3,795 $3,705 $ 90 Change due to unit costs $(43)

Wholesale 2,335 1,713 622 Change due to volume consumed 89 Total electric generation sales 6,130 5,418 712 46 Transmission 39 59 (20)

Other 35 10 25 Purchased Power Change due to unit costs 297 Total Revenues $6,204 $5,487 $717 Change due to volume purchased 153 Increase indeferred costs (33) 417 The higher wholesale revenues were due to higher unit 2003 JCP&L disallowed purchased power costs (153) prices and increased generation available for the wholesale Net Increase inFuel and Purchased Power Costs $310 market which was possible due in part to a 13 % increase in available generation resulting from record production from our generation fleet. Increased retail sales reflected the effect Fuel costs increased primarily from higher nuclear of higher unit prices. The following table summarizes the generation in 2004. Excluding the unusual charge resulting price and volume factors contributing to the increased from the July 2003 JCP&L rate decision, purchased power revenues from retail and wholesale customers. costs increased by $417 million.

Other operating costs decreased $321 million in 2004 Increase Source of Change in Electric Generation Sales (Decrease) compared to 2003. This decrease principally resulted from (InMillions) lower non-fuel nuclear and fossil generation costs. Nuclear Retail: operating costs decreased by $169 million resulting from one Effect of 0.6% decrease incustomer usage $(22)

Change inprices 112 scheduled refueling outage at Beaver Valley Unit 1 in 2004 90 compared to three scheduled refueling outages in 2003 (Beaver Valley Unit 1, Beaver Valley Unit 2 and Perry) and Wholesale:

Effect of 26.7% increase incustomer usage 492 reduced incremental maintenance costs at the Davis-Besse Change inprices 130 Plant related to its restart. Fossil generation expense was $49 622 million lower primarily due to reduced maintenance outages Net Increase inElectric Generation Sales $712 in 2004 compared to the prior year. Lower transmission costs, due to the power supply agreement amendments discussed above, and reduced employee benefit expenses (see POSTRE-The $20 million decrease in transmission revenues relates TIREMENT PLANS) also contributed to the remaining $103 to lower PJM network transmission system revenue, reduced million decrease in other operating costs.

financial transmission rights (FTR)/auction revenue rights (ARR), and PJM congestion credit revenues related to trans- Other - 2004 Compared with 2003 mission transactions that Met-Ed and Penelec assumed in June FirstEnergy's financial results from other operating seg-2004 due to their amended power supply agreement with FES. ments and reconciling adjustments included interest expense on holding company debt, corporate support services revenues Expenses - and expenses, FSG results and results from international busi-Total operating expenses increased by $6 million in 2004 nesses acquired in the 2001 merger. As of January 30, 2004, all compared to 2003. Higher costs for fuel and purchased power, of the international operations were divested. The absence of depreciation and general taxes were almost entirely offset by the EGSA sale loss of $33 million and the Emdersa abandon-lower other operating costs. Fuel and purchased power costs ment charge of $67 million included in the 2003 discontinued increased $310 million, resulting from higher fuel costs of $46 operations losses was a primary cause of the $180 million million and increased purchased power costs of $264 million. increase in net income in 2004 compared to 2003. In addition, Factors contributing to the higher costs are summarized in the an $86 million decrease in FSG goodwill impairment charges following table: in 2004 compared to 2003 (see Note 2(H)) was the other pri-mary factor in the net income increase.

CUMULATIVE EFFECT OF ACCOUNTING CHANGE Results in 2003 included an after-tax credit to income of $102 million recorded upon the adoption of SFAS 143 in January 2003. We identified applicable legal obligations as defined under SFAS 143 for nuclear power plant decommis-sioning, reclamation of a sludge disposal pond at the Bruce Mansfield Plant and two coal ash disposal sites. As a result of adopting SPAS 143 in January 2003, asset retirement costs of

$602 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation 22 FirstEnergy Corp. 2005

of $415 million. The ARO liability at the date of adoption Postretirement Expenses 2005 2004 2003 was $1.11 billion, including accumulated accretion for the an mllons) period from the date the liability was incurred to the date Pension $ 32 S 83 $123 OPEB 72 87 156 of adoption. As of December 31, 2002, we had recorded Total $104 $170 $279 decommissioning liabilities of $1.24 billion. We expect substantially all of our nuclear decommissioning costs for Met-Ed, Penelec and JCP&L to be recoverable in rates over Pension and OPEB expenses are included in various cost time. Therefore, we recognized a regulatory liability of $185 categories and have contributed to cost decreases discussed million upon adoption of SFAS 143 for the transition amounts above for 2005. We made an additional $500 million volun-related to establishing the ARO for nuclear decommissioning tary contribution to our pension plan in the fourth quarter for those companies. The remaining cumulative effect of 2005 that is expected to result in reduced pension costs in adjustment for unrecognized depreciation and accretion, 2006 and 2007 compared to costs that would have otherwise offset by the reduction in the existing decommissioning resulted without the voluntary contribution. In 2008, we liabilities and the reversal of accumulated estimated removal will increase retirees' share of their coinsurance, as well as costs for non-regulated generation assets, was a $175 million increase retirees' health care premiums, which will reduce increase to income, or $102 million net of income taxes. OPEB costs in 2006 and 2007. See "Critical Accounting Policies - Pension and Other Postretirement Benefits DISCONTINUED OPERATIONS Accounting" for a discussion of the impact of underlying Discontinued operations for 2005 include the divestiture assumptions on postretirement expenses.

of two FSG subsidiaries: Elliott-Lewis Corporation and L. H.

Cranston and Sons, Inc.; the divestiture of an MYR subsidiary SUPPLY PLAN

- Power Piping Company; and the sale of FES' natural gas Our affiliates are obligated to provide generation service business. The operating results for these divested businesses with an estimated power demand of 101.2 billion KWH for were adjusted in the presentation for prior years. 2006. These obligations arise from customers who have elected In 2003, the results of certain FSG subsidiaries to continue to receive generation service from our utility (Colonial Mechanical, Webb Technologies and Ancoma, Inc.) subsidiaries under regulated retail tariffs and from customers and MARBEL's subsidiary, which were divested in 2003, who have selected FES as their alternate generation provider.

were reported as discontinued operations. In addition, 2003 Geographically, approximately 65 % of the total generation discontinued operations were reflected for Emdersa and service obligation is for customers located in the MISO market EGSA, as we substantially completed our exit from foreign area and 35 % for customers located in the PJM market area.

operations acquired through the merger with GPU in 2001. Included in the PJM market area are obligations of FES to pro-vide power to electric distribution customers in the State of The following table summarizes the sources of income New Jersey, including customers in JCP&L's service territory.

(losses) from discontinued operations: FES incurred this obligation as a successful bidder in the State of NewJersey's auction of BGS.

• Discontinued Operations (Net of tax) 2005 2004 2003 Within the franchise territories of our utilities, alternative (nmullions) energy suppliers currently provide generation service for Emdersa - abandonment $- $- $ (67) approximately 100 MW (summer peak) of load with an estimated EGSA - loss on sale - - (33)

FES natural gas business - gain on sale 5 - energy requirement of 0.8 billion KWH. If these alternate FSG and MYR subsidiaries - gain (loss) on sale 12 - (3) suppliers fail to deliver power to their customers located in Total gain (loss) on divestitures 17 - (103) the utility's service area, the utility must procure replacement i Redassification of operating income (loss) to discontinued operations: power in the role of PLR (see Note 10 for discussion of the iFES natural gas business - 4 (2) auction of JCP&L's PLR obligation). JCP&L's costs for any iFSG and MYR subsidiaries 1 (22) (22)

Emdersa, EGSA and NEO - - 4 replacement power would be recovered under NJBPU rules.

Income (loss) from discontinued operations $18 S(18) $(123) To meet these generation service obligations, our affiliates own and operate 13,427 MW of installed generating capacity, which for 2006 is expected to provide approximately 80 % of POSTRETIREMENT PLANS the required power supply. The balance has been secured Strengthened equity markets, as well as a $500 million through a combination of long-term purchases (contract term voluntary cash pension contribution made in September 2004, of greater than one year) and short-term purchases (contract contributed to a $66 million reduction of postretirement of term of less than one year). Additional power supply benefits expenses in 2005 from the prior year. Improved equity requirements will be met through spot market transactions.

markets and amendments to our health care benefits plan in the first quarter of 2004 and the Medicare Act signed by President PJM INTERCONNECTION TRANSACTIONS Bush in December 2003 combined to reduce postretirement FES engages in purchase and sale transactions in the PJM benefits expenses by $109 million in 2004 from the prior year. Market to support the supply of end-use customers, including The following table reflects the portion of postretirement costs PLR requirements in Pennsylvania. In conjunction with our that were charged to expense in 2005, 2004 and 2003: dedication of the Beaver Valley Plant to PJM on January 1, 2005, FES began accounting for purchase and sale transactions FirstEnergy Corp. 2005 23

in the PJM market based on its net hourly position - recording Cash earnings (in the table above) are not a measure of each hour as either an energy purchase or an energy sale in performance calculated in accordance with GAAP. We believe the Consolidated Statements of Income relating to the Power that cash earnings is a useful financial measure because it pro-Supply Management Services segment. Hourly energy posi- vides investors and management with an additional means of tions are aggregated to recognize gross purchases and sales for evaluating our cash-based operating performance. The follow-the month. This revised method of accounting, which has no ing table reconciles cash earnings with net income:

impact on net income, is consistent with the practice of other energy companies that have dedicated generating capacity in Reconciliation of Cash Earnings 2005 2004 2003 PJM and correlates with PJM's scheduling and reporting of (inmillions)

Net Income (GAAP) $ 861 $ 878 $ 423 hourly energy transactions. FES also applies the net hourly Non-Cash Charges (Credits):

methodology to purchase and sale transactions in MISO's Provision for depreciation 589 587 604 Amortization of regulatory assets 1,281 1,166 1,079 energy market, which became active on April 1, 2005. Deferral of new regulatory assets (405) (257) (194)

Nuclear fuel and lease amortization 90 96 66 Deferred purchased power and other costs (384) (451) (459)

CAPITAL RESOURCES AND LIQUIDITY Deferred income taxes and investment tax credits* 154 58 (18)

Our cash requirements in 2005 for operating expenses, Investment impairments 15 30 135 construction expenditures, scheduled debt maturities and pre- Disallowed rerulaory assets - - 153 Cumulative effect o accounting changes 30 - (102) ferred stock redemptions were met without increasing our net Deferred rents and lease market valuation liability (104) (84) (119)

Accrued compensation and retirement benefits 90 156 202 debt and preferred stock outstanding. During 2006, we expect Amortization of electric service program (34) (18) (16) to meet our contractual obligations primarily with cash from Loss (income) from discontinued operations (18) 18 123 Other non-cash expenses 23 18 (4) operations. Borrowing capacity under credit facilities is avail-able to manage working capital requirements. In subsequent Cash Earnings (Non-GAAP) $2,188 $2,197 $1,873 years, we expect to use a combination of cash from operations *Erdudes5$200million of deWrred tar benefitfrom pension contibutions in2004.

and funds from the capital markets.

Net cash provided from operating activities increased Changes in Cash Position $328 million in 2005 compared to 2004 primarily due to a Our primary source of cash required for continuing opera- $378 million increase from changes in working capital and tions as a holding company is cash from the operations of our a $9 million decrease in cash earnings as described under subsidiaries. We also have access to $2.0 billion of short-term "Results of Operations". In 2005 and 2004, we made volun-financing under a revolving credit facility which expires in tary after-tax pension trust contributions of $341 million and 2010, subject to short-term debt limitations under current reg- $300 million, respectively. The increase from working capital ulatory approvals of $1.5 billion and to outstanding borrowings resulted from increased returned cash collateral of $259 mil-by subsidiaries of FirstEnergy that are also parties to such lion, decreased outflow of $143 million for payables and $242 facility. In 2005, we received $1.3 billion of cash dividends million of funds received in 2005 for prepaid electric service from our subsidiaries and paid $546 million in cash dividends (under a three-year Energy for Education Program with the to our common shareholders. There are no material restric- Ohio Schools Council). These increases were partially offset tions on the payment of cash dividends by our subsidiaries. by decreases in cash provided from the settlement of receiv-As of December 31, 2005, we had $64 million of cash and ables of $241 million and the absence of a $53 million NUG cash equivalents compared with $53 million as of December power contract restructuring transaction in 2005.

31, 2004 (each includes $3 million restricted as an indemnity Net cash provided from operating activities increased reserve). The major sources for changes in these balances are $115 million in 2004 compared to 2003 due to a $324 million summarized below. increase in cash earnings as described under "Results of Operations" and a $91 million increase from changes in Cash Flows From OperatingActivities working capital, partially offset by a $300 million after-tax Our consolidated net cash from operating activities is voluntary pension trust contribution. The increase from provided primarily by our regulated services and power supply working capital changes resulted in part from increases in management services businesses (see Results of Operations - cash provided from the settlement of receivables of $88 million Business Segments above). Net cash provided from operating and prepayments and other current assets of $78 million, activities was $2.2 billion in 2005, $1.9 billion in 2004 and decreased outflow of $59 million in payables and a $53 million

$1.8 billion in 2003, summarized as follows: NUG power contract restructuring transaction, partially offset by an increased outflow of $235 million for tax payments.

Operating Cash Flows 2005 2004 2003 (Inmillions) Cash Flows From FinancingActivities Cash earningsM1' $2,188 $2,197 $1,873 Pension trust contributions2 (341) (300) - In 2005, 2004 and 2003, net cash used for financing Working capital and other 373 (5) (96) activities was $876 million, $1.5 billion and $1.3 billion, Net cash provided from operating activities $2,220 $1,892 $1,777 respectively, primarily reflecting the redemptions of debt

) Coashearnings are aNon-G4AP measure (see reconcilation below). and preferred stock shown below:

WPension trust contributins in 2005 and 2004 are net of $159 milion and $200 million of related current year cash income tar benefits respectide 24 FirstEnergy Corp. 2005

Securities Issued or Redeemed 2005 2004 2003 debt was issued) as of December 31, 2005. CEI, Met-Ed and (In milions) Penelec do not have similar restrictions and could issue up to New Isues

$ 934 the number of preferred stock shares authorized under their Common stock S - $ -

Pollution control notes 721 261 - respective charters (see Note 11(B)).

Senior secured notes - 300 400 Unsecured notes - 400 627 As of December 31, 2005, approximately $1 billion of capacity remained unused under an existing shelf registration

$ 721 $ 961 $1,961 statement, filed by FirstEnergy with the SEC in 2003, to Redemptions support future securities issuances. The shelf registration FMB $ 252 $ 589 $1,483 Pollution control notes 555 80 238 provides the flexibility to issue and sell various types of Senior secured notes 94 471 323 Long-term revolving credit 215 95 85 securities, including common stock, debt securities, and Unsecured notes 308 337 - share purchase contracts and related share purchase units.

Preferred stock 170 2 127 Our working capital and short-term borrowing needs

$1,594 $1,574 $2,256 are met principally with a $2 billion five-year revolving credit Short-term borrowings, net $ 561 S (351) $ (575) facility (included in the table above). Borrowings under the facility are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the We had approximately $731 million of short-term indebted- commitment expiration date, June 16, 2010.

ness as of December 31, 2005 compared to approximately $170 The following table summarizes the borrowing sub-limits million as of December 31, 2004. The increase in short-term for each borrower under the facility, as well as the limitations indebtedness in 2005 was due to funding the $341 million after- on short-term indebtedness applicable to each borrower under tax pension trust contribution and refinancing a $300 million current regulatory approvals and applicable statutory and/or senior note in the fourth quarter of 2005. In addition, an off- charter limitations:

balance sheet receivables financing agreement was renewed as an on-balance sheet short-term debt financing agreement in Revolving Regulatory and Credit Facility Other Short-Term June 2005 that had a $140 million indebtedness balance as of Borrower Sub-ULmit Debt Limitations(s)

December 31, 2005. Available consolidated bank borrowing ain mil/ions) capacity as of December 31, 2005 included the following: FirstEnergy $2,000 $1,500 OE 500 500 Penn 50 44 Borrowing Capability CEI 250 500 (inmillions) TE 250 500 Short-term credit fadlities(') $2,020 JCP&L 425 412 Accounts receivable financing facilities 550 Met-Ed 250 300 (718) Penelec 250 300 Utilized FES -nia Letters of credit (101)

ATSI -. ') 26 Net $1,751

(')As of December31, 2005

(°)A $2billion revyrng credit ferihty that expires in 2010isovailable inwrnous amounts to 0tZBorrowing sub-limits for FES and ATSl maybe increased to up to $250 mi/lion and$S100Mn604 frstEnergy and certain ofits subsidiaries. A$20 million uncommitted line of creditfoility added respecive by delivering notice to the administrative agent that either (i such borrower has inSeptember 2005 isavailable to FirstEnergy only senior unsecured debt ratings of at least BB- by S&P andBaa3 by Moodys or ) FirstEnergy has guaranteed the obligations of such borrawer under the faciity As of December 31, 2005, the Ohio Companies and Penn The revolving credit facility, combined with an aggregate had the aggregate capability to issue approximately $1.2 billion $550 million ($270 million unused as of December 31, 2005) of additional FMB on the basis of property additions and retired of accounts receivable financing facilities for OE, CEI, TE, bonds under the terms of their respective mortgage indentures.

Met-Ed, Penelec and Penn, are intended to provide liquidity to The issuance of FMB by OE and CEI are also subject to provi-meet short-term working capital requirements for FirstEnergy sions of their senior note indentures generally limiting the and its subsidiaries, incurrence of additional secured debt, subject to certain excep-Under the revolving credit facility, borrowers may request tions that would permit, among other things, the issuance of the issuance of LOCs expiring up to one year from the date of secured debt (including FMB) (i) supporting pollution control issuance. The stated amount of outstanding LOCs will count notes or similar obligations, or (ii) as an extension, renewal against total commitments available under the facility and or replacement of previously outstanding secured debt. In against the applicable borrower's borrowing sub-limit. Total addition, these provisions would permit OE and CEI to incur unused borrowing capability under existing credit facilities additional secured debt not otherwise permitted by a specified and accounts receivable financing facilities was $1.75 billion exception of up to $651 million and $582 million, respectively, as of December 31, 2005.

as of December 31, 2005. Under the provisions of its senior The revolving credit facility contains financial covenants note indenture, JCP&L may issue additional FMIB only as requiring each borrower to maintain a consolidated debt to collateral for senior notes. As of December 31, 2005,JCP&L total capitalization ratio of no more than 65 %, measured at had the capability to issue $715 million of additional senior the end of each fiscal quarter.

notes upon the basis of FMB collateral.

Based upon applicable earnings coverage tests in their respective charters, OE, Penn, TE and JCP&L could issue a total of $5.5 billion of preferred stock (assuming no additional FirstEnergy Corp. 2005 25

As of December 31, 2005, FirstEnergy and its FirstEnergy's access to capital markets and costs of subsidiaries' debt to total capitalization ratios (as defined financing are influenced by the ratings of its securities. The under the revolving credit facility) were as follows: following table displays FirstEnergy's and the Companies' securities ratings as of December 31, 2005. The ratings out-Borrower look from S&P on all securities is stable. The ratings outlook FirstEnergy 55% from Moody's & Fitch on all securities is positive.

OE 38%

Penn 42%

CEI 53% Issuer Securities S&P Moody's Fitch TE 28%

JCP&L 26% FirstEnergy Senior unsecured BBB- Baa3 BBB-Met-Ed 39%

Penelec 36% OE Senior unsecured BBB- Baa2 BBB Preferred stock BB+ Bal BBB-CEI Senior secured BBB Baa2 BBB-Senior unsecured BBB- Baa3 BB+

The revolving credit facility does not contain provisions that either restrict the ability to borrow or accelerate repay- TE Senior secured BBB Baa2 BBB-Preferred stock BB+ Ba2 BB ment of outstanding advances as a result of any change in credit ratings. Pricing is defined in "pricing grids", whereby Penn Senior secured BBB+ Baal BBB+

Senior unsecured(' BBB- Baa2 BBB the cost of funds borrowed under the facility is related to the Preferred stock BB+ Bal BBB-credit ratings of the company borrowing the funds. JCP&L Senior secured BBB+ Baal BBB+

Our regulated companies also have the ability to borrow Preferred stock BB+ Bal BBB-from each other and the holding company to meet their short- Met-Ed Senior secured BBB+ Baal BBB+

Senior unsecured BBB Baa2 BBB term working capital requirements. A similar but separate arrangement exists among our unregulated companies. FESC Penelec Senior unsecured BBB Baa2 BBB administers these two money pools and tracks surplus funds (') Penn's onusenorurneddebtobhgoaons are notes undedgpoUocontrol revenue I refunding bonds issuedby the O Air QuolyD evelopmntAuttyto which bonds E rot-of FirstEnergy and the respective regulated and unregulated 0ig applies subsidiaries, as well as proceeds available from bank borrow-ings. Companies receiving a loan under the money pool On January 20, 2006, TE redeemed all 1.2 million of its agreements must repay the principal amount of the loan, outstanding shares of Adjustable Rate Series B preferred stock together with accrued interest, within 364 days of borrowing at $25.00 per share, plus accrued dividends to the date of the funds. The rate of interest is the same for each company redemption.

receiving a loan from their respective pool and is based on the FirstEnergy will consider a share repurchase program average cost of funds available through the pool. The average later in 2006 after we gain additional clarity on three interest rate for borrowings in 2005 was 3.24 % for the regu- important milestones:

lated companies' money pool and 3.22 % for the unregulated companies' money pool.

• The approval of the RCP by the PUCO (received in On December 16, 2005, in conjunction with the intra- January 2006);

system generation asset transfers, FirstEnergy made a $750

• Completion of the Beaver Valley Unit 1 extended million cash capital contribution to NGC. NGC used the outage; and proceeds from the capital contribution to pre-pay a portion

• Finalization of our environmental compliance plan of the promissory notes to CEI and TE for $375 million each. for our fossil plants.

(See Note 15.)

On July 18, 2005, Moody's revised its rating outlook Cash Flows From Investing Activities on FirstEnergy and its subsidiaries to positive from stable. Net cash flows used in investing activities resulted princi-Moody's stated that the revision to FirstEnergy's outlook pally from property additions. Regulated services expenditures resulted from steady financial improvement and steps taken for property additions primarily include expenditures supporting by management to improve operations, including the stabiliza- the distribution of electricity. Capital expenditures by the tion of its nuclear operations. On October 3, 2005, S&P raised power supply management services segment are principally its corporate credit rating on FirstEnergy and the Companies generation-related. The following table summarizes investments to 'BBB' from 'BBB-'. At the same time, S&P raised the senior for the three years ended December 31, 2005 by our regulated unsecured ratings at the holding company to 'BBB-' from services, power supply management services and other segments:

'BB +' and each of the Companies by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter of 2005.

On December 23, 2005, Fitch revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Fitch stated that the revision to FirstEnergy's outlook resulted from improved performance of the Company's generating fleet and ongoing debt reduction.

26 FirstEnergy Corp. 2005

Summary of Cash Flows Guaranteesand Other Assurances Used for Investing Property As part of normal business activities, we enter into Activities By Segtient Additions Investments Other Total various agreements on behalf of our subsidiaries to provide 2005 Sources (Uses) On mfllions)

Regulated services $ (788) $(106) $(14) S (908) financial or performance assurances to third parties. These Power supply management services (375) (21) 5 (391) agreements include contract guarantees, surety bonds, and Other (8) 18 (21) (11)

Reconciling adjustments (37) . 8 6 (23) LOCs. Some of the guaranteed contracts contain collateral Total $(1,208) S(101) $(24) $(1,333) provisions that are contingent upon our credit ratings.

As of December 31, 2005, our maximum exposure 2004 Sources (Uses)

Regulated services S (572) S 184 $(88) $ (476) to potential future payments under outstanding guarantees Power supply management services (246) (13) (2) (261) and other assurances totaled approximately $3.4 billion, Other (7) 175 (4) 164 Reconciling adjustments (21) (2) 100 77 as summarized below:

Total S (846) S 344 $ 6 S (496) F and Other Assurances Maximum Exposure I Guarantees 2003 Sources (Uses) (Inmillions)

Regulated services S (434) S 94 S 16 S (324) FirstEnergy Guarantees of Subsidiaries Power supply management services (335) (32) 8 (359) Energ2 and Energy-Related Contracts(M $ 832 Other (10) 34 (83) (59) Other% 894 Reconciling adjustments (77) 90 138 151 1,726 Total S (856) S 186 S79 $ (591)

.SuretyBonds 312 LOC( 1,324 Net cash used for investing activities in 2005 increased Total Guarantees and Other Assurances $3,362 by $837 million from 2004. The increase was principally due s) for open-ended terms,ith a day termination nghtbyFirstEnergy ksued to a $362 million increase in property additions, a $153 mil- 1)Issued for various temns lion decrease in proceeds from asset sales (see Note 8) and the 0)Includes $101 million issued for various terms under LOC capao*avoiwobk in frstEners mnsng credit agreement and $604 mi/hon outstanding insupport of pollution co" revenue absence in 2005 of cash proceeds of $278 million from certifi- bonds issued Mithvanous matuities cates of deposit (CD) received in 2004 when the CDs were no Iucese approimtel S194 mifflion pledged inconnection ivith the sale andleosebock of f Beaverliok Unit 2 by CEIand 1E$291 million pedged in connection AS Mtesale and ke-longer required as OE sale leaseback LOC collateral. boot of Bettver Valley U~nk2 by OE andS134mfflion pledgd in tampecion MM the safe end Net wit used for investing activities in 2004 decreased kosebod ofPen7y Unit by OE.

by $95 millioiifrom 2003. The decrease was primarily due to

$278 million ftom certificates of deposit cash proceeds, par- We guarantee energy and energy-related payments of our tially offset by I $117 million change in NUG trust activity. subsidiaries involved in energy commodity activities principally Our capital spending for the period 2006-2010 is expected to facilitate normal physical transactions involving electricity, to be about $6.7 billion (excluding nuclear fuel), of which $1 gas, emission allowances and coal. We also provide guarantees billion applies to 2006. Investments for additional nuclear fuel to various providers of subsidiary financing principally for during the 2006-2010 period are estimated to be approximate- the acquisition of property, plant and equipment. These ly $711 million, of which about $169 million applies to 2006. agreements legally obligate us to fulfill the obligations of our During the same period, our nuclear fuel investments are subsidiaries directly involved in these energy and energy-relat-expected to be reduced by approximately $560 million and ed transactions or financings where the law might otherwise

$92 million, respectively, as the nuclear fuel is consumed. limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing CONTRACTUAL OBLIGATIONS obligations, our guarantee enables the counterparty's legal As of December 31, 2005, out estimated cash payments claim to be satisfied by our other assets. The likelihood that under existing contractual obligatioMs that we consider firm such parental guarantees will increase amounts otherwise obligations are as follows: - paid by us to meet our obligations incurred in connection with ongoing energy and energy-related contracts is remote.

2007- 2bM- While these types of guarantees are normally parental Contractual Obligations " Total 2006 2008 201o JTherafter 20 commitments for the future payment of subsidiary obligations, (7nmnilons) .

Long-term debt"l $10,200 $1,324 $ 560 S 467 5-71p4 subsequent to the occurrence of a credit rating downgrade or Short-term borrowings 731 731 - - "mato,,, adverse event" the immediate posting of cash collat-Capital leasesW2) 13 5 2 2 4 Operating leases(2) 2,356 202 397 399 1,358 _5319 or provision of an LOC may be required of the subsidiary.

Pension funding3) - - - - _

- Fuel and purchased power(

4 15,105 2,844 ,4,715 3,880 3,666 The followilgs table summarizes collateral provisions in effect Total $28,405 $5,106 $5,674 $4,748 $12,877 as of December 31, 2005:

IVAmounts reflecteddo not include interest on longterm debt

• See Note 6 to the consolidated finonda lstotemne&t 0)Weestimate that no further pension contributions wil be required through 2010 to maintain our demined enefit pension pon's funding at amdinimun required evel as determinedhby i government regulaons. Weare unable to estimate projected contubutions beyond 201 1.

See Note 3 to the consolidated financial stotement (4 Amounts under contract fith fixed or minimum quantities and oppiroimate timing.

. FEnergy Corp. 2005 27

Collateral Paid including forward contracts, options, futures contracts and Total Remaining:

Collateral Provisions Exposure Cash LOC Exposure swaps. The derivatives are used principally for hedging (Inmilions) purposes. Derivatives that fall within the scope of SFAS 133 Credit rating downgrade $380 $78 $- $302 l must be recorded at their fair value and marked to market.

Material adverse event 74 - - 74 The majority of our derivative hedging contracts qualify for Total $454 $78 $- $376 the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the table below.

Contracts that are not exempt from such treatment include Most of our surety bonds are backed by various indemni-power purchase agreements with NUG entities that were ties common within the insurance industry. Surety bonds and structured pursuant to the Public Utility Regulatory Act of related guarantees provide additional assurance to outside 1978. These non-trading contracts are adjusted to fair value parties that contractual and statutory obligations will be at the end of each quarter, with a corresponding regulatory met in a number of areas including construction contracts, asset recognized for above-market costs. The change in the environmental commitments and various retail transactions.

fair value of commodity derivative contracts related to energy We have guaranteed the obligations of the operators of the production during 2005 is summarized in the following table:

TEBSA project up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance Increase (Decrease) in the agreement. In connection with the sale of TEBSA inJanuary Fair Value of Derivative Contracts Non-Hedge Hedge Total 2004, the purchaser indemnified FirstEnergy against any loss Change In the fair value of (in milions) commodity derivative contracts:

under this guarantee. We have also provided an LOC ($36 mil- Outstanding net asset (liability) lion as of December 31, 2005), which is renewable and declines as of January 1, 2005 $(1,939) $ 2 $(1,937)

New contract value when entered I - - -

yearly based upon the senior outstanding debt of TEBSA. Additionslchange invalue of existing contracts 452 3 455 Change in techniques/assumptions - - -

Settled contracts 316 (2) 314 OFF-BALANCE SHEET ARRANGEMENTS Sale of retail natural gas contracts 1 (6) (5)

We have obligations that are not included on our Outstanding net asset (liability)

Consolidated Balance Sheets related to the sale and leaseback as of December 31, 2005(1) (1,170) (3) (1,173) arrangements involving Perry Unit 1, Beaver Valley Unit 2 Non-commodity net assets as of December 31, 2005:

and the Bruce Mansfield Plant, which are satisfied through Interest rate swaps") - (21) (LI) operating lease payments. The present value of these sale and Net Assets (Liabilities) - Derivative leaseback operating lease commitments, net of trust invest- Contracts as of December 31, 2005 $(1,170) $(24) $(1,194) ments, total $1.3 billion as of December 31, 2005. Impact of Changes in Commodity We have equity ownership interests in certain businesses Derivative Contracts3 Income Statement effects (Pre-Tax) $ 12 $ - $ 12 that are accounted for using the equity method. There are no Balance Sheet effects: - /

undisclosed material contingencies related to these invest- OCI (Pre-Tax) $ ' $ (5) S (5)

Regulatory asset (net) $ (754 $ - $ (757) ments. Certain guarantees that we do not expect will have a (1) Jnchidp(I IA?mi inn in nn hAedo Aod,ti,* mntmi, rnn. hA, A l ICA

.nmmnMmv i

material current or future effect on our financial condition, wihare offiet by a wegulhofty asset liquidity or results of operations are disclosed under lntst rnte swapsarreeated ascsh flow orfair value hedges(see Interest Rote Swna Guarantees and Other Assurances above. Agreement Woew).

0)Represent the change invlue of esting contracsdekd contracts and changes in In June 2005, the CFC accounts receivables financing techniqueVassumptons.

facility for CEI and TE was renewed and restructured from an off-balance sheet transaction to an on-balance sheet trans- Derivatives are included on the Consolidated Balance action. Under the revised facility, any borrowings by CFC Sheet as of December 31, 2005 as follows:

appear on our Consolidated Balance Sheets as short-term debt.

Balance Sheet Classiflcation Non-Hedge Hedge Total X MARKET RISK INFORMATION (inMnAions)

We use various market risk sensitive instruments, Current- .

Other assets $ 4 $ 15 $ 191 including derivative contracts, primarily to manage the 9tlr liabilities (2) (19) (21)W risk of price and interest rate fluctuations. Our Risk Policy Nan-Current-Committee, comprised of members of senior managerrrjlj~-x. Other deferred charges 69 5 74

- Other noncurrentlia ilities (1,241) (25) (1,266) provides general oversight to risk management activities throughout the Company. Net assets (liabilities) $(1,170) $(24) $(1,194)

Commodity Price Risk The valuation of derivative contracts is based on observ-We are exposed to financial and inarket risks resulting able market information to the extent that such information from the fluctuation of interest rateS and commodity prices is available. In cases where such information is not available, primarily due to fluctuations ineiectricity, energy transmis-we rely on model-based information. The model provides esti-sion, natural gas, coal, nuclear fuel and emission allowance mates of future regional prices for electricity and an estimate prices. To manage the vbiatility relating to these exposures, of related price volatility. We use these results to develop esti-we use a variety of ncn-derivative and derivative instruments, mates of fair value for financial reporting purposes and for 28 FirstEnergy Corp. 2005 /

internal management decision making. Sources of information an earnings effect from fluctuations in their decommissioning for the valuation of commodity derivative contracts by year trust balances. As of December 31, 2005, our decommissioning are summarized in the following table: trust balances totaled $1.8 billion, with $1.3 billion held by NGC and our Ohio Companies and the remaining balance held Source of Information -Fair Value by Contract Year by JCP&L, Met-Ed and Penelec. As of year-end 2005, the trust 2006 2007 2008 2009 2010 Thereafter Total balances of NGC and our Ohio Companies were comprised of IIn millions) 61 % equity securities and 39 % debt instruments.

IPrices actively quoted(') $(278) 1(297) $ $- - $ - $ - $ (575)

! Other external sources2) 21 10 - - - - 31 Prices based on models - - (260) (179) (142) (48) (629) Interest Rate Swap Agreements - FairValue Hedges TOWaP) $(257) $(287) X(260) $(179) $(142) $(48) $(1,173) We utilize fixed-for-floating interest rate swap agreements as part of our ongoing effort to manage the interest rate risk Excange traded.

v Broker quote sheens associated with our debt portfolio. These derivatives are treat-r) inddes $1res mllion innon-hedge commodiy dereatie contracts pnmarnl imth lNUGs), ed as fair value hedges of fixed-rate, long-term debt issues -

which are offset byae reglatory rsset protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap We perform sensitivity analyses to estimate our exposure maturities, call options, fixed interest rates and interest pay-to the market risk of our commodity positions. A hypothetical ment dates match those of the underlying obligations. During 10 % adverse shift (an increase or decrease depending on the 2005, we entered into interest rate swap agreements on $150 derivative position) in quoted market prices in the near term million notional amount of senior notes with a weighted on our derivative instruments would not have had a material average fixed interest rate of 6.59 %. In addition, we unwound effect on our consolidated financial position (assets, liabilities swaps with a total notional amount of $700 million from and equity) or cash flows as of December 31, 2005. Based on which we received $16 million in cash gains during 2005.

derivative contracts held as of December 31, 2005, an adverse The gains will be recognized over the remaining maturity of 10 % change in commodity prices would decrease net income each respective hedged security as reduced interest expense.

by approximately $4 million for the next twelve months. As of December 31, 2005, the debt underlying the $1.1 billion outstanding notional amount of interest rate swaps had a Interest Rate Risk weighted average fixed interest rate of 5.71 %, which the Our exposure to fluctuations in market interest rates swaps have effectively converted to a current weighted is reduced since a significant portion of our debt has fixed average variable rate of 5.63 %.

interest rates, as noted in the table below.

December 31, 2005 December 31, 2004 Comparison of Carrying Value to Fair Value Notional Maturity Fair Notional Maturity Fair There- Fair Interest Rate Swaps Amount Date Value Amount Date Value Year of Maturity 2006 2007 2008 2009 2010 after Total Value (Inmillions)

(Dollrsinmllions) Fixed to Floating Rate $ - 2006 $ - $ 200 2006 $(1)

(Fair value hedges)

Assets 100 2008 (3) 100 2008 (1)

Investments other 50 2010 - 100 2010 1 than Cash and Cash 50 2011 - 100 2011 2 Equivalents-Fixed Income $ 96 S 77 $ 57 S 68 $ 84 $1,648 $2,030 $2,135 450 2013 (4) 400 2013 4 Average interest rate 6.8l 7.9% 7.7' 7.8' 7.9% 5.9' 6.2' - 2014 - 100 2014 2 LiabilIties 150 2015 (9) 150 2015 (7)

Long-term Debt and Other 150 2016 - 200 2016 1 Long-term Obligations

- 2018 - 150 2018 5 Fixed rated $1,324 $229 $331 $278 $189 $5,956 $8,307 $8,824 - 2019 - 50 2019 2 Average interest rate 5.7' 6.6% 5.3' 6.8' 5.4% 6.5' 6.3' 50 2025 (1) - 2025 -

Variable rate10 $1,893 $1,893 $1,892 100 2031 (5) 100 2031 (4)

Average interest rate 3.3% 3.3%

Short-tenm Borrowings $ 731 $731 S 731 $1,100 $(22) $1,650 14 Average interest rate 4.7' 4.7%

( Balarnesand rates do not reflect the frxeda4floating interestrateswap agreements discussed below ForwardStarting Swap Agreements - Cash Flow Hedges During 2005, we entered into several forward starting We are subject to the inherent interest rate risks related to swap agreements (forward swaps) in order to hedge a portion refinancing maturing debt by issuing new debt securities. As of the consolidated interest rate risk associated with the future discussed in Note 6 to the consolidated financial statements, planned issuances of fixed-rate, long-term debt securities for our investments in capital trusts effectively reduce future lease one or more of our consolidated entities in 2006 through obligations, also reducing interest rate risk. Fluctuations in the 2008. These derivatives are treated as cash flow hedges, fair value of NGC's and the Ohio Companies' decommissioning protecting against the risk of changes in future interest pay-trust balances will eventually affect earnings (affecting OCI ments resulting from changes in benchmark U.S. Treasury initially) based on the guidance in SFAS 115. Our rates between the date of hedge inception and the date of the Pennsylvania and New Jersey companies, however, have the debt issuance. As of December 31, 2005, we had entered into opportunity to recover from customers, or refund to customers, forward swaps with an aggregate notional amount of $975 the difference between the investments held in trust and their million. As of December 31, 2005 the forward swaps had a decommissioning obligations. Thus, there is not expected to be fair value of $3 million.

FirstEnergy Corp. 2005 29

December 31, 2005 I Regulatory Assets Inarease lJ As of December 31 2005 2004 (Decrease)

Forward Starting Swaps Notional Maturity Fair (Cash flow hedges) Amount Date Value (in mdhaons)

OE $ 775 $1,116 $ (341)

(n mflibns) ' CEI 862 944 (82)

$ 25 2015 I TE 287 366 (79) i 600 2016 2 JCP&L 2,227 2,169 58 25 2017 - Met-Ed 310 691 (381) 275 2018 1 1 Penelec - 200 (200) 50 2020 - I ATSI 25 13 12

$975 $3 Total $4,486 $5,499 $(1,013)

Penn hodnet mulatorty Wities of awcolmately $59 milion and $19 milaon as ofDecember 31, 2005 Ond 2004 respecdiwf4 dianges inPenele's net regidatory asset components in2005 Equity Price Risk resuftedin ithating netreguatoryliabitofs appmmately $163 mriffon as of Decernber3l, 2005 These net regultoryiabtes are inkidedin OteruNonrentLiabdioes an Mhe Included in nuclear decommissioning trusts are mar- ConsolidatedBalance Sheets as of December31, 2005 and2004.

ketable equity securities carried at their current fair value of approximately $1.1 billion and $951 million as of December Regulatory Assets By Source Increase I As of December 31 2005 2004 (Decrease) 31, 2005 and 2004, respectively. A hypothetical 10 % decrease ain milions) in prices quoted by stock exchanges would result in a $107 Regulatory transition costs $3,576 $4,889 S(1,313) million reduction in fair value as of December 31, 2005 (see Customer shopping incentives 884 612 272 Customer receivables for future income taxes 217 246 (29)

Note 5 - Fair Value of Financial Instruments). Societal benefits charge 29 51 (22)

Loss on reacquired debt 41 56 (15)

Employee postretirement benefits costs 55 65 (10)

CREDIT RISK Nudear decommissioning, decontamination and spent fuel disposal costs (126) (169) 43 Credit risk is the risk of an obligor's failure to meet the Asset removal costs (365) (340) (25) terms of any investment contract, loan agreement or other- Property losses and unrecovered plant costs 29 50 (21)

MISO transmission costs 91 - 91 wise perform as agreed. Credit risk arises from all activities JCP&L reliability costs 23 - 23 in which success depends on issuer, borrower or counterparty Other 32 39 (7) performance, whether reflected on or off the balance sheet. Total $4,486 $5,499 $(1,013)

We engage in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy Ohio companies within the industry. On May 27, 2005, the Ohio Companies filed an applica-We maintain credit policies with respect to our counter- tion with the PUCO to establish a GCAF rider under the RSP parties to manage overall credit risk. This includes performing which had been approved by the PUCO in August 2004. The independent risk evaluations, actively monitoring portfolio GCAF application sought recovery of increased fuel costs from trends and using collateral and contract provisions to mitigate 2006 through 2008 applicable to the Ohio Companies' retail exposure. As part of our credit program, we aggressively man- customers through a tariff rider to be implemented January 1, age the quality of our portfolio of energy contracts, evidenced 2006. The application reflected projected increases in fuel by a current weighted average risk rating for energy contract costs in 2006 compared to 2002 baseline costs. The new rider, counterparties of BBB (S&P). As of December 31, 2005, the after adjustments made in testimony, sought to recover all largest credit concentration with one party (currently rated costs above the baseline (approximately $88 million in 2006).

investment grade) represented 7.6 % of our total credit risk. Various parties including the OCC intervened in this case and Within our unregulated energy subsidiaries, 99 % of credit the case was consolidated with the RCP application discussed exposures, net of collateral and reserves, were with invest- below. On November 1, 2005, the Ohio Companies filed tariffs ment-grade counterparties as of December 31, 2005. in compliance with the RSP, which were approved by the PUCO on December 7, 2005.

REGULATORY MATTERS On September 9, 2005, the Ohio Companies filed an appli-The Companies and ATSI recognize, as regulatory cation with the PUCO that supplemented their existing RSP assets, costs which the FERC, PUCO, PPUC and NJBPU have with an RCP which was designed to provide customers with authorized for recovery from customers in future periods or more certain rate levels than otherwise available under the RSP for which authorization is probable. Without the probability during the plan period. Major provisions of the RCP include:

of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. The

• Maintain the existing level of base distribution rates following tables disclose the regulatory assets by company through December 31, 2008 for OE and TE, and and by source: April 30, 2009 for CEI;

• Defer and capitalize for future recovery with carrying charges certain distribution costs to be incurred during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years;

• Adjust the RTC and Extended RTC recovery periods and rate levels so that full recovery of authorized costs will occur as of December 31, 2008 for OE and TE and as of December 31, 2010 for CEI; 30 FirstEnergy Corp. 2005

• Reduce the deferred shopping incentive balances as of Under provisions of the RSP, the PUCO may require the January 1, 2006 by up to $75 million for OE, $45 mil- Ohio Companies to undertake, no more often than annually, lion for TE, and $85 million for CEI by accelerating the a competitive bid process to secure generation for the years application of each respective company's accumulated 2007 and 2008. On July 22, 2005, we filed a competitive bid cost of removal regulatory liability; and process for the period beginning in 2007 that is similar to the

• Recover increased fuel costs of up to $75 million, competitive bid process approved by the PUCO for the Ohio

$77 million, and $79 million, in 2006, 2007, and 2008, Companies in 2004 which resulted in the PUCO accepting no respectively, from all OE and TE distribution and bids. Any acceptance of future competitive bid results would transmission customers through a fuel recovery terminate the RSP pricing, with no accounting impacts to the mechanism. OE, TE, and CEI may defer and capitalize RSP, and not until twelve months after the PUCO authorizes increased fuel costs above the amount collected through such termination. On September 28, 2005, the PUCO issued the fuel recovery mechanism (in lieu of implementation an Entry that essentially approved the Ohio Companies' filing of the GCAF rider). but delayed the proposed timing of the competitive bid process by four months, calling for the auction to be held on March The following table provides the estimated net 21, 2006. OCC filed an application for rehearing of the amortization of regulatory transition costs and deferred September 28, 2005 Entry, which the PUCO denied on shopping incentives (including associated carrying charges) November 22, 2005. On February 23, 2006, the auction under the RCP for the period 2006 through 2010: manager notified the PUCO that there was insufficient interest in the auction process to allow it to proceed in 2006.

TAmortization Period OE CEI TE Total Ohio See Note 10 to the consolidated financial statements for (Inm5ons) further details and a complete discussion of regulatory matters 2006 $169 $10O $ 80 $ 349 I2007 2008 176 198 ill 129 89 100 376 427 in Ohio.

. 2009 - 216 - 216 2010 - 268 - 268 Pennsylvania Total Amortization $543 $824 $269 $1,636 As of December 31, 2005, Met-Ed's and Penelec's regulatory deferrals pursuant to the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the On November 4, 2005, a supplemental stipulation was FirstEnergy/GPU Merger Settlement Stipulation are $333 filed with the PUCO which was in addition to a stipulation million and $48 million, respectively. Penelec's $48 million filed with the September 9, 2005 application. On January 4, is subject to the pending resolution of taxable income issues 2006, the PUCO approved the RCP filing with modifications. associated with NUG Trust Fund proceeds.

On January 10, 2006, the Ohio Companies filed a Motion for Met-Ed and Penelec purchase a portion of their PLR Clarification of the PUCO order approving the RCP. The Ohio requirements from FES through a wholesale power sales Companies sought clarity on issues related to distribution agreement and a portion from contracts with unaffiliated third deferrals, including requirements of the review process, timing party suppliers, including NUGs. Assuming continuation of for recognizing certain deferrals and definitions of the types of these existing contractual arrangements, the available supply qualified expenditures. The Ohio Companies also sought con- represents approximately 100 % of the combined retail sales firmation that the list of deferrable distribution expenditures obligations of Met-Ed and Penelec in 2006 and 2007; almost originally included in the revised stipulation fall within the 100 % for 2008; and approximately 85 % for 2009 and 2010.

PUCO order definition of qualified expenditures. On January Met-Ed and Penelec are authorized to defer any excess of 25, 2006, the PUCO issued an Entry on Rehearing granting in NUG contract costs over current market prices. Under the part, and denying in part, the Ohio Companies' previous terms of the wholesale agreement with FES, FES retains the requests and clarifying issues referred to above. The PUCO supply obligation and the supply profit and loss risk for the granted the Ohio Companies' requests to: 1) recognize fuel portion of power supply requirements not self-supplied by and distribution deferrals commencing January 1, 2006; 2) Met-Ed and Penelec under their contracts with NUGs and recognize distribution deferrals on a monthly basis prior to other unaffiliated suppliers. This arrangement reduces review by the PUCO Staff; 3) clarify that the types of distribu- Met-Ed's and Penelec's exposure to high wholesale power tion expenditures included in the Supplemental Stipulation prices by providing power at a fixed price for their uncommitted may be deferred; and 4) clarify that distribution expenditures PLR energy costs during the term of the agreement with FES.

do not have to be "accelerated" in order to be deferred. The The wholesale agreement with FES is automatically extended PUCO granted the Ohio Companies' methodology for deter- for each successive calendar year unless any party elects to mining distribution deferral amounts, but denied the Motion cancel the agreement by November 1 of the preceding year.

in that the PUCO Staff must verify the level of distribution On November 1, 2005, FES and the other parties thereto expenditures contained in current rates, as opposed to simply amended the agreement to provide FES the right over the accepting the amounts contained in the Companies' Motion. next year to terminate the agreement at any time upon 60 On February 3, 2006, several other parties filed applications days notice. If the wholesale power agreement were terminated for rehearing on the PUCO's January 4, 2006 Order. The Ohio or modified, Met-Ed and Penelec would need to satisfy the Companies responded to the application for rehearing on portion of their PLR obligations currently supplied by FES February 13, 2006. from unaffiliated suppliers at prevailing prices, which are like-FirstEnergy Corp. 2005 31

ly to be higher than the current price charged by FES under for recovery of $165 million of actual above-market NUG the agreement and, as a result, Met-Ed's and Penelec's pur- costs incurred from August 1, 2005 through October 31, 2005 chased power costs could materially increase. If Met-Ed and and forecasted above-market NUG costs for November and Penelec were to replace the FES supply at current market December 2005. The filing also includes a request for recovery power prices without corresponding regulatory authorization of $49 million for above-market NUG costs incurred prior to to increase their generation prices to customers, each compa- August 1, 2003, to the extent those costs are not recoverable ny would likely incur a significant increase in operating through securitization.

expenses and experience a material deterioration in credit On May 25, 2005, the NJBPU approved two stipulated quality metrics. Under such a scenario, each company's credit settlement agreements. The first stipulation between JCP&L profile would no longer support an investment grade rating and the NJBPU staff resolves all of the issues associated with for its fixed income securities. Met-Ed and Penelec are in the JCP&L's motion for reconsideration of the 2003 NJBPU deci-process of preparing a comprehensive rate filing that will sion on JCP&L's base electric rate proceeding (Phase I Order).

address a number of transmission, distribution and supply The second stipulation between JCP&L, the NJBPU staff and issues and is expected to be filed with the PPUC in the second the Ratepayer Advocate resolves all of the issues associated quarter of 2006. That filing will include, among other things, with JCP&L's Phase II petition requesting an increase in base a request for appropriate regulatory action to mitigate adverse rates of $36 million for the recovery of system reliability costs consequences from any future reduction, in whole or in part, and a 9.75 % return on equity. The stipulated settlements in the availability to Met-Ed and Penelec of supply under the provide for, among other things, the following:

existing FES agreement. There can be no assurance, however, that if FES ultimately determines to terminate, or significantly

• An annual increase in distribution revenues of $23 modify the agreement, timely regulatory relief will be granted million, effective June 1, 2005, associated with the by the PPUC or, to the extent granted, adequate to mitigate Phase I Order reconsideration; such adverse consequences.

• An annual increase in distribution revenues of $36 On October 11, 2005, Penn filed a plan with the PPUC to million, effective June 1, 2005, related to JCP&L's secure electricity supply for its customers at set rates following Phase II Petition; the end of its transition period on December 31, 2006. Penn is

• An annual reduction in both rates and amortization recommending that an RFP process cover the period January expense of $8 million, effective June 1, 2005, in 1, 2007 through May 31, 2008. Hearings were held on January anticipation of an NjBPU order regarding JCP&L's 10, 2006 with main briefs filed on January 27, 2006 and reply request to securitize up to $277 million of its deferred briefs on February 3, 2006. On February 17, 2006, the AX cost balance; issued a Recommended Decision to adopt Penn's RFP process

• An increase in JCP&L's authorized return on with modifications. A PPUC vote is expected in April 2006. common equity from 9.5 % to 9.75 %; and Under Pennsylvania's electric competition law, Penn is

• A commitment byJCP&L, through December 31, 2006 required to secure generation supply for customers who do or until related legislation is adopted, whichever occurs not choose alternative suppliers for their electricity. first, to maintain a target level of customer service relia-See Note 10 to the consolidated financial statements for bility with a reduction in JCP&L's authorized return on further details and a complete discussion of regulatory matters common equity from 9.75 % to 9.5 % if the target is not in Pennsylvania. met for two consecutive quarters. The authorized return on common equity would then be restored to New Jersey 9.75 % if the target is met for two consecutive quarters.

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS The Phase II stipulation included an agreement that the to non-shopping customers and costs incurred under NUG distribution revenue increase also reflects a three-year amorti-agreements exceed amounts collected through BGS and MTC zation of JCP&L's one-time service reliability improvement rates and market sales of NUG energy and capacity. As of costs incurred in 2003-2005. This resulted in the creation of a December 31, 2005, the accumulated deferred cost balance regulatory asset associated with accelerated tree trimming and totaled approximately $541 million. New Jersey law allows for other reliability costs which were expensed in 2003 and 2004.

securitization of JCP&L's deferred balance upon application by The establishment of the new regulatory asset of approximate-JCP&L and a determination by the NJBPU that the conditions ly $28 million resulted in an increase to net income of of the New Jersey restructuring legislation are met. On approximately $16 million ($0.05 per share of FirstEnergy February 14, 2003,JCP&L filed for approval to securitize the common stock) in the second quarter of 2005.

July 31, 2003 deferred balance. JCP&L is in discussions with On August 1, 2005, the NJBPU established a proceeding the NJBPU staff as a result of the stipulated settlement agree- to determine whether additional ratepayer protections are ments (as further discussed below) which recommended that required at the state level in light of the recent repeal of the NJBPU issue an order regarding JCP&L's application. On PUHCA under the EPACT. An NJBPU proposed rulemaking July 20, 2005,JCP&L requested the NJBPU to set a procedural to address the issues was published in the NJ Register on schedule for this matter and is awaiting NJBPU action. On December 19, 2005. The proposal would prevent a holding February 1, 2006, the NJBPU selected Bear Stearns as the company that owns a gas or electric public utility from invest-financial advisor. On December 2, 2005,JCP&L filed a request ing more than 25 % of the combined assets of its utility and 32 FirstEnergy Corp. 2005

utility-related subsidiaries into businesses unrelated to the util- Ohio Companies to defer incremental transmission and ancil-ity industry. A public hearing was held on February 7, 2006 lary service-related charges incurred as a participant in MISO, and comments to the NJBPU were due by February 17, 2006. but only for those costs incurred during the period December See Note 10 to the consolidated financial statements for 30, 2004 through December 31, 2005. Permission to defer further details and a complete discussion of regulatory matters costs incurred prior to December 30, 2004 was denied. The in New Jersey. PUCO also authorized the Ohio Companies to accrue carrying charges on the deferred balances. On August 31, 2005, the Transmission OCC appealed the PUCO's decision. All briefs have been filed.

ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be A motion to dismiss filed on behalf of the PUCO is currently involved in FERC hearings concerning the calculation and pending. Unless the court grants the motion, the appeal will imposition of Seams Elimination Cost Adjustment (SECA) be set for oral argument, which should be heard in the second charges to various load serving entities. Pursuant to its January half of 2006.

30, 2006 Order, the FERC has compressed both phases of this On January 12, 2005, Met-Ed and Penelec filed a request proceeding into a single hearing scheduled to begin May 1, with the PPUC for deferral of transmission-related costs 2006, with an initial decision on or before August 11, 2006. beginning January 1, 2005, estimated to be approximately On November 1, 2004, ATSI requested authority from $8 million per month. The OCA, OSBA, OTS, MEIUG, PICA, the FERC to defer approximately $54 million of vegetation Allegheny Electric Cooperative and Pennsylvania Rural management costs estimated to be incurred from 2004 Electric Association have all intervened in the case. To date through 2007. On March 4, 2005, the FERC approved ATSI's no hearing schedule has been established, and neither company request to defer those costs ($26 million deferred as of has yet implemented deferral accounting for these costs.

December 31, 2005). ATSI expects to file a rate application On January 31, 2005, certain PJM transmission owners with the FERC that would include recovery of the deferred made three filings with the FERC pursuant to a settlement costs beginning in June 2006. agreement previously approved by the FERC. JCP&L, Met-Ed On January 24, 2006, ATSI and MISO filed an applica- and Penelec were parties to that proceeding and joined in two tion with the FERC to modify the Attachment 0 formula rate of the filings. In the first filing, the settling transmission own-mechanism to permit ATSI to accelerate recovery of revenues ers submitted a filing justifying continuation of their existing lost due to the FERC's elimination of through and out rates rate design within the PJM RTO. In the second filing, the between MISO and PJM, and the elimination of other ATSI settling transmission owners proposed a revised Schedule rates in the MISO tariff. Revenues formerly collected under 12 to the PJM tariff designed to harmonize the rate treatment these rates are currently used to reduce the ATSI zonal of new and existing transmission facilities. Interventions and transmission rate in the Attachment 0 formula. The revenue protests were filed on February 22, 2005. In the third filing, shortfall created by elimination of these rates would not Baltimore Gas and Electric Company and Pepco Holdings, Inc, be fully reflected in ATSI's formula rate untilJune 1, 2006, requested a formula rate for transmission service provided unless the proposed Revenue Credit Collection is approved within their respective zones. On May 31, 2005, the FERC by the FERC. The Revenue Credit Collection mechanism is issued an order on these cases. First, it set for hearing the designed to collect approximately $40 million in revenues on existing rate design and indicated that it will issue a final an annualized basis beginning June 1, 2006. FERC is expected order within six months. Second, the FERC approved the to act on this filing on or before April 1, 2006. proposed Schedule 12 rate harmonization. Third, the FERC On August 31, 2005, the PUCO approved the Ohio accepted the proposed formula rate, subject to referral and Companies' settlement stipulation for a rider to recover trans- hearing procedures. On June 30, 2005, the settling PJM trans-mission and ancillary service-related costs beginning January mission owners filed a request for rehearing of the May 31, 1, 2006, to be adjusted eachJuly 1 thereafter. The incremental 2005 order. The rate design and formula rate proceedings are transmission and ancillary service revenues expected to be currently being litigated before the FERC. If the FERC accepts recovered from January through June 2006 are approximately a proposal by American Electric Power Company, Inc. to

$66 million, including recovery of the 2005 deferred MISO create a "postage stamp" rate for high voltage transmission expenses as described below. In May 2006, the Ohio facilities across PJM, significant additional transmission Companies will file a modification to the rider to determine revenues would be imposed on JCP&L, Met-Ed, Penelec, revenues from July 2006 through June 2007. On January 20, and other transmission zones within PJM.

2006, the OCC sought rehearing of the PUCO approval of the On November 1, 2005, FES filed two power sales rider recovery during the period January 1, 2006 through June agreements for approval with the FERC. One power sales 30, 2006, as that amount pertains to recovery of the deferred agreement provided for FES to provide the PLR requirements costs. The PUCO denied the OCC's application on February 6, of the Ohio Companies at a price equal to the retail generation 2006. The OCC has sixty days from that date to appeal the rates approved by the PUCO for a period of three years begin-PUCO's approval of the rider. ning January 1, 2006. The Ohio Companies will be relieved of In response to the Ohio Companies' December 2004 their obligation to obtain PLR power requirements from FES application for authority to defer costs associated with trans- if the Ohio competitive bid process, mandated by the PUCO, mission and ancillary service-related costs incurred during results in a lower price for retail customers. A similar power the period October 1, 2003 through December 31, 2005, the sales agreement between FES and Penn permits Penn to PUCO granted the accounting authority in May 2005 for the obtain its PLR power requirements from FES at a fixed price FirstEnergy Corp. 2005 33

equal to the retail generation price during 2006. Penn has filed thereby eliminating the need for full litigation. The AU's a plan with the PPUC to use an RFP process to obtain its recommendation, adopting the revised benchmarks and power supply requirements after 2006. standards was approved by the PPUC on February 9,2006.

On December 29, 2005, the FERC issued an order EPACT provides for the creation of an ERO to establish setting the two power sales agreements for hearing. The order and enforce reliability standards for the bulk power system, criticizes the Ohio competitive bid process, and requires FES subject to FERC review. On February 3, 2006, the FERC to submit additional evidence in support of the reasonableness adopted a rule establishing certification requirements for of the prices charged in the two power sales agreements. A the ERO, as well as regional entities envisioned to assume pre-hearing conference was held on January 18, 2006 to monitoring responsibility for the new reliability standards.

determine the hearing schedule in this case. FES expects an The NERC has been preparing the implementation aspects initial decision to be issued in this case in the fall of 2006. of reorganizing its structure to meet the FERC's certification The outcome of this proceeding cannot be predicted. FES requirements for the ERO. The NERC will make a filing with has sought rehearing of the December 29, 2005 order. the FERC to obtain certification as the ERO and to obtain FERC approval of delegation agreements with regional entities.

Reliability Initiatives The new FERC rule referred to above, further provides for We are proceeding with the implementation of the recom- reorganizing regional reliability organizations (regional enti-mendations that were issued from various entities, including ties) that would replace the current regional councils and for governmental, industry and ad-hoc reliability entities (PUCO, rearranging the relationship with the ERO. The "regional enti-FERC, NERC and the U.S. - Canada Power System Outage ty" may be delegated authority by the ERO, subject to FERC Task Force) in late 2003 and early 2004, regarding enhance- approval, for enforcing reliability standards adopted by the ments to regional reliability that were to be completed ERO and approved by the FERC. NERC also intends to make subsequent to 2004. We will continue to periodically assess the a parallel filing with the FERC seeking approval of mandatory FERC-ordered Reliability Study recommendations for forecast- reliability standards. These reliability standards are expected to ed 2009 system conditions, recognizing revised load forecasts be based on the current NERC Version 0 reliability standards and other changing system conditions which may impact the with some additional standards. The two filings are expected recommendations. Thus far, implementation of the recommen- to be made in the second quarter of 2006.

dations has not required, nor is expected to require, substantial The ECAR, Mid-Atlantic Area Council, and Mid-investment in new, or material upgrades to existing, equip- American Interconnected Network reliability councils have ment The FERC or other applicable government agencies and completed the consolidation of these regions into a single new reliability coordinators, however, may take a different view as regional reliability organization known as ReliabilityFirst to recommended enhancements or may recommend additional Corporation. ReliabilityFirst began operations as a regional enhancements in the future as the result of adoption of manda- reliability council under NERC on January 1, 2006 and tory reliability standards pursuant to EPACT that could require intends to file and obtain certification consistent with the additional, material expenditures. Finally, the PUCO is contin- final rule as a "regional entity" under the ERO during 2006.

uing to review our filing that addressed upgrades to control All of FirstEnergy's facilities are located within the room computer hardware and software and enhancements to ReliabilityFirst region.

the training of control room operators before determining the On a parallel path, the NERC is establishing working groups next steps, if any, in the proceeding. to develop reliability standards to be filed for approval with the As a result of outages experienced in JCP&L's service FERC following the NERC's certification as an ERO. These area in 2002 and 2003, the NJBPU had implemented reviews reliability standards are expected to build on the current NERC into JCP&L's service reliability. In 2004, the NJBPU adopted Version 0 reliability standards. It is expected that the proposed an MOU that set out specific tasks and a timetable for comple- reliability standards will be filed with the FERC in early 2006.

tion of actions related to service reliability to be performed by We believe that we are in compliance with all current JCP&L and also approved a Stipulation that incorporates the NERC reliability standards. However, it is expected that the final report of a Special Reliability Master who made recom- FERC will adopt stricter reliability standards than those mendations on appropriate courses of action necessary to contained in the current NERC Version 0 standards. The ensure system-wide reliability. JCP&L continues to file com- financial impact of complying with the new standards cannot pliance reports reflecting activities associated with the MOU be determined at this time. However, EPACT requires that and Stipulation. all prudent costs incurred to comply with the new reliability In May 2004, the PPUC issued an order approving standards be recovered in rates. If we are unable to meet the revised reliability benchmarks and standards, including reliability standards for the bulk power system in the future, revised benchmarks and standards for Met-Ed, Penelec and it could have a material adverse effect on our financial Penn. Met-Ed, Penelec and Penn filed a Petition for condition, results of operations and cash flows.

Amendment of Benchmarks with the PPUC on May 26,2004, See Note 10 to the consolidated financial statements due to their implementation of automated outage management for a more detailed discussion of reliability initiatives.

systems following restructuring. On December 30, 2005, the AX recommended that the PPUC adopt the Joint Petition for ENVIRONMENTAL MATrERS Settlement among the parties involved in the three Companies' We accrue environmental liabilities only when it is request to amend the distribution reliability benchmarks, probable that we have an obligation for such costs and can 34 FirstEnergy Corp. 2005

reasonably estimate the amount of such costs. Unasserted The model rules for both CAIR and CAMR contemplate claims are reflected in our determination of environmental an input-based methodology to allocate allowances to affected liabilities and are accrued in the period that they are both facilities. Under this approach, allowances would be allocated probable and reasonably estimable. based on the amount of fuel consumed by the affected sources.

On December 1, 2005, we issued a comprehensive We would prefer an output-based generation-neutral method-report to shareholders regarding air emissions regulations ology in which allowances are allocated based on megawatts and an assessment of our future risks and mitigation efforts. of power produced. Since this approach is based on output, The report is available on our web site at new and non-emitting generating facilities, including renewables www.firstenergycorp.com/environmental. and nuclear, would be entitled to their proportionate share of the allowances. Consequently, we would be disadvantaged if NationalAmbient Air Quality Standards these model rules were implemented because our substantial In July 1997, the EPA promulgated changes in the NAAQS reliance on non-emitting (largely nuclear) generation is not for ozone and proposed a new NAAQS for fine particulate mat- recognized under input-based allocation.

ter. On March 10, 2005, the EPA finalized CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and W H. Sammis Plant Pennsylvania) and the District of Columbia based on proposed In 1999 and 2000, the EPA issued NOV or Compliance findings that air emissions from 28 eastern states and the Orders to nine utilities alleging violations of the Clean Air District of Columbia significantly contribute to non-attainment Act based on operation and maintenance of 44 power plants, of the NAAQS for fine particles and/or the "8-hour" ozone including the W. H. Sammis Plant, which was owned at that NAAQS in other states. CAIR provides each affected state until time by OE and Penn. In addition, the DOJ filed eight civil 2006 to develop implementing regulations to achieve additional complaints against various investor-owned utilities, including reductions of NOx and S02 emissions in two phases (Phase I in a complaint against OE and Penn in the U.S. District Court 2009 for NOx, 2010 for S0 2 and Phase II in 2015 for both NOx for the Southern District of Ohio. These cases are referred to and SO 2). Our Michigan, Ohio and Pennsylvania fossil-fired as New Source Review cases. On March 18, 2005, OE and generation facilities will be subject to caps on SO 2 and NOx Penn announced that they had reached a settlement with the emissions, whereas our New Jersey fossil-fired generation facili- EPA, the DOJ and three states (Connecticut, New Jersey, and ties will be subject to a cap on NOx emissions only. According New York) that resolved all issues related to the W. H. Sammis to the EPA, S0 2 emissions will be reduced by 45 % (from 2003 Plant New Source Review litigation. This settlement agreement levels) by 2010 across the states covered by the rule, with reduc- was approved by the Court on July 11, 2005, and requires tions reaching 73 % (from 2003 levels) by 2015, capping S02 reductions of NOx and SO2 emissions at the W. H. Sammis emissions in affected states to just 2.5 million tons annually. Plant and other coal fired plants through the installation of NOx emissions will be reduced by 53 % (from 2003 levels) by pollution control devices and provides for stipulated penalties 2009 across the states covered by the rule, with reductions for failure to install and operate such pollution controls in reaching 61 % (from 2003 levels) by 2015, achieving a regional accordance with that agreement. Consequently, if we fail to NOx cap of 1.3 million tons annually. The future cost of com- install such pollution control devices, for any reason, including, pliance with these regulations may be substantial and will but not limited to, the failure of any third-party contractor to depend on how they are ultimately implemented by the states timely meet its delivery obligations for such devices, we could in which the Companies operate affected facilities. be exposed to penalties under the settlement agreement.

Capital expenditures necessary to meet those requirements are Mercury Emissions currently estimated to be $1.5 billion (the primary portion of In December 2000, the EPA announced it would proceed which is expected to be spent in the 2008 to 2011 time period).

with the development of regulations regarding hazardous air On August 26, 2005, FGCO entered into an agreement with pollutants from electric power plants, identifying mercury as Bechtel Power Corporation (Bechtel), under which Bechtel the hazardous air pollutant of greatest concern. On March 14, will engineer, procure, and construct air quality control systems 2005, the EPA finalized CAMR, which provides for a cap-and- for the reduction of sulfur dioxide emissions. The settlement trade program to reduce mercury emissions from coal-fired agreement also requires OE and Penn to spend up to $25 mil-power plants in two phases. Initially, mercury emissions will lion toward environmentally beneficial projects, which include be capped nationally at 38 tons by 2010 (as a "co-benefit" wind energy purchased power agreements over a 20-year term.

from implementation of S0 2 and NOx emission caps under OE and Penn agreed to pay a civil penalty of $8.5 million.

the EPA's CAIR program). Phase H of the mercury cap-and- Results in 2005 included the penalties payable by OE and Penn trade program will cap nationwide mercury emissions from of $7.8 million and $0.7 million, respectively. OE and Penn coal-fired power plants at 15 tons per year by 2018. However, also recognized liabilities of $9.2 million and $0.8 million, the final rules give states substantial discretion in developing respectively, for probable future cash contributions toward rules to implement these programs. In addition, both CAIR environmentally beneficial projects.

and CAMR have been challenged in the United States Court of Appeals for the District of Columbia. Our future cost of Climate Change compliance with these regulations may be substantial and will In December 1997, delegates to the United Nations' depend on how they are ultimately implemented by the states climate summit in Japan adopted an agreement, the Kyoto in which we operate affected facilities. Protocol, to address global warming by reducing the amount FirstEnergy Corp. 2005 35

of man-made GHG emitted by developed countries by 5.2 % power outages resulted from an alleged failure of both from 1990 levels between 2008 and 2012. The United States FirstEnergy and ECAR to assess and understand perceived signed the Kyoto Protocol in 1998 but it failed to receive the inadequacies within our system; inadequate situational aware-two-thirds vote of the United States Senate required for ratifi- ness of the developing conditions; and a perceived failure to cation. However, the Bush administration has committed the adequately manage tree growth in certain transmission rights United States to a voluntary climate change strategy to reduce of way. The Task Force also concluded that there was a failure domestic GHG intensity - the ratio of emissions to economic of the interconnected grid's reliability organizations (MISO output - by 18 % through 2012. EPACT established a and PJM) to provide effective real-time diagnostic support.

Committee on Climate Change Technology to coordinate fed- The final report is publicly available through the Department eral climate change activities and promote the development of Energy's website (www.doe.gov). We believe that the final and deployment of GHG reducing technologies. report does not provide a complete and comprehensive picture We cannot currently estimate the financial impact of of the conditions that contributed to the August 14, 2003 climate change policies, although the potential restrictions power outages and that it does not adequately address the on C0 2 emissions could require significant capital and other underlying causes of the outages. We remain convinced that expenditures. However, the CO 2 emissions per kilowatt-hour the outages cannot be explained by events on any one utility's of electricity generated by the Companies is lower than many system. The final report contained 46 "recommendations to regional competitors due to the Companies' diversified genera- prevent or minimize the scope of future blackouts." Forty-five tion sources which include low or non-CO2 emitting gas-fired of those recommendations related to broad industry or policy and nuclear generators. matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, Regutation of Hazardous Waste MISO, PJM, ECAR, and other parties to correct the causes of The Companies have been named as PRPs at waste the August 14, 2003 power outages. We implemented several disposal sites, which may require cleanup under the initiatives, both prior to and since the August 14, 2003 power Comprehensive Environmental Response, Compensation, outages, which were independently verified by NERC as com-and Liability Act of 1980. Allegations of disposal of hazardous plete in 2004 and were consistent with these and other substances at historical sites and the liability involved are recommendations and collectively enhance the reliability of often unsubstantiated and subject to dispute; however, federal our electric system. Our implementation of these recommen-law provides that all PRPs for a particular site are liable on a dations in 2004 included completion of the Task Force joint and several basis. Therefore, environmental liabilities recommendations that were directed toward FirstEnergy.

that are considered probable have been recognized on the We also are proceeding with the implementation of the recom-Consolidated Balance Sheet as of December 31, 2005, based mendations regarding enhancements to regional reliability on estimates of the total costs of cleanup, our proportionate that were to be completed subsequent to 2004 and will contin-responsibility for such costs and the financial ability of other ue to periodically assess the FERC-ordered Reliability Study unaffiliated entities to pay. In addition, JCP&L has accrued recommendations for forecasted 2009 system conditions, liabilities for environmental remediation of former manufac- recognizing revised load forecasts and other changing system tured gas plants in New Jersey. Those costs are being conditions which may impact the recommendations. Thus far recovered byJCP&L through a non-bypassable SBC. Total implementation of the recommendations has not required, nor liabilities of approximately $64 million have been accrued is expected to require, substantial investment in new or mate-through December 31, 2005. rial upgrades to existing equipment, and therefore we have not See Note 14(C) to the consolidated financial statements accrued a liability as of December 31, 2005 for any expendi-for further details and a complete discussion of environmental tures in excess of those actually incurred through that date.

matters. We note, however, that the FERC or other applicable govern-ment agencies and reliability coordinators may take a different OTHER LEGAL PROCEEDINGS view as to recommended enhancements or may recommend There are various lawsuits, claims (including claims additional enhancements in the future that could require addi-for asbestos exposure) and proceedings related to our tional, material expenditures. Finally, the PUCO is continuing normal business operations pending against FirstEnergy to review our filing that addressed upgrades to control room and its subsidiaries. The other material items not otherwise computer hardware and software and enhancements to the discussed above are described below. training of control room operators before determining the next steps, if any, in the proceeding.

Power Outages and Related Litigation FirstEnergy companies also are defending six separate On August 14, 2003, various states and parts of southern complaint cases before the PUCO relating to the August 14, Canada experienced widespread power outages. The outages 2003 power outage. Two cases were originally filed in Ohio affected approximately 1.4 million customers in our service State courts but were subsequently dismissed for lack of sub-area. The U.S. - Canada Power System Outage Task Force's ject matter jurisdiction and further appeals were unsuccessful.

final report in April 2004 on the outages concludes, among In these cases the individual complainants-three in one case other things, that the problems leading to the outages began in and four in the other-sought to represent others as part of a our Ohio service area. Specifically, the final report concluded, class action. The PUCO dismissed the class allegations, stating among other things, that the initiation of the August 14, 2003 that its rules of practice do not provide for class action com-36 FirstEnergy Corp. 2005

plaints. Of the four other pending PUCO complaint cases, agreed to pay a penalty of $28 million (which is not deductible three were filed by various insurance carriers either in their for income tax purposes) which reduced FirstEnergy's earnings own name as subrogees or in the name of their insured. In by $0.09 per common share in the fourth quarter of 2005. As each of the four cases, the carrier seeks reimbursement from part of the deferred prosecution agreement entered into with various FirstEnergy companies (and, in one case, from PJM, the DOJ, $4.35 million of that amount will be directed to MISO and American Electric Power Company, Inc. as well) community service projects.

for claims paid to insureds for claims allegedly arising as a On April 21, 2005, the NRC issued a NOV and proposed result of the loss of power on August 14, 2003. The listed a $5 million civil penalty related to the degradation of the insureds in these cases, in many instances, are not customers Davis-Besse reactor vessel head issue described above. We of any FirstEnergy company. The fourth case involves the accrued $2 million for a potential fine prior to 2005 and claim of a non-customer seeking reimbursement for losses accrued the remaining liability for the proposed fine during incurred when its store was burglarized on August 14, 2003. the first quarter of 2005. On September 14, 2005, FENOC In addition to these six cases, the Ohio Companies were filed its response to the NOV with the NRC. FENOC accepted named as respondents in a regulatory proceeding that was full responsibility for the past failure to properly implement initiated at the PUCO in response to complaints alleging fail- its boric acid corrosion control and corrective action pro-ure to provide reasonable and adequate service stemming grams. The NRC NOV indicated that the violations do not primarily from the August 14, 2003 power outages. No esti- represent current licensee performance. We paid the penalty mate of potential liability is available for any of these cases. in the third quarter of 2005. On January 23, 2006, FENOC In addition to the above proceedings, FirstEnergy was supplemented its response to the NRC's NOV on the Davis-named in a complaint filed in Michigan State Court by an Besse head degradation to reflect the deferred prosecution individual who is not a customer of any FirstEnergy company. agreement that FENOC had reached with the DOJ.

A responsive pleading to this matter has been filed. Effective July 1, 2005 the NRC oversight panel for FirstEnergy was also named, along with several other entities, Davis-Besse was terminated and Davis-Besse returned to the in a complaint in New Jersey State Court. The allegations standard NRC reactor oversight process. At that time, NRC against FirstEnergy are based, in part, on an alleged failure to inspections were augmented to include inspections to support protect the citizens of Jersey City from an electrical power out- the NRC's Confirmatory Order dated March 8, 2004 that was age. No FirstEnergy entity serves any customers in Jersey City. issued at the time of startup and to address an NRC White A responsive pleading has been filed. No estimate of potential Finding related to the performance of the emergency sirens.

liability has been undertaken in either of these matters. By letter dated December 8, 2005, the NRC advised FENOC We are vigorously defending these actions, but cannot pre- that the White Finding had been closed.

dict the outcome of any of these proceedings or whether any On August 12, 2004, the NRC notified FENOC that it further regulatory proceedings or legal actions may be initiated would increase its regulatory oversight of the Perry Nuclear against the Companies. Although unable to predict the impact Power Plant as a result of problems with safety system equip-of these proceedings, if FirstEnergy or its subsidiaries were ment over the preceding two years and the licensee's failure to ultimately determined to have legal liability in connection with take prompt and corrective action. FENOC operates the Perry these proceedings, it could have a material adverse effect on Nuclear Power Plant.

our financial condition, results of operations and cash flows. On April 4, 2005, the NRC held a public meeting to dis-cuss FENOC's performance at the Perry Nuclear Power Plant Nuclear PlantMatters as identified in the NRC's annual assessment letter to On January 20, 2006, FENOC announced that it has FENOC. Similar public meetings are held with all nuclear entered into a deferred prosecution agreement with the U.S. power plant licensees following issuance by the NRC of their Attorney's Office for the Northern District of Ohio and the annual assessments. According to the NRC, overall the Perry Environmental Crimes Section of the Environment and Plant operated "in a manner that preserved public health Natural Resources Division of the DOJ related to FENOC's and safety" even though it remained under heightened NRC communications with the NRC during the fall of 2001 in con- oversight. During the public meeting and in the annual assess-nection with the reactor head issue at the Davis-Besse Nuclear ment, the NRC indicated that additional inspections will Power Station. Under the agreement, which expires on continue and that the plant must improve performance to be December 31, 2006, the United States acknowledged FENOC's removed from the Multiple/Repetitive Degraded Cornerstone extensive corrective actions at Davis-Besse, FENOC's coopera- Column of the Action Matrix. By an inspection report dated tion during investigations by the DOJ and the NRC, FENOC's January 18, 2006, the NRC closed one of the White Findings pledge of continued cooperation in any related criminal and (related to emergency preparedness) which led to the multiple administrative investigations and proceedings, FENOC's degraded cornerstones.

acknowledgement of responsibility for the behavior of its On May 26, 2005, the NRC held a public meeting to dis-employees, and its agreement to pay a monetary penalty. The cuss its oversight of the Perry Plant. While the NRC stated DOJ will refrain from seeking an indictment or otherwise ini- that the plant continued to operate safely, the NRC also stated tiating criminal prosecution of FENOC for all conduct related that the overall performance had not substantially improved to the statement of facts attached to the deferred prosecution since the heightened inspection was initiated. The NRC reiter-agreement, as long as FENOC remains in compliance with the ated this conclusion in its mid-year assessment letter dated agreement, which FENOC fully intends to do. FENOC has August 30, 2005. On September 28, 2005, the NRC sent a FirstEnergy Corp. 2005 37

CAL to FENOC describing commitments that FENOC had level. JCP&L recognized a liability for the potential $16 made to improve the performance of Perry and stated that the million award in 2005.

CAL would remain open until substantial improvement was The City of Huron filed a complaint against OE with the demonstrated. The CAL was anticipated as part of the NRC's PUCO challenging the ability of electric distribution utilities Reactor Oversight Process. If performance does not improve, to collect transition charges from a customer of a newly the NRC has a range of options under the Reactor Oversight formed municipal electric utility. The complaint was filed on Process, from increased oversight to possible impact to the May 28, 2003, and OE timely filed its response on June 30, plant's operating authority. Although unable to predict a 2003. In a related filing, the Ohio Companies filed for potential impact, its ultimate disposition could have a material approval with the PUCO a tariff that would specifically allow adverse effect on FirstEnergy's or its subsidiaries' financial the collection of transition charges from customers of munici-condition, results of operations and cash flows. pal electric utilities formed after 1998. An adverse ruling As of December 16, 2005, NGC acquired ownership of could negatively affect full recovery of transition charges by the nuclear generation assets transferred from OE, CEI, TE the utility. Hearings on the matter were held in August 2005.

and Penn with the exception of leasehold interests of OE and Initial briefs from all parties were filed on September 22, 2005 TE in certain of the nuclear plants that are subject to sale and and reply briefs were filed on October 14, 2005. It is leaseback arrangements with non-affiliates. unknown when the PUCO will decide this case.

If it were ultimately determined that FirstEnergy or its Other Legal Matters subsidiaries have legal liability or are otherwise made subject On October 20, 2004, we were notified by the SEC that to liability based on the above matters, it could have a material the previously disclosed informal inquiry initiated by the adverse effect on our financial condition, results of operations SEC's Division of Enforcement in September 2003 relating to and cash flows.

the restatements in August 2003 of previously reported results See Note 14(D) to the consolidated financial statements by FirstEnergy and the Ohio Companies, and the Davis-Besse for further details and a complete discussion of these other extended outage, have become the subject of a formal order of legal proceedings.

investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of CRITICAL ACCOUNTING POLICIES FirstEnergy and the Companies under PUHCA. Concurrent We prepare our consolidated financial statements in with this notification, we received a subpoena asking for back- accordance with GAAP. Application of these principles often ground documents and documents related to the restatements requires a high degree of judgment, estimates and assumptions and Davis-Besse issues. On December 30, 2004, we received a that affect financial results. All of our assets are subject to subpoena asking for documents relating to issues raised dur- their own specific risks and uncertainties and are regularly ing the SEC's PUHCA examination. On August 24, 2005 reviewed for impairment. Our more significant accounting additional information was requested regarding Davis-Besse policies are described below.

related disclosures, which we have provided. We have cooper-ated fully with the informal inquiry and will continue to do Revenue Recognition so with the formal investigation. We follow the accrual method of accounting for revenues, On August 22, 2005, a class action complaint was filed recognizing revenue for electricity that has been delivered to against OE in Jefferson County, Ohio Common Pleas Court, customers but not yet billed through the end of the accounting seeking compensatory and punitive damages to be determined period. The determination of electricity sales to individual at trial based on claims of negligence and eight other tort customers is based on meter readings, which occur on a sys-counts alleging damages from W.H. Sammis Plant air emis- tematic basis throughout the month. At the end of each sions. The two named plaintiffs are also seeking injunctive month, electricity delivered to customers since the last meter relief to eliminate harmful emissions and repair property reading is estimated and a corresponding accrual for unbilled damage and the institution of a medical monitoring program sales is recognized. The determination of unbilled sales for class members. requires management to make estimates regarding electricity JCP&L's bargaining unit employees filed a grievance available for retail load, transmission and distribution line challenging JCP&L's 2002 call-out procedure that required bar- losses, demand by customer class, weather-related impacts, gaining unit employees to respond to emergency power prices in effect for each customer class and electricity provid-outages. On May 20, 2004, an arbitration panel concluded ed by alternative suppliers.

that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 Regulatory Accounting hearing, the Arbitrator decided not to hear testimony on Our regulated services segment is subject to regulation damages and closed the proceedings. On September 9, 2005, that sets the prices (rates) we are permitted to charge our cus-the Arbitrator issued an opinion to award approximately $16 tomers based on costs that the regulatory agencies determine million to the bargaining unit employees. On February 6, we are permitted to recover. At times, regulators permit the 2006, the federal court granted a Union motion to dismiss future recovery through rates of costs that would be currently JCP&L's appeal of the award as premature. JCP&L will file its charged to expense by an unregulated company. This ratemak-appeal again in federal district court once the damages associ- ing process results in the recording of regulatory assets based ated with this case are identified at an individual employee on anticipated future cash inflows. We regularly review these 38 FirstEnergy Corp. 2005

assets to assess their ultimate recoverability within the $94 million in 2006. This compares to $131 million in 2005 approved regulatory guidelines. Impairment risk associated and $194 million in 2004.

with these assets relates to potentially adverse legislative, Pension expense in our non-qualified pension plans is judicial or regulatory actions in the future. expected to be approximately $19 million in 2006, compared to $16 million in 2005 and $14 million in 2004.

Pension and Other PostretirementBenefits Accounting In the fourth quarter of 2005, we made a $500 million Our reported costs of providing non-contributory qualified voluntary contribution to our pension plan. As a result of our defined pension benefits and post employment benefits other voluntary contribution and the increased market value of than pensions are dependent upon numerous factors resulting pension plan assets, we recognized a prepaid benefit cost of $1 from actual plan experience and certain assumptions. billion as of December 31, 2005. As prescribed by SFAS 87, we Pension and OPEB costs are affected by employee demo- eliminated our additional minimum liability of $567 million graphics (including age, compensation levels, and employment and our intangible asset of $63 million. In addition, the entire periods), the level of contributions we make to the plans, and AOCL balance was credited by $295 million (net of $208 mil-earnings on plan assets. Such factors may be further affected lion of deferred taxes) as the fair value of trust assets exceeded by business combinations, which impact employee demo- the accumulated benefit obligation as of December 31, 2005.

graphics, plan experience and other factors. Pension and Health care cost trends continue to increase and wil OPEB costs are also affected by changes to key assumptions, affect future OPEB costs. The 2005 and 2004 composite including anticipated rates of return on plan assets, the dis- health care trend rate assumptions are approximately 9-11 %,

count rates and health care trend rates used in determining gradually decreasing to 5 % in later years. In determining our the projected benefit obligations for pension and OPEB costs. trend rate assumptions, we included the specific provisions of In accordance with SFAS 87, changes in pension and our health care plans, the demographics and utilization rates OPEB obligations associated with these factors may not be of plan participants, actual cost increases experienced in our immediately recognized as costs on the income statement, but health care plans, and projections of future medical trend generally are recognized in future years over the remaining rates. The effect on our pension and OPEB costs from changes average service period of plan participants. SPAS 87 and SFAS in key assumptions are as follows:

106 delay recognition of changes due to the long-term nature Increase inCosts from Adverse Changes inKey Assumptions of pension and OPEB obligations and the varying market con-Assumption Adverse Change Pension OPEB Total ditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in an millions)

Discount rate Decrease by 0.25% $10 S5 $15 any period may not reflect the actual level of cash benefits Long-term return on assets Decrease by 0.25w $10 $1 111 provided to plan participants and are significantly influenced Heath care trend rate Increase by I% na $41 $41 by assumptions about future market conditions and plan participants' experience. Ohio Transition Cost Amortization In selecting an assumed discount rate, we consider cur- In connection with the Ohio Companies' transition plan, rently available rates of return on high-quality fixed income the PUCO determined allowable transition costs based on investments expected to be available during the period to amounts recorded on the regulatory books of the Ohio maturity of the pension and other postretirenient benefit obli- Companies. These costs exceeded those deferred or capitalized gations. Due to declines in corporate bond yields and interest on our balance sheet prepared under GAAP since they includ-rates in general, we reduced the assumed discount rate as of ed certain costs which had not yet been incurred or that were December 31, 2005 to 5.75% from 6.00% and 6.25% used recognized on the regulatory financial statements (fair value as of December 31, 2004 and 2003, respectively. purchase accounting adjustments). We use an effective inter-Our assumed rate of return on pension plan assets con- est method for amortizing the Ohio Companies' transition siders historical market returns and economic forecasts for the costs, often referred to as a "mortgage-style" amortization.

types of investments held by our pension trusts. In 2005, 2004 The interest rate under this method is equal to the rate of and 2003, our qualified pension plan assets actually earned return authorized by the PUCO in the transition plan for each

$325 million or 8.2 %, $415 million or 11.1 % and $671 mil- respective company. In computing the transition cost amorti-lion or 24.2 %, respectively. Our qualified pension costs in zation, we include only the portion of the transition revenues 2005, 2004 and 2003 were computed using an assumed 9.0 % associated with transition costs included on the balance sheet rate of return on plan assets which generated $345 million, prepared under GAAP. Revenues collected for the off-balance

$286 million and $248 million expected returns on plan sheet costs and the return associated with these costs are rec-assets, respectively. The 2005 expected return was based upon ognized as income when received. Amortization of deferred projections of future returns and our pension trust investment customer shopping incentives and interest costs will be equal allocation of approximately 63 % equities, 33 % bonds, 2 % to the related revenue recovery that is recognized under the real estate and 2 % cash. The gains or losses generated as a RCP (see Note 2(A)).

result of the difference between expected and actual returns on plan assets are deferred and amortized and will increase Long-Lived Assets or decrease future net periodic pension expense, respectively. In accordance with SPAS 144, we periodically evaluate Using an expected rate of return on plan assets of 9.0 %, our long-lived assets to determine whether conditions exist we expect our qualified pension expense to be approximately that would indicate that the carrying value of an asset might FirstEnergy Corp. 2005 39

not be fully recoverable. The accounting standard requires that carrying value of the goodwill. Our annual review was if the sum of future cash flows (undiscounted) expected to result completed in the third quarter of 2005 with no impairment from an asset is less than the carrying value of the asset, an asset indicated.

impairment must be recognized in the financial statements. If SFAS 142 requires the goodwill of a reporting unit to be impairment has occurred, we recognize a loss - calculated as tested for impairment if there is a more-likely-than-not expec-the difference between the carrying value and the estimated tation that the reporting unit or a significant asset group fair value of the asset (discounted future net cash flows). within the reporting unit will be sold. In December 2005, The calculation of future cash flows is based on MYR qualified as an asset held for sale in accordance with assumptions, estimates and judgment about future events. SFAS 144. As a result, in the fourth quarter of 2005, the good-The aggregate amount of cash flows determines whether will of MYR was retested for impairment, resulting in a an impairment is indicated. The timing of the cash flows non-cash charge of $9 million (there is no corresponding is critical in determining the amount of the impairment. income tax benefit). In December 2004, the FSG subsidiaries qualified as an asset held for sale, resulting in a non-cash Asset Retirement Obligations charge of $36 million ($30 million, net of tax) in the fourth In accordance with SFAS 143 and FIN 47, we recognize quarter of 2004.

an ARO for the future decommissioning of our nuclear power The forecasts used in our evaluations of goodwill reflect plants and future remediation of other environmental liabili- operations consistent with our general business assumptions.

ties associated with all of our long-lived assets. The ARO Unanticipated changes in those assumptions could have a liability represents an estimate of the fair value of our current significant effect on our future evaluations of goodwill.

obligation related to nuclear decommissioning and the retire-ment or remediation of environmental liabilities of other NEW ACCOUNTING STANDARDS AND INTERPRETATIONS assets. A fair value measurement inherently involves uncer- FSPFAS 115-1 and FAS 124-1, 'The Meaning of tainty in the amount and timing of settlement of the liability. Other-Than-Temporary Impairment and its Application We use an expected cash flow approach to measure the fair to Certain Investments' value of the nuclear decommissioning and environmental Issued in November 2005, FSP 115-1 and FAS 124-1 remediation ARO. This approach applies probability weight- addresses the determination as to when an investment is con-ing to discounted future cash flow scenarios that reflect a sidered impaired, whether that impairment is other than range of possible outcomes. The scenarios consider settlement temporary, and the measurement of an impairment loss. The of the ARO at the expiration of the nuclear power plants' FSP finalized and renamed EITF 03-1 and 03-1-a to FSP FAS current license, settlement based on an extended license term 115-1. This FSP will (1) nullify certain requirements of Issue and expected remediation dates. 03-1 and supersedes EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of Income Taxes a Security Whose Cost Exceeds Fair Value," (2) clarify that an We record income taxes in accordance with the liability investor should recognize an impairment loss no later than method of accounting. Deferred income taxes reflect the net when the impairment is deemed other than temporary, even if tax effect of temporary differences between the carrying a decision to sell has not been made, and (3) be effective for amounts of assets and liabilities for financial reporting other-than-temporary impairment and analyses conducted in purposes and the amounts recognized for tax purposes. periods beginning after September 15, 2005. The FSP requires Investment tax credits, which were deferred when utilized, prospective application with an effective date for reporting are being amortized over the recovery period of the related periods beginning after December 15, 2005. We are currently property. Deferred income tax liabilities related to tax and evaluating this FSP Issue and any impact on our investments.

accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when FSP No. FAS 13-1, "Accountingfor Rental Costs Incurred the liabilities are expected to be paid. Deferred tax assets are during the Construction Period" recognized based on income tax rates expected to be in effect Issued in October 2005, FSP No. FAS 13-1 requires rental when they are settled. costs associated with ground or building operating leases that are incurred during a construction period to be recognized as Goodwill rental expense. The effective date of the FSP guidance is the In a business combination, the excess of the purchase first reporting period beginning after December 15, 2005. We price over the estimated fair values of the assets acquired will apply this FSP to all construction projects, new and in and liabilities assumed is recognized as goodwill. Based on progress, beginning afterJanuary 1, 2006.

the guidance provided by SFAS 142, we evaluate goodwill for impairment at least annually and make such evaluations more EITFIssue 04-13, "Accountingfor Purchases and Sales frequently if indicators of impairment arise. In accordance of Inventory with the Same Counterparty" with the accounting standard, if the fair value of a reporting In September 2005, the EITF reached a final consensus unit is less than its carrying value (including goodwill), the on Issue 04-13 concluding that two or more legally separate goodwill is tested for impairment. If an impairment is indicat- exchange transactions with the same counterparty should be ed we recognize a loss - calculated as the difference between combined and considered as a single arrangement for purpos-the implied fair value of a reporting unit's goodwill and the es of applying APB 29, when the transactions were entered 40 FirstEnergy Corp. 2005

into "in contemplation" of one another. If two transactions SPAS 123(R), "Share-Based Payment" are combined and considered a single arrangement, the EITF In December 2004, the FASB issued SEAS 123(R), a reached a consensus that an exchange of inventory should be revision to SEAS 123, which requires expensing stock options accounted for at fair value. Although electric power is not in the financial statements. Important to applying the new capable of being held in inventory, there is no substantive con- standard is understanding how to (1) measure the fair value ceptual distinction between exchanges involving power and of stock-based compensation awards and (2) recognize the other storable inventory. Therefore, we will adopt this EITF related compensation cost for those awards. For an award to effective for new arrangements entered into, or modifications qualify for equity classification, it must meet certain criteria or renewals of existing arrangements, in interim or annual in SEAS 123(R). An award that does not meet those criteria periods beginning after March 15, 2006. will be classified as a liability and remeasured each period.

SEAS 123(R) retains SEAS 123's requirements on accounting SPAS 154 - 'Accounting Changes and Error Corrections for income tax effects of stock-based compensation. In April

- a replacement of APB Opinion No. 20 and FASB 2005, the SEC delayed the effective date of SEAS 123(R) to Statement No. 3" annual, rather than interim, periods that begin after June 15, In May 2005, the FASB issued SFAS 154 to change the 2005. We adopted this Statement effectiveJanuary 1, 2006 requirements for accounting and reporting a change in with modified prospective application. We use the Black-accounting principle. It applies to all voluntary changes in Scholes option-pricing model to value options for disclosure accounting principle and to changes required by an account- purposes only and continued to apply this pricing model with ing pronouncement when that pronouncement does not the adoption of SFAS 123(R). As discussed in Note 4, we include specific transition provisions. This Statement requires reduced our use of stock options beginning in 2005, with no retrospective application to prior periods' financial statements stock options being awarded subsequent to 2004. As a result, of changes in accounting principle, unless it is impracticable all currently unvested stock options will vest by 2008. We to determine either the period-specific effects or the cumula- expect the adoption of SEAS 123(R) will increase annual tive effect of the change. In those instances, this Statement compensation expense (after-tax) by approximately $7 requires that the new accounting principle be applied to the million, $2 million and $0.5 million in 2006, 2007 and 2008, balances of assets and liabilities as of the beginning of the ear- respectively or $0.02 per share in 2006 and less than $0.01 liest period for which retrospective application is practicable per share in 2007 and 2008.

and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components SPAS 151, "Inventory Costs - an amendment of ARB No.

of equity or net assets in the statement of financial position) 43, Chapter 4" for that period rather than being reported in the Consolidated In November 2004, the FASB issued SEAS 151 to clarify Statements of Income. This Statement also requires that a the accounting for abnormal amounts of idle facility expense, change in depreciation, amortization, or depletion method for freight, handling costs and wasted material (spoilage).

long-lived, nonfinancial assets be accounted for as a change in Previous guidance stated that in some circumstances these accounting estimate affected by a change in accounting princi- costs may be "so abnormal" that they would require treatment ple. The provisions of this Statement are effective for as current period costs. SFAS 151 requires abnormal amounts accounting changes and corrections of errors made in fiscal for these items to always be recorded as current period costs.

years beginning after December 15, 2005. We adopted this In addition, this Statement requires that allocation of fixed Statement effective January 1, 2006. production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provi-SPAS 153, "Exchanges of Nonmonetary Assets - sions of this statement are effective for inventory costs an amendment of APB Opinion No. 29" incurred by us beginning January 1, 2006. We do not expect In December 2004, the FASB issued SFAS 153 amending it to have a material impact on the financial statements.

APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain excep-tions to that principle. SEAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has com-mercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange.

The provisions of this Statement are effective January 1, 2006 for FirstEnergy. This FSP is not expected to have a material impact on our financial statements.

FirstEnergy Corp. 2005 41

Consolidated Statements of Income (an millions, exceptper share amounts)

For the Years Ended December 31, 2005 2004 2003 REVENUES:

Electric utilities $9,704 $8,860 $8,777 Unregulated businesses 2,285 3,200 2,548 Total revenues 11,989 12,060 11,325 OPERATING EXPENSES AND TAXES:

Fuel and purchased power 4,011 4,469 4,159 Other operating expenses 3,725 3,374 3,640 Claim settlement (Note 8) - - (168)

Provision for depreciation 589 587 604 Amortization of regulatory assets 1,281 1,166 1,079 Deferral of new regulatory assets (405) (257) (194)

Goodwill impairment 9 12 91 General taxes 713 678 638 Total expenses 9,923 10,029 9,849 OPERATING INCOME 2,066 2,031 1,476 OTHER INCOME (EXPENSE):

Investment income 218 205 185 Interest expense (661) (671) (799)

Capitalized interest 19 25 32 Subsidiaries' preferred stock dividends (15) (21) (42)

Total other income (expense) (439) (462) (624)

INCOME TAXES 754 673 408 INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF ACCOUNTING CHANGES 873 896 444 Discontinued operations (net of income taxes (benefit) of ($9 million),

$1million and ($3 million) respectively) (Note 2(J)) 18 (18) (123)

Cumulative effect of accounting changes (net of income taxes (benefit) of ($17 million) and$72 million, respectively) (Note 2(K)) (30) - 102 NET INCOME $ 861 $ 878 $ 423 BASIC EARNINGS PER SHARE OF COMMON STOCK:

Income before discontinued operations and cumulative effect of accounting changes $ 2.66 $ 2.74 $ 1.46 Discontinued operations (Note 2(J)) 0.05 (0.06) (0.40)

Cumulative effect of accounting changes (Note 2(K)) (0.09) - 0.33 Net Income $ 2.62 $ 2.68 S 1.39 WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING 328 327 304 DILUTED EARNINGS PER SHARE OF COMMON STOCK:

Income before discontinued operations and cumulative effect of accounting changes $ 2.65 $2.73 $ 1.46 Discontinued operations (Note 2(J)) 0.05 (0.06) (0.40)

Cumulative effect of accounting changes (Note 2(K)) (0.09) - 0.33 Net income $2.61 $ 2.67 $ 1.39 WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING 330 329 305 The accomparrnng Notes to Consalidated f-nanal Statements are an integralpart of these statements 42 FirstEnergy Corp. 2005

Consolidated Balance Sheets (Inmillions)

As of December 31, 2005 2004 ASSETS CURRENT ASSETS:

Cash and cash equivalents $ 64 $ 53 Receivables -

Customers (less accumulated provisions of $38 million and $34 million, respectively, for uncollectible accounts) 1,293 979 Other (less accumulated provisions of $27 million and $26 million, respectively, for uncollectible accounts) 205 377 Materials and supplies, at average cost -

Owned 518 364 Under consignment _ 94 Prepayments and other 237 145 2,317 2,012 PROPERTY, PLANT AND EQUIPMENT:

Inservice 22,893 22,213 Less -Accumulated provision for depreciation 9,792 9,413 13,101 12,800 Construction work in progress 897 679 13,998 13,479 INVESTMENTS:

Nuclear plant decommissioning trusts 1,752 1,583 Investment inlease obligation bonds (Note 6) 890 951 Other 765 740 3,407 3,274 DEFERRED CHARGES:

Goodwill 6,010 6,050 Regulatory assets 4,486 5,499 Prepaid pension costs 1,023 Other 600 721 12,119 12,270

$31,841 $31,035 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES:

Currently payable long-term debt $ 2,043 $ 941 Short-term borrowings (Note 13) 731 170 Accounts payable 727 611 Accrued taxes 800 657 Other 1,152 929 5,453 3,308 CAPITALIZATION (See Consolidated Statements of Capitalization): 8,590 Common stockholders' equity 9,188 Preferred stock of consolidated subsidiaries not subject to mandatory redemption 184 335 Long-term debt and other long-term obligations 8,155 10,013 17,527 18,938 NONCURRENT LIABILITIES:

Accumulated deferred income taxes 2,726 2,324 Asset retirement obligations 1,126 1,078 Power purchase contract loss liability 1,226 2,001 Retirement benefits 1,316 1,239 Lease market valuation liability 851 936 Other 1,616 1,211 8,861 8,789 COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 6 and 14)

$31,841 $31,035 The accompanying Notes to Consolidated fnanoal Statements are an integral part of these balance sheets.

FirstEnergy Corp. 2005 43

Consolidated Statements of Capitalization (Dollars in millions xept per shore aounts)

As of December 31, 2005 2004 COMMON STOCKHOLDERS' EQUITY:

Common stock,$0.10 par value -authorized 375,000,000 shares-329,836,276 shares outstanding $ 33 $ 33 Other paid-in capital 7,043 7,056 Accumulated other comprehensive loss (Note 2(1)) (20) (313)

Retained earnings (Note 11(A)) 2,159 1,857 Unallocated employee stock ownership plan common stock- 1,444,796 and 2,032,800 shares, respectively (Note 4(B)) (27) (43)

Total common stockholders' equity 9,188 8,590 Number of Shares Optional Outstanding (Thousands) Redemption Price 2005 2004 Per Share Aggregate PREFERRED STOCK OF CONSOLIDATED SUBSIDIARIES NOT SUBJECT TO MANDATORY REDEMPTION (Note 1(B)):

Ohio Edison Company Cumulative,$100 par value-Authorized 6,000,000 shares 3.90% 153 153 $103.63 $16 15 15 4.40% 176 176 108.00 19 18 18 4.44% 137 137 103.50 14 14 14 4.56% 144 144 103.38 15 14 14 Total 610 610 64 61 61 Pennsylvania Power Company Cumulative,$ 100 par value-Authorized 1,200,000 shares 4.24% 40 40 103.13 4 4 4 4.25% 41 41 105.00 4 4 4 4.64% 60 60 102.98 6 6 6 7.75% - 250 - - 25 Total 141 391 14 14 39 Cleveland Electric Illuminating Company Cumulative, without par value-Authorized 4,000,000 shares

$ 7.40 Series A _ 500 _ _ 50 Adjustable Series L _ 474 _ _ 46 Total _ 974 _ - 96 Toledo Edison Company Cumulative,$100 par value-Authorized 3,000,000 shares

$ 4.25 160 160 104.63 17 16 16

$ 4.56 50 50 101.00 5 5 5

$ 4.25 100 100 102.00 10 10 10 310 310 32 31 31 Cumulative,$25 par value-Authorized 12,000,000 shares

$2.365 1,400 1,400 27.75 39 35 35 Adjustable Series A - 1,200 - - - 30 Adjustable Series B 1,200 1,200 25.00 30 30 30 2,600 3,800 69 65 95 Total 2,910 4,110 101 96 126 Jersey Central Power & Light Company Cumulative,$ 100 stated value-Authorized 15,600,000 shares 4.00% Series 125 125 106.50 13 13 13 44 FirstEnergy Corp. 2005

Consolidated Statements of Capitalization (Cont'd)

LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 11(C)) (anmillions)

(Interest rates refled weighted average rates )

First Mortage Bonds Secured Notes Unsecured Notes Total As of December 31, 2005 2004 2005 2004 2005 2004 2005 2004 Ohio Edison Co.-

Due 2005-2010 - $- $ 80 4.00% $113 $ 169 4.68% $331 $361 Due 2011-2015 - - - 3.35% 19 59 5.45% 150 150 Due 2016-2020 - - - 5.45% 108 108 - - -

Due 2026-2030 - - - 3.47% 180 180 _ _

Due 2031-2035 - - - 3.58% 205 249 _ _

Total-Ohio Edison - 80 625 765 481 511 $1,106 $1,356 Cleveland Electric Illuminating Co.-

Due 2005-2010 6.86% 125 125 6.23% 399 401 5.31% 28 28 Due 2011-2015 - - - 3.15% 40 40 5.72% 379 378 Due 2016-2020 - - - 6.72% 506 506 - - -

Due 2021-2025 - - - - - 143 _ _ _

Due 2026-2030 - - - 3.93% 29 29 _ _ _

Due 2031-2035 - - - 3.66% 219 76 9.00% 103 103 Total-Cleveland Electric 125 125 1,193 1,195 510 509 1,828 1,829 Toledo Edison Co.-

Due 2005-2010 - - - 7.13% 30 30 5.21% 54 91 Due 2016-2020 - - - - - 99 - - -

Due 2021-2025 - - - 3.26% 67 67 - - -

Due 2026-2030 - - - 5.90% 14 14 - - -

Due 2031-2035 - - - 3.57% 127 82 - - -

Total-Toledo Edison - - 238 292 54 91 292 383 Pennsylvania Power Co.-

Due 2005-2010 9.74% 5 6 5.55% 54 10 3.50% 15 15 Due 2011-2015 9.74% 5 5 5.40% 1 1 - - -

Due 2016-2020 9.74% 4 4 4.27% 28 45 - - -

Due 2021-2025 7.63% 6 6 3.60% 10 28 - - -

Due 2026-2030 - - - 5.44% 9 23 - - -

Due 2031-2035 - - - - 5 - - -

Total-Penn Power 20 21 102 112 15 15 137 148 Jersey Central Power

& Light Co.-

Due 2005-2010 6.85% 40 46 5.88% 245 261 - -

Due 2011-2015 7.10% 12 12 5.96% 125 125 _ _

Due 2016-2020 - - - 5.42% 494 495 _ _ _

Due 2021-2025 7.09% 275 325 - - - _ _ _

Total-Jersey Central 327 383 864 881 _ 1,191 1,264 Metropolitan Edison Co.-

Due 2005-2010 _ - 38 _- - 5.25% 250 250 Due 2011-2015 _- - - - 4.90% 400 400 Due 2021-2025 - - 28 - - - 3.25% 28 -

Due 2026-2030 5.95% 14 14 - - - - - -

Total-Metropolitan Edison 14 80 - - 678 650 692 730 Pennsylvania Electric Co.-

Due 2005-2010 5.35% 24 28 - - - 6.55% 135 143 Due 2011-2015 - - - - - - 5.13% 150 150 Due 2016-2020 _ - 20 - - - 6.16% 145 125 Due 2021-2025 _ - 25 - - - 3.19% 25 -

Total-Pennsylvania Electric 24 73 - - 455 418 479 491 FirstEnergy Corp. 2005 45

Consolidated Statements of Capitalization (Cont'd)

LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Cont'd)

Qnterest rates reffect weighted average rates) an millions)

First Mortage Bonds Secured Notes Unsecured Notes Total As of December 31, 2005 2004 2005 2004 2005 2004 2005  ; 2004 FirstEnergy Corp.-

Due 2005-2010 _$- $ - $- $- 5.50% $1,000 $1,515 Due 2011-2015 _- - 6.45% 1,500 1,500 Due 2031-2035 _- - 7.38% 1,500 1,500 Total-FirstEnergy - - - - 4,000 4,515 4,000 $ 4,515 Bay Shore Power - - 6.25% 134 138 - - - 134 138 Facilities Services Group - - 7.29% 4 7 - - - 4 7 FirstEnergy Generation - - - - - 4.25% 58 15 58 15 FirstEnergy Nuclear Generation - - - - - 4.17% 270 - 270 -

FirstEnergy Properties - - 7.89% 9 9 - - - 9 9 First Communications - - - - - _ _ 5 5 Total 510 762 3,169 3,399 6,521 6,729 10,200 10,890 Preferred stock subject to mandatory redemption - 17 Capital lease obligations 8. 10 Net unamortized premium (discount) on debt (10) 37 Long-term debt due within one year (2,043) (941)

Total long-term debt and other long-term obligations 8,155 10,013 TOTAL CAPITALIZATION $174527 $18,938 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements 46 FirstEnergy Corp. 2005

Consolidated Statements of Common Stockholders' Equity (Dolars in millions)

Accumulated Unallocated Other Other ESOP Comprehensive Number Par Paid- In Comprehensive Retained Common Income of Shares Value Capital Income (Loss) Earnings Stock Balance, January 1,2003 297,636,276 $30 $6,120 $(656) $1,635 $(78)

Net income $ 423 423 Minimum liability for unfunded retirement benefits, net of $102 million of income taxes 144 144 Unrealized gain on investments, net of

$53 million of income taxes 68 68 Currency translation adjustments 91 91 Comprehensive income $ 726 Stock options exercised (3)

Common stock issued 32,200,000 3 931 Allocation of ESOP shares 15 20 Cash dividends declared on common stock (453)

Balance, December 31, 2003 329,836,276 33 7,063 (353) 1,605 (58)

Net income $ 878 878 Minimum liability for unfunded retirement benefits, net of $(5) million of income taxes (6) (6)

Unrealized gain on derivative hedges, net of $10 million of income taxes 19 19 Unrealized gain on investments, net of

$20 million of income taxes 27 27 Comprehensive income $ 918 Stock options exercised (24)

Allocation of ESOP shares 17 15 Common stock dividends declared in 2004 payable in2005 (135)

Cash dividends declared on common stock (491)

Balance, December 31, 2004 329,836,276 33 7,056 (313) 1,857 (43)

Net income $ 861 861 Minimum liability for unfunded retirement benefits, net of $208 million of income taxes 295 295 Unrealized gain on derivative hedges, net of $9million of income taxes 14 14 Unrealized loss on investments, net of $(15) million of income taxes (16) (16)

Comprehensive income $1,154 Stock options exercised (41)

Allocation of ESOP shares 22 16 Restricted stock units 6 Cash dividends declared on common stock (559)

Balance, December 31, 2005 329,836,276 $33 $7,043 $ (20) $2,159 $(27)

Theaccomponying Notes to Consolidated Fnanrial Statements are an integral part of these statement FirstEnergy Corp. 2005 47

Consolidated Statements of Preferred Stock (Dollars in milhons)

Not Subject to Mandatory Redemption Subject to Mandatory Redemption*

Number of Shares Par or Stated Value Number of Shares Par or Stated Value Balance, January 1,2003 6,209,699 $335 17,202,500 $430 Redemptions-7.625% Series (7,500) (1)

$7.35 Series C (10,000) (1) 8.56% Series (5,000,000) (125)

FIN 46 Deconsolidation-9.00% Series (4,000,000) (100) 7.35% Series (4,000,000) (92) 7.34% Series (4,000,000) (92)

Balance, December 31, 2003 6,209,699 335 185,000 19 Redemptions-7.625% Series (7,500) (1)

$7.35 Series C (10,000) (1)

Balance, December 31, 2004 6,209,699 335 167,500 17 Redemptions-7.750% Series (250,000) (25)

$7.40 Series A (500,000) (50)

Adjustable Series L (474,000) (46)

Adjustable Series A (1,200,000) (30) 7.625% Series (127,500) (13)

$7.35 Series C (40,000) (4)

Balance, December 31, 2005 3,785,699 $184 $ -

stock subjed to mandaoowy redemption isdassified as debt under SFAS Prefeened ISW Theoaompanying Notes to Consolidated Financial Statements ore an integral part of these statements 48 FirstEnergy Corp. 2005

Consolidated Statements of Cash Flows (Dofors inmillions)

For the Years Ended December 31, 2005 2004 2003 CASH FLOWS FROM OPERATING ACTIVITIES:

Net Income $861 $878 $423 Adjustments to reconcile net income to net cash from operating activities-Provision for depreciation 589 587 604 Amortization of regulatory assets 1,281 1,166 1,079 Deferral of new regulatory assets (405) (257) (194)

Nuclear fuel and lease amortization 90 96 66 Deferred purchased power and other costs (384) (451) (459)

Deferred income taxes and investment tax credits, net 154 258 (18)

Disallowed regulatory assets - - 153 Investment impairments (Note 2(H)) 15 30 135 Cumulative effect of accounting changes 30 - (102)

Deferred rents and lease market valuation liability (104) (84) (119)

Revenue credits to customers - - (72)

Accrued compensation and retirement benefits 90 156 202 Tax refund related to pre-merger period 18 - 51 Commodity derivative transactions, net 6 18 19 Loss (income) from discontinued operations (Note 2(J)) (18) 18 123 Cash collateral 196 (63) (89)

Pension trust contribution (500) (500) -

Decrease (increase) inoperating assets-Receivables (87) 154 66 Materials and supplies (60) (9) 5 Prepayments and other current assets 3 47 (31)

Increase (decrease) inoperating liabilities-Accounts payable 32 (111) (170)

Accrued taxes 154 (13) 222 Accrued interest (6) (42) (60)

Electric service prepayment programs 208 (18) (16)

NUG power contract restructuring - 53 -

Other 57 (21) (41)

Net cash provided from operating activities 2,220 1,892 1,777 CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-Common Stock - - 934 Long-term debt 721 961 1,027 Short-term borrowings, net 561 - -

Redemptions and Repayments-Preferred stock (170) (2) (127)

Long-term debt (1,424) (1,572) (2,129)

Short-term borrowings, net - (351) (575)

Net controlled disbursement activity (18) (2) 25 Common stock dividend payments (546) (491) (453)

Net cash used for financing activities (876) (1,457) (1,298)

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (1,208) (846) (856)

Proceeds from asset sales 61 214 79 Proceeds from certificates of deposit - 278 -

Nonutility generation trusts withdrawals (contributions) - (51) 66 Contributions to nuclear decommissioning trusts (101) (101) (101)

Long-term note receivable - - 82 Cash investments (Note 5) 36 27 53 Other (121) (17) 86 Net cash used for investing activities (1,333) (496) (591)

Net increase (decrease) in cash and cash equivalents 11 (61) (112)

Cash and cash equivalents at beginning of year 53 114 226 Cash and cash equivalents at end of year $64 $ 53 $114 SUPPLEMENTAL CASH FLOW INFORMATION:

Cash Paid During the Year-Interest (net of amounts capitalized) $665 $704 $730 Income taxes $406 $512 $162 The accomponying Notes to Consolidated Financial Statements ore an integral part ofthese statements FirstEnergy Corp. 2005 49

Consolidated Statements of Taxes (Dollars inmillions)

For the Years Ended December 31. 2005 2004 2003 GENERAL TAXES:

Kilowatt-hour excise* $ 244 $ 236 $ 228 State gross receipts* 151 140 130 Real and personal property 222 208 184 Social security and unemployment 79 76 68 Other 17 18 28 Total general taxes $ 713 $ 678 $ 638 PROVISION FOR INCOME TAXES:

Currently payable-Federal $ 456 $ 283 $ 309 State 143 133 118 Foreign - - (1) 599 416 426 Deferred, net-Federal 72 245 16 State 110 39 (8) 182 284 8 Investment tax credit amortization (27) (27) (26)

Total provision for income taxes $ 754 $ 673 $ 408 RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:

Book income before provision for income taxes $1,627 $1,569 $ 852 Federal income tax expense at statutory rate $569 $549 $ 298 Increases (reductions) intaxes resulting from-Amortization of investment tax credits (27) (27) (26)

State income taxes, net of federal income tax benefit 165 111 72 Penalties 14 -

Amortization of tax regulatory assets 38 33 32 Preferred stock dividends 5 8 7 Reserve for foreign operations - - 44 Other, net (10) (1) (19)

Total provision for income taxes $ 754 $ 673 $ 408 ACCUMULATED DEFERRED INCOME TAXES AS OF DECEMBER 31:

Property basis differences $2,368 $2,348 $2,180 Regulatory transition charge 537 785 1,085 Customer receivables for future income taxes 131 103 139 Shopping credit incentive deferral 321 252 153 Deferred sale and leaseback costs (86) (92) (95)

Nonutility generation costs (177) (174) (221)

Unamortized investment tax credits (54) (61) (70)

Other comprehensive income (18) (219) (244)

Retirement benefits (135) (280) (445)

Lease market valuation liability (361) (420) (455)

Oyster Creek securitization (Note 11(D)) 173 184 193 Loss carryforwards (417) (463) (495)

Loss carryforward valuation reserve 402 420 471 Asset retirement obligations 65 71 64 Deferred nuclear expenses (105) (100) (65)

All other 82 (30) (17)

Net deferred income tax liability $2,726 $2,324 $2,178

• Coleded from customers through regulted rates and induded inrevenue inthe Consolidated Statements of Income Theaccompanying Notes to Consolidated Fnancial Statements are an integral part of these statements 50 FirstEnergy Corp. 2005

Notes to Consolidated Financial Statements I. ORGANIZATION AND BASIS OF PRESENTATION 2.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES FirstEnergy's principal business is the holding, directly or (A)ACCOUNTING FOR THE EFFECTS OF REGULATION indirectly, of all of the outstanding common stock of its eight FirstEnergy accounts for the effects of regulation principal electric utility operating subsidiaries: OE, CEI, TE, through the application of SFAS 71 to its operating utilities Penn, ATSI, JCP&L, Met-Ed and Penelec. Penn is a wholly since their rates:

owned subsidiary of OE. FirstEnergy's consolidated financial statements also include its other subsidiaries: FENOC, FES

• are established by a third-party regulator with the and its subsidiary FGCO, NGC, FESC, FSG and MYR. authority to set rates that bind customers; FirstEnergy and its subsidiaries follow GAAP and comply

• are cost-based; and with the regulations, orders, policies and practices prescribed

• can be charged to and collected from customers.

by the SEC, FERC and, as applicable, PUCO, PPUC and NJBPU. The preparation of financial statements in conformity An enterprise meeting all of these criteria capitalizes with GAAP requires management to make periodic estimates costs that would otherwise be charged to expense if the rate and assumptions that affect the reported amounts of assets, actions of its regulator make it probable that those costs will liabilities, revenues and expenses and disclosure of contingent be recovered in future revenue. SFAS 71 is applied only to the assets and liabilities. Actual results could differ from these parts of the business that meet the above criteria. If a portion estimates. The reported results of operations are not indicative of the business applying SFAS 71 no longer meets those of results of operations for any future period. requirements, previously recorded regulatory assets are FirstEnergy and its subsidiaries consolidate all majority- removed from the balance sheet in accordance with the owned subsidiaries over which they exercise control and, guidance in SFAS 101.

when applicable, entities for which they have a controlling In Ohio, Pennsylvania and NewJersey, laws applicable to financial interest. Intercompany transactions and balances are electric industry restructuring contain similar provisions that eliminated in consolidation. FirstEnergy consolidates a VIE are reflected in the Companies' respective state regulatory (see Note 7) when it is determined to be the VIE's primary plans. These provisions include:

beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to

• restructuring the electric generation business and allow-exercise significant influence, but not control (20-50 % owned ing the Companies' customers to select a competitive companies, joint ventures and partnerships) are accounted electric generation supplier other than the Companies; for under the equity method. Under the equity method, the

• establishing or defining the PLR obligations to cus-interest in the entity is reported as an investment in the tomers in the Companies' service areas; Consolidated Balance Sheets and the percentage share of the

• providing the Companies with the opportunity to recover entity's earnings is reported in the Consolidated Statements potentially stranded investment (or transition costs) of Income. not otherwise recoverable in a competitive generation Certain prior year amounts have been reclassified to market; conform to the current year presentation. Certain businesses

• itemizing (unbundling) the price of electricity into its divested in 2005 have been classified as discontinued component elements - including generation, transmis-operations on the Consolidated Statements of Income (see sion, distribution and stranded costs recovery charges; Note 2Q)). As discussed in Note 16, segment reporting in

• continuing regulation of the Companies' transmission 2004 and 2003 was reclassified to conform to the 2005 and distribution systems; and business segment organization and operations.

• requiring corporate separation of regulated and Unless otherwise indicated, defined terms used herein unregulated business activities.

have the meanings set forth in the accompanying Glossary of Terms. Rsgulatory Assets The Companies and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered from customers under the Companies' respective transition and regulatory plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distri-bution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of FirstEnergy Corp. 2005 51

SFAS 71 to those operations. Regulatory assets that do not estimated net amortization of regulatory transition costs and earn a current return totaled approximately $255 million as Extended RTCs (including associated carrying charges) under of December 31, 2005. the RCP for the period 2006 through 2010:

Net regulatory assets on the Consolidated Balance Sheets Amortization Period OE CEI TE Total Ohio are comprised of the following:

An milions) 2006 $169 $100 $ 80 $ 349 2005 2004 2007 176 111 89 376 2008 198 129 100 427 (in ilnons) 2009 - 216 - 216 Regulatory transition costs $3,576 $4,889 2010 - 268 - 268 Customer shopping incentives 884 612 $1,636 Customer receivables for future income taxes 217 246 Total Amortization $543 $824 $269 Societal benefits charge 29 51 Loss on reacquired debt 41 56 Employee postretirement benefit costs 55 65 Nudear decommissioning decontamination Regulatory transition costs as of December 31, 2005 for and spent fuel disposalcosts (126) (169)

Asset removal costs (365) (340) JCP&L and Met-Ed are approximately $2.2 billion and $308 Property losses and unrecovered plant costs 29 50 million, respectively. Deferral of above-market costs from MISO transmission costs 91 -

JCP&L reliability costs 23 - power supplied by NUGs to JCP&L are approximately $1.2 bil-Other 32 39 lion and are being recovered through BGS and MTC revenues.

Total $4,486 $5,499 Met-Ed has deferred above-market NUG costs totaling approxi-mately $143 million. These costs are being recovered through CTC revenues. The liability for projected above-market NUG The Ohio Companies have been deferring customer costs and corresponding regulatory asset are adjusted to fair shopping incentives and interest costs (Extended RTC) as new value at the end of each quarter. Recovery of the remaining regulatory assets in accordance with the prior transition and regulatory transition costs is expected to continue under the rate stabilization plans. As a result of the RCP approved in provisions of the various regulatory proceedings for New January 2006, the Extended RTC balances (OE - $325 mil- Jersey and Pennsylvania discussed in Note 10.

lion, CEI - $427 million, TE - $132 million, as of December 31, 2005) were reduced on January 1, 2006 by $75 million for (B) CASH AND SHORT-TERM FINANCIAL INSTRUMENTS OE, $85 million for CEI and $45 million for TE by accelerat- All temporary cash investments purchased with an initial ing the application of those amounts of each respective maturity of three months or less are reported as cash equiva-company's accumulated cost of removal regulatory liability lents on the Consolidated Balance Sheets at cost, which against the Extended RTC balances. In accordance with the approximates their fair market value.

RCP, the recovery periods for the aggregate of the regulatory transition costs and the Extended RTC amounts were adjusted (C) REVENUES AND RECEIVABLES so that recovery of these aggregate amounts through each The Companies' principal business is providing electric company's RTC rate component began on January 1, 2006, service to customers in Ohio, Pennsylvania and New Jersey.

with full recovery expected to be completed for OE and TE as The Companies' retail customers are metered on a cycle basis.

of December 31, 2008. CEI's recovery of its regulatory transi- Electric revenues are recorded based on energy delivered tion costs is projected to be completed by April 2009 at which through the end of the calendar month. An estimate of time recovery of its Extended RTC will begin, with recovery unbilled revenues is calculated to recognize electric service estimated to be completed as of December 31, 2010. At the provided between the last meter reading and the end of the end of their respective recovery periods, any remaining month. This estimate includes many factors including estimat-unamortized regulatory transition costs and Extended RTC ed weather impacts, customer shopping activity, historical line balances will be eliminated, first, by applying any remaining loss factors and prices in effect for each class of customer. In cost of removal regulatory liability balances; and then by each accounting period, the Companies accrue the estimated writing off any remaining regulatory transition costs and unbilled amount receivable as revenue and reverse the related Extended RTC balances. In addition, the RCP allowed the prior period estimate.

Ohio Companies to defer and capitalize certain distribution Receivables from customers include sales to residential, costs during the period January 1, 2006 through December 31, commercial and industrial customers and sales to wholesale 2008, not to exceed $150 million in each of the years 2006, customers. There was no material concentration of receivables 2007 and 2008. These deferrals will be recovered in distribu- as of December 31, 2005 with respect to any particular seg-tion rates effective on or afterJanuary 1, 2009. See Note 10 ment of FirstEnergy's customers. Total customer receivables for further discussion of the recovery of the shopping incen- were $1.3 billion (billed - $841 million and unbilled - $452 tives and the new cost deferrals. million) and $979 million (billed - $672 million and unbilled -

$307 million) as of December 31, 2005 and 2004, respectively.

Transition Cost Amortization OE, CEI and TE amortize transition costs (see Regulatory Matters - Ohio) using the effective interest method. Extended RTC amortization will be equal to the related revenue recov-ery that is recognized. The following table provides the 52 FirstEnergy Corp. 2005

(D) ACCOUNTING FOR CERTAIN WHOLESALE ENERGY Reconciliation of Basic and Diluted Earnings per Share of Common Stock 2005 2004 2003 TRANSACTIONS (Onnmliorn, exceptper share amounts)

FES engages in purchase and sale transactions in the PJM Income Before Discontinued Operations and Market to support the supply of end-use customers, including Cumulative Effect of Accounting Changes $ 873 $ 896 $ 444 Average Shares of Common Stock Outstanding:

PLR requirements in Pennsylvania. In conjunction with Denominator for basic earnings per share FirstEnergy's dedication of its Beaver Valley Plant to PJM on (weighted average shares outstanding) 328 327 304 Assumed exercise of dilutive stock options and awards 2 2 1 January 1, 2005, FES began accounting for purchase and sale Denominator for diluted earnings per share 330 329 305 transactions in the PJM Market based on its net hourly posi-tion - recording each hour as either an energy purchase or Income Before Discontinued Operations and Cumulative Effect of Accounting Changes, per common share:

an energy sale in the Consolidated Statements of Income Basic $2.66 $2.74 $1.46 Diluted $2.65 $2.73 $1.46 relating to the Power Supply Management Services segment.

Hourly energy positions are aggregated to recognize gross purchases and sales for the month. This revised method of (F) PROPERTY, PLANT AND EQUIPMENT accounting, which has no impact on net income, is consistent Property, plant and equipment reflects original cost with the practice of other energy companies that have dedicat- (except for nuclear generating assets which were adjusted to ed generating capacity in PJM and correlates with PJM's fair value in accordance with SFAS 144), including payroll scheduling and reporting of hourly energy transactions. FES and related costs such as taxes, employee benefits, administra-also applies the net hourly methodology to purchase and sale tive and general costs, and interest costs incurred to place the transactions in MISO's energy market, which became active assets in service. The costs of normal maintenance, repairs on April 1, 2005. and minor replacements are expensed as incurred.

For periods prior to January 1, 2005, FirstEnergy did not FirstEnergy's accounting policy for planned major mainte-have substantial generating capacity in PJM and as such, FES nance projects is to recognize liabilities as they are incurred.

recognized purchases and sales in the PJM Market by record- The Companies provide for depreciation on a straight-line ing each discrete transaction. Under those transactions, FES basis at various rates over the estimated lives of property would often buy a specific quantity of energy at a certain included in plant in service. The respective annual composite location in PJM and simultaneously sell a specific quantity rates for the Companies' electric plant in 2005, 2004 and 2003 of energy at a different location. Physical delivery occurred are shown in the following table:

and the risks and rewards of ownership transferred with each transaction. FES accounted for those transactions on a gross Annual Composite Depredation Rate 2005 2004 2003 basis in accordance with EITF 99-19. The recognition of those OE 2.1w 2.3w 2.2%

CEI 2.9 2.8 2.8 transactions on a net basis in prior periods would have no TE 3.1 2.8 2.8 impact on net income, but would have reduced both wholesale Penn 2.4 2.2 2.2 JCP&L 2.2 2.1 2.8 revenue and purchased power expense by $1.1 billion and Met-Ed 2.4 2A 2.6

$617 million in 2004 and 2003, respectively. Penelec 2.6 2.5 2.7 (E) EARNINGS PER SHARE OF COMMON STOCK In October 2005, the Ohio Companies' and Penn's non-Basic earnings per share of common stock are computed nuclear generation assets were transferred to FGCO and in using the weighted average of actual common shares outstand-December 2005, the Ohio Companies' and Penn's nuclear ing during the respective period as the denominator. The generation assets were transferred to NGC. FGCO and NGC denominator for diluted earnings per share of common stock provide for depreciation on a straight-line basis at various reflects the weighted average of common shares outstanding rates over the estimated lives of property included in plant in plus the potential additional common shares that could result service.

if dilutive securities and other agreements to issue common stock were exercised. In 2004 and 2003, stock-based awards Jointly-Owned GeneratingStations to purchase shares of common stock totaling 0.1 million and JCP&L holds a 50 % ownership interest in Yards Creek 3.3 million, respectively, were excluded from the calculation Pumped Storage Facility - its net book value was approximately of diluted earnings per share of common stock because their $20 million as of December 31, 2005. All other generating units exercise prices were greater than the average market price of are owned and/or leased by FGCO, NGC and the Companies.

common shares during the period. No stock-based awards were excluded from the calculation in 2005. The following table Asset Retirement Obligations reconciles the denominators for basic and diluted earnings FirstEnergy recognizes a liability for retirement obliga-per share of common stock from Income Before Discontinued tions associated with tangible assets in accordance with SFAS Operations and Cumulative Effect of Accounting Changes:

143 and FIN 47. These standards require recognition of the fair value of a liability for an ARO in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and depreciated over time, as described further in Note 12, "Asset Retirement Obligations".

FirstEnergy Corp. 2005 53

Nuclear Fuel exceeded the fair value, resulting in a non-cash goodwill Property, plant and equipment includes nuclear fuel impairment charge of $9 million in the fourth quarter of recorded at original cost, which includes material, enrich- 2005, with no corresponding income tax benefit ment, fabrication and interest costs incurred prior to reactor FirstEnergy's 2004 annual review was completed in the load. Nuclear fuel is amortized based on the units of produc- third quarter of 2004 with no impairment indicated. In tion method. December 2004, the FSG subsidiaries qualified as an asset held for sale in accordance with SFAS 144. As required by (G) STOCK-BASED COMPENSATION SFAS 142, the goodwill of FSG was tested for impairment, FirstEnergy applies the recognition and measurement resulting in a non-cash charge of $36 million in the fourth principles of APB 25 and related Interpretations in accounting quarter of 2004. Of that amount, $12 million was reported for its stock-based compensation plans (see Note 4). No mate- as an operating expense and $24 million was included in rial stock-based employee compensation expense for options the results from discontinued operations. FSG's fair value is reflected in net income as all options granted under those was estimated using current market valuations.

plans had an exercise price equal to the market value of the FirstEnergy's 2003 annual review resulted in a goodwill underlying common stock on the grant date, resulting in impairment charge of $122 million in the third quarter of substantially no intrinsic value. FirstEnergy will apply the 2003, reducing the carrying value of FSG. Of that amount, recognition and measurement principles of SFAS 123(R) $91 million is reported as an operating expense and $31 mil-effective January 1, 2006 (see Note 17). lion is included in the results from discontinued operations.

The impairment charge reflected the slow down in the devel-(H) ASSET IMPAIRMENTS opment of competitive retail markets and depressed economic conditions that affected the value of FSG. The fair value of Long-Lived Assets FSG was estimated using primarily its expected discounted FirstEnergy evaluates the carrying value of its long-lived future cash flows.

assets when events or circumstances indicate that the carrying The forecasts used in FirstEnergy's evaluations of good-amount may not be recoverable. In accordance with SFAS 144, will reflect operations consistent with its general business the carrying amount of a long-lived asset is not recoverable if assumptions. Unanticipated changes in those assumptions it exceeds the sum of the undiscounted cash flows expected to could have a significant effect on FirstEnergy's future evalua-result from the use and eventual disposition of the asset. If an tions of goodwill. FirstEnergy's goodwill primarily relates to impairment exists, a loss is recognized for the amount by its regulated services segment. In the year ended December which the carrying value of the long-lived asset exceeds its 31, 2005, FirstEnergy adjusted goodwill related to the divesti-estimated fair value. Fair value is estimated by using available ture of non-core operations (FES' retail natural gas business, market valuations or the long-lived asset's expected future net MYR's Power Piping Company subsidiary, and a portion of its discounted cash flows. The calculation of expected cash flows interest in FirstCom) as further discussed in Note 8. In addi-is based on estimates and assumptions about future events. tion, adjustments to the former GPU and Centerior companies' goodwill were recorded to reverse pre-merger tax Goodwill accruals due to final resolution of these tax contingencies.

In a business combination, the excess of the purchase The impairment analysis includes a significant source of cash price over the estimated fair values of assets acquired and representing the Companies' recovery of transition costs as liabilities assumed is recognized as goodwill. Based on the described in Note 10. FirstEnergy estimates that completion guidance provided by SFAS 142, FirstEnergy evaluates its of transition cost recovery will not result in an impairment goodwill for impairment at least annually and makes such of goodwill relating to its regulated business segment.

evaluations more frequently if indicators of impairment arise. A summary of the changes in FirstEnergy's goodwill for In accordance with the accounting standard, if the fair value the three years ended December 31, 2005 is shown below by of a reporting unit is less than its carrying value (including segment (see Note 16 - Segment Information):

goodwill), the goodwill is tested for impairment. If an impair-ment is indicated, FirstEnergy recognizes a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill.

FirstEnergy's 2005 annual review was completed in the third quarter of 2005 with no impairment indicated.

In December 2005, MYR qualified as an asset held for sale in accordance with SFAS 144. SFAS 142 requires the goodwill of a reporting unit to be tested for impairment if there is a more-likely-than-not expectation that the reporting unit or a significant asset group within the reporting unit will be sold.

As a result, in the fourth quarter of 2005, the goodwill of MYR was retested for impairment. Based on market valua-tions that were not available prior to the fourth quarter of 2005, it was determined that the carrying value of MYR 54 FirstErergy Corp. 2005

Power Other comprehensive income reclassified to net income Supply Regulated Management Fadlities in 2005, 2004 and 2003 totaled $52 million, $8 million and Services Services Services Other Consolidated $29 million, respectively. These amounts were net of income (InMillions) taxes in 2005, 2004 and 2003 of $35 million, $6 million and Balance as of $20 million, respectively.

January 1, 2003 $5,993 $24 $196 $65 $6,278 Impairment charges (122) (122)

FSG divestitures (41) (41)

Other 3 10 13 (J)ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS In 2005, three FSG subsidiaries, Elliott-Lewis, Spectrum Balance as of December 31, 2003 5,993 24 36 75 6,128 and Cranston, and MYR's Power Piping Company subsidiary Impairment charges (36) (36) were sold resulting in an after-tax gain of $13 million. As of Adjustments related to GPU acquisition (42) (42) December 31, 2005, the remaining FSG subsidiaries continue Balance as of to qualify as assets held for sale in accordance with SPAS 144.

December 31, 2004 5,951 24 - 75 6,050 Management anticipates that the transfer of FSG assets, with Impairment charges (9) (9)

Non-core asset sales (12) (12) a carrying value of $100 million as of December 31, 2005 will Adjustments related qualify for recognition as completed sales within one year.

to GPU acquisition (10) (10)

Adjustments related The FSG facilities which were deemed held for sale as of to Centerior acquisition (9) (9)

December 31, 2004 continue to be actively marketed as of Balance as of December 31, 2005 and meet the criteria under SPAS 144 to December 31, 2005 $5,932 $24 $ - $54 $6,010 continue to qualify as held for sale. As of December 31, 2005, the FSG subsidiaries classified as held for sale did not meet Investments the criteria for discontinued operations. The carrying FirstEnergy periodically evaluates other investments for amounts of FSG's assets and liabilities held for sale are not impairment, including available-for-sale securities held by its material and have not been classified as assets held for sale nuclear decommissioning trusts. In accordance with SPAS 115, on FirstEnergy's Consolidated Balance Sheet. See Note 16 for securities classified as available-for-sale are evaluated to deter- FSG's segment financial information.

mine whether a decline in fair value below the cost basis is In December 2005, MYR qualified as an asset held for other than temporary. If the decline in fair value is determined sale but did not meet the criteria to be classified as a discon-to be other than temporary, the cost basis of the security is writ- tinued operation. Management anticipates that the transfer of ten down to fair value. FirstEnergy considers, among other MYR assets, with a carrying value of $226 million as of factors, the length of time and the extent to which the security's December 31, 2005, will qualify for recognition as completed fair value has been less than cost and the near-term financial sales within one year. As required by SFAS 142, the goodwill prospects of the security issuer when evaluating investments of MYR was tested for impairment, resulting in a non-cash for impairment. The fair value and unrealized gains and losses charge of $9 million in the fourth quarter of 2005 (see Note of FirstEnergy's investments are disclosed in Note 5. 2(H)). The carrying amounts of MYR's assets and liabilities held for sale are not material and have not been classified as (I) COMPREHENSIVE INCOME assets held for sale on FirstEnergy's Consolidated Balance Comprehensive income includes net income as reported Sheet. See Note 16 for MYR's segment financial information.

on the Consolidated Statements of Income and all other In December 2004, the FES retail natural gas business changes in common stockholders' equity except those result- qualified as assets held for sale in accordance with SPAS 144.

ing from transactions with common stockholders. As of As required by SPAS 142, goodwill associated with the FES December 31, 2005, AOCL consisted of a minimum liability natural gas business was tested for impairment as of December for unfunded retirement benefits on non-qualified plans of 31, 2004 with no impairment indicated. On March 31, 2005,

$17 million, unrealized gains on investments in securities FES completed the sale for an after-tax gain of $5 million.

available for sale of $74 million and unrealized losses on The FSG subsidiaries, Colonial Mechanical, Webb derivative instrument hedges of $77 million. A summary Technologies and Ancoma, Inc., and MARBEL subsidiary, of the changes in FirstEnergy's AOCL balance for the three NEO, were sold in 2003. The financial results for these divest-years ended December 31, 2005 is shown below: ed businesses included in discontinued operations totaled a loss of $4 million for the year ended December 31, 2003 and 2005 2004 2003 are included in "FSG and MYR subsidiaries" and "Other" in o(Inillions) the table below.

AOCIL balance as of January 1, $(3 13) $(353) $(656)

In December 2003, EGSA, GPU Power's Bolivia Minimum liability for unfunded retirement benefits 503 (11) 246 subsidiary, was sold to Bolivia Integrated Energy Limited.

Unrealized gain (loss) on available for sale securities (31) 46 119 Unrealized gain (loss) on derivative hedges 23 29 2 FirstEnergy included in discontinued operations a $33 Currency translation adjustments - - 91 million loss on the sale of EGSA in the fourth quarter of Other comprehensive income 495 64 458 2003 (no income tax benefit was realized) and an operating Income taxes related to OCI 202 24 155 loss for the year of $2 million.

Other comprehensive income, net of tax 293 40 303 In April 2003, FirstEnergy divested its ownership in Emdersa through the abandonment of its shares in Emdersa's AOCL balance as of December 31, $ (20) S(313) $(353) parent company, GPU Argentina Holdings, Inc. The abandon-FirstEnergy Corp. 2005 55

ment was accomplished by relinquishing FirstEnergy's shares decommissioning. The cumulative effect adjustment also to the independent Board of Directors of GPU Argentina included the reversal of $60 million of accumulated estimated Holdings, relieving FirstEnergy of all rights and obligations removal costs for non-regulated generation assets.

relative to this business. FirstEnergy included in discontinued operations Emdersa's operating income of $7 million and a (L)INCOME TAXES

$67 million charge for the abandonment in the second quarter Details of the total provision for income taxes are shown of 2003 (no income tax benefit was recognized). on the Consolidated Statements of Taxes. FirstEnergy records Revenues associated with discontinued operations were income taxes in accordance with the liability method of

$206 million, $690 million and $819 million in 2005, 2004 accounting. Deferred income taxes reflect the net tax effect of and 2003, respectively. The following table summarizes the temporary differences between the carrying amounts of assets net income (loss) included in "Discontinued Operations" on and liabilities for financial reporting purposes and loss carry-the Consolidated Statements of Income for the three years forwards and the amounts recognized for tax purposes.

ended December 31, 2005: Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related 2005 2004 2003 property. Deferred income tax liabilities related to tax and an milions) accounting basis differences and tax credit carryforward items FESnatural gas business $5 S 4 $ (2)

EGSA - - (35) are recognized at the statutory income tax rates in effect when Emdersa - - (60) the liabilities are expected to be paid. Deferred tax assets are FSGand MYR subsidiaries 13 (22) (25)

Other - - (1) recognized based on income tax rates expected to be in effect Income (loss) from discontinued operations $18 S(18) $(123) when they are settled. (See Note 9 for Ohio Tax Legislation discussion.)

FirstEnergy has certain tax returns that are under review (K) CUMULATIVE EFFECT OF ACCOUNTING CHANGES at the audit or appeals level of the IRS and certain state Results in 2005 include an after-tax charge of $30 million authorities. Since reserves have been recorded, final settle-recorded upon the adoption of FIN 47 in December 2005. ments of these audits are not expected to have a material FirstEnergy identified applicable legal obligations as defined adverse effect on FirstEnergy's financial condition or result under the new standard at its active and retired generating of operations.

units, substation control rooms, service center buildings, line FirstEnergy has capital loss carryforwards of approxi-shops and office buildings, identifying asbestos as the primary mately $1 billion, most of which expire in 2007. The deferred conditional ARO. The Company recorded a conditional ARO tax assets associated with these capital loss carryforwards liability of $57 million (including accumulated accretion for ($354 million) are fully offset by a valuation allowance as of the period from the date the liability was incurred to the date December 31, 2005, since management is unable to predict of adoption), an asset retirement cost of $16 million (recorded whether sufficient capital gains will be generated to utilize as part of the carrying amount of the related long-lived asset), all of these capital loss carryforwards. Any ultimate utilization and accumulated depreciation of $12 million. FirstEnergy of capital loss carryforwards for which valuation allowances charged regulatory liabilities for $5 million upon adoption of were established through purchase accounting would adjust FIN 47 for the transition amounts related to establishing the goodwill. During 2005 the valuation allowance was reduced ARO for asbestos removal from substation control rooms and by $13 million due to the utilization of capital loss carryfor-service center buildings for OE, Penn, CEI, TE and JCP&L. wards to offset realized capital gains, resulting in an The remaining cumulative effect adjustment for unrecognized adjustment to goodwill.

depreciation and accretion of $48 million was charged to Valuation allowances also include $48 million for income ($30 million, net of tax), or $0.09 per share of com- deferred tax assets associated with impairment losses related mon stock (basic and diluted share) for the year ended to certain domestic assets.

December 31, 2005. (See Note 12.) FirstEnergy has net operating loss carry forwards for As a result of adopting SFAS 143 in January 2003, state and local income tax purposes of approximately $766 FirstEnergy recorded a $175 million increase to income, $102 million. The associated deferred tax assets are $15 million.

million net of tax, or $0.33 per share of common stock (basic These losses expire as follows:

and diluted) in the year ended December 31, 2003. Upon adoption of the accounting standard, FirstEnergy reversed Expiration Period Amount accrued nuclear plant decommissioning costs of $1.24 billion (enmikeon) 2006-2010 $277 and recorded an ARO of $1.11 billion, including accumulated 2011-2015 34 accretion of $507 million for the period from the date the lia- 2016-2020 178 2021-2024 277 bility was incurred to the date of adoption. FirstEnergy also recorded asset retirement costs of $602 million as part of the $766 carrying amount of the related long-lived asset and accumulat-ed depreciation of $415 million. FirstEnergy recognized a regulatory liability of $185 million for the transition amounts subject to refund through rates related to the ARO for nuclear 56 FirstEnergy Corp. 2005

Obligations and Funded Status As of December 31

3. PENSION AND OTHER POSTRETIREMENT Pension Benefits Other Benefits BENEFIT PLANS 2005 2004 2005 2004 FirstEnergy provides noncontributory defined benefit On millions)

Change in benefit obligation pension plans that cover substantially all of its employees. Benefit obligation as of January 1 $4,364 $4,162 $ 1,930 S 2,368 The trusteed plans provide defined benefits based on years of Service cost 77 77 40 36 Interest cost 254 252 111 112 service and compensation levels. The Company's funding policy Plan participantsI contributions - - 18 14 Plan amendments 15 - (312) (281) is based on actuarial computations using the projected unit Actuarial (gain) loss 310 134 197 (211) credit method. In the fourth quarter of 2005, FirstEnergy made Benefits paid (270) (261) (100) (108) a $500 million voluntary cash contribution to its qualified pen- Benefit obligation as of December 31 $4,750 $4,364 $ 1,884 $ 1,930 sion plan. Projections indicated that absent this funding, cash Change In fair value of plan assets contributions would have been required at some point prior to Fair value of plan assets as of January 1 $3,969 $3,315 S 564 $ 537 2010. Pre-funding the pension plan is expected to eliminate this Actual return on plan assets 325 415 33 57 Company contribution 500 500 58 64 future funding requirement under current pension funding Plan participants' contribution - - 18 14 Benefits paid (270) (261) (100) (108) rules and should also minimize FirstEnergy's exposure to any funding requirements resulting from proposed pension reform. Fair value of plan assets S 573 $ 564 as of December 31 $4,524 $3,969 FirstEnergy provides a minimum amount of noncontribu-tory life insurance to retired employees in addition to optional Funded status $ (226) $ (395) $(1.311) 1(1,366)

Unrecognized net actuarial loss 1,179 885 899 730 contributory insurance. Health care benefits, which include Unrecognized prior service cost (benefit) 70 63 (645) (378) certain employee contributions, deductibles and co-payments, Net asset (liability) recognized $1,023 $ 553 $(1,057) $(1,014) are also available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circum- Amounts Recognized in the Consolidated Balance Sheets stances, their survivors. The Company recognizes the As of December 31 Prepaid benefit cost $1,023 $ - $ - $ -

expected cost of providing other postretirement benefits to Accrued benefit cost - (14) (1,057) (1,014) employees and their beneficiaries and covered dependents Intangible assets - 63 - -

Accumulated other comprehensive loss - 504 - -

from the time employees are hired until they become eligible Net amount recognized $1,023 $ 553 $(1,057) $(1,014) to receive those benefits. In addition, FirstEnergy has obliga-tions to former or inactive employees after employment, but Decrease in minimum liability induded in other comprehensive income before retirement for disability related benefits. (netof tax) $ (295) $ (4)

Pension and OPEB costs are affected by employee demo-Assumptions Used graphics (including age, compensation levels, and employment to Determine Benefit Obligations periods), the level of contributions made to the plans and earn- As of December 31 ings on plan assets. Such factors may be further affected by Discount rate 5.75% 6.00% 5.75% 6.00X Rate of compensation increase 3.50w 3.50w business combinations which impact employee demographics, plan experience and other factors. Pension and OPEB costs Allocation of Plan Assets As of December 31 may also be affected by changes in key assumptions, including Asset Category Equity securities 63X 68% 71% 74%

anticipated rates of return on plan assets, the discount rates Debt securities 33 29 27 25 and health care trend rates used in determining the projected Real estate 2 2 - -

Cash 2 1 2 1 benefit obligations and pension and OPEB costs. FirstEnergy uses a December 31 measurement date for most of its plans. Total 100% 100w 100w 100w Information for Pension Plans With an Accumulated Benefit Obligation hi Excess of Plan Assets 2005 2004 Onmillions)

Projected benefit obligation $4,750 $4,364 Accumulated benefit obligation 4,327 3,983 Fair value of plan assets 4,524 3,969 FirstEnergy Corp. 2005 57

Components of Net Periodic Benefit Costs one-percentage-point change in assumed health care cost trend Pension Benefits Other Benefits rates would have the following effects:

2005 2004 2003 2005 2004 2003 1-Percentage- 1-Percentage-an millons)

Point Increase Point Decrease Servicecost $77 $77 $ 66 S 40 $ 36 $ 43 Interest cost 254 252 253 111 112 137 an milons)

Expected return on plan assets (345) (286) (248) (45) (44) (43)

Effect on total of service and interest cost $23 $(19)

Effect on accumulated postretirement Amortzation ofprir service cost 8 9 9 (45) (40) (9) benefit obligation $239 $(209)

Amortization of I transition obligation - - - - - 9 Recognized net actuarial loss 36 39 62 40 39 40 Net periodic cost $30 $91 $142 $101 $103 $177 As a result of its voluntary contribution and the increased market value of pension plan assets, FirstEnergy recognized a prepaid benefit cost of $1 billion as of December 31, 2005. As prescribed by SFAS 87, FirstEnergy eliminated Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 its additional minimum liability of $567 million and its intangible asset of $63 million. In addition, the entire AOCL Pension Benefits Other Benefits balance was credited by $295 million (net of $208 million 2005 2004 2003 2005 2004 2003 of deferred taxes) as the fair value of trust assets exceeded Discount rate 6.00' 6.25% 6.75' 6.00' 6.25' 6.75% the accumulated benefit obligation as of December 31, 2005.

Expected long-term return on plan assets 9.00' 9.00' 9.00' 9.00' 9.00% 9.00' Taking into account estimated employee future service, Rate of compensation FirstEnergy expects to make the following benefit payments increase 3.50' 3.50' 3.50' from plan assets:

In selecting an assumed discount rate, FirstEnergy con- Pension Benefits Other Benefits siders currently available rates of return on high-quality fixed (inmronm) 2006 $228 $106 income investments expected to be available during the period 2007 228 109 to maturity of the pension and other postretirement benefit 2008 236 112 2009 247 115 obligations. The assumed rates of return on pension plan 2010 264 119 Years 2011- 2015 1,531 642 assets consider historical market returns and economic forecasts for the types of investments held by the Company's pension trusts. The long-term rate of return is developed FirstEnergy also maintains two unfunded benefit plans, considering the portfolio's asset allocation strategy. an Executive Deferred Compensation Plan (EDCP) and FirstEnergy employs a total return investment approach Supplemental Executive Retirement Plan (SERP) under whereby a mix of equities and fixed income investments are which non-qualified supplemental pension benefits are paid to used to maximize the long-term return on plan assets for a certain employees in addition to amounts received under the prudent level of risk. Risk tolerance is established through Company's qualified retirement plan, which is subject to IRS careful consideration of plan liabilities, plan funded status, limitations on covered compensation. See Note 4(C) for a dis-and corporate financial condition. The investment portfolio cussion regarding the stock compensation component of the contains a diversified blend of equity and fixed-income invest- EDCP. The net periodic pension cost of these plans was $16 ments. Furthermore, equity investments are diversified across million for the year ended 2005 and $14 million for the years U.S. and non-U.S. stocks, as well as growth, value, and small ended 2004 and 2003. The projected benefit obligation and and large capitalization funds. Other assets such as real estate the unfunded status was $161 million and $139 million as of are used to enhance long-term returns while improving portfo- December 31, 2005 and 2004, respectively. The net liability lio diversification. Derivatives may be used to gain market recognized was $254 million and $222 million as of December exposure in an efficient and timely manner; however, deriva- 31, 2005 and 2004, respectively, and is included in the caption tives are not used to leverage the portfolio beyond the market "retirement benefits" on the Consolidated Balance Sheets. The value of the underlying investments. Investment risk is meas- benefit payments, which reflect future service, as appropriate, ured and monitored on a continuing basis through periodic are expected to be $7 million for each of the years ended investment portfolio reviews, annual liability measurements, 2006-2009, $8 million in year ended 2010 and $53 million and periodic asset/liability studies. for years ended 2011-2015.

Assumed Health Care Cost Trend Rates As of December 31 2005 2004 Health care cost trend rate assumed for next 4. STOCK-BASED COMPENSATION PLANS year (prelpost-Medicare) 9-11% 9-11%

Rate to which the cost trend rate isassumed to decline (the ultimate trend rate) 5% 5% FirstEnergy has four stock-based compensation programs:

Year that the rate reaches the ultimate trend Long-term Incentive Program (LTIP); EDCP; Employee Stock rate (pre/post-Medicare) 2010-2012 2009-2011 Ownership Plan (ESOP); and Deferred Compensation Plan for Outside Directors (DCPD). FirstEnergy has also assumed Assumed health care cost trend rates have a significant responsibility for several stock-based plans through acquisi-effect on the amounts reported for the health care plans. A tions. In 2001, FirstEnergy assumed responsibility for two 58 FirstEnergy Corp. 2005

stock-based plans as a result of its acquisition of GPU. No fur- FirstEnergy's stock performance. Restricted stock units grant-ther stock-based compensation can be awarded under GPU's ed in 2005 were 477,920 with a weighted average vesting Stock Option and Restricted Stock Plan for MYR Group Inc. period of 3.32 years.

Employees (MYR Plan) or 1990 Stock Plan for Employees of Compensation expense recognized for restricted stock and GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock units during 2005 approximated $10 million.

restricted stock under both plans have been converted into Compensation expense recognized for restricted stock during FirstEnergy options and restricted stock. Options under the 2004 and 2003 totaled $2 million in each year.

GPU Plan became fully vested on November 7, 2001, and will expire on or before June 1, 2010. Under the MYR Plan, all Stock Options options and restricted stock maintained their original vesting Stock options were granted to eligible employees allowing periods, which range from one to four years, and will expire them to purchase a specified number of common shares at a on or before December 17, 2006. The Centerior Equity Plan fixed grant price over a defined period of time. Stock option (CE Plan) is an additional stock-based plan administered by activities under the FE Programs for the past three years were FirstEnergy for which it assumed responsibility as a result of as follows:

the acquisition of Centerior Energy Corporation in 1997. All Weighted Average options are fully vested under the CE Plan, and no further Stock Option Activities Number of Options Exerdse Price awards are permitted. Outstanding options will expire on or Balance, January l, 2003 10,435,486 $28.95 before February 25, 2007. (1,400,206 options exercisable) 26.07 Options granted 3,981,100 29.71 (A)LTIP Options exercised 455,986 25.94 Options forfeited 311,731 29.09 FirstEnergy's LTIP includes four stock-based compensa- Balance, December 31, 2003 13,648,869 29.27 (1,919,662 options exercisable) 29.67 tion programs - restricted stock, restricted stock units, stock options, and performance shares. During 2005, FirstEnergy Options granted 3,373,459 38.77

! Options exercised 3,622,148 26.52 began issuing restricted stock units and reduced its use of Optionsforfeited 167,425 32.58 stock options. Balance, December 31, 2004 13,232,755 32.40 (3,175,023 options exercisable) 29.07 Under FirstEnergy's LTIP, total awards cannot exceed Options granted - -

22.5 million shares of common stock or their equivalent. Only Options exercised 4,140,893 29.79 stock options, restricted stock and restricted stock units have Optionsforfeited 225,606 34.37 Balance,December 31,2005 8,866,256 33.57 currently been designated to pay out in common stock, with (4,090,829 options exercisable) 31.97 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 Options outstanding by plan and range of exercise price against the limit on stock-based awards. As of December 31, as of December 31, 2005 were as follows:

2005, 3.9 million shares were available for future awards.

Options Options Outstanding Exercisable Restricted Stock and Restricted Stock Units Eligible employees receive awards of FirstEnergy common Weighted Weighted Avg. Remaining Avg.

stock or stock units subject to restrictions. Those restrictions Range of Exercise Contractual Exercise FEProgram Exercise Prices Shares Price Lfe Shares Price lapse over a defined period of time or based on performance.

Dividends are received on the restricted stock and are rein- FE plan $19.31-$29.87 3,828,991 $29.13 6.4 2,114,691 $28.66

$30.17-$39.46 4,912,141 $37.10 7.4 1,851,014 $35.84 vested in additional shares. Restricted common stock grants GPU plan $23.75-$35.92 122,818 $30.99 3.3 122,818 $30.99 under the FE Plan were as follows: MYR M plan $14.23 1,256 $14.23 3.8 1,256 $14.23 CE plan $25.14 1,050 $25.14 1.2 1,050 $25.14 2005 2004 2003* Total 8,866,256 $33.57 6.9 4,090,829 $31.97 Restricted common shares granted 356,200 62,370 Weighted average market price $41.52 $40.69 Weiohted average vesting period (years) 5.4 2.7 There were no stock options granted in 2005. The Divi ends restricted Yes Yes weighted average fair value of options granted in 2004 and M restrictedstod was granted 2003 are estimated below using the Black-Scholes option-pricing model and the following assumptions:

There are two types of restricted stock unit awards -

discretionary-based and performance-based. With the discre- 2004 2003 tionary-based, the Company grants the right to receive, at the Fair value per option $6.72 $5.09 end of the period of restriction, a number of shares of com- .Weighted average valuation assumptions:

Expected option term (years) 7.6 7.9 mon stock of FirstEnergy equal to the number of restricted Expected volatility 26.25w 26.91%

stock units set forth in each agreement. With performance- Expected dividend yield 3.88w 5.09%

Risk-free interest rate 1.99% 3.67w based, FirstEnergy grants the right to receive, at the end of the period of restriction, a number of shares of common stock of FirstEnergy equal to the number of restricted stock units set forth in the agreement subject to adjustment based on FirstEnergy Corp. 2005 59

Compensation expense for FirstEnergy stock options is assumptions were made including the size and growth rate of based on intrinsic value, which equals any positive difference the Company's workforce, earnings, dividends, and trading between FirstEnergy's common stock price on the option's price of common stock. In 2005, the ESOP loan was refi-grant date and the option's exercise price. The exercise prices nanced ($66 million principal amount) and its term was of all stock options granted in 2004 and 2003 equaled the extended by three years. In 2005, 2004 and 2003, 588,004 market price of FirstEnergy's common stock on the options' shares, 864,151 shares and 1,069,318 shares, respectively, grant dates. If fair value accounting were applied to were allocated to employees with the corresponding expense FirstEnergy's stock options, net income and earnings per recognized based on the shares allocated method. The fair share would be reduced as summarized below. value of 1,444,796 shares unallocated as of December 31, 2005 was approximately $71 million. Total ESOP-related 2005 2004 2003 compensation expense was calculated as follows:

On milions, except per share amounts)

Net Income, as reported $ 861 $ 878 5423 2005 2004 2003 Add back compensation expense reported in net income, net of tax (based on APB 25)* 32 21 24 An millions)

Deduct compensation expense based Base compensation $39 $32 $35 upon estimated fair value, net of tax' (39) (35) (36) Dividends on common stock held by the ESOP and used to service debt (10) (9) (9)

Pro forma net income $ 854 S 864 $ 411 Net expense $29 $23 $26 Earnings Per Share of Common Stock -

Basic As Reported $2.62 $2.68 $1.39 Pro Forma $2.60 $2.64 S1.35 (C) EDCP Diluted As Reported $2.61 $2.67 $1.39 Under the EDCP, covered employees can direct a portion of Pro Forma $2.59 $2.63 $1.35 their compensation, including annual incentive awards and/or Includes restrKtedstoc resuricted stock unit, stoct options pefformance shares ESOP, EDCP long-term incentive awards, into an unfunded FirstEnergy andDCPD.

stock account to receive vested stock units or into an unfunded retirement cash account An additional 20 % premium is As noted above, FirstEnergy reduced its use of stock received in the form of stock units based on the amount allocat-options beginning in 2005 and increased its use of perform-ed to the FirstEnergy stock account Dividends are calculated ance-based, restricted stock units. FirstEnergy has not quarterly on stock units outstanding and are paid in the form of accelerated out-of-the-money options in anticipation of adopt-additional stock units. Upon withdrawal, stock units are con-ing SFAS 123(R) onJanuary 1, 2006 (see Note 17). As a verted to FirstEnergy shares. Payout typically occurs three years result, all currently unvested stock options will vest by 2008.

from the date of deferral; however, an election can be made in The Company expects the adoption of SFAS 123(R) will the year prior to payout to further defer shares into a retire-increase annual compensation expense (after-tax) by approxi-mately $7 million, $2 million and $0.5 million in 2006, 2007 ment stock account that will pay out in cash upon retirement (see Note 3). Interest is calculated on the cash allocated to the and 2008, respectively, or $0.02 per share in 2006 and less cash account and the total balance will pay out in cash upon than $0.01 per share in 2007 and 2008.

retirement. Of the 1.3 million EDCP stock units authorized, 678,503 stock units were available for future awards as of Performance Shares December 31, 2005. Compensation expense recognized on Performance shares are share equivalents and do not have EDCP stock units in 2005, 2004 and 2003 approximated $5 voting rights. The shares track the performance of million, $2 million and $2 million, respectively.

FirstEnergy's common stock over a three-year vesting period.

During that time, dividend equivalents are converted into (D) DCPD additional shares. The final account value may be adjusted Under the DCPD, directors can elect to allocate all or a based on the ranking of FirstEnergy stock performance to a portion of their cash retainers, meeting fees and chair fees to composite of peer companies. Compensation expense recog-deferred stock or deferred cash accounts. If the funds are nized for performance shares during 2005, 2004 and 2003 totaled approximately $7 million, $5 million and $7 million, deferred into the stock account, a 20 % match is added to the funds allocated. The 20% match and any appreciation on it respectively.

are forfeited if the director leaves the Board within three years from the date of deferral for any reason other than retirement, (B) ESOP disability, death, upon a change in control, or when a director An ESOP Trust funds most of the matching contribution is ineligible to stand for re-election. Compensation expense is for FirstEnergy's 401(k) savings plan. All full-time employees recognized for the 20 % match over the three-year vesting eligible for participation in the 401(k) savings plan are cov-period. Directors may also elect to defer their equity retainers ered by the ESOP. The ESOP borrowed $200 million from into the deferred stock account; however, they do not receive OE and acquired 10,654,114 shares of OE's common stock a 20 % match on that deferral. DCPD expenses recognized in (subsequently converted to FirstEnergy common stock) 2005, 2004 and 2003 were approximately $3 million, $4 mil-through market purchases. Dividends on ESOP shares are lion and $2 million, respectively. The net liability recognized used to service the debt. Shares are released from the ESOP was $5 million and $3 million as of December 31, 2005 and on a pro rata basis as debt service payments are made.

2004, respectively, and is included in the caption "retirement In determining the amount of borrowing under the ESOP, benefits" on the Consolidated Balance Sheets.

60 FirstEnergy Corp. 2005

for-sale. The Companies and NGC have no securities held for

5. FAIR VALUE OF FINANCIAL INSTRUMENTS trading purposes. The following table summarizes the amor-tized cost basis, unrealized gains and losses and fair values for Long-term Debt and Other Long-term Obligations decommissioning trust investments as of December 31:

All borrowings with initial maturities of less than one 2004 2005 year are defined as short-term financial instruments under Un- Un- Un- Un-GAAP and are reported on the Consolidated Balance Sheets at Cost realized realized Fair Cost realized realized Fair cost in the caption "short-term borrowings", which approxi- Basis Gains Losses Value Basis Gains Losses Value mates their fair market value. The following table provides the (inmilions) approximate fair value and related carrying amounts of long- Debt securities S 681 $ 12 $ 7 S 686 S 616 $ 19 $ 3 $ 632 Equity securities 898 190 21 1,067 763 207 19 951 term debt and other long-term obligations (including currently

$1,579 $202 $28 $1,753 $1,379 $226 $22 $1,583 payable) as of December 31:

2005 2004 Proceeds from the sale of decommissioning trust invest-Carrying Fair Carrying Fair ments, realized gains and losses on those sales, and interest Value Value Value Value and dividend income for the three years ended December 31, (Anmillion) 2005 were as follows:

Long-term debt $10,097 $10,576 $10,787 $11,341 Subordinated debentures 2004 2003 toaffiliatedtrusts 103 140 103 112 2005 Preferred stock subject 7n Mawlions) to mandatory redemption - - 17 16 Proceeds from sales $1,419 $1,234 $758

$10,200 $10,716 $10,907 $11,469 Realized gains 133 144 38 Realized losses 58 43 32 Interest and dividend income 49 45 37 The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relat-The following table provides the fair value of, and unreal-ing to those securities based on the current call price, the yield ized losses on, nuclear decommissioning trust investments to maturity or the yield to call, as deemed appropriate at the that are deemed to be temporarily impaired as of December end of each respective year. The yields assumed were based on 31, 2005:

securities with similar characteristics offered by corporations with credit ratings similar to the Companies' ratings. LessThan 12 Months 12 Mornthsor More Total Fair Unrealized Fair Unrealized Fair Unrealized Investments Value Losses Value Losses Value Losses The carrying amounts of cash and cash equivalents (inmllions)

Debtsecurities $276 $5 $ 81 $ 2 $357 $7 approximate fair value due to the short-term nature of these 240 10 39 11 279 21 Equity securities investments. The following table provides the approximate

$516 $15 $120 $13 $636 $28 fair value and related carrying amounts of investments other than cash and cash equivalents as of December 31:

The Companies and NGC periodically evaluate the securi-2005 2004 ties held by their nuclear decommissioning trusts for Carrying Fair Carrying Fair other-than-temporary impairment FirstEnergy considers the Value Value Value Value length of time and the extent to which the security's fair value Oinmilons) has been less than its cost basis and other factors to determine Debt securities:")

- Government obligations 5 $ 893 $ 887 $ 797 $ 797 whether impairment is other than temporary. Unrealized

-Corporate debt securities'2 1,137 1,248 1,205 1,362

- Mortgage-backed securities - - 2 2 gains and losses applicable to OE's, TE's and the majority of NGC's decommissioning trusts are recognized in OCI in 2,030 2,135 2,004 2,161 Equity securities"l) 1,129 1,130 1,033 1,033 accordance with SFAS 115, as fluctuations in fair value will

$3,159 $3,265 $3,037 $3,194 eventually affect earnings. The decommissioning trusts of JCP&L, Met-Ed and Penelec are subject to regulatory account-

0) hudes nudeardeco'nmnssoning, nudear Wse dispoad and NUG&stkvestnent ing in accordance with SFAS 71. Net unrealized gains and m

Inhdes ineotmentsinlease obligabonbonds (see Note 6). losses are recorded as regulatory assets or liabilities since the difference between investments held in trust and the decom-The fair value of investments other than cash and cash missioning liabilities will be recovered from or refunded to equivalents represent cost (which approximates fair value) or customers.

the present value of the cash inflows based on the yield to The investment policy for the nuclear decommissioning maturity. The yields assumed were based on financial instru- trust funds restricts or limits the ability to hold certain types ments with similar characteristics and terms. of assets including private or direct placements, warrants, Investments other than cash and cash equivalents include securities of FirstEnergy, investments in companies owning held-to-maturity securities and available-for-sale securities. nuclear power plants, financial derivatives, preferred stocks, Decommissioning trust investments are classified as available-FirstErwergy Corp. 2005 61

securities convertible into common stock and securities of loss was amortized to interest expense.

the trust fund's custodian or managers and their parents or FirstEnergy has entered into fixed-for-floating interest subsidiaries. rate swap agreements, whereby FirstEnergy receives fixed cash flows based on the fixed coupons of the hedged securities Derivatives and pays variable cash flows based on short-term variable FirstEnergy is exposed to financial risks resulting from market interest rates (3 and 6-month LIBOR indices). These the fluctuation of interest rates and commodity prices, includ- derivatives are treated as fair value hedges of fixed-rate, long-ing prices for electricity, natural gas, coal and energy term debt issues - protecting against the risk of changes in the transmission. To manage the volatility relating to these expo- fair value of fixed-rate debt instruments due to lower interest sures, FirstEnergy uses a variety of non-derivative and rates. Swap maturities, fixed interest rates received, and inter-derivative instruments, including forward contracts, options, est payment dates match those of the underlying obligations.

futures contracts and swaps. The derivatives are used princi- During 2005, FirstEnergy entered into interest rate swap pally for hedging purposes. FirstEnergy's Risk Policy agreements on $150 million notional amount of senior notes Committee, comprised of members of senior management, with a weighted average fixed interest rate of 6.59 %. In addi-provides general management oversight to risk management tion, FirstEnergy unwound swaps with a total notional activities throughout the Company. They are responsible for amount of $700 million from which it received $16 million in promoting the effective design and implementation of sound cash gains during 2005. The gains will be recognized over the risk management programs. They also oversee compliance remaining maturity of each respective hedged security as with corporate risk management policies and established risk reduced interest expense. As of December 31, 2005, the aggre-management practices. gate notional value of interest rate swap agreements FirstEnergy accounts for derivative instruments on its outstanding was $1.1 billion.

Consolidated Balance Sheet at their fair value unless they During 2005, FirstEnergy entered into several forward meet the normal purchase and normal sales criteria. starting swap agreements (forward swaps) in order to hedge a Derivatives that meet the normal purchase and sales criteria portion of the consolidated interest rate risk associated with are accounted for on the accrual basis. The changes in the fair the future planned issuances of fixed-rate, long-term debt value of derivative instruments that do not meet the normal securities for one or more of its consolidated entities in 2006 -

purchase and sales criteria are recorded in current earnings, 2008. These derivatives are treated as cash flow hedges, pro-in AOCL, or as part of the value of the hedged item, depend- tecting against the risk of changes in future interest payments ing on whether or not it is designated as part of a hedge resulting from changes in benchmark U.S. Treasury rates transaction, the nature of the hedge transaction and hedge between the date of hedge inception and the date of the debt effectiveness. issuance. As of December 31, 2005, FirstEnergy had entered FirstEnergy's primary ongoing hedging activities involves into forward swaps with an aggregate notional amount of cash flow hedges of electricity and natural gas purchases and $975 million. As of December 31, 2005, the forward swaps anticipated interest payments associated with future debt had a fair value of $3 million.

issuances. The effective portion of such hedges is initially recorded in equity as AOCL and is subsequently recorded in net income, as an operating expense, when the underlying hedged 6. LEASES commodities are delivered or interest payments are made.

AOCL as of December 31, 2005 includes a net deferred loss of The Companies lease certain generating facilities, office

$78 million for derivative hedging activity. The $14 million space and other property and equipment under cancelable and decrease from the December 31,2004 balance of $92 million noncancelable leases.

includes $2 million reduction related to current hedging activity In 1987, OE sold portions of its ownership interests in and a $12 million decrease due to net hedge losses included in Perry Unit 1 and Beaver Valley Unit 2 and entered into oper-earnings during the year. Approximately $17 million (after tax) ating leases on the portions sold for basic lease terms of of the current net deferred loss on derivative instruments in approximately 29 years. In that same year, CEI and TE also AOCL is expected to be reclassified to earnings during the next sold portions of their ownership interests in Beaver Valley twelve months as hedged transactions occur. The fair value of Unit 2 and Bruce Mansfield Units 1, 2 and 3 and entered into these derivative instruments will continue to fluctuate from similar operating leases for lease terms of approximately 30 period to period based on various market factors. Gains and years. During the terms of their respective leases, OE, CEI and losses from any ineffective portion of the cash flow hedge are TE continue to be responsible, to the extent of their leasehold recorded directly to earnings. The impact of ineffectiveness on interests, for costs associated with the units including con-earnings during 2005 and 2004 was not material. struction expenditures, operation and maintenance expenses, FirstEnergy entered into interest rate derivative transac- insurance, nuclear fuel, property taxes and decommissioning.

tions in 2001 to hedge a portion of the anticipated interest They have the right, at the expiration of the respective basic payments on debt related to the GPU acquisition. Gains and lease terms, to renew their respective leases. They also have losses from hedges of anticipated interest payments on acqui- the right to purchase the facilities at the expiration of the sition debt are included in net income, as a component of basic lease term or any renewal term at a price equal to the interest expense, over the periods that hedged interest pay- fair market value of the facilities. The basic rental payments ments are made - 5, 10 and 30 years. In 2005, a $24 million are adjusted when applicable federal tax law changes.

62 hrstEnergy Corp. 2005

Consistent with the regulatory treatment, the rentals for 7. VARIABLE INTEREST ENTITIES capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs for the three FIN 46R addresses the consolidation of VIEs, including years ended December 31, 2005 are summarized as follows: special-purpose entities, that are not controlled through voting 2005 2004 2003 interests or in which the equity investors do not bear the enti-(Inmillons) ty's residual economic risks and rewards. FirstEnergy adopted Operating leases FIN 46R for special-purpose entities as of December 31, 2003 Interest element $171 $175 $184 Other 162 140 166 and for all other entities in the first quarter of 2004.

Ca ital leases 1 2 FirstEnergy and its subsidiaries consolidate VIEs when they interest element 1 Other 2 3 2 are determined to be the VIE's primary beneficiary as defined Total rentals $336 $319 $354 by FIN 46R.

Leases Established by OE in 1996, PNBV purchased a portion of FirstEnergy's consolidated financial statements include the lease obligation bonds issued on behalf of lessors in OE's PNBV and Shippingport, VIEs created in 1996 and 1997, respec-Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback tively, to refinance debt originally issued in connection with the transactions. Similarly, CEI and TE established Shippingport sale and leaseback transactions discussed above in Note 6. PNBV in 1997 to purchase the lease obligation bonds issued on and Shippingport financial data are included in the consolidated behalf of lessors in their Bruce Mansfield Units 1, 2 and 3 sale financial statements of OE and CEI, respectively.

and leaseback transactions. The PNBV and Shippingport PNBV was established to purchase a portion of the lease arrangements effectively reduce lease costs related to those obligation bonds issued in connection with OE's 1987 sale transactions (see Note 7). and leaseback of its interests in the Perry Plant and Beaver The future minimum lease payments as of December 31, Valley Unit 2. OE used debt and available funds to purchase 2005 are: the notes issued by PNBV. Ownership of PNBV includes a 3 %

equity interest by an unaffiliated third party and a 3 % equity Operating Leases interest held by OES Ventures, a wholly owned subsidiary of Capital Lease Capital OE. Shippingport was established to purchase all of the lease Leases Payments Trusts Net obligation bonds issued in connection with CEI's and TE's (Inmillions) 2006 $5 $ 344 $ 142 $ 202 Bruce Mansfield Plant sale and leaseback transaction in 1987.

2007 1 320 131 189 CEI and TE used debt and available funds to purchase the 2008 1 313 105 208 2009 1 316 112 204 notes issued by Shippingport.

2010 1 316 121 195 OE, CEI and TE are exposed to losses under the applica-Years thereafter 4 1,997 639 1,358 ble sale-leaseback agreements upon the occurrence of certain Total minimum lease payments 13 $3,606 $1,250 $2,356 contingent events that each company considers unlikely to Executory costs 2 occur. OE, CEI and TE each have a maximum exposure to loss Net minimum lease payments 11 under these provisions of approximately $1 billion, which rep-Interest portion 3 resents the net amount of casualty value payments upon the Present value of net minimum 8 occurrence of specified casualty events that render the applica-lease payments ble plant worthless. Under the applicable sale and leaseback Less current portion 3 agreements, OE, CEI and TE have net minimum discounted Noncurrent portion $5 lease payments of $652 million, $105 million and $539 mil-lion, respectively, that would not be payable if the casualty value payments are made.

FirstEnergy has recorded above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant associated Power PurchaseAgreements with the 1997 merger between OE and Centerior. The total In accordance with FIN 46R, FirstEnergy evaluated its above-market lease obligation of $722 million associated with power purchase agreements and determined that certain NUG Beaver Valley Unit 2 is being amortized on a straight-line basis entities may be VIEs to the extent they own a plant that sells through the end of the lease term in 2017 (approximately $37 substantially all of its output to the Companies and the contract million per year). The total above-market lease obligation of price for power is correlated with the plant's variable costs of

$755 million associated with the Bruce Mansfield Plant is production. FirstEnergy, through its subsidiaries JCP&L, Met-being amortized on a straight-line basis through the end of Ed and Penelec, maintains approximately 30 long-term power 2016 (approximately $48 million per year). As of December purchase agreements with NUG entities. The agreements were 31, 2005, the above-market lease liabilities for Beaver Valley structured pursuant to the Public Utility Regulatory Policies Act Unit 2 and the Bruce Mansfield Plant totaled $936 million, of of 1978. FirstEnergy was not involved in the creation of, and which $85 million is classified as current liabilities. has no equity or debt invested in, these entities.

FirstEnergy has determined that for all but eight of these entities, neither JCP&L, Met-Ed nor Penelec have variable FirstEnergy Corp. 2005 63

interests in the entities or the entities are governmental or NRG Energy Inc. because NRG stated that it could not com-not-for-profit organizations not within the scope of FIN 46R. plete the transaction under the original terms of the JCP&L, Met-Ed or Penelec may hold variable interests in the agreement NRG filed voluntary bankruptcy petitions in May remaining eight entities, which sell their output at variable 2003; subsequently, FirstEnergy reached an agreement for set-prices that correlate to some extent with the operating costs of tlement of its claim against NRG. FirstEnergy sold its entire the plants. As required by FIN 46R, FirstEnergy periodically claim for $170 million (including $32 million of cash proceeds requests from these eight entities the information necessary to received in December 2003).

determine whether they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been International Operations unable to obtain the requested information, which in most FirstEnergy completed the sale of its international opera-cases was deemed by the requested entity to be proprietary. tions in January 2004 with the sales of its remaining 20.1 %

As such, FirstEnergy applied the scope exception that exempts interest in Avon (parent of Midlands Electricity in the United enterprises unable to obtain the necessary information to Kingdom) and its 28.67% interest in TEBSA, for $12 million.

evaluate entities under FIN 46R. In the fourth quarter of 2003, after-tax impairment charges Since FirstEnergy has no equity or debt interests in the reduced the carrying value of Avon ($5 million) and TEBSA NUG entities, its maximum exposure to loss relates primarily ($26 million). As a result, no gain or loss was recognized to the above-market costs it incurs for power. FirstEnergy rec- upon the sales in 2004. Avon, TEBSA and other international ognizes a liability and a corresponding regulatory asset on its assets sold in 2003 were originally acquired as part of Consolidated Balance Sheets for the projected above-market FirstEnergy's November 2001 merger with GPU.

costs related to its NUG agreements. As of December 31, 2005, International operations in Bolivia were divested by the the projected above-market loss liability recognized for these December 2003 sale of FirstEnergy's wholly owned sub-eight NUG agreements was $119 million. Purchased power sidiary, Guaracachi America, Inc., a holding company with costs from these entities during 2005, 2004 and 2003 were a 50.001 % interest in EGSA, resulting in a loss on sale of

$180 million, $175 milion and $167 million, respectively. $33 million (recognized in Discontinued Operations in the Consolidated Statement of Income for the year ended December 31, 2003). International operations in Argentina

8. DIVESTITURES represented by FirstEnergy's ownership in Emdersa were divested through the abandonment of its shares in Emdersa's Other Domestic Operations parent company, GPU Argentina Holdings, Inc. in April 2003.

In 2005, FirstEnergy sold three FSG subsidiaries - As a result of the abandonment, FirstEnergy recognized a one-Pennsylvania-based Elliott-Lewis Corporation, Ohio-based time, non-cash charge of $67 million, or $0.23 per share of Spectrum Control Systems, Inc. and Maryland-based L. H. common stock in 2003. The charge did not include the expect-Cranston and Sons, Inc. - and a MYR subsidiary - Power ed income tax benefits related to the abandonment, which Piping Company, resulting in an aggregate after-tax gain of were fully reserved. FirstEnergy expects tax benefits of

$13 million. AU of these sales, with the exception of L.H. approximately $129 million, of which $50 million would Cranston and Sons, Inc, met the discontinued operations crite- increase net income in the period that it becomes probable ria (see Note 20)). In 2003, FirstEnergy sold three additional those benefits will be realized. The remaining $79 million of FSG subsidiaries - Ancoma, Inc., a mechanical contracting tax benefits would reduce goodwill recognized in connection company based in Rochester, New York, and Virginia-based with the acquisition of GPU.

Colonial Mechanical and Webb Technologies - and a MAR- In 2003 FirstEnergy recognized an after-tax impairment BEL subsidiary - Northeast Ohio Natural Gas, for an of $8 million related to the carrying value of the note receiv-aggregate after-tax gain of $3 million. able from Aquila. After receiving the first annual installment In March 2005, FES completed the sale of its retail natu- payment of $19 million in May 2003, FirstEnergy sold the ral gas business for an after-tax gain of $5 million. Also in remaining balance of its note receivable in the secondary March 2005, FirstEnergy sold 51 % of its interest in FirstCom, market and received $63 million in proceeds in July 2003.

resulting in an after-tax gain of $4 million. FirstEnergy accounts for its remaining 31.85 % interest in FirstCom on the equity basis. 9. OHIO TAX LEGISLATION FirstEnergy sold its 50 % interest in GLEP in June 2004.

Proceeds of $220 million included cash of $200 million and On June 30, 2005, tax legislation was enacted in the State the right, valued at $20 million, to participate for up to a 40% of Ohio that created a new CAT tax, which is based on quali-interest in future wells in Ohio. This transaction produced an fying "taxable gross receipts" and does not consider any after-tax loss of $7 million, including the benefits of prior tax expenses or costs incurred to generate such receipts, except capital losses that had been previously fully reserved, which for items such as cash discounts, returns and allowances, and offset the capital gain from the sale. bad debts. The CAT tax was effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio Generation Assets personal property tax. The CAT tax is phased-in while the In August 2002, FirstEnergy cancelled a November 2001 current income-based franchise tax is phased-out over a five-agreement to sell four coal-fired power plants (2,535 MW) to year period at a rate of 20 % annually, beginning with the year 64 FirstEnergy Corp. 2005

ended 2005, and the personal property tax is phased-out over applicable government agencies and reliability coordinators a four-year period at a rate of approximately 25 % annually, may, however, take a different view as to recommended beginning with the year ended 2005. During the phase-out enhancements or may recommend additional enhancements period the Ohio income-based franchise tax will be computed in the future as the result of adoption of mandatory reliability consistent with the prior tax law, except that the tax liability standards pursuant to the EPACT that could require addition-as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; al, material expenditures. Finally, the PUCO is continuing to 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current review the FirstEnergy filing that addressed upgrades to con-income-based franchise tax over a five-year period. As a result trol room computer hardware and software and enhancements of the new tax structure, all net deferred tax benefits that to the training of control room operators before determining were not expected to reverse during the five-year phase-in the next steps, if any, in the proceeding.

period were written-off as ofJune 30, 2005. As a result of outages experienced in JCP&Us service The increase to income taxes associated with the area in 2002 and 2003, the NJBPU had implemented reviews adjustment to net deferred taxes in 2005 is summarized below intoJCP&T's service reliability. In 2004, the NJBPU adopted (in millions): an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and OE $32 endorsed JCP&Us ongoing actions to implement the MOU. On CEI 4 June 9, 2004, the NJBPU approved a Stipulation that incorpo-TE 18 Other FirstEnergy subsidiaries (2) rates the final report of a Special Reliability Master who made Total FirstEnergy $52 recommendations on appropriate courses of action necessary to ensure system-wide reliability. The Stipulation also incor-porates the Executive Summary and Recommendation Income tax expenses were reduced (increased) during portions of the final report of a focused audit of JCP&L's 2005 by the initial phase-out of the Ohio income-based fran- Planning and Operations and Maintenance programs and chise tax and phase-in of the CAT tax as summarized below practices (Focused Audit). A final order in the Focused Audit (in millions): docket was issued by the NJBPU on July 23, 2004. On February 11, 2005,JCP&L met with the Ratepayer Advocate OE $3 to discuss reliability improvements. JCP&L continues to file CEI 5 compliance reports reflecting activities associated with the TE 1 Other FirstEnergy subsidiaries (3) MOU and Stipulation.

Total FirstEnergy $6 In May 2004, the PPUC issued an order approving revised reliability benchmarks and standards, including revised bench-marks and standards for Met-Ed, Penelec and Penn. Met-Ed, Penelec and Penn filed a Petition for Amendment of

10. REGULATORY MATTERS Benchmarks with the PPUC on May 26, 2004, due to their implementation of automated outage management systems (A) RELIABILITY INITIATIVES following restructuring. On December 30, 2005 the ALJ In late 2003 and early 2004, a series of letters, reports recommended that the PPUC adopt the Joint Petition for and recommendations were issued from various entities, Settlement among the parties involved in the three Companies' including governmental, industry and ad hoc reliability enti- request to amend the distribution reliability benchmarks, ties (PUCO, FERC, NERC and the U.S. - Canada Power thereby eliminating the need for full litigation. The AU's rec-System Outage Task Force) regarding enhancements to region- ommendation, adopting the revised benchmarks and standards al reliability. In 2004, FirstEnergy completed implementation was approved by the PPUC on February 9, 2006.

of all actions and initiatives related to enhancing area reliabili- The EPACT provides for the creation of an ERO to ty, improving voltage and reactive management, operator establish and enforce reliability standards for the bulk power readiness and training and emergency response preparedness system, subject to FERC review. On February 3, 2006, the recommended for completion in 2004. On July 14, 2004, FERC adopted a rule establishing certification requirements NERC independently verified that FirstEnergy had imple- for the ERO, as well as regional entities envisioned to assume mented the various initiatives to be completed by June 30 or monitoring responsibility for the new reliability standards.

summer 2004, with minor exceptions noted by FirstEnergy, The NERC has been preparing the implementation aspects which exceptions are now essentially complete. FirstEnergy is of reorganizing its structure to meet the FERC's certification proceeding with the implementation of the recommendations requirements for the ERO. The NERC will make a filing with that were to be completed subsequent to 2004 and will contin- the FERC to obtain certification as the ERO and to obtain ue to periodically assess the FERC-ordered Reliability Study FERC approval of delegation agreements with regional entities.

recommendations for forecasted 2009 system conditions, rec- The new FERC rule referred to above, further provides for ognizing revised load forecasts and other changing system reorganizing regional reliability organizations (regional enti-conditions which may impact the recommendations. Thus far, ties) that would replace the current regional councils and for implementation of the recommendations has not required, nor rearranging the relationship with the ERO. The "regional enti-is expected to require, substantial investment in new, or mate- ty" may be delegated authority by the ERO, subject to FERC rial upgrades to existing equipment. The FERC or other approval, for enforcing reliability standards adopted by the FirstEnergy Corp. 2005 65

ERO and approved by the FERC. NERC also intends to make case and the case was consolidated with the RCP application a parallel filing with the FERC seeking approval of mandatory discussed below.

reliability standards. These reliability standards are expected On September 9, 2005, the Ohio Companies filed an appli-to be based on the current NERC Version 0 reliability standards cation with the PUCO that supplemented their existing RSP with some additional standards. The two filings are expected with an RCP which was designed to provide customers with to be made in the second quarter of 2006. more certain rate levels than otherwise available under the RSP The ECAR, Mid-Atlantic Area Council, and Mid- during the plan period. Major provisions of the RCP include:

American Interconnected Network reliability councils have completed the consolidation of these regions into a single

• Maintain the existing level of base distribution rates new regional reliability organization known as ReliabilityFirst through December 31, 2008 for OE and TE, and Corporation. ReliabilityFirst began operations as a regional April 30, 2009 for CEI; reliability council under NERC on January 1, 2006 and

• Defer and capitalize for future recovery with carrying intends to file and obtain certification consistent with the charges certain distribution costs to be incurred during final rule as a "regional entity" under the ERO during 2006. the periodJanuary 1, 2006 through December 31, 2008, All of FirstEnergy's facilities are located within the not to exceed $150 million in each of the three years; ReliabilityFirst region.

• Adjust the RTC and extended RTC recovery periods On a parallel path, the NERC is establishing working and rate levels so that full recovery of authorized costs groups to develop reliability standards to be filed for approval will occur as of December 31, 2008 for OE and TE as of with the FERC following the NERC's certification as an ERO. December 31, 2010 for CEI; These reliability standards are expected to build on the cur-

• Reduce the deferred shopping incentive balances as of rent NERC Version 0 reliability standards. It is expected that January 1, 2006 by up to $75 million for OE, $45 million the proposed reliability standards will be filed with the FERC for TE, and $85 million for CEI by accelerating the in early 2006. application of each respective company's accumulated FirstEnergy believes it is in compliance with all current cost of removal regulatory liability; and NERC reliability standards. However, it is expected that the

• Recover increased fuel costs of up to $75 million, $77 FERC will adopt stricter reliability standards than those con- million, and $79 million, in 2006, 2007, and 2008, tained in the current NERC Version 0 standards. The respectively, from all OE and TE distribution and financial impact of complying with the new standards cannot transmission customers through a fuel recovery be determined at this time. However, the EPACT required that mechanism. OE, TE, and CEI may defer and capitalize all prudent costs incurred to comply with the new reliability increased fuel costs above the amount collected through standards be recovered in rates. the fuel recovery mechanism (in lieu of implementation of the GCAF rider).

(B)OHIO On August 5, 2004, the Ohio Companies accepted the On November 4, 2005, a supplemental stipulation was RSP as modified and approved by the PUCO in an August 4, filed with the PUCO which was in addition to a stipulation 2004 Entry on Rehearing, subject to a competitive bid process. filed with the September 9, 2005 application. On January 4, The RSP was intended to establish generation service rates 2006, the PUCO approved the RCP filing with modifications.

beginning January 1, 2006, in response to PUCO concerns On January 10, 2006, the Ohio Companies filed a Motion for about price and supply uncertainty following the end of the Clarification of the PUCO order approving the RCP. The Ohio Ohio Companies' transition plan market development period. Companies sought clarity on issues related to distribution In October 2004, the OCC and NOAC filed appeals with the deferrals, including requirements of the review process, timing Supreme Court of Ohio to overturn the original June 9, 2004 for recognizing certain deferrals and definitions of the types of PUCO order in this proceeding as well as the associated qualified expenditures. The Ohio Companies also sought con-entries on rehearing. On September 28, 2005, the Ohio firmation that the list of deferrable distribution expenditures Supreme Court heard oral arguments on the appeals and originally included in the revised stipulation fall within the it is expected that the Court will issue its opinion in 2006. PUCO order definition of qualified expenditures. On January On November 1, 2005, the Ohio Companies filed tariffs in 25, 2006, the PUCO issued an Entry on Rehearing granting in compliance with the approved RSP, which were approved part, and denying in part, the Ohio Companies' previous by the PUCO on December 7, 2005. requests and clarifying issues referred to above. The PUCO On May 27, 2005, the Ohio Companies filed an applica- granted the Ohio Companies' requests to: 1) recognize fuel tion with the PUCO to establish a GCAF rider under the RSP. and distribution deferrals commencingJanuary 1, 2006; 2)

The GCAF application sought recovery of increased fuel costs recognize distribution deferrals on a monthly basis prior to from 2006 through 2008 applicable to the Ohio Companies' review by the PUCO Staff; 3) clarify that the types of distribu-retail customers through a tariff rider to be implemented tion expenditures included in the Supplemental Stipulation January 1, 2006. The application reflected projected increases may be deferred; and 4) clarify that distribution expenditures in fuel costs in 2006 compared to 2002 baseline costs. The do not have to be "accelerated" in order to be deferred. The new rider, after adjustments made in testimony, sought to PUCO granted the Ohio Companies' methodology for deter-recover all costs above the baseline (approximately $88 million mining distribution deferral amounts, but denied the Motion in 2006). Various parties including the OCC intervened in this in that the PUCO Staff must verify the level of distribution 66 FirstEnergy Corp. 2005

expenditures contained in current rates, as opposed to simply on a retroactive basis. On October 22, 2003, Met-Ed and accepting the amounts contained in the Companies' Motion. Penelec filed an Objection with the Commonwealth Court ask-On February 3, 2006, several other parties filed applications ing that the Court reverse this PPUC finding; a for rehearing on the PUCO's January 4, 2006 Order. The Ohio Commonwealth Court judge subsequently denied their Companies responded to the application for rehearing on Objection on October 27, 2003 without explanation. On February 13, 2006. October 31, 2003, Met-Ed and Penelec filed an Application for Under provisions of the RSP, the PUCO may require the Clarification of the Court order with the judge, a Petition for Ohio Companies to undertake, no more often than annually, a Review of the PPUC's October 2 and October 16, 2003 competitive bid process to secure generation for the years 2007 Orders, and an application for reargument, if the judge, in his and 2008. On July 22, 2005, FirstEnergy filed a competitive clarification order, indicates that Met-Ed's and Penelec's bid process for the period beginning in 2007 that is similar to Objection was intended to be denied on the merits. The the competitive bid process approved by the PUCO for the Reargument Brief before the Commonwealth Court was filed Ohio Companies in 2004, which resulted in the PUCO accept- on January 28, 2005.

ing no bids. Any acceptance of future competitive bid results As of December 31, 2005, Met-Ed's and Penelec's regula-would terminate the RSP pricing, with no accounting impacts tory deferrals pursuant to the 1998 Restructuring Settlement to the RSP, and not until twelve months after the PUCO (including the Phase 2 Proceedings) and the FirstEnergy/GPU authorizes such termination. On September 28, 2005, the Merger Settlement Stipulation are $333 million and $48 mil-PUCO issued an Entry that essentially approved the Ohio lion, respectively. Penelec's $48 million is subject to the Companies' filing but delayed the proposed timing of the com- pending resolution of taxable income issues associated with petitive bid process by four months, calling for the auction to NUG Trust Fund proceeds.

be held on March 21, 2006. OCC filed an application for Met-Ed and Penelec purchase a portion of their PLR rehearing of the September 28, 2005 Entry, which the PUCO requirements from FES through a wholesale power sales denied on November 22, 2005. On February 23, 2006, the auc- agreement and a portion from contracts with unaffiliated third tion manager notified the PUCO that there was insufficient party suppliers, including NUGs. Assuming continuation of interest in the auction process to allow it to proceed in 2006. these existing contractual arrangements, the available supply represents approximately 100 % of the combined retail sales (C) PENNSYLVANIA obligations of Met-Ed and Penelec in 2006 and 2007; almost A February 2002 Commonwealth Court of Pennsylvania 100 % for 2008; and approximately 85 % for 2009 and 2010.

decision affirmed the June 2001 PPUC decision regarding Met-Ed and Penelec are authorized to defer any excess of approval of the FirstEnergy/GPU merger, remanded the issues NUG contract costs over current market prices. Under the of quantification and allocation of merger savings to the PPUC terms of the wholesale agreement with FES, FES retains the and denied Met-Ed and Penelec the rate relief initially supply obligation and the supply profit and loss risk for the approved in the PPUC decision. On October 2, 2003, the portion of power supply requirements not self-supplied by PPUC issued an order concluding that the Commonwealth Met-Ed and Penelec under their contracts with NUGs and Court reversed the PPUC's June 2001 order in its entirety. In other unaffiliated suppliers. This arrangement reduces Met-accordance with the PPUC's direction, Met-Ed and Penelec Ed's and Penelec's exposure to high wholesale power prices by filed supplements to their tariffs that became effective in providing power at a fixed price for their uncommitted PLR October 2003 and that reflected the CTC rates and shopping energy costs during the term of the agreement with FES. The credits in effect prior to the June 2001 order. wholesale agreement with FES is automatically extended for Met-Ed and Penelec had been negotiating with interested each successive calendar year unless any party elects to cancel parties in an attempt to resolve the merger savings issues that the agreement by November 1 of the preceding year. On are the subject of remand from the Commonwealth Court. November 1, 2005, FES and the other parties thereto amend-Met-Ed's and Penelec's combined portion of total merger sav- ed the agreement to provide FES the right over the next year ings during 2001 - 2004 is estimated to be approximately $51 to terminate the agreement at any time upon 60 days notice. If million. In late 2005, settlement discussions broke off as the wholesale power agreement were terminated or modified, unsuccessful. A procedural schedule was established by the Met-Ed and Penelec would need to satisfy the portion of their AUJ on January 17, 2006. The companies' initial testimony is PLR obligations currently supplied by FES from unaffiliated due on March 1, 2006 with testimony of the other parties and suppliers at prevailing prices, which are likely to be higher additional testimony by the companies to be filed through than the current price charged by FES under the agreement October, 2006. Hearings are scheduled for the end of October and, as a result, Met-Ed's and Penelec's purchased power costs 2006 with the ALJ's recommended decision to be issued in could materially increase. If Met-Ed and Penelec were to February, 2007. The companies are unable to predict the out- replace the FES supply at current market power prices with-come of this proceeding. out corresponding regulatory authorization to increase their In an October 16, 2003 order, the PPUC approved generation prices to customers, each company would likely September 30, 2004 as the date for Met-Ed's and Penelec's incur a significant increase in operating expenses and experi-NUG trust fund refunds. The PPUC order also denied their ence a material deterioration in credit quality metrics. Under accounting treatment request regarding the CTC rate/shop- such a scenario, each company's credit profile would no ping credit swap by requiring Met-Ed and Penelec to treat the longer support an investment grade rating for its fixed income stipulated CTC rates that were in effect from January 1, 2002 securities. Met-Ed and Penelec are in the process of preparing FirstEnergy Corp. 2005 67

a comprehensive rate filing that will address a number of its system's reliability are prudent and reasonable for rate transmission, distribution and supply issues and is expected recovery. Depending on its assessment of JCP&L's service to be filed with the PPUC in the second quarter of 2006. That reliability, the NJBPU could have increased JCP&L's return filing will include, among other things, a request for appropri- on equity to 9.75 % or decreased it to 9.25 %.

ate regulatory action to mitigate adverse consequences from On July 16, 2004, JCP&L filed the Phase II petition and any future reduction, in whole or in part, in the availability testimony with the NJBPU, requesting an increase in base to Met-Ed and Penelec of supply under the existing FES rates of $36 million for the recovery of system reliability costs agreement. There can be no assurance, however, that if FES and a 9.75 % return on equity. The filing also requested an ultimately determines to terminate, or significantly modify increase to the MTC deferred balance recovery of approxi-the agreement, timely regulatory relief will be granted by the mately $20 million annually.

PPUC or, to the extent granted, adequate to mitigate such On May 25, 2005, the NJBPU approved two stipulated adverse consequences. settlement agreements. The first stipulation between JCP&L On October 11, 2005, Penn filed a plan with the PPUC to and the NJBPU staff resolves all of the issues associated with secure electricity supply for its customers at set rates following JCP&L's motion for reconsideration of the Phase I Order. The the end of its transition period on December 31, 2006. Penn is second stipulation between JCP&L, the NJBPU staff and the recommending that the RFP process cover the period January Ratepayer Advocate resolves all of the issues associated with 1, 2007 through May 31, 2008. Hearings were held on January JCP&L's Phase II proceeding. The stipulated settlements 10, 2006 with Main Briefs filed on January 27, 2006 and provide for, among other things, the following:

Reply Briefs on February 3, 2006. On February 17, 2006, the AIJ issued a Recommended Decision to adopt Penn's RFP

• An annual increase in distribution revenues of process with modifications. A PPUC vote is expected in April $23 million effective June 1, 2005, associated with 2006. Under Pennsylvania's electric competition law, Penn is the Phase I Order reconsideration; required to secure generation supply for customers who do

• An annual increase in distribution revenues of not choose alternative suppliers for their electricity. $36 million effectiveJune 1, 2005, related toJCP&L's Phase II Petition; (D)NEW JERSEY

• An annual reduction in both rates and amortization JCP&L is permitted to defer for future collection from expense of $8 million, effective June 1, 2005, in customers the amounts by which its costs of supplying BGS to anticipation of an NJBPU order regardingJCP&L's non-shopping customers and costs incurred under NUG agree- request to securitize up to $277 million of its deferred ments exceed amounts collected through BGS and MTC rates cost balance; and market sales of NUG energy and capacity. As of December

• An increase in JCP&L's authorized return on common 31,2005, the accumulated deferred cost balance totaled approxi- equity from 9.5% to 9.75%; and mately $541 million. New Jersey law allows for securitization

• A commitment byJCP&L, through December 31, 2006 ofJCP&L's deferred balance upon application byJCP&L and or until related legislation is adopted, whichever occurs a determination by the NJBPU that the conditions of the New first, to maintain a target level of customer service Jersey restructuring legislation are met On February 14,2003, reliability with a reduction in JCP&L's authorized JCP&L filed for approval to securitize theJuly 31,2003 deferred return on common equity from 9.75 % to 9.5 % if the balance, JCP&L is in discussions with the NJBPU staff as a target is not met for two consecutive quarters. The result of the stipulated settlement agreements (as further dis- authorized return on common equity would then be cussed below) which recommended that the NJBPU issue an restored to 9.75 % if the target is met for two order regarding JCP&L's application. On July 20, 2005,JCP&L consecutive quarters.

requested the NJBPU to set a procedural schedule for this matter and is awaiting NJBPU action. On February 1,2006, the NJBPU The Phase II stipulation included an agreement that the selected Bear Stearns as the financial advisor. On December 2, distribution revenue increase also reflects a three-year amorti-2005, JCP&L filed a request for recovery of $165 million of zation ofJCP&L's one-time service reliability improvement actual above-market NUG costs incurred from August 1,2005 costs incurred in 2003-2005. This resulted in the creation of a through October 31,2005 and forecasted above-market NUG regulatory asset associated with accelerated tree trimming and costs for November and December 2005. The filing also includes other reliability costs which were expensed in 2003 and 2004.

a request for recovery of $49 million for above-market NUG The establishment of the new regulatory asset of approximate-costs incurred prior to August 1,2003, to the extent those costs ly $28 million resulted in an increase to net income of are not recoverable through securitization. approximately $16 million ($0.05 per share of common stock)

The 2003 NJBPU decision onJCP&L's base electric rate in the second quarter of 2005.

proceeding (the Phase I Order) disallowed certain regulatory JCP&L sells all self-supplied energy (NUGs and owned assets and provided for an interim return on equity of 9.5 % generation) to the wholesale market with offsetting credits to on JCP&L's rate base. The Phase I order also provided for a its deferred energy balance with the exception of 300 MW Phase II proceeding in which the NJBPU would review from JCP&L's NUG committed supply currently being used to whether JCP&L is in compliance with current service reliabili- serve BGS customers pursuant to NJBPU order for the period ty and quality standards and determine whether the June 1, 2005 through May 31, 2006. New BGS tariffs reflect-expenditures and projects undertaken byJCP&L to increase ing the results of a February 2005 auction for the BGS supply became effective June 1, 2005.

68 FirstEnergy Corp. 2005

The NJBPU decision approving the BGS procurement ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be proposal for the period beginning June 1, 2006 was issued on involved in FERC hearings concerning the calculation and October 12, 2005. JCP&L submitted a compliance filing on imposition of Seams Elimination Cost Adjustment (SECA)

October 26, 2005, which was approved onl November 10, charges to various load serving entities. Pursuant to its January 2005. The written Order was dated December 8, 2005. The 30, 2006 Order, the FERC has compressed both phases of this auction took place in early February 2006 and the results have proceeding into a single hearing scheduled to begin May 1, been approved by the NJBPU. 2006, with an initial decision on or before August 11, 2006.

In accordance with an April 28, 2004 NJBPU order, On December 30, 2004, the Ohio Companies filed with JCP&L filed testimony on June 7, 2004 supporting a continua- the PUCO two applications related to the recovery of trans-tion of the current level and duration of the funding of TMI-2 mission and ancillary service related costs. The first decommissioning costs by New Jersey customers without a application sought recovery of these costs beginning January reduction, termination or capping of the funding. On 1, 2006. The Ohio Companies requested that these costs be September 30, 2004, JCP&L filed an updated TMI-2 decom- recovered through a rider that would be effective on January missioning study. This study resulted in an updated total 1, 2006 and adjusted each July 1 thereafter. The PUCO decommissioning cost estimate of $729 million (in 2003 dol- approved the settlement stipulation on August 31, 2005. The lars) compared to the estimated $528 million (in 2003 dollars) incremental transmission and ancillary service revenues from the prior 1995 decommissioning study. The Ratepayer expected to be recovered from January through June 2006 are Advocate filed comments on February 28, 2005. On March 18, approximately $66 million. This amount includes the recovery 2005, JCP&L filed a response to those comments. A schedule of the 2005 deferred MISO expenses as described below. In for further proceedings has not yet been set. May 2006, the Companies will file a modification to the rider On August 1, 2005, the NJBPU established a proceeding to determine revenues from July 2006 through June 2007.

to determine whether additional ratepayer protections are The second application sought authority to defer costs required at the state level in light of the recent repeal of associated with transmission and ancillary service related PUHCA under the EPACT. An NJBPU proposed rulemaking costs incurred during the period from October 1, 2003 to address the issues was published in the NJ Register on through December 31, 2005. On May 18, 2005, the PUCO December 19, 2005. The proposal would prevent a holding granted the accounting authority for the Ohio Companies to company that owns a gas or electric public utility from invest- defer incremental transmission and ancillary service-related ing more than 25 % of the combined assets of its utility and charges incurred as a participant in MISO, but only for those utility-related subsidiaries into businesses unrelated to the costs incurred during the period December 30, 2004 through utility industry. A public hearing was held on February 7, December 31, 2005. Permission to defer costs incurred prior 2006 and comments may be submitted to the NJBPU by to December 30, 2004 was denied. The PUCO also authorized February 17, 2006. JCP&L is not able to predict the outcome the Ohio Companies to accrue carrying charges on the of this proceeding at this time. deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. All briefs have been filed. A motion to dis-(E)TRANSMISSION miss filed on behalf of the PUCO is currently pending. Unless On November 1, 2004, ATSI requested authority from the court grants the motion, the appeal will be set for oral the FERC to defer approximately $54 million of vegetation argument, which should be heard in the third or fourth quar-management costs estimated to be incurred from 2004 ter of 2006.

through 2007. On March 4, 2005, the FERC approved ATSI's On January 20, 2006 the OCC sought rehearing of the request to defer those costs ($26 million deferred as of PUCO approval of the rider recovery during the period January December 31, 2005). ATSI expects to file an application with 1, 2006 throughJune 30, 2006, as that amount pertains to the FERC in 2006 that would include recovery of the deferred recovery of the deferred costs. The PUCO denied the OCC's costs beginning June 1, 2006. application on February 6, 2006. The OCC has sixty days from On January 24, 2006, ATSI and MISO filed an applica- that date to appeal the PUCO's approval of the rider.

tion with the FERC to modify the Attachment 0 formula rate On January 12, 2005, Met-Ed and Penelec filed, before mechanism to permit ATSI to accelerate recovery of revenues the PPUC, a request for deferral of transmission-related costs lost due to the FERC's elimination of through and out rates beginning January 1, 2005, estimated to be approximately $8 between MISO and PJM, and the elimination of other ATSI million per month. The OCA, OSBA, OTS, MEIUG, PICA, rates in the MISO tariff. Revenues formerly collected under Allegheny Electric Cooperative and Pennsylvania Rural these rates are currently used to reduce the ATSI zonal trans- Electric Association have all intervened in the case. To date, mission rate in the Attachment 0 formula. The revenue no hearing schedule has been established, and neither compa-shortfall created by elimination of these rates would not be ny has yet implemented deferral accounting for these costs.

fully reflected in ATSI's formula rate until June 1, 2006, OnJanuary 31, 2005, certain PJM transmission owners unless the proposed Revenue Credit Collection is approved by made three filings pursuant to a settlement agreement previ-the FERC. The Revenue Credit Collection mechanism is ously approved by the FERC. JCP&L, Met-Ed and Penelec designed to collect approximately $40 million in revenues on were parties to that proceeding and joined in two of the fil-an annualized basis beginning June 1, 2006. FERC is expected ings. In the first filing, the settling transmission owners to act on this filing on or before April 1, 2006. submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling FirstEnergy Corp. 2005 69

transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new 11 . CAPrrAUZATION and existing transmission facilities. Interventions and protests (A) COMMON STOCK were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested Retained Earnings and Dividends a formula rate for transmission service provided within their Under applicable federal law, FirstEnergy and its sub-respective zones. On May 31, 2005, the FERC issued an order sidiaries can pay dividends only from retained or current on these cases. First, it set for hearing the existing rate design earnings, unless the FERC specifically authorizes payment and indicated that it will issue a final order within six from other capital accounts. As of December 31, 2005, months. Second, the FERC approved the proposed Schedule FirstEnergy's unrestricted retained earnings were $2.2 billion.

12 rate harmonization. Third, the FERC accepted the pro-The articles of incorporation, indentures and various other posed formula rate, subject to referral and hearing procedures.

agreements relating to the long-term debt and preferred stock On June 30, 2005, the PJM transmission owners filed a of certain FirstEnergy subsidiaries contain provisions that request for rehearing of the May 31, 2005 order. The rate could further restrict the payment of dividends on their com-design and formula rate proceedings are currently being liti-mon and preferred stock. As of December 31, 2005, none of gated before the FERC. If FERC accepts AEP's proposal to these provisions materially restricted FirstEnergy's sub-create a "postage stamp" rate for high voltage transmission sidiaries ability to pay cash dividends to FirstEnergy.

facilities across PJM, significant additional transmission rev-On November 15, 2005, the Board of Directors increased enues would be imposed on JCP&L, Met-Ed, Penelec, and the indicated annual dividend to $1.80 per share, payable other transmission zones within PJM.

quarterly at a rate of $0.45 per share beginning in the first On November 1, 2005, FES filed two power sales agree-quarter of 2006. Dividends declared in 2005 were $1.705 ments for approval with the FERC. One power sales which included quarterly dividends of $0.4125 per share paid agreement provided for FES to provide the PLR requirements in the second and third quarters of 2005, a quarterly dividend of the Ohio Companies at a price equal to the retail generation of $0.43 per share paid in the fourth quarter of 2005 and a rates approved by the PUCO for a period of three years begin-quarterly dividend of $0.45 per share payable in the first quar-ning January 1, 2006. The Ohio Companies will be relieved of ter of 2006. Dividends declared in 2004 were $1.9125, which their obligation to obtain PLR power requirements from FES included quarterly dividends of $0.375 per share paid in each if the Ohio competitive bid process results in a lower price for quarter of 2004 and an additional dividend of $.04125 paid in retail customers. A similar power sales agreement between FES the first quarter of 2005. The amount and timing of all divi-and Penn permits Penn to obtain its PLR power requirements dend declarations are subject to the discretion of the Board from FES at a fixed price equal to the retail generation price and its consideration of business conditions, results of during 2006. Penn has filed a plan with the PPUC to use an operations, financial condition and other factors.

RFP process to obtain its power supply requirements after 2006.

On December 29, 2005, the FERC issued an order setting (B)PREFERRED AND PREFERENCE STOCK the two power sales agreements for hearing. The order criti-All preferred stock may be redeemed by the Companies cizes the Ohio competitive bid process, and requires FES to in whole, or in part, with 30-90 days' notice.

submit additional evidence in support of the reasonableness of On January 20, 2006, TE redeemed all 1.2 million of its the prices charged in the Ohio and Pennsylvania Contracts. A outstanding shares of Adjustable Rate Series B preferred stock pre-hearing conference was held on January 18, 2006 to deter-at $25.00 per share, plus accrued dividends to the date of mine the hearing schedule in this case. FES expects an initial redemption.

decision to be issued in this case in the fall of 2006. The out-Met-Ed's and Penelec's preferred stock authorizations come of this proceeding cannot be predicted. FES has sought consist of 10 million and 11.435 million shares, respectively, rehearing of the December 29, 2005 order.

without par value. No preferred shares are currently outstand-ing for those companies.

The Companies' preference stock authorization consists of 8 million shares without par value for OE; 3 million shares without par value for CEI; and 5 million shares, $25 par value for TE. No preference shares are currently outstanding.

(C)LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS SubordinatedDebentures to Affiliated Trusts As of December 31, 2005, CEI's wholly owned statutory business trust, Cleveland Electric Financing Trust, had $100 million of outstanding 9.00 % preferred securities that mature in 2031. The sole assets of the trust are CEI's subordinated debentures having the same rate and maturity date as the preferred securities.

70 FirstEnergy Corp. 2005

CEI formed the trust to sell preferred securities and invest- issued under the various mortgage indentures amounts to ed the gross proceeds in the 9.00 % subordinated debentures of $67 million. OE and Penn expect to deposit funds with their CEI. The sole assets of the trust are the applicable subordinated respective mortgage bond trustees in 2006 that will then be debentures. Interest payment provisions of the subordinated withdrawn upon the surrender for cancellation of a like debentures match the distribution payment provisions of the principal amount of FMB, specifically authenticated for trust's preferred securities. In addition, upon redemption or such purposes against unfunded property additions or against payment at maturity of subordinated debentures, the trust's previously retired FMB. This method can result in minor preferred securities will be redeemed on a pro rata basis at their increases in the amount of the annual sinking fund require-liquidation value. Under certain circumstances, the applicable ment. JCP&L, Met-Ed and Penelec could fulfill their sinking subordinated debentures could be distributed to the holders of fund obligations by providing bondable property additions, the outstanding preferred securities of the trust in the event previously retired FMB or cash to the respective mortgage that the trust is liquidated. CEI has effectively provided a full bond trustees.

and unconditional guarantee of payments due on the trust's Sinking fund requirements for FMB and maturing long-preferred securities. The trust's preferred securities are term debt (excluding capital leases) for the next five years are:

redeemable at 100 % of their principal amount at CEI's option (n niftins) beginning in December 2006. Interest on the subordinated 2006 $2,040 debentures (and therefore distributions on the trust's preferred 2007 229 securities) may be deferred for up to 60 months, but CEI may 2008 463 2009 278 not pay dividends on, or redeem or acquire, any of its cumula- 2010 204 tive preferred or common stock until deferred payments on its subordinated debentures are paid in full.

Included in the table above are amounts for certain vari-Securitized TransitionBonds able interest rate pollution control bonds that have provisions JCP&L Transition (Issuer), a wholly owned limited liabil- by which individual debt holders are required to "put back" ity company of JCP&L, sold $320 million of transition bonds the respective debt to the issuer for redemption prior to its to securitize the recovery of JCP&L's bondable stranded costs maturity date. These amounts are $662 million, $132 million associated with the previously divested Oyster Creek Nuclear and $15 million in 2006, 2008 and 2010, respectively, repre-Generating Station. JCP&L did not purchase and does not senting the next times the debt holders may exercise this own any of the transition bonds. As of December 31, 2005, provision.

$264 million of transition bonds are outstanding and included Obligations to repay certain pollution control revenue in long-term debt on FirstEnergy's Consolidated Balance bonds are secured by several series of FMB. Certain pollution Sheet. The transition bonds represent obligations only of the control revenue bonds are entitled to the benefit of irrevocable Issuer and are collateralized solely by the equity and assets bank LOCs of $604 million at December 31, 2005 or non-of the Issuer, which consist primarily of bondable transition cancelable municipal bond insurance policies of $1.419 billion property. The bondable transition property is solely the at December 31, 2005 to pay principal of, or interest on, the property of the Issuer. applicable pollution control revenue bonds. To the extent that Bondable transition property represents the irrevocable drawings are made under the LOCs or the policies, FGCO, right of a utility company to charge, collect and receive from NGC and the Companies are entitled to a credit against their its customers, through a non-bypassable TBC, the principal obligation to repay those bonds. FGCO, NGC and the amount and interest on the transition bonds and other fees Companies pay annual fees of 0.65 % to 1.70 % of the amounts and expenses associated with their issuance. JCP&L, as ser- of the LOCs to the issuing banks and 0.16 % to 0.60 % of the vicer, manages and administers the bondable transition amounts of the policies to the insurers and are obligated to property, including the billing, collection and remittance of reimburse the banks or insurers, as the case may be, for any the TBC, pursuant to a servicing agreement with the Issuer. drawings thereunder. Certain of the issuing banks and insur-ers hold FMB as security for such reimbursement obligations.

Other Long-term Debt Certain secured notes of CEI and TE are entitled to the Each of the Companies has a first mortgage indenture benefit of noncancelable municipal bond insurance policies under which it issues FMB secured by a direct first mortgage of $120 million and $30 million, respectively, to pay principal lien on substantially all of its property and franchises, other of, or interest on, the applicable notes. To the extent that than specifically excepted property. FirstEnergy and its sub- drawings are made under the policies, CEI and TE are entitled sidiaries have various debt covenants under their respective to a credit against their obligation to repay those notes. CEI financing arrangements. The most restrictive of the debt and TE are obligated to reimburse the insurer for any draw-covenants relate to the nonpayment of interest and/or princi- ings thereunder.

pal on debt and the maintenance of certain financial ratios. CEI and TE have unsecured LOCs of approximately $194 There also exist cross-default provisions among financing million in connection with the sale and leaseback of Beaver arrangements of FirstEnergy and the Companies. Valley Unit 2 for which they are jointly and severally liable.

Based on the amount of FMB authenticated by the respec- OE has LOCs of $291 million and $134 million in connection tive mortgage bond trustees through December 31, 2005, the with the sale and leaseback of Beaver Valley Unit 2 and Perry Companies' annual sinking fund requirement for all FMB Unit 1, respectively. OE entered into a Credit Agreement pur-FirstEnergy Corp. 2005 71

suant to which a standby LOC was issued in support of the decommissioning ARO. As of December 31,2005, the fair value replacement LOCs and the issuer of the standby LOC obtained of the decommissioning trust assets was $1.752 billion.

the right to pledge or assign participations in OE's reimburse- FirstEnergy implemented FIN 47, "Accounting for ment obligations to a trust. The trust then issued and sold Conditional Asset Retirement Obligations", an interpretation trust certificates to institutional investors that were designed of SFAS 143, on December 31, 2005. FIN 47 provides to be the credit equivalent of an investment directly in OE. accounting standards for conditional retirement obligations associated with tangible long-lived assets, requiring recogni-tion of the fair value of a liability for an ARO in the period in

12. ASSET RETIREMENT OBLIGATIONS which it is incurred if a reasonable estimate can be identified.

FIN 47 states that an obligation exists even though there may In January 2003, FirstEnergy implemented SPAS 143, be uncertainty about timing or method of settlement and fur-which provides accounting guidance for retirement obligations ther clarifies SFAS 143, stating that the uncertainty associated with tangible long-lived assets. This standard surrounding the timing and method of settlement when settle-requires recognition of the fair value of a liability for an ARO ment is conditional on a future event occurring should be in the period in which it is incurred. The associated asset reflected in the measurement of the liability, not in the recog-retirement costs are capitalized as part of the carrying amount nition of the liability. Accounting for conditional ARO under of the long-lived asset. Over time the capitalized costs are FIN 47 is the same as described above for SFAS 143.

depreciated and the present value of the ARO increases, FirstEnergy identified applicable legal obligations as resulting in a period expense. However, rate-regulated entities defined under the new standard at its active and retired gener-may recognize a regulatory asset or liability instead of an ating units, substation control rooms, service center buildings, expense if the criteria for such treatment are met. Upon retire- line shops and office buildings, identifying asbestos remedia-ment, a gain or loss would be recognized if the cost to settle tion as the primary conditional ARO. As a result of adopting the retirement obligation differs from the carrying amount. FIN 47 in December 2005, FirstEnergy recorded a conditional FirstEnergy initially identified applicable legal obligations ARO liability of $57 million (including accumulated accretion as defined under the standard for nuclear power plant decom- for the period from the date the liability was incurred to the missioning, reclamation of a sludge disposal pond related to date of adoption), an asset retirement cost of $16 million the Bruce Mansfield Plant and closure of two coal ash disposal (recorded as part of the carrying amount of the related long-sites. The ARO liability associated with decommissioning was lived asset) and accumulated depreciation of $12 million.

$1.069 billion as of December 31, 2005 and included $1.054 FirstEnergy charged a regulatory liability of $5 million upon billion for decommissioning the Beaver Valley, Davis-Besse, adoption of FIN 47 for the transition amounts related to Perry and TMI-2 nuclear generating facilities. The obligation establishing the ARO for asbestos removal from substation to decommission these units was developed based on site control rooms and service center buildings for OE, Penn, CEI, specific studies performed by an independent engineer. TE and JCP&L. The remaining cumulative effect adjustment FirstEnergy utilized an expected cash flow approach to for unrecognized depreciation and accretion of $48 million measure the fair value of the nuclear decommissioning ARO. was charged to income ($30 million, net of tax), - $0.09 per In 2005, FirstEnergy revised the ARO associated with share of common stock (basic and diluted) for the year ended Beaver Valley Units 1 and 2, Davis-Besse and Perry, as a result December 31, 2005. The obligation to remediate asbestos, lead of updated decommissioning studies. The present value of paint abatement and other remediation costs at retired gener-revisions in the estimated cash flows associated with projected ating units was developed based on site specific studies decommissioning costs increased the ARO for Beaver Valley performed by an independent engineer. The cost to remediate Unit 1 by $21 million and decreased the ARO for Beaver asbestos, lead paint and other environmental liabilities at Valley Unit 2 by $22 million, resulting in a net decrease in the active generating units was calculated utilizing a per-kilowatt ARO liability and corresponding plant asset of $1 million. The removal cost developed from the independent studies complet-present value of revisions in the estimated cash flows associat- ed at the retired generating units, applied to the specific ed with projected decommissioning costs decreased the ARO kilowatt capacity of each individual active generating unit.

and corresponding plant asset for Davis-Besse and Perry by The costs of asbestos, lead paint and other remediation at the

$21 million and $57 million, respectively. Company's substation control rooms, service center buildings, In 2004, FirstEnergy revised the ARO associated with line shops and office buildings were based on costs incurred TMI-2 as the result of an updated study and the anticipated during recent remediation projects performed at each of these operating license extension for TMI-1. The abandoned TMI-2 locations. The conditional ARO liability was developed utiliz-is adjacent to TMI-1 and the units are expected to be decom- ing an expected cash flow approach (as discussed in SFAC No.

missioned concurrently. The decrease in the present value of 7). The Company used a probability weighted analysis to esti-estimated cash flows associated with the license extension of mate when remediation payments would begin.

$202 million was partially offset by the $26 million present value of an increase in projected decommissioning costs. The net decrease in the TMI-2 ARO liability and corresponding regulatory asset was $176 million.

FirstEnergy maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear 72 FirstEnergy Corp. 2005

The following table describes the changes to the ARO bal-ances during 2005 and 2004.

1 3. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT ARO Reconciliation 2005 2004 O(nmtorns) FirstEnergy had approximately $731 million of short-Balance at beginning of year $1,078 S1,179 term indebtedness as of December 31, 2005, comprised of Liabilities incurred - -

Uabilities settled . - $439 million in borrowings from a $2 billion revolving line Accretion 70 75 of credit, $280 million in borrowings through $550 million Revisions Inestimated cash flows (79) (176)

FIN 47 ARO 57 - of available accounts receivables financing and $12 million Balance at end of year $1,126 $1,078 of other bank borrowings. Total short-term bank lines of committed credit to FirstEnergy and the Companies as of December 31, 2005 were approximately $2.6 billion.

The following table provides the year-end balance of the On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, conditional ARO as if FIN 47 had been adopted on January 1, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered 2005 and 2004, respectively: into a syndicated $2 billion five-year revolving credit facility with a syndicate of banks that expires in June 2010.

Adjusted ARO Reconciliation 2005 2004 Borrowings under the facility are available to each Borrower

, n miions) separately and mature on the earlier of 364 days from the date Beginning balance as of January 1 $54 $51 Accretion 3 3 of borrowing or the commitment expiration date, as the same

$57 $54 may be extended. As of December 31, 2005, FirstEnergy was l Ending balance as of December 31 the only borrower on this revolver with an outstanding balance of $439 million. The annual facility fees are 0.15% to 0.50%.

The following table provides the effect on income as if The Companies, with the exception of TE and JCP&L, FIN 47 had been applied during 2004 and 2003. each have a wholly owned subsidiary whose borrowings are secured by customer accounts receivable purchased from its

. Effect of the Change in Accounting respective parent company. The CEI subsidiary's borrowings Principle Applied Retroactively 2004 2003 are also secured by customer accounts receivable purchased Otnmilions excep per shore amounts)

Net income as reported $ 878 $ 423 from TE. Each subsidiary company has its own receivables

! Increase (Decrease):

financing arrangement and, as a separate legal entity with

Depreciation of asset retirement cost Accretion of ARO liability (3) (2) separate creditors, would have to satisfy its obligations to Income tax effect 1 1 creditors before any of its remaining assets could be available Net income adjusted S876 $ 422 to its parent company. The receivables financing borrowing Basic earnings per share of common stock

capacity and outstanding balance by company, as of December As reported $2.68 $1.39 31, 2005, appear in the table that follows.

As adjusted $2.68 $1.39 Diluted earnings per share of common stock:

$2.67 $1.39 Outstanding Annual As reported Parent Company Capacity Balance Facility Fee As adjusted $2.66 $1.38 Subsidiary Company Oinmibbls)

OES Capital, Incorporated OE $170 $140 0.20$

Centerior Funding Corp. CEI 200 140 0.25 Penn Power Funding LLC Penn 25 - 0.15 Met-Ed Funding LLC Met-Ed 80 - 0.15 Penelec Funding LLC Penelec 75 - 0.15

$550 $280 All of the receivables financing agreements will terminate in 2006 and are expected to be renewed prior to expiration.

The weighted average interest rates on short-term bor-rowings outstanding as of December 31, 2005 and 2004 were 4.68 % and 2.35 % respectively. The annual facility fees on all current committed short-term bank lines of credit range from 0.15 % to 0.50 %.

FirstEnergy corp. 2005 73

and ongoing energy and energy-related activities.

14. COMMITMENTS, GUARANTEES AND While these types of guarantees are normally parental CONTINGENCIES commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating-downgrade or (A) NUCLEAR INSURANCE "material adverse event" the immediate posting of cash collat-The Price-Anderson Act limits the public liability relative eral or provision of an LOC may be required of the subsidiary.

to a single incident at a nuclear power plant to $10.8 billion.

The following table summarizes collateral provisions as of The amount is covered by a combination of private insurance December 31, 2005:

and an industry retrospective rating plan. FirstEnergy's maxi-mum potential assessment under the industry retrospective Collateral Paid Remnaining rating plan would be $402 million per incident but not more Collateral Provisions Exposure Cash LOC Exposure than $60 million in any one year for each incident.

(Inmilions)

FirstEnergy is also insured under policies for each Credit rating downgrade $380 $78 $- $302 nuclear plant. Under these policies, up to $2.75 billion is AdverseEvent 74 - - 74 provided for property damage and decontamination costs. Total $454 $78 1- $376 FirstEnergy has also obtained approximately $1.7 billion of insurance coverage for replacement power costs. Under these policies, FirstEnergy can be assessed a maximum of approxi- Most of FirstEnergy's surety bonds are backed by various mately $80 million for incidents at any covered nuclear indemnities common within the insurance industry. Surety facility occurring during a policy year which are in excess of bonds and related FirstEnergy guarantees of $312 million pro-accumulated funds available to the insurer for paying losses. vide additional assurance to outside parties that contractual FirstEnergy intends to maintain insurance against and statutory obligations will be met in a number of areas nuclear risks, as described above, as long as it is available. including construction jobs, environmental commitments and To the extent that replacement power, property damage, various retail transactions.

decontamination, repair and replacement costs and other such FirstEnergy has also guaranteed the obligations of the costs arising from a nuclear incident at any of FirstEnergy's operators of the TEBSA project, up to a maximum of $6 mil-plants exceed the policy limits of the insurance in effect with lion (subject to escalation) under the project's operations and respect to that plant, to the extent a nuclear incident is maintenance agreement. In connection with the sale of determined not to be covered by FirstEnergy's insurance policies, TEBSA in January 2004, the purchaser indemnified or to the extent such insurance becomes unavailable in the FirstEnergy against any loss under this guarantee. FirstEnergy future, FirstEnergy would remain at risk for such costs. has also provided an LOC ($36 million as of December 31, 2005), which is renewable and declines yearly based upon the (B)GUARANTEES AND OTHER ASSURANCES senior outstanding debt of TEBSA.

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to pro- (C) ENVIRONMENTAL MATTERS vide financial or performance assurances to third parties. Various federal, state and local authorities regulate the These agreements include contract guarantees, surety bonds Companies with regard to air and water quality and other and LOCs. As of December 31, 2005, outstanding guarantees environmental matters. The effects of compliance on the and other assurances aggregated approximately $3.4 billion - Companies with regard to environmental matters could have a contract guarantees ($1.7 billion), surety bonds ($0.3 billion) material adverse effect on FirstEnergy's earnings and competi-and LOC ($1.4 billion). tive position to the extent that it competes with companies FirstEnergy guarantees energy and energy-related pay- that are not subject to such regulations and therefore do not ments of its subsidiaries involved in energy commodity bear the risk of costs associated with compliance, or failure to activities principally to facilitate normal physical transactions comply, with such regulations. Overall, FirstEnergy believes it involving electricity, gas, emission allowances and coal. is in compliance with existing regulations but is unable to pre-FirstEnergy also provides guarantees to various providers of dict future changes in regulatory policies and what, if any, the subsidiary financing principally for the acquisition of proper- effects of such changes would be. FirstEnergy estimates addi-ty, plant and equipment. These agreements legally obligate tional capital expenditures for environmental compliance of FirstEnergy to fulfill the obligations of those subsidiaries approximately $1.8 billion for 2006 through 2010.

directly involved in energy and energy-related transactions or The Companies accrue environmental liabilities only financing where the law might otherwise limit the counterpar- when they conclude that it is probable that they have an obli-ties' claims. If demands of a counterparty were to exceed the gation for such costs and can reasonably estimate the amount ability of a subsidiary to satisfy existing obligations, of such costs. Unasserted claims are reflected in the FirstEnergy's guarantee enables the counterparty's legal claim Companies' determination of environmental liabilities and are to be satisfied by other FirstEnergy assets. The likelihood is accrued in the period that they are both probable and reason-remote that such parental guarantees of $0.8 billion (included ably estimable.

in the $1.7 billion discussed above) as of December 31, 2005 On December 1, 2005, FirstEnergy issued a comprehen-would increase amounts otherwise payable by FirstEnergy to sive report to shareholders regarding air emissions regulations meet its obligations incurred in connection with financings and an assessment of its future risks and mitigation efforts.

74 FirstEnergy Corp. 2005

Clean Air Act Compliance be substantial and will depend on how they are ultimately FirstEnergy is required to meet federally approved S02 implemented by the states in which FirstEnergy operates regulations. Violations of such regulations can result in shut- affected facilities.

down of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the unit is in violation. Mercurry Emissions The EPA has an interim enforcement policy for S02 regula- In December 2000, the EPA announced it would proceed tions in Ohio that allows for compliance based on a 30-day with the development of regulations regarding hazardous air averaging period. The Companies cannot predict what action pollutants from electric power plants, identifying mercury as the EPA may take in the future with respect to the interim the hazardous air pollutant of greatest concern. On March 14, enforcement policy. 2005, the EPA finalized the CAMR, which provides a cap-and-FirstEnergy believes it is complying with S02 reduction trade program to reduce mercury emissions from coal-fired requirements under the Clean Air Act Amendments of 1990 power plants in two phases. Initially, mercury emissions will by burning lower-sulfur fuel, generating more electricity from be capped nationally at 38 tons by 2010 (as a "co-benefit" lower-emitting plants, and/or using emission allowances. NOx from implementation of SO 2 and NOx emission caps under reductions required by the 1990 Amendments are being the EPA's CAIR program). Phase II of the mercury cap-and-achieved through combustion controls and the generation of trade program will cap nationwide mercury emissions from more electricity at lower-emitting plants. In September 1998, coal-fired power plants at 15 tons per year by 2018. However, the EPA finalized regulations requiring additional NOx reduc- the final rules give states substantial discretion in developing tions from FirstEnergy's facilities. The EPA's NOx Transport rules to implement these programs. In addition, both the Rule imposes uniform reductions of NOx emissions (an CAIR and the CAMR have been challenged in the United approximate 85 % reduction in utility plant NOx emissions States Court of Appeals for the District of Columbia.

from projected 2007 emissions) across a region of nineteen FirstEnergy's future cost of compliance with these regulations states (including Michigan, NewJersey, Ohio and may be substantial and will depend on how they are ultimate-Pennsylvania) and the District of Columbia based on a conclu- ly implemented by the states in which FirstEnergy operates sion that such NOx emissions are contributing significantly to affected facilities.

ozone levels in the eastern United States. FirstEnergy believes The model rules for both CAIR and CAMR contemplate its facilities are also complying with the NOx budgets estab- an input-based methodology to allocate allowances to affected lished under State Implementation Plans through combustion facilities. Under this approach, allowances would be allocated controls and post-combustion controls, including Selective based on the amount of fuel consumed by the affected sources.

Catalytic Reduction and Selective Non-Catalytic Reduction We would prefer an output-based generation-neutral method-systems, and/or using emission allowances. ology in which allowances are allocated based on megawatts of power produced. Since this approach is based on output, National Ambient Air Qualit, Standards new and non-emitting generating facilities, including renew-In July 1997, the EPA promulgated changes in the ables and nuclear, would be entitled to their proportionate NAAQS for ozone and proposed a new NAAQS for fine par- share of the allowances. Consequently, we would be disadvan-ticulate matter. On March 10, 2005, the EPA finalized the taged if these model rules were implemented because our "Clean Air Interstate Rule" covering a total of 28 states substantial reliance on non-emitting (largely nuclear) genera-(including Michigan, New Jersey, Ohio and Pennsylvania) and tion is not recognized under input-based allocation.

the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia W H. Sammis Plant significantly contribute to non-attainment of the NAAQS for In 1999 and 2000, the EPA issued NOV or Compliance fine particles and/or the "8-hour" ozone NAAQS in other Orders to nine utilities alleging violations of the Clean Air states. CAIR provides each affected state until 2006 to develop Act based on operation and maintenance of 44 power plants, implementing regulations to achieve additional reductions of including the W.H. Sammis Plant, which was owned at that NOx and SO2 emissions in two phases (Phase I in 2009 for time by OE and Penn. In addition, the DOJ filed eight civil NOx, 2010 for SO2 and Phase H in 2015 for both NOx and complaints against various investor-owned utilities, including SO 2). FirstEnergy's Michigan, Ohio and Pennsylvania fossil- a complaint against OE and Penn in the U.S. District Court fired generation facilities will be subject to caps on S02 and for the Southern District of Ohio. These cases are referred to NOx emissions, whereas its New Jersey fossil-fired generation as New Source Review cases. On March 18, 2005, OE and facilities will be subject to only a cap on NOx emissions. Penn announced that they had reached a settlement with the According to the EPA, SO2 emissions will be reduced by 45 % EPA, the DOJ and three states (Connecticut, New Jersey, and (from 2003 levels) by 2010 across the states covered by the New York) that resolved all issues related to the W H. Sammis rule, with reductions reaching 73 % (from 2003 levels) by Plant New Source Review litigation. This settlement agree-2015, capping SO2 emissions in affected states to just 2.5 mil- ment was approved by the Court on July 11, 2005, and lion tons annually. NOx emissions will be reduced by 539% requires reductions of NOx and S02 emissions at the W. H.

(from 2003 levels) by 2009 across the states covered by the Sammis Plant and other coal fired plants through the installa-rule, with reductions reaching 61 % (from 2003 levels) by tion of pollution control devices and provides for stipulated 2015, achieving a regional NOx cap of 1.3 million tons annu- penalties for failure to install and operate such pollution con-ally. The future cost of compliance with these regulations may trols in accordance with that agreement. Consequently, if FirstEnergy Corp. 2005 75

FirstEnergy fails to install such pollution control devices, for intake structures at certain existing large electric generating any reason, including, but not limited to, the failure of any plants. The regulations call for reductions in impingement third-party contractor to timely meet its delivery obligations mortality, when aquatic organisms are pinned against screens for such devices, FirstEnergy could be exposed to penalties or other parts of a cooling water intake system and entrain-under the settlement agreement. Capital expenditures neces- ment, which occurs when aquatic species are drawn into a sary to meet those requirements are currently estimated to be facility's cooling water system. FirstEnergy is conducting com-

$1.5 billion (the primary portion of which is expected to be prehensive demonstration studies, due in 2008, to determine spent in the 2008 to 2011 time period). On August 26, 2005, the operational measures, equipment or restoration activities, FGCO entered into an agreement with Bechtel Power if any, necessary for compliance by its facilities with the Corporation (Bechtel), under which Bechtel will engineer, performance standards. FirstEnergy is unable to predict the procure, and construct air quality control systems for the outcome of such studies. Depending on the outcome of such reduction of sulfur dioxide emissions. The settlement agree- studies, the future cost of compliance with these standards ment also requires OE and Penn to spend up to $25 million may require material capital expenditures.

toward environmentally beneficial projects, which include wind energy purchased power agreements over a 20-year Regulation of Hazardous Waste term. OE and Penn agreed to pay a civil penalty of $8.5 As a result of the Resource Conservation and Recovery million. Results in 2005 included the penalties payable by Act of 1976, as amended, and the Toxic Substances Control OE and Penn of $7.8 million and $0.7 million, respectively. Act of 1976, federal and state hazardous waste regulations OE and Penn also recognized liabilities of $9.2 million and have been promulgated. Certain fossil-fuel combustion waste

$0.8 million, respectively, for probable future cash contributions products, such as coal ash, were exempted from hazardous toward environmentally beneficial projects. waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently Climate Change determined that regulation of coal ash as a hazardous waste In December 1997, delegates to the United Nations' is unnecessary. In April 2000, the EPA announced that it climate summit inJapan adopted an agreement, the Kyoto will develop national standards regulating disposal of coal Protocol, to address global warming by reducing the amount ash under its authority to regulate nonhazardous waste.

of man-made GHG emitted by developed countries by 5.2 % The Companies have been named as PRPs at waste from 1990 levels between 2008 and 2012. The United States disposal sites, which may require cleanup under the signed the Kyoto Protocol in 1998 but it failed to receive the Comprehensive Environmental Response, Compensation, two-thirds vote required for ratification by the United States and Liability Act of 1980. Allegations of disposal of hazardous Senate. However, the Bush administration has committed the substances at historical sites and the liability involved are United States to a voluntary climate change strategy to reduce often unsubstantiated and subject to dispute; however, federal domestic GHG intensity - the ratio of emissions to economic law provides that all PRPs for a particular site are liable on output - by 18 % through 2012. The EPACT established a a joint and several basis. Therefore, environmental liabilities Committee on Climate Change Technology to coordinate that are considered probable have been recognized on the federal climate change activities and promote the development Consolidated Balance Sheet as of December 31, 2005, based and deployment of GHG reducing technologies. on estimates of the total costs of cleanup, the Companies' FirstEnergy cannot currently estimate the financial proportionate responsibility for such costs and the financial impact of climate change policies, although the potential ability of other unaffiliated entities to pay. In addition, JCP&L restrictions on CO 2 emissions could require significant capital has accrued liabilities for environmental remediation of for-and other expenditures. The CO2 emissions per kilowatt-hour mer manufactured gas plants in NewJersey; those costs are of electricity generated by FirstEnergy is lower than many being recovered by JCP&L through a non-bypassable SBC.

regional competitors due to its diversified generation sources, Total liabilities of approximately $64 million have been which include low or non-CO2 emitting gas-fired and nuclear accrued through December 31, 2005.

generators.

(D) OTHER LEGAL PROCEEDINGS Clean Water Act Various water quality regulations, the majority of which Power Outages and Related Litigation are the result of the federal Clean Water Act and its amendments, In July 1999, the Mid-Atlantic States experienced a severe apply to FirstEnergy's plants. In addition, Ohio, New Jersey heat wave, which resulted in power outages throughout the and Pennsylvania have water quality standards applicable to service territories of many electric utilities, including JCP&L's FirstEnergy's operations. As provided in the Clean Water Act, territory. In an investigation into the causes of the outages authority to grant federal National Pollutant Discharge and the reliability of the transmission and distribution sys-Elimination System water discharge permits can be assumed tems of all four of New Jersey's electric utilities, the NJBPU by a state. Ohio, New Jersey and Pennsylvania have assumed concluded that there was not a prima facie case demonstrating such authority. that, overall, JCP&L provided unsafe, inadequate or improper On September 7,2004, the EPA established new performance service to its customers. Two class action lawsuits (subse-standards under Section 316(b) of the Clean Water Act for quently consolidated into a single proceeding) were filed in reducing impacts on fish and shellfish from cooling water New Jersey Superior Court in July 1999 againstJCP&L, GPU 76 FirstEnergy Corp. 2005

and other GPU companies, seeking compensatory and puni- recommendations that were directed toward FirstEnergy.

tive damages arising from the July 1999 service interruptions FirstEnergy also is proceeding with the implementation of the in the JCP&L territory. recommendations regarding enhancements to regional reliabil-In August 2002, the trial court granted partial summary ity that were to be completed subsequent to 2004 and will judgment to JCP&L and dismissed the plaintiffs' claims for continue to periodically assess the FERC-ordered Reliability consumer fraud, common law fraud, negligent misrepresenta- Study recommendations for forecasted 2009 system condi-tion, and strict product liability. In November 2003, the trial tions, recognizing revised load forecasts and other changing court granted JCP&L's motion to decertify the class and system conditions which may impact the recommendations.

denied plaintiffs' motion to permit into evidence their class- Thus far, implementation of the recommendations has not wide damage model indicating damages in excess of $50 required, nor is expected to require, substantial investment in million. These class decertification and damage rulings were new or material upgrades to existing equipment, and therefore appealed to the Appellate Division. The Appellate Division FirstEnergy has not accrued a liability as of December 31, issued a decision on July 8, 2004, affirming the decertification 2005 for any expenditures in excess of those actually incurred of the originally certified class, but remanding for certification through that date. The FERC or other applicable government of a class limited to those customers directly impacted by the agencies and reliability coordinators may, however, take a dif-outages of JCP&L transformers in Red Bank, New Jersey. On ferent view as to recommended enhancements or may September 8, 2004, the New Jersey Supreme Court denied the recommend additional enhancements in the future that could motions filed by plaintiffs and JCP&L for leave to appeal the require additional, material expenditures. Finally, the PUCO is decision of the Appellate Division. JCP&L has filed a motion continuing to review FirstEnergy's filing that addressed for summary judgment. FirstEnergy is unable to predict the upgrades to control room computer hardware and software outcome of these matters and no liability has been accrued as and enhancements to the training of control room operators of December 31, 2005. before determining the next steps, if any, in the proceeding.

On August 14, 2003, various states and parts of southern FirstEnergy companies also are defending six separate Canada experienced widespread power outages. The outages complaint cases before the PUCO relating to the August 14, affected approximately 1.4 million customers in FirstEnergy's 2003 power outage. Two cases were originally filed in Ohio service area. The U.S. - Canada Power System Outage Task State courts but were subsequently dismissed for lack of sub-Force's final report in April 2004 on the outages concluded, ject matter jurisdiction and further appeals were unsuccessful.

among other things, that the problems leading to the outages In these cases the individual complainants-three in one case began in FirstEnergy's Ohio service area. Specifically, the final and four in the other-sought to represent others as part of a report concluded, among other things, that the initiation of class action. The PUCO dismissed the class allegations, stating the August 14, 2003 power outages resulted from an alleged that its rules of practice do not provide for class action com-failure of both FirstEnergy and ECAR to assess and under- plaints. Of the four other pending PUCO complaint cases, stand perceived inadequacies within the FirstEnergy system; three were filed by various insurance carriers either in their inadequate situational awareness of the developing conditions; own name as subrogees or in the name of their insured. In and a perceived failure to adequately manage tree growth in each of the four cases, the carrier seeks reimbursement from certain transmission rights of way. The Task Force also con- various FirstEnergy companies (and, in one case, from PJM, cluded that there was a failure of the interconnected grid's MISO and American Electric Power Company, Inc. as well) reliability organizations (MISO and PJM) to provide effective for claims paid to insureds for claims allegedly arising as a real-time diagnostic support. The final report is publicly avail- result of the loss of power on August 14, 2003. The listed able through the Department of Energy's website insureds in these cases, in many instances, are not customers (www.doe.gov). FirstEnergy believes that the final report does of any FirstEnergy company. The fourth case involves the not provide a complete and comprehensive picture of the con- claim of a non-customer seeking reimbursement for losses ditions that contributed to the August 14, 2003 power outages incurred when its store was burglarized on August 14, 2003.

and that it does not adequately address the underlying causes In addition to these six cases, the Ohio Companies were of the outages. FirstEnergy remains convinced that the out- named as respondents in a regulatory proceeding that was ini-ages cannot be explained by events on any one utility's tiated at the PUCO in response to complaints alleging failure system. The final report contained 46 "recommendations to to provide reasonable and adequate service stemming primari-prevent or minimize the scope of future blackouts." Forty-five ly from the August 14, 2003 power outages. No estimate of of those recommendations related to broad industry or policy potential liability is available for any of these cases.

matters while one, including subparts, related to activities the In addition to the above proceedings, FirstEnergy was Task Force recommended be undertaken by FirstEnergy, named in a complaint filed in Michigan State Court by an indi-MISO, PJM, ECAR, and other parties to correct the causes of vidual who is not a customer of any FirstEnergy company. A the August 14, 2003 power outages. FirstEnergy implemented responsive pleading to this matter has been filed. FirstEnergy several initiatives, both prior to and since the August 14, 2003 was also named, along with several other entities, in a com-power outages, which were independently verified by NERC plaint in New Jersey State Court. The allegations against as complete in 2004 and were consistent with these and other FirstEnergy are based, in part, on an alleged failure to protect recommendations and collectively enhance the reliability of its the citizens of Jersey City from an electrical power outage.

electric system. FirstEnergy's implementation of these recom- No FirstEnergy entity serves any customers in Jersey City.

mendations in 2004 included completion of the Task Force A responsive pleading has been filed. No estimate of potential FirstEnergy Corp. 2005 77

liability has been undertaken in either of these matters. standard NRC reactor oversight process. At that time, NRC FirstEnergy is vigorously defending these actions, but inspections were augmented to include inspections to support cannot predict the outcome of any of these proceedings or the NRC's Confirmatory Order dated March 8, 2004 that was whether any further regulatory proceedings or legal actions issued at the time of startup and to address an NRC White may be initiated against the Companies. Although unable to Finding related to the performance of the emergency sirens.

predict the impact of these proceedings, if FirstEnergy or its By letter dated December 8, 2005, the NRC advised FENOC subsidiaries were ultimately determined to have legal liability that the White Finding had been closed.

in connection with these proceedings, it could have a material On August 12, 2004, the NRC notified FENOC that it adverse effect on FirstEnergy's or its subsidiaries' financial would increase its regulatory oversight of the Perry Nuclear condition, results of operations and cash flows. Power Plant as a result of problems with safety system equip-ment over the preceding two years and the licensee's failure to Nuclear PlantMatters take prompt and corrective action. FENOC operates the Perry On May 11, 2005, FENOC received a subpoena for docu- Nuclear Power Plant ments related to outside meetings attended by Davis-Besse On April 4, 2005, the NRC held a public meeting to dis-personnel on corrosion and cracking of control rod drive cuss FENOC's performance at the Perry Nuclear Power Plant mechanisms and additional root cause evaluations. On as identified in the NRC's annual assessment letter to January 20, 2006, FENOC announced that it has entered into FENOC. Similar public meetings are held with all nuclear a deferred prosecution agreement with the U.S. Attorney's power plant licensees following issuance by the NRC of their Office for the Northern District of Ohio and the annual assessments. According to the NRC, overall the Perry Environmental Crimes Section of the Environment and Plant operated "in a manner that preserved public health and Natural Resources Division of the DOJ related to FENOC's safety" even though it remained under heightened NRC over-communications with the NRC during the fall of 2001 in con- sight During the public meeting and in the annual nection with the reactor head issue at the Davis-Besse Nuclear assessment, the NRC indicated that additional inspections will Power Station. Under the agreement, which expires on continue and that the plant must improve performance to be December 31, 2006, the United States acknowledged FENOC's removed from the Multiple/Repetitive Degraded Cornerstone extensive corrective actions at Davis-Besse, FENOC's coopera- Column of the Action Matrix. By an inspection report dated tion during investigations by the DOJ and the NRC, FENOC's January 18, 2006, the NRC closed one of the White Findings pledge of continued cooperation in any related criminal and (related to emergency preparedness) which led to the multiple administrative investigations and proceedings, FENOC's degraded cornerstones.

acknowledgement of responsibility for the behavior of its On May 26, 2005, the NRC held a public meeting to dis-employees, and its agreement to pay a monetary penalty. The cuss its oversight of the Perry Plant. While the NRC stated DOJ will refrain from seeking an indictment or otherwise ini- that the plant continued to operate safely, the NRC also stated tiating criminal prosecution of FENOC for all conduct related that the overall performance had not substantially improved to the statement of facts attached to the deferred prosecution since the heightened inspection was initiated. The NRC reiter-agreement, as long as FENOC remains in compliance with the ated this conclusion in its mid-year assessment letter dated agreement, which FENOC fully intends to do. FENOC has August 30, 2005. On September 28, 2005, the NRC sent a agreed to pay a penalty of $28 million (which is not deductible CAL to FENOC describing commitments that FENOC had for income tax purposes) which reduced FirstEnergy's earn- made to improve the performance of Perry and stated that the ings by $0.09 per common share in the fourth quarter of CAL would remain open until substantial improvement was 2005. As part of the deferred prosecution agreement entered demonstrated. The CAL was anticipated as part of the NRC's into with the DOJ, $4.35 million of that amount will be direct- Reactor Oversight Process. If performance does not improve, ed to community service projects. the NRC has a range of options under the Reactor Oversight On April 21, 2005, the NRC issued a NOV and proposed Process, from increased oversight to possible impact to the a $5 million civil penalty related to the degradation of the plant's operating authority. Although unable to predict a Davis-Besse reactor vessel head issue described above. We potential impact, its ultimate disposition could have a material accrued $2 million for a potential fine prior to 2005 and adverse effect on FirstEnergy's or its subsidiaries' financial accrued the remaining liability for the proposed fine during condition, results of operations and cash flows.

the first quarter of 2005. On September 14, 2005, FENOC As of December 16, 2005 NGC acquired ownership of the filed its response to the NOV with the NRC. FENOC accepted nuclear generation assets transferred from OE, CEI, TE and full responsibility for the past failure to properly implement Penn with the exception of leasehold interests of OE and TE its boric acid corrosion control and corrective action pro- in certain of the nuclear plants that are subject to sale and grams. The NRC NOV indicated that the violations do not leaseback arrangements with non-affiliates.

represent current licensee performance. We paid the penalty in the third quarter of 2005. On January 23, 2006, FENOC Other Legal Matters supplemented its response to the NRC's NOV on the Davis- There are various lawsuits, claims (including claims for Besse head degradation to reflect the deferred prosecution asbestos exposure) and proceedings related to FirstEnergy's agreement that FENOC had reached with the DOJ. normal business operations pending against FirstEnergy and Effective July 1, 2005, the NRC oversight panel for Davis- its subsidiaries. The other potentially material items not Besse was terminated and Davis-Besse returned to the otherwise discussed above are described below.

78 FirstEnergy Corp. 2005

On October 20, 2004, FirstEnergy was notified by the to liability based on the above matters, it could have a material SEC that the previously disclosed informal inquiry initiated adverse effect on FirstEnergy's or its subsidiaries' financial by the SEC's Division of Enforcement in September 2003 condition, results of operations and cash flows.

relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject 15. FIRSTENERGY INTRA-SYSTEM GENERATION of a formal order of investigation. The SEC's formal order of ASSET TRANSFERS investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under On May 13, 2005, Penn, and on May 18, 2005, the Ohio PUHCA. Concurrent with this notification, FirstEnergy Companies entered into certain agreements implementing a received a subpoena asking for background documents and series of intra-system generation asset transfers that were documents related to the restatements and Davis-Besse issues. completed in the fourth quarter of 2005. The asset transfers On December 30, 2004, FirstEnergy received a subpoena ask- resulted in the respective undivided ownership interests of the ing for documents relating to issues raised during the SEC's Ohio Companies and Penn in FirstEnergy's nuclear and non-PUHCA examination. On August 24, 2005 additional informa- nuclear generation assets being owned by NGC and FGCO, tion was requested regarding Davis-Besse. FirstEnergy has respectively. The generating plant interests transferred do not cooperated fully with the informal inquiry and continues to include leasehold interests of CEI, TE and OE in certain of do so with the formal investigation. the plants that are currently subject to sale and leaseback On August 22, 2005, a class action complaint was filed arrangements with non-affiliates.

against OE in Jefferson County, Ohio Common Pleas Court, On October 24, 2005, the Ohio Companies and Penn seeking compensatory and punitive damages to be determined completed the intra-system transfer of non-nuclear generation at trial based on claims of negligence and eight other tort assets to FGCO. Prior to the transfer, FGCO, as lessee under a counts alleging damages from W.H. Sammis Plant air emis- Master Facility Lease with the Ohio Companies and Penn, sions. The two named plaintiffs are also seeking injunctive leased, operated and maintained the non-nuclear generation relief to eliminate harmful emissions and repair property assets that it now owns. The asset transfers were consummat-damage and the institution of a medical monitoring program ed pursuant to FGCO's purchase option under the Master for class members. Facility Lease.

JCP&I's bargaining unit employees filed a grievance On December 16, 2005, the Ohio Companies and Penn challenging JCP&L's 2002 call-out procedure that required completed the intra-system transfer of their respective owner-bargaining unit employees to respond to emergency power ship in the nuclear generation assets to NGC through, in the outages. On May 20, 2004, an arbitration panel concluded case of OE and Penn, an asset spin-off by way of dividend that the call-out procedure violated the parties' collective and, in the case of CEI and TE, a sale at net book value.

bargaining agreement. At the conclusion of the June 1, 2005 FENOC continues to operate and maintain the nuclear hearing, the Arbitrator decided not to hear testimony on generation assets.

damages and closed the proceedings. On September 9, 2005, These transactions were pursuant to the Ohio the Arbitrator issued an opinion to award approximately $16 Companies' and Penn's restructuring plans that were million to the bargaining unit employees. On February 6, approved by the PUCO and the PPUC, respectively, under 2006, the federal court granted a Union motion to dismiss applicable Ohio and Pennsylvania electric utility restructuring JCP&L's appeal of the award as premature. JCP&L will file legislation. Consistent with the restructuring plans, generation its appeal again in federal district court once the damages assets that had been owned by the Ohio Companies and Penn associated with this case are identified at an individual were required to be separated from the regulated delivery employee level. JCP&L recognized a liability for the potential business of those companies through transfer to a separate

$16 million award in 2005. corporate entity. The transactions essentially completed the The City of Huron filed a complaint against OE with the divestitures contemplated by the restructuring plans by PUCO challenging the ability of electric distribution utilities transferring the ownership interests to NGC and FGCO to collect transition charges from a customer of a newly- without impacting the operation of the plants.

formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for 16. SEGMENT INFORMATION approval with the PUCO of a tariff that would specifically allow the collection of transition charges from customers of FirstEnergy has two reportable segments: regulated serv-municipal electric utilities formed after 1998. An adverse rul- ices and power supply management services. The aggregate ing could negatively affect full recovery of transition charges "Other" segments do not individually meet the criteria to be by the utility. Hearings on the matter were held in August considered a reportable segment. FirstEnergy's primary seg-2005. Initial briefs from all parties were filed on September ment is its regulated services segment, whose operations 22, 2005 and reply briefs were filed on October 14, 2005. include the regulated sale of electricity and distribution and It is unknown when the PUCO will decide this case. transmission services by its eight utility subsidiaries in Ohio, If it were ultimately determined that FirstEnergy or its Pennsylvania and New Jersey. The power supply management subsidiaries have legal liability or are otherwise made subject services segment primarily consists of the subsidiaries (FES, FirstEnergy Corp. 2005 79

FGCO, NGC and FENOC) that sell electricity in deregulated Segment Financial Information markets and operate and now own the generation facilities of OE, CEI, TE and Penn resulting from the deregulation of the Regulated MMaragem Fadiits Rbondli Sotks Sales Servie Oter Apsten* Consoidate Companies' electric generation business. "Other" consists of MYR (a construction service company), retail natural gas (Anmilkons) 2005 operations (recer ly sold - see Note 8) and telecommunica- External revenues $5,483 $5,739 $212 $533 $22 $11,989 Internal revenues 270 - - - (270) -

tions services. T assets and revenues for the other business Total revenues 5,753 5,739 212 533 (248) 11,989 operations are below the quantifiable threshold for operating Depreciation and amortization 1,392 45 - 2 26 1,465 segments for separate disclosure as "reportable segments." Investment income 218 - - - - 218 Net interest charges 390 54 1 6 206 657 The regulated services segment designs, constructs, oper- Income taxes 763 36 3 13 (61) 754 ates and maintains FirstEnergy's regulated transmission and Income before discontinued operations and distribution systems. Its revenues are primarily derived from cumulative effect of electricity delivery and transition cost recovery. Assets of the accounting change 1,067 23 (8) 17 (226) 873 Discontinued operations 13 5 - 18 regulated services segment as of December 31, 2004 included Cumulative effect of accounting change (21) (9) - - - (30) generating units that were leased or whose output had been Net income 1,046 14 5 22 (226) 861 sold to the power supply management services segment (see Total assets 23,975 6,556 69 536 705 31,841 Total goodwill 5,932 24 - 54 - 6,010 Note 15). The regulated services segment's internal revenues Property additions 788 375 2 6 36 1,207 represented the rental revenues for the generating unit leases 2004 which ceased in the fourth quarter of 2005 as a result of the External revenues $5,191 $6,204 $217 $444 $ 4 $12,060 Internal revenues 318 - - - (318) -

intra-system asset transfers (see Note 15). Total revenues 5,509 6,204 217 444 (314) 12,060 The power supply management services segment supplies Depreciation and amortization 1,422 35 2 3 34 1,496 all of the electric power needs of FirstEnergy's end-use cus- Investment income 205 - - - - 205 tomers through retail and wholesale arrangements, including Net interest charges 363 37 1 14 252 667 Income taxes 740 72 (8) (24) (107) 673 regulated retail sales to meet the PLR requirements of our Income before discontinued operations 1,015 104 (13) 40 (250) 896 Ohio and Pennsylvania companies and competitive retail sales Discontinued operations - - (23) 5 - (18) to commercial and industrial businesses primarily in Ohio, Net income 1,015 104 (36) 45 (250) 878 Total assets 28,308 1,488 135 625 479 31,035 Pennsylvania and Michigan. This business segment owns and Total goodwill 5,951 24 - 75 - 6,050 operates our generating facilities and purchases electricity Property additions 572 246 3 4 21 846 from the wholesale market to meet our sales obligations (See 2003 External revenues $5,068 $5,487 $179 $547 $44 $11,325 Note 15.) The segment's net income is primarily derived from Internal revenues 319 - - - (319) -

all electric generation sales revenues less the related costs of Total revenues 5,387 5,487 179 547 (275) 11,325 Depreciation and electricity generation, including purchased power, and net amortization 1,423 29 - 2 35 1,489 1 Investment income 185 - - - - 185 transmission, congestion and ancillary costs charged by PJM Net interest charges 493 44 1 107 164 809 and MISO to deliver energy to retail customers. Income taxes 779 (222) (34) (19) (96) 408 Income before discontinued Segment reporting for interim periods in 2004 and 2003 operations and have been reclassified to conform to the current year business cumulative effect of accounting change 1,063 (320) (55) (64) (180) 444 segment organization and operations and the reclassification Discontinued operations - - (26) (97) - (123) of discontinued operations (see Note 20)). FSG is being dis- Cumulative effect of accounting change 101 - - 1 - 102 closed as a reporting segment due to its subsidiaries qualifying Net income 1,164 (320) (81) (160) (180) 423 Total assets 29,789 1,423 166 912 620 32,910 as held for sale (see Note 2(j) for discussion of the divestiture Total goodwill 5,993 24 36 75 - 6,128 of three of those subsidiaries in 2005). Interest expense on Property additions 434 335 4 9 74 856 holding company debt and corporate support services rev-enues and expenses are included in "Reconciling Items."

80 FirstEnergy Corp. 2005

Reconciling adjustments to segment operating results from EEITF Issue 04-13, 'Accounting for Purchases and internal management reporting to consolidated external finan- Sales of Inventory with the Same Counterparty' cial reporting primarily consist of interest expense related to In September 2005, the EITF reached a final consensus holding company debt, corporate support services revenues on Issue 04-13 concluding that two or more legally separate and expenses, fuel marketing revenues, which are reflected as exchange transactions with the same counterparty should be reductions to expenses for internal management reporting pur- combined and considered as a single arrangement for purpos-poses, and elimination of intersegment transactions. es of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions Products and Services* are combined and considered a single arrangement, the EITF Energy Related Year Electridty Sales Sales and Services reached a consensus that an exchange of inventory should be 2005 $10,546 $708 accounted for at fair value. Although electric power is not 2004 10,831 551 capable of being held in inventory, there is no substantive con-L2003 10,205 601 ceptual distinction between exchanges involving power and dSe Note 2(J) for dissionof dicntinuedoperatons other storable inventory. Therefore, FirstEnergy will adopt this EITF effective for new arrangements entered into, or Geographic Information modifications or renewals of existing arrangements, in interim Following the sales of international operations in 2002 or annual periods beginning after March 15, 2006.

through January of 2004, less than 1% of FirstEnergy's rev-enues and assets were in foreign countries in 2003 and 2004. SFAS 154 - 'Accounting Changes and Error Corrections-See Note 8 for a discussion of the divestitures. a replacement of APB Opinion No. 20 and FASB Statement No. 3" In May 2005, the FASB issued SPAS 154 to change the

17. NEW ACCOUNTING STANDARDS AND requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in INTERPRETATIONS accounting principle and to changes required by an account-FSPFAS 115-1 and FAS 124-1, "The Meaning of Other- ing pronouncement when that pronouncement does not Than-Temporary Impairment and its Application to include specific transition provisions. This Statement requires CertainInvestments' retrospective application to prior periods' financial statements Issued in November 2005, FSP 115-1 and FAS 124-1 of changes in accounting principle, unless it is impracticable addresses the determination as to when an investment is con- to determine either the period-specific effects or the cumula-sidered impaired, whether that impairment is other than tive effect of the change. In those instances, this Statement temporary, and the measurement of an impairment loss. The requires that the new accounting principle be applied to the FSP finalized and renamed EITF 03-1 and 03-1-a to FSP FAS balances of assets and liabilities as of the beginning of the ear-115-1. This FSP will (1) nullify certain requirements of Issue liest period for which retrospective application is practicable 03-1 and supersedes EITF topic No. D-44, "Recognition of and that a corresponding adjustment be made to the opening Other Than Temporary Impairment upon the Planned Sale of balance of retained earnings (or other appropriate components a Security Whose Cost Exceeds Fair Value," (2) clarify that an of equity or net assets in the statement of financial position) investor should recognize an impairment loss no later than for that period rather than being reported in the Consolidated when the impairment is deemed other than temporary, even if Statements of Income. This Statement also requires that a a decision to sell has not been made, and (3) be effective for change in depreciation, amortization, or depletion method for other-than-temporary impairment and analyses conducted in long-lived, nonfinancial assets be accounted for as a change in periods beginning after September 15, 2005. The FSP requires accounting estimate affected by a change in accounting princi-prospective application with an effective date for reporting ple. The provisions of this Statement are effective for periods beginning after December 15, 2005. FirstEnergy is cur- accounting changes and corrections of errors made in fiscal rently evaluating this FSP and any impact on its investments. years beginning after December 15, 2005. FirstEnergy and the Companies adopted this Statement effective January 1, 2006.

FSP No. FAS 13-1, 'Accounting for Rental Costs Incurred during the ConstructionPeriod" SFAS 153, "Exchanges of Nonmonetary Assets -

Issued in October 2005, FSP No. FAS 13-1 requires rental an amendment of APB Opinion No. 29" costs associated with ground or building operating leases that In December 2004, the FASB issued SPAS 153 amending are incurred during a construction period to be recognized as APB 29, which was based on the principle that nonmonetary rental expense. The effective date of the FSP guidance is the assets should be measured based on the fair value of the assets first reporting period beginning after December 15, 2005. exchanged. The guidance in APB 29 included certain excep-FirstEnergy will apply this FSP to all construction projects, tions to that principle. SPAS 153 eliminates the exception beginningJanuary 1, 2006. from fair value measurement for nonmonetar exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonnmonetary exchange has com-mercial substance if the future cash flows of the entity are FirstEnergy Corp. 2005 81

expected to change significantly as a result of the exchange.

The provisions of this Statement are effective January 1, 2006

18.

SUMMARY

OF QUARTERLY FINANCIAL DATA (UNAUDITED) for FirstEnergy. This FSP is not expected to have a material impact on FirstEnergy's financial statements.

The following summarizes certain consolidated operating SPAS 123(R), "Share-Based Payyment" results by quarter for 2005 and 2004. Certain financial results In December 2004, the FASB issued SFAS 123(R), a revi- have been reclassified to discontinued operations from sion to SEAS 123, which requires expensing stock options in amounts previously reported due to the divestiture of certain non-core businesses in 2005 as discussed in Note 2(J).

the financial statements. Important to applying the new stan-dard is understanding how to (1) measure the fair value of March 31. June 30, Sept. 30, Dec. 31. !

stock-based compensation awards and (2) recognize the relat- Three Months Ended 2005 2005 2005 2005 1 ed compensation cost for those awards. For an award to ain mion4 eycept per shaoe oamaunt) qualify for equity classification, it must meet certain criteria Revenues $2,750 $2,843 $3,504 $2,892 Expenses 2,358 2,309 2,861 2,395 in SEAS 123(R). An award that does not meet those criteria Other Expense, net 130 114 74 122 IncomeTaxes 121 241 237 155 will be classified as a liability and remeasured each period.

SFAS 123(R) retains SEAS 123's requirements on accounting Income Before Discontinued Operations and Cumulative Effect for income tax effects of stock-based compensation. In April of Accounting Change 141 179 332 220 Discontinued Operations 2005, the SEC delayed the effective date of SFAS 123(R) to (Netof IncomeTaxes) 19 (1) - _

annual, rather than interim, periods that begin after June 15, Cumulative Effect of Accounting Change (Net of Income Taxes) - - - (30) 2005. FirstEnergy adopted this Statement effective January 1, 2006 with modified prospective application. The Company Net Income $ 160 $ 178 $ 332 $ 190 uses the Black-Scholes option-pricing model to value options Basic Earnings Per Share of Common Stock:

for disclosure purposes only and continued to apply this pric- Before Discontinued Operations and Cumulative Effect of ing model with the adoption of SFAS 123(R). As discussed in Accounting Change $ 0.43 $ 0.54 $ 1.01 $ 0.67 Discontinued Operations 0.06 - - -

Note 4, the Company reduced its use of stock options begin- Cumulative Effect of Accounting Change - - - (0.09) ning in 2005, with no stock options being awarded Basic Earnings Per Share of Common Stock $ 0.49 $ 0.54 $ 1.01 $ 0.58 subsequent to 2004. As a result, all currently unvested stock options will vest by 2008. We expect the adoption of SEAS Diluted Earnings Per Share of Common Stock Before Discontinued Operations 123(R) will increase annual compensation expense (after-tax) and Cumulative Effect of by approximately $7 million, $2 million and $0.5 million in Accounting Change $ 0.42 $ 0.54 $ 1.01 $ 0.67 Discontinued Operations 0.06 - - -

2006, 2007 and 2008, respectively or $0.02 per share in 2006 Cumulative Effect of Accounting Change - - - (0.09) and less than $0.01 per share in 2007 and 2008. Diluted Earnings Per Share of Common Stock $ 0.48 $ 0.54 $ 1.01 $ 0.58 SPAS 151, "Inventory Costs - an amendment of ARB No. 43, Chapter 4" In November 2004, the FASB issued SEAS 151 to clarify March 31, June 30, Sept. 30, Dec. 31, the accounting for abnormal amounts of idle facility expense, Three Months Ended 2004 2004 2004 2004 freight, handling costs and wasted material (spoilage). (an mAons, e t per shore amount)

Revenues $2,934 $2,929 $3,365 $2,832 Previous guidance stated that in some circumstances these Expenses 2,524 2,418 2,752 2,335 costs may be "so abnormal" that they would require treatment OtherExpense, net 123 133 102 104 IncomeTaxes 115 176 215 167 as current period costs. SEAS 151 requires abnormal amounts for these items to always be recorded as current period costs. Income Before Discontinued Operations 172 202 296 226 Discontinued Operations In addition, this Statement requires that allocation of fixed (Net of Income Taxes) 2 2 2 (24) production overheads to the cost of conversion be based on Net Income $174 $204 $298 $202 the normal capacity of the production facilities. The provi-Basic Earnings Per Share of Common Stock:

sions of this statement are effective for inventory costs Before Discontinued Operations 0.53 0.61 0.90 0.69 incurred by FirstEnergy beginning January 1, 2006. Discontinued Operations - 0.01 0.01 (0.08)

FirstEnergy does not expect this Statement to have a material Basic Earnings Per Share of Common Stock $ 0.53 $ 0.62 $ 0.91 $ 0.61 impact on its financial statements. Diluted Earnings Per Share of Common Stock:

Before Discontinued Operations 0.53 0.61 0.90 0.69 Discontinued Operations - 0.01 0.01 (0.08)

Diluted Earnings Per Share of Common Stock $ 0.53 $ 0.62 $ 0.91 $ 0.61 82 FirstEnergy Corp. 2005

Results for the fourth quarter of 2005 included a $30 million, net of tax, or $0.09 per share, cumulative effect adjustment associated with the adoption of FIN 47 (see Note 12), a $9 million (with no corresponding tax impact) or

$0.03 per share, non-cash charge for impairment of goodwill of MYR as required by SFAS 142 (see Note 2(H)) and a $28 million (which is not deductible for income tax purposes),

or $0.09 per share, charge related to the Davis-Besse DOJ and NRC fines (see Note 14). Net income for the fourth quarter also included a $15 million, net of tax, or $0.05 per share, charge relating to prior periods as a result of a JCP&L tax audit adjustment which was applicable to prior quarters in 2005 and prior years. Management concluded that the adjust-ment was not material to FirstEnergy's reported consolidated results of operations for any quarter of 2004 or 2005, nor was it material to the consolidated balance sheets and consolidated cash flows for any of these quarters.

Results for the fourth quarter of 2004 included a $37 million net-of-tax, or $0.11 per share, non-cash charge for impairment of goodwill and other assets of FSG as required by SFAS 142 and SFAS 144 (see Note 2 (H)).

FirstEnergy Corp. 2005 83

Consolidated Financial and Pro Forma Combined Operating Statistics (Unaudited) 2005 2004 2003 2002 2001 2000 1995 GENERAL FINANCIAL INFORMATION (Dollars in millions)

Revenues $11,989 $12,060 $11,325 $11,169 $ 6,924 $ 6,308 $2,501 Net Income $861 $878 $423 $553 $646 $599 $295 SEC Ratio of Earnings to Fixed Charges 2.73 2.62 1.75 1.88 2.22 2.10 2.32 Capital Expenditures $1,144 $731 $792 $904 $888 $569 $196 Total Capitalization(a) $17,527 $18,938 $18,414 $18,686 $21,339 $11,205 $5,566 Capitalization Ratios(a):

Common Stockholders' Equity 52.4w 45.3% 45.0% 37.7% 34.7% 41.5% 43.3%

Preferred and Preference Stock:

Not Subject to Mandatory Redemption 1.1 1.8 1.8 1.8 2.2 5.8 3.8 Subject to Mandatory Redemption - - - 2.3 2.8 1.4 2.9 Long-Term Debt 46.5 52.9 53.2 58.2 60.3 51.3 50.0 Total Capitalization 100.0% 100.0% 100.00% 100.00% 100.00% 100.00w 100.00%

Average Capital Costs:

Preferred and Preference Stock 5.67% 6.51% 6.47% 7.50% 7.90% 7.92% 7.59%

Long-Term Debt 6.05% 5.93% 6.08% 6.56% 6.98% 7.84% 8.00%

COMMON STOCK DATA Earnings per Share(b):

Basic $ 2.66 $ 2.74 $ 1.46 $ 2.09 $ 2.82 $ 2.69 $ 2.05 Diluted $ 2.65 $ 2.73 $ 1.46 $ 2.08 $ 2.81 $ 2.69 $ 2.05 Return on Average Common Equity(b) 10.0% 10.6% 5.9% 8.2% 12.9% 13.0% 12.5%

Dividends Paid per Share $ 1.67 $ 1.50 $ 1.50 $ 1.50 $ 1.50 $ 1.50 $ 1.50 D Aidend Payout Ratio (b) 63% 55% 103% 72% 53% 56% 73%

Dividend Yield 3.4% 3.89 4.3% 4.5% 4.3% 4.8% 6.4%

Price/Earnings Ratio b) 18.4 14.4 24.1 15.8 12.4 11.7 11.5 Book Value per Share $ 27.98 $ 26.20 $ 25.35 $ 24.01 $ 25.29 $ 21.29 $16.73 Market Price per Share $ 48.99 $ 39.51 $ 35.20 $ 32.97 $ 34.98 $ 31.56 $23.50 Ratio of Market Price to Book Value 175% 151% 139% 137% 138% 148% 140%

OPERATING STATISTICS(c)

Generation Kilowatt-Hour Sales (Millions):

Residential 34,716 31,781 31,322 31,937 32,708 32,519 30,575 Commercial 32,878 32,114 32,311 32,892 32,170 33,139 28,389 Industrial 32,907 31,675 32,451 32,726 33,024 31,140 34,663 Other 547 504 554 531 536 522 1,432 Total Retail 101,048 96,074 96,638 98,086 98,438 97,320 95,059 Total Wholesale 28,521 53,268 42,059 30,007 20,240 13,761 14,484 Total Sales 129,569 149,342 138,697 128,093 118,678 111,081 109,543 Customers Served:

Residential 3,941,030. 3,916,855 3,874,052 3,868,499 3,833,013 3,798,716 3,651,383 Commercial 509,933 500,695 496,253 471,440 464,053 472,410 431,206 Industrial 10,637 10,597 10,871 18,416 18,652 18,996 21,130 Other 6,124 5,654 5,635 5,716 5,762 6,001 7,608 Total 4,467,724 4,433,801 4,386,811 4,364,071 4,321,480 4,296,123 4,111,327 Number of Employees 14,586 15,245 15,905 17,560 18,700 18,912 21,919 (20017capitoliation includes approlimate4y $1.4billion of long-term debt (excuding long-term debt due to be repaid within one year) indudedin Liobilities Related to AssetsPending Sake on the Consolidated BalAnce Sheet as of December 31,200.L

• Before discontinued operations in 2005, 2004,2003 and 2002, and accounting changes in 2005, 2003 and 2001.

• Reflects pro forma combined FirstEnergy and GPU statistins i 2000 and 2001 and pro forma combined Ohio Edison, Centenor and GPU statistcs in 1995 84 FirstEnergy Corp. 2005

.41 .6 I *lkA+/- Ok Shareholder Services, Transfer Agent and Registrar Combining Stock Accounts FirstEnergy Securities Transfer Company, a subsidiary of If you have more than one stock account and want to com-FirstEnergy, acts as the transfer agent and registrar for all stock bine them, please write or call Shareholder Services and specify issues of FirstEnergy and its subsidiaries. Shareholders wanting the account that you want to retain as well as the registration of to transfer stock, or who need assistance or information, can each of your accounts.

send their stock or write to Shareholder Services, FirstEnergy Corp., 76 South Main Street, Akron, Ohio 44308-1890. Stock Investment Plan Shareholders also can call the following toll-free telephone Shareholders and others can purchase or sell shares of number, which is valid in the United States, Canada, Puerto Rico FirstEnergy common stock through the Company's Stock and the Virgin Islands, weekdays between 8 a.m. and 4:30 p.m., Investment Plan. Investors who are not registered shareholders can Eastern time: 1-800-736-3402. For Internet access to general enroll with an initial $250 cash investment. Participants may invest shareholder information and useful forms, visit our Web site all or some of their dividends or make optional cash payments at at wwwfirstenergycorp.com/ir. any time of at least $25 per payment up to $100,000 annually.

Contact Shareholder Services to receive an enrollment form.

Stock Listings and Trading Newspapers generally report FirstEnergy common stock Safekeeping of Shares under the abbreviation FSTENGY, but this can vary depending Shareholders can request that the Company hold their upon the newspaper. The common stock of FirstEnergy and shares of FirstEnergy common stock in safekeeping. To take preferred stock of its electric utility subsidiaries are listed on advantage of this service, shareholders should forward their the following stock exchanges: common stock certificate(s) to the Company along with a signed letter requesting that the Company hold the shares. Shareholders Company Stock Exchange Symbol also should state whether future dividends for the held shares are to be reinvested or paid in cash. The certificate(s) should FirstEnergy New York FE not be endorsed, and registered mail is suggested. The shares Jersey Central New York JYP will be held in uncertificated form, and we will make Ohio Edison New York OEC certificate(s) available to shareholders upon request at no cost.

Pennsylvania Power OTC PPC Shares held in safekeeping will be reported on dividend checks Toledo Edison New York, OTC TED or Stock Investment Plan statements.

American Form 10-K Annual Report Dividends Form 10-K, the Annual Report to the Securities and Proposed dates for the payment of FirstEnergy common Exchange Commission, will be sent without charge upon written stock dividends in 2006 are: request to David W. Whitehead, Corporate Secretary, FirstEnergy Corp., 76 South Main Street, Akron, Ohio 44308-1890.

Ex-Dividend Date Record Date Payment Date Institutional Investor and Security Analyst Inquiries February 3 February 7 March 1 Institutional investors and security analysts should direct May 3 May 5 June 1 inquiries to: Kurt E. Turosky, Director, Investor Relations, August 3 August 7 September 1 330-384-5500.

November 3 November 7 December 1 Annual Meeting of Shareholders Shareholders are invited to attend the 2006 Annual Meeting All dividends are subject to declaration by the Board of of Shareholders on Tuesday, May 16, at 10:30 a.m. Eastern time, Directors at its discretion.

at the John S. Knight Center, 77 East Mill Street, in Akron, Ohio.

Registered shareholders not attending the meeting can appoint Direct Dividend Deposit a proxy and vote on the items of business by telephone, Internet Shareholders can have their dividend payments automatically or by completing and returning the proxy card that is sent to deposited to checking and savings accounts at any financial them. Shareholders whose shares are held in the name of a institution that accepts electronic direct deposits. Use of this free broker can attend the meeting if they present a letter from service ensures that payments will be available to you on the pay-their broker indicating ownership of FirstEnergy common ment date, eliminating the possibility of mail delay or lost checks.

stock on the record date of March 21, 2006.

Contact Shareholder Services to receive an authorization form.

FirstEnergy has included as Exhibit 31 to its Annual Report on Form 10-K for fiscal year 2005 filed with the Securities and Exchange Commission certificates of FirstEnergy's Chief Executive Officer and Chief Financial Officer certifying the quality of the Company's public disclosure. FirstEnergy's Chief Executive Officer has also submitted to the New York Stock Exchange (NYSE) a certificate certifying that he was not aware of any violation by FirstEnergy of the NYSE corporate governance listing standards as of the date of the certification.

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FirstEnergy 76 South Main Street, Akron, OH 44308-1890 www. firstenergycorp. corn PRESORTED STD.

U.S. POSTAGE PAID AKRON, OHIO PERMIT NO. 561 2005 Annual Report