ML051450526

Firstenergy 2004 Annual Report, Building on Our Progress

ML051450526
Person / Time
Site:	Beaver Valley, Perry
Issue date:	03/18/2005
From:	Alexander A FirstEnergy Nuclear Operating Co
To:	Office of Nuclear Reactor Regulation
References
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Download: ML051450526 (135)

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Financial Highlights (Dollars in thousands, except per share amounts) 2004 2003 Total revenues S12.453,046

$11,674,888 Income before discontinued operations and cumulative effect of accounting change' S873,779

$424,249 Net income S878,175

$422,764 Basic earnings per common share:

Before discontinued operations and cumulative effect of accounting change

$2.67

$1.40 After discontinued operations and cumulative effect of accounting change S2.68

$1.39 Diluted earnings per common share:

Before discontinued operations and cumulative effect of accounting change S2.66

$1.40 After discontinued operations and cumulative effect of accounting change S2.67

$1.39 Dividends declared per common share"*

S1.9125

$1.50 Book value per common share S26.20

$25.35 Net cash from operations S1,876,850

$1,754,855 The 2004 and 2003 discontinued operations are described in Note 2(J) to the Consolidated Financial Statements. The 2003 accounting change is described in Note 2(K) to the Consolidated Financial Statements.

A quarterly dividend of $0.4 125 was declared in 2004 payable March 1, 2005. increasing the indicated annual dividend rate from $1.50 to $1.65 per share.

The following analysis reconciles basic earnings per share of common stock in 2004 and 2003 computed under generally accepted accounting principles (GAAP) to adjusted basic earnings per share excluding unusual items in both years (non-GW )*.

2004 2003 Adjusted basic earnings per share:

Basic earnings per share (GAAP)

S2.68

$1.39 Claim settlement (0.33)

Davis-Besse extended outage impacts 0.12 0.56 Rate case disallowance 0.36 Asset impairments 0.19 0.41 Litigation settlement 0.03 Discontinued international operations 0.33 Cumulative effect of accounting change (0.33)

Other unusual items (see Management's Discussion) 0.01 0.03 Adjusted basic earnings per share (non-GAAP)

$3.03

$2.42 Generally, a non-GAAP financial measure is a numerical measure of a company's historical or future financialperformance, financialposition, or cash flows that either excludes or includes amounts that are not normally excluded or included in the most directly comparable measure calculated and presented in accordance with GAAR Forward-Looking Statements This annual report includes forward-ooking 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 in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), the receipt of approval from and entry of a final order by the U.S. District Court, Southem District of Ohio, on the pending settlement agreement resolving the New Source Review litigation and the uncertainty of the timing and amounts of the capital expenditures (including that such amounts could be higher than anticipated) related to this settlement, adverse regulatory or legal decisions and outcomes (including revocation of necessary licenses or operating permits, tines or other enforcement actions and remedies) of government investigations, inchlding by the Securities and Exchange Commission, the United States Attorney's Office and the Nuclear Regulatory Commission as disclosed in our Securities and Exchange Commission filings, generally, and with respect to the Davis-Besse Nuclear Power Station outage in particular, the availability and cost of capital, the continuing availability and operation of generating units, our inability to accomplish or realize anticipated benefits from strategic goals, our ability to improve electric commodity margins and to experience growth in the distribution business, our ability to access the public securities and other capital markets, further investigation into the causes of the August 14, 2003 regional power outage and the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the outage, the final outcome in the proceeding related to FirstEnergy's Application for a Rate Stabilization Plan in Ohio, the risks and other factors discussed from time to time in our Securities and Exchange Commission filings, and other similar factors. We expressly disclaim any current intention to update any forwardlooking statements contained herein as a result of new information, future events, or otherwise.

To Shareholders We also delivered to shareholders a total annualized return - a measure of stock price appreciation plus reinvest-ed dividends - of 16.6 percent in 2004. This brings our five-year annualized total return to 17.1 percent, ranking us 17th among the 64 U.S. investor-owned electric utilities that comprise the Edison Electric Institute's (EEI) index.

Our performance and outlook supported your Board of Directors' action to increase the common stock dividend by 10 percent, the first increase since the Company was created in 1997.

Operational Results To support our ongoing focus on enhancing service reliability, last year we spent $940 million on capital improve-ment projects and operating and maintenance activities in our energy delivery area. In 2005, we expect to spend more than S1 billion, including expenditures on a wide range of system enhancements. Our plans include upgrading and renewing our transmission and distribution facilities, improving relaying and protection to minimize service interruptions, installing remote control and automation to ensure timely restoration when service interruptions occur, and adding new technologies such as advance lightning detection, which enables our system to better protect itself. We are investing in our critical infrastructure with the clear goal of strengthening our reliability and improving customer service.

In another effort to improve service reliability, we modified our existing information technologies to develop a leading-edge capability to track outage history down to the individual customer. Scheduled for full implementation in June 2005, this system can pinpoint locations and causes of prob-lems, enabling us to target our investments in improvements that enhance reliability and customer satisfaction.

W e

made significant progress in 2004.

We positioned ourselves for continued success in the years ahead and placed many of the challenges of the past several years behind us.

Our key accomplishments included:

• Returning the Davis-Besse Nuclear Power Station to safe and reliable operation

• Enhancing the reliability of our service to customers

• Achieving record performance by our generation fleet

• Gaining approval for our Rate Stabilization Plan in Ohio Our financial performance in 2004 was strong, particularly in the key areas of earnings, cash flow and debt reduction. We delivered basic earnings per share of

$2.91 on a non-GAAP* basis, exceeding our guidance to the financial community of $2.70 to $2.85. Net cash from operating activities also remained strong at $1.88 billion -

up from $1.75 billion in 2003 - and we met our target to reduce debt by $1 billion.

2

Our storm restoration process proved its effectiveness in response to a major storm event in May of 2004, as well as during two ice storms this past winter. All three events caused interruptions to hundreds of thousands of customers.

Despite severe damage to our system, we restored service to all customers faster than at any time in our history, with 80 percent back in service within the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

In addition to the storm process work at home, some 400 volunteer employees traveled to Florida and Alabama to assist in restoring service in the aftermath of the multi-ple hurricanes that ravaged those areas in 2004. Along with the hundreds of letters of thanks we received from grateful residents, we are proud that the hard work and dedication of our employees were further recognized by EEI, which named FirstEnergy a recipient of the EEI Emergency Assistance Award.

"Our financial performance in 2004 was strong, particularly in the key areas of earnings, cash flow and debt reduction."

18 billion KWH, topping its previous record by more than 2 billion KWH. Its 88.9 percent capacity factor - the actual amount of electricity generated compared with the amount that could be generated at full power for the year - placed its performance in the industry's top decile. In the fall of 2005, we expect to initiate the plant's first capacity expan-sion program with a planned upgrade of Unit 1's turbine, which should increase its output by about 50 MW. Similar upgrades are planned for units 2 and 3 in coming years, which would enable the plant to produce an additional 1 billion KWH annually.

Turning to our nuclear fleet, we completed a major reor-ganization of our FirstEnergy Nuclear Operating Company (FENOC) subsidiary that added experienced nuclear man-agers and centralized managerial oversight of our nuclear units; established a uniform organizational structure within the plants; and began implementing common procedures and practices across the fleet. The capacity factor of our nuclear fleet reached 90.6 percent, a historic high, even with Davis-Besse's return to service in March. Beaver Valley earned a Performance Improvement Award from the Institute of Nuclear Power Operations, and its Unit 2 has operated for more than 500 consecutive days, establishing a plant record for continuous operation. More important, the fleet posted a record low U.S. Occupational Safety and Health Administration (OSHA) Reportable Incident Rate, led by the Perry Plant, where employees have worked 8.9 million hours without a lost-time accident.

In 2004 and early 2005, we also reached multi-year labor agreements with 8 union locals representing more than 3,250 workers. Employees represented by these unions have joined our new health care plan, providing them with competitive benefits while enabling the Company to better manage the increasing costs of health care.

Another highlight of 2004 was the performance of our generation fleet, which produced a record 76 billion kilowatt-hours (KWH). The fossil generation fleet provided solid performance, producing more than 45 billion KWH, while our nuclear fleet produced a record 29.9 billion KWH.

Our largest coalbased generating facility, the 2,360-megawatt (MW) Bruce Mansfield Plant, led the way for our fossil fleet. The plant set a generation record of more than 3

We accomplished these solid results while maintaining our focus on safety. In 2004, we achieved a Company-wide OSHA rate of 1.44 incidents per 100 employees, a 9-percent reduction compared with 2003 results. This performance typically would rank us in the top decile of our industry, although EEI has not yet published results for 2004.

We expect to continue enhancing our operational performance under the leadership of our Executive Vice President and Chief Operating Officer, Richard R. Grigg, who joined the Company in August. With 34 years of industry experience, most recently as president and chief executive officer of WE Generation, Mr. Grigg leads our Energy Delivery, Fossil Generation and Commodity Operations business units.

Protecting the Environment We also delivered strong results in our efforts to protect the environment. Last year, 40 percent of our electricity was produced from our nonemitting nuclear fleet. We also achieved continuing emission reductions from our coal-based plants.

Since 1990, we've reduced nitrogen oxides (NOx) by more than 60 percent and sulfur dioxide (SO2) by nearly one-half.

In the past three years, we've spent $196 million to install selective catalytic reduction equipment on all three units of our scrubber-equipped Bruce Mansfield Plant. This equipment is designed to reduce NOx emissions, a precursor to ozone, by more than 8,000 tons during the summer ozone season.

And, in March of this year, we announced plans to significantly reduce emissions of NOx and S02 from current levels at several of our power plants as part of a settlement agreement that resolves all issues related to the New Source Review case involving our W. H. Sammis Plant. Under the "Last year, 40 percent of our electricity was produced from our non-emitting nuclear fleet."

agreement, we will install additional environmental controls at Sammis, as well as at a number of our other power plants.

For example, in the fall of 2005, we will begin a three-year project to improve the existing scrubbers at the Mansfield Plant as part of our plans to further reduce S02 emissions.

The new environmental controls also will provide the foundation for achieving the emission reductions we will be making to comply with the U.S. Environmental Protection Agency's recently announced Clean Air Interstate and Clean Air Mercury rules.

We're working on the development of cost-effective, new technologies to help achieve these additional reductions. One promising new technology is the Electro-Catalytic Oxidation' T (ECO) system developed by Powerspan Corp. and currently being demonstrated at our R. E. Burger Plant. This technology is designed to reduce NOx, SO2, fine particulates and mercury emissions, and, if successful, will be available for commercial application at coalbased power plants across the country.

Setting the Stage for the Future As a result of our successful efforts to reduce debt, control costs and enhance cash flow, your Board declared a new quarterly dividend of 41.25 cents per share of out-standing common stock, which represents a 10-percent increase over the previous quarterly rate. The new indicated annual dividend is $1.65 per share, up from $1.50 per share.

Your Board also adopted a dividend policy that targets sustainable annual dividend increases after 2005, generally reflecting an annual growth rate of 4 to 5 percent, and an earnings payout ratio generally within the range of 50 to 60 percent. The Board will continue to review FirstEnergy's dividend policy regularly. The amount and timing of all dividend payments are subject to the Board's consideration of business conditions, results of operations, financial condition and other factors.

We also enhanced the value of your investment by retiring, refinancing or restructuring more than $2.8 billion in long-term debt last year, which reduced interest costs by approximately $54 million in 2004.

4

"We expect' to fill approximatelY 1,6O0 positions system-wide in the next two years..."

The $1 billion in debt we eliminated brings the total to

$3 billion since 2002, reducing our adjusted debt-to-capital ization ratio to 57 percent from 65 percent three years ago. At the same time, we were able to resolve funding issues related to our pension program for the next several years by making a $500-million contribution to the plan in September. Even so, the total capacity of our primary credit facilities stood at $2.3 billion at year-end.

Another significant accomplishment in 2004 - for our customers and for your Company - was gaining approval by the Public Utilities Commission of Ohio (PUCO) of our Rate Stabilization Plan. The plan will provide a longer period of predictable revenue from our three Ohio electric utility operating companies. In addition, it will provide customers with more stable generation prices for three years following the end of Ohio's market development period on December 31, 2005, under the state's electricity deregulation law. An independent auction conducted last fall at the direction of the PUCO confirmed that the price we offered under the plan was competitive.

We addressed another key challenge last year with an agreement that resolves all pending private securities and derivative lawsuits related to the extended outage at Davis-Besse; the August 14, 2003, regional power outage; and financial restatements related to changed accounting treat-ments for transition assets being recovered in Ohio. Four customer damage cases related to the regional power outage remain in various venues in Ohio and New York.

Preparing for Our Workforce of the Future We're also addressing a significant issue facing compa-nies throughout the U.S. - the need to replace experienced employees who will retire over the next several years. We expect to fill approximately 1,600 positions system-wide in the next two years alone - some through promotions and reassignments, but primarily through aggressive efforts to recruit talented and highly motivated people from outside our Company who will help ensure our future success.

The hiring will occur across the Company, including generating plant and utility workers, as well as an array of technical and professional positions.

Our business requires considerable skills and continu-ous attention to safety by our employees. We will work to ensure that new employees receive on-the-job training, as well as ongoing mentoring from the experienced and knowl-edgeable employees we're fortunate to have on staff now.

Building on Our Progress Executing our plan was critical to our progress in 2004, and will serve as a solid foundation for future growth.

Certainly, challenges remain. However, I'm confident that, through the hard work of our skilled and dedicated employees and your continued support, we will build on that progress and enhance the long-term value of your investment.

Sincerely, 7

7 Anthony J. Alexander President and Chief Executive Officer March 18, 2005

• This letter to shareholders contains nono AP earnings per share. This non-GAP measure excludes amounts that are not normaliy excluded in the most directly com-parable measure calculated and presented in accordance with accounting principles generally accepted in the United States (GAAP). A reconciliation of GAAP basic earnings per share (52.68 in 2004) to non-GAP basic earnings per share ($3.03 in 2004, before the reduction of 50.12 per share for DavisBesse impacts) can be found in the accompanying Managements Discussion and Analysis of Results of Operations and Financial Condition on page 13.

5

FirstEnergy Board of Directors--

Dear Shareholders:

O n

behalf of your Board of Directors, I would like'to take this opportunity to thank our management team and all employ-ees for a year of significant progress and achievement..

During the year, your Board also took a number of steps to enhance our responsiveness to the shareholders we are privileged to serve.

For example, we reviewed and strengthened our overall corporate governance practices - taking steps that included updat-ing charters and policies, separating the functions of chairman and CEO, and eliminating staggered terms so that all directors will be elected annually when their current terms expire.

We also elected to eliminate the Shareholder Rights Plan -'a move that a majority of our shareholders supported - and we agreed to put any future plan to a shareholder vote within one year of adoption.

These and other actions have helped make your Company a.

leader in an important corporate governance measurement deve-'

oped by Institutional Shareholder Services (ISS) - the Corporate Governance Quotient (CGQ). At year-end, our CGQ index ranking was 96.9, reflecting the percentage of companies in the S&P 500 Index we outperformed. Our industry ranking of 95.7 reflected our per-formance against companies in ISS's utility group.

In addition, we were pleased to raise your Company's common-stock dividend - the first increase since FirstEnergy was formed in 1997. And, we adopted a policy that should provide for dividend growth in the future.

On a more personal note, I join the Board in expressing our appreciation to recently retired Director John M. Pietruski for his many years of service to GPU, Inc., and FirstEnergy. Also, we welcome Ernest J. Novak, Jr., who was elected to the Board in May,' and Wesley M. Taylor, who was elected in September.' Mr. Novak, retired managing partner of the Cleveland office of Ernst '& Young LLP, is serving as your Board's designated financial expert. -

We are confident that these and other changes represent the best interests of our shareholders, and we appreciate your continued support as we consider new ways to enhance the value of your investment in FirstEnergy.

Anthony J. Aexander Paul I Addison Paul J. Powers Catherine A. Rein Paul T. Addison, 58 Retired, formerly Managing Director in the Utilities Department of Salomon Smith Barney (Citigroup). Member, Audit and Finance Committees. Director of FirstEnergy Corp. since 2003.

Anthony J. Alexander, 53 President and Chief Executive Officer of FirstEnergy Corp. Director of FirstEnergy Corp. since 2002.

Dr. Carol A. Cartwright, 63 President, Kent State University.

Chair, Corporate Governance Committee; Member, Compensation Committee.

Director of FirstEnergy Corp. since 1997 and of Ohio Edison from 1992-1997.

William T. Cottle, 59 Retired, formerly Chairman of the Board, President and Chief Executive Officer of STP Nuclear Operating Company. Chair, Nuclear Committee; Member, Corporate Governance Committee. Director of FirstEnergy Corp.

since 2003.

Sincerely, George M. Smart Chairman of the Board

Dr. Carol A. Cartwright William T. Cottle Russell W. Maier Ernest J. Novak, Jr.

Robert N. Pokletwaldt Robert C. Savage George M. Smart Wesley M. Taylor Jesse I Williams, Sr.

Dr. Patricia K. Woolf Russell W. Maier, 68 President and Chief Executive Officer of Michigan Seamless Tube LLC.

Member, Compensation and Nuclear Committees. Director of FirstEnergy Corp. since 1997 and of Ohio Edison from 1995-1997.

Ernest J. Novak, Jr., 60 Retired, formerly Managing Partner of the Cleveland office of Ernst & Young LLP. Member, Audit and Finance Committees. Director of FirstEnergy Corp. since 2004.

Robert N. Pokelwaldt, 68 Retired, formerly Chairman of the Board and Chief Executive Officer of YORK International Corporation.

Member, Audit and Finance Committees. Director of FirstEnergy Corp. since 2001 and of the former GPU, Inc., from 2000.2001.

Paul J. Powers, 70 Retired, formerly Chairman of the Board and Chief Executive Officer of Commercial Intertech Corp. Chair, Finance Committee; Member, Compensation Committee. Director of FirstEnergy Corp. since 1997 and of Ohio Edison from 1992-1997.

Catherine A. Rein, 62 Senior Executive Vice President and Chief Administrative Officer of Metropolitan Life Insurance Company.

Chair, Compensation Committee; Member, Audit Committee. Director of FirstEnergy Corp. since 2001 and of the former GPU, Inc., from 1989-2001.

Robert C. Savage, 67 Chairman of the Board of Savage

& Associates, Inc. Member, Finance and Nuclear Committees. Director of FirstEnergy Corp. since 1997 and of the former Centerior Energy Corporation from 1990-1997.

George M. Smart, 59 Non-executive Chairman of the FirstEnergy Board of Directors.

Retired, formerly President of Sonoco-Phoenix, Inc. Chair, Audit Committee. Director of FirstEnergy Corp. since 1997 and of Ohio Edison from 1988-1997.

Wesley M. Taylor, 62 Retired, formerly President of TXU Generation. Member, Nuclear Committee. Director of FirstEnergy Corp. since 2004.

Jesse T. Williams, Sr., 65 Retired, formerly Vice President of Human Resources Policy, Employment Practices and Systems of The Goodyear Tire & Rubber Company.

Member, Corporate Governance and Nuclear Committees. Director of FirstEnergy Corp. since 1997 and of Ohio Edison from 1992-1997.

Dr. Patricia K. Woolf, 70 Consultant, author, and former Lecturer in the Department of Molecular Biology at Princeton University. Member, Corporate Governance and Nuclear Committees. Director of FirstEnergy Corp. since 2001 and of the former GPU, Inc., from 1983-2001.

7

FirstEnergy Officers FirstEnergy Corp.

Anthony J. Alexander President and Chief Executive Officer Richard R. Grigg Executive Vice President and Chief Operating Officer Richard H. Marsh' Senior Vice President and Chief Financial Officer Leila L Vespoli' Senior Vice President and General Counsel Harvey L Wagner Vice President, Controller and Chief Accounting Officer David W. Whitehead Corporate Secretary Thomas C. Navin*

Treasurer Paulette R. Chatman*

Assistant Controller Jeffrey R. Kalata' Assistant Controller Randy Scilla' Assistant Treasurer Jacqueline S. Cooper*

Assistant Corporate Secretary Edward J. Udovich' Assistant Corporate Secretary

• Also holds the same title with FirstEnergy Service Company, FirstEnergy Solutions Corp. and FirstEnergy Nuclear Operating Company FirstEnergy Service Company Anthony J. Alexander President and Chief Executive Officer Richard R. Grigg Executive Vice President and Chief Operating Officer Mark T. Clark Senior Vice President Douglas S. Elliott Senior Vice President Charles E. Jones Senior Vice President Kevin J. Keough Senior Vice President Carole B. Snyder Senior Vice President Thomas M. Welsh Senior Vice President David M. Blank Vice President Mary Beth Carroll Vice President Lynn M. Cavalier Vice President Kathryn W. Dindo Vice President and Chief Risk Officer Ralph J. DiNicola Vice President Michael J. Dowling Vice President and Chief Procurement Officer Bradley S. Ewing Vice President Terrance G. Howson Vice President Ali Jamshidi Vice President Mark A. Julian Vice President David C. Luff Vice President Stanley F. Szwed Vice President Bradford F. Tobin Vice President and Chief Information Officer Harvey L. Wagner Vice President and Controller David W. Whitehead Vice President, Corporate Secretary and Chief Ethics Officer Usa S. Wilson Assistant Controller FirstEnergy Solutions Corp.

Guy L Pipitone Alfred G. Roth Trent A. Smith Harvey L. Wagner David W. Whitehead President Vice President Vice President Vice President and Corporate Secretary Charles D. Lasky Donald R. Schneider Daniel V. Steen Controller Vice President Vice President Vice President FirstEnergy Nuclear Operating Company Anthony J. Alexander Joseph J. Hagan Mark B. Bezilla L. William Pearce Harvey L. Wagner Chief Executive Officer Senior Vice President Vice President, Vice President, Vice President Gary R. Leidich Lew W. Myers Davis-Besse Beaver Valley and Controller President and Chief Operating Officer Richard L. Anderson Jeanine M. Rinckel David W. Whitehead Chief Nuclear Officer Vice President, Perry Vice President, Corporate Secretary Oversight FirstEnergy Regional Operations Management Dennis M. Chack Regional President The Cleveland Electric Illuminating Company Thomas A. Clark Regional President Ohio Edison Company James M. Murray Regional President The Toledo Edison Company Stephen E. Morgan President Jersey Central Power

& Light Company Donald M. Lynch Regional President Jersey Central Power

& Light Company Steven E. Strah Regional President Jersey Central Power

& Light Company Ronald P. Lantzy Regional President Metropolitan Edison Company John E. Paganie Regional President Pennsylvania Electric Company 8

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 Avon Avon Energy Partners Holdings CEI The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary CFC Centerior Funding Corporation, a wholly owned finance subsidiary of CEI Companies OE. CEI.

TE. Penn. JCP&L Met-Ed and Penelec Emdersa Empresa Distribuidora Electrica Regional SA EUOC Electric Utility Operating Companies JOE. CEI.

TE. Penn. JCP&L Met-Ed.

Penetec. and ATSIQ FENOC FirstEnergy Nuclear Operating Company, operates nuclear generating facilities FES FirstEnergy Solutions Corp., provides energy-related products and services FESC FirstEnergy Service Company, provides legal. financial, and other corporate support services FGCO FirstEnergy Generation Corp.. operates nonnuclear generating facilities FirstCom First Communications. LLC, provides local and long-distance telephone service FirstEnergy FirstEnergy Corp.. a registered public utility holding company FSG FirstEnergy Facilities Services Group, UIC. the parent company of several heating. ventilation, air conditioning and energy management companies GLEP Great Lakes Energy Partners, UIC. an oil and natural gas exploration and production venture GPU GPU. Inc.. former parent of JCP&L Met-Ed and Penefec, which merged with FirstEnergy on November 7, 2001 GPU Capital GPU Capital. Inc., owned and operated electric distribution systems in foreign countries GPU Power GPU Power, Inc.. owned and operated generation facilities in foreign countries JCP&L Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary MARBEL MARBEL Energy Corporation, previously held FirstEnergys interest in GLEP Met-Ed Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary MYR MYR Group. Inc., a utility infrastructure construction service company NEO Northeast Ohio Natural Gas Corp.. formerly a MARBEL subsidiary OE Ohio Edison Company. an Ohio electric utility operating subsidiary Ohio Companies CEI. OE and TE Penelec Pennsylvania Electric Company. a Pennsylvania electric utility operating subsidiary Penn Pennsylvania Power Company. a Pennsylvania electric utility operating subsidiary of OE PNBV PNBV Capital Trust, a special purpose entity created by OE in 1996 Shippingport Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997 TE The Toledo Edison Company. an Ohio electric utility operating subsidiary TEBSA Termobarranquilla SA, Empresa de Servicios Publicos The following abbreviations and acronyms are used to identify frequently used terms in this report:

AW Administrative Law Judge AOCL Accumulated Other Comprehensive Loss APB Accounting Principles Board APB 25 APB Opinion No. 25. 'Accounting for Stock Issued to Employees' APB 29 APB Opinion No. 29, 'Accounting for Nonmonetary Transactions' ARB 43 Accounting Research Bulletin No. 43. 'Restatement and Revision of Accounting Research Bulletins' ARO Asset Retirement Obligation ASLB Atomic Safety and Licensing Board BGS Basic Generation Service CO2 Carbon Dioxide CTC Competitive Transition Charge ECAR East Central Area Reliability Coordination Agreement EITF Emerging Issues Task Force EITF 03-1 EITF Issue No. 03-1. 'The Meaning of Other-Than-Temporary and Its Application to Certain Investments' EITF 03-16 EITF Issue No. 03-16, 'Accounting for Investments in Limited Liability Companies' EITF 97-4 EITF Issue No. 97-4 'Deregulation of the Pricing of Electricity - Issues Related to the Application of FASO Statements No. 71 and 101' EITF 99-19 EITF Issue No. 99-19. Reponing Revenue Gross as a Principal versus Net as an Agent' EPA Environmental Protection Agency FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission FIN FASB Interpretation FIN 46R FIN 46 (revised December 2003L 'Consolidation of Variable Interest Entities' FMB First Mortgage Bonds FSP FASO Staff Position FSP EITF 03-1-1 FASO Staff Position No. EITF Issue 03-1-1, 'Effective Date of Paragraphs 10-20 of EITF Issue No. 03-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments' FSP 106-1 FASB Staff Position No.106-1. 'Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003' FSP 106-2 FASB Staff Position No.106-2. 'Accounting and Disclosure Requirements Related to the Medicare Prescription Drug. Improvement and Modernization Act of 2003' FSP 109-1 FASB Staff Position No. 109-1. 'Application of FASB Statement No. 109.

Accounting for Income Taxes, to the Tax Deduction and Qualified Production Activities provided by the American Jobs Creation Act of 2004' GAAP Accounting Principles Generally Accepted in the United States HVAC Heating. Ventilation and Air-conditioning IRS Internal Revenue Service ISO Independent System Operator KWH Kilowatt-hours LOC Letter of Credit MACT Maximum Achievable Control Technologies Medicare Act Medicare Prescription Drug. Improvement and Modernization Act of 2003 MISO Midwest Independent System Transmission Operator. Inc.

Moodys Moody's Investors Service MTC Market Transition Charge MW Megawatts NAAOS National Ambient Air Guality Standards NERC North American Electric Reliability Council NJBPU New Jersey Board of Public Utilities NOAC Northwest Ohio Aggregation Coalition NOV Notices of Violation NOx Nitrogen Oxide NRC Nuclear Regulatory Commission NUG Non-Utility Generation OCC Ohio Consumers' Counsel OCI Other Comprehensive Income OPEB Other Post-Employment Benefits PCAOB Public Company Accounting Oversight Board (United States)

PJM PJM Interconnection L.L.C.

PLR Provider of Last Resort PPUC Pennsylvania Public Utility Commission PRP Potentially Responsible Party PUCO Public Utilities Commission of Ohio PUHCA Public Utility Holding Company Act RTC Regulatory Transition Charge S&P Standard & Poor's Ratings Service SBC Societal Benefits Charge SEC United States Securities and Exchange Commission SFAS Statement of Financial Accounting Standards SFAS 71 SFAS No. 71. 'Accounting for the Effects of Certain Types of Regulation' SFAS 87 SFAS No. 87, 'Employers' Accounting for Pensions' SFAS 101 SFAS No. 101, 'Accounting for Discontinuation of Application of SFAS 71' SFAS 106 SFAS No. 106, 'Employers' Accounting for Postretirement Benefits Other Than Pensions' SFAS 115 SFAS No. 115 'Accounting for Certain Investments in Debt and Equity Securities' SFAS 123 SFAS No. 123. 'Accounting for Stock-Based Compensation' SFAS 123(R)

SFAS No. 123(R). 'Share-Based Payment' SFAS 131 SFAS No. 131. 'Disclosures about Segments of an Enterprise and Related Information' SFAS 133 SFAS No. 133. 'Accounting for Derivative Instruments and Hedging Activities' SFAS 140 SFAS No. 140, 'Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities' SFAS 142 SFAS No. 142 'Goodwill and Other Intangible Assets' SFAS 143 SFAS No. 143, 'Accounting for Asset Retirement Obligations' SFAS 144 SFAS No. 144. 'Accounting for the Impairment or Disposal of Long-Lived Assets' SFAS 150 SFAS No. 150. 'Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity' SFAS 151 SFAS No. 151 'Inventory costs - an amendment of ARB No. 43. Chapter4' S02 Sulfur Dioxide TBC Transition Bond Charge TMI-1 Three Mile Island Unit 1 TMI-2 Three Mile Island Unit 2 VIE Variable Interest Entity

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Management Reports Management's Responsibility for Financial Statements The consolidated financial statements were prepared by management who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company's 2004 consolidated financial statements.

FirstEnergy Corp.'s internal auditors, who are responsible to the Audit Committee of FirstEnergy's Board of Directors, review the results and performance of operating units within the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.

FirstEnergy's Audit Committee consists of five inde-pendent directors whose duties include: consideration 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 indepen-dent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm's independence. The Committee also reviews manage-ment'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 six meetings in 2004.

Management's Report on Internal Control Over Financial Reporting Management is responsible for establishing and main-taining adequate internal control over financial reporting as defined in Rule 13a-1 5(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework, management con-ducted an evaluation of the effectiveness of the Company's internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer.

Based on that evaluation, management concluded that the Company's internal control over financial reporting was effec-tive as of December 31, 2004. Management's assessment of the effectiveness of the Company's internal control over financial reporting, as of December 31, 2004, has been audit-ed by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page 11.

70. ISr' 8' '-qvG!9 ar.

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

We have completed an integrated audit of FirstEnergy Corp.'s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 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 statements In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stock-holders' equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of FirstEnergy Corp. and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these state-ments in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and per-form the audit to obtain reasonable assurance about whether the financial statements are free of material mis-statement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant esti-mates made by management, and evaluating the overall financial state-ment presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2(K) to the consolidated financial statements, the Company changed its method of accounting for asset retirement obliga-tions as of January 1, 2003. As discussed in Note 7 to the consolidated financial statements, the Company changed its method of accounting for the consolidation of variable interest entities as of December 31, 2003.

Internal control over financial reporting Also, in our opinion, management's assessment, included in the accompany-ing Management's Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management's assessment and on the effectiveness of the Company's internal control over financial reporting based on our audit. We. conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of inter-nal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circum-stances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reason-able assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting princi-ples, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP Cleveland, Ohio, March 7, 2005

SELECTED FINANCIAL DATA (in thousands, except per share amounts)

For the Years Ended December 31, 200 2003 2002 2001 2000 Revenues

$1Z453,046

$11,674,888

$11,453,354

$ 7,237,011

$ 6,470,488 Income Before Discontinued Operations and Cumulative Effect of Accounting Changes

$ 873,779

$ 424,249

$ 618,385

$ 654,946

$ 598,970 Net Income S 878,175

$ 422,764

$ 552,804

$ 646,447 S 598,970 Basic Earnings per Share of Common Stock:

Before Discontinued Operations and Cumulative Effect of Accounting Changes 2.67 1.40 2.11 2.85 2.69 After Discontinued Operations and Cumulative Effect of Accounting Changes

.2.68 1.39 1.89 2.82 2.69 Diluted Earnings per Share of Common Stock:

Before Discontinued Operations and Cumulative Effect of Accounting Changes 266 1.40 2.10 2.84 2.69 After Discontinued Operations and Cumulative Effect of Accounting Changes S

2.67; 1.39 1.88 2.81 2.69 Dividends Declared per Share of Common Stock' 1.9125 1.50 1.50 1.50 1.50 Total Assets

$31,067,944

$32,909,948

$34,386,353

$37,351,513

$17,941,294 Capitalization as of December 31:

Common Stockholders' Equity 8,589.294

$ 8,289,341

$ 7,050,661

$ 7,398,599

$ 4,653,126 Preferred Stock:

Not Subject to Mandatory Redemption 335,123 335,123 335,123 480,194 648,395 Subject to Mandatory Redemption 428,388 594,856 161,105 Long-Term Debt and Other Long-Term Obligations 10,013,349 9,789,066 10,872,216 12,865,352 5,742,048 Total Capitalization

$18,937,766

$18,413,530

$18,686,388

$21,339,001

$11,204,674

' Dividends declared in each year include four quarterly dividends of S$.375per share paid in those years. In addition, a quarterly dividend of $04125 as declared in 2004 payable March 1,2 005. increasing the indicated annual dividend rate from $1.50 to $1.65 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.

2004 2003 First Quarter High-Low

$39.37

$3524

$35.19

$27.04 Second Quarter High-Low

$39.73

$36.73

$38.90

$30.57 Third Quarter High-Low

$4223

$37.04

$38.75

$25.82 Fourth Quarter High-Low

$43.41

-3835

$35.95

$31.66 Yearly High-Low

$43.41

$3524

$38.90

$25.82 Prices are based on reports published in The Wall Street Journal for New York Stock Exchange Composite Transactions.

HOLDERS OF COMMON STOCK There were 143,111 and 142,825 holders of 329,836,276 shares of FirstEnergy's Common Stock as of December 31, 2004 and January 31, 2005, respectively. Information regarding retained earnings available for payment of cash dividends is given in Note 10(A) to the consolidated financial statements.

72..

Management's Discussion and Analysis of Results of Operations and Financial Condition This discussion 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 and include reference to an indicated annual dividend. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements),

adverse regulatory or legal decisions and outcomes (including revocation of necessary licenses or operating permits, fines or other enforcement actions and remedies) of government investigations, including by the Securities and Exchange Commission, the United States Attomey's Office and the Nuclear Regulatory Commission as disclosed in our Securities and Exchange Commission filings, generally, and with respect to the Davis-Besse Nuclear Power Station outage in particular, the availability and cost of capital, the continuing availability and operation of generating units, our inability to accomplish or realize anticipated benefits from strategic goals, our ability to improve electric commodity margins and to experience growth in the distribution business, our ability to access the public securities and other capital markets, further investiga-tion into the causes of the August 14, 2003 regional power outage and the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the outage, the final outcome in the proceeding related to FirstEnergy's Application for a Rate Stabilization Plan in Ohio, 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. FirstEnergy expressly disclaims any current intention to update any forward-looking statements contained herein as a result of new information, future events, or otherwise.

EXECUTIVE

SUMMARY

On a non-GAAP basis, earnings in 2004 increased to

$991 million, or basic earnings of $3.03 per share of com-mon stock, from earnings of $736 million (basic earnings of $2.42 per share) in 2003 and $889 million (basic earnings of $3.03 per share) in 2002. On a GAAP basis, net income increased to $878 million, or basic earnings of $2.68 per share in 2004 from $423 million (basic earnings of $1.39 per share) in 2003 and $553 million (basic earnings of $1.89 per share) in 2002. The following Non-GAAP Reconciliation displays the unusual items resulting in the difference between GAAP and non-GAAP earnings.

Non-GAAP Reconciliation 2004 200 2002 After-tax Basic After-tax Basic After-tax Basic

. nout Eanigs Amount Earnings Amount Earings (Millions) Per Share (Millions) PerShare (Millions) PerShare Earnings Before Unusual Items (Non-GAAP)

$991

$3.03

$736

$2.42

$889

$3.03 Cumulative effect of accounting change 102 0.33 Discontinued International operations (101-10.331 180) (0.27)

Non-core asset sales/impairments (60) 10.19)

(125) 10.41) 162) 10.211

-Davis-Besse impacts (381 (0.12)

(170) 10.561 1139) 10.47)

JCP&L

. disallowance (109) 10.36)

Litigation settlement (11)

(0.03)

Lake plants transaction (17)

(0.06)

NRG settlement 99 0.33 Long-term derivative contract adjustment

( 111) (0.04)

Generation project cancellation (10)

(0.04)

Other 14 10.01)

(9) 10.03) -

(17)

(0.05)

Net Income (GAAP).

$878

$2.68

$423 r. $1.39

$553.

1Sl.89 The Non-GAAP measure above, earnings before unusual items, is not calculated in accordance with GAAP because it excludes the impact of "unusual items." Unusual items reflect the impact on earnings of events that are not routine, are relat-ed to discontinued businesses or are the cumulative effect of an accounting change. We believe presenting normalized earn-ings calculated in this manner provides useful information to investors in evaluating the ongoing results of our businesses and assists investors in comparing our operating performance to the operating performance of others in the energy sector.

Under our debt paydown and refinancing program, we retired, refinanced, or restructured more than $2.8 billion in long-term debt during the year. These financing activities contributed to the $143 million decrease in interest charges in 2004.

Sales for 2004 were up over the previous year, driven pri-marily by strong sales in the wholesale power market. This increase is largely reflective of a stronger economy and the return of the Davis-Besse Nuclear Power Station to active sta-tus. Despite milder weather experienced over much of our service area in 2004, our generating fleet produced a record 76 billion KWH. Our fossil fleet produced 46 billion KWH and our nuclear fleet produced a record 30 billion KWH.

The Company made a voluntary $500 million contribu-tion to its pension plan in order to help add security to future plan benefits. The net after-tax cost of the contribu-tion was approximately $300 million. This contribution is

$If: W(t.8 Car2pX; 13

expected to reduce our overall risk profile, because it reduces uncertainty regarding the plan's unfunded liability.

We continue to participate in meaningful settlement negotiations with the parties to the New Source Review case involving our W. H. Sammis Plant (see Environmental Matters). As a result, the U.S. District Court judge hearing' the case has delayed without rescheduling the remedy phase of the trial, originally scheduled to begin in January 2005.

In November 2004, the Board of Directors increased our indicated annual dividend to $1.65 per share, payable quarterly at a rate of $0.4125 per share. This action repre-sents a 10% increase over the previous quarterly rate and is the first dividend increase since FirstEnergy was formed in 1997. The Board also adopted a dividend policy that will tar-get sustainable annual dividend increases after 2005 that generally reflect an annual growth rate within the range of 4% to 5%, and an earnings payout ratio generally within the range of 50% to 60%.

At the end of December 2004, accrued dividends of approximately $135 million were included in other current liabilities on the accompanying consolidated balance sheet.

Dividends declared in 2004 were $1.9125 which included quarterly dividends of $0.375 per share paid in each quarter of 2004 and a dividend of $0.4125 payable in the first quar-ter of 2005. The amount and timing of all dividend declarations are subject to the discretion of the Board and its consideration of business conditions, results of opera-tions, financial condition and other factors.

FIRSTENERGY'S BUSINESS FirstEnergy is a registered public utility holding compa-ny headquartered in Akron, Ohio that provides regulated and competitive energy services (see Results of Operations -

Business Segments). Our eight EUOC provide transmission and distribution services and comprise the nation's fifth largest investor-owned electric system - based on serving 4.4 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey. ATSI provides transmission services to our Ohio Companies and Penn. The service areas of our EUOC are highlighted below.

Operating Company Area Served Customers Served OE Central and northeastern Ohio 1.031.066 Penn Western Pennsylvania 157.411 CEI Northeastern Ohio 757,889 TE Northwestern Ohio 311,225 JCP&L Northern, western and east central New Jersey 1.061,764 Met-Ed Eastern Pennsylvania 526.380 Penelec Western Pennsylvania 588.066.-

ATSI Service areas of OE. Penn. CEI and TE Competitive energy services are principally provided by FES. FSG and MYR provide heating, ventilation, air-condi-tioning, refrigeration, process piping, plumbing, electrical and facility control systems and high-efficiency electrotech-nologies. While competitive revenues have increased since 2001, regulated energy services continue to provide the majority of our revenues and earnings.

14 !,'sr.nz'.

f

'Cp 2004 Beginning in 2001, Ohio utilities that offered both com-petitive and regulated retail electric services were required to implement a corporate separation plan approved by the PUCO - one which provided a clear separation between reg-ulated and competitive operations. FES provides generation services while the EUOC provide regulated transmission and distribution services. FGCO, a wholly owned subsidiary of FES, leases and operates fossil and hydroelectric plants owned by the Ohio Companies and Penn. Under the terms of the Ohio Rate Stabilization Plan, the deadline for achiev-ing structural separation by transferring the ownership of applicable EUOC generating assets to a competitive affiliate was extended until twelve months after the termination of the Rate Stabilization Plan, unless otherwise extended fur-ther by the PUCO, or until December 31, 2008, whichever is earlier. All of the power supply requirements for the Ohio Companies and Penn are provided through FES.

FirstEnergy acquired international assets in the merger with GPU in November 2001. GPU Capital and its sub-sidiaries had provided electric distribution services in foreign countries (see Results of Operations - Discontinued Operations). GPU Power and its subsidiaries owned and operated generation facilities in foreign countries. As of January 30, 2004, all of the international operations had been divested because those assets were inconsistent with our vision for FirstEnergy.

STRATEGY We continue to pursue our goal of being the leading regional supplier of energy and related services in the north-east quadrant of the United States, where we see the best opportunities for growth. Our fundamental business strate-gy remains stable and unchanged. While we continue to build a strong regional presence, key elements for our strat-egy are in place and management's focus continues to be on execution. We intend to continue providing competitively priced, high-quality products and value-added services -

energy sales and services, energy delivery, power supply and supplemental services related to our core business.

Our current focus includes: (1) minimizing unplanned extended generation outages; (2) enhancing our system reli-ability; (3) optimizing our generation portfolio; (4) effectively managing commodity supplies and risks; 15) preserving and enhancing appropriate margins; (6) enhancing our credit pro-file and financial flexibility; and (7) managing the skills and diversity of our workforce.

RISKS We face a number of industry and enterprise risks and challenges, including:

• Changes in commodity prices, which could adversely affect our margins;

• Complex and changing government regulations, which could have a negative impact on results of operations;

• Costs of compliance with environmental laws, which are significant, and the cost of compliance with future environmental laws, which could adversely affect cash flow and profitability;

• Financial performance risks related to the economic cycles of the electric utility industry; I

• The continuing availability and operation of generating units, which is dependent on retaining the necessary licenses, permits, and operating authority from govern-mental entities, including the NRC;

• Risks of nuclear generation, including uncertainties relating to health and safety, additional capital costs, the adequacy of insurance coverage and nuclear plant decommissioning;

• Operational risks arising from the reliability of our power plants and transmission and distribution equipment;

• Regulatory changes in the electric industry, which could affect our competitive position and result in unrecoverable costs adversely affecting our business and results of operations;

• Human resource risks associated with the availability of trained and qualified labor to meet our future staffing requirements;

• Weather conditions such as tornadoes, hurricanes, storms and droughts, as well as seasonal tempera-ture variations;

• A downgrade in credit ratings, which could negatively affect our ability to access capital; and

• We may ultimately incur liability in connection with federal proceedings described in Note 13 to the consolidated financial statements.

RECLASSIFICATIONS As discussed in Notes 1 and 14 to the consolidated financial statements, certain prior year amounts have been reclassified to conform to the current year presentation.

Revenues related to transmission activities previously recorded as wholesale electric sales revenues were reclassi-fied as transmission revenues. Expenses (including transmission and congestion charges) were reclassified among purchased power, other operating costs and amorti-zation of regulatory assets to conform to the current year presentation of generation commodity costs. As further dis-cussed in Note 14 to the consolidated financial statements, segment reporting in 2003 and 2002 was reclassified to conform to the 2004 business segment organizations and operations. These reclassifications did not change previously reported earnings in 2003 and 2002.

RESULTS OF OPERATIONS The 2004 increase in net income of $455 million from the prior year resulted from several factors. First, the number of unusual charges incurred in 2004 decreased as certain ini-tiatives began to reach their conclusion in 2003 and early 2004. Second, adverse operating results at FSG led to impairment of its goodwill in 2003. Its remaining goodwill and certain other assets were further impaired in 2004 as we prepared to sell the FSG operations. Finally, a positive turn in the economy, moderation in the rate at which alternative suppliers expanded their presence in our franchise areas, and reduced expenses enhanced 2004 financial results.

Moderating those positive results was the absence in 2004 of the NRG settlement gain recorded in 2003 and the cumu-lative effect of an accounting change which offset some of the negative 2003 factors described above.

The $130 million decrease in net income in 2003 com-pared with 2002 reflected many of the factors described above. Additional costs were being incurred during the extended outage at Davis-Besse for replacement power, accelerated maintenance, extended-scope enhancements to plant design and human performance and safety issues.

Also, losses were being recorded on international opera-tions, alternative suppliers were expanding more rapidly in our franchise areas, the economy negatively influenced financial results and we recorded our first impairment of goodwill. In 2003, the NRG settlement gain and cumulative effect of an accounting change offset the negative factors.

The financial results in 2004, 2003 and 2002 are summarized in the table below.

FirstEnergy 2004 2003 2002 (In millions, except per share amounts)

Total revenues 512.453

$11,675 511,453 "Income before discontinued operations and cumulative effect of accounting change 874 424 618 Discontinued operations 4

(1031 (65)

Cumulative effect of accounting change 102 Net Income 5 878 S 423 S 553 Basic Earnings Per Share:

Income before discontinued operations and cumulative effect of accounting change

$2.67

$1.40

$2.11 Discontinued operations 0.01 (0.34)

(0.22)

Cumulative effect of accounting change 0.33 Net Income

$268

$1.39

$1.89 Diluted Earnings Per Share:

Income before discontinued operations and cumulative effect of accounting change'

$2.66

$1.40 52.10 Discontinued operations 0.01 (0.34) 10.22)

Cumulative effect of accounting change 0.33 Net Income

$2.67

$1.39

$1.88 Results of Operations - 2004 Compared With 2003 Sources of changes in total revenues are summarized in the following table:

Increase Sources of Revenue Changes -

2004 20M3 (Decrease)

(In millions)

Retail Electric Sales:

EUOC -Wires S 4,701

$ 4.787

$186)

-Generation 3,158 3.139 19 FES 637 566 71 lWholesale Electric Sales:

EUOC' 512 570 (58)

FES 1,823 1,143 680 Total Electric Sales 10,831 10,205 626 Transmission Revenues:

EUOC 333 23 310 FES 39 59 1201 Other Revenues:

.EUOC 361 443 (82)

FES

-Generation 35 10 25 FSG 398 327 71

'International 25 (25)

Miscellaneous 456 583 (127)

Total Revenues

$12,453

$11,675

$778 Changes in electric generation sales and distribution deliveries in 2004 are summarized in the following table:

9 '. a.

1.

' 75

Changes In KWH Sales Increase (Decrease)

Electric Generation Sales:

Retail:

EUOC (1.51%

FES Wholesale e26.7%

Total Electric Generation Sales 7.7%

EUOC Distribution Deliveries:

Residential 2.0" Commercial 2.65 Industrial 0.6'.

Total Distribution Deliveries 1.6' Retail sales by our EUOC remain the largest source of revenues, contributing more than 70% of electric revenues and over 60% of total revenues. The following major factors contributed to the $67 million decrease in retail electric revenues from our EUOC in 2004.

Sources of the Changes In EUOC Retail Electric Revenue Increase (Decrease)

(In millions)

Changes in Customer Consumption:

Alternative suppliers S177)

- Economyweatherandother 109 32 Changes in Price:

- Rate changes (19)

Shopping incentives (51)

Rate mix and other (29)

(99)

Net Decrease

$(67)

Lower prices were partially offset by increased energy use due to a strengthening economy. Although the demand for energy increased in all three customer groups - residen-tial, commercial and industrial - milder weather in 2004 moderated the energy needs of residential and commercial customers. Customers shopping in our franchise areas for alternative energy suppliers remained a major factor con-tributing to lower EUOC revenues with alternative suppliers providing a larger portion of franchise customer energy requirements.

Alternative suppliers provided 24.3% of the total energy delivered to retail customers in our franchise areas in 2004, compared to 21.8% in 2003. Lower prices resulted from three factors - a shopping credit rate increase, a change in the mix of sales with fewer retail customers receiving EUOC generation in Ohio, and lower base distribution rates at JCP&L. Partially offsetting JCP&Us lower base distribu-tion rates were higher energy, MTC and SBC rates.

Additional credits provided to customers (primarily under the Ohio transition plan) to promote customer shop-ping for alternative suppliers reduced regulated retail electric sales revenues. Reductions from shopping incentives are deferred for future recovery under our Ohio transition plan and do not affect current period earnings.

Electric sales by FES increased by $751 million primarily from additional sales to the wholesale market that increased

$680 million in 2004. Higher electric sales to the wholesale market were possible due in part to a 13% increase in gen-eration resulting from record production from our generating fleet. Retail sales increased $71 million, with nearly half of the revenue increase from customers within our franchise areas switching to FES.

The gross generation margin in 2004 improved by $402 million compared to 2003, with electric generation revenue increasing more rapidly than the costs of fuel and purchased power. Excluding the unusual charge resulting from the July 2003 JCP&L rate decision, the gross generation margin improved by $249 million and the ratio of gross generation margin to revenue increased from 26.1 % to 27.1 %, primari-ly reflecting additional lower-cost nuclear generation, offset in part by higher purchased power prices.

Gross Generation Margin 2004 2003 Increase (In millions)

Electric generation revenue S6.130 55.418

$712

,'Fuel and purchased power costs 4,469 4,159 310

.Gross Generation Margin 1,661

$1259

$402 Income before discontinued operations and the cumula-tive effect of an accounting change increased $450 million in 2004. In addition to the impact of improved gross genera-tion margin discussed above, the following factors contributed to the change in earnings:

• Lower nuclear expenses of $169 million primarily as a result of one scheduled refueling outage at Beaver Valley Unit 1 in 2004 compared to three scheduled refueling outages in 2003 (Beaver Valley Unit 1, Beaver Valley Unit 2 and Perry) and reduced incre-mental maintenance costs at the Davis-Besse Nuclear Power Station related to its restart;

• Lower energy delivery expenses of $94 million due to reduced storm restoration costs in 2004, a higher level of construction activities in 2004 compared to a higher level of maintenance activities in the prior year and additional distribution reliability expenses incurred in the third quarter of 2003;

• Reduced fossil generation expenses of $49 million due to less maintenance in 2004 compared to the prior year;

• A net $51 million decrease in employee benefits expense primarily as a result of reduced postretire-ment benefit plan expenses (see Postretirement Plans below), offset in part by higher incentive com-pensation and severance costs;

• Lower interest charges of $143 million primarily due to debt and preferred stock redemption and refinancing activities and pollution control note repricings;

• A net $81 million reduction in goodwill impairment charges for FSG with $36 million (see Note 2(H))

and $117 million recognized in 2004 and 2003, respectively; and

• Additional deferrals of regulatory assets of $63 million, due principally to Ohio shopping incentives.

Partially offsetting the above sources of improved earnings were five factors:

• Reduced revenues of $86 million from distribution deliveries due to lower prices;

• Increased amortization of regulatory assets of $87 16 Ccr

,,.t;v,,

. nap

million primarily from additional Ohio transition plan amortization and a change in amortization resulting from the July 2003 JCP&L rate decision;

• The absence in 2004 of the 2003 earnings benefit of

$168 million realized from the settlement of our claim against NRG for the terminated sale of four fossil plants;

• An aggregate increase in Ohio property tax expense and other state taxes of $40 million; and

• Increased income taxes of $263 million primarily reflecting higher taxable earnings.

Results of Operations - 2003 Compared With 2002 Sources of changes in total revenues are summarized in the following table:

Increase Sources of Revenue Changes 2003 202 (Decrease)

(In millions)

Retail Electric Sales.

EUOC - Wires

$4,787

$4,872 S(85)

- Generation 3,139 3.357 1218)

FES 566 348 218 Wholesale Electric Sales:

EUDC 570 511 59 FES 1.143 568 575 Total Electric Sales 10,205 9.656 549.

Transmission Revenues:.

EUOC 23 39 (161.

FES 59 2.

57 Other Revenues:

EUOC 443 387 56.

FES

- Generation 10 39 (29)

FSG 327 383 (56)

International 25 294 (269)

Miscellaneous 583 653 (70)

TotalRevenues S11.675

$11.453

$222 Changes in electric generation sales and distribution deliveries in 2003 are summarized in the following table:

Changes In KWH Sales.

Increase (Decrease)

Electric Generation Sales:

Retail:

EUOC (7.2).

FES 53.0 Wholesale 40.2%

Total Electric Generation Sales 8.3 G

EUOC Distribution Deliveries:

Residential (0.7)%

Commercial 1.27 Industrial (10.4)'

Total Distribution Deliveries Retail sales by our EUOC contributed more than 70%

of electric revenues and over 60% of total revenues. The following major factors contributed to the $303 million decrease in retail electric revenues from our EUOC in 2003:

r I_

.II ISources of the Changes In EUOC Retail Electric Revenue Increase (Decrease)

Changes in Customer Consumption:

Alternative suppliers (In millions)

$(295)

Economy, weather ana other b

(311)

Changes in Price:

Ratechanges (11)

Shopping incentives (6)

Rate mix and other 25 8

Net Decrease

$1303)

The lower retail electric revenues resulted principally from increased sales by alternative suppliers in our franchise areas. Alternative suppliers provided 21.8% of the total energy delivered to retail customers in our franchise areas in 2003. compared to 15.7% in 2002. As a result, generation kilowatt-hour sales to retail customers of our regulated services were 7.2% lower. Additional credits provided to customers (primarily under the Ohio transition plan) to pro-mote customer shopping for alternative suppliers further reduced regulated retail electric sales revenues. Reductions from shopping incentives are deferred for future recovery under our Ohio transition plan and do not materially affect current period earnings. The NJBPU decision in July 2003 that lowered JCP&L's base electric rates effective August 1, 2003 contributed to lower rates.

Electric sales by FES increased by $793 million primarily from additional sales to the wholesale market that increased

$575 million in 2003 on a 75% increase in kilowatt-hour sales. A majority of the increase was due to sales by our competitive electric energy services segment for a portion of New Jersey's BGS requirements and sales in the spot market. Retail sales by FES increased by $218 million as a result of a 53% increase in kilowatt-hour sales. That increase primarily resulted from retail customers within our Ohio franchise areas switching to FES under Ohio's electricity choice program and from growth in competitive retail sales outside our franchise areas.

The gross generation margin in 2003 declined by $215 million compared to the same period in 2002. Excluding the unusual charge of $153 million of power costs that were disallowed in the July 2003 JCP&L rate decision referred to above, our gross generation margin decreased $62 million and the ratio of gross generation margin to revenue decreased from 30.8% to 26.1 %. Higher electric generation sales resulted principally from the additional sales in the wholesale market and were more than offset by increased fuel and purchased power costs. Purchased power costs increased by $879 million due to higher unit costs and addi-tional quantities purchased. Increased volumes were required to supply obligations assumed by FES for BGS sales in New Jersey, as well as other wholesale commit-ments, and additional supplies were required to replace

.17

reduced nuclear generation (down 14%). Reduced nuclear generation output resulted from additional refueling outage work performed at the Perry and Beaver Valley plants in 2003 and the Davis-Besse extended outage.

Increase Gross Generation Margin 2003 2002 (Decrease)

(In millionsl Electric generation revenue S5418 54.784

-S 634 Fuelandpurchasedpowercosts 4,159 3.310 849'.

Gross Generation Margin

$1259

$1.474 5(2151 Income before discontinued operations and the cumula-tive effect of an accounting change decreased $194 million in 2003. In addition to the impact of reduced gross genera-tion margin and lower revenues from distribution deliveries discussed above, the following factors contributed to the decrease in earnings:

• Asset impairment charges of $56 million incurred in 2003 including a $26 million non-cash charge related to the divestiture of our interest in TEBSA; a $13 mil-lion impairment on the monetization of the note received from the sale of our 79.9% interest in Avon; an additional $5 million impairment upon the divesti-ture of our remaining interest in Avon; and $12 million related to the disposition of NEO and the write down of our investment in Pantellos, an internet business-to-business marketplace serving the utility sector;

• A non-cash goodwill impairment charge of $117 mil-lion recorded in the third quarter of 2003 reducing the carrying value of FSG;

• Increased energy delivery costs of $36 million princi-pally due to storm restoration expenses and an accelerated reliability program within JCP&L's service territory;

• Higher nuclear expenses of $54 million as a result of an additional scheduled nuclear refueling outage in 2003 and unplanned work performed during the scheduled refueling outages at the Perry Plant and Beaver Valley Unit 1. The higher production costs were partially offset by lower maintenance costs at the Davis-Besse Nuclear Power Station;

• Planned maintenance outages at three of our fossil generating plants during the fourth quarter of 2003 increased non-nuclear operating expenses by approxi-mately $25 million;

• Increased postretirement plan expenses (see Postretirement Plans below) offset in part by lower incentive compensation costs contributed to a net cost increase of $94 million;

• Revenues less operating expenses for energy-related services declined $17 million due to general declines associated with economic conditions;

• An estimated environmental liability of $15 million was recognized in the fourth quarter of 2003; and

• Increased amortization of regulatory assets of $138 million due principally to additional Ohio transition plan amortization and a July 2003 JCP&L rate case disallowance.

Partially offsetting these higher costs were five factors:

• A settlement of our claim against NRG for the terminated sale of four fossil plants resulted in a $168 million gain;

• Reduced depreciation resulting from several factors lower charges resulting from the implementation of SFAS 143 ($61 million), revised service life assump-tions for nuclear generating plants ($28 million) and reduced depreciation rates resulting from the JCP&L rate case ($18 million);

• Lower interest charges of $146 million primarily due to debt and preferred stock redemption and refinanc-ing activities and pollution control note repricings;

• The absence of unusual charges recognized in 2002 resulted in a further net reduction of other operating expenses ($181 million) in 2003; and

• Reduced income taxes of $106 million primarily reflecting lower taxable earnings.

Cumulative Effect of Accounting Change Results in 2003 included an after-tax credit to net income of $102 million recorded upon the adoption of SFAS 143 in January 2003 (see discussion below). We identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond at the Bruce Mansfield Plant and two coal ash disposal sites. As a result of adopting SFAS 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 of $415 million. The ARO liability at the date of adoption was $1.11 billion, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, we had recorded decommissioning liabilities of $1.24 billion. We expect substantially all of our nuclear decommis-sioning costs for Met-Ed, Penelec, JCP&L and Penn to be recoverable in rates over time. Therefore, we recognized a regulatory liability of $185 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning for those companies. The remaining cumulative effect adjustment for unrecognized depreciation and accretion, offset by the reduction in the existing decom-missioning liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was a $175 million increase to income, or $102 million net of income taxes. The application of SFAS 143 (excluding the cumulative adjustment described above) resulted in the follow-ing changes to expense categories and net income in 2003:

Effect of SFAS 143 Increase (Decrease) tIn millionsl Other operating expense:

Cost of removal expenditures (previously included in depreciation)

$10 Depreciation:

Elimination of decommissioning expense 1891 Depreciation of asset retirement cost 2

Accretion of asset retirement liability 42 Elimination of removal cost component 116)

ANet decrease to depreciation 1611 Income taxes 21 Net income effect

$30 18:- '.< rove !(,~

a"D;

DISCONTINUED OPERATIONS Discontinued operations for 2004, 2003 and 2002 include FES' natural gas business (see Note 2(J)) which management expects to sell within one year. In 2003 and 2002. discontinued operations were reflected for Emdersa and EGSA, as we substantially completed our exit from for-eign operations acquired through the merger with GPU in 2001. In addition, the results for the FSG subsidiaries, Colonial Mechanical, Webb Technologies and Ancoma, Inc.

and the MARBEL subsidiary, NEO, which were divested in 2003, have been reported as discontinued operations for the years 2003 and 2002. The following table summarizes the sources of income (losses) from discontinued operations:

Discontinued Operations lNet of tax) 2004 2003

. 2002 fi {/millioni).>

Emdersa-abandonment f

-ilios 67)

EGSA - kiss on sale (331 E-Ancorna - loss on sale 131

.Total losses 1103)

Reclassification of operating income (loss) to discontinued operations FES natural gas business 4

(2) 15 Emdersa. EGSk Colonial. Webb, Ancoma and NEO -

2 (80)

Total S 4

$1103)

$165)

POSTRETIREMENT PLANS Strengthened equity markets (reducing pension costs),

as well as amendments to our health care benefits plan in the first quarter of 2004 and the Medicare Act signed by President Bush in December 2003 (reducing OPEB costs) combined to reduce postretirement benefits expenses by

$109 million in 2004 from the prior year. A $191 million increase in benefits expenses in 2003 from 2002 resulted from declines in equity markets in 2001 and 2002 and a reduction in our assumed discount rate in 2002 which increased pension expenses. Also, higher health care pay-ments and a related increase in projected trend rates led to higher OPEB expenses in 2003. The following table reflects the portion of postretirement costs that were charged to expense in 2004, 2003 and 2002.

SUPPLY PLAN Our affiliates are obligated to provide generation service with an estimated power supply of 99.5 billion KWH for 2005. These obligations arise from customers who have elected to continue to receive generation service from our EUOCs under regulated retail rate tariffs and from cus-tomers who have selected FES as their alternate generation provider. Geographically, approximately 63% of the total generation service obligation is for customers located in the MISO market area and 37% for customers located in the PJM market area. Included in the PJM market area are obli-gations of FES to provide power to electric distribution companies in the state of New Jersey, including JCP&L.

FES incurred this obligation as a successful bidder in the State of New Jersey's auction of BGS.

Within the franchise territories of the EUOC, alternative energy suppliers currently provide generation service for approximately 1,800 MW (summer peak) of load with an estimated energy requirement of eight billion KWH. If these alternate suppliers fail to deliver power to their customers located in the EUOC's service areas, the EUOC must pro-cure replacement power in the role of PLR (see Note 2(D) for discussion of the auction of JCP&Us PLR obligation).

JCP&L's costs for any replacement power would be recov-ered under the applicable state regulatory rules.

To meet these generation service obligations, our affili-ates own and operate 13,387 MW of installed generating capacity, which for 2005 is expected to provide approximate-ly 75% of the required power supply. The balance has been secured through a mix of long-term purchases (term of con-tract greater than one year) and short-term purchases (term of contract less than one year). Changes in power supply requirements will be met through spot market transactions.

PJM INTERCONNECTION TRANSACTIONS FES engages in purchase and sale transactions in the PJM Market (see Note 2 (D)) to support the supply of end-use customers, including its BGS obligation in New Jersey and PLR requirements in Pennsylvania. FES meets its supply commitments by transmitting energy into the PJM control area and through bilateral purchased power contracts with counterparties in PJM. FES schedules purchase and sale transactions for each hour in PJM on a day-ahead basis with system balancing occurring real-time. FES sells energy to the PJM Market at the location of its supply (transmitted and con-tracted energy) and purchases energy from the PJM Market at the location of its demand (end-use customer load).

FES accounts for energy transactions in the PJM Market in accordance with EITF 99-19, recognizing purchas-es and sales on a gross basis by recording each discrete transaction (see Note 2(D)). This presentation may not be comparable to other energy companies that have dedicated generating capacity in ISOs or fail to meet the criteria for gross presentation in EITF 99-19.

o s t e I e e t E p n e. n o m e)..

Postretirement Expenses (Income) 2004 20-03 20 I

02 fIn millions)

Pension S 83

$123

$11 OPEB 87 156 10 Total

$170 S 279

$ 8

4) r2,.

1141 Pension and OPEB expenses are included in various cost categories and have contributed to cost decreases in 2004, discussed above. The $500 million voluntary contribu-tion made in 2004 is expected to result in a reduction in pension costs in 2005, 2006 and 2007 compared to the level they would have been without the voluntary contribu-tion. Including the effect of higher interest costs resulting from funding the voluntary contribution, earnings per share are expected to benefit by approximately $0.06 in each of the next three years. See "Critical Accounting Policies -

Pension and Other Postretirement Benefits Accounting" for a discussion of the impact of underlying assumptions on postretirement expenses.

F.: r w O.

a: O :.J'9; 1 19

RESULTS OF OPERATIONS - BUSINESS SEGMENTS We have three reportable segments: regulated services, competitive electric energy services and facilities (HVAC) services. The aggregate "Other" segments do not individually meet the criteria to be considered a reportable segment.

"Other" consists of international businesses that have subsequently been divested, MYR (a construction service company); natural gas operations and telecommunications services. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as "reportable seg-ments." FirstEnergy's primary segment is its regulated services segment, whose operations include the regulated sale of electricity and distribution and transmission services by its eight EUOC in Ohio, Pennsylvania and New Jersey.

The competitive electric energy services business segment primarily consists of the subsidiaries (FES, FGCO and FENOC) that sell electricity in deregulated markets and operate the generation facilities of OE, CEI, TE and Penn resulting from the deregulation of the Companies' electric generation business (see Note 2(A) - Accounting for the Effects of Regulation).

The regulated services segment designs, constructs, operates and maintains our regulated transmission and distribution systems. Its revenues are primarily derived from electricity delivery and transition costs recovery. The regulated services segment assets include generating units that are leased to the competitive electric energy services.

Its internal revenues represent the rental revenues for the generating unit leases.

The competitive electric energy services segment has responsibility for our generation operations as discussed under Note 2(A) to the consolidated financial statements.

Its net income is primarily derived from revenues from all electric generation sales consisting of generation services to regulated franchise customers who have not chosen an alternative generation supplier, retail sales in deregulated markets and all domestic unregulated electricity sales in the retail and wholesale markets and the related costs of elec-tricity generation and sourcing of commodity requirements.

Its net income also reflects the expense of the interseg-ment generating unit leases discussed above and property tax amounts related to those generating units.

Segment reporting for 2003 and 2002 was reclassified to conform with the current year business segment organi-zation and operations emphasizing our regulated electric businesses and competitive electric energy operations.

A previous reportable segment was the more expansive competitive services segment whose aggregate operations consisted of our generation operations, natural gas com-modity sales, providing local and long-distance phone service and other competitive energy related businesses such as facilities services and construction service (MYR) which was viewed as offering a comprehensive menu of energy related services. Management's focus is now on our core electric business. This has resulted in a change in per-formance review analysis from an aggregate view of all competitive services operations to a focus on its competi-tive electric energy operations. During our periodic review of reportable segments under SFAS 131, that change resulted in the revision of reportable segments to the separate reporting of competitive electric energy operations, facilities services and including all other competitive services opera-tions in the "Other" segment. Facilities services is being disclosed as a reporting segment due to the subsidiaries qualifying as held for sale (see Note 2 (J)). In addition, cer-tain amounts (including transmission and congestion charges) were reclassified among purchased power, other operating costs and depreciation and amortization to con-form with the current year presentation of generation commodity costs. Interest expense on holding company debt and corporate support services revenues and expenses are now included in "Reconciling Items" and "Other" includes those operating segment results discussed above.

Financial results discussed below include revenues and expenses from transactions among our business segments.

A reconciliation of segment financial results to consolidated financial results is provided in Note 14 to the consolidated financial statements. Net income (loss) by business seg-ment was as follows:

Net Income (Loss) By Business Segment 2004 2003 2002 fin millions)

Segments:

- Regulated services

$1.015 O

$1.164

$962 Competitive electric energy services 104 (3201 (170)

Facilities services 136) 181) 3 Other 45 1160)

(47)

Reconciling Items.

(2501 (180)

(195)

Total

$ 878 S 423

$553

. Includes interest expense on holding company debt corporate support services revenues and expenses and otherreconciling items.

Regulated Services - 2004 versus 2003 Financial results of the regulated services segment were as follows:

Increase

-Regulated Services 2004 2003 (Decrease) tin millions)

. Total revenues

$5,713

$5.572

$141 Income before cumulative effect of accounting change 1.015 1.063 (48)

Net income 1.015 1,164 (149)

The change in operating revenues resulted from the following sources:

i Increase Sources of Revenue Changes 2.04 2003 (Decrease)

(In millions)

Electric sales 4.70i

$4,787

$ 186)

Other revenues:

External sales 694.

466 228 Internal sales 318 319 (1)

Total Revenues

$5,713

$5.572

$141 The net increase in operating revenues resulted from:

• A decrease of $86 million in retail sales - a $60 mil-lion reduction in revenues from distribution deliveries and a $26 million increase in the credits for shopping incentives to customers; and

• A $228 million increase in other revenues primarily 20 Firtf;Inf-9W CcrLo 2004

due to higher transmission revenues and, to a lesser extent, earnings recognized on decommissioning trust investments (see Note 5 - Investments).

Income before discontinued operations and the cumula-tive effect of an accounting change decreased $48 million.

In addition to the above changes in revenue, the following factors contributed to the change:

• The absence in 2004 of the earnings benefit of the 2003 settlement of our claim against NRG for the ter-minated sale of four fossil plants, which resulted in a

$168 million gain;

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

• Additional MISO and PJM transmission costs of $238 million related to the transmission component of other revenue discussed above.

Partially offsetting those factors were:

• Lower energy delivery expenses (net of refunds to third-party suppliers) of $71 million due to reduced storm restoration costs in 2004, a higher level of con-struction activities in 2004 compared to a higher level of maintenance activities in the prior year and distribution reliability expenses incurred in the third quarter of 2003;

• Lower interest charges of $130 million primarily related to debt and preferred stock redemption and refinancing activities and pollution control note repricings; and

• Reduced income taxes of $38 million primarily reflect-ing reduced taxable earnings.

Regulated Services - 2003 versus 2002 Financial results for regulated services were as follows:

Increase Regulated Services 2003 2002 IDecrease)

• in millions)

Total revenues

$5,572

$5,616

$ (44)

Income before cumulative effect of accounting change 1.063 962

-101 Net income.

1,164 962

• 202 The change in operating revenues resulted from the following sources:

- Increase Sources of Revenue Changes 2003 200 (Decrease),

ein millions)

Electric sales

$4,787

$4,872

..$(85 Other revenues:

Externalsales 466 426 40 Internal sales 319 318 1

Total Revenues S5,572 55.616

-5441 The net decrease in operating revenues resulted from:

• A decrease of $85 million in retail sales - a $40 million reduction in revenues from distribution deliveries and a $45 million increase in the credits for shopping incentives to customers; and

• A net $40 million increase in other revenues due in part to JCP&L TBC revenue and jobbing and contract-ing revenue.

Income before discontinued operations and the cumula-tive effect of an accounting change increased $101 million.

The following factors offset the lower revenues and con-tributed to the net increase in income:

• Settlement of our claim against NRG for the terminat-ed sale of four fossil plants which resulted in our recording a $168 million pre-tax credit to earnings;

• Lower interest charges of $95 million primarily related to debt and preferred stock redemption and refinanc-ing activities and pollution control note repricings; and

• The absence of unusual charges recognized in 2002 of $6 million.

Partially offsetting the above sources of improved earnings were four factors:

• Increased energy delivery costs of $41 million princi-pally due to storm restoration expenses and an accelerated reliability program within JCP&L's service territory;

• A net increase in depreciation and amortization expense of $9 million resulting from additional amorti-zation of regulatory assets offset in part by reduced depreciation;

• Additional MISO and PJM transmission costs of $29 million related to the transmission component of other revenue; and

• Increased income taxes of $57 million primarily reflecting higher taxable earnings.

Competitive Electric Energy Services - 2004 versus 2003

• Financial results for competitive electric energy services were as follows:

Compethive Electric Energy Services 2004 2003 Increase (In millions)

Total revenues

$6.204

$5.487

$717 Net income (loss) 104 (3201 424 The change in total revenues resulted from the following sources:

Sources of Revenue Changes 20W4 20M Increase (In millions)

Electric sales

$6.130

$5.418

$712 Otherrevenues 74 69 5

Total Revenues

$6.204

$5,487

$717 The net increase in electric sales resulted from:

• Higher retail generation sales from customer choice programs ($71 million) and EUOC regulated cus-tomers ($19 million); and

• Increased FES wholesale revenues of $680 million offset in part by a $58 million decrease in sales to EUOC wholesale customers.

The gross generation margin increased $402 million as electric generation revenues increased at a greater rate than the related costs of fuel and purchased power. Higher elec-tric generation revenues resulted from increased sales to both retail and wholesale customers. Excluding the impact F rr wt 5,f

'- ( )- '-;

21

of the July 2003 JCP&L rate decision, the gross generation margin increased $249 million, reflecting the benefit of increased sales and the availability of additional lower-cost nuclear generation.

Net income increased $424 million. In addition to the improved gross generation margin discussed above, the fol-lowing factors contributed to the increase in earnings:

• Lower nuclear expenses of $169 million primarily as a result of one scheduled refueling outage at Beaver Valley Unit 1 in 2004 compared to three scheduled refueling outages in 2003 (Beaver Valley Unit 1, Beaver Valley Unit 2 and Perry) and reduced incre-mental maintenance costs at the Davis-Besse Nuclear Power Station related to its restart; and

• Reduced fossil generation expenses of $49 million due to less maintenance in 2004 compared to the prior year.

Partially offsetting the above sources of improved earn-ings were increased income taxes of $294 million reflecting higher taxable earnings.

Competitive Electric Energy Services - 2003 versus 2002 Financial results for competitive electric energy services were as follows:

were partially offset by lower maintenance costs at the Davis-Besse Nuclear Power Station; and

• Planned maintenance outages at three of our fossil generating plants during the fourth quarter of 2003 increased non-nuclear operating expenses by approxi-mately $25 million.

Partially offsetting the above sources of lower earnings were reduced income taxes of $134 million reflecting lower taxable income.

Facilities Services - 2004 versus 2003 Financial results for facilities services were as follows:

Facilities Services 2004 2003 Increase (Decrease)

(In millions)

Total revenues 398

$327

$71 Net loss 36 81 145)

Revenue increased $71 million or 22% in 2004 com-pared to 2003 reflecting stronger market conditions. Losses from FSG goodwill impairment dominated financial results in 2004 and 2003 resulting in non-cash, pre-tax charges to earn-ings of $36 million and $117 million, respectively (see Note 2 (H)). The impairment in 2003 was identified during our annual assessment of goodwill and in 2004 from an analysis per-formed at year-end when a firm decision was made to divest all FSG assets. Excluding the after-tax impact of the goodwill impairments FSG experienced net income in 2004 of $1 mil-lion, following a $255,000 loss in 2003.

Facilities Services - 2003 versus 2002 Financial results for facilities services were as follows:

. Competitive Electric Energy Services 2003 2002 Increase (In millions)

Total revenues

$5,487

$4,825

-$ 662 Net loss 320 170

.150:

The change in total revenues resulted from the following sources:

Sources of Revenue Changes 2003 2002 Increase (in millions)

Electric sales 55.418

$4.784

$634 Other revenues 69 41 28

$5.487

$4,825

$662 The net increase in electric sales resulted from increased FES wholesale revenues of $575 million and increased sales to EUOC wholesale customers of $59 million.

The gross generation margin decreased $215 million as fuel and purchased power costs increased more rapidly than related electric generation revenue. Excluding the unusual charge from the July 2003 JCP&L rate decision, the gross generation margin decreased $62 million, reflecting higher fuel and purchased power costs. Purchased power costs increased due to higher unit costs and additional quantities purchased. Increased volumes were required to supply obli-gations assumed and to replace reduced nuclear generation.

In addition to the reduced gross generation margin dis-cussed above, the following factors contributed to the increase in the net loss:

Higher nuclear expenses of $54 million as a result of an additional scheduled nuclear refueling outage in 2003 and unplanned work performed during the scheduled refueling outages at the Perry Plant and Beaver Valley Unit 1. The higher production costs

. Facilities Services

2003 2002 (Decrease)

(-In millions)

Total revenues S327

$383

$556)

Net income Iloss)

(81) 3 (84)

Revenues decreased $56 million or 15% in 2003 prima-rily reflecting depressed market conditions and reduced customer maintenance services due to mild weather. The loss in 2003 resulted principally from the effect of the $117 million pre-tax charge (discussed above). Excluding the effect of the goodwill impairment, after-tax earnings decreased $3 million in 2003 compared to 2002.

CAPITAL RESOURCES AND LIQUIDITY Our cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and pre-ferred stock redemptions were met without increasing our net debt and preferred stock outstanding. During 2005, we expect to meet our contractual obligations primarily with cash from operations. Thereafter, we expect to use a combination of cash from operations and funds from the capital markets.

Changes In Cash Position The primary source of ongoing cash for FirstEnergy, as a holding company, is cash dividends from its subsidiaries. The 22 rri p 2?i'-

holding company also has access to $1.375 billion through revolving credit facilities. In 2004, FirstEnergy received $782 million of cash dividends on common stock from its sub-sidiaries and paid $491 million in cash dividends on common stock to its shareholders. There are no material restrictions on the payments of cash dividends by our subsidiaries.

As of December 31, 2004, we had $53 million of cash and cash equivalents, compared with $114 million as of December 31, 2003. Cash and cash equivalents as of December 31, 2003 included $32 million received in December 2003 from the NRG settlement claim sold in January 2004. The major sources for changes in these bal-ances are summarized below.

Cash Flows From Operating Activities Our consolidated net cash from operating activities is provided primarily by our regulated and competitive electric energy businesses (see Results of Operations - Business Segments above). Net cash provided from operating activi-ties was $1.877 billion in 2004, $1.755 billion in 2003 and

$1.932 billion in 2002, summarized as follows:

Operating Cash Flows 2004 203M 2002 Increase (Decrease) fIn millions)

Cash earnings (-

$2.168

$1,825'

$1,640 Pension trust contributionr2) 1300 '

Working capital and other 9

(701 292 Total S1.877

$1,755.

S1.932 1I)

Cash earnings are a non-GAAP measure (see reconciliation belowl) 0 Pension trust contribution net of $200 million of income tax benefits Cash earnings (in the table above) is not a measure of performance calculated in accordance with GAAR We believe that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating our cash-based operating performance. The fol-lowing table reconciles cash earnings with net income.

Reconciliation of Cash Earnings 2004 2003 2002 (In millions)

Net Income (GAAP S 878 S 423 S553 Non-Cash Charges (Credits Provision for depreciation 590 607 722 Amortization of regulatory assets 1.166 1.079 941 Deferral of new regulatory assets 257)

(1941

'1184);

Nuclear fuel and lease amortization 96 66 81 Deferred costs recoverable as regulatory assets 1417)

(427) '1544)

Deferred income taxes 58 54 77 Goodwill Impairment 36 117,'!

Disallowedregulatoryassets 153 Cumulative effect of accounting change (1751 -

Other non-cash expenses 18 122

- - (61 Cash Earnings(Non-GAAP)

SZ168

$1.825 51.640

' Excludes $200 million of deferred tax benefit from pension contribution in 2004.

Net cash provided from operating activities increased

$122 million in 2004 compared to 2003 due to a $343 mil-lion increase in cash earnings as described under "Results of Operations" and a $79 million increase from changes in working capital, partially offset by a $300 million after-tax voluntary pension trust contribution. The working capital increase resulted in part from changes of $88 million in receivables, $78 million in prepayments and other current assets, $59 million in payables and a $53 million NUG power contract restructuring transaction, partially offset by a

$237 million decrease in accrued tax balances. Net cash pro-vided from operating activities decreased $177 million in 2003 compared to 2002 due to a $362 million decrease in working capital partially offset by a $185 million increase in cash earnings, as described above under "Results of Operations." The working capital decrease primarily resulted from changes of $388 million in payables and $165 million in prepayments and other current assets, partially offset by a

$196 million increase in accrued tax balances.

Cash Flows From Financing Activities In 2004, 2003 and 2002, net cash used for financing activities of $1.457 billion, $1.298 billion and $1.138 billion, respectively, primarily reflected the redemptions of debt and preferred stock shown below. The following table provides details regarding new issues and redemptions during 2004, 2003 and 2002:

Securities Issued or Redeemed 2004 2003 2002 (In millions)

New Issues:

Common stock S

S 934 S

Pollution control notes 261 158 Senior secured notes 300 400 370 Unsecured notes 400 627 140

$ 961

$1.961 S 668 Redemptions:

First mortgage bonds

$ 589 S1.483 S 728 Pollution control notes 80 238 93 Senior secured notes -

471 323 278 Long-term revolving credit 95 85 Unsecured notes 337 210 Preferred stock 2

127 522

$1.574

$2,256

$1,831 Short-term borrowings, net

$(3511 5(575)

$ 479 Net cash used for financing activities increased by $159 million in 2004 from 2003. The increase resulted primarily from the absence of a $934 million common equity financ-ing in 2003 and a $37 million increase in common stock dividends partially offset by an $840 million decrease in net redemption of preferred securities and debt. Net cash used for financing activities in 2003 increased $160 million from 2002. The increase in cash used for financing activities resulted primarily from an increase in net redemptions of debt and preferred securities of $1.1 billion partially offset by the common equity financing in 2003.

We had approximately $170 million of short-term indebtedness at the end of 2004 compared to approximately

$522 million at the end of 2003. Available borrowing capabil-ity as of December 31, 2004 included the following:

Borrowing Capability FirstEnergy. CE Total (In millions)

Long-term revolving credit

$1,375

$375

$1.750 Utilized (215) 1215)

Letters of credit (135)

(135)

Net 1.025 375 1.400 Short-term bank facilities 34 34 Utilized.

(21)

(21)

Net-13 13 Total Unused Borrowing Capability, S 1.025

$388

$1,413

,, c

, ', r '"6 a, C n,

23

At the end of 2004, the Ohio Companies and Penn had the aggregate capability to issue approximately $4.4 billion of additional FMB on the basis of property additions iind retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE and CEI are also subject to provisions of their senior note indentures general-ly limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) Ci) sup-porting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously out-standing secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not oth-erwise permitted by a specified exception of up to $641 million and $588 million, respectively, as of December 31, 2004. Under the provisions of its senior note indenture, JCP&L may issue additional FMB only as collateral for sen-ior notes. As of December 31, 2004, JCP&L had the capability to issue $644 million of additional senior 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 $4.5 billion of preferred stock (assuming no additional debt was issued) as of the end of 2004. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock (see Note 10(C) - Long-Term Debt and Other Long-Term Obligations for a discussion of debt covenants).

As of December 31, 2004, approximately $1.0 billion remained under FirstEnergy's shelf registration statement, filed with the SEC in 2003, to support future securities issues. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, and share purchase contracts and related share purchase units.

At the end of 2004 and 2003, our common equity as a percentage of capitalization stood at 45% compared to 38%

at the end of 2002. The higher common equity percentage in 2004 and 2003 compared to 2002 reflects net redemptions of preferred stock and long-term debt, and the increase in retained earnings.

Our working capital and short-term borrowing needs are met principally with a syndicated $1 billion three-year revolv-ing credit facility maturing in June 2007. Combined with our syndicated $375 million three-year facility maturing in October 2006, a $125 million three-year facility for OE maturing in October 2006, and a syndicated $250 million two-year facility for OE maturing in May 2005, our primary syndicated credit facilities total $1.75 billion. These revolving credit facilities, combined with an aggregate $550 million of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet our short-term working capital requirements and those of our subsidiaries. Total unused borrowing capability under existing facilities and accounts receivable financing facilities totaled $1.7 billion as of December 31, 2004.

Borrowings under these facilities are conditioned on maintaining compliance with certain financial covenants in the agreements. FirstEnergy and OE are each required to maintain a debt to total capitalization ratio of no more than 0.65 to 1 and a contractually defined fixed charge coverage ratio of no less than 2 to 1. As of December 31, 2004, FirstEnergy's and OE's fixed charge coverage ratios, as defined under the credit agreements, were 4.48 to 1 and 7.15 to 1, respectively. FirstEnergy's and OE's debt to total capitalization ratios, as defined under the credit agreements, were 0.55 to 1 and 0.39 to 1, respectively. FirstEnergy and OE are in compliance with these financial covenants. The ability to draw on each of these facilities is also conditioned upon FirstEnergy or OE making certain representations and warranties to the lending banks prior to drawing on their respective facilities, including a representation that there has been no material adverse change in their business, condition (financial or otherwise), results of operations, or prospects.

Neither FirstEnergy's nor OE's primary credit facilities contain any provisions that either restrict their ability to bor-row or accelerate repayment of outstanding advances as a result of any change in their credit ratings. Each primary facility does contain "pricing grids", whereby the cost of funds borrowed under the facility is related to the credit rat-ings of the company borrowing the funds.

Our regulated companies have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but sepa-rate arrangement exists among our unregulated companies.

FESC administers these two money pools and tracks sur-plus funds of FirstEnergy.and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. For the regulated companies, available bank borrowings include $1.75 billion from FirstEnergy's and OE's revolving credit facilities. For the unregulated com-panies, available bank borrowings include only FirstEnergy's

$1.375 billion of revolving credit facilities. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2004 was 1.43% for the regulated companies' money pool and 1.55% for the unregulated companies' money pool.

Our access to capital markets and costs of financing are influenced by the ratings of our securities. The following table shows our securities ratings as of December 31, 2004.

The ratings outlook from the ratings agencies on all securi-ties is stable.

24 ~

.,- i-f c,

I

..Y31

Ratings of Securities Securities S&P Moody's Fitch FirstEnergy Senior unsecured BB+

Baa3 BB8-.

COE Seniorsecured BBB Baal BBB+

Senior unsecured BB+

Baa2 W.

888 Preferred stock BB Bal

'BBB-CEI Senior secured BBS-Baa2 BBB-.

Senior unsecured BB+

'Baa3 BB Preferred stock BB Ba2 B-TE Senior secured BBB-Baa2 BBB-Senior unsecured BB+

Baa3 BB Preferred stock BB Ba2 BB-Penn Senior secured BB BUat BBB+

Senior unsecuredI BB+

Baa2 BBB Preferred stock.

BB Bal BBB-JCP&L Senior secured BBB+

Baal

+BBB Preferred stock BB Bal BBB Met-Ed Senior secured B8 Baal B8+

Senior unsecured BBB-Baa2 688 Penelec Senior secured BBB Baal BB6+

Senior unsecured -BBB-

.Baa2 8-8

11) Penns only senior unsecured debt obligations are notes underlying pollution crontireenue refunding bonds issued by the Ohio Air Duality Development Authority to which bonds this rating applies.

On December 10, 2004, S&P reaffirmed our 'BBB-corpo-rate credit rating and kept the outlook stable. S&P noted that the stable outlook reflects our improving financial profile and cash flow certainty through 2006. S&P stated that should the two refueling outages at the Davis-Besse and Perry nuclear plants scheduled for the first quarter of 2005 be completed suc-cessfully without any significant negative findings and delays, our outlook would be revised to positive. S&P also stated that a ratings upgrade in the next several months did not seem likely, as remaining issues of concern to S&P, primarily the outcome of environmental litigation and SEC investigations, are not likely to be resolved in the short term.

Cash Flows From Investing Activities Net cash flows used in investing activities resulted principal-ly from property additions. Regulated services expenditures for property additions primarily include expenditures supporting the distribution of electricity. Capital expenditures by the competitive electric energy services segment are principally generation-relat-ed. The following table summarizes 2004 investments by our regulated services and competitive services segments:

Summary of Cash Flows Property Used for Investing Activities Additions Investments Other Total 2004 Sources (Uses) tin millions)

Regulated services S(572)

$181 S (88)

.5(479)

Competitive electric energy services (246) 16 12 r (232)

Facilities services (31 2

-- -(1)

Other (4) 184 (61 174 Reconciling items 1211 (22) 100 57

.Total 5(8461

$359

$ 6

1481) 2003 Sources (Uses)

Regulated services

$.434) -

$105

$ 16

$1313)

Competitive electric energy services (335)

(32) 8 (359)

Facilities services 4,

(4) 61 (70.

(131 Other (9) 46

'116

. 153 Reconciling items (74) 28 9

1 (37)

Total

$18561 $208

$ 79

$(569) 2002 Sources (Uses)

Regulated services

$1490)

$ 27 S 2

$1461).

Competitive electric energy services (391)

(251 (4161 Facilities services (6)

( 16)

Other I(91 96-

43.

130 Reconciling items (102)

(401 62 (80)

Total

$1998)

$ 83 S 82

.$18331 Net cash used for investing activities in 2004 decreased by $88 million from 2003. The decrease was primarily due to $278 million in cash proceeds from certificates of deposit received in the third quarter of 2004 partially offset by a

$117 million change in NUG trust activity. Net cash used for investing activities in 2003 decreased by $264 million from 2002. The decrease was primarily due to a $142 million decrease in property additions and a $174 million increase in cash payments on long-term notes receivable.

Our capital spending for the period 2005-2007 is expected to be about $3.3 billion (excluding nuclear fuel),

of which $979 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $268 million, of which about

$53 million applies to 2005. During the same period, our nuclear fuel investments are expected to be reduced by approximately $280 million and $90 million, respectively, as the nuclear fuel is consumed.

CONTRACTUAL OBLIGATIONS Contractual Obligations As of December 31, 2004, our estimated cash payments under existing contractual obligations that we consider firm obligations are as follows:

2006-2008-Contractual Obligations Total 2005 2007

.2009 Thereafter fin millions)

Long-terrndebtn

$10,890

$ 710

$1,565 S 622

$ 7.993

.Short-term borrowings 170 170 Preferred stocktll 17 2

14 1

Capitalleases 19 5

6 2

6 Operating leases 12) 362

.183 349.

376 1.454 Pension funding M Fuel and purchased power 14) 13.765 2,464 4.184 3.148 3.969 Total.

$27.223

$3,534

$6.118

$4,149

$13.422

(: tSubject to mandator/nedemption.

0 See Note 6 to the consolidatedfi'ancialstatements.

tD We estimate that no turtherpension contributions will be required through 2009 to maintain ourdefinedbenefitpensionplank funding ata minimum required level as determined by government regulations. We are unable to estimate projected contributions beyond2009. See Note 3 to the consolidated financialstatements.

w4JAmounts under contract with fixed orminimum quantities andapproximate timing.

51 Amounts reflected do not include interest on long-term debt.

Guarantees and Other Assurances As part of normal business activities, we enter into various agreements on behalf of our subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds, and LOCs. Some of the guaranteed contracts contain ratings contingent collateralization provisions.

As of December 31, 2004, our maximum exposure to potential future payments under outstanding guarantees and other assurances totaled approximately $2.4 billion, as summarized below:

Uovu-,, Cc.,;,,
:X; ' 25

Guarantees and Other Assurances Maximum Exposure

[I. n millions),:.

FirstEnergy Guarantees of Subsidiaries Energy and Energy-Related Contracts III

$ 878 Otherm-149 1,027 Surety Bonds 279 LOC InM) 1.098 Total Guarantees and Other Assurances 52,404

(') Issued fora one-year term, with a 10-day termination right by FirstEnergy.

,) Issued for various terms.

t Includes $135 million issued for various terms under lOC capacity available in FirstEnergys revolving credit agreement and $299 million outstanding in support of pollution control revenue bonds issued with various maturities t Includes approximately $216 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by CEI and [E. $294 million pledged in connection with the sale and leaseback ofBeaver Valley Unit 2by OEand$154 million pledged in connection with the sale and leaseback of Perry Unit 1 byOE We guarantee energy and energy-related payments of our subsidiaries involved in energy commodity activities -

principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. We also pro-vide guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equip-ment. These agreements legally obligate us to fulfill the obligations of our subsidiaries directly involved in these energy and energy-related transactions or financings where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, our guarantee enables the counterparty's legal claim to be satisfied by our other assets. The likelihood that such parental guarantees will increase amounts otherwise paid by us to meet our obli-gations incurred in connection with ongoing energy and energy-related contracts is remote.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obliga-tions, subsequent to the occurrence of a credit rating downgrade or "material adverse event" the immediate post-ing of cash collateral or provision of an LOC may be required of the subsidiary. The following table summarizes collateral provisions in effect as of December 31, 2004:

Total Collateral Paid Remaining

-Collateral Provisions Exposure Cash LOC Exposuren)

(lnmillions)

Credit rating downgrade

$349

$162

$ 18

$169 Adverseevent 135

.- 22

..113 Total

$484

$162

$40

-.$282 UAAs of February 7, 2005 our total exposure decreased to $476 million and the remaining exposure increased to $290 million -net of $146 million of cash.

collateral and $40 million of LOC collateralprovided to counterparties.

Most of our surety bonds are backed by various indem-nities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to out-side parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

We have guaranteed the obligations of the operators of the TEBSA project up to a maximum of $6.0 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. We have also provided an LOC (current-ly at $47 million), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

OFF-BALANCE SHEET ARRANGEMENTS We have obligations that are not included on our Consolidated Balance Sheets related to the sale and lease-back arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are reflected as part of the operating lease payments disclosed above (see Notes 6 and 7). The present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.4 billion as of December 31, 2004.

CEI and TE sell substantially all of their retail customer receivables to CFC, a wholly owned subsidiary of CEL. CFC subsequently transfers the receivables to a trust (a "qualified special purpose entity" under SFAS 140) under an asset-backed securitization agreement. This arrangement provided

$84 million of off-balance sheet financing as of December 31, 2004. See Note 12 to the consolidated financial state-ments for additional information regarding this arrangement.

We have equity ownership interests in various busi-nesses that are accounted for using the equity method.

There are no undisclosed material contingencies related to these investments. Certain guarantees that we do not expect to have a material current or future effect on our financial condition, liquidity or results of operations are dis-closed above as contractual obligations.

MARKET RISK INFORMATION We use various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. Our Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk manage-ment activities throughout the company. They are responsible for promoting the effective design and imple-mentation of sound risk management programs. They also oversee compliance with corporate risk management poli-cies and established risk management practices.

Commodity Price Risk We are exposed to market risk primarily due to fluctua-tions in electricity, natural gas, coal, nuclear fuel and emission allowance prices. To manage the volatility relating to these exposures, we use a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used prin-cipally for hedging purposes and, to a much lesser extent, for trading purposes. Most of our non-hedge derivative con-tracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during 2004 is summarized in the following table:

26 s

t*,x,-,

"o:,,

Increase (Decrease) In the Fair Value of Derivative Contracts Change In the fair value of commodity derivative contracts.

Outstanding net asset as of January 1. 2004 New contract value when entered Additions/change in value of existing contrac

.Change In technioues/assumotions Non-Hedge

-Hedge Total (In millions).'

I S67

$12 S79 cts (4) 6:

2 Settled contracts (1)

(16) :.

17)

Outstanding net asset asofDecember31 20041

62 2

.64 Non-commodity net assets -

as of December 31 2004:

Interest rate swaps 4

.4 Net Assets - Derivatives Contracts as of December 31. 2004 S62 S 6 68 Impact of Changes in Commodity Derivative Contracts CO Income Statement Effects (Pre-Tax)

S15)

S (5)

Balance Sheet Effects:

OCI (Pre-Tax)

$(10) 5(10)

(1) Includes $61 million in non-hedge commodity derivative contracts, which are offset bya regulatory liability.

M Interest rate swaps are primarily treated as fair value hedges. Changes in derivative values of the fair value hedges are offset by changes in the hedged debts'premium or discount (see Interest Rate Swap Agreements below).

c3J Represents the increase In value of existing contracts, settled contracts and changes in techniques/assumptions.

Derivatives are included on the Consolidated Balance Sheet as of December 31, 2004 as follows:

Non-Hedge Hedge Total (In millions)

Current-Otherassets

$2 S 2

$S4 Other liabilities (2)-

(1)

(3)

Non-Current-Other deferred charges 62 15 77 Other noncurrent liabilities

-10)

(101 -

Netassets

$62

$ 6

$ 68 The valuation of derivative contracts is based on observ-able market information to the extent that such information is available. In cases where such information is not available, we rely on model-based information. The model provides estimates of future regional prices for electricity and an esti-mate of related price volatility. We use these results to develop estimates of fair value for financial reporting purpos-es and for internal management decision making. Sources of information for the valuation of commodity derivative con-tracts by year are summarized in the following table:

Source of Information-Fair Value by Contract Year 2005 2006 207 2008 Thereafter Total

-In millions)

Prices activelyquoted IIl S 2 S 1 5-5-

S 3 Otherexternalsourcesl 2t 17 10 27 Prices based on models 10 9

.15 34 Total' m

$19

$11

$10

$9

$15

$64 R/ Exchange traded.

0 Broker quote sheets.

PlIncludes$61 million from an embeddedoption thatisoffsetbyaregulatory liability and does not affect earnings.

We perform sensitivity analyses to estimate our expo-sure to the market risk of our commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on both our trading and nontrading derivative instruments would not have had a material effect on our consolidated financial position or cash flows as of December 31, 2004. We estimate that if energy commodity prices experienced an adverse 10% change, net income for the next twelve months would decrease by approximately

$3 million.

Interest Rate Risk Our exposure to fluctuations in market interest rates is reduced since a significant portion of our debt has fixed interest rates, as noted in the table below.

Comparison of Carrying Value to Fair Value

-There-Year of Maturity 2005 2006 200722008 2009 after Total Assets:

(in millions)

Investments other than Cash and Cash E alents-HxedrInome

$73

$82 S77 $ 57

$68 S1.729 $2.086

• Average interest rate 6.8% 7.8' 7.9% 7.7% 7.8$

6.0'

6.3 liabilities

Long-term Debt and Other Long-term Obligations:

Fixed rate IIl

$495 $1,327 $238 $338 $284 $6,674 $9,356 Average interest rate 7.4%

5.7$ 6.6' 5.3' 6.8' 6.5' 6.4 Variable rate 1a)

$215

$1,319 $1.534 Average interest rate 3.6 2.2%

2.4

Preferred Stock Subject to Mandatory Redemption

$2

-$2

$12

$1

$17 Average dividend rate 7.5%

7.5% 7.6' 74%

7.6 Short-term Borrowings

$170

$170 Average interest rate 2,4' 2.4 c(lealances andrates do not reflect the fixed-to-floating interest rate swap agreements discussed below.

Fair I Value 6 $2,243

$9.915

$1,53a

$16

$170 We are subject to the inherent interest rate risks relat-ed to refinancing maturing debt by issuing new debt securities. As discussed in Note 6 to the consolidated finan-cial statements, our investments in capital trusts effectively reduce future lease obligations, also reducing interest rate risk. While fluctuations in the fair value of our Ohio Companies' decommissioning trust balances will eventually affect earnings (affecting OCI initially) based on the guid-ance provided by SFAS 115, our non-Ohio EUOC have the opportunity to recover from customers, or refund to cus-tomers, the difference between the investments held in trust and their decommissioning obligations. Thus, there is not expected to be an earnings effect from fluctuations in their decommissioning trust balances. As of December 31, 2004, decommissioning trust balances totaled $1.583 billion, with $975 million held by our Ohio Companies and the bal-ance held by our non-Ohio EUOC. As of year-end 2004, trust balances of our Ohio Companies were comprised of 64%

equity securities and 36% debt instruments.

Interest Rate Swap Agreements We have utilized fixed-to-floating interest rate swap agreements, as part of our ongoing effort to manage the interest rate risk of our debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues - protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and s;:{;-CO". I>~

2z

interest payment dates match those of the underlying obli-gations. During the fourth quarter of 2004, in a period of declining interest rates, we unwound swaps with a total notional amount of $400 million. We received $12 million in cash gains from unwinding the swaps and interest expense will be reduced by that amount over the term of the related hedged debt. Due to the differences between fixed and vari-able debt rates, interest expense in 2004 and 2003 was reduced by $37 million and $27 million, respectively. We increased the total notional amount of outstanding interest rate swaps to $1.65 billion as of December 31, 2004, from

$1.15 billion at the end of 2003 from cumulative swap activi-ties. As of December 31, 2004, the debt underlying the interest rate swaps had a weighted average fixed interest rate of 5.53%, which the swaps have effectively converted to a current weighted average variable interest rate of 3.42%.

Fixed to Floating Rate Interest Rate Swaps IFair value hedges)

December 31,2004 December 31,2003 Notional Maturity Fair Notional Maturity

. Fair.

Amount Date Value Amount Date Value (Dollars in millions) 5200 2006

$(1)

V200 2006 S 1.:

100 2008 (1I 50 2008 100 2010 1

100 2010 1

100 2011 2

100 2011 I1 400 2013 4

350 2013 (1)..

100 2014 2

150 2015 (7) 150 2015 (101, 200 2016 1

150 2018 5

150 2018 1

50 2019.

.2 50 2019 A1 100 2031 (4) sented 7% of our total credit risk. Within our unregulated energy subsidiaries, 99% of credit exposures, net of collat-eral and reserve, were with investment-grade counterparties as of December 31, 2004.

REGULATORY MATTERS In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the Companies' respective state regula-tory plans. These provisions include:

• restructuring the electric generation business and allowing the Companies' customers to select a com-petitive electric generation supplier other than the Companies;

• establishing or defining the PLR obligations to cus-tomers in the Companies' service areas;

• providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;

• itemizing (unbundling) the price of electricity into its component elements - including generation, trans-mission, distribution and stranded costs recovery charges;

• continuing regulation of the Companies' transmission and distribution systems; and

• requiring corporate separation of regulated and unreg-ulated business activities.

The EUOC recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recov-ery 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 expect-ed 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 distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those opera-tions. Regulatory assets that do not earn a current return totaled approximately $240 million as of December 31, 2004.

Increase Regulatory Assets As of December 31 2004 2003 (Decrease)

(In millions)

OE 1.116 51,451 S (335)

CEI 959 1,056 (97)

TE 375 459 1841

.Penn' 28 1281 JCP&L 2,176 2.558 (382)

Met-Ed 693 1.028 (3351 Penelec 200 497 (297)

ATSI 13 13

.Total 55.532 57.077 n 1.545)

Changes in Penn's net regulatory asset components In 2004 resulted in net regulatory liabilities of approximately S18 million included in Other Noncurrent Liabilities on the Consolidated Balance Sheet as of December31. 2004.

Equity Price Risk Included in nuclear decommissioning trusts are mar-ketable equity securities carried at their current fair value of approximately $951 million and $779 million as of December 31, 2004 and 2003, respectively. A hypothetical 10%

decrease in prices quoted by stock exchanges would result in a $95 million reduction in fair value as of December 31, 2004 (see Note 5 - Fair Value of Financial Instruments).

CREDIT RISK Credit risk is the risk of an obligor's failure to meet the terms of any investment contract, loan agreement or other-wise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counter-party performance, whether reflected on or off the balance sheet. 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 companies within the industry.

We maintain credit policies with respect to our counter-parties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of our credit program, we aggressively manage the quality of our portfolio of energy contracts, evidenced by a current weighted average risk rat-ing for energy contract counterparties of BBB (S&P). As of December 31, 2004, the largest credit concentration was with one party, currently rated investment grade that repre-28 frsCtcp 2rCWt.

Regulatory assets by source are as follows:

Regulatory Assets By Source Increase As of December 31 2004 2003 (Decrease) a (In millions)

Regulatory transition costs 6427.

( 1.538)

Customer shopping incentives 612 371 241 Customer receivables for future income taxes 246 340 (94)

Societal benefits charge 51 81 (301 Loss on reacquired debt 89 75 14 Employee postretirement benefits costs 65 77 (12)

Nuclear decommissioning, decontamination and spent fuel disposal costs (1691 (96)

(73)

Asset removal costs (340)

(321)

A19)

Property losses and unrecovered plant costs 50 70 (20)

Other 39 53 114)<

Total

-5.532

$7,077 S(1.545)

The Ohio Companies are defetring customer shoping incentives and interest costs as new regulatory assets in accordance with the transition and rate stabilization -

plans. These regulatory assets, totaling $612 million as of December31. 2004, will be rcovered thrruih a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered. Recovery of the new regulatory assets will begin at that time and amortization of the regulatory assets for each accounting period will be equal to the surcharge rvenue reccgnized during thatperiod.

Ohio On February 24, 2004, the Ohio Companies filed a revised Rate Stabilization Plan to address PUCO concerns related to the original Rate Stabilization Plan that the Ohio Companies filed in October 2003. On June 9, 2004, the PUCO issued an order approving the revised Rate Stabilization Plan, subject to conducting a competitive bid process. On August 5, 2004, the Ohio Companies accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. In the second quarter of 2004, the Ohio Companies implemented the accounting modifica-tions related to the extended amortization periods and interest cost deferrals on the deferred customer shopping incentive balances. On October 1 and October 4, 2004, the OCC and NOAC, respectively, filed appeals with the Supreme Court of Ohio to overturn the June 9, 2004 PUCO order and associated entries on rehearing.

The revised Rate Stabilization Plan extends current gen-eration prices through 2008, ensuring adequate generation supply at stabilized prices, and continues the Ohio Companies' support of energy efficiency and economic development efforts. Other key components of the revised Rate Stabilization Plan include the following:

• extension of the amortization period for transition costs being recovered through the RTC for OE from 2006 to as late as 2007; for CEI from 2008 to as late as mid-2009 and for TE from mid-2007 to as late as mid-2008;

• deferral of interest costs on the accumulated customer shopping incentives as new regulatory assets; and

• ability to request increases in generation charges dur-ing 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes.

On December 9, 2004, the PUCO rejected the auction price results from a required competitive bid process and issued an entry stating that the pricing under the approved revised Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may cause the Ohio Companies to under-take, no more often than annually, a similar competitive bid process to secure generation for the years 2007 and 2008. Any acceptance of future competitive bid results would terminate the Rate Stabilization Plan pricing, but not the related approved accounting, and not until twelve months after the PUCO authorizes such termination.

On December 30, 2004, the Ohio Companies filed an application with the PUCO seeking tariff adjustments to recover increases of approximately $30 million in transmis-sion and ancillary service-related costs beginning January 1, 2006. The Ohio Companies also filed an application for authority to defer costs such as those associated with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees, and the ATSI rate increase (described below), as applicable, from October 1, 2003 through December 31, 2005.

See Note 9 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.

New Jersey In July 2003, the NJBPU announced its JCP&L base electric rate proceeding decision, which reduced JCP&L's annual revenues effective August 1, 2003 and disallowed

$153 million of deferred energy costs. The NJBPU decision also provided for an interim return on equity of 9.5% on JCP&L's rate base. The decision ordered a Phase II proceed-ing be conducted to review whether JCP&L is in compliance with current service reliability and quality standards. The BPU also ordered that any expenditures and projects under-taken by JCP&L to increase its system's reliability be reviewed as part of the Phase II proceeding, to determine their prudence and reasonableness for rate recovery. In that Phase II proceeding, the NJBPU could increase JCP&L's return on equity to 9.75% or decrease it to 9.25%, depend-ing on its assessment of the reliability of JCP&L's service.

Any reduction would be retroactive to August 1, 2003.

JCP&L recorded charges to net income for the year ended December 31, 2003, aggregating $185 million ($109 million net of tax) consisting of the $153 million of disallowed deferred energy costs and $32 million of other disallowed regulatory assets. In its final decision and order issued on May 17, 2004, the NJPBU clarified the method for calculat-ing interest attributable to the cost disallowances, resulting in a $5.4 million reduction from the amount estimated in 2003. JCP&L filed an August 15, 2003 interim motion for rehearing and reconsideration with the NJBPU and a June 1, 2004 supplemental and amended motion for rehearing and reconsideration. On July 7, 2004, the NJBPU granted limited reconsideration and rehearing on the following issues: (1) deferred cost disallowances (2) the capital structure includ-ing the rate of return (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning. Management is unable to predict when a decision may be reached by the NJBPU.

On July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU requesting an increase in base rates of $36 million for the recovery of system reliability costs and a 9.75% return on equity. The filing also requests an increase to the MTC deferred balance recovery of i '

C

-f!!,

?; A;.

'; 29

approximately $20 million annually. The Ratepayer Advocate filed testimony on November 16, 2004, JCP&L submitted rebuttal testimony on January 4, 2005. Settlement confer-ences are ongoing.

See Note 9 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.

Pennsylvania Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sale agreement. The PLR sale is automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the sup-ply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. Met-Ed and Penelec are authorized to continue deferring differences between NUG contract costs and current market prices.

On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005 estimated to be approxi-mately $8 million per month.

See Note 9 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania.

Transmission On September 16, 2004, the FERC issued an order that imposed additional obligations on CEI.under certain pre-Open Access transmission contracts among CEI and the cities of Cleveland and Painesville. Under the FERC's deci-sion, CEI may be responsible for a portion of new energy market charges imposed by MISO when its energy markets begin in the spring of 2005. CEI filed for rehearing of the order from the FERC on October 18, 2004. The impact of the FERC decision on CEI is dependent upon many factors, including the arrangements made by the cities for transmis-sion service, the startup date for the MISO energy market, and the resolution of the rehearing request, and cannot be determined at this time.

On November 1, 2004, ATSI requested authority from the FERC to defer approximately $54 million of vegetation management costs ($13 million deferred as of December 31, 2004 pending authorization) estimated to be incurred from 2004 through 2007. The FERC approved ATSI's request to defer those costs on March 4, 2005.

ATSI and MISO filed with the FERC on December 2, 2004, seeking approval for ATSI to have transmission rates established based on a FERC-approved cost of service for-mula rate included in Attachment 0 under the MISO tariff.

The ATSI Network Service net revenue requirement increased under the formula rate to approximately $159 million. On January 28, 2005, the FERC accepted for filing the revised tariff sheets to become effective February 1, 2005, subject to refund, and ordered a public hearing be held to address the reasonableness of the proposal to elimi-nate the voltage-differentiated rate design for the ATSI zone.

Reliability Initiatives In 2004, we completed implementation of all actions and initiatives related to enhancing area reliability, improving voltage and reactive management, operator readiness and training, and emergency response preparedness as recom-mended by various governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. -

Canada Power System Outage Task Force) for completion in 2004. We certified to NERC on June 30, 2004, that we had completed our initiatives with minor exceptions noted, and an independent team led by NERC verified the implementa-tion. Further, we reported to NERC on December 28, 2004 that the minor exceptions were essentially complete.

We are proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the rec-ommendations has not required, nor is expected to require, substantial investment in new, or material upgrades to exist-ing equipment. We note, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhance-ments or may recommend additional enhancements in the future that could require additional, material expenditures.

Finally, the PUCO is continuing to review our filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding. See Note 9 to the consolidated financial statements for a more detailed discussion of reliability initia-tives, including actions by the PPUC that impact Met-Ed, Penelec and Penn.

On July 5, 2003, JCP&L experienced a series of 34.5 kilovolt sub-transmission line faults that resulted in outages on the New Jersey shore. As a result of an investigation into these outages, the NJBPU issued an order to JCP&L on July 23, 2004 to implement actions to improve reliability in accor-dance with a Special Reliability Master (SRM) report findings and an operations audit.

See Note 9 to the consolidated financial statements for a more detailed discussion of reliability initiatives, including actions by the PPUC, that impact Met-Ed, Penelec and Penn.

ENVIRONMENTAL MATTERS We believe we are in compliance with current S02 and NOx reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' Ohio and Pennsylvania facilities. Various regulatory and judi-cial actions have since sought to further define NOx 30 L,!-io r c... A, ",.-

reduction requirements (see Note 13(C) - Environmental Matters). We continue to evaluate our compliance plans and other compliance options.

Clean Air Act Compliance The Companies are required to meet federally approved S02 regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for S02 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

The Companies believe they are complying with S02 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electrici-ty from lower-emitting plants, and/or using emission allowances. NOx reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants.

In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclu-sion that such NOx emissions are contributing significantly to ozone levels in the eastern United States. The Companies believe their facilities are also complying with NOx budgets established under State Implementation Plans (SIP) through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.

National Ambient Air Quality Standards In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine par-ticulate matter. On December 17, 2003, the EPA proposed the "Interstate Air Quality Rule" covering a total of 29 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on pro-posed findings that air pollution emissions from 29 eastern states and the District of Columbia significantly contribute-to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. The EPA has pro-posed the Interstate Air Quality Rule to "cap-and-trade" NOx and S02 emissions in two phases (Phase I in 2010 and Phase 11 in 2015). According to the EPA, S02 emissions would be reduced by approximately 3.6 million tons annually by 2010, across states covered by the rule, with reductions ultimately reaching more than 5.5 million tons annually. NOx emission reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in 2015. The future cost of compliance with these proposed regulations may be sub-stantial and will depend on whether and how they are ultimately implemented by the states in which the Companies operate affected facilities.

Mercury Emissions In December 2000, the EPA announced it would pro-ceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern.

On December 15, 2003, the EPA proposed two different approaches to reduce mercury emissions from coal-fired power plants. The first approach would require plants to install controls known as MACT based on the type of coal burned. According to the EPA, if implemented, the MACT proposal would reduce nationwide mercury emissions from coal-fired power plants by 14 tons to approximately 34 tons per year. The second approach proposes a cap-and-trade program that would reduce mercury emissions in two dis-tinct phases. Initially, mercury emissions would be reduced by 2010 as a "co-benefit" from implementation of S02 and NOx emission caps under the EPA's proposed Interstate Air Quality Rule. Phase 11 of the mercury cap-and-trade program would be implemented in 2018 to cap nationwide mercury emissions from coal-fired power plants at 15 tons per year.

The EPA has agreed to choose between these two options and issue a final rule by March 15, 2005. The future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn.

In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S.

District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dat-ing back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase of the trial to address any civil penalties and what, if any, actions should be taken to further reduce emis-sions at the plant has been delayed without rescheduling by the Court because the parties are engaged in meaningful settlement negotiations. The Court indicated, in its August 2003 ruling, that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consid-er the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact f ::.i 'r'r, L :; ',;1 31

on FirstEnergy's, OE's and Penn's respective financial condi-tion and results of operations. While the parties are engaged in meaningful settlement discussions, management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of December 31, 2004.

Regulation of Hazardous Waste As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from haz-ardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subse-quently determined that regulation of coal ash, as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhaz-ardous waste.

The Companies have been named as PRPs at waste dis-posal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous sub-stances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of December 31, 2004, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Included in Current Liabilities and Other Noncurrent Liabilities are accrued liabilities aggregating approximately $65 million as of December 31, 2004. The Companies accrue environmental liabilities only when they can conclude that it is probable that they have an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims are reflected in the Companies' determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

Climate Change In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity - the ratio of emissions to economic output - by 18% through 2012.

The Companies cannot currently estimate the financial impact of climate change policies, although the potential restrictions on C02 emissions could require significant capi-tal and other expenditures. However, the C02 emissions per kilowatt-hour of electricity generated by the Companies is lower than many regional competitors due to the Companies' diversified generation sources which includes low or non-C02 emitting gas-fired and nuclear generators.

Clean Water Act Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amend-ments, apply to the Companies' plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to the Companies' operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.

On September 7, 2004, the EPA established new per-formance standards under Clean Water Act Section 316(b) for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric gen-erating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake sys-tem and entrainment, which occurs when aquatic species are drawn into a facility's cooling water system. The Companies are conducting comprehensive demonstration studies, due in 2008, to determine the operational meas-ures, equipment or restoration activities, if any, necessary for compliance by their facilities with the performance stan-dards. FirstEnergy is unable to predict the outcome of such studies. Depending on the outcome of such studies, the future cost of compliance with these standards may require material capital expenditures.

OTHER LEGAL PROCEEDINGS Power Outages and Related Litigation Three substantially similar actions were filed in various Ohio state courts by plaintiffs seeking to represent cus-tomers who allegedly suffered damages as a result of the August 14, 2003 power outages. All three cases were dis-missed for lack of jurisdiction. One case was refiled at the PUCO. The other two cases were appealed. One case was dismissed and no further appeal was sought. The remaining case is pending. In addition to the one case that was refiled at the PUCO, the Ohio Companies were named as respon-dents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages.

One complaint has been filed against FirstEnergy in the New York State Supreme Court. In this case, several plain-tiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy filed a motion to dismiss with the Court on October 22, 2004. No timetable for a deci-sion on the motion to dismiss has been established by the 32 C('qt Cc, 20Y54

Court. No damage estimate has been provided and thus potential liability has not been determined.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.

Nuclear Plant Matters In late 2003, FENOC received a subpoena from a grand jury in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station. FirstEnergy is unable to predict the outcome of this investigation. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements relating to the Davis-Besse Nuclear Power Station outage made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-

01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. FirstEnergy is unable to pre-dict the outcome of this investigation. On February 10, 2005, FENOC received an additional subpoena for documents relat-ed to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse. In addition, FENOC remains subject to possible civil enforcement action by the NRC in connection with the events leading to the Davis-Besse outage in 2002.

On August 12, 2004, the NRC notified FENOC that it will increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the past two years. FENOC operates the Perry Nuclear Power Plant, which is either owned or leased by OE, CEI, TE and Penn. Although the NRC noted that the plant continues to operate safely, the agency has indicated that its increased oversight will include an extensive NRC team inspection to assess the equipment problems and the sufficiency of FENOC's corrective actions. The outcome of these matters could include NRC enforcement action or other impacts on operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition.

Other Legal Matters Various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations are pending against FirstEnergy and its subsidiaries. The most significant not otherwise discussed above are described below.

On July 27. 2004, FirstEnergy announced that it had reached an agreement to resolve pending lawsuits alleging violations of federal securities laws and related state laws filed against FirstEnergy in connection with, among other things, the restatements in August 2003 by FirstEnergy and the Ohio Companies of previously reported results, the August 14, 2003 power outages and the extended outage at the Davis-Besse Nuclear Power Station. The settlement agreement, which does not constitute any admission of wrongdoing, provides for a total settlement payment of

$89.9 million. Of that amount, FirstEnergy's insurance carri-ers paid $71.92 million, based on a contractual pre-allocation, and FirstEnergy paid $17.98 million, which resulted in an after-tax charge against FirstEnergy's second quarter earnings of $11 million or $0.03 per share of com-mon stock (basic and diluted). On December 30, 2004, the court approved the settlement.

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 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 of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised dur-ing the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notifica-tion, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a second subpoena asking for documents relating to issues raised during the SEC's PUHCA examination.

FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made sub-ject to liability based on the above matter, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.

CRITICAL ACCOUNTING POLICIES We prepare our consolidated financial statements in accordance with GAAR Application of these principles often requires a high degree of judgment, estimates and assump-tions that affect financial results. All of our assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Our more significant accounting policies are described below.

Regulatory Accounting Our regulated services segment is subject to regulation that sets the prices (rates) we are permitted to charge our customers based on costs that the regulatory agencies deter-mine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be cur-rently charged to expense by an unregulated company. This ratemaking process results in the recording of regulatory assets based on anticipated future cash inflows. We regularly review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse 33

legislative, judicial or regulatory actions in the future.

Revenue Recognition We follow the accrual method of accounting for rev-enues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled sales is recognized. The determination of unbilled sales requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class, weather-related impacts, prices in effect for each customer class and electricity provided by alternative suppliers.

Pension and Other Postretirement Benefits Accounting Our reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions.

Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions we make to the plans, and earnings on plan assets. Such factors may be further affected by business combinations, which impact employee demographics, plan experience and other factors.

Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs.

In accordance with SFAS 87, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remain-ing average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time.

As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are signifi-cantly influenced by assumptions about future market conditions and plan participants' experience.

In selecting an assumed discount rate, we consider cur-rently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obli-gations. Due to recent declines in corporate bond yields and interest rates in general, we reduced the assumed discount rate as of December 31, 2004 to 6.00% from 6.25% and 6.75% used as of December 31, 2003 and 2002, respectively.

Our assumed rate of return on pension plan assets con-siders historical market returns and economic forecasts for the types of investments held by our pension trusts. In 2004, 2003 and 2002, plan assets actually earned 11.1 %,

24.2% and (11.3)%, respectively. Our pension costs in 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and our pension trust investment allocation of approximately 68%

equities, 29% bonds, 2% real estate and 1 % cash.

In the third quarter of 2004, we made a $500 million voluntary contribution to our pension plan. Prior to this contribution, projections indicated that cash contributions of approximately $600 million would have been required during the 2006 to 2007 time period under minimum funding requirements established by the IRS. Our election to pre-fund the plan is expected to eliminate that funding requirement.

As a result of our voluntary contribution and the increased market value of pension plan assets, we reduced our accrued benefit cost as of December 31, 2004 by $424 million. As prescribed by SFAS 87, we reduced our additional minimum liability by $15 million, recording a decrease in an intangible asset of $9 million and crediting OCI by $6 million. The balance in AOCL of $296 million (net of $208 million in deferred taxes) will reverse in future periods to the extent the fair value of trust assets exceeds the accumulated benefit obligation.

Health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2005 composite health care trend rate assumptions are approximately 10%-

12% and 9%-11 %, respectively, gradually decreasing to 5%

in later years. In determining our trend rate assumptions, we included the specific provisions of our health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in our health care plans, and projections of future medical trend rates. The effect on our pension and OPEB costs and liabilities from changes in key assumptions are as follows:

Increase In Costs from Adverse Changes In Key Assumptions Assumption Adverse Change Pension OPEB Total

/In millions)

Discount rate Decrease by 0.25%

$10 m1lo5 ns 5

Long-term return on assets

-Decrease by 025%

$10

$1

$11 Healthcaretrendrate Increasebyl na

$19

$19 Increase In Minimum Liability Discountrate Decreaseby0.25%

$110 na

$110 Ohio Transition Cost Amortization In connection with the Ohio Companies' transition plan, the PUCO determined allowable transition costs based on amounts recorded on the regulatory books of the Ohio Companies. These costs exceeded those deferred or capi-talized on FirstEnergy's balance sheet prepared under GAAP since they included certain costs which had not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments).

FirstEnergy uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for each respective company. In computing the transi-tion cost amortization, FirstEnergy includes only the portion 34 [u&,..!

Cc:p 2Ox4

of the transition revenues associated with transition costs included on the balance sheet prepared under GAAR Revenues collected for the off-balance sheet costs and the return associated with these costs are recognized as income when received.

Long-Lived Assets In accordance with SFAS 144, we periodically evaluate our long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expect-ed to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, we recog-nize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (dis-counted future net cash flows).

The calculation of future cash flows is based on assumptions, estimates and judgment about future events.

The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment.

Nuclear Decommissioning In accordance with SFAS 143, we recognize an ARO for the future decommissioning of our nuclear power plants.

The ARO liability represents an estimate of the fair value of our current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measure-ment inherently involves uncertainty in the amount and timing of settlement of the liability. We used an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consid-er settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term.

Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, we evaluate goodwill for impairment at least annually and make such evaluations more frequently if indicators of impairment arise. In accor-dance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including good-will), the goodwill is tested for impairment. If an impairment is indicated we recognize a loss - calculated as the differ-ence between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. Our annual review was completed in the third quarter of 2004 with no impairment indicated.

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. In December 2004, the FSG subsidiaries qualified as held for sale in accordance with SFAS 144. As required by SFAS 142, the goodwill of FSG was tested for impairment, resulting in a non-cash charge of $36 million in the fourth quarter of 2004.

The forecasts used in our evaluations of goodwill reflect operations consistent with our general business assumptions.

Unanticipated changes in those assumptions could have a significant effect on our future evaluations of goodwill.

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS SFAS 123 (revised 20041 'Share-BasedPayment' In December 2004, the FASB issued this revision to SFAS 123, which requires expensing stock options in the financial statements. Important to applying the new stan-dard is understanding how to (1) measure the fair value of stock-based compensation awards and (2) recognize the related compensation cost for those awards. For an award to qualify for equity classification, it must meet certain crite-ria in SFAS 1231R). An award that does not meet those criteria will be classified as a liability and remeasured each period. SFAS 123(R) retains SFAS 123's requirements on accounting for income tax effects of stock-based compensa-tion. The effective date for FirstEnergy is July 1, 2005 and the Company will be applying modified prospective applica-tion, without restatement of prior interim periods. Any potential cumulative adjustments have not been deter-mined. FirstEnergy uses the Black-Scholes option pricing model to value options and will continue to do so upon adoption of SFAS 123(R). The impacts of the fair value recognition provisions of SFAS 123 on FirstEnergy's net income and earnings per share for 2002 through 2004 are disclosed in Note 4 to the consolidated financial statements.

FirstEnergy is considering alternative compensation strate-gies in conjunction with the adoption of SFAS 123(R).

EITF Issue No. 03-1, 'The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments' In March 2004, the EITF reached a consensus on the application guidance for EITF 03-1, which provides a model for determining when investments in certain debt and equi-ty securities are considered other than temporarily impaired.

When an impairment is other-than-temporary, the invest-ment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measure-ment provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will continue to evaluate its investments as required by existing authoritative guidance.

-.'. ' 35

CONSOLIDATED STATEMENTS OF INCOME

[In thousands, except per share amounts)

For the Years Ended December 31, 2004 2003 2002 Revenues:

Electric utilities

$9,064,853

$8,962,201

$9,165,805 Unregulated businesses

.3388,193 2,712,687 2,287,549 Total revenues 12,453,046 11,674,888 11,453,354 Expenses:

Fuel and purchased power 4,469,484 4,159,143 3,309,658 Other operating expenses 3,558,676 3,796,062 3,927,370 Provision for depreciation 589,652 606,436 721,493 Amortization of regulatory assets 1,166,323 1,079,337 940,991 Deferral of new regulatory assets (256,795)

(194,261)

(183,947)

Goodwill impairment (Note 2(H))

36,471 116,988 General taxes 67i,757 637,967 649,400 Total expenses 10,241,568 10,201,672 9,364,965 Claim Settlement (Note 8) 167,937 Income Before Interest and Income Taxes 2,211,478 1,641,153 2,088,389 Net Interest Charges:

Interest expense 670,945 798,911 904,697 Capitalized interest (25,581)

(31,900)

(24,474)

Subsidiaries' preferred stock dividends 21,413 42,369 75,647 Net interest charges 566,777 809,380 955,870 Income Taxes 670,922 407,524 514,134 Income Before Discontinued Operations and Cumulative Effect of Accounting Change 873,779 424,249 618,385 Discontinued operations (net of income taxes (benefit) of $3,038,000,

($3,064,000) and $14,560,000, respectively) (Note 2(J))

4,396 (103,632)

(65,581)

Cumulative effect of accounting change (net of income taxes of $72,51 6,000) (Note 2(K))

102,147 Net Income

$ 878,175

$ 422,764

$ 552,804 Basic Earnings Per Share of Common Stock:

Income before discontinued operations and cumulative effect of accounting change 2.67 1.40 2.11 Discontinued operations (Note 2(J))

0.01 (0.34)

(0.22)

Cumulative effect of accounting change (Note 2(K))

0.33 Net income 2.68 1.39 1.89 Weighted Average Number of Basic Shares Outstanding 327,387 303,582 293,194 Diluted Earnings Per Share of Common Stock:

Income before discontinued operations and cumulative effect of accounting change 2.66 1.40 2.10 Discontinued operations (Note 2(J))

0.01 (0.34)

(0.22)

Cumulative effect of accounting change (Note 2(K 0.33 Net income 2.67 1.39 1.88 Weighted Average Number of Diluted Shares Outstanding 328,982 304,972 294,421 The accompanying Notes to ConsolidatedFinancial Statements are an integralpart of these statements.

36

.'K.!

.9.- C rfp,

• W

CONSOLIDATED BALANCE SHEETS (In thousands)

As of December 31, 2004 2003 ASSETS Current Assets:

Cash and cash equivalents 52,941 113,975 Receivables-Customers (less accumulated provisions of $34,476,000 and $50,247,000 respectively, for uncollectible accounts)

.979,242 1,000,259 Other (less accumulated provisions of $26.070,000 and $18,283,000 respectively, for uncollectible accounts) 377,195 505,241 Materials and supplies, at average cost-Owned 363,547 325,303 Under consignment 94,226 95,719 Prepayments and other

.145,196 202,814 2,012,347 2,243,311 Property, Plant and Equipment In service 22,213,218 21,594,746 Less-Accumulated provision for depreciation 9,413,730 9,105,303 12,799,488 12,489,443 Construction work in progress 678,868 779,479 13,478,356 13,268,922 Investments:

Nuclear plant decommissioning trusts 1,582,588 1,351,650 Investments in lease obligation bonds (Note 6) 951,352 989,425 Certificates of deposit (Note 10(C))

277,763 Other 740,026 878,853 3,273,966 3,497,691 Deferred Charges:

Regulatory assets 5,532,087 7,076,923 Goodwill 6,050,277 6,127,883 Other 720,911 695,218 12,303,275 13,900,024

$ 31,067,944

$ 32,909,948 LIABILITIES AND CAPITALIZATION Current Liabilities:

Currently payable long-term debt 940944

$ 1,754,197 Short-term borrowings (Note 12) 170,489 521,540 Accounts payable 610,589 725,239 Accrued taxes 657,219 669,529 Other 929,194 801,662 3,308,435 4,472,167 Capitalization (See Consolidated Statement of Capitalization):

Common stockholders' equity 8,589,294 8,289,341 Preferred stock of consolidated subsidiaries not subject to mandatory redemption 335,123 335,123 Long-term debt and other long-term obligations 10,013,349 9,789,066 18,937,766 18,413,530 Noncurrent Liabilities:

Accumulated deferred income taxes 2,324,097 2,178,075 Asset retirement obligations (Note 11) 1,077,557 1,179,493 Power purchase contract loss liability 2,001,006 2,727,892 Retirement benefits 1,238,973 1,591,006 Lease market valuation liability

- 936,200 1,021,000 Other 1,243,910 1,326,785 8,821,743 10,024,251 Commitments, Guarantees and Contingencies (Notes 6 and 13)

$ 31,067,944

$ 32,909,948 The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

fasiIoorg-, Cor' V

37

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Dollars In thousands, except for share amounts)

As of December 31, 2004 2003 Common Stockholders' Equity:

Common stock, $0.10 par value -authorized 375,000,000 shares-329,836,276 shares outstanding S 32,984

$ 32,984 Other paid-in capital 7,055,676 7,062.825 Accumulated other comprehensive loss (Note 2(l))

(313,112)

(352,649)

Retained earnings (Note 10(A))

1,856,863 1,604,385 Unallocated employee stock ownership plan common stock-2,032,800 and Z896,951 shares, respectively (Note 4(B))

(43,117) 158,204)

Total common stockholders' equity 8,589,294 8,289,341 Number of Shares Optional Outstanding Redemption Price 2004 2003 Per Share Aggregate Preferred Stock of Consolidated Subsidiaries Not Subject To Mandatory Redemption (Note 10(B)):

Ohio Edison Company Cumulative, $100 par value-Authorized 6,000,000 shares 3.90%

152,510 152,510

$103.63

$ 15,804 15,251 15,251 4.40%

176,280 176,280 108.00 19.038 17.628 17,628 4.44%

136,560 136,560 103.50 14,134 13,656 13,656 4.56%

144,300 144,300 103.38 14,917 14,430 14,430 Total 609,650 609,650

$ 63,893 60,965 60,965 Pennsylvania Power Company Cumulative,

$100 par value-Authorized 1,200,000 shares 4.24%

40,000 40,000 103.13 4,125 4,000 4,000 4.25%

41,049 41,049 105.00 4,310 4,105 4,105 4.64%

60,000 60,000 102.98 6,179 6,000 6,000 7.75%

250,000 250,000 100.00 25,000 25,000 25,000 Total 391,049 391,049 39,614 39,105 39,105 Cleveland Electric Illuminating Company Cumulative, without par value-Authorized 4,000,000 shares

$ 7.40 Series A 500,000 500,000 101.00 50,500 50.000 50,000 Adjustable Series L 474,000 474,000 100.00 47.400 46,404 46,404 Total 974,000 974,000 97,900 96,404 96,404 Toledo Edison Company Cumulative, $100 par value-Authorized 3,000,000 shares

$4.25 160,000 160,000 104.63 16,740 16,000 16,000

$4.56 50,000 50,000 101.00 5,050 5,000 5,000

$4.25 100,000 100,000 102.00 10,200 10,000 10,000 310,000 310,000 31,990 31,000 31,000 Cumulative, $25 par value-Authorized 12,000,000 shares

$2.365 1,400,000 1,400,000 27.75 38,850 35,000 35,000 Adjustable Series A 1,200,000 1,200,000 25.00 30,000 30,000 30,000 Adjustable Series B 1,200,000 1,200,000 25.00 30,000 30,000 30,000 3,800,000 3,800.000 98,850 95,000 95,000 Total 4,110,000 4,110,000 130,840

• 126,000 126,000 Jersey Central Power & Light Company Cumulative,

$100 stated value-Authorized 15,600,000 shares 4.00% Series 125,000 125,000 13,313

. 12,649 12,649 106.50 38 70s0 4 L(dz

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cuntmued)

Long-Term Debt and Other Long-Term Obligations (Note 10(C)) (Interest rates reflect weighted average rates)

(In thousands)

First Mortgage Bonds Secured Notes Unsecured Notes Total As of December 31.

2004 2003 2004 2003 2004 2003 2004 2003 Ohio Edison Co.-

Due 2004-2009 6.88% $80,000

$80,000 7.61%

$ 67,476

$ 229,257 4.46% $ 175,000 $ 526,725 Due 2010-2014 7.16%

1,257 1,256 3.70%

50,000 Due 2015-2019 3.80%

156,725 59,000 5.04%

206,000 150,000 Due 2020-2024 7.01%

60,443 60,443 3.87%

50,000 Due 2025-2029 5.75%

119,734 13,522 Due 2030-2034 2.19%

359,800 308,012 3.35%

30,000 Total-Ohio Edison 80,000 80,000

'765,435 671,490 511,000 676,725 $1,356,435 $1,428,215 Cleveland Electric Illuminating Co.-

Due 2004-2009 6.86%

125,000 125,000 7.29%

271,700 622,485 27,700 Due 2010-2014 5.72%

378,700 378,700 Due 2015-2019 6.23%

412,630 412,630 Due 2020-2024 5.35%

180,560 186,660 Due 2025-2029 7.59%

148,843 148,843 Due 2030-2034 2.79%

180,995 30,000 7.87%

130,793 103,093 Total-Cleveland Electric 125,000 125,000 1,194,728 1,400,618 509,493 509,493 1,829,221 2,035,111 Toledo Edison Co.-

Due 2004-2009 145,000 7.13%

30,000 100,000 85,250 Due 2020-2024 5.37%

166,300 144,500 Due 2025-2029 5.90%

13.851 13,851 Due 2030-2034 2.01%

81,600 51,100 3.90%

90,950 Total-Toledo Edison 145,000 291,751 309,451 90,950 85,250 382Z701 539,701 Pennsylvania Power Co.-

Due 2004-2009 9.74%

4,870 40,344 10,300 19,700 Due 2010-2014 9.74%

4,870 4,870 5.40%

1,000 1,000 Due 2015-2019 9.74%

4,903 4,903 4.24%

45,325 45,325 Due 2020-2024 7.63%

6,500 33,750 3.94%

27,182 27,182 Due 2025-2029 4.93%

33,472 23,172 3.38%

14,500 Due 2030-2034 2.04%

5,200 Total-Penn Power 21,143 83,867 112,179 106,979 14,500 19,700 147,822 210,546 Jersey Central Power

& Light Co.-

Due 2004-2009 6.89%

45,985 256,300 5.79%

240,391 255,980 124 Due 2010-2014 5.84%

117,735 117,735 155 Due 2015-2019 7.10%

12,200 12,200 5.46%

522,486 222,486 224 Due 2020-2024 7.50%

125,000 205,000 325 Due 2025-2029 7.18%

200,000 200,000 471 Due 2030-2034 682 Due 2035-2039 987 Total-Jersey Central 383,185 673,500 880,612 596,201 2,968 1,263,797 1,272,669 Metropolitan Edison Co.-

Due 2004-2009 6.61%

37,830 128,265 150,000 5.79%

150,000 248 Due 2010-2014 250,000 4.81%

500,000 310 Due 2015-2019 449 Due 2020-2024 6.10%

28,500 28,500 650 Due 2025-2029 5.95%

13,690 13,690 941 Due 2030-2034 1,364 Due 2035-2039 97,685 Total-Metropolitan Edison 80,020 170,455 400,000 650,000 101,647 730,020 672,102 i ' "'.';

! 3.9

CONSOLIDATED STATEMENTS OF CAPITALIZAtION XContintued)

Long-Termn Debt and Other Long-Term Obligations (Interest rates reflect weighted average rates)

(In thousands)

First Mortgage Bonds Secured Notes Unsecured Notes Total As of December 31, 2004 2003 2004 2003 2004 2003 2004 2003 Pennsylvania Electric Co.-

Due 2004-2009 6.12% $ 3,495

$ 3,700 6.23% $ 108,000 $ 233,124 Due 2010-2014 5.35%

24,310 24,310 5.63%

185,000 35,155 Due 2015-2019 6.63%

125,000 125,224 Due 2020-2024 5.80%

20,000 20,000 325 Due 2025-2029 6.05%

25,000 25,000 470 Due 2030-2034 682 Due 2035-2039 96,508 Total-Pennsylvania Electric 72,805 73,010 418,000 491,488

$ 490,805

$ 564,498 FirstEnergy Corp.

Due 2004-2009 5.98% 1,515,000 1,570,000 Due 2010-2014 6.45% 1,500,000 1,500,000 Due 2030-2034 7.38% 1,500,000 1,500,000 Total-FirstEnergy 4,515,000 4,570,000 4,515,000 4,570,000 Bay Shore Power 6.24%

137,500 140,600 137,500 140,600 Facilities Services Group 5.94%

7,340 7,754 7,340 7,754 FirstEnergy Generation 5.00%

15,000 15,000

.15,000 15,000 FirstEnergy Properties 7.89%

9,182 9,438 9,182 9,438 Warrenton River Terminal 6.00%

220 410 220 410 First Communications 6.26%

5,000 5,407 5,000 5,407 Total 762,153 1,350,832 3,398,947 3,642,941 6,728,943 6,477,678 10,890,043 11,471,451 Preferred stock subject to mandatory redemption 16,759 18,514 Capital lease obligations 10,732 13,313 Net unamortized premium on debt 36,759 39,985 Long-term debt due within one year (940,944)

(1,754,197)

Total long-term debt and other long-term obligations 10,013,349 9,789,066 Total Capitalization

$18,937,.766 $18,413,530 The accompanyrng Notes to Consolidated Financial Statements are an integral part of these statements.

40 a.'sln-.

CCrp 20X'4

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (Dollars in thousandsl 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, 2002 297,636,276 $29,764 $6,113,260

$(169,003)

$1,521,805

$ (97,227)

Net income

$ 552,804 552,804 Minimum liability for unfunded retirement benefits, net of $(316,681,000) of income taxes (449,615)

(449,615)

Unrealized gain on derivative hedges, net of $37,458,000 of income taxes 59,187 59,187 Unrealized loss on investments, net of

$(3,796,000) of income taxes (5,269)

(5.269)

Currency translation adjustments (91,448)

(91.448)

Comprehensive income

$ 65,659 Stock options exercised (8,169)

Allocation of ESOP shares 15,250 18,950 Cash dividends on common stock (439,628)

Balance, December 31, 2002 297,636,276 29,764 6,120,341 (656,148) 1,634,981 (78,277)

Net income

$ 422.764 422,764 Minimum liability for unfunded retirement benefits, net of $101,950,000 of income taxes 144,236 144,236 Unrealized loss on derivative hedges, net of $(241,000) of income taxes (347)

(347)

Unrealized gain on investments, net of

$53,431,000 of income taxes 68,162 68,162 Currency translation adjustments 91,448 91,448 Comprehensive income

$ 726,263 Stock options exercised (3,502)

Common stock issued 32,200,000 3,220 930,918 Allocation of ESOP shares 15,068 20,073 Cash dividends on common stock (453,360)

Balance, December 31. 2003 329,836,276 32,984 7,062,825 (352,649) 1,604,385 (58,204)

Net income

$ 878,175 878,175 Minimum liability for unfunded retirement benefits, net of $(4,698,000) of income taxes 16,256)

(6,256)

Unrealized gain on derivative hedges, net of $9,638,000 of income taxes 19,031 19,031 Unrealized gain on investments, net of

$19,783,000 of income taxes 26,762 26,762 Comprehensive income

$ 917,712 Stock options exercised 124,174)

Allocation of ESOP shares 17,025 15,087 Common stock dividends declared in 2004 payable in 2005 (135,168)

Cash dividends on common stock (490,529)

Balance, December 31, 2004 329,836,276 $32,9B4 $7,055,676

$ (313,112)

$1,856,863

$ (43.117)

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

2 J!pj

,'j..:.- 41

CONSOLIDATED STATEMENTS OF PREFERRED STOCK (Dollars in thousands)

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, 2002 12,449,699

$ 661,044 22,552,751

$ 624,449 Redemptions-7.75% Series (4,000,000)

(100,000)

$7.56 Series B (450,000)

(45,071)

$42.40 Series T (200,000)

(96,850)

$8.32 Series (100,000)

(10,000)

$7.76 Series (150,000)

(15,000)

$7.80 Series (150,000)

(15,000)

$10.00 Series (190,000)

(19,000)

$2.21 Series (1,000,000)

(25,000) 7.625% Series (7,500)

(750)

$7.35 Series C (10,000)

(1,000)

$90.00 Series S (17,750)

(17,010) 8.65% Series J (250,001)

(26,750) 7.52% Series K (265,000)

(28,951) 9.00% Series (4.800,000)

(120,000)

Amortization of fair market value adjustments-

$ 7.35 Series C (9)

$90.00 Series S (258) 8.56% Series (6) 7.35% Series 209 7.34% Series 214 Balance, December 31, 2002 6,209,699 335,123 17,202,500 430,138 Redemptions-7.625% Series (7,500)

(750)

$7.35 Series C (10.000)

(1,000) 8.56% Series (5,000,000)

(125,242)

FIN 46 Deconsolidation-9.00% Series (4,000,000)

(100,000) 7.35% Series (4,000,000)

(92,618) 7.34% Series (4,000,000)

(92,428)

Amortization of fair market value adjustments-

$ 7.35 Series C (7) 8.56% Series (2) 7.35% Series 209 7.34% Series 214 Balance, December 31, 2003 6,209,699

$ 335,123 185,000 18,514*

Redemptions-7.625% Series (7,500)

(750)

$7.35 Series C (10,000)

(1,000)

Amortization of fair market value adjustments-

$7.35 Series C (5)

Balance, December 31, 2004 6,209,699

$ 335,123 167,500

$ 16,759*

' The December31, 2003 and 2004 balances for Preferred Stock subject to mandatory redemption are classified as debt under SFAS 150.

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

42 q"

CONSOLIDATED STATEMENTS OF CASH FLOWS

{In thousands)

For the Years Ended December 31,

.2004 2003 2002 Cash Flows From Operating Activities:

Net Income

$ 878,175

$ 422,764

$ 552,804 Adjustments to reconcile net income to net cash from operating activities:

Provision for depreciation 589,652 606,436 721,493 Amortization of regulatory assets 1,166,323 1.079,337 940,991 Deferral of new regulatory assets 1256,795)

(194.261)

(183,947)

Nuclear fuel and lease amortization 96,084 66,072 80,507 Other amortization, net (19,436)

(16.278)

(16,593)

Deferred purchased power and other costs (416,617)

(427.092)

(543.644)

Deferred income taxes and investment tax credits, net' 258,263 53,639 76,786 Goodwill impairment (Note 2(H))

36,471 116,988 Disallowed regulatory assets 152,500 Investment impairments (Note 2(H))

17,897 43,803 50,000 Cumulative effect of accounting change

(- 174,663)

Deferred rents and lease market valuation liability (84,696)

(119,398)

(84,800)

Revenue credits to customers (71,984)

(43,016)

Accrued retirement benefit obligations 137,742 287,112 124,678 Accrued compensation, net 18,397 (84,503)

(92,197)

Tax refund related to pre-merger period 51,073 Commodity derivative transactions, net (48,840)

(70,498)

(8,682)

Loss (income) from discontinued operations (see Note 2(J))

(4,396) 103,632 65,581 Pension trust contribution (500,000).

Decrease (increase) in operating assets:

Receivables 154,053 66,311 (73,392)

Materials and supplies (36,751) 5,399 (29,134)

Prepayments and other current assets 47,010 (31,155) 133,677 Increase (decrease) in operating liabilities:

Accounts payable

( (110,947)

(169,652) 218,226 Accrued taxes (15,011) 221,500 25,183 Accrued interest (41,656)

(59,782)

(29,693)

NUG power contract restructuring 52,800 Other (40,872)

(102,445) 47,466 Net cash provided from operating activities 1,876,850 1,754,855 1,932,294 Cash Flows From Financing Activities:

New Financing-Common stock 934,138 Long-term debt 961,474 1,027,312 668,676 Short-term borrowings, net 478,520 Redemptions and Repayments-Preferred stock (1,750)

(127,087)

(522,223)

Long-term debt (1,572,080)

(2,128,567)

(1,308,814)

Short-term borrowings, net (351,051)

(575,391)

Net controlled disbursement activity (2,740) 24,689 (14,083)

Common stock dividend payments (490,529)

(453,360)

(439,628)

Net cash used for financing activities (1,456,676)

(1,298,266)

(1,137,552)

Cash Flows From Investing Activities:

Property additions (846,221)

(856,316)

(997,723)

Proceeds from asset sales 214,258 78,743 155,034 Proceeds from certificates of deposit 277,763 Nonutility generation trusts withdrawals (contributions)

(50,614) 66,327 49,044 Contributions to nuclear decommissioning trusts (101,483)

(101,218)

(103,143)

Avon cash and cash equivalents (Note 8) 31,326 Net assets held for sale (31,326)

Long-term note receivable 82,250 (91,335)

Cash investments (Note 5) 27,082 52,884 81,349 Asset retirements and transfers 9,513 37,580 29,619 Other investments (7,993) 29,137 (7,944)

Other (3,513) 42,067 52,397 Net cash used for investing activities (481,208)

(568,546)

(832,702)

Net decrease in cash and cash equivalents (61,034)..

(111,957)

(37,960)

Cash and cash equivalents at beginning of year 113,975 225,932 263,892 Cash and cash equivalents at end of year S 52,941

$ 113,975

$ 225,932 Supplemental Cash Flows Information:

Cash Paid During the Year-Interest Inet of amounts capitalized)

$ 704,067

$ 730,277

$ 881,515 Income taxes

$ 512,419

$ 161,915

$389,180 The accompanying Notes to ConsolidatedFinancial Statements are an integralpartof these statements.

l'a;

Cor~.7~ 43

CONSOLIDATED STATEMENTS OF TAXES (In thousands)

For the Years Ended December 31, 2004 2003 2002 General Taxes:

Kilowatt-hour excise*

$ 236,398

$ 228,216

$ 219,970 State gross receipts*

139,616 130,244 132,622 Real and personal property 207,504 183,694 218,683 Social security and unemployment 75,898 68,019 46,345 Other 18,436 28,292 32,709 Total general taxes

$ 677,852

$ 638,465

$ 650,329 Provision For Income Taxes:

Currently payable-Federal S 283,341

$ 306,347

$ 326,417 State 132,356 118,155 104,867 Foreign 11,165) 20,624 415,697 423,337 451,908 Deferred, net-Federal 245,967 71,910 81,934 State 38,968 8,133 7.759 Foreign 13,600 284,935 80,043 103,293 Investment tax credit amortization 126,672)

(26,404)

(26,507)

Total provision for income taxes

$ 673,960

$ 476,976

$ 528,694 Reconciliation of Federal Income Tax Expense at Statutory Rate lo Total Provision For Income Taxes:

Book income before provision for income taxes S 1,552,135

$ 899,740

$ 1,081,498 Federal income tax expense at statutory rate S 543,247

$ 314,909

$ 378,524 Increases (reductions) in taxes resulting from-Amortization of investment tax credits (26,672)

(26,404)

(26,507)

State income taxes, net of federal income tax benefit 111.361 82,088 73,207 Amortization of tax regulatory assets 32683 31,909 29,296 Preferred stock dividends 7,495 7,202 13,634 Reserve for foreign operations 44,305 48,587 Other, net 5,846 22,967 11,953 Total provision for income taxes

$ 673,960

$ 476.976

$ 528,694 Accumulated Deferred Income Taxes at December 31:

Property basis differences S 2,451,213

$ 2,293,209

$ 2,052,594 Regulatory transition charge 785,312 1,084,871 1.408,232 Customer receivables for future income taxes 103,149 139,335 144,073 Deferred sale and leaseback costs (92,417)

(95,474)

(99.647)

Nonutility generation costs (174,174)

(221,063)

(228,476)

Unamortized investment tax credits (61,267)

(70,054)

(78,227)

Other comprehensive income (219,020)

(243.743)

(398.883)

Lease market valuation liability (420,078)

(455,074)

(490.698)

Retirement Benefits (185,513)

(359,038)

(223,065)

Oyster Creek securitization (Note 10(C))

184,245 193,558 202,447 Loss carryforwards (463,106)

(495,254)

(507.690)

Loss carryforward valuation reserve 419,978 470,813 482,061 Purchase accounting basis differences (2,657)

(2.657) 12,657)

Sale of generating assets (9,539)

(11,785)

(11,786)

Provision for rate refund (29,370)

All other 8,031 (49,569)

(149,226)

Net deferred income tax liability

$ 2324,097

$ 2,178,075

$ 2.069,682

' Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income.

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

44 F rs'nfr-, Corp

.. ?

Notes To Consolidated Financial Statements

1. Organization and Basis of Presentation FirstEnergy's principal business is the holding, directly or indirectly, of all of the outstanding common stock of its eight principal electric utility operating subsidiaries: OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed and Penelec. Penn is a wholly owned subsidiary of OE. FirstEnergy's consolidated financial statements also include its other subsidiaries:

FENOC, FES and its subsidiary FGCO, FESC, FirstCom, FSG, GPU Capital, GPU Power and MYR.

FirstEnergy and its subsidiaries follow GAAP and com-ply with the regulations, orders, policies and practices prescribed by the SEC, FERC and, as applicable, the PUCO, PPUC and NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates.

FirstEnergy consolidates all majority-owned subsidiaries over which the Company exercises control and, when applica-ble, entities for which the Company has a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. Investments in nonconsolidated affiliates (20-50 percent owned companies, joint ventures and partnerships) over which the Company has the ability to exercise significant influence, but not control, are accounted for on the equity basis.

Certain prior year amounts have been reclassified to con-form to the current year presentation. Revenue amounts related to transmission activities previously recorded as whole-sale electric sales revenues were reclassified as transmission revenues. Expenses (including transmission and congestion charges) were reclassified among purchased power, other operating costs and amortization of regulatory assets to con-form to the current year presentation of generation commodity costs. FES' natural gas business has been classified as discon-tinued operations on the Consolidated Statements of Income (See Note 2(J)). As discussed in Note 14, segment reporting in 2003 and 2002 was reclassified to conform to the 2004 busi-ness segment organization and operations.

Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

2. Summary of Significant Accounting Policies (A) ACCOUNTING FOR THE EFFECTS OF REGULATION FirstEnergy accounts for the effects of regulation through the application of SFAS 71 to its operating utilities when their rates:

• are established by a third-party regulator with the authority to set rates that bind customers;

• are cost-based; and

• can be charged to and collected from customers.

An enterprise meeting all of these criteria capitalizes costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. SFAS 71 is applied only to the parts of the business that meet the above criteria. If a portion of the business applying SFAS 71 no longer meets those requirements, previously recorded regulatory assets are removed from the balance sheet in accordance with the guidance in SFAS 101.

In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions, that are reflected in the Companies' respective state regula-tory plans. These provisions include:

• restructuring the electric generation business and allow-ing the Companies' customers to select a competitive electric generation supplier other than the Companies;

• establishing or defining the PLR obligations to customers in the Companies' service areas;

• providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;

• itemizing (unbundling) the price of electricity into its component elements - including generation, transmis-sion, distribution and stranded costs recovery charges;

• continuing regulation of the Companies' transmission and distribution systems; and

• requiring corporate separation of regulated and unregulated business activities.

Regulatory Assets The EUOC recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recov-ery 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 expect-ed 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 distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those opera-tions. Regulatory assets that do not earn a current return totaled approximately $240 million as of December 31, 2004.

Net regulatory assets on the Consolidated Balance Sheets are comprised of the following:

2004 2003 (In millions)

Regulatory transition costs

$4.889 S6.427 Customer shopping Incentives -

612 371 Customer receivables for future income taxes 246 340 Societal benefits charge 51 81 Loss on reacquired debt 89 75 Employee postretirement benefit costs 65 77 Nuclear decommissioning. decontamination and spent fuel disposal costs 1169)

(961 Asset removal costs 1340 13211 Property losses and unrecovered plant costs 50 70 Other 39 53 Total

$5,532

$7,077 I

!SlGOE a.,.-,

.'45

The Ohio Companies are deferring customer shopping incentives and interest costs as new regulatory assets in accordance with the transition and rate stabilization plans.

These regulatory assets (OE - $228 million, CEI - $295 mil-lion, TE - $89 million, as of December 31, 2004) will be recovered through a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered.

Recovery of the new regulatory assets will begin at that time and amortization of the regulatory assets for each accounting period will be equal to the surcharge revenue recognized dur-ing that period. OE, TE and CEI expect to recover these deferred customer shopping incentives by August 31, 2008, September 30, 2008 and August 31. 2010, respectively.

Transition Cost Amortization OE, CEI and TE amortize transition costs (see Regulatory Matters - Ohio) using the effective interest method. Under the Rate Stabilization Plan, total transition cost amortization is expected to approximate the following for 2005 through 2009.

FirstEnergy OE CEI TE (In millions) 2005

$82B

$467

$222

$139 2006 404 193 126 85 2007 327 93 139 95 2008 159 159 2009

-54 54 The decrease in amortization beginning in 2006 results from the termination of generation-related transition cost recovery under the Ohio transition plan.

Regulatory transition costs as of December 31, 2004 for JCP&L, Met-Ed and Penelec are approximately $2.2 billion,

$0.7 billion and $0.1 billion, respectively. Deferral of above-market costs from power supplied by NUGs to JCP&L are approximately $1.2 billion and are being recovered through BGS and MTC revenues. Met-Ed and Penelec have deferred above-market NUG costs totaling approximately $0.5 billion and $0.1 billion, respectively. These costs are being recovered through CTC revenues. The regulatory asset for above-market NUG costs and a corresponding liability are adjusted to fair value at the end of each quarter. Recovery of the remaining regulatory transition costs is expected to continue under the.

provisions of the various regulatory proceedings for New Jersey and Pennsylvania discussed in Note 9.

Accounting for Generation Operations The application of SFAS 71 was discontinued prior to 2001 with respect to the Companies' generation operations.

The SEC's interpretive guidance regarding asset impairment measurement provided that any supplemental regulated cash flows such as a CTC should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows.

Consistent with the SEC guidance and EITF 97-4, $1.8 billion of impaired plant investments ($1.2 billion, $227 million, $304 million and $53 million for OE, Penn, CEI and TE, respectively) were recognized as regulatory assets recoverable as transition costs through future regulatory cash flows. The following summarizes net assets included in property, plant and equipment relating to operations for which the application of SFAS 71 was discontinued, com-pared with the respective company's total assets as of December 31, 2004.

SFAS 71 Discontinued Net Assets Total Assets (In millions)

CE

$1,059

$5.814 CEI 1263 6.690 TE 652

.Z834 Penn 263 921 JCP&L 39 7.291 Met-Ed 13 3.245 IB) CASH AND SHORT-TERM FINANCIAL INSTRUMENTS All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value.

IC) REVENUES AND RECEIVABLES The Companies' principal business is providing electric service to customers in Ohio, Pennsylvania and New Jersey.

The Companies' retail customers are metered on a cycle basis. Electric revenues are recorded based on energy deliv-ered through the end of the calendar month. An estimate of unbilled revenues is calculated to recognize electric service provided between the last meter reading and the end of the month. This estimate includes many factors including estimated weather impacts, customer shopping activity, his-torical line loss factors and prices in effect for each class of customer. In each accounting period, the Companies accrue the estimated unbilled amount receivable as revenue and reverse the related prior period estimate.

Receivables from customers include sales to residential, commercial and industrial customers and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2004 or 2003, with respect to any par-ticular segment of FirstEnergy's customers. Total customer receivables were $979 million (billed - $672 million and unbilled - $307 million) and $1.0 billion (billed - $664 million and unbilled - $336 million) as of December 31, 2004 and 2003, respectively.

Other receivables include amounts due from customers for unregulated sales and CEI's retained interest in customer receivables sold to CFC (see Note 12).

(Dl ACCOUNTING FOR CERTAIN WHOLESALE ENERGY TRANSACTIONS FES engages in purchase and sale transactions in the PJM Market to support the supply of end-use customers, including its BGS obligation in New Jersey and PLR require-ments in Pennsylvania. FES meets its supply commitments by transmitting energy into the PJM control area and through bilateral purchased power contracts with counterparties in PJM. FES schedules purchase and sale transactions for each 46 F AspF.c! acrp 20:k4

hour in PJM on a day-ahead basis with system balancing occurring real-time. FES sells energy to the PJM Market at the location of its supply (transmitted and contracted energy) and purchases energy from the PJM Market at the location of its demand (end-use customer load).

FES accounts for energy transactions in the PJM Market in accordance with EITF 99-19, recognizing purchases and sales on a gross basis by recording each discrete transaction.

This presentation may not be comparable to other energy companies that have dedicated generating capacity in ISOs or fail to meet the criteria for gross presentation in EITF 99-19.

FES' purchase and sale transactions in the PJM Market for the three years ended December 31, 2004 are summa-rized as follows:

2X4 2003 2002 (in millions)

Sales S1.182

$665

$272 Purchases 1,107 826 376 taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service.

The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred.

The Companies provide for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite rates for the Companies' electric plant in 2004, 2003 and 2002 are shown in the following table:

Annual Composite Depreciation Rate 2004 2003 2002 OE 2.3%

22%

2.4%

CEI 2Z8 2.8 3.6 TE 2.8 2.8 3.8 Penn

.:2.2 22 2.3.

JCP&L 2.1 2.8 3.5 Met-Ed 2A 2.6 3.0 Penelec 2.5

2.

3.0 (El EARNINGS PER SHARE Basic earnings per share are computed using the weight-ed average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. In 2004, 2003 and 2002, stock-based awards to purchase shares of common stock totaling 0.1 million, 3.3 million and 3.4 million, respectively, were excluded from the calculation of diluted earnings per share of common stock because their exercise prices were greater than the average market price of common shares during the period. The following table recon-ciles the denominators for basic and diluted earnings per share from Income Before Discontinued Operations and Cumulative Effect of Accounting Change:

Reconciliation of Basic and Diluted Earnings per Share 2004 2003 2002 (in thousands)

Income Before Discontinued Operations and Cumulative Effect of Accounting Change

$873,779

$424249

$618.385 Average Shares of Common Stock Outstanding:

Denominator for basic earnings per share (weighted average shares outstanding) 327,387 303.582 293,194

• Assumed exercise of dilutive stock options and awards 1595 1,390

-1227 Denominator for diluted earnings per share 328.982 304,972 294,421 Income Before Discontinued Operations and Cumulative Effect of Accounting Change per common share:

EBasic

$2.67

$1.40

$2.11 Diluted

$2.66

$1.40

$2.10 Jointly-Owned Generating Stations JCP&L holds a 50 percent ownership interest in Yards Creek Pumped Storage Facility - its net book value was approximately $19.2 million as of December 31, 2004. All other generating units are owned and/or leased by the Companies individually or together as tenants in common.

Asset Retirement Obligations FirstEnergy recognizes a liability for retirement obliga-tions associated with tangible assets in accordance with SFAS 143. This standard requires 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 capital-ized as part of the carrying value of the long-lived asset and depreciated over time, as described further in Note 11, "Asset Retirement Obligations".

Nuclear Fuel Property, plant and equipment includes nuclear fuel recorded at original cost, which includes material, enrich-ment, fabrication and interest costs incurred prior to reactor load. The Companies amortize the cost of nuclear fuel based on the units of production method.

(G) STOCK-BASED COMPENSATION FirstEnergy applies the recognition and measurement principles of APB 25 and related Interpretations in account-ing for its stock-based compensation plans (see Note 4).

No material stock-based employee compensation expense is reflected in net income for options as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the grant date, resulting in substantially no intrinsic value. FirstEnergy will apply the recognition and measurement principles of SFAS 123R effective July 1, 2005 (see Note 15).

(H) ASSET IMPAIRMENTS Long-Lived Assets FirstEnergy evaluates the carrying value of its long-lived assets when events or circumstances indicate that the car-(F) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment reflects original cost (except for nuclear generating assets which were adjusted to fair value), including payroll and related costs such as C,:

r.-,.I

)E<l?

47

rying amount may not be recoverable. In accordance with SFAS 144, the carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposi-tion of the asset. If an impairment exists, a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. Fair value is estimated by using available market valuations or the long-lived asset's expected future net discounted cash flows. The calculation of expected cash flows is based on estimates and assumptions about future events.

Goodwill In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment at least annually and makes such evaluations more frequently if indicators of impairment arise.

In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including 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 report-ing unit's goodwill and the carrying value of the goodwill.

FirstEnergy's 2003 annual review resulted in a non-cash goodwill impairment charge of $122 million in the third quar-ter of 2003, reducing the carrying value of FSG. Of this amount, $117 million was reported as an operating expense and $5 million was included in the results from discontinued operations. The impairment charge reflected the slow down in the development of competitive retail markets and depressed economic conditions that affected the value of FSG. The fair value of FSG was estimated using primarily its expected discounted future cash flows.

FirstEnergy's 2004 annual review was completed in the third quarter of 2004 with no impairment indicated. In December 2004, the FSG subsidiaries qualified as 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 required by SFAS 142, the goodwill of FSG was tested for impairment, resulting in a non-cash charge of $36 million in the fourth quarter of 2004. FSG's fair value was estimated using current market valuations.

The forecasts used in FirstEnergy's evaluations of good-will reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on FirstEnergy's future evalu-ations of goodwill. FirstEnergy's goodwill primarily relates to its regulated services segment. In the year ended December 31, 2004, FirstEnergy adjusted goodwill related to the former GPU companies for interest received on a pre-merger income tax refund and for the reversal of tax valuation allowances related to income tax benefits realized attributable to prior period capital loss carryforwards that were used to offset capital gains generated in 2004. The impairment analysis includes a significant source of cash representing the Companies' recovery of transition costs as described in Note 9. FirstEnergy estimates that completion of transition cost recovery will not result in an impairment of goodwill relating to its regulated business segment.

A summary of the changes in FirstEnergy's goodwill for the years ended December 31, 2004 and 2003 is shown below by segment (See Note 14 - Segment Information):

Competitive Electric Regulated Energy Facilities Services Services Services Otier Consolidated tin milions)

Balance as of Jan. 1,2003 S5.993

$24

$196

$65

$6.278 Impairment charges (1221 1122)

FSG divestitures 1411 (41)

Other

3.

10 13 Balance as of Dec. 31, 2003 5.993 24 36 75 6.128

, Impairment charges 136) 1361 Adjustments related to GPU acquisition (42) 142)

Balance as of Dec. 31, 2004 55.951

$24

$75

$6.050 Investments The Companies periodically evaluate for impairment investments that include available-for-sale securities held by their nuclear decommissioning trusts. In accordance with SFAS 115, securities classified as available-for-sale are eval-uated to determine whether a decline in fair value below the cost basis is other than temporary. If the decline in fair value is determined to be other than temporary, the cost basis of the security is written down to fair value. FirstEnergy con-siders, among other factors, the length of time and the extent to which the security's fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating investments for impairment. The fair value and unrealized gains and losses of the Companies' investments are disclosed in Note 5.

(1) COMPREHENSIVE INCOME Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholders' equity except those resulting from transactions with common stockholders.

As of December 31, 2004, AOCL consisted of a minimum liability for unfunded retirement benefits of $312 million, unrealized gains on investments in securities available for sale of $91 million, and unrealized losses on derivative instrument hedges of $92 million. As of December 31, 2003, AOCL consisted of a minimum liability for unfunded retirement benefits of $306 million, unrealized gains on investments in securities available for sale of $64 million, and unrealized losses on derivative instrument hedges of

$111 million. Other comprehensive income of $8 million was reclassified to net income in 2004, including an $8 million loss on derivative instrument hedges ($5 million net of tax) and a $22 million gain on available-for-sale securities ($13 million net of tax). Other comprehensive income (loss) reclassified to net income in 2003 and 2002 totaled $29 million and $(1 0) million, respectively. These amounts were net of income taxes in 2003 and 2002 of

$20 million and $(7) million, respectively.

48 (N

i.c, o"

(J) ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS In December 2004, the FSG subsidiaries qualified as held for sale in accordance with SFAS 144. Management anticipates that the transfer of FSG assets, with a carrying value of $57 million as of December 31, 2004, will qualify for recognition as completed sales within one year. As required by SFAS 142, the goodwill of FSG was tested for impairment, resulting in a non-cash charge of $36 million in the fourth quarter of 2004 (See Note 2(H)). As of December 31, 2004, the FSG subsidiaries classified as held for sale did not meet the criteria for discontinued operations. The carry-ing amounts of FSG's assets and liabilities held for sale are not material to and have not been classified as assets held for sale on FirstEnergy's Consolidated Balance Sheets. See Note 14 for FSG's segment financial information.

FES operates a natural gas business with commercial and industrial customers in Ohio, Pennsylvania and West Virginia.

Sales requirements are sourced through a combination of short-term and long-term supply agreements. In December 2004, FES' natural gas business qualified as held for sale in accordance with SFAS 144. Management expects to complete the sale within one year. As required by SFAS 142, goodwill associated with FES' natural gas business was tested for impairment as of December 31, 2004 with no impairment indi-cated. Financial results are included in discontinued operations on the Consolidated Statements of Income and classified as

'Other" in the segment financial information (See Note 14).

FES' natural gas purchases and sales for the three years ended December 31, 2004 are summarized as follows:

these divested businesses included in discontinued operations

("Other" in the table below) for the years ended December 2003 and 2002 totaled $(6) million and $5 million, respectively.

Revenues associated with discontinued operations were $496 million, $655 million and $878 million for 2004, 2003 and 2002, respectively. The following table summa-rizes the net income (loss) included in "Discontinued Operations" on the Consolidated Statements of Income for the three years ended December 31, 2004:

2004 2003 2002 (In millions)

FES' natural gas business

$ 4

$ 12)

$15 EGSA (35) 5 Emdersa (60)

.187) f0ther (6) 2 Discontinued operations income lioss)

$4

$1103)

$165) 2004 2003

'20' (In millions)

Natural gas sales 496

$603

$594 Natural gas purchases 480 583

-544 In December 2003, EGSA, GPU Power's Bolivia subsidiary, was sold to Bolivia Integrated Energy Limited.

FirstEnergy included in discontinued operations a $33 million loss on the sale of EGSA in the fourth quarter of 2003 (no income tax benefit was realized) and an operating loss for the year of $2 million. Discontinued operations in 2002 include EGSA's operating income of $10 million.

In April 2003, FirstEnergy divested its ownership in Emdersa through the abandonment of its shares in Emdersa's parent company, GPU Argentina Holdings, Inc. The abandon-ment was accomplished by relinquishing FirstEnergy's shares to the independent Board of Directors of GPU Argentina Holdings, relieving FirstEnergy of all rights and obligations relative to this business. FirstEnergy included in discontinued operations Emdersa's operating income of $11 million and a $67 million charge for the abandonment in the second quarter of 2003 (no income tax benefit was recognized). An after-tax loss of $87 million (including $109 million in currency transaction losses arising principally from U.S. dollar denomi-nated debt) was included in discontinued operations in 2002.

The FSG subsidiaries, Colonial Mechanical and Webb Technologies, were sold in January 2003 and Ancoma, Inc. was sold in December 2003. The MARBEL subsidiary, NEO was sold in June 2003. The 2003 and 2002 operating results for (K) CUMULATIVE EFFECT OF ACCOUNTING CHANGE As a result of adopting SFAS 143 in January 2003, FirstEnergy recorded a $175 million increase to income,

$102 million net of tax, or $0.33 per share of common stock (basic and diluted) in the year ended December 31, 2003. Upon adoption of the accounting standard, FirstEnergy reversed accrued nuclear plant decommissioning costs of $1.24 billion and recorded an ARO of $1.11 billion, including accumulated accretion of $507 million for the peri-od from the date the liability was incurred to the date of adoption. FirstEnergy also recorded asset retirement costs of $602 million as part of the carrying amount of the related long-lived asset and accumulated depreciation of $415 mil-lion. FirstEnergy recognized a regulatory liability of $185 million for the transition amounts subject to refund through rates related to the ARO for nuclear decommissioning. The cumulative effect adjustment also included the reversal of

$60 million of accumulated estimated removal costs for non-regulated generation assets.

(L) INCOME TAXES Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property.

Deferred income tax liabilities related to tax and accounting basis differences and tax credit carryforward items are rec-ognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled.

FirstEnergy has capital loss carryforwards of approximately

$1.1 billion, most of which expire in 2007. The deferred tax assets associated with these capital loss carryforwards

($364 million) are fully offset by a valuation allowance as of December 31, 2004, since management is unable to predict f

h,!1,;

,a:

49

whether sufficient capital gains will be generated to utilize all of these capital loss carryforwards. Any ultimate utiliza-tion of capital loss carryforwards for which valuation allowances were established through purchase accounting would adjust goodwill.

The Company has also recorded valuation allowances of

$51 million for deferred tax assets associated with impair-ment losses related to certain domestic assets and the divestiture of international assets acquired through the merger with GPU (see Note 8).

FirstEnergy has net operating loss carryforwards for state and local income tax purposes of approximately $884 million. A valuation allowance of $5 million has been record-ed against the associated deferred tax assets of $48 million. These losses expire as follows:

Expiration Period Amount (in millions) 2005-2009 o260 2010-2014 46 2015-2019 217 2020-2023 361

$884-employee demographics, plan experience and other factors.

Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations and pension and OPEB costs. FirstEnergy uses a December 31 measurement date for the majority of its plans.

3. Pension and Other Postretirement Benefit Plans FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees.

The trusteed plans provide defined benefits based on years of service and compensation levels. The Company's funding policy is based on actuarial computations using the project-ed unit credit method. In the third quarter of 2004, FirstEnergy made a $500 million voluntary contribution to its pension plan. Prior to this contribution, projections indicated that cash contributions of approximately $600 million would have been required during the 2006 to 2007 time period under minimum funding requirements established by the IRS. The election to pre-fund the plan is expected to elimi-nate that funding requirement. Since the contribution is deductible for tax purposes, the after-tax cash impact of the voluntary contribution was approximately $300 million.

FirstEnergy provides a minimum amount of noncontrib-utory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their sur-vivors. The Company recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits.

Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans and earnings on plan assets. Such factors may be fur-ther affected by business combinations which impact Obligations and Funded Status As of December 31 Pension Benefits Other Benefits 2004 2003 2004 2003 (In millions)

Change in benefit obligation Benefit obligation as of January 1 54.162 53,866

$ 2.368 5 2.077 Service cost 77 66 36 43 Interest cost 252 253 112 136 Plan participants' contributions 14 6

Plan amendments 1281)

(123)

- Actuarial (gain) loss 134 222 (211) 323 Benefits paid 1261)

(245) 1108)

(94)

Benefit obligation as of December31 54.364

$4.162

$ 1.930 52.368 Change in fair value of plan assets

-Fair value of plan assets as of January 1 53.315 52.889 S 537 S 473 Actual return on plan assets 415 671 -

57 88 Company contribution 500 64 68 Plan participants' contribution 14 2

Benefits paid 1261) 1245)

(1081 (94)

.Fair value of plan assets asofDecember31

$3.969

$3.315 S

564 S 537 Funded status S (395) 5 (847) 5 (1,366)

S(1,831)

Unrecognized net actuarialloss 885 919 730 994

,Unrecognized prior service cost (benefit) 63 72 (378)

(221)

Unrecognized net transition obligation 83 Net asset (liability) recognized

$ 553 5 144

$ (1.014) 5 (975)

Amounts Recognized in the Consolidated Balance Sheets As of December 31 Accrued benefit cost 5(14)

$ (438) 511,014) 5 (975)

• Intangible assets 63 72 Accumulated other comprehensive loss 504 510 Net amount recognized 5553 5 144 511.014) 5 (975)

Increase (decrease) in minimum liability included in other comprehensive income (netof tax)

$ (4)

$ 1145)

Assumptions Used to Determine Benefit Obligations

' As of December 31

-Discount rate 6.00%

6.25-6.00%

6.25' i',Rate of compensation increase

- 3.50%

3.50' Allocation of Plan Assets As of December 31 Asset Category

'Equity securities 68%

70%

74%

71' Debt securities 29 27 25 22 Real estate 2

2 Cash 1

1 1

7

• Total 100' 100' 100' 100' Information for Pension Plans With an Accumulated Benefit

.Obligation In Excess of Plan Assets Projected benefit obligation

'Accumulated benefit obligation Fair value of plan assets 2004 2003 (In millions) 54,364 54,162 3.983 3,753 3.969 3,315 50 1

- vC.'

f

Components of Net Periodic Benefit Costs -

Pension Benefits Other Benefits 2004 2003 2002 2004 2003 2002

--In millions)

Service cost

$77

$ 66

$59

$36

$43.

29 Interest cost 252 253

.249 112 137.-

114 Expected return on plan assets 1286)

(248)

(346) 144) 143) (52)

Amortization of prior service cost 9

9 9

(40).

(9) 3-Amortization of transition obligation (asset) 9 9

Recognizednetactuarialloss 39 62 39 40 11; Netperiodiccost(income)

$91

$142 S(29)

$103

$177

$114 Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 Pension Benefits Other Benefits 20o4 200 2002 2004 203 20m Discount rate 6.25' 6.75' 7.25' 6.25' 6.75' 7.25' Expected long-term return on plan assets 9.00%

9.00%

10.25' 9.00' 9.00% 10.25%

Rate of compensation increase 3.50' 3.50%

4.00' Effect on total of service and interest cost Effect on postretirement benefit obligation 1-Percentage 1-Percentage Point Increase Point Decrease (In millions)

$ 19 S 116)

$205

$1179)

In selecting an assumed discount rate, FirstEnergy con-siders currently available rates of return on high-quality fixed income investments expected to be available during the peri-od to maturity of the pension and other postretirement benefit obligations. The assumed rate of return on pension plan assets considers 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 con-sidering the portfolio's asset allocation strategy.

FirstEnergy employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversi-fied across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalizations. Other assets such as real estate are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments.

Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.

Assumed Health Care Cost Trend Rates As of December 31 2004 2003 Health care cost trend rate assumed for next year (pre/post-Medicare) 9%-l's 10%-12'.-

Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) 5%

5%

Year that the rate reaches the ultimate trend rate Ipre/post-Medicare) 2009-2011 2009-2011 Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

Pursuant to FSP 106-1 issued January 12, 2004, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 because of a plan amendment during the quarter, which required remeasure-ment of the plan's obligations. The plan amendment, which increases cost sharing by employees and retirees effective January 1, 2005, reduced postretirement benefit costs by

$51 million during 2004.

Consistent with the guidance in FSP 106-2 issued on May 19, 2004, FirstEnergy recognized a reduction of $318 million in the accumulated postretirement benefit obligation as a result of the federal subsidy provided under the Medicare Act related to benefits for past service. This reduction was accounted for as an actuarial gain in 2004 pursuant to FSP 106-2. The subsidy reduced net periodic postretirement benefit costs by $48 million during 2004.

As a result of its voluntary contribution and the increased market value of pension plan assets, FirstEnergy reduced its accrued benefit cost as of December 31, 2004 by $424 million. As prescribed by SFAS 87, FirstEnergy reduced its additional minimum liability by $15 million, recording a decrease in an intangible asset of $9 million and crediting OCI by $6 million. The balance in AOCL of $296 million (net of $208 million in deferred taxes) will reverse in future periods to the extent the fair value of trust assets exceeds the accumulated benefit obligation.

Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets:

Pension Benefits Other Benefits

-/n millions) 2005

$ 228

$111 2006 228 106 2007 236.

109 2008 247 112 2009 264 115 Years2010-2014 1.531 627

4. Stock-Based Compensation Plans FirstEnergy has four stock-based compensation pro-grams: Long-term Incentive Program (LTIP); Executive Deferred Compensation Plan (EDCP); Employee Stock Ownership Plan (ESOP); and the Deferred Compensation Plan for Outside Directors (DCPD). FirstEnergy has also assumed responsibility for several stock-based plans through acquisitions. In 2001, FirstEnergy assumed respon-sibility for two stock-based plans as a result of its acquisition of GPU. No further stock-based compensation can be awarded under GPU's Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan) or 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock

.. 51

under both plans have been converted into FirstEnergy options and restricted stock. Options under the GPU Plan became fully vested on November 7, 2001, and will expire on or before June 1, 2010. Under the MYR Plan, all options and restricted stock maintained their original vesting periods, which range from one to four years, and will expire on or before December 17, 2006. The Centerior Equity Plan (CE Plan) is an additional stock-based plan administered by FirstEnergy for which it assumed responsibility as a result of the acquisition of Centerior Energy Corporation in 1997. All options are fully vested under the CE Plan, and no further awards are permitted. Outstanding options will expire on or before February 25, 2007.

Stock Option Activities Balance. January 1, 2002 (1.828.341 options exercisable)

• Options granted Options exercised Options forfeited Balance. December31, 2002 (1,400,206 options exercisable)

Options granted Options exercised

- Options forfeited Balance. December 31, 2003

(1.919,662 options exercisable)

Options granted Options exercised Options forfeited Balance, December 31, 2004 13.175.023 options exercisable)

Number of Weighted Average Options Exercise Price 8.447,688 526.04 24.83 3.399.579 34.48 1,018.852 23.56 392.929 28.19 10,435,486 28.95 26.07 3.981,100 29.71 455.986 25.94 311.731 29.09 13,648,869 29.27 29.67 3.373,459 38.77 3,622,148 26.52 167.425 32.58 13.232.755 32.40 29.07 (A) ILTIP FirstEnergy's LTIP includes three stock-based compen-sation programs - restricted stock, stock options, and performance shares.

Under FirstEnergy's LTIP, total awards cannot exceed 22.5 million shares of common stock or their equivalent.

Only stock options and restricted stock have currently been designated to pay out in common stock, with vesting periods ranging from two months to seven years. Performance share awards are currently designated to be paid in cash rather than common stock and therefore do not count against the limit on stock-based awards. As of December 31, 2004, 4.5 million shares were available for future awards.

Restricted Stock Eligible employees receive awards of FirstEnergy com-mon stock subject to restrictions. Those restrictions lapse over a defined period of time or based on performance.

Dividends are received on the restricted stock and are rein-vested in additional shares. Restricted common stock grants under the FE Plan were as follows:

Options outstanding by plan and range of exercise price as of December 31, 2004 were as follows:

Options Options Outstanding Exercisable Weighted Weighted Range of Avg.

Remaining

- Avg.

Exercise Exercise Contractual Exercise FE Program Prices Shares Price ufe Shares Price

'FE plan

$19.31-529.87 6.972,940 528.82 7.0 1.903.790

$26.72 la a S30.17-$39.46 5.907,710 536.89 8.3 919.128 534.37 Plans acquired

-Thrnigh merger.

.GPu plan S23.75-435.92 341,455 528.35 4.4 341,455

$28.35 MYR plan S 9.35-514.23 8.550

$12.70 4.5 8.550

$12.70 CE plan 525.14-525.15 2,100 525.14 2.2 2.100

$25.14 Total 13.232,755

$32.40 7.5 3.175,023

$29.07 The weighted average fair value of options granted in 2004, 2003 and 2002, respectively, are estimated below using the Black-Scholes option-pricing model and the following assumptions:

2004 2003

,2002 Fair value per option

$6.72 55.09 56.45

• Weighted average valuation assumptions:

Expected option term (yearsl 7.6 7.9

. 8.1 Expected volatility 26.25' 26.91%

23.31' Expected dividend yield 3.88' 5.09' 4.36' Risk-free interest rate 1.99%

3.67' 4.60' Compensation expense for FirstEnergy stock options is based on intrinsic value, which equals any positive differ-ence between FirstEnergy's common stock price on the option's grant date and the option's exercise price. The exer-cise prices of all stock options granted in 2004, 2003 and 2002 equaled the market price of FirstEnergy's common stock on the options' grant dates. If fair value accounting were applied to FirstEnergy's stock options, net income and earnings per share would be reduced as summarized below.

Restricted common shares granted

• Weighted average market price -

Weighted average vesting period (years)

Dividends restricted I No restricted stock was granted.

2004 62,370

$40.69 2.7 Yes 2003' 200 36.922

$36M.04 s3.2 Yes :

Compensation expense recognized for restricted stock during 2004, 2003 and 2002 totaled $1,982,000, $1,747,000 and $2,259,000, respectively.

Stock Options Stock option grants are provided to eligible employees allowing them to purchase a specified number of common shares at a fixed grant price over a defined period of time.

Stock option activities under the FE Programs for the past three years were as follows:

52 ;

I "t-a-,~ C(;rp S.-1,

2004 2003

-2002 fin thousands, except per share amounts)

Net Income. as reported 5878.175 5422.764

$552.804 Add back compensation expense reported in net income, net of tax (based on APB 251.

21.177 23.625

',22.981 Deduct compensation expense based upon estimated fair value, net of tax' (35,6601 (35.8161 (31,6401 Proforma net income 5853.692 5410.573 5544.145 Earnings Per Share of Common Stock -

Basic As Reported

$2.68 S139 51.89 Proforma

$2.64 51.35

$1.86.

Diluted As Reported

-2.67 51.39

'1.88 Proforma 52.63 51.35 51.85 Incldes restricted stock stock options, performance shares, ESO) EDCP and DCPD.

FirstEnergy anticipates reducing its use of stock options beginning in 2005 and increasing its use of performance-based, restricted stock units. Therefore, the pro forma effects of applying SFAS 123 may not be representative of its future effect. FirstEnergy has not and does not expect to accelerate out-of-the-money options in anticipation of imple-menting revisions to SFAS 123 on July 1, 2005 (see Note 15

- "New Accounting Standards and Interpretations").

Performance Shares Performance shares are share equivalents and do not have voting rights. The shares track the performance of FirstEnergy's common stock over a three-year vesting peri-od. During that time dividend equivalents are converted into additional shares. The final account value may be adjusted based on the ranking of FirstEnergy stock to a composite of peer companies. Compensation expense recognized for per-formance shares during 2004, 2003 and 2002 totaled

$4,924,000, $7,131,000 and $6,757,000, respectively.

(B) ESOP An ESOP Trust funds most of the matching contribution for FirstEnergy's 401 (k) savings plan. All full-time employees eligible for participation in the 401(k) savings plan are cov-ered by the ESOCR The ESOP borrowed $200 million from OE and acquired 10,654,114 shares of OE's common stock (subsequently converted to FirstEnergy common stock) through market purchases. Dividends on ESOP shares are used to service the debt. Shares are released from the ESOP on a pro rata basis as debt service payments are made. In 2004, 2003 and 2002, 864,151 shares, 1,069,318 shares and 1,151,106 shares, respectively, were allocated to employees with the corresponding expense recognized based on the shares allocated method. The fair value of 2,032,800 shares unallocated, as of December 31, 2004, was approximately $80 million. Total ESOP-related compen-sation expense was calculated as follows:

2004 2003 2002 (In millions)

Base compensation 532 535 534 Dividends on common stock held by the ESOP and used to service debt (9)

19) 18)

Net expense 523 526

$26 (C) EDCP Under the EDCP. covered employees can direct a portion of their compensation, including annual incentive awards and/or long-term incentive awards, into an unfunded FirstEnergy stock account to receive vested stock units. An additional 20 percent premium is received in the form of stock units based on the amount allocated to the FirstEnergy stock account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout typically occurs three years from the date of deferral; however, an elec-tion can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement. Of the 1.3 million EDCP stock units author-ized, 776,072 stock units were available for future award as of December 31, 2004. Compensation expense recognized on EDCP stock units in 2004, 2003 and 2002 totaled $2,31 1.000,

$2,312,000 and $206,000, respectively.

(D) DCPD Under the DCPD, directors can elect to allocate all or a portion of their cash retainers, meeting fees and chair fees to a deferred stock or deferred cash accounts. If the funds are deferred into the stock account, a 20 percent match is added to the funds allocated. The 20 percent match and any appreci-ation on it are forfeited if the director leaves the Board within three years from the date of deferral for any reason other than retirement, disability, death, upon a change in control, or when a director is ineligible to stand for re-election. Compensation expense is recognized for the 20 percent match over the three-year investing period. Directors may also elect to defer their equity retainers into the deferred stock account, however, they do not receive a 20 percent match for this deferral.

DCPD expenses recognized in 2004, 2003, and 2002 were

$3,556,000, $2,233,000 and $2,728,000, respectively.

5. Fair Value of Financial Instruments Long-term Debt and Other Long-term Obligations All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following table provides the approximate fair value and related carry-ing amounts of long-term debt and other long-term obligations as of December 31:

2004 2003 Carrying Fair Carrying Fair Value Value Value Value (In millions)

Long-termdebt 510.787 511,341

$11,177 511,648 Subordinated debentures to affiliated trusts 103 112 294 322 Preferred stock subject to mandatory redemption 17 16 19 19

$10.907 511,469

$11,490

$11.989 The fair values of long-term debt and other long-term

. Cy,.;Y.'

53

obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by cor-porations with credit ratings similar to the Companies' ratings.

Investments The carrying amounts of cash and cash equivalents approximate fair value due to the short-term nature of these investments. The following table provides the approximate fair value and related carrying amounts of investments other than cash and cash equivalents as of December 31:

2004 2003' Carrying Fair Carrying Fair Value Value Value Value (In millions)

Debt securities: (I.

-Government obligations S 797 S 797 S 707

$ 707

-Corporate debt securities M 1.205 1.362 1.492

- 1,601

-Mortgage-backed securities 2

2 2,004 2.161 2,199 2.308.

Equity securities

'13 1.033 1,033 1.068 1,068

$3.037 33.194

-$3267-33.376 -

17) hIludes nuclear decommissioning. nuclear fuel disposal and NUG trust investments:

0 includes investments in lease obligation bonds (See Note 6).

The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms.

Investments other than cash and cash equivalents include held-to-maturity securities and available-for-sale secu-rities. Decommissioning trust investments are classified as available-for-sale. The Companies have no securities held for trading purposes. The following table summarizes the amor-tized cost basis, unrealized gains and losses and fair values for decommissioning trust investments as of December 31:

2004 2003 Un-

- Un-Un-Un-Cod realized realized Fair Cost realized realized Fairk Basis Gains Losses Value Basis Gains Losses Value

( {In millions)

Debtsecurities 616 $19 S 3S 632 $ 548 $ 26 S 1 S 573 Equity securities 763 207 19 951.

593 >217 31 779

$1.379

$226

$22 S1.583 S1.141

$243

$32 S1.352 losses on nuclear decommissioning trust investments that are deemed to be temporarily impaired as of December 31, 2004:

Less Than 12 Months Fair Unrealized Value,

Losses 12 Months or More -

, Total Fair Unrealized Fair -Unrealized Value

-Losses Value' Losses (In millions)

.Debtsecurities

$175 S 3

$20 3195 '

$ 3 Equity securities 129 12 39 7

168 19

$34

$15

$59

$7

$363

$22 The Companies periodically evaluate the securities held by their nuclear decommissioning trusts for other-than-tem-porary impairment. FirstEnergy considers the length of time and the extent to which the security's fair value has been less than its cost basis and other factors to determine whether impairment is other than temporary. Unrealized gains and losses applicable to the decommissioning trusts of FirstEnergy's Ohio Companies are recognized in OCI in accordance with SFAS 115, as fluctuations in fair value will eventually affect earnings. The decommissioning trusts of FirstEnergy's Pennsylvania and New Jersey Companies are subject to regulatory accounting in accordance with SFAS

71. Net unrealized gains and losses are recorded as regula-tory liabilities or assets since the difference between investments held in trust and the decommissioning liabilities are recovered from, or refunded to, customers.

The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securi-ties of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries.

Proceeds from the sale of decommissioning trust investments, realized gains and losses on those sales, and interest and dividend income for the three years ended December 31, 2004 were as follows:

2004 203 20 (In millions)

Proceeds from sales 1.234

$ 758

$599 Realized gains 144 38 32 Realized losses 43 32 47 Interest and dividend income 45 37

' 33 '

Derivatives FirstEnergy is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including prices for electricity, natural gas and coal. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes, and to a lesser extent, for trading purposes. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout the Company.

They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.

How derivative instruments are used and classified deter-mines how they are reported in FirstEnergy's financial statements. FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchase and normal sales criteria. The changes in the fair value of a derivative instrument are recorded in current earnings, in other comprehensive income, or as part of the value of the hedged item depending on whether or not it is designated as part of a hedge transaction and on the nature of the hedge transaction. FirstEnergy's primary ongoing hedging The following table provides the fair value of and unrealized 54,.-t v g Cears ',X

activity involves cash flow hedges of electricity and natural gas purchases. The maximum periods over which the variability of electricity and natural gas cash flows are hedged are two and three years, respectively. Gains and losses from hedges of com-modity price risks are included in net income when the underlying hedged commodities are delivered. Also, gains and losses are included in net income when ineffectiveness occurs on certain natural gas hedges. The impact of ineffectiveness on earnings during 2004 was not material. FirstEnergy entered into interest rate derivative transactions during 2001 to hedge a por-tion of the anticipated interest payments on debt related to the GPU acquisition. Gains and losses from hedges of anticipated interest payments on acquisition debt are included in net income over the periods that hedged interest payments are made - 5, 10 and 30 years. Gains and losses from derivative contracts are included in other operating expenses. AOCL as of December 31, 2004 includes a net deferred loss of $92 million for derivative hedging activity. The $19 million decrease from the December 31, 2003 balance of $111 million includes an $11 million reduction due to the sale of GLEP. a $3 million reduction related to current hedging activity and a $5 million decrease due to net hedge losses included in earnings during the year. Approximately $14 million (after tax) of the current net deferred loss on derivative instruments in AOCL is expected to be reclassified to earnings during the next twelve months as hedged transactions occur.

The fair value of these derivative instruments will continue to fluctuate from period to period based on various market factors.

During 2004, FirstEnergy executed fixed-for-floating interest rate swap agreements, whereby FirstEnergy receives fixed cash flows based on the fixed coupons of the hedged securities and pays variable cash flows based on short-term variable market inter-est rates (3 and 6 months LIBOR index). These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues -

protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, fixed interest rates received, and interest payment dates match those of the underlying obligations. FirstEnergy entered into inter-est rate swap agreements on a $900 million notional amount of subsidiaries' senior notes and subordinated debentures with a weighted average fixed interest rate of 5.67%. In addition, FirstEnergy unwound swaps with a total notional amount of $400 million from which it received $12 million in cash gains during 2004. The gains will be recognized over the remaining maturity of each respective hedged security as reduced interest expense. As of December 31, 2004, the aggregate notional value of interest rate swap agreements outstanding was $1.65 billion.

FirstEnergy engages in the trading of commodity deriva-tives and periodically experiences net open positions.

FirstEnergy's risk management policies limit the exposure to market risk from open positions and require daily reporting to management of potential financial exposures. Discretionary trad-ing in 2004 resulted in a $2 million gain.

6. Leases The Companies lease certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases.

OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years. CEI and TE also sold portions of their ownership inter-ests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 and entered into similar operating leases for lease terms of approximately 30 years. During the terms of their respec-tive leases, OE, CEI and TE continue to be responsible, to the extent of their individual combined ownership and leasehold interests, for costs associated with the units including con-struction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning.

They have the right, at the expiration of the respective basic lease terms, to renew their respective leases. They also have the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair mar-ket value of the facilities. The basic rental payments are adjusted when applicable federal tax law changes.

Consistent with the regulatory treatment, the rentals for capi-tal and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs for the three years ended December 31, 2004 are summarized as follows:

2004 2003 2002 (In millions)

Operating leases Interest element

$172

$181

$188 Other 126 150 136 Capital leases Interest element 1

2 2

Other 3

2

.3 Total rentals

$302

$335

$329 OE invested in the PNBV Capital Trust, which was established to purchase a portion of the lease obligation bonds issued on behalf of lessors in OE's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. CEI and TE established the Shippingport Capital Trust to pur-chase the lease obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. The PNBV and Shippingport Capital Trust arrangements effectively reduce lease costs related to those transactions (see Note 7).

The future minimum lease payments as of December 31, 2004 are:

Operating Leases Capital Lease Capital Leases Payments Trusts Net (In millions)

.2005

$ 5

$ 313 S 130 S 183 2006 5

322 142 180 2007 1

299 130 169

.2008 1

294 105 189 2009 1

298 111 187 Years thereafter

.6 2.217 763 1,454

'Total minimum lease payments 19

.$3.743.

$1.381

2. 3262 Executory costs 4

Net minimum lease payments 15

. Interest portion 4

Present value of net minimum lease payments 11 Less current portion 2

Noncurrent portion

$ S 9 f,:fr~wresor;C

,X' 55

FirstEnergy has recorded above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant asso-ciated with the 1997 merger between OE and Centerior.

The total above-market lease obligation of $722 million asso-ciated with Beaver Valley Unit 2 is being amortized on a straight-line basis through the end of the lease term in 2017 (approximately $37 million per year). The total above-market lease obligation of $755 million associated with the Bruce Mansfield Plant is being amortized on a straight-line basis through the end of 2016 (approximately $48 million per year). As of December 31, 2004 the above-market lease lia-bilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant totaled $1.0 billion, of which $85 million is current.

7. Variable Interest Entities FIN 46R, addresses the consolidation of VIEs, including spe-cial-purpose entities, that are not controlled through voting interests or in which the equity investors do not bear the residual economic risks and rewards. FirstEnergy adopted FIN 46R for special-purpose entities as of December 31, 2003 and for all other entities in the first quarter of 2004. The first step under FIN 46R is to determine whether an entity is within the scope of FIN 46R, which occurs if it is deemed to be a VIE. FirstEnergy and its subsidiaries consolidate VIEs where they have determined that they are the primary beneficiaries as defined by FIN 46R.

Leases Included in FirstEnergy's consolidated financial state-ments are PNBV and Shippingport, two VIEs created in 1996 and 1997, respectively, to refinance debt originally issued in connection with the sale and leaseback transac-tions discussed above in Note 6. PNBV and Shippingport financial data are included in the consolidated financial state-ments of OE and CEI, respectively.

PNBV was established to purchase a portion of the lease obligation bonds issued in connection with OE's 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. Ownership of PNBV includes a three-percent equity interest by a nonaffiliated third party and a three-percent equity interest held by OES Ventures, a whol-ly owned subsidiary of OE. Shippingport was established to purchase all of the lease obligation bonds issued in connec-tion with CEl's and TE's Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.

Through its investment in PNBV, OE has, and through their investments in Shippingport, CEI and TE have, variable interests in certain owner trusts that acquired the interests in the Perry Plant and Beaver Valley Unit 2, in the case of OE, and the Bruce Mansfield Plant, in the case of CEI and TE. FirstEnergy concluded that OE, CEI and TE were not the primary beneficiaries of the relevant owner trusts and were therefore not required to consolidate these entities. The combined purchase price of $3.1 billion for all of the inter-ests acquired by the owner trusts in 1987 was funded with debt of $2.5 billion and equity of $600 million.

OE, CEI and TE are exposed to losses under the appli-cable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. OE, CEI and TE each have a maximum exposure to loss under these provisions of approximately $1 billion, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the applicable plant worthless. Under the appli-cable sale and leaseback agreements, OE, CEI and TE have net minimum discounted lease payments of $673 million,

$115 million and $570 million, respectively, that would not be payable if the casualty value payments are made.

Power Purchase Agreements FirstEnergy has evaluated its power purchase agree-ments and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Companies and the contract price for power is correlated with the plant's variable costs of produc-tion. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains approximately 30 long-term power pur-chase agreements with NUG entities. The agreements were structured pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.

FirstEnergy has determined that for all but nine of these entities, neither JCP&L, Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R.

JCP&L, Met-Ed or Penelec may hold variable interests in the remaining nine entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants.

As required by FIN 46R, FirstEnergy requests, on a quarterly basis, the information necessary from these nine entities to determine whether they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary.

FirstEnergy has been unable to obtain the requested infor-mation, which in most cases was deemed by the requested entity to be proprietary. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R. The maximum exposure to loss from these entities results from increases in the variable pricing component under the contract terms and cannot be determined without the requested data. The cost of power purchased from these entities during 2004, 2003 and 2002 was $210 mil-lion, $194 million and $184 million, respectively.

FirstEnergy is required to continue to make exhaustive efforts to obtain the necessary information in future periods and is unable to determine the possible impact of consoli-dating any such entity without this information.

8. Divestitures International Operations FirstEnergy completed the sale of its international oper-ations in January 2004 with the sales of its remaining 20.1 56 :. :

....... Lcilv AX-4^

percent interest in Avon (parent of Midlands Electricity in the United Kingdom) on January 16, 2004, and its 28.67 percent interest in TEBSA for $12 million on January 30, 2004. Impairment charges related to TEBSA and Avon (included in Other Operating Expenses on the Consolidated Statements of Income) were recorded in the fourth quarter of 2003 and no gain or loss was recognized upon the sales in 2004. Avon, TEBSA and other international assets sold in 2003 were originally acquired as part of FirstEnergy's November 2001 merger with GPU.

International operations in Bolivia were divested by the December 2003 sale of FirstEnergy's wholly owned sub-sidiary, Guaracachi America, Inc., a holding company with a 50.001 percent interest in EGSA, resulting in a loss on sale of $33 million (recognized in Discontinued Operations in the Consolidated Statement of Income for the year ended December 31, 2003). International operations in Argentina represented by FirstEnergy's ownership in Emdersa were divested through the abandonment of its shares in Emdersa's parent company, GPU Argentina Holdings, Inc. in April 2003. As a result of the abandonment, FirstEnergy rec-ognized a one-time, non-cash charge of $67 million, or $0.23 per share of common stock in the second quarter of 2003.

The charge did not include the expected income tax bene-fits related to the abandonment, which were fully reserved during the second quarter of 2003. FirstEnergy expects tax benefits of approximately $129 million, of which $50 million would increase net income in the period that it becomes probable those benefits will be realized. The remaining $79 million of tax benefits would reduce goodwill recognized in connection with the acquisition of GPU.

FirstEnergy had sold a 79.9 percent equity interest in Avon in May 2002 to Aquila, Inc. for approximately $1.9 bil-lion (consisting of the assumption of $1.7 billion of debt,

$155 million in cash and a $87 million note receivable). In the fourth quarter of 2002, FirstEnergy recorded a $50 mil-lion after-tax charge to reduce the carrying value of its remaining 20.1 percent interest. After reaching agreement to sell its remaining 20.1 percent interest in the fourth quar-ter of 2003, FirstEnergy recorded a $5 million after-tax charge to reduce the carrying value. These charges were included in Other Operating Expenses on the Consolidated Statements of Income for the years ended December 31, 2002 and 2003, respectively. In the second quarter of 2003, FirstEnergy recognized an impairment of $13 million ($8 mil-lion net of tax) related to the carrying value of the note receivable from Aquila. After receiving the first annual installment payment of $19 million in May 2003, FirstEnergy sold the remaining balance of its note receivable in the secondary market and received $63 million in pro-ceeds in July 2003.

Generation Assets In August 2002, FirstEnergy cancelled a November 2001 agreement to sell four coal-fired power plants (2,535 MW) to NRG Energy Inc. because NRG stated that it could not complete the transaction under the original terms of the agreement. NRG filed voluntary bankruptcy petitions in May 2003; subsequently, FirstEnergy reached an agreement for settlement of its claim against NRG. FirstEnergy sold its entire claim (including $32 million of cash proceeds received in December 2003) for $170 million in January 2004.

Other Domestic Operations FirstEnergy sold its 50 percent interest in GLEP on June 23, 2004. Proceeds of $220 million included cash of

$200 million and the right, valued at $20 million, to partici-pate for up to a 40% interest in future wells in Ohio. This transaction produced an after-tax loss of $7 million, or $0.02 per share of common stock, including the benefits of prior tax capital losses that had been previously fully reserved, which offset the capital gain from the sale. In 2003, FirstEnergy sold three FSG subsidiaries - Ancoma, Inc., a mechanical contracting company based in Rochester, New York, and Virginia-based Colonial Mechanical and Webb Technologies - and a MARBEL subsidiary - Northeast Ohio Natural Gas (see Note 2(J)).

9. Regulatory Matters Reliability Initiatives In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability enti-ties (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force) regarding enhancements to regional reliability. With respect to each of these reliability enhancement initiatives, FirstEnergy submitted its response to the respective entity according to any required response dates. In 2004, FirstEnergy completed implementation of all actions and initiatives related to enhancing area reliability, improving voltage and reactive management, operator readi-ness and training, and emergency response preparedness recommended for completion in 2004. Furthermore, FirstEnergy certified to NERC on June 30, 2004, with minor exceptions noted, that FirstEnergy had completed the rec-ommended enhancements, policies, procedures and actions it had recommended be completed by June 30, 2004. In addition, FirstEnergy requested, and NERC provided, a tech-nical assistance team of experts to assist in implementing and confirming timely and successful completion of various initiatives. The NERC-assembled independent verification team confirmed on July 14, 2004, that FirstEnergy had implemented the NERC Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts required to be completed by June 30, 2004, as well as NERC recommendations contained in the Control Area Readiness Audit Report required to be completed by summer 2004, and recommendations in the U.S. - Canada Power System Outage Task Force Report directed toward FirstEnergy and required to be completed by June 30, 2004, with minor exceptions noted by FirstEnergy. On December 28, 2004, FirstEnergy submitted a follow-up to its June 30, 2004 Certification and Report of Completion to NERC addressing the minor exceptions, which are now essentially complete.

FirstEnergy is proceeding with the implementation of the recommendations that were to be completed subse-I f er noe1,'8-Cst,. ^'i 57

quent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for fore-casted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhance-ments in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review the FirstEnergy filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

On July 5, 2003, JCP&L experienced a series of 34.5 kilovolt sub-transmission line faults that resulted in outages on the New Jersey shore. On July 16, 2003, the NJBPU ini-tiated an investigation into the cause of JCP&L's outages of the July 4, 2003 weekend. The NJBPU selected an SRM to oversee and make recommendations on appropriate cours-es of action necessary to ensure system-wide reliability.

Additionally, pursuant to the stipulation of settlement that was adopted in the NJBPU's Order of March 13, 2003 in its docket relating to the investigation of outages in August 2002, the NJBPU, through an independent auditor working under direction of the NJBPU Staff, undertook a review and focused audit of JCP&L's Planning and Operations and Maintenance programs and practices (Focused Audit).

Subsequent to the initial engagement of the auditor, the scope of the review was expanded to include the outages during July 2003.

Both the independent auditor and the SRM submitted interim reports primarily addressing improvements to be made prior to the next occurrence of peak loads in the sum-mer of 2004. On December 17, 2003, the NJBPU adopted the SRM's interim recommendations related to service relia-bility. With the assistance of the independent auditor and the SRM, JCP&L and the NJBPU staff created a Memorandum of Understanding (MOU) that set out specific tasks to be performed by JCP&L and a timetable for completion. On March 29, 2004, the NJBPU adopted the MOU and endorsed JCP&L's ongoing actions to implement the MOU.

On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of the SRM and the Executive Summary and Recommendation portions of the final report of the Focused Audit. A Final Order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. JCP&L continues to file compliance reports reflecting activities asso-ciated with the MOU and Stipulation.

In May 2004, the PPUC issued an order approving the revised reliability benchmark and standards, including revised benchmarks and standards for Met-Ed, Penelec and Penn. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004 seeking amendment of the benchmarks and standards due to their implementation of automated outage manage-ment systems following restructuring. Evidentiary hearings have been scheduled for September 2005. FirstEnergy is unable to predict the outcome of this proceeding.

On January 16, 2004, the PPUC initiated a formal inves-tigation of whether Met-Ed's, Penelec's and Penn's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Hearings were held in early August 2004.

On September 30, 2004, Met-Ed, Penelec and Penn filed a settlement agreement with the PPUC that addresses the issues related to this investigation. As part of the settle-ment, Met-Ed, Penelec and Penn agreed to enhance service reliability, ongoing periodic performance reporting and com-munications with customers and to collectively maintain their current spending levels of at least $255 million annually on combined capital and operation and maintenance expen-ditures for transmission and distribution for the years 2005 through 2007. The settlement also outlines an expedited remediation process to address any alleged non-compliance with terms of the settlement and an expedited PPUC hear-ing process if remediation is unsuccessful. On November 4, 2004, the PPUC accepted the recommendation of the ALJ approving the settlement.

Ohfo In October 2003, the Ohio Companies filed an applica-tion for a Rate Stabilization Plan with the PUCO to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncer-tainty following the end of the Ohio Companies' transition plan market development period. On February 24, 2004, the Ohio Companies filed a revised Rate Stabilization Plan to address PUCO concerns related to the original Rate Stabilization Plan. On June 9, 2004, the PUCO issued an order approving the revised Rate Stabilization Plan, subject to conducting a competitive bid process. On August 5, 2004, the Ohio Companies accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. In the second quarter of 2004, the Ohio Companies implemented the accounting modifications related to the extended amortization periods and interest costs deferral on the deferred customer shopping incentive balances. On October 1 and October 4, 2004, the OCC and NOAC, respectively, filed appeals with the Supreme Court of Ohio to overturn the June 9, 2004 PUCO order and associated entries on rehearing.

The revised Rate Stabilization Plan extends current gen-eration prices through 2008, ensuring adequate generation supply at stabilized prices, and continues the Ohio Companies' support of energy efficiency and economic development efforts. Other key components of the revised Rate Stabilization Plan include the following:

• extension of the transition cost amortization period for OE from 2006 to as late as 2007; for CEI from 2008 to as late as mid-2009 and for TE from mid-2007 to as late as mid-2008;

• deferral of interest costs on the accumulated cus-tomer shopping incentives as new regulatory assets; and 58 c..s'.'rr'c

.7c0, 4

• ability to request increases in generation charges dur-ing 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes.

On December 9, 2004, the PUCO rejected the auction price results from a required competitive bid process and issued an entry stating that the pricing under the approved revised Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may cause the Ohio Companies to under-take, no more often than annually, a similar competitive bid process to secure generation for the years 2007 and 2008.

Any acceptance of future competitive bid results would ter-minate the Rate Stabilization Plan pricing, but not the related approved accounting, and not until twelve months after the PUCO authorizes such termination.

New Jersey JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and MTC rates. As of December 31, 2004, the accumulated deferred cost balance totaled approximately $446 million.

New Jersey law allows for securitization of JCP&Ls deferred balance upon application by JCP&L and a determi-nation by the NJBPU that the conditions of the New Jersey restructuring legislation are met. On February 14, 2003, JCP&L filed for approval of the securitization of the deferred balance. There can be no assurance as to the extent, if any, that the NJBPU will permit such securitization.

In July 2003, the NJBPU announced its JCP&L base electric rate proceeding decision, which reduced JCP&L's annual revenues effective August 1, 2003 and disallowed

$153 million of deferred energy costs. The NJBPU decision also provided for an interim return on equity of 9.5% on JCP&L's rate base. The decision ordered a Phase II proceed-ing be conducted to review whether JCP&L is in compliance with current service reliability and quality standards. The BPU also ordered that any expenditures and projects under-taken by JCP&L to increase its system's reliability be reviewed as part of the Phase II proceeding, to determine their prudence and reasonableness for rate recovery. In that Phase II proceeding, the NJBPU could increase JCP&L's return on equity to 9.75% or decrease it to 9.25%, depend-ing on its assessment of the reliability of JCP&L's service.

Any reduction would be retroactive to August 1, 2003.

JCP&L recorded charges to net income for the year ended December 31, 2003, aggregating $185 million ($109 million net of tax) consisting of the $153 million of disallowed deferred energy costs and $32 million of other disallowed regulatory assets. In its final decision and order issued on May 17, 2004, the NJPBU clarified the method for calculat-ing interest attributable to the cost disallowances, resulting in a $5.4 million reduction from the amount estimated in 2003. JCP&L filed an August 15, 2003 interim motion for rehearing and reconsideration with the NJBPU and a June 1, 2004 supplemental and amended motion for rehearing and reconsideration. On July 7, 2004, the NJBPU granted limited reconsideration and rehearing on the following issues: (1) deferred cost disallowances (2) the capital structure including the rate of return (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning costs. Management is unable to predict when a decision may be reached by the NJBPU.

On July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU, requesting an increase in base rates of $36 million for the recovery of system reliability costs and a 9.75% return on equity. The filing also requests an increase to the MTC deferred balance recovery of approximately $20 million annually. The Ratepayer Advocate filed testimony on November 16, 2004, and JCP&L submit-ted rebuttal testimony on January 4, 2005. Settlement conferences are ongoing.

JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order.

The BGS auction for periods beginning June 1, 2004 was completed in February 2004 and new BGS tariffs reflecting the auction results became effective June 1, 2004. The NJBPU decision on the BGS post transition year three process was announced on October 22, 2004, approving with minor modifications the BGS procurement process filed by JCP&L and the other New Jersey electric distribu-tion companies and authorizing the continued use of NUG committed supply to serve 300 MW of BGS load. The auc-tion for the supply period beginning June 1, 2005 was completed in February 2005.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a contin-uation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding.

On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study (see Note 11 - Asset Retirement Obligations). This study resulted in an updated total decom-missioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The Ratepayer Advocate filed comments on February 28, 2005. A schedule for further proceedings has not yet been set.

Pennsylvania In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties in the combined merger and rate relief proceedings, which approved the FirstEnergy/GPU merger and provided Met-Ed and Penelec PLR deferred accounting treatment for energy costs. A February 2002 Commonwealth Court of Pennsylvania deci-sion affirmed the PPUC decision regarding approval of the merger, remanded the issue of quantification and allocation of merger savings to the PPUC and denied the PLR deferral accounting treatment. In October 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC's June 2001 order in its entirety. In accordance with the PPUC's direction, Met-Ed and Penelec filed supple-ments to their tariffs which were effective October 2003 I,'_!.

59

that reflected the CTC rates and shopping credits in effect prior to the June 21, 2001 order.

In response to its October 8, 2003 petition, the PPUC approved June 30, 2004 as the date for Met-Ed's and Penelec's NUG trust fund refunds and denied their account-ing request regarding the CTC rate/shopping credit swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1. 2002 on a retroac-tive basis. Met-Ed and Penelec subsequently filed with the Commonwealth Court, on October 31, 2003, an Application for Clarification with the judge, a Petition for Review of the PPUC's October 2 and October 16 Orders, and an applica-tion for reargument if the judge, in his clarification order, indicates that Met-Ed's and Penelec's Objection was intend-ed to be denied on the merits. The Reargument Brief before the Commonwealth Court was filed January 28, 2005.

In accordance with PPUC directives, Met-Ed and Penelec have been negotiating with interested parties in an attempt to resolve the merger savings issues that are the subject of remand from the Commonwealth Court. These companies' combined portion of total merger savings is esti-mated to be approximately $31.5 million. If no settlement can be reached, Met-Ed and Penelec will take the position that any portion of such savings should be allocated to customers during each company's next rate proceeding.

Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sale agreement. The PLR sale is automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. Met-Ed and Penelec are authorized to continue deferring differences between NUG contract costs and current market prices.

Transmission On November 1, 2004, ATSI requested authority from the FERC to defer approximately $54 million of vegetation management costs ($13 deferred as of December 31, 2004 pending authorization) estimated to be incurred from 2004 through 2007. The FERC approved ATSI's request to defer those costs on March 4, 2005.

ATSI and MISO filed with the FERC on December 2, 2004, seeking approval for ATSI to have transmission rates established based on a FERC-approved cost of service - for-mula rate included in Attachment 0 under the MISO tariff.

The ATSI Network Service net revenue requirement increased under the formula rate to approximately $159 mil-lion. On January 28, 2005, the FERC accepted for filing the revised tariff sheets to become effective February 1, 2005, subject to refund, and ordered a public hearing be held to address the reasonableness of the proposal to eliminate the voltage-differentiated rate design for the ATSI zone.

On December 30, 2004, the Ohio Companies filed an application with the PUCO seeking tariff adjustments to recover increases of approximately $30 million in transmis-sion and ancillary service costs beginning January 1, 2006.

The Ohio Companies also filed an application for authority to defer costs associated with MISO Day 1, MISO Day 2, con-gestion fees, FERC assessment fees, and the ATSI rate increase, as applicable, from October 1, 2003 through December 31, 2005.

On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005, estimated to be approxi-mately $8 million per month.

Various parties have intervened in each of the cases above.

On September 16, 2004, the FERC issued an order that imposed additional obligations on CEI under certain pre-Open Access transmission contracts among CEI and the cities of Cleveland and Painesville. Under the FERC's deci-sion, CEI may be responsible for a portion of new energy market charges imposed by MISO when its energy markets begin in the spring of 2005. CEI filed for rehearing of the order from the FERC on October 18, 2004. The impact of the FERC decision on CEI is dependent upon many factors, including the arrangements made by the cities for transmis-sion service, the startup date for the MISO energy market, and the resolution of the rehearing request, and cannot be determined at this time.

10. Capitalization (A) COMMON STOCK Retained Earnings and Dividends Under applicable federal law, FirstEnergy (as a regis-tered holding company) and its subsidiaries can pay dividends only from retained, undistributed or current earn-ings, unless the SEC specifically authorizes payment from other capital accounts. As of December 31, 2004, FirstEnergy's unrestricted retained earnings were $1.9 bil-lion. Provisions within the articles of incorporation, indentures and various other agreements relating to the long-term debt and preferred stock of certain FirstEnergy subsidiaries contain provisions that could restrict the pay-ment of dividends on their common and preferred stock. As of December 31, 2004, there were no material restrictions on retained earnings under these agreements for payment of cash dividends on FirstEnergy's common stock.

On November 30, 2004, the Board of Directors increased the indicated annual dividend to $1.65 per share, payable quarterly at a rate of $0.4125 per share, and declared the first quarter 2005 dividend. At December 31, 2004, accrued dividends of approximately $135 million were included in other current liabilities on the Consolidated Balance Sheet. Dividends declared in 2004 were $1.9125 which included quarterly dividends of $0.375 per share paid in each quarter of 2004 and a dividend of $0.4125 payable in the first quarter of 2005. Dividends declared in 2003 were 60 a-slrr.'

l C

OCVJ

$1.50, which included quarterly dividends of $0.375 per share paid in each quarter of 2003. The amount and timing of all dividend declarations are subject to the discretion of the Board and its consideration of business conditions, results of operations, financial conditions and other factors.

(B) PREFERRED AND PREFERENCE STOCK All preferred stock may be redeemed by the Companies in whole, or in part, with 30-90 days' notice.

CEI will exercise its option to redeem all outstanding shares of two series of preferred stock during the first quar-ter of 2005 as follows:

Series Outstanding Shares Call Price 7.40A 500,000 101.00 l

474.000 100.00 Met-Ed's and Penelec's preferred stock authorizations consist of 10 million and 11.435 million shares, respectively, without par value. No preferred shares are currently out-standing 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 Preferred Stock Subject to Mandatory Redemption SFAS 150 requires financial instruments issued in the form of shares that are mandatorily redeemable to be classi-fied as long-term debt. Annual sinking fund provisions for the Companies' preferred stock are as follows:

Redemption Price -

Series Shares PerShare CEo S 7.35C 10.000

$1S0:0 Penn 7.625%

7.500 100 Annual sinking fund requirements will be satisfied by the end of 2008 and consist of $1.8 million in 2005 and 2006, $12.3 million in 2007 and $1.0 million in 2008.

Subordinated Debentures to Affiliated Trusts As of December 31, 2004, CEI's wholly owned statuto-ry business trust, Cleveland Electric Financing Trust, had

$100 million of outstanding 9.00% preferred securities maturing in 2031. The sole assets of the trust are CEl's sub-ordinated debentures with the same rate and maturity date as the preferred securities.

CEI formed the trust to sell preferred securities and invest the gross proceeds in the 9.00% subordinated debentures of CEI. The sole assets of the trust are the appli-cable subordinated debentures. Interest payment provisions of the subordinated debentures match the distribution pay-ment provisions of the trust's preferred securities. In addition, upon redemption or payment at maturity of subordi-nated debentures, the trust's preferred securities will be redeemed on a pro rata basis at their liquidation value. Under certain circumstances, the applicable subordinated deben-tures could be distributed to the holders of the outstanding preferred securities of the trust in the event that the trust is liquidated. CEI has effectively provided a full and uncondi-tional guarantee of payments due on the trust's preferred securities. The trust's preferred securities are redeemable at 100 percent of their principal amount at CEl's option begin-ning in December 2006. Interest on the subordinated debentures (and therefore distributions on the trust's pre-ferred securities) may be deferred for up to 60 months, but CEI may not pay dividends on, or redeem or acquire, any of its cumulative preferred or common stock until deferred pay-ments on its subordinated debentures are paid in full.

Met-Ed and Penelec had each formed statutory busi-ness trusts for substantially similar transactions to those of CEI, with ownership of the respective Met-Ed and Penelec trusts through separate wholly owned limited partnerships.

In June 2004 and September 2004, respectively, Met-Ed and Penelec extinguished the subordinated debentures held by their respective trusts, who in turn redeemed their respective preferred securities.

Securitized Transition Bonds On June 11, 2002, JCP&L Transition Funding LLC (Issuer), a wholly owned limited liability company of JCP&L, sold $320 million of transition bonds to securitize the recov-ery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station.

JCP&L does not own nor did it purchase any of the transition bonds, which are included in long-term debt on FirstEnergy's Consolidated Balance Sheets. The transition bonds represent obligations only of the Issuer and are collat-eralized solely by the equity and assets of the Issuer, which consist primarily of bondable transition property. The bond-able transition property is solely the property of the Issuer.

Bondable transition property represents the irrevocable right of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on the transition bonds and other fees and expenses associated with their issuance. JCP&L, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to a servicing agreement with the Issuer.

Other Long-term Debt Each of the Companies has a first mortgage indenture under which it issues FMBs secured by a direct first mort-gage lien on substantially all of its property and franchises, other than specifically excepted property. FirstEnergy and its subsidiaries have various debt covenants under their respec-tive financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt and the maintenance of certain financial ratios. The fixed charge ratio and debt-to-capitalization ratio covenants are applicable to only financing arrangements of FirstEnergy, the Ohio Companies and Penn. There also exist cross-default provisions among financing arrangements of 61

FirstEnergy and the Companies.

Based on the amount of FMBs authenticated by the respective mortgage bond trustees through December 31, 2004, the Companies' annual sinking fund requirements for all FMBs issued under the various mortgage indentures amounts to $71 million. OE and Penn expect to deposit funds with their respective mortgage bond trustees in 2005 that will then be withdrawn upon the surrender for cancella-tion of a like principal amount of FMBs, specifically authenticated for such purposes against unfunded property additions or against previously retired FMBs. This method can result in minor increases in the amount of the annual sinking fund requirement. JCP&L, Met-Ed and Penelec expect to fulfill their sinking fund obligations by providing bondable property additions and/or previously retired FMBs to the respective mortgage bond trustees.

Sinking fund requirements for FMBs and maturing long-term debt (excluding capital leases) for the next five years are:

(In millions) 2005 S 937 2006 1,327 2007

.453 2008 470 2009 285 Included in the table above are amounts for various vari-able interest rate pollution control bonds which have provisions by which individual debt holders have the option to "put back" or require the respective debt issuer to redeem their debt at those times when the interest rate may change prior to its maturity date. These amounts are $442 million and

$132 million in 2005 and 2008, respectively, representing the next times the debt holders may exercise this provision.

The Companies' obligations to repay certain pollution control revenue bonds are secured by several series of FMBs. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank LOCs of $299 million or noncancelable municipal bond insurance policies of $922 million to pay principal of, or interest on, the applicable pol-lution control revenue bonds. To the extent that drawings are made under the LOCs or the policies, the Companies are entitled to a credit against their obligation to repay those bonds. The Companies pay annual fees of 1.0% to 1.7% of the amounts of the LOCs to the issuing banks and 0.20% to 0.55% of the amounts of the policies to the insurers and are obligated to reimburse the banks or insurers, as the case may be, for any drawings thereunder.

FirstEnergy had unsecured borrowings of $215 million as of December 31, 2004, under its $1 billion revolving cred-it facility agreement which expires June 22, 2007.

FirstEnergy currently pays an annual facility fee of 0.30% on the total credit facility amount. FirstEnergy had no borrow-ings as of December 31, 2004 under a $375 million long-term revolving credit facility agreement, which expires October 23, 2006. FirstEnergy currently pays an annual facil-ity fee of 0.50% on the total credit facility amount. The fees are subject to change based on changes to FirstEnergy's credit ratings.

OE had no unsecured borrowings as of December 31, 2004 under a $250 million long-term revolving credit facility agreement, which expires May 12, 2005. OE currently pays an annual facility fee of 0.20% on the total credit facility amount.

OE had no unsecured borrowings as of December 31, 2004 under a $125 million long-term revolving credit facility, which expires October 23, 2006. OE currently pays an annual facility fee of 0.25% on the total credit facility amount. The fees are subject to change based on changes to OE's credit ratings.

OES Finance, Incorporated, a wholly owned subsidiary of OE, had maintained certificates of deposits pledged as collateral to secure reimbursement obligations relating to certain LOCs supporting OE's obligations to lessors under the Beaver Valley Unit 2 sale and leaseback arrangements.

In June 2004, these LOCs were replaced by a new LOC, which did not require the collateral deposits. OE entered into a Credit Agreement pursuant to which a standby LOC was issued in support of the replacement LOCs and the issuer of the standby LOC obtained the right to pledge or assign participations in OE's reimbursement obligations to a trust. The trust then issued and sold trust certificates to institutional investors that were designed to be the credit equivalent of an investment directly in OE. The certificates of deposit were cancelled and FirstEnergy received cash proceeds of $278 million in the third quarter of 2004.

CEI and TE have unsecured LOCs of approximately $216 million in connection with the sale and leaseback of Beaver Valley Unit 2 that expire in April 2005. CEI and TE are jointly and severally liable for such LOCs. OE has LOCs of $294 mil-lion and $154 million in connection with the sale and leaseback of Beaver Valley Unit 2 and Perry Unit 1, respectively.

11. Asset Retirement Obligations In January 2003, FirstEnergy implemented SFAS 143, which provides accounting guidance for retirement obligations associated with tangible long-lived assets. This standard requires recognition of the fair value of a liability for an ARO in the period in which it is incurred. The associated asset retire-ment costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depre-ciated and the present value of the ARO increases, resulting in a period expense. However, rate-regulated entities may recog-nize a regulatory asset or liability instead of an expense if the criteria for such treatment are met. Upon retirement, a gain or loss would be recognized if the cost to settle the retirement obligation differs from the carrying amount.

FirstEnergy has identified applicable legal obligations as defined under the standard for nuclear power plant decom-missioning, reclamation of a sludge disposal pond related to the Bruce Mansfield Plant and closure of two coal ash dispos-al sites. The ARO liability was $1.078 billion as of December 31, 2004 and included $1.063 billion for nuclear decommis-sioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. The Companies' share of the obligation to decommission these units was developed based on site specific studies performed by an independent engi-neer. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

62

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In the third quarter of 2004, FirstEnergy revised the ARO associated with TMI-2 as the result of a recently completed study and the anticipated operating license extension for TMI-

1. The abandoned TMI-2 is adjacent to TMI-1 and the units are expected to be decommissioned concurrently. The decrease in the present value of estimated cash flows associated with the license extension of $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.

The Companies maintain nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of December 31, 2004, the fair value of the decommissioning trust assets was

$1.583 billion.

The following table describes the changes to the ARO balances during 2004 and 2003.

AR0 Reconciliation 2004 2003 (in millions)

Balanceatbeginningofyear

$1.179

$1,109 Liabilities incurred Liabilities settled Accretion 75

-70 Revisions in estimated cash flows (176)

Balance at end of year

$1,078

$1,179 The following table describes the changes to the ARO for 2002, as if SFAS 143 had been adopted on January 1, 2002.

Adjusted ARO Reconciliation 2002 (In millions)

Beginning balance as of January 1.2002

$1,042

-Accretion 67 Ending balance as of December 31. 2002

$1,109 The following table provides the effect on income as if SFAS 143 had been applied during 2002.

12. Short-Term Borrowings and Bank Lines of Credit:

Short-term borrowings outstanding as of December 31, 2004, consisted of $29 million of OE bank borrowings and

$142 million of OES Capital, Incorporated borrowings. OES Capital is a wholly owned subsidiary of OE whose borrow-ings are secured by customer accounts receivable purchased from OE. OES Capital can borrow up to $170 million under a receivables financing arrangement at rates based on certain bank commercial paper and is required to pay an annual fee of 0.25% on the amount of the entire finance limit. The receivables financing agreement expires in October 2005.

Penn, Met-Ed and Penelec have, through separate wholly owned subsidiaries, receivables financing arrangements that provide a combined borrowing capability of up to $180 mil-lion at rates based on bank commercial paper rates. The financing arrangements require payment of an annual facility fee of 0.30% on the entire finance limit. The receivables financing agreements for Penn, Met-Ed and Penelec expire in March 2005. These receivables financing arrangements are expected to be renewed prior to expiration.

OE has various bilateral credit facilities with domestic banks that provide for borrowings of up to $34 million under various interest rate options. To assure the availability of these lines, OE is required to pay annual commitment fees that vary from 0.20% to 0.25% of total lender commit-ments. These lines expire at various times during 2005. The weighted average interest rates on short-term borrowings outstanding as of December 31, 2004 and 2003 were 2.35% and 2.14%, respectively.

CEI and TE sell substantially all of their retail customer receivables to CFC, a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust under an asset-backed securitization agreement. The trust is a "quali-fied special purpose entity' under SFAS 140, which provides it with certain rights relative to the transferred assets. Transfers are made in return for an interest in the trust (62% as of December 31, 2004), which is stated at fair value, reflecting adjustments for anticipated credit losses.

The fair value of CFC's interest in the trust approximates the stated value of its retained interest in the underlying receiv-ables, after adjusting for anticipated credit losses, because the average collection period is 27 days. Accordingly, subse-quent measurements of the retained interest under SFAS 115, (as an available-for-sale financial instrument) result in no material change in value. Sensitivity analyses reflecting 10% and 20% increases in the rate of anticipated credit losses would not have significantly affected FirstEnergy's retained interest in the pool of receivables through the trust.

Of the $222 million sold to the trust and outstanding as of December 31, 2004, FirstEnergy retained interests in

$138 million of the receivables. Accordingly, receivables recorded as other receivables on the Consolidated Balance Sheets were reduced by approximately $84 million due to these sales. Collections of receivables previously transferred to the trust and used for the purchase of new receivables from CFC during 2004 totaled approximately $2.5 billion. CEI Effect of the Change In Accounting Principle Applied Retroactively (In millions)

Reported net income

, $553.

Increase (Decrease Elimination of decommissioning expense 88 Depreciation of asset retirement cost 13)

Accretion of ARO liability (38)

Non-regulated generation cost of removal component net

- 15 Income tax effect (25)U.-

Net earnings increase 37 Net income adjusted

$5-9 Basic earnings per share of common stock:

Net income as previously reported

$1.89 Adjustment for effect of change in accounting principle applied retroactively 0.12 Net income adjusted

$2.01 Diluted earnings per share of common stock Net income as previously reported

$1.88 Adjustment for effect of change in accounting principle applied retroactively 0.12 Net income adjusted

- $2.00

[.Ct, t.'O :.,,::,

63

and TE processed receivables for the trust and received servicing fees of approximately $4.8 million in 2004.

Expenses associated with the factoring discount related to the sale of receivables were $3.5 million in 2004.

13. Commitments, Guarantees and Contingencies:

(A) NUCLEAR INSURANCE-The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $10.8 billion.

The amount is covered by a combination of private insurance and an industry retrospective rating plan. The Companies' maximum potential assessment under the industry retro-spective rating plan would be $402 million per incident but not more than $40 million in any one year for each incident.

The Companies are also insured under policies for each nuclear plant. Under these policies, up to $2.75 billion is provid-ed for property damage and decontamination costs. The Companies have also obtained approximately $1.5 billion of insurance coverage for replacement power costs. Under these policies, the Companies can be assessed a maximum of approximately $67.5 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses.

The Companies intend to maintain insurance against nuclear risks as long as it is available. To the extent that replacement power, property damage, decontamination, repair and replacement costs and other such costs arising from a nuclear incident at any of the Companies' plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Companies' insurance policies, or to the extent such insurance becomes unavailable in the future, the Companies would remain at risk for such costs.

(B) GUARANTEES AND OTHER ASSURANCES-As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to pro-vide financial or performance assurances to third parties.

Such agreements include contract guarantees, surety bonds and ratings contingent collateralization provisions. As of December 31, 2004, outstanding guarantees and other assurances aggregated approximately $2.4 billion and includ-ed contract guarantees ($1.0 billion), surety bonds ($0.3 billion) and LOC ($1.1 billion).

FirstEnergy guarantees energy and energy-related pay-ments of its subsidiaries involved in energy commodity activities - principally to facilitate normal physical transac-tions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisi-tion of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterpar-ty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.9 billion (included in the $1.0 bil-lion discussed above) as of December 31, 2004 will increase amounts otherwise to be paid by FirstEnergy to meet its obligations incurred in connection with financings and ongo-ing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obliga-tions, subsequent to the occurrence of a credit rating downgrade or "material adverse event" the immediate post-ing of cash collateral or provision of an LOC may be required of the subsidiary. The following table summarizes collateral provisions as of December 31, 2004:

Collateral Provisions Collateral Paid Exposure Cash LOC Remaining Exposures)

(in millions)

Credit rating downgrade

$349

$162

$18

$169 Adverse Event 135 22 113 Total

$484

$162

$40

$282.

-JAs of February 7. 2005. the total exposure decreased to $476 million and the remaining exposure increased to $290 million -net of $146 million of cash collateral and $40 million of LOC collateralprovided by counterpartes.

Most of FirstEnergy's surety bonds are backed by vari-ous indemnities common within the insurance industry.

Surety bonds and related FirstEnergy guarantees of $279 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction jobs, environmental commit-ments and various retail transactions.

FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $6 mil-lion (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee.

FirstEnergy has also provided an LOC (currently at $47 mil-lion), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

(C) ENVIRONMENTAL MATTERS Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position. These environmental regulations affect FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, FirstEnergy believes it is in com-pliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $430 million for 2005 through 2007.

64 Fts! e'- rcv

'00J

Clean Air Act Compliance The Companies are required to meet federally approved S02 regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for S02 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

The Companies believe they are complying with S02 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more elec-tricity from lower-emitting plants, and/or using emission allowances. NOx reductions required by the 1990 Amend-ments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants.

In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' facilities.

The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85 percent reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOx emissions are con-tributing significantly to ozone levels in the eastern United States. The Companies believe their facilities are also com-plying with the NOx budgets established under State Implementation Plans (SlPs) through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.

National Ambient Air Quality Standards In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine par-ticulate matter. On December 17, 2003, the EPA proposed the "Interstate Air Quality Rule" covering a total of 29 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on pro-posed findings that air pollution emissions from 29 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. The EPA has proposed the Interstate Air Quality Rule to "cap-and-trade" NOx and S02 emissions in two phases (Phase I in 2010 and Phase II in 2015). According to the EPA, S02 emissions would be reduced by approximately 3.6 million tons annually by 2010, across states covered by the rule, with reductions ultimately reaching more than 5.5 million Ions annually.

NOx emission reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in 2015. The future cost of compliance with these proposed regulations may be substantial and will depend on whether and how they are ultimately implemented by the states in which the Companies operate affected facilities.

Mercury Emissions In December 2000, the EPA announced it would pro-ceed with the development of regulations regarding haz-ardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern.

On December 15, 2003, the EPA proposed two different approaches to reduce mercury emissions from coal-fired power plants. The first approach would require plants to install controls known as MACT based on the type of coal burned. According to the EPA, if implemented, the MACT proposal would reduce nationwide mercury emissions from coal-fired power plants by 14 tons to approximately 34 tons per year. The second approach proposes a cap-and-trade program that would reduce mercury emissions in two dis-tinct phases. Initially, mercury emissions would be reduced by 2010 as a "co-benefit" from implementation of S02 and NOx emission caps under the EPA's proposed Interstate Air Quality Rule. Phase II of the mercury cap-and-trade program would be implemented in 2018 to cap nationwide mercury emissions from coal-fired power plants at 15 tons per year.

The EPA has agreed to choose between these two options and issue a final rule by March 15, 2005. The future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn.

In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S.

District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dat-ing back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase of the trial to address civil penalties and what, if any, actions should be taken to further reduce emis-sions at the plant has been delayed without rescheduling by the Court because the parties are engaged in meaningful settlement negotiations. The Court indicated, in its August 2003 ruling, that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consid-er the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on FirstEnergy's, OE's and Penn's respective financial condi-tion and results of operations. While the parties are engaged 2

.v '

, C..2U 65

in meaningful settlement discussions, management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of December 31, 2004.

Regulation of Hazardous Waste As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently deter-mined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste.

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Compre-hensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiat-ed and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis.

Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of December 31, 2004, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Included in Current Liabilities and Other Noncurrent Liabilities are accrued liabilities aggregating approxi-mately $65 million as of December 31, 2004. The Companies accrue environmental liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims are reflected in the Companies' determination of environ-mental liabilities and are accrued in the period that they are both probable and reasonably estimable.

Climate Change In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity - the ratio of emissions to eco-nomic output - by 18 percent through 2012.

The Companies cannot currently estimate the financial impact of climate change policies, although the potential restrictions on C02 emissions could require significant capi-tal and other expenditures. However, the C02 emissions per kilowatt-hour of electricity generated by the Companies is lower than many regional competitors due to the Companies' diversified generation sources which includes low or non-C02 emitting gas-fired and nuclear generators.

Clean Water Act Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amend-ments, apply to the Companies' plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to the Companies' operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania

,have assumed such authority.

On September 7, 2004, the EPA established new per-formance standards under Clean Water Act Section 316(b) for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mor-tality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system and entrainment, which occurs when aquatic species are drawn into a facility's cooling water system. The Companies are conducting compre-hensive demonstration studies, due in 2008, to determine the operational measures, equipment or restoration activities, if any, necessary for compliance by their facilities with the per-formance standards. FirstEnergy is unable to predict the outcome of such studies. Depending on the outcome of such studies, the future cost of compliance with these standards may require material capital expenditures.

(D) OTHER LEGAL PROCEEDINGS-Power Outages and Related Litigation In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the caus-es of the outages and the reliability of the transmission and distribution systems of all four New Jersey electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inade-quate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceed-ing) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresenta-tion, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Court issued a decision on July 8, 2004, affirming the decertification of the originally certified class but remanding for certification of a class limited to those customers directly impacted by the 66 F.rs'-1/2ecv C. rc 20a:

outages of transformers in Red Bank, New Jersey. On September 8, 2004, the New Jersey Supreme Court denied the motions filed by plaintiffs and JCP&L for leave to appeal the decision of the Appellate Court. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of December 31, 2004.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. On April 5, 2004, the U.S. - Canada Power System Outage Task Force released its final report on the out-ages. In the final report, the Task Force concluded, among other things, that the problems leading to the outages began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand per-ceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a per-ceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organi-zations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy's website (www.doe.gov).

FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the out-ages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contains 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommen-dations relate to broad industry or policy matters while one, including subparts, relates to activities the Task Force recom-mends be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outage. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which are consistent with these and other recommendations and collectively enhance the reliability of its electric system.

FirstEnergy certified to NERC on June 30, 2004, completion of various reliability recommendations and further received inde-pendent verification of completion status from a NERC verification team on July 14, 2004 with minor exceptions noted by FirstEnergy (see Note 9). FirstEnergy's implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its continuing operations or financial results.

FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend addi-tional enhancements in the future that could require additional, material expenditures. FirstEnergy has not accrued a liability as of December 31, 2004 for any expenditures in excess of those actually incurred through that date.

Three substantially similar actions were filed in various Ohio state courts by plaintiffs seeking to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outages. All three cases were dismissed for lack of juris-diction. One case was refiled at the PUCO. The other two cases were appealed. One case was dismissed and no further appeal was sought. The remaining case is pending. In addition to the one case that was refiled at the PUCO, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages.

One complaint has been filed against FirstEnergy in the New York State Supreme Court. In this case, several plain-tiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy filed a motion to dismiss with the Court on October 22, 2004. No timetable for a deci-sion on the motion to dismiss has been established by the Court. No damage estimate has been provided and thus potential liability has not been determined.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.

Nuclear Plant Matters FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury inves-tigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assess-ment of reactor head management issues at Davis-Besse.

In addition, FENOC remains subject to possible civil enforcement action by the NRC in connection with the events leading to the Davis-Besse outage in 2002. If it were ultimately determined that FirstEnergy or its subsidiaries has legal liability or is otherwise made subject to enforcement action based on the Davis-Besse outage, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.

On August 12, 2004, the NRC notified FENOC that it will increase its regulatory oversight of the Perry Nuclear Power 23 67

Plant as a result of problems with safety system equipment over the past two years. FENOC operates the Perry Nuclear Power Plant, which is either owned or leased by OE, CEI, TE and Penn. Although the NRC noted that the plant continues to operate safely, the agency has indicated that its increased over-sight will include an extensive NRC team inspection to assess the equipment problems and the sufficiency of FENOC's correc-tive actions. The outcome of these matters could include NRC enforcement action or other impacts on operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition.

Other Legal Matters There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The most significant not otherwise discussed above are described below.

Various legal proceedings alleging violations of federal secu-rities laws and related state laws were filed against FirstEnergy in connection with, among other things, the restatements in August 2003 by FirstEnergy and the Ohio Companies of previ-ously reported results, the August 14, 2003 power outages described above, and the extended outage at the Davis-Besse Nuclear Power Station. The lawsuits were filed against FirstEnergy and certain of its officers and directors. On July 27, 2004, FirstEnergy announced that it had reached an agreement to resolve these pending lawsuits. The settlement agreement, which does not constitute any admission of wrongdoing, pro-vides for a total settlement payment of $89.9 million. Of that amount, FirstEnergy's insurance carriers paid $71.92 million, based on a contractual pre-allocation, and FirstEnergy paid

$17.98 million, which resulted in an after-tax charge against FirstEnergy's second quarter 2004 earnings of $11 million or

$0.03 per share of common stock (basic and diluted). On December 30, 2004, the court approved the settlement.

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 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 of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restate-ments and Davis-Besse issues. On December 30, 2004, FirstEnergy received a second subpoena asking for documents relating to issues raised during the SEC's PUHCA examination.

FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

If it were ultimately determined that FirstEnergy or its sub-sidiaries have legal liability or are otherwise made subject to liability based on the above matter, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial con-dition and results of operations.

14. Segment Information:

FirstEnergy has three reportable segments: regulated services, competitive electric energy services and facilities (HVAC) services. The aggregate 'Other" segments do not individually meet the criteria to be considered a reportable segment. "Other" consists of international businesses that have subsequently been divested, MYR (a construction service company); natural gas operations and telecommunications services. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as 'reportable segments."

FirstEnergy's primary segment is its regulated services seg-ment, whose operations include the regulated sale of electricity and distribution and transmission services by its eight EUOC in Ohio, Pennsylvania and New Jersey. The competitive electric energy services business segment primarily consists of the subsidiaries (FES, FGCO and FENOC) that sell electricity in deregulated markets and operate the generation facilities of OE, CEI, TE and Penn resulting from the deregulation of the Companies' electric generation business (see Note 2(A) -

Accounting for the Effects of Regulation).

The regulated services segment designs, constructs, oper-ates and maintains FirstEnergy's regulated transmission and distribution systems. Its revenues are primarily derived from elec-tricity delivery and transition costs recovery. The regulated services segment assets include generating units that are leased to the competitive electric energy services. Its internal revenues repre-sent the rental revenues for the generating unit leases.

The competitive electric energy services segment has responsibility for FirstEnergy generation operations as discussed under Note 2(A). Its net income is primarily derived from rev-enues from all electric generation sales revenues consisting of generation services to regulated franchise customers who have not chosen an alternative generation supplier, retail sales in deregulated markets and all domestic unregulated electricity sales in the retail and wholesale markets and the related costs of electricity generation and sourcing of commodity requirements.

Its net income also reflects the expense of the intersegment generating unit leases discussed above and property tax amounts related to those generating units.

Segment reporting for 2003 and 2002 was reclassified to conform with the current year business segment organization and operations emphasizing FirstEnergy's regulated electric busi-nesses and competitive electric energy operations. A previous reportable segment was the more expansive competitive servic-es segment whose aggregate operations consisted of FirstEnergy generation operations, natural gas commodity sales, providing local and long-distance phone service and other com-petitive energy related businesses such as facilities services and construction service (MYR) which was viewed as offering a com-prehensive menu of energy related services. Management's focus is on its core electric business. This has resulted in a change in performance review analysis from an aggregate view of all competitive services operations to a focus on its competi-tive electric energy operations. During FirstEnergy's periodic review of reportable segments under SFAS 131, that change resulted in the revision of reportable segments to the separate reporting of competitive electric energy operations, facilities serv-68 ! --

I.;

ices and including all other competitive services operations in the "Other" segment. Facilities services is being disclosed as a reporting segment due to the subsidiaries qualifying as held for sale (see Note 2 (H)). In addition, certain amounts (including transmission and congestion charges) were reclassified among purchased power, other operating costs and depreciation and amortization to conform with the current year presentation of generation commodity costs. Interest expense on holding com-pany debt and corporate support services revenues and expenses are now included in "Reconciling Items" and "Other" includes those operating segment results described above.

. Products and Services'

> Year i :- -:

s.20104 2003

, 2002 Energy Related Electricity Sales Sales and Services 3W-1

,In millions) 910.6315 :

9745

-10205 :

766 9.656 904

'See Note 2(J) for discussion of discontinued operations.

Segment Financial Information:

Geographic Information Following the sales of international operations in 2002 through January of 2004, less than one percent of FirstEnergy's revenues and assets were in foreign countries in 2003 and 2004. See Note 8 for a discussion of the divestitures.

I pli91ted serify kwvMic W Mtic Facilities Keosecilig :

Seri ther Ajesuses Camdid a

2004 External revenues Internal revenues Total revenues Depreciation and

• amortization Goodwvill Impairment Net interest charges Income taxes Income before.

discontinued operations Discontinued operations

- 35.395 318 5.713 1,422 363 740

..SE

.E 1.015 Net Income Total assets Total goodwill Property additions

• 1,015 28,341 5.951 572 1

2003 External revenues 35.253 Internal revenues 319

.Total revenues 5,572 Depreciation and amortization 1.423 Goodwill impairment Net interest charges 493 Income taxes 779 Income before discontinued operations and cumulative effect of accounting change

.-1.063 Discontinued operations Cumulative effect of accounting change 101 Netincome 1.164 Total assets 29.789 Total goodwill 5,993 Property additions 434 2002 External revenues 35.298 Internal revenues 318 Total revenues 5.616 Depreciation and amortization 1.413 Net interest charges 588 Income taxes 722 Income before discontinued operations 962 Discontinued operations Net income 962

• Total assets 30.494 Total goodwill 5,993 Property additions 490 tin millionsl

.204 3398 3451 S 5 312.453 (3181

.,204 398 451 (3131 12.453 35 5

3 34 1,499 36 36 37 1

14 252 667 72 1101 '(24)

(107)

.:671 104 (36) 41 1250) 874 4

4 104 (361 '45 (250) 878

.488 135 625 479 31,068 24 75 6.050 246

- 3 4

.21 846 5.487 3327 3564 344.

311.675 1319) 5.487 327 564 12751 11.675 29 2

38 1.492 117 117 44 1

107 164 809.

(222)

(35) -18)

(961 408 (320)

(75)

(64). (1801 -424 (61 (97)

(103) i 1

102 (320)

(811 (160)

(180) 1 423

.423 166 912 620 32,910 24 36 75 6,128.

335 4

9 74 856 35

.1

15. New Accounting Standards and Interpretations SFAS 153, 'Exchanges of Nonmonetary Assets -

an amendment of APB Opinion No. 29" In December 2004, the FASB issued this Statement amending 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 exceptions to that principle. SFAS 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 non-monetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this state-ment are effective for nonmonetary exchanges occurring in fiscal periods beginning after June 15, 2005 and are to be applied prospectively. FirstEnergy is currently evaluating this standard but does not expect it to have a material impact on the financial statements.

SFAS 123 (revised 2004) "Share-Based Payment" In December 2004, the FASB issued this revision to SFAS 123, which requires expensing stock options in the financial statements. Important to applying the new stan-dard is understanding how to (1) measure the fair value of stock-based compensation awards and (2) recognize the related compensation cost for those awards. For an award to qualify for equity classification, it must meet certain crite-ria in SFAS 123(R). An award that does not meet those criteria will be classified as a liability and remeasured each period. SFAS 123(R) retains SFAS 123's requirements on accounting for income tax effects of stock-based compensa-tion. The effective date for FirstEnergy is July 1, 2005 and the Company will be applying modified prospective applica-tion, without restatement of prior interim periods. Any potential cumulative adjustments have not been deter-mined. FirstEnergy uses the Black-Scholes option-pricing model to value options and will continue to do so upon adoption of SFAS 123(R). The impacts of the fair value recognition provisions of SFAS 123 on FirstEnergy's net

$4.825 3383 3907 340 114A53 13181 -

4.825 383 907 (2781 A.453 24 6

2 34 1,479:

43 2

134 189

.956 (88) 2 114) (108)

-514' (170).

21 j1951, 618 3

1681 -

-(65)

(1701 3 (471 (195) 553 1.340 402 1,606 544

. 34.386 24 196 65 6.278 391 6

9 102 998 Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consists of interest expense related to holding company debt corporate support services revenues' andexpenses, fuel marketing revenues, which are reflected as reductions to-:

expenses for internal management reporting purposes and elimination of intersegment transactions.

• c,-;,;;

69

income and earnings per share for 2002 through 2004 are disclosed in Note 4. FirstEnergy is considering alternative compensation strategies in conjunction with the adoption of SFAS 123(R).

SFAS 151, "Inventory Costs - an amendment of ARB No. 43, Chapter 4" In November 2004, the FASB issued this statement to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circum-stances these costs may be "so abnormal" that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of con-version be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by FirstEnergy after June 30, 2005.

FirstEnergy is currently evaluating this standard but does not expect it to have a material impact on the financial statements.

EITF Issue No. 03-1, 'The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments' In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired.

When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will continue to evaluate its investments as required by existing authoritative guidance.

EITF Issue No. 03-16, "Accounting for Investments In Limited Liability Companies' In March 2004, the FASB ratified the final consensus on Issue 03-16. EITF 03-16 requires that an investment in a lim-ited liability company that maintains a "specific ownership account" for each investor should be viewed as similar to an investment in a limited partnership for determining whether the cost or equity method of accounting should be used. The equity method of accounting is generally required for investments that represent more than a three to five percent interest in a limited partnership. EITF 03-16 was adopted by FirstEnergy in the third quarter of 2004 and did not affect the Companies' financial statements.

FSP 109-1, "Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction and Qualified Production Activities Provided by the American Jobs Creation Act of 2004-Issued in December 2004, FSP 109-1 provides guidance related to the provision within the American Jobs Creation At of 2004 (Act) that provides a tax deduction on qualified pro-duction activities. The Act includes a tax deduction of up to 9 percent (when fully phased-in) of the lesser of (a) "qualified production activities income," as defined in the Act, or (b) taxable income (after the deduction for the utilization of any net operating loss carryforwards). This tax deduction is limit-ed to 50 percent of W-2 wages paid by the taxpayer. The FASB believes that the deduction should be accounted for as a special deduction in accordance with SFAS No. 109, "Accounting for Income Taxes." FirstEnergy is currently eval-uating this FSP but does not expect it to have a material impact on the Company's financial statements.

FSP 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued in May 2004, FSP 106-2 provides guidance on accounting for the effects of the Medicare Act for employ-ers that sponsor postretirement health care plans that provide prescription drug benefits. FSP 106-2 also requires certain disclosures regarding the effect of the federal sub-sidy provided by the Medicare Act. The effect of the federal subsidy provided under the Medicare Act on FirstEnergy's consolidated financial statements is described in Note 3.

16. Summary of Quarterly Financial Data (Unaudited):

The following summarizes certain consolidated operating results by quarter for 2004 and 2003. Certain financial results have been reclassified from amounts previously reported due to FES' natural gas business qualifying as held for sale in accordance with SFAS 144 as discussed in Note 2(J).

-Three Months Ended

March31, June 30, Sept 30, Dec. 31, 2004 2004 2014 2004

-(In millions, except per share amounts)

Revenues

$3.027 S3.041

.3.435

$2.950

'Expenses 2,568 2,481

.2.771 2.421 Income Before Interest

, and Income Taxes 459 560 664 529 Net Interest Charges 171 180 151 165 Income Taxes 115 177 215 163 Income Before Discontinued Operations 173 203 298 201

-Discontinued Operations (Net of Income Taxes)

. 1

-1 1

1 Net Income

$174 7204

$299 7202 Basic Earnings Per Share of Common Stock:

. Before Discontinued Operations $0.53

$0.62

$0.91

$0.61 Discontinued Operations i Basic Earnings Per Share

of Common Stock

$0.53

$0.62

$0.91

$0.61 Diluted Earnings Per Share of Common Stock:

Before Discontinued Operations $0.53

$0.62

$0.91

$0.61 Discontinued Operations Diluted Earnings PerShareofCommonStock

$0.53

$0.62 S 0.91

$0.61 70 i {fS '+

`_

`4,t(,

r;.,.04,

March31, June30.

Sept 30.

Dec. 31, Three Months Ended 2003 2003 2003 2003 (in millions, except pershare amounts/

Revenues 2.981

$27728

$3,317

.2,649 Expenses 2.571 2.488

.2,833 2.310 Claim Settlement(Note 8) 168 Income Before Interest and Income Taxes 410 240 484 507 Net Interest Charges 205 205 200 199 Income Taxes

-93 21 134 160 Income Before Discontinued Operations and Cumulative Effect of Accounting Change 112 14 150 148 Discontinued Operations lNet of Income Taxes) 5 (721 2

138)

Cumulative Effect of Accounting Change (Net of Income Taxes) 102 Netincome(Loss) 5 219 S (581 S 152 S 110 Basic Eamings (Loss) Per Share of Common Stock:

Before Discontinued Operations and Cumulative Effect of Accounting Change S 0.38 S 0.05

$ 0.51

$ 0.45 Discontinued Operations 0.01 (0.25)

(0.12)

Cumulative Effect of Accounting Change 0.35 Basic Earnings (Loss)

Per Share of Common Stock S 0.74 S 10.20)

S 0.51 S 0.33 Diluted Earnings (Loss)

Per Share of Common Stock:

Before Discontinued Operations and Cumulative Effect of Accounting Change

$ 0.38 S 0.05 S 0.50 S 0.45

- Discontinued Operations 0.01 (0.25)

(0.12)

Cumulative Effect of Accounting Change 0.35 Diluted Earnings (Loss)

Per Share of Common Stock

$ 0.74 S (0.20)

$ 0.50 S 0.33 Results in the second quarter of 2004 included FirstEnergy's sale of its 50 percent interest in GLEP, which produced an after-tax loss of $7 million, or $0.02 per share (see Note 8). Third quarter 2004 results were impacted by a

$17 million net-of-tax, or $0.05 per share charge for losses and impairments relating to the divestiture of certain non-core, technology-related investments. Fourth quarter 2004 results 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)).

The net loss for the second quarter of 2003 included a charge resulting from the NJBPU's decision to disallow recovery by JCP&L of $153 million in deferred energy costs and a $67 million non-cash charge (no tax benefit recog-nized) from the abandonment of operations in Argentina.

Results for the fourth quarter of 2003 included a $33 million after-tax loss from the divestiture of assets in Bolivia reported as discontinued operations and a $26 million impairment of the equity TEBSA investment in Columbia included in continuing operations. The fourth quarter 2003 results also include a $170 million gain ($168 million net of expenses) from the NRG Energy Inc. settlement claim.

i -

l: e Z

' 71

CONSOLIDATED FINANCIAL AND PRO FORMA COMBINED OPERATING STATISTICS ('auttedf{see NAote ?,JWY (Dollars in thousands) 2004 2003 2002 2001 2000 1999 1994 General Financial Information Revenues

$12,453,046

$11,674,888

$11,453,354

$ 7,237.011

$ 6,470,488 $ 6,130,004

$2,390,957 Net Income

$ 878,175

$ 422,764

$ 552,804

$ 646,447

$ 598,970 $ 568,299

$ 281,852 SEC Ratio of Earnings to Fixed Charges 2.60 1.73 1.88 2.22 2.10 2.01 2.24 Capital Expenditures

$ 731,342

$ 791,834

$ 903.606

$ 887,929 568,711

$ 474,118

$ 258,642 Total Capitalization (a)

$18,937,766

$18,413,530

$18,686,388

$21,339,001

$11,204,674

$11,469,795

$5,852,030 Capitalization Ratios a):

Common Stockholders' Equity 45.3%

45.0%

37.7%

34.7%

41.5%

39.8%

39.6%

Preferred and Preference Stock:

Not Subject to Mandatory Redemption 1.8 1.8 1.8 2.2 5.8 5.7 5.6 Subject to Mandatory Redemption 2.3 2.8 1.4 2.2 0.7 Long-Term Debt 52.9 53.2 58.2 60.3 51.3 52.3 54.1 Total Capitalization 100.0%

100.0%

100.0%

100.0%

100.0%

100.0%

100.0%

Average Capital Costs:

Preferred and Preference Stock 6.51%

6.47%

7.50%

7.90%

7.92%

7.99%

7.15%

Long-Term Debt 5.93%

6.08%

6.56%

6.98%

7.84%

7.65%

8.17%

Common Stock Data Earnings per Share(b):

Basic

$2.67

$1.40

$2.11

$2.85

$2.69

$2.50

$1.97 Diluted

$2.66*

$1.40

$2.10

$2.84

$2.69

$2.50

$1.97 Return on Average Common Equitylb) 10.4%

5.7%

8.2%

12.9%

13.0%

12.7%

12.4%

Dividends Paid per Share

$1.50

$1.50

$1.50

$1.50

$1.50

$1.50

$1.50 Dividend Payout Ratio C 56%

107%

71%

53%

56%

60%

76%

Dividend Yield 3.8%

4.3%

4.5%

4.3%

4.8%

6.6%

8.1%

Price/Eamings Ratio (b) 14.8 25.1 15.6 12.3 11.7 9.1 9.4 Book Value per Share

$26.20

$25.35

$24.01

$25.29

$21.29

$20.22

$16.15 Market Price per Share

$39.51

$35.20

$32.97

$34.98

$31.56

$22.69

$18.50 Ratio of Market Price to Book Value 151%

139%

137%

138%

148%

112%

115%

Operating Statistics (c)

Generation Kiowatt-Hou Sales (Millions):

Residential 31,781 31,322 31,937 32,708 32,519 32,616 29.969 Commercial

-32,114 32,311 32,892 32,170 33,139 30,311 27,667 Industrial 31,675 32,451 32,726 33,024 31,140 30,422 33,893 Other

- 504 554 531 536 522 566 1,454 Total Retail 96,074 96,638 98,086 98,438 97,320 93,915 92,983 Total Wholesale 53,268 42,059 30,007 20,240 13,761 14,631 9,389 Total Sales 149,342 138,697 128,093 118,678 111,081 108,546 102.372 Customers Served:

Residential 3,916,855 3,874,052 3,868,499 3,833,013 3,798,716 3,767,534 3,615,157 Commercial 500,695 496,253 471,440 464,053 472,410 455,919 422,468 Industrial 10,597 10,871 18,416 18,652 18,996 19,549 21,087 Other 5,654 5,635 5,716 5,762 6,001 5,992 7,468 Total 4,433,801 4,386,811 4,364,071 4,321,480 4,296,123 4,248,994 4,066,180 Number of Employees 15,245 15,905 17,560 18,700 18,912 19,470 22.488 la' 2001 capitalization includes approximately $1.4 billion of long-term debt (excluding long-term debt due to be repaid within one year) included in Liabilities Related to Assets Pending Saleorn the Consolidated Balance Sheet as of December31, 2001.

lb Before discontinued operations in 2004. 2003 and 2002 and accounting changes in 2003 and 2001.

ki Reflects pro forma combined FirstrEnergy and GPU statistics in the years 1999 to 2001 and pro forma combined Ohio Edison, Centerior and GPU statistics in years prior to 1999.

72 ':e r-s.4 !":rs "LXI;

Shareholder Information Shareholder Services, Transfer Agent and Registrar FirstEnergy Securities Transfer Company, a subsidiary of FirstEnergy, acts as our own transfer agent and registrar for all stock issues of FirstEnergy and its subsidiaries. Shareholders wanting to transfer stock, or who need assistance or information, can send their stock or write to Shareholder Services, FirstEnergy Corp., 76 South Main Street, Akron, Ohio 44308-1890. Shareholders also can call the following tollfree telephone number, which is valid in the United States, Canada, Puerto Rico and the Virgin Islands, weekdays between 8 a.m. and 4:30 p.m., Eastern Time: 1-800-736-3402.

For Internet access to general shareholder information and useful forms, visit our Web site at www.firstenergycorp.comlir.

Stock Listings and Trading Newspapers generally report FirstEnergy common stock under the abbreviation FSTENGY, but this can vary depending upon the news-paper. The common stock of FirstEnergy and preferred stock of its electric utility subsidiaries are listed on the following stock exchanges:

Company Stock Exchange Symbol

'FirstEnergy New York

-,FE, Jersey Central New York JYP Ohio Edison New York OEC '

K'Pennsylvania Power Philadelphia PPC Toledo Edison New York, OTC TED,.

American.

Dividends Proposed dates for the payment of FirstEnergy common stock dividends in 2005 are:

'Ex-Dividend Date" Record Date Payment Date February3-3 February 7 March'1 May4 -

May6 June 1 August 3 August 5 September 1:

November 3 November 7 December 1.'

All dividends are subject to declaration by the Board of Directors at its discretion.

Direct Dividend Deposit Shareholders can have their dividend payments automatically deposited to checking and savings accounts at any financial institu-bon that accepts electronic direct deposits. Use of this free service ensures that payments will be available to you on the payment date, eliminating the possibility of mail delay or lost checks. Contact Shareholder Services to receive an authorization form.

Combining Stock Accounts If you have more than one stock account and want to combine them, please write or call Shareholder Services and specify the account that you want to retain as well as the registration of each of your accounts.

Stock Investment Plan Shareholders and others can purchase or sell shares of FirstEnergy common stock through the Company's Stock Investment Plan.

Investors who are not registered shareholders can enroll with an initial $250 cash investment. Participants may invest all or some of their dividends or make optional cash payments at any time of at least $25 per payment up to $100,000 annually. Contact Shareholder Services to receive an enrollment form.

Safekeeping of Shares Shareholders can request that the Company hold their shares of FirstEnergy common stock in safekeeping. To take advantage of this service, shareholders should forward their common stock certfi-cate(s) to the Company along with a signed letter requesting that the Company hold the shares. Shareholders also should state whether future dividends for the held shares are to be reinvested or paid in cash. The certificate(s) should not be endorsed, and registered mail is suggested. The shares will be held in uncertificated form, and we will make certificate(s) available to shareholders upon request at no cost. Shares held in safekeeping will be reported on dividend checks or Stock Investment Plan statements.

Form 10-K Annual Report Form 10-K, the Annual Report to the Securities and Exchange Commission, will be sent without charge by writing to David W.

Whitehead, Corporate Secretary, FirstEnergy Corp., 76 South Main Street, Akron, Ohio 44308-1890.

Institutional Investor and Security Analyst Inquiries Institutional investors and security analysts should direct inquiries to:

Kurt E. Turosky, Director, Investor Relations, 330384-5500.

Annual Meeting of Shareholders Shareholders are invited to attend the 2005 Annual Meeting of Shareholders on Tuesday, May 17, at 10:30 a.m. Eastern Time, at the John S. Knight Center, 77 East Mill Street, in Akron, Ohio.

Registered shareholders not attending the meeting can appoint a proxy and vote on the items of business by telephone, Internet or by completing and returning the proxy card that is sent to them.

Shareholders whose shares are held in the name of a broker can attend the meeting if they present a letter from their broker indicating ownership of FirstEnergy common stock on the record date of March 22, 2005.

FirstEnergy has included as Exhibit 31 to its Annual Report on Form I 0-K for fiscal year 2004 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 Execufive Officer has also submitted to the New York Stock Exchange (NYSE) a certificate certifing that he was not aware of any violation by FirstEnergy of the NYSE corporate governance listing standards as of the date of the certification.

@ Printed on recycled paper

,.; :1r;A;>:

73

EirstEnerg 76 South Main Street, Akron, OH 44308-1890 www.firstenergycorp.com PRESORTED STD.

U.S. POSTAGE PAID AKRON, OHO PERMIT NO. 561 2004 Annual Report

Enclosure I Exhibit G L-05-080 PY-CEI/NRR-2880L EXHIBIT G FORM OF SUPPORT AGREEMENT BETWEEN FIRSTENERGY CORP. AND FIRSTENERGY NUCLEAR GENERATION CORP.

THIS SUPPORT AGREEMENT, dated as of_

, 20_ between FirstEnergy Corp., an Ohio corporation ("Parent"), and FirstEnergy Nuclear Generation Corp.

("FENGenCo") an Ohio corporation ("Subsidiary"),

WITNESSETH:

WHEREAS, Parent is the indirect owner of 100% of the outstanding shares of the Subsidiary; WHEREAS, the Subsidiary intends to acquire certain assets located at the Beaver Valley Power Station, Units Nos. 1 & 2 and Perry Nuclear Power Plant, Unit No. 1

("BVPS and Perry"); and WHEREAS, Parent and the Subsidiary desire to take certain actions to assure the Subsidiary's ability to pay the pro rata expenses of operating BVPS and Perry safely and protecting the public health and safety (the "Operating Expenses") and to meet Nuclear Regulatory Commission ("NRC") requirements during the operating life of the BVPS and Perry Assets (the "NRC Requirements").

Now, THEREFORE, in consideration of the mutual promises herein contained, the parties hereto agree as follows:

1.

Availability of Funding. From time to time, upon request of Subsidiary, Parent shall provide or cause to be provided to Subsidiary such funds as the Subsidiary determines to be necessary to pay Operating Expenses and meet NRC Requirements; provided, however, in any event the aggregate amount which Parent is obligated to provide under this Agreement shall not exceed $80 million.

2.

No Guarantee. This Support Agreement is not, and nothing herein contained, and no action taken pursuant hereto by Parent shall be Exhibit G L-05-080 PY-CEI/NRR-2880L construed as, or deemed to constitute, a direct or indirect guarantee by Parent to any person of the payment of the Operating Expenses or of any liability or obligation of any kind or character whatsoever of the Subsidiary. This Agreement may, however, be relied upon by the NRC in determining the financial qualifications of the Subsidiary to hold the operating license for BVPS and Perry.

3.

Waivers. Parent hereby waives any failure or delay on the part of the Subsidiary in asserting or enforcing any of its rights or in making any claims or demands hereunder.

4.

Amendments and Termination. This Agreement may not be amended or modified at any time without 30 days prior written notice to the NRC. This Agreement shall terminate at such time as Parent is no longer the direct or indirect owner of any of the shares or other ownership interests in Subsidiary. This Agreement shall also terminate with respect to the Operating Expenses and NRC Requirements applicable to BVPS and Perry at such time as BVPS and Perry permanently cease commercial operations.

5.

Successors. This Agreement shall be binding upon the parties hereto and their respective successors and assigns.

6.

Third Parties. Except as expressly provided in Sections 2 and 4 with respect to the NRC, this Agreement is not intended for the benefit of any person other than the parties hereto, and shall not confer or be deemed to confer upon any other such person any benefits, rights, or remedies hereunder.

7.

Governing Law. This Agreement shall be governed by the laws of the State of Ohio.

Exhibit G L-05-080 PY-CEINRR-2880L IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed and delivered by their respective officers thereunto duly authorized as of the day and year first above written.

FirstEnergy Corp.

By:

Name:

Title:

FirstEnergy Nuclear Generation Corp.

By:

Name:_

Title:

^...

Exhibit H L-05-080 PY-CEIINRR-2880L Page 1 EXHIBIT H (Non-Proprietary Version) (1)

FIRSTENERGY NUCLEAR GENERATION CORP.

Pro-Forma Income Statements

($ in thousands, except $/Mwh) 2006 2007 2008 2009 2010 Operating Revenues Operating Expenses:

Fuel Nuclear Operating Costs Property Taxes Depreciation and Amortization Other Operating Costs Total O&M Operating Income Other Income/(Expense):

Interest Expense Capitalized Interest Other, net Total Other Income/(Expense)

Income Before Income Taxes Income Taxes Net Income

[ ]

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II II II I]

Note:

(1) Information contained within the brackets [ ] is considered proprietary.

Exhibit H L-05-080 PY-CEI/NRR-2880L Page 2 FIRSTENERGY SOLUTIONS CORP. (PARTIAL)

Pro Forma Generation Capacity at Penn Power Share (4)

The purpose of this schedule is to quantify the estimated revenues FirstEnergy Solutions could realize at market rates compared to the Power Supply Agreement included in the preceding Pro Forma Income Statements.

• MDC (MW)( )

Generation (Mwh)

Estimated Capacity Factor (Net MDC) (2)

Market Rate (PJM) (3)

Estimated Revenue

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Market Rate (PJM) (3)

Estimated Revenue

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Market Rate (MISO) (3)

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• MDC = Maximum Dependable Capacity Exhibit H L-05-080 PY-CEI/NRR-2880L Page 3 Notes:

(1) Power uprates for Beaver Valley 1 and Beaver Valley 2 have been requested from the NRC, but are not included in developing the estimated revenues noted above.

(2) The Capacity Factors shown above reflect a conservative view of generation (i.e., not greater than

[ ] %) when developing estimated revenue at market rates.

(3) Market Rates are based on an average of 8760 hourly prices (i.e., round the clock) for MISO and PJM markets, respectively.

(4) Information contained within the brackets [ ] is considered proprietary.

Enclosure I Exhibit I L-05-080 PY-CEI/NRR-2880L Page 1 EXHIBIT I (Non-Proprietary Version) (

FIRSTENERGY NUCLEAR GENERATION CORP.

Pro Forma Opening Balance Sheet As of December 31, 2005 (S In thousands)

ASSETS UTILITY PLANT:

In service Less-Accumulated provision for depreciation Construction work In progress-Electric Plant Nuclear Fuel I I I1 l I II II 11 1I I1 I I I l I I OTHER PROPERTY AND INVESTMENTS:

Nuclear plant decommissioning trusts Long-term notes receivable from associated companies CURRENT ASSETS:

Cash and cash equivalents Receivables-Associated companies Notes receivable from associated companies Materials and supplies, at average cost Prepayments and other II 11 II I]

II DEFERRED CHARGES:

Other I I Exhibit I L-05-080 PY-CEI/NRR-2880L Page 2 CAPITAUZATION AND UABILTIES CAPITALIZATIO N:

Common stockholders equity-Common stock, no par value, 100 shares authorized and outstanding Retained earnings Total common stockholders equity Long-term notes payable to associated companies Long-term debt and other long-term obligations CURRENT LIABILmES:

Currently payable long-term debt Accounts payable-Associated companies Other Notes payable to associated companies Accrued taxes Accrued Interest Other II II II lI I1 II II 1I I1 I1 II II II II II NONCURRENT UABILITIES:

Accumulated deterred Income taxes Asset retirement obligation Other II 1I I I I

I 1I COMMITMENTS AND CONTINGENCIES Note:

(1) Information contained within the brackets [ ] is considered proprietary.

Exhibit J L-05-080 PY-CEIINRR-2880L EXHIBIT J Form of Nuclear Decommissioning Trust Agreement Exhibit J L-05-080 PY-CEI/NRR-2880L FIRSTENERGY NUCLEAR GENERATION CORP.

MASTER DECOMMISSIONING TRUST AGREEMENT FOR BEAVER VALLEY POWER STATION, UNIT NOS. 1 AND 2, AND PERRY NUCLEAR POWER PLANT, UNIT NO. 1 Dated:

2005 Exhibit J L-05-080 PY-CEI/NRR-2880L TABLE OF CONTENTS PAGE I. Definitions 2

Section 1.01. Definitions............................................

2 II. Purposes of the Funds; Contributions 6

Section 2.01. Establishment of the Funds............................................

6 Section 2.02. Purposes of the Funds............................................

6 Section 2.03. Contributions to the Funds.............................................

7 III. Payments by the Trustee 7

Section 3.01. Use of Assets............................................

7 Section 3.02. Certification for Decommissioning Costs........................................ 7 Section 3.03. Administrative Costs............................................

8 Section 3.04. Notice Regarding Disbursements or Payments...............................9 Section 3.05. Payments between the Funds.............................................

9 IV. Concerning the Trustee 9

Section 4.01. Authority of Trustee............................................

9 Section 4.02. Investment of Funds............................................

10 Section 4.03. Prohibition Against Self Dealing...........................................

11 Section 4.04. Compensation...........................................

11 Section 4.05. Books of Account...........................................

12 Section 4.06. Reliance on Documents...........................................

12 Section 4.07. Liability and Indemnification............................................

13 Section 4.08. Resignation, Removal and Successor Trustees.............................. 14 Section 4.09. Merger of Trustee............................................

14 V. Amendments 14 VI. Powers of the Trustee and Investment Manager 15 Section 6.01. General Powers...........................................

15 Section 6.02. Specific Powers of the Trustee...........................................

17 Section 6.03. Authorized Party............................................

19 Section 6.04. Prohibition Against Nuclear Sector Investments.......................... 19 VII. Termination 20 i

Exhibit J L-05-080 PY-CEIINRR-2880L TABLE OF CONTENTS (continued)

PAGE VIII. Miscellaneous 20 Section 8.01. Binding Agreement...............................

20 Section 8.02. Notices..............................

20 Section 8.03. Governing Law..............................

20 Section 8.04. Counterparts...............................

20 Section 8.05. Contractual Income...............................

20 Section 8.06. Contractual Settlement...............................

22 Section 8.07. Representations & Warranties..............................

22 EXHIBIT A EXHIBIT B EXHIBIT C EXHIBIT D EXHIBIT E SPECIAL TERMS OF THE QUALIFIED NUCLEAR DECOMMISSIONING RESERVE FUNDS CERTIFICATE FOR PAYMENT OF DECOMMISSIONING COSTS CERTIFICATE FOR TRANSFER BETWEEN THE QUALIFIED FUND AND THE NONQUALIFIED FUND CERTIFICATE FOR WITHDRAWAL OF EXCESS CONTRIBUTIONS FROM QUALIFIED FUND CROSS-TRADING INFORMATION SCHEDULE A SCHEDULE B

Enclosure I Exhibit J L-05-080 PY-CEVNRR-2880L Page 1 NUCLEAR DECOMMISSIONING MASTER TRUST AGREEMENT THIS NUCLEAR DECOMMISSIONING MASTER TRUST AGREEMENT (the "Agreement"), effective upon approval by the Nuclear Regulatory Commission, between FirstEnergy Nuclear Generation Corp., a corporation duly organized and existing under the laws of the State of Ohio, having its principal office at 76 South Main Street, Akron, Ohio 49308 (the "Company"), and MELLON BANK, N.A., as Trustee, having its principal office at One Mellon Bank Center, Pittsburgh, Pennsylvania 15258 (the "Trustee");

WITNESSETH:

WHEREAS, the Company is the owner in whole of each of the Units ("Unit" shall mean each, and "Units" shall mean all, of the nuclear power plants listed on the Schedule A attached to this Agreement as that Schedule may be supplemented from time to time by the Company by written notice to the Trustee). Each Unit of a multi-unit nuclear power plant site shall be considered as a separate Unit for the purposes of this Agreement; and WHEREAS, the assets of the funds governed by the Master Decommissioning Trust Agreement between Pennsylvania Power Company ("Penn Power") and Mellon Bank, N.A., described in Schedule B ("Prior Agreement"), and established for the purpose of holding the decommissioning funds established by Penn Power for each Unit in which Penn Power owned an interest in whole or in part, has been transferred to the Company; and WHEREAS, the Company desires to appoint Mellon Bank, N.A. as Trustee to maintain pursuant to this Agreement its funds which qualify as a Nuclear Decommissioning Reserve Fund under Section 468A of the Internal Revenue Code of 1986, as amended, or any corresponding section or sections of any future United States internal revenue statute (the "Code"), and the regulations thereunder (the "Qualified Funds"), and its funds which do not so qualify (the "Nonqualified Funds"; collectively, the "Funds"), under the laws of the Commonwealth of Pennsylvania; and WHEREAS, the execution and delivery of this Agreement have been duly authorized by the Company and the Trustee and all things necessary to make this Agreement a valid and binding agreement by the Company and the Trustee have been done.

1 Exhibit J L-05-080 PY-CEI/NRR-2880L Page 2 NOW, THEREFORE, THIS AGREEMENT WITNESSETH, that to provide for the maintenance of the Funds and making of payments therefrom and the performance of the covenants of the Company and the Trustee set forth herein, the Company does hereby sell, assign, transfer, set over and pledge unto the Trustee, and to its successors in the trust and its assigns, all of the Company's right, title and interest in and to any and all cash and property herewith and hereafter contributed to the Funds, subject to the provisions of Article VI hereof and Section 4 of the Special Terms of the Qualified Nuclear Decommissioning Reserve Fund, attached hereto as Exhibit A ("the Special Terms").

TO HAVE AND TO HOLD THE SAME IN TRUST for the exclusive purpose of providing funds for the decommissioning of the Units in order to satisfy the liability in connection therewith, to pay the administrative costs and other incidental expenses of the Funds, and to make certain investments, all as hereinafter provided.

I.

Definitions Section 1.01. Definitions As used in this Agreement, the following terms shall have the following meanings:

(1)

"Agreement" shall mean this Master Decommissioning Trust Agreement as the same may be amended, modified, or supplemented from time to time.

(2)

"Applicable Law" shall mean all applicable laws, statutes, treaties, rules, codes, ordinances, regulations, certificates, orders, interpretations, licenses and permits of any Governmental Authority and judgments, decrees, injunctions, writs, orders or like action of any court, arbitrator or other judicial or quasi judicial tribunal of competent jurisdiction (including those pertaining to health, safety, the environment or otherwise).

(3)

"Applicable Tax Law" shall mean Section 468A of the Code (or comparable subsequent provision of the Code) and the regulations thereunder, and any other provision of the Code relating to the Federal taxation of the Funds or credits or deductions based on Contributions.

2 Exhibit J L-05-080 PY-CEI/NRR-2880L Page 3 (4)

"Authorized Party" shall mean the persons designated as such pursuant to Section 6.03 hereof.

(5)

"BVPS 1" shall mean the nuclear generating unit located at the Beaver Valley Power Station and known as Unit No.

1, together with its associated facilities and equipment.

(6)

"BVPS 2" shall mean the nuclear generating unit located at the Beaver Valley Power Station and known as Unit No.

2, together with its associated facilities and equipment.

(7)

"Beaver Valley Power Station" or "BVPS" shall mean the electric generating station located on the south bank of the Ohio River in Beaver County, Pennsylvania, approximately 25 miles northwest of Pittsburgh.

(8)

"Business Day" shall mean a day that is not a Saturday or Sunday or a legal holiday in the State of Ohio.

(9)

"Code" shall mean the Internal Revenue Code of 1986, as the same may be amended from time to time.

(10)

"Company" shall have the meaning set forth in the opening paragraph of this Agreement.

(11)

"Contribution" shall mean any contribution, cash or otherwise, made to the Trustee for deposit in one or more of the Funds and in such subaccount thereunder as provided in this Agreement. No contribution which consists of real property shall be permitted.

(12)

"Decommissioning" shall mean the decommissioning and retiring of a nuclear generating unit from commercial service under Applicable Law and, to the extent a method of decommissioning is not prescribed by Applicable Law, by the method of decommissioning determined as provided in the operating agreement relating to such unit, and may include the removal (as a facility) of such unit safely from service, the dismantling, shipping, long-term storage and disposal of all radioactive parts and components of such unit and the reduction of 3

Exhibit J L-05-080 PY-CEI/NRR-2880L Page 4 residual radioactivity at the site of such unit, including reduction of residual radioactivity to a level that permits, and the removal of non-contaminated structures and components and such restoration as shall be necessary or desirable to permit, the release of the property for unrestricted use and termination of the NRC license relating to the unit. This process may include, but is not limited to (a) the removal of both radioactively contaminated and radioactively uncontaminated portions of the unit, and shipping, long-term storage and disposal of the same, in each case, in accordance with Applicable Law at the end of the useful life of such unit or if there shall be no Applicable Law at that time, in accordance with the operating agreement with respect to such unit (b) work done to the site of the unit and its associated equipment and facilities and to adjacent areas, whether or not such areas are contiguous to such site, in order to decontaminate such site and such areas and (c) work done by or on behalf of the Company (or for which the Company is charged) to the site where any portion of the unit and its associated equipment and facilities are to be stored or disposed of in order to prepare and maintain such site as a storage or disposal site.

(13)

"Decommissioning Costs" shall mean all costs and expenses relating or allocable to, or incurred in connection with Decommissioning, including but not limited to the removal of the equipment, structures and portions of a nuclear generating unit and its site containing radioactive contaminants or the decontamination of the same, plus, in the case of decontamination, the cost of removal, shipping and long-term storage or disposal of such equipment structures and portions; provided, however, that if Applicable Law prohibits the foregoing or imposes requirements that are more costly to implement than the removal, shipping, storage, disposal or decontamination referred to above in this definition, the term "Decommissioning Costs" shall mean all costs and expenses relating or allocable to, or incurred in connection with, the most costly requirements imposed by Applicable Law with respect to radioactive contaminants after a nuclear generating unit ceases operation.

(14)

"Funds" shall mean the Qualified Funds and the Nonqualified Funds, collectively.

4 Exhibit J L-05-080 PY-CE1/NRR-2880L Page 5 (15)

"Investment Manager(s)" shall mean the person(s) appointed by the Company pursuant to Section 4.02 hereof.

(16)

"Nonqualified Funds" shall mean, collectively, the Funds not constituting Qualified Funds established under, and in accordance with, Section 2.01 and Section 2.02 of the Agreement with respect to any of the Units. Each Nonqualified Fund shall have such subaccounts as are provided for herein or as the Company may otherwise specify.

(17)

"NRC" shall mean Nuclear Regulatory Commission.

(18)

"Order" shall mean any order relating to Decommissioning issued by a Governmental Authority and applicable to one or more of the Units.

(19)

"Perry" shall mean the nuclear generating unit located at the Perry Nuclear Power Plant and known as Unit No. 1, together with its associated facilities and equipment.

(20)

"Perry Nuclear Power Plant" shall mean the electric generating station located on the shore of Lake Erie in Lake County, Ohio, approximately 35 miles northeast of Cleveland.

(21)

"Qualified Funds" shall mean, collectively, the accounts established under, and in accordance with, Section 2.01 and Section 2.02 of the Agreement for purposes of Section 468A of the Code which are designated as such in the records of the Trustee. Each Qualified Fund shall have such subaccounts as are specified herein or as the Company may otherwise specify.

Contributions, if any, made with respect to each such Fund in any year shall not exceed the amount permitted to be made to such Fund with respect to the year in question in order for the Company to be allowed to take the deduction afforded by Section 468A of the Code. It shall be the Company's responsibility and not that of the Trustee to monitor the amount of such contributions.

(22)

"Service" shall mean the Internal Revenue Service.

5 Exhibit J L-05-080 PY-CEI/NRR-2880L Page 6 (23)

"Trustee" shall have the meaning ascribed thereto in the opening paragraph of this Agreement or any successor appointed pursuant to Section 4.08 hereof.

(24)

"Units" shall mean BVPS 1, BVPS 2, and Perry, collectively.

II.

Purposes of the Funds: Contributions Section 2.01. Establishment of the Funds The Trustee shall hold a separate Qualified Fund and a separate Nonqualified Fund for each Unit. The Funds shall be as identified in Schedule A.

The Funds shall be maintained separately at all times in the United States as the Nonqualified Funds and the Qualified Funds pursuant to this Agreement and in accordance with the laws of the Commonwealth of Pennsylvania. The Company intends that the Qualified Funds shall qualify as Nuclear Decommissioning Reserve Funds under section 468A of the Code. The assets of the Qualified Funds may be used only in a manner authorized by section 468A of the Code and the Treasury Regulations thereunder and this Agreement cannot be amended to violate section 468A of the Code or the Treasury Regulations thereunder.

The Trustee shall maintain such records as are necessary to reflect each Fund separately on its books from each other Fund and shall create and maintain such subaccounts within each Fund as the Company shall direct. In performing its duties under this Agreement, the Trustee shall exercise the same care and diligence that it would devote to its own property in like circumstances.

Section 2.02. Purposes of the Funds The Funds are established for the exclusive purpose of providing funds for the decommissioning of the Units. The Nonqualified Fund for a Unit shall accumulate all contributions (whether from the Company or others) which do not satisfy the requirements for contributions to the Qualified Fund for that Unit, pursuant to Section 2 of the Special Terms. The Qualified Funds shall accumulate all contributions (whether from the Company or others) which satisfy the requirements of Section 2 of the Special Terms. The Qualified Funds shall also be governed by the provisions of the Special Terms, which provisions shall take precedence over any provisions of this Agreement construed to be in conflict therewith. The assets in the Qualified Funds shall be used as authorized by section 468A of the Code and the Treasury Regulations thereunder.

None of the assets of the Funds shall be subject to attachment, garnishment, execution or levy in any manner for the benefit of creditors of the Company or any other party.

6 Exhibit J L-05-080 PY-CEI/NRR-2880L Page 7 Section 2.03. Contributions to the Funds The assets of the Funds shall be transferred or contributed by the Company (or by others approved in writing by the Company) from time to time. Cash contributions for each Unit shall be allocated to its Qualified Fund unless the Company designates in writing at the time of payment to which of the Unit's two Funds the payment is allocated. The Company shall have sole discretion as to whether cash payments are allocated to a Qualified Fund or a Nonqualified Fund.

Contributions of property other than cash shall be allocated to the Nonqualified Fund.

III.

Payments by the Trustee Section 3.01. Use of Assets The assets of each Fund shall be used exclusively (a) to satisfy, in whole or in part, any expenses or liabilities incurred with respect to the Decommissioning Costs of that Fund's Unit, including expenses incurred in connection with the preparation for decommissioning of that Unit, (b) to pay the administrative costs and other incidental expenses of each Fund, and (c) to invest in publicly-traded securities and investments (including common trust funds) as directed by the investment manager(s) pursuant to Section 4.02(a) or the Trustee pursuant to Section 4.02(b), except that all assets of the Qualified Funds must be invested in Permissible Assets as defined in the Special Terms. Except for investments tied to market indexes or other non-nuclear sector collective, commingled or mutual funds, the assets of the Funds shall not be invested in:

(1) the securities or other obligations of FirstEnergy Corp. or FirstEnergy Nuclear Generation Corp., or affiliates thereof, or their successors or assigns; and (2) the securities or other obligations of any entity owning or operating one or more nuclear power plants. A non-nuclear sector collective, commingled or mutual fund is one in which less than 50 percent of the fund is invested in the securities of entities that own or operate a nuclear power plant or that are parent companies of subsidiaries that own or operate a nuclear power plant. Use of the assets of the Qualified Funds shall be further limited by the provisions of the Special Terms. The assets of the Funds shall be used, in the first instance, to pay the expenses related to the decommissioning of that Fund's Unit, as defined by the NRC in its regulations and issuances, and as provided in the NRC issued license to operate each Unit and any amendments thereto.

Section 3.02. Certification for Decommissioning Costs (a)

If assets of a Fund are required to satisfy Decommissioning Costs of that Fund's Unit, the Company shall present a certificate substantially in the form attached hereto as Exhibit B to the Trustee signed by its Chairman of the Board, its President or one of its Vice Presidents and another officer of the Company, requesting payment from 7

Exhibit J L-05-080 PY-CEI/NRR-2880L Page 8 its Fund. Any certificate requesting payment by the Trustee to a third party or to the Company from a Fund for Decommissioning Costs shall include the following:

(1) a statement of the amount of the payment to be made from the Fund and whether the payment is to be made from the Nonqualified Fund, the Qualified Fund or in part from both Funds; (2) a statement that the payment is requested to pay Decommissioning Costs which have been incurred, and if payment is to be made from the Qualified Fund, a statement that the Decommissioning Costs to be paid constitute Qualified Decommissioning Costs, as defined in the Special Terms; (3) the nature of the Decommissioning Costs to be paid; (4) the payee, which may be the Company in the case of reimbursement for payments previously made or expenses previously incurred by the Company for Decommissioning Costs; (5) a statement that the Decommissioning Costs for which payment is requested have not theretofore been paid out of the Funds; and (6) a statement that any necessary authorizations of the NRC and/or any other governmental agencies having jurisdiction with respect to the decommissioning have been obtained.

(b)

The Trustee shall retain at least one copy of such certificates (including attachments) and related documents received by it pursuant to this Article II.

(c)

The Company shall have the right to enforce payments from the Funds upon compliance with the procedures set forth in this Section 3.02.

Section 3.03. Administrative Costs The Trustee shall pay, as directed by the Company, the administrative costs and other incidental expenses of each Nonqualified Fund, including all federal, state, and local taxes, if any, imposed directly on the Nonqualified Fund or the income therefrom, legal expenses, accounting expenses, actuarial expenses and trustee expenses, from the assets of the respective Nonqualified Fund and shall pay, as directed by the Company, the administrative costs and other incidental expenses of each Qualified Fund, as defined in the Special Terms, from the assets of the respective Qualified Fund.

8 Exhibit J L-05-080 PY-CEIINRR-2880L Page 9 Section 3.04. Notice Regarding Disbursements or Payments Except for (i) payments of ordinary administrative costs (including taxes) and other incidental expenses of the fund (including legal, accounting, actuarial, and trustee expenses) in connection with the operation of the fund, (ii) withdrawals being made under 10 CFR 50.82(a)(8), and (iii) adjustments for Excess Contributions pursuant to Section 3.05 hereof being transferred between a Unit's Qualified Fund and Non-qualified Fund, no disbursement or payment may be made from the trust until written notice of the intention to make a disbursement or payment has been given to the Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable, at least 30 working days before the date of the intended disbursement or payment. The disbursement or payment from the trust may be made following the 30-working day notice period if no written notice of objection from the Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable, is received by the Trustee or the Company within the notice period. The required notice may be made by the Trustee or on the Trustee's behalf. No such notice is required for withdrawals being made pursuant to 10 CFR 50.82(a)(8)(ii), including withdrawals made during the operating life of the plant to be used for decommissioning planning. In addition, no such notice is required to be made to the NRC after decommissioning has begun and withdrawals are being made under 10 CFR 50.82(a)(8).

Section 3.05. Payments between the Funds The Trustee shall make payments (i) from a Unit's Qualified Fund to that Unit's Nonqualified Fund provided such payments are in cash and are in accordance with Section 4 of the Special Terms or (ii) from a Unit's Nonqualified Fund to that Unit's Qualified Fund provided such payments are in cash and are in accordance with the contribution limitations set forth in Section 2 of the Special Terms, as the case may be, upon presentation by the Company of a certificate substantially in the form of Exhibit C hereto executed by the Company instructing the Trustee to make any such payments. The Trustee shall be fully protected in relying upon such certificate.

IV.

Concerning the Trustee Section 4.01. Authority of Trustee The Trustee hereby accepts the Trust created under this Agreement. The Trustee shall have the authority and discretion to manage and control the Funds to the extent provided in this Agreement but does not guarantee the Funds in any manner against investment loss or depreciation in asset value or guarantee the adequacy of the Funds to satisfy the Decommissioning Costs. The Trustee shall not 9

Exhibit J L-05-080 PY-CEI/NRR-2880L Page 10 be liable for the making, retention or sale of any asset of a Qualified Fund which qualifies as a Permissible Asset, as defined in the Special Terms, nor shall the Trustee be responsible for any other loss to or diminution of the Funds, or for any other loss or damage which may result from the discharge of its duties hereunder except for any action not taken in good faith.

Section 4.02. Investment of Funds (a) The Company shall have the authority to appoint one or more investment managers who shall have the power to direct the Trustee in investing the assets of the Funds; provided, however, that the Trustee shall not follow any direction which would result in assets of the Qualified Funds being invested in assets other than Permissible Assets as defined in the Special Terms.

Any such investment manager(s) or other person directing investments made in the Trusts shall adhere to the "prudent investor" standard as specified in 18 C.F.R. 35.32(a)(3) of the Federal Energy Regulatory Commission ("FERC") regulations (the "Prudent Investor Standard"). To the extent that the Company chooses to exercise this authority, it shall so notify the Trustee and instruct the Trustee in writing to separate into a separate account those assets the investment of which will be directed by each investment manager. The Company shall designate in writing the person or persons who are to represent any such investment manager in dealings with the Trustee. Upon the separation of the assets in accordance with the Company instructions, the Trustee, as to those assets while so separated, shall be released and relieved of all investment duties, investment responsibilities and investment liabilities normally or statutorily incident to a trustee; provided, however, that the Trustee shall not be relieved of the responsibility of ensuring that assets of the Qualified Funds are invested solely in Permissible Assets, as defined in the Special Terms. The Trustee shall retain all other fiduciary duties with respect to assets the investment of which is directed by investment managers.

(b)

To the extent that the investment of assets of the Funds is not being directed by one or more investment managers under Section 4.02(a), the Trustee shall hold, invest, and reinvest the funds delivered to it hereunder as it in its sole discretion deems advisable, subject to: (i) the restrictions on the Use of Assets of the Funds set forth in Section 3.01 hereof; (ii) the limitations on the powers of the Trustee in Section VI hereof; and (iii) adherence to the Prudent Investor Standard.

(c)

Regardless of the person directing investments, any assets of the Qualified Funds shall be invested solely in Permissible Assets as defined in, and required by, the Special Terms, and shall be accumulated, invested, and reinvested in like manner. Upon the written consent of the Company, the assets of a Qualified Fund relating to a Unit may be pooled with the assets of any other Qualified Fund relating to any other Unit; provided that the book and tax allocations of the pooling arrangement are made in compliance with 10 Exhibit J L-05-080 PY-CEINRR-2880L Page I 1 Code section 704 (and the Treasury Regulations thereunder) provided further that such pooling arrangement elects to be classified as a partnership for federal income tax purposes.

(d)

Notwithstanding any other provision of this Agreement, with respect to the pooling of investments authorized by subparagraph (c) no part of any Fund's (or any subsequent holder's) interest in such pool, nor any right. pertaining to such interest (including any right to substitute another entity for the Fund or for any subsequent holder, as holder of investments pooled pursuant to subparagraph (c)) may be sold, assigned, transferred or otherwise alienated or disposed of by any holder of an interest in the pool unless the written consent to the transfer of every other holder of interests in such pool is obtained in advance of any such transfer.

(e)

Notwithstanding the provisions of subparagraph (d) of this Section, a Fund's investment in a pooled arrangement may be withdrawn from the pool (but not from the Master Trust, except as otherwise permitted by this Agreement) at any time upon 7 days written notice to the Trustee by the Fund. If the Fund withdraws its entire interest in a pool, the pooled arrangement shall terminate 30 days after notice of final withdrawal has been given by any withdrawing Fund unless a majority in interest of the remaining Funds give their written consent to continue the pool within such 30 day period. If the pooled arrangement terminates, each Fund's assets will be segregated into a separate account under the Master Trust, and no further commingling may occur for a period of at least one year after such termination.

(f)

Subparagraphs (c), (d) and (e) apply to transfers of interests within, and withdrawals from, the pooling arrangement.

Nothing within these sections shall be interpreted to permit or to limit transfer of interests in, or withdrawals from, a Fund, which transfers and withdrawals are governed by other provisions of this Agreement. In addition, the provisions of subparagraphs (c), (d) and (e) shall not limit the Trustee's authority to invest in permissible common or collective trust funds.

Section 4.03. Prohibition Against Self Dealing Notwithstanding any other provision in this Agreement, the Trustee shall not engage in any act of self dealing as defined in section 468A(e)(5) of the Code and Treasury Regulations § 1.468A-5(b) or any corresponding future law or Treasury Regulation.

Section 4.04. Compensation The Trustee shall be entitled to receive out of the Funds reasonable compensation for services rendered by it, as well as expenses necessarily incurred by it in the execution of the Trusts hereunder, provided such compensation and expenses qualify as administrative costs and other incidental expenses 11 Exhibit J L-05-080 PY-CEI/NRR-2880L Page 12 of a Qualified Fund, as defined in the Special Terms, with respect to any payment of compensation and expenses from that Qualified Fund. The Company acknowledges that, as part of the Trustee's compensation, the Trustee will earn interest on balances, including disbursement balances and balances arising from purchase and sale transactions. If the Trustee advances cash or securities for any purpose, including the purchase or sale of foreign exchange or of contracts for foreign exchange, or in the event that the Trustee shall incur or be assessed taxes, interest, charges, expenses, assessments, or other liabilities in connection with the performance of this Agreement, except such as may arise from its own negligent action, negligent failure to act, or willful misconduct, any property at any time held for the Funds or under this Agreement shall be security therefor and the Trustee shall be entitled to collect from the Funds sufficient cash for reimbursement, and if such cash is insufficient, 'dispose of the assets of the Company held under this Agreement to the extent necessary to obtain reimbursement. To the extent the Trustee advances funds to the Funds for disbursements or to effect the settlement of purchase transactions, the Trustee shall be entitled to collect from the Funds reasonable charges established under the Trustee's standard overdraft terms, conditions, and procedures.

Section 4.05. Books of Account The Trustee shall keep separate true and correct books of account with respect to each Fund, which books of account shall at all reasonable times be open to inspection by the Company or its duly appointed representatives.

The Trustee shall, upon written request of the Company, permit government agencies, such as the NRC or the Service, to inspect the books of account of each Fund. The Trustee shall furnish to the Company on or about the tenth business day of each month a statement for each Fund showing, with respect to the preceding calendar month, the balance of assets on hand at the beginning of such month, all receipts, investment transactions, and disbursements which took place during such month and the balance of assets on hand at the end of such month. The Trustee agrees to provide on a timely basis any information deemed necessary by the Company to file the Company's federal, state and local tax returns.

Section 4.06. Reliance on Documents The Trustee, upon receipt of documents furnished to it by the Company pursuant to the provisions of this Agreement, shall examine the same to determine whether they conform to the requirements thereof. The Trustee acting in good faith may conclusively rely, as to the truth of statements and the correctness of opinions expressed, on any certificate or other documents conforming to the requirements of this Agreement. If the Trustee in the administration of the Funds, shall deem it necessary or desirable that a matter be provided or established prior to taking or suffering any action hereunder, such matter (unless evidence in respect thereof is otherwise specifically prescribed hereunder) may be deemed by the Trustee to be conclusively provided or established by a certificate signed by the Chairman of the Board, 12

Enclosure I Exhibit J L-05-080 PY-CEIINRR-2880L Page 13 the President or any Vice President of the Company and delivered to the Trustee. The Trustee shall have no duty to inquire into the validity, accuracy or relevancy of any statement contained in any certificate or document nor the authorization of any party making such certificate or delivering such document, and the Trustee may rely and shall be protected in acting or refraining from acting upon any such written certificate or document furnished to it hereunder and believed by it to be genuine and to have been signed or presented by the proper party or parties. The Trustee shall not, however, be relieved of any obligation (a) to refrain from self-dealing as provided in Section 4.03 hereof; (b) to ensure that all assets of the Qualified Funds are invested solely in Permissible Assets as defined in the Special Terms; or (c) to adhere to the Prudent Investor Standard if acting as manager.

Section 4.07. Liability and Indemnification The Trustee shall not be liable for any action taken by it in good faith and without gross negligence, willful misconduct or recklessness and reasonably believed by it to be authorized or within the rights or powers conferred upon it by this Agreement and may consult with counsel of its own choice (including counsel for the Company) and shall have full and complete authorization and protection for any action taken or suffered by it hereunder in good faith and without gross negligence and in accordance with the opinion of such counsel, provided, however, that the Trustee shall be liable for direct damages resulting from investing assets of the Qualified Funds in other than Permissible Assets or from self dealing as provided in Section 4.03 hereof.

Provided indemnification does not result in self dealing under Section 4.03 hereof or in a deemed contribution to a Qualified Fund in excess of the limitation on contributions under Section 468A of the Code and the Treasury Regulations thereunder, the Company hereby agrees to indemnify the Trustee for, and to hold it harmless against, any loss, liability or expense incurred without gross negligence, willful misconduct, recklessness or bad faith on the part of the Trustee, arising out of or in connection with its entering into this Agreement and carrying out its duties hereunder, including the costs and expenses of defending itself against any claim of liability, provided such loss, liability or expense does not result from investing assets of the Qualified Funds in other than Permissible Assets as defined in the Special Terms or from self dealing under Section 4.03 hereof, and provided further that no such costs or expenses shall be paid if the payment of such costs or expenses is prohibited by section 468A of the Code or the Treasury Regulations thereunder.

The Trustee shall not be responsible or liable for any losses or damages suffered by a Fund arising as a result of the insolvency of any custodian, subtrustee or subcustodian, except to the extent the Trustee was negligent in its selection or continued retention of such entity. Under no circumstances shall the Trustee be liable for any indirect, consequential, or special damages with respect to its role as Trustee.

13

Enclosure I Exhibit J L-05-080 PY-CEI/NRR-2880L Page 14 Section 4.08. Resignation, Removal and Successor Trustees The Trustee may resign at any time upon sixty (60) days' written notification to the Company.

The Company may remove the Trustee for any reason at any time upon thirty (30) days' written notification to the Trustee. If a successor Trustee shall not have been appointed within these specified time periods after the giving of written notice of such resignation or removal, the Trustee or Company may apply to any court of competent jurisdiction to appoint a successor Trustee to act until such time, if any, as a successor shall have been appointed and shall have accepted its appointment as provided below. If the Trustee shall be adjudged bankrupt or insolvent, a vacancy shall thereupon be deemed to exist in the office of Trustee and a successor shall thereupon be appointed by the Company. Any successor Trustee appointed hereunder shall execute, acknowledge and deliver to the Company an appropriate written instrument accepting such appointment hereunder, subject to all the terms and conditions hereof, and thereupon such successor Trustee shall become fully vested with all the rights, powers, trusts, duties and obligations of its predecessor in trust hereunder, with like effect as if originally named as Trustee hereunder. The predecessor Trustee shall, upon written request of the Company and payment of all fees and expenses, deliver to the successor Trustee the corpus of the Funds and perform such other acts as may be required or be desirable to vest and confirm in said successor Trustee all right, title and interest in the corpus of the Funds to which it succeeds.

Section 4.09. Merger of Trustee Any corporation or other legal entity into which the Trustee may be merged or with which it may be consolidated, or any corporation or other legal entity resulting from any merger or consolidation to which the Trustee shall be a party, or any corporation or other legal entity to which the corporate trust functions of the Trustee may be transferred, shall be the successor Trustee under this Agreement without the necessity of executing or filing any additional acceptance of this Agreement or the performance of any further act on the part of any other parties hereto.

V.

Amendments The Company may revoke this Agreement at any time or may amend this Agreement from time to time, provided such amendment does not cause the Qualified Funds to fail to qualify as Nuclear Decommissioning Reserve Funds under section 468A of the Code and the Treasury Regulations thereunder.

The Agreement may not be amended so as to violate 468A of the Code or the Treasury Regulations thereunder. The Qualified Funds are established and shall be maintained for the sole purpose of qualifying as Nuclear Decommissioning Reserve Funds under section 468A of the Code and the Treasury Regulations thereunder. If the Qualified Funds would fail to so qualify because 14 Exhibit J L-05-080 PY-CEIINRR-2880L Page 15 of any provision contained in this Agreement, this Agreement shall be deemed to be amended as necessary to conform with the requirements of section 468A and the Treasury Regulations thereunder. If a proposed amendment shall affect the responsibility of the Trustee, such amendment shall not be considered valid and binding until such time as the amendment is executed by the Trustee. Notwithstanding any provision herein to the contrary, this Agreement cannot be modified in any material respect without having first given 30 working days Notice before the proposed effective date of the amendment to the NRC Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable. This Agreement may not be amended if the Trustee or the Company receives written notice of objection from the Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards within the notice period.

VI.

Powers of the Trustee and Investment Manager Section 6.01. General Powers The Trustee shall have and exercise the following powers and authority in the administration of the Funds only on the direction of an Investment Manager where such powers and authority relate to a separate account established for an Investment Manager, and in its sole discretion where such powers and authority relate to investments made by the Trustee in accordance with Section 4.02(b):

(a) to purchase, receive or subscribe for any securities or other property and to retain in trust such securities or other property; (b) to sell, exchange, convey, transfer, lend, or otherwise dispose of any property held in the Funds and to make any sale by private contract or public auction; and no person dealing with the Trustee shall be bound to see to the application of the purchase money or to inquire into the validity, expediency or propriety of any such sale or other disposition; (c) to vote in person or by proxy any stocks, bonds or other securities held in the Funds; (d) to exercise any rights appurtenant to any such stocks, bonds or other securities for the conversion thereof into other stocks, bonds or securities, or to exercise rights or options to subscribe for or purchase additional stocks, bonds or other securities, and to make any and all necessary payments with respect to any such conversion or exercise, as well as to write options with respect to such stocks and to enter into any transactions in other forms of options with respect to any options which the Funds have outstanding at any time; 15 Exhibit J L-05-080 PY-CEUNRR-2880L Page 16 (e) to join in, dissent from or oppose the reorganization, recapitalization, consolidation, sale or merger of corporations or properties of which the Funds may hold stocks, bonds or other securities or in which it may be interested, upon such terms and conditions as deemed wise, to pay any expenses, assessments or subscriptions in connection therewith, and to accept any securities or property, whether or not trustees would be authorized to invest in such securities or property, which may be issued upon any such reorganization, recapitalization, consolidation, sale or merger and thereafter to hold the same, without any duty to sell; (f) to enter into any type of contract with any insurance company or companies, either for the purposes of investment or otherwise; provided that no insurance company dealing with the Trustee shall be considered to be a party to this Agreement and shall only be bound by and held accountable to the extent of its contract with the Trustee.

Except as otherwise provided by any contract, the insurance company need only look to the Trustee with regard to any instructions issued and shall make disbursements or payments to any person, including the Trustee, as shall be directed by the Trustee. Where applicable, the Trustee shall be the sole owner of any and all insurance policies or contracts issued. Such contracts or policies, unless otherwise determined, shall be held as an asset of the Funds for safekeeping or custodian purposes only; (g) upon authorization of the Company to lend the assets of the Funds and, specifically, to loan any securities to brokers, dealers or banks upon such terms, and secured in such manner, as may be determined by the Trustee, to permit the loaned securities to be transferred into the name of the borrower or others and to permit the borrower to exercise such rights of ownership over the loaned securities as may be required under the terms of any such loan; provided, that, with respect to the lending of securities pursuant to this paragraph, the Trustee's powers shall subsume the role of custodian (the expressed intent hereunder being that the Trustee, in such case, be deemed a financial institution, within the meaning of Section 101(22) of the Bankruptcy Code);

and provided, further, that any loans made from the Funds shall be made in conformity with such laws or regulations governing such lending activities which may have been promulgated by any appropriate regulatory body at the time of such loan; (h) to purchase, enter, sell, hold, and generally deal in any manner in and with contracts for the immediate or future delivery of financial instruments of any issuer or of any other property and in foreign exchange or foreign exchange contracts; to grant, purchase, sell, exercise, permit to expire, permit to be held in escrow, and otherwise to acquire, dispose of, hold and generally deal in any manner with and in all forms of options in any combination.

16 Exhibit J L-05-080 PY-CEI/NRR-2880L Page 17 Settlements of transactions may be effected in trading and processing practices customary in the jurisdiction or market where the transaction occurs. The Company acknowledges that this may, in certain circumstances, require the delivery of cash or securities (or other property) without the concurrent receipt of securities (or other property) or cash and, in such circumstances, the Company shall have sole responsibility for nonreceipt of payment (or late payment) by the counterparty.

Notwithstanding anything in this Agreement to the contrary, the Trustee shall not be responsible or liable for its failure to perform under this Agreement or for any losses to the Funds resulting from any event beyond the reasonable control of the Trustee, its agents or subcustodians, including but not limited to nationalization,

strikes, expropriation, devaluation, seizure, or similar'action by any governmental authority, de facto or de jure; or enactment, promulgation, imposition or enforcement by any such governmental authority of currency restrictions, exchange controls, levies or other charges affecting the Funds' property; or the breakdown, failure or malfunction of any utilities or telecommunications systems; or any order or regulation of any banking or securities industry including changes in market rules and market conditions affecting the execution or settlement of transactions; or acts of war, terrorism, insurrection or revolution; or acts of God; or any other similar event. This Section shall survive the termination of this Agreement.

Section 6.02. Specific Powers of the Trustee The Trustee shall have the following powers and authority, to be exercised in its sole discretion with respect to the Funds:

(a) to appoint agents, custodians, subtrustees, depositories or counsel, domestic or foreign, as to part or all of the Funds and functions incident thereto where, in the sole discretion of the Trustee, such delegation is necessary in order to facilitate the operations of the Funds and such delegation is not inconsistent with the purposes of the Funds or in contravention of any applicable law. To the extent that the appointment of any such person or entity may be deemed to be the appointment of a fiduciary, the Trustee may exercise the powers granted hereby to appoint as such a fiduciary any person or entity. Upon such delegation, the Trustee may require such reports, bonds or written agreements as it deems necessary to properly monitor the actions of its delegate; (b) to cause any, investment, either in whole or in part, in the Funds to be registered in, or transferred into, the Trustee's name or the names of a nominee or nominees, including but not limited to that of the Trustee or an affiliate of the Trustee, a clearing corporation, or a depository, or in book-entry form, or to retain any such 17 Exhibit J L-05-080 PY-CEI/NRR-2880L Page 18 investment unregistered or in a form permitting transfer by delivery, provided that the books and records of the Trustee shall at all times show that such investments are a part of the Funds; and to cause any such investment, or the evidence thereof, to be held by the Trustee, in a depository, in a clearing corporation, in book-entry form, or by any other entity or in any other manner permitted by law; provided that the Trustee shall not be responsible for any losses resulting from the deposit or maintenance of securities or other property (in accordance with market practice, custom, or regulation) with any recognized foreign or domestic clearing facility, book-entry system, centralized custodial depository, or similar organization; (c) to make, execute and deliver, as Trustee, any and all deeds, leases, mortgages, conveyances, waivers, releases or other instruments in writing necessary or desirable for the accomplishment of any of the foregoing powers; (d) to defend against or participate in any legal actions involving the Funds or the Trustee in its capacity stated herein, in the manner and to the extent it deems advisable; (e) to form corporations and to create trusts, to hold title to any security or other property, to enter into agreements creating partnerships or joint ventures for any purpose or purposes determined by the Trustee to be in the best interests of the Funds; (f) to establish and maintain such separate accounts in accordance with the instructions of the as the Company deems necessary for the proper administration of the Funds, or as determined to be necessary by the Trustee; (g) to hold uninvested cash in its commercial bank or that of an affiliate, as it shall deem reasonable or necessary; (h) to invest in any collective, common or pooled trust fund operated or maintained exclusively for the commingling and collective investment of monies or other assets including any such fund operated or maintained by the Trustee or an affiliate. The Company expressly understands and agrees that any such collective fund may provide for the lending of its securities by the collective fund trustee and that such collective fund's trustee will receive compensation for the lending of securities that is separate from any compensation of the Trustee hereunder, or any compensation of the collective fund trustee for the management of such collective fund. The Trustee is authorized to invest in a collective fund which invests in Mellon Financial Corporation stock in accordance with the terms and conditions of the Department of Labor Prohibited Transaction Exemption 95-56 (the "Exemption") granted to the Trustee and its affiliates and to use a 18 Exhibit J L-05-080 PY-CEIINRR-2880L Page 19 cross-trading program in accordance with the Exemption. The Company acknowledges receipt of the notice entitled "Cross-Trading Information," a copy of which is attached to this Agreement as Exhibit E; (i) to invest in open-end and closed-end investment companies, including those for which the Trustee or an affiliate provides services for a fee, regardless of the purposes for which such fund or funds were created, and any partnership, limited or unlimited, joint venture and other forms of joint enterprise created for any lawful purpose; and (j) to generally take all action, whether or not expressly authorized, which the Trustee may deem necessary or desirable for the protection of the Funds.

Notwithstanding anything else in this Agreement to the contrary, including, without limitation, any specific or general power granted to the Trustee and to the investment managers, including the power to invest in real property, no portion of the Funds shall be invested in real estate (except for investments tied to market indexes or other non-nuclear sector common trust funds or mutual funds). For this purpose "real estate" includes, but is not limited to, real property, leaseholds or mineral interests.

Section 6.03. Authorized Party The powers described in Section 6.02 may be exercised by the Trustee with or without instructions from the Company or a party authorized by the Company to act on its behalf, but where the Trustee acts on Authorized Instructions, the Trustee shall be fully protected as described in Section 4.07. All directions and instructions to the Trustee from an Authorized Party shall be in writing, by facsimile transmission, electronic transmission subject to the Trustee's practices, or any other method specifically agreed to in writing by the Company and the Trustee, provided the Trustee may, in its discretion, accept oral directions and instructions and may require confirmation in writing. Without limiting the generality of the foregoing, the Trustee shall not be liable for the acts or omissions of any person appointed under paragraph (a) of Section 6.02 pursuant to Authorized Instructions.

Section 6.04. Prohibition Against Nuclear Sector Investments Except for investments tied to market indexes or other non-nuclear sector collective, commingled or mutual funds, the assets of the Funds shall not be invested in: (1) the securities or other obligations of FirstEnergy Corp. or FirstEnergy Nuclear Generation Corp., or affiliates thereof, or their successors or assigns, as identified by CUSIP by the Company; and (2) the securities or other obligations of any entity owning or operating one or more nuclear power plants. A non-nuclear sector collective, commingled or mutual fund is one in which less than 50 percent of the fund is invested in the securities of entities that own 19 Exhibit J L-05-080 PY-CEIINRR-2880L Page 20 or operate a nuclear power plant or that are parent companies of subsidiaries that own or operate a nuclear power plant.

VII.

Termination A Unit's Qualified Fund shall terminate upon the later of (A) the earlier of either (i) substantial completion of decommissioning of that Fund's Unit, as defined in the Special Terms, or (ii) disqualification of that Unit's Qualified Fund by the Service as provided in Treasury Regulations § 1.468A5(c) or any corresponding future Treasury Regulation or (B) termination by the NRC of that Unit's operating license.

A Nonqualified Fund shall terminate upon termination by the NRC of that Unit's license. If a Fund termination occurs before the NRC terminates the respective Unit's operating license, the Trustee will adhere to Section 6.02(b) of this Agreement.

Upon the termination of any Fund, the assets of the terminated Fund shall be distributed to the Company.

20 Exhibit J L-05-080 PY-CEI/NRR-2880L Page 21 VIII. Miscellaneous Section 8.01. Binding Agreement All covenants and agreements in this Agreement shall be binding upon and inure to the benefit of the respective parties hereto, their successors and assigns.

"I Section 8.02. Notices All notices and communications hereunder shall be in writing and shall be deemed to be duly given on the date mailed if sent by registered mail, return receipt requested, as follows:

MELLON BANK, N.A.

Trust and Investment Department Attn: Trust Administration Room 151-1320 One Mellon Bank Center Pittsburgh, PA 15258 FIRSTENERGY NUCLEAR GENERATION CORP.

Attn:

Title:

76 South Main Street Akron, OH 49308 or at such other address as the Trustee or Company may have furnished to the other party in writing by registered mail, return receipt requested.

Section 8.03. Governing Law Each Unit's Funds have been established pursuant to this Agreement in accordance with the requirements for trusts under the laws of the State of Ohio and this Agreement shall be governed by and construed and enforced in accordance with the laws of the State of Ohio.

Section 8.04. Counterparts This Agreement may be executed in several counterparts, and all such counterparts executed and delivered, each an original, shall constitute but one and the same instrument.

Section 8.05. Contractual Income The Trustee shall credit the Funds with income and maturity proceeds on securities on the contractual payment date net of any taxes or upon actual receipt as agreed between the Trustee and the Company. To the extent the Company and the Trustee have agreed to credit income on the contractual 21 Exhibit J L-05-080 PY-CEIINRR-2880L Page 22 payment date, the Trustee may reverse such accounting entries with back value to the contractual payment date if the Trustee reasonably believes that such amount will not be received by it.

Section 8.06. Contractual Settlement The Trustee will attend to the settlement of securities transactions on the basis of either contractual settlement date accounting or actual settlement date accounting as agreed between the Company and the Trustee. To the extent the Company and the Trustee have agreed to settle certain securities transactions on the basis of contractual settlement date accounting, the Trustee may reverse with back value to the contractual settlement date any entry relating to such contractual settlement where the related transaction remains unsettled according to established procedures.

Section 8.07. Representations & Warranties The Company and the Trustee hereby each represent and warrant to the other that it has full authority to enter into this Agreement upon the terms and conditions hereof and that the individual executing this Agreement on its behalf has the requisite authority to bind the Company and the Trustee to this Agreement.

22 Exhibit J L-05-080 PY-CEI/NRR-2880L Page 23 IN WITNESS WHEREOF, the parties hereto, each intending to be legally bound hereby, have hereunto set their hands and seals as of the day and year first above written.

FIRSTENERGY NUCLEAR GENERATION CORP.

By:

Name:

Title:

MELLON BANK, N.A.

By:

Name:

Title:

23 Exhibit J L-05-080 PY-CEI/NRR-2880L Page 1 EXHIBIT "A" SPECIAL TERMS OF THE QUALIFIED NUCLEAR DECOMMISSIONING RESERVE FUNDS The following Special Terms of the Qualified Nuclear Decommissioning Reserve Funds (hereinafter referred to as the "Special Terms") will apply for purposes of the Nuclear Decommissioning Master Trust Agreement (the "Agreement"),

dated between FIRSTENERGY NUCLEAR GENERATION CORP.

(the "Company") and MELLON BANK, N.A. (the Trustee").

Section 1. Definitions. The following terms as used in the Special Terms shall, unless the context clearly indicates otherwise, have the following respective meanings:

(a)

"Administrative costs and other incidental expenses of the Qualified Funds" shall mean all ordinary and necessary expenses incurred in connection with the operation of the Qualified

Funds, as provided in Treasury Regulations

§ 1.468A-5(a)(3)(ii)(A) or any corresponding future Treasury Regulation, including without limitation, federal, state and local income tax (including any Final Tax Liabilities), legal expenses, accounting expenses, actuarial expenses and trustee expenses.

(b)

"Final Tax Liabilities" shall mean any and all tax liabilities determined to be owing but not paid out of the assets of any of the Seller's or Transferor's Qualified Fund related to each unit prior to the transfer of the assets of the Seller's or Transferor's Qualified Fund to the Qualified Fund.

(c)

"Final Tax Refunds" shall mean any and all tax refunds determined to be receivable but not collected by the Seller's or Transferor's Qualified Fund prior to the transfer of the assets of the Seller's or Transferor's Qualified Fund to the Qualified Funds.

(d)

"Permissible Assets" shall mean any investment permitted for a qualified nuclear decommissioning reserve fund under section 468A of the Internal Revenue Code of 1986, as amended, or any corresponding section or sections of any future United States internal revenue statute (the "Code") and the Treasury Regulations thereunder, subject to the restrictions provided in Section 5.04 6.04of the Agreement.

(e)

"Qualified Decommissioning Costs" shall mean all expenses otherwise deductible for federal income tax purposes without regard to section 280B of the Code, 1

Exhibit J L-05-080 PY-CEIINRR-2880L Page 2 incurred (or to be incurred) in connection with the entombment, decontamination, dismantlement, removal and disposal of the structures, systems and components of a Unit when it has permanently ceased the production of electric energy, excluding any costs incurred for the disposal of spent nuclear fuel, as provided in Treasury Regulations

§ 1.468A-l(b)(5) or any corresponding future Treasury Regulation. Such term includes all otherwise deductible expenses to be incurred in connection with the preparation for decommissioning, such as engineering and other planning expenses, and all otherwise deductible expenses to be incurred with respect to a Unit after the actual decommissioning occurs, such as physical security and radiation monitoring expenses.

(f)

"Seller's or Transferor's Qualified Fund" shall mean the trust established and maintained for any respective unit that qualified as a nuclear decommissioning reserve fund under Code section 468A prior to the sale or transfer of such unit.

(g)

"Substantial completion of decommissioning" shall mean the date that the maximum acceptable radioactivity levels mandated by the NRC with respect to a decommissioned nuclear power plant are satisfied by the Unit; provided, however, that if the Company requests a ruling from the Service, the date designated by the Service as the date on which substantial completion of decommissioning occurs shall govern; provided, further, that the date on which substantial completion of decommissioning occurs shall be in accordance with Treasury Regulations §1.468A-5(d)(2) or any corresponding future Treasury Regulation.

Section 2. Contributions to a Oualified Fund. The assets of the Qualified Funds shall be contributed by the Company (or by others approved by the Company in writing) from time to time in cash. The Trustee shall not accept any contributions for the Qualified Funds other than cash payments with respect to which the Company is allowed a deduction under section 468A(a) of the Code and Treasury Regulations § 1.468A-2(a) or any corresponding future Treasury Regulations, except for any Final Tax Refunds.

The Company hereby represents that all contributions (or deemed contributions), except for any Final Tax Refunds, by the Company to the Qualified Funds in accordance with the provisions of Section 2.03 of the Agreement shall be deductible under section 468A of the Code and Treasury Regulations § 1.468A-2(a) or any corresponding future Treasury Regulation or shall be withdrawn pursuant to Section 4 hereof.

Section 3. Limitation on Use of Assets. The assets of the Qualified Funds shall be used exclusively as follows:

(a)

To satisfy, in whole or in part, the liability of the Company for Qualified Decommissioning Costs through payments by the Trustee pursuant to Article III of the 2

Exhibit J L-05-080 PY-CEI/NRR-2880L Page 3 Agreement; and (b)

To pay the administrative costs and other incidental expenses of the Qualified Funds; and (c)

To the extent the assets of the Qualified Funds are not currently required for (a) and (b) above, to invest directly in Permissible Assets.

Section 4. Transfers by the Company.

If the Company's contribution (or deemed contribution) excluding any Final Tax Refunds to the Qualified Funds in any one year exceeds the amount deductible under section 468A of the Code and the Treasury Regulations thereunder, the Company may instruct the Trustee to transfer such excess contribution from a Unit's Qualified Fund to that Unit's Nonqualified Fund, as defined in the Agreement, pursuant to Section 3.05 of the Agreement, provided any such transfer occurs on or before the date prescribed by law (including extensions) for filing the federal income tax return of the Qualified Funds for the taxable year to which the excess contribution relates for withdrawals pursuant to Treasury Regulations §§ 1.468A-5(c)(2) and 1.468A-2(f)(2) and occurs on or before the later of the date prescribed by law (including extensions) for filing the federal income tax return of the Qualified Funds for the taxable year to which the excess contribution relates or the date that is thirty (30) days after the date that the Company receives the ruling amount for such taxable year for withdrawals pursuant to Treasury Regulations § 1.468A-3(j)(3).

If the Company determines that transfer pursuant to this Section 4 is appropriate, the Company shall present a certificate so stating to the Trustee signed by its Chairman of the Board, its President or one of its Vice Presidents and its Treasurer or an Assistant Treasurer, requesting such withdrawal and transfer. The certificate shall be substantially in the form attached as Exhibit C to the Agreement for transfers to Nonqualified Funds as provided in Section 3.05 of the Agreement and substantially in the form of Exhibit D to the Agreement for withdrawals and transfers by the Company.

Section 5. Taxable Year/Tax Returns. The accounting and taxable year for the Qualified Funds shall be the taxable year of the Company for federal income tax purposes. If the taxable year of the Company shall change, the Company shall notify the Trustee of such change and the accounting and taxable year of the Qualified Funds must change to the taxable year of the Company as provided in Treasury Regulations

§ 1.468A-4(c)(1) or any corresponding future Treasury Regulation. The Company shall assist the Trustee in complying with any requirements under section 442 of the Code and Treasury Regulations § 1.442-1. The Company shall prepare, or cause to be prepared, any tax returns required to be filed by the Qualified Funds, and the Trustee shall sign and 3

Exhibit J L-05-080 PY-CEI/NRR-2880L Page 4 file such returns on behalf of the Qualified Funds. The Trustee shall cooperate with the Company in the preparation of such returns.

4

Enclosure I Exhibit J L-05-080 PY-CEI/NRR-2880L Page 1 EXHIBIT '"B" CERTIFICATE FOR PAYMENT OF DECOMMISSIONING COSTS MELLON BANK, N.A.,

as Trustee Trust and Investment Department Attn: Trust Administration Room 151-3346 One Mellon Bank Center Pittsburgh, PA 15258 This Certificate is submitted pursuant to Section 3.02 of the Nuclear Decommissioning Master Trust Agreement (the "Agreement"), dated _

between Mellon Bank, N.A. (the "Trustee") and FirstEnergy Nuclear Generation Corp.

(the "Company"). All capitalized terms used in this Certificate and not otherwise defined herein shall have the meanings assigned to such terms in the Agreement. In your capacity as Trustee, you are hereby authorized and requested to disburse out of the [Unit name's]

Funds to [payee] the amount of $_

_ from the Qualified Fund and the amount of from the Nonqualified Fund for the payment of the Decommissioning Costs which have been incurred with respect to the [Unit name].

Prior to making such disbursements, however, if required pursuant to Section 3.04 of the Agreement, the Trustee shall provide thirty days prior written notice of such disbursement to the NRC and shall not make such disbursement if the Trustee receives written notice of any objections from the NRC Director, Office of Nuclear Reactor Regulations during such thirty day period, or if the Trustee receives such notice at any later time that is nevertheless prior to disbursement. With respect to such Decommissioning Costs, the Company hereby certifies as follows:

1.

The amount to be disbursed pursuant to this Certificate shall be solely used for the purpose of paying the Decommissioning Costs described in Schedule A hereto.

2.

None of the Decommissioning Costs described in Schedule A hereto have previously been made the basis of any certificate pursuant to Section 3.02 of the Agreement.

1 Exhibit J L-05-080 PY-CEI/NRR-2880L Page 2

/

3.

The amount to be disbursed from the Qualified Fund pursuant to this Certificate shall be used solely for the purpose of paying Qualified Decommissioning Costs as defined in the Special Terms.

4.

Any necessary authorizations of the NRC or any corresponding governmental authority having jurisdiction over the decommissioning of the Unit have been obtained, except that prior written notice to the NRC [is] [is not] required pursuant to Section 3.04 of the Agreement.

IN WITNESS WHEREOF, the undersigned have executed this Certificate in the capacity shown below as of FIRSTENERGY NUCLEAR GENERATION CORP.

By:

Name:

Title:

[President] [Vice President]

FIRSTENERGY NUCLEAR GENERATION CORP.

By:

Name:

Title:

[Company Officer]

Acknowledged by:

MELLON BANK, N.A.

By:

Name:

Title:

2.

- -- --- Exhibit J L-05-080 PY-CEIINRR-2880L Page 1 EXHIBIT "C" CERTIFICATE FOR TRANSFER BETWEEN THE QUALIFIED FUND AND THE NONQUALIFIED FUND MELLON BANK, N.A.,

as Trustee Trust and Investment Department Attn: Trust Administration Room 151-3346 One Mellon Bank Center Pittsburgh, PA 15258 This Certificate is submitted pursuant to Section 3.05 of the Nuclear Decommissioning Master Trust Agreement (the "Agreement"), dated _

between Mellon Bank, N.A. (the "Trustee") and FirstEnergy Nuclear Generation Corp.

(the "Company"). All capitalized terms used in this Certificate and not otherwise defined herein shall have the meanings assigned to such terms in the Agreement. In your capacity as Trustee, you are hereby authorized and instructed as follows (complete one):

To pay $

in cash from the [Unit name's] Nonqualified Fund to that Unit's Qualified Fund; or To pay $

in cash from the [Unit name's] Qualified Fund to that Unit's Nonqualified Fund.

With respect to such payment, the Company hereby certifies as follows:

1.

Any amount stated herein to be paid from the Nonqualified Fund to the Qualified Fund is in accordance with the contribution limitations applicable to the Qualified Fund set forth in Section 2 of the Special Terms and the limitations of Section 3.05 of the Agreement.

1

Enclosure I Exhibit J L-05-080 PY-CEIFNRR-2880L Page 2

2.

Any amount stated herein to be paid from the Qualified Fund to the Nonqualified Fund is in accordance with Section 4 of the Special Terms.

The Company has determined that such payment is appropriate under the standards of Section 4 of the Special Terms.

IN WITNESS WHEREOF, the undersigned have executed this Certificate in the capacity as shown below as of FIRSTENERGY NUCLEAR GENERATION CORP.

By:

Name:

Title:

Acknowledged by:

MELLON BANK, N.A.

By:

Name:

Title:

2

Enclosure I Exhibit J L-05-080 PY-CEI/NRR-2880L Page 1 EXHIBIT "D" CERTIFICATE FOR WITHDRAWAL OF EXCESS CONTRIBUTIONS FROM QUALIFIED FUND MELLON BANK, N.A.,

as Trustee Trust and Investment Department Attn: Trust Administration Room 151-3346 One Mellon Bank Center Pittsburgh, PA 15258 This Certificate is submitted pursuant to Section 4 of the Special Terms attached as Exhibit A to the Nuclear Decommissioning Master Trust Agreement (the "Agreement"), dated _

between Mellon Bank, N.A. (the 'Trustee") and FirstEnergy Nuclear Generation Corp. (the "Company"). All capitalized terms used in this Certificate and not otherwise defined herein shall have the meanings assigned to such terms in the Agreement. In your capacity as Trustee, you are hereby authorized and instructed to pay $_

in cash to the Company from the [Unit name's] Qualified Fund. With respect to such payment, the Company hereby certifies that withdrawal and transfer pursuant to Section 4 of the Special Terms is appropriate and that $-

constitutes an excess contribution pursuant to such Section.

IN WITNESS WHEREOF, the undersigned have executed this Certificate in the capacity as shown below as of__

1 Exhibit J L-05-080 PY-CEI/NRR-2880L Page 2 FIRSTENERGY NUCLEAR GENERATION CORP.

By:

Name:

Title:

Acknowledged by:

MELLON BANK, N.A.

By:

Name:

Title:

2 Exhibit J L-05-080 PY-CEI/NRR-2880L Page 1 EXHIBIT "E" CROSS-TRADING INFORMATION As part of the cross-trading program covered by the Exemption for the Trustee and its affiliates, the Trustee is to provide to each affected Trust the following information:

I.

The existence of the cross-trading program The Trustee has developed and intends to utilize, wherever practicable, a cross-trading program for Indexed Accounts and Large Accounts as those terms are defined in the Exemption.

II.

The "triggering events" creating cross-trade opportunities In accordance with the exemption three "triggering events" may create opportunities for cross-trading transactions. They are generally the following (see the Exemption for more information):

A.

A change in the composition or weighting of the index by the independent organization creating and maintaining the index; B.

A change in the overall level of investment in an Indexed Account as a result of investments and withdrawals on the account's opening date, where the Account is a bank collective fund, or on any relevant date for non-bank collective funds; provided, however, a change in an Indexed Account resulting from investments or withdrawals of assets of the Trustee's own plans (other than the Trustee's defined contribution plans under which participants may direct among various investment options, including Indexed Accounts) are excluded as a "triggering event"; or C

A recorded declaration by the Trustee that an accumulation of cash in an Indexed Account attributable to interest or dividends on, and/or tender offers for, portfolio securities equal to not more than 0.5% of the Account's total value has occurred.

111.

The pricing mechanism utilized for securities purchased or sold Securities will be valued at the current market value for the securities on the date of the crossing transaction.

Equity securities - the current market value for the equity security will be the closing price on the day of trading as determined by an independent pricing I

Exhibit J L-05-080 PY-CEI/NRR-2880L Page 2 service; unless the security was added to or deleted from an index after the close of trading, in which case the price will be the opening price for that security on the next business day after the announcement of the addition or deletion.

Debt securities - the current market value of the debt security will be the price determined by the Trustee as of the close of the day of trading according to the Securities and Exchange Commission's Rule 17a-7(b)(4) under the Investment Company Act of 1940.

Debt securities that are not reported securities or traded on an exchange will be valued based on an average of the highest current independent bids and the lowest current independent offers on the day of cross-trading. The Trustee will use reasonable inquiry to obtain such prices from at least three independent sources that are brokers or market makers. If there are fewer than three independent sources to price a certain debt security, the closing price quotations will be obtained from all available sources.

IV.

The allocation methods Direct cross-trade opportunities will be allocated among potential buyers or sellers of debt or equity securities on a pro rata basis. With respect to equity securities, please note the Trustee imposes a trivial share constraint to reduce excessive custody ticket charges to participating accounts.

V.

Other procedures implemented by the Trustee for its cross-trading practices The Trustee has developed certain internal operational procedures for cross-trading debt and equity securities. These procedures are available upon request.

2 Exhibit J L-05-080 PY-CEI/NRR-2880L Page 1 SCHEDULE A The following is a list of nuclear power plants owned in whole by FirstEnergy Nuclear Generation Corp.:

Beaver Valley Power Station, Unit No. 1 Beaver Valley Power Station, Unit No. 2 Perry Nuclear Power Plant, Unit No. 1 The Funds for these units are identified as follows:

FirstEnergy Nuclear Generation Corp. BVPS 1 Qualified Fund FirstEnergy Nuclear Generation Corp. BVPS 2 Qualified Fund FirstEnergy Nuclear Generation Corp. Perry Qualified Fund FirstEnergy Nuclear Generation Corp. BVPS 1 Nonqualified Fund FirstEnergy Nuclear Generation Corp. BVPS 2 Nonqualified Fund FirstEnergy Nuclear Generation Corp. Perry Nonqualified Fund 1

Enclosure I Exhibit J L-05-080 PY-CEIINRR-2880L Page 1 SCHEDULE B Prior Agreement:

1.

Pennsylvania Power Company Master Decommissioning Trust-Beaver Valley No. 1, Beaver Valley No. 2, and Perry No. 1, dated as of April 21, 1995, as amended by Amendment # 1, dated December 2, 1999, as amended by Amendment # 2, dated December 9, 2003 1

Exhibit K L-05-080 PY-CEI/NRR-2880L Page 1 EXHIBIT K DECOMMISSIONING FUNDING WORKSHEET Calculation of Minimum Financial Assurance Amount for December 2004 BEAVER VALLEY POWER STATION, UNIT NO. 1 Pennsylvania Regions Labor (L) = Northeast Energy (E) = National Waste Burial (B) = South Carolina For PWR Unit Adjustment Escalation Factor Ratio Factor L =

2.070 0.65 1.346 E =

1.434 0.13 0.186 B =

9.467 0.22 2.083 PWR Escalation Factor=

3.615 Base Amount for PWR between 1200 MWt and 3400 MWt = ($75m + 0.0088P)

(P = power level in megawatts thermal = 2,689)

($75 + 0.0088(2,689)) million =

$98,663,200 Escalated Amount for unit = 98,663,200 x 3.615

=

$356,667,468 Escalated Amount for Penn Power Company's ownership interest (65%) in the unit:

$356,667,468 x

65.0%

=

$231,833,854 at December 2004 1

Exhibit K L-05-080 PY-CEI/NRR-2880L Page 2 EXHIBIT K DECOMMISSIONING FUNDING WORKSHEET Calculation of Minimum Financial Assurance Amount for December 2004 BEAVER VALLEY POWER STATION, UNIT NO. 2 Pennsylvania Regions Labor (L) = Northeast Energy (E) = National Waste Burial (B) = South Carolina For PWR Unit Adjustment Factor 2.070 1.434 9.467 Escalation Ratio Factor 0.65 1.346 0.13 0.186 0.22 2.083 PWR Escalation Factor =

Base Amount for PWR between 1200 MWt and 3400 MWt = ($75i (P = power level in megawatts thermal = 2,689)

($75 + 0.0088(2,689)) million =

Escalated Amount for Unit = 98,663,200 x 3.615 Escalated Amount for Pennsylvania Power Company's ownership interest (13.74% in the unit)

$356,667,468 x

13.74%

=

$49,006,105 3.615 m + 0.0088P)

$98,663,200

$356,667,468

) at December 2004 1

Exhibit K L-05-080 PY-CEI/NRR-2880L Page 3 EXHIBIT K DECOMMISSIONING FUNDING WORKSHEET Calculation of Minimum Financial Assurance Amount for December 2004 PERRY NUCLEAR POWER PLANT, UNIT NO. 1 Ohio Regions Labor (L) = Midwest Energy (E) = National Waste Burial (B) = South Carolina For BWR Unit Adjustment Factor 2.000 1.448 8.860 Ratio 0.65 0.13 0.22 Escalation Factor 1.3 0.188 1.949 3.437 135,000,000 463,995,000.00 BWR Escalation Factor =

Base Amount for BWR greater than 3400 MWt =

Escalated Amount for unit = 135,000,000 x 3.437 Escalated Amount for Penn Power Company's ownership interest (5.24%) in the unit:

$463,995,000 x 5.24%

=

$24,313,338 at December 2004 1

Exhibit L L-05-080 PY-CEI/NRR-2880L Page 1 EXHIBIT L NRC Financial Test for Parent Guarantees (10 CFR Part 30, App. A, § II.A.2)

(All amounts in $ millions)

Financial Test II.A.2 Source: 1999Annual Report (i) A current rating for its most recent bond issuance of AAA, AA, A, or BBB as issued by Standard and Poor's or AAA, AA, A, or BAA as issued by Moody's; and FirstEnergy Corp. Standard & Poor's Corporate Credit Rating (December 31, 2004)

FirstEnergy Corp. Moody's Corporate Credit Rating (December 31, 2004)

BBB-Baa3 (ii) Tangible net worth each at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof (Tangible net worth shall be calculated to exclude the net book value of the nuclear unit(s)); and Tangible Net Worth

$3,173 Amount of Decommissioning Funds Assured for BVPS I & 2 and Perry (Guarantee

$80 Amount)

Ratio of Tangible Net Worth to Guarantee Amount 39.66 (iii) Tangible net worth of at least $10 million; and ITangible Net Worth l

$3,173 (iv) Assets located in the United States amounting to at least 90 percent of the total assets or at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof.

ITotal Assets l

$31,068 I

ITotal Foreign Assets I

$0 d Total U.S. Assets

$31,068 lAmount of Decommissioning Funds Assured for BVPS I & 2 and Perry (Guarantee F

$80 lAmount) l l

lRatio of U.S. Assets to Guarantee Amount l

388.35 Exhibit M L-05-080 PY-CEI/NRR-2880L Page 1 EXHIBIT M Form of Parent Guaranty GUARANTY GUARANTY, dated as of F

, 2005], made by FirstEnergy Corp., a Ohio corporation (the "Guarantor") to the U.S. Nuclear Regulatory Commission (the "NRC") on behalf of Guarantor's subsidiary, FirstEnergy Nuclear Generation Corp. ("Licensee"). Except as otherwise defined herein, terms used herein and defined in the Purchase and Sale Agreement (as hereinafter defined) shall be used herein as so defined.

WITNESS ETH:

WHEREAS, Pennsylvania Power Company ("Penn Power") has agreed to transfer its undivided ownership interests in Beaver Valley Power Station, Units I & 2 and the Perry Nuclear Power Plant ("BVPS 1 & 2 and Perry") to the Licensee (the "Acquired Assets");

WHEREAS, the Licensee is an indirect wholly-owned subsidiary of the Guarantor; WHEREAS, the NRC has promulgated regulations in Title 10, Chapter 1 of the Code of Federal Regulations ("CFR"), Part 50 which requires that a holder of, or an applicant for, a license issued pursuant to 10 CFR Part 50 provide assurance that funds will be available when needed for required decommissioning activities.

WHEREAS, Penn Power will transfer approximately $140 million to qualified and non-qualified decommissioning trust funds established and maintained by Licensee for BVPS 1 & 2 and Perry; WHEREAS, it is estimated that a total of approximately $220 million in decommissioning funding assurance is necessary to meet the Licensee's pro rata share of the NRC decommissioning funding requirements for BVPS 1 & 2 and Perry, and therefore that approximately $80 million in decommissioning funding assurance in addition to the amounts held in the qualified and non-qualified funds is necessary; and WHEREAS, the Guarantor expects to receive substantial indirect benefits from the acquisition of the Acquired Assets by the Licensee (which benefits are hereby acknowledged),

and accordingly, desires to execute and deliver this Guaranty in order to provide financial assurance for licensee's pro rata share of decommissioning activities for BVPS 1 & 2 and Perry as required by 10 CFR Part 50; NOW, THEREFORE, in consideration of the foregoing and other benefits accruing to the Guarantor, the receipt and sufficiency of which are hereby acknowledged, the Guarantor hereby Exhibit M L-05-080 PY-CEI/NRR-2880L Page 2 makes the following representations and warranties to the NRC and hereby covenants and agrees as follows:

1.

The Guarantor guarantees to the NRC that if the Licensee fails to perform the required decommissioning activities, as defined by the NRC regulations at 10 CFR 50.2 and as required by NRC License No. DPR-21 for BVPS 1 & 2 and Perry, the Guarantor shall (a) carry out the required activities, or (b) set up a trust fund for the benefit of the NRC in the amount of

$80 million (in year 2005 dollars) (the "Guaranteed Obligation"). In addition, Guarantor hereby agrees to pay any and all costs and expenses (including fees and disbursements of counsel) incurred by the NRC in enforcing any rights under this Guaranty.

2.

Guarantor's obligation pursuant to this Guaranty is an unconditional guaranty of payment and not of collectibility. This Guaranty shall remain in full force and effect until the date on which it is no longer required to comply with the applicable financial assurance requirements of 10 CFR Part 50 for the Acquired Assets, or until otherwise earlier terminated in accordance with the provisions of Section 6 below or extinguished by the NRC. No delay or omission by the NRC to exercise any right under this Guaranty shall impair any right, nor shall it be construed to be a waiver thereof. No waiver of any single breach or default under this Guaranty shall be deemed a waiver of any other breach or default.

3.

Except for termination or cancellation of this Guaranty under Section 6 or action by the NRC extinguishing Guarantor's obligations under this Guaranty, the obligations and liability of the Guarantor under this Guaranty shall be absolute, unconditional and shall remain in full force and effect without regard to, and shall not be released, suspended, discharged, terminated or otherwise affected by, any circumstance or occurrence whatsoever, including, without limitation: (a) any change in time, manner or place of payment of, or in any other term of, the Guaranteed Obligation; (b) any change in ownership of Guarantor or Licensee; (c) any bankruptcy, insolvency, or reorganization of, or other similar proceedings involving Guarantor or Licensee; (d) any other circumstances which might otherwise constitute a legal or equitable discharge of a surety or guarantor; or (e) any amendment or modification of the BVPS 1 & 2 and Perry license or the NRC-approved decommissioning funding plan for the BVPS 1 & 2 and Perry, the extension or reduction of the time of performance of required activities, or any other modification or alteration of an obligation of the licensee pursuant to 10 CFR Part 50; provided that, except for the matters set forth in (a)-(e) above, the Guarantor shall be entitled to assert and claim the benefit of any defense, offset or counterclaim which the Licensee may have in law or equity to the payment or performance of the Guaranteed Obligation, as a defense, offset or counterclaim to its obligations under this Guaranty.

4.

Guarantor, hereby irrevocably, unconditionally and expressly waives, to the fullest extent permitted by applicable law, promptness, diligence, notice of acceptance and other notice with respect to the Guaranteed Obligation and this Guaranty and any requirement that the NRC protect, secure or perfect any security interest or exhaust any right or first proceed against Licensee or any other person or entity. Likewise, Guarantor expressly waives notice of acceptance of this Guaranty by the NRC and of any amendments or modification of the decommissioning requirements or the license.

Exhibit M L-05-080 PY-CEIINRR-2880L Page 3

5.

This Guaranty shall be binding upon Guarantor and its successors and permitted assigns and inure to the benefit of and be enforceable by the NRC and its successors and permitted assigns.

6.

This Guaranty shall terminate and be of no further force and effect upon the date on which the Licensee no longer is required to comply with the applicable financial assurance requirements of 10 CFR Part 50 for the Acquired Assets; provided, however, that the Guarantor may terminate this Guaranty by sending notice by certified mail to the NRC and the Licensee, such cancellation to become effective no earlier than 120 days after receipt of such notice by both the NRC and the Licensee. If at the time of cancellation the qualified and nonqualified decommissioning funds maintained by Licensee for BVPS 1 & 2 and Perry are insufficient to meet NRC requirements and the Licensee fails to provide alternative financial assurance within 90 days of Guarantor's notice of cancellation, the Guarantor will (a) provide such alternate financial assurance in the name of the Licensee, (b) make full payment under the Guaranty, or (c) restore the Guaranty.

7.

Annually within 90 days of the close of Guarantor's fiscal year, Guarantor will submit to the NRC its financial statements for such fiscal year, a current estimate of the decommissioning funding assurance required for BVPS 1 & 2 and Perry and any corresponding adjustment to this guarantee, and a statement showing compliance with the NRC's financial tests for parent guarantees in 10 CFR Part 30. If at the end of any fiscal year before termination of this guarantee, Guarantor fails to meet such financial test criteria, the Licensee and Guarantor will submit notice to the NRC within 90 days by certified mail that Licensee intends to provide alternative financial assurance as specified in 10 CFR Part 50. If Licensee fails to provide such alternative financial assurance within 30 days after such notice, the Guarantor shall provide the alternative financial assurance in the name of the Licensee.

8.

If at any time the NRC notifies Licensee and Guarantor of a determination by the NRC that Guarantor no longer meets the financial test criteria in 10 CFR Part 30, Appendix A, Licensee will within 30 days of such notice provide alternative financial assurance in accordance with the applicable requirements in 10 CFR Part 50. If Licensee fails to provide such alternative financial assurance, Guarantor will provide such assurance in Licensee's name.

9.

The Guarantor further represents, warrants and agrees that:

(a)

The Guarantor (i) is a duly organized and validly existing corporation in good standing under the laws of the State of Ohio, (ii) has the power and authority to own its property and assets and to transact the business in which it is engaged and (iii) is duly qualified as a foreign corporation and in good standing in each jurisdiction where the ownership, leasing or operation of property or the conduct of its business requires such qualification.

(b)

The Guarantor has the corporate power to execute, deliver and perform the terms and provisions of this Guaranty and has taken all necessary corporate action to authorize the execution, delivery and performance by it of this Exhibit M L-05-080 PY-CEIINRR-2880L Page 4 Guaranty. The Guarantor has duly executed and delivered this Guaranty, and this Guaranty constitutes its legal, valid and binding obligation enforceable in accordance with its terms.

(c)

Neither the execution, delivery or performance by the Guarantor of this Guaranty, nor compliance by it with the terms and provisions hereof, (i) will contravene any provision of any law, statute, rule or regulation or any order, writ, injunction or decree of any court or governmental instrumentality, (ii) will conflict or be inconsistent with or result in any breach of any of the terms, covenants, conditions or provisions of, or constitute a default under, or result in the creation or imposition of (or the obligation to create or impose) any lien upon any of the property or assets of the Guarantor or any of its subsidiaries pursuant to the terms of any indenture, mortgage, deed of trust, credit agreement, loan agreement or any other agreement, contract or instrument to which the Guarantor or any of its subsidiaries is a party or by which it or any of its property or assets is bound or to which it may be subject or (iii) will violate any provision of the certificate of incorporation or by-laws of the Guarantor or any of its subsidiaries.

(d)

No order, consent, approval, license, authorization or validation of, or filing, recording or registration with (except as have been obtained previously),

or exemption by, any governmental or public body or authority, or any subdivision thereof (except as have been previously obtained), is required to authorize, or is required in connection with, (i) the execution, delivery and performance of this Guaranty or (ii) the legality, validity, binding effect or enforceability of this Guaranty.

(e)

Neither the Guarantor nor any of its subsidiaries is an "investment company" within the meaning of the Investment Company Act of 1940, as amended.

(f)

The Licensee is an indirect, wholly-owned subsidiary of Guarantor, and Guarantor has through its wholly-owned subsidiaries majority control of the voting stock of the Licensee.

(g)

The Guarantor meets or exceeds the financial test criteria in 10 CFR Part 30, Appendix B, section II.A.2.

10.

This Guaranty and the rights and obligations of the NRC and the Guarantor hereunder, shall be governed by and construed in accordance with the domestic laws of the Ohio without giving effect to any choice or conflict-of-law provision or rule (whether of Ohio or any other jurisdiction) that would cause the application of the laws of any jurisdiction other than Ohio. The Guarantor and the NRC each consent to the exclusive jurisdiction and venue of any state or federal court within the Ohio for adjudication of any suit, claim, action or other proceeding at law or in equity relating to this Guaranty, or to any transaction contemplated hereby. The Guarantor and the NRC each accept, generally and unconditionally, the exclusive Exhibit M L-05-080 PY-CELINRR-2880L Page 5 jurisdiction and venue of the aforesaid courts and waive any objection as to venue, and any defense offonum non conveniens. The Guarantor hereby irrevocably designates, appoints and empowers [

], with offices on the date hereof at [

1, as its designee, appointee and agent to receive, accept and acknowledge for and on its behalf, and in respect of its property, service of any and all legal process, summons, notices and documents which may be served in any such action or proceeding. If for any reason such designee, appointee and agent shall cease to be available to act as such, the Guarantor agrees to designate a new designee, appointee and agent in Ohio on the terms and for the purposes of this provision satisfactory to the NRC. The Guarantor further irrevocably consents to the service of process out of any of the aforementioned courts in any such action or proceeding by the mailing of copies thereof by registered or certified mail, postage prepaid, to the Guarantor at its address set forth opposite its signature below, such service to become effective 30 days after such mailing.

Nothing herein shall affect the right of the NRC to serve process in any other manner permitted by law or to commence legal proceedings or otherwise proceed against the Guarantor in any other jurisdiction. The Guarantor hereby irrevocably waives any objection which it may now or hereafter have to the laying of venue of any of the aforesaid actions or proceedings arising out of or in connection with the Guaranty brought in the courts referred to above and hereby further irrevocably waives and agrees not to plead or claim in any such court that any such action or proceeding brought in any such court has been brought in an inconvenient forum.

11.

All notices and other communications hereunder shall be made at the addresses of the NRC and the Guarantor specified opposite their signatures below.

IN WITNESS WHEREOF, the Guarantor has caused this Guaranty to be executed and delivered as of the date first above written.

Address FirstEnergy Corp.

Attention: _

By

Title:

L-05-080 PY-CEI/NRR-2880L Page 1 Regulatory Commitments The following list identifies those actions committed to by the FirstEnergy Nuclear Operating Company (FENOC) for the Beaver Valley Power Station, Unit Nos. 1 & 2 and Perry Nuclear Power Plant, Unit No. 1 in this document. Any other actions discussed in the submittal represent intended or planned actions by FENOC. They are described only as information and are not regulatory commitments. Please notify Mr. Gregory H. Halnon, FENOC Director, Regulatory Affairs at (330) 315-7500 of any questions regarding this document or associated regulatory commitments.

Commitment Due Date

1. A form of Power Supply Agreement between FENGenCo and FE Solutions will be submitted to NRC or made available for inspection upon request.

2. FENOC will provide the names and business addresses of the directors and principal officers of FENGenCo all of whom will be U.S. citizens, once those individuals are identified.

3. FENOC will inform the NRC of any significant changes in the status of any other required approvals or any other developments that have an impact on the schedule.

4. Prior to the license transfer FENOC will provide proof that FENGenCo will have all required nuclear property damage insurance pursuant to 10 CFR 50.54(w) and nuclear energy liability insurance pursuant to Section 170 of the AEA and 10 CFR Part 140.

5. FENGenCo will assume the licenses to possess Pennsylvania Power's existing undivided ownership interests in BVPS and Perry consistent with the commitments made within this application.

October 1, 2005 October 1, 2005 December 31, 2006 December 31, 2006 December 31, 2006