L-05-067, Letter Transmitting Firstenergy Corp. 2004 Annual Report

Letter Transmitting Firstenergy Corp. 2004 Annual Report

ML051090392
Person / Time
Site:	Beaver Valley, Davis Besse, Perry
Issue date:	04/08/2005
From:	Scilla R FirstEnergy Corp
To:	Dinitz I Office of Nuclear Reactor Regulation
References
-RFPFR, BV-No. L-05-067, DB-Serial No.-3146, PY-CEI/NRR-2876L
Download: ML051090392 (77)

Text

RrstEnergy, 76 South Main Steet Akron, Ohio 44308-1890 Randy Scilla 330-384-5202 Assistant Treasurer Fax: 330-364-3772 April 8, 2005 PY-CEI/NRR-2876L DB-Serial No.-3146 BV-No. L-05-067 Mr. Ira Dinitz U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Washington, D.C. 20555 Dear Mr. Dinitz; Re: Docket Nos. 50-346, 50-440, 50-412, 50-334 Retrospective Premium Guarantee Enclosed you will find the 2004 FirstEnergy Corp. Annual Report. This is in addition to the 2005 Internal Cash Flow Projection sent March 8, 2005 and completes the requirements for the Retrospective Premium Guarantee.

Very truly yours, adp Enclosures

FirstEnergy

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Financial Highlights (Dollars in thousands, except per share amounts) 2004 2003 Total revenues $12,453,046 $11,674,888 Income before discontinued operations and cumulative effect of accounting change' $873,779 $424,249 Net income $878,175 $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 $2.68 $1.39 Diluted earnings per common share:

Before discontinued operations and cumulative effect of accounting change $2.66 $1.40 After discontinued operations and cumulative effect of accounting change $2.67 $1.39 Dividends declared per common share` S1.9125 $1.50 Book value per common share $26.20 $25.35 Net cash from operations $1,876,850 $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 $0.4125 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 GMP)*.

2004 2003 Adjusted basic earnings per share:

Basic earnings per share (GAAP) $2.68 $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, anon-GAAP financial measure is a numerical measure of a company's historical or future financial performance, financial position, 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

• I accordance with GAAR Forward-Looking Statements

• This annual report includes forwardjooking 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, Southern 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, 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 inparticular, 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 inthe 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 aRate Stabilization Plan inOhio, the risks and other factors discussed from time to time inour Securities and Exchange Commission filings, and other similar factors. We expressly disclaim any current intention to update any forward4ooking statements contained herein as a result of new information, future events, or otherwise.

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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 W e made significant progress in 2004. reliability, last year we spent $940 million on capital improve-We positioned ourselves for continued ment projects and operating and maintenance activities in success in the years ahead and placed our energy delivery area. In2005, we expect to spend more many of the challenges of the past several years behind us. than $1 billion, including expenditures on a wide range of Our key accomplishments included: system enhancements. Our plans include upgrading and

• Returning the Davis-Besse Nuclear Power Station renewing our transmission and distribution facilities, improving to safe and reliable operation relaying and protection to minimize service interruptions,

• Enhancing the reliability of our service to customers installing remote control and automation to ensure timely

• Achieving record performance by our restoration when service interruptions occur, and adding new generation fleet technologies such as advance lightning detection, which

• Gaining approval for our Rate Stabilization enables our system to better protect itself. We are investing Plan in Ohio in our critical infrastructure with the clear goal of strengthening our reliability and improving customer service.

Our financial performance in 2004 was strong, Inanother effort to improve service reliability, we particularly in the key areas of earnings, cash flow and modified our existing information technologies to develop a debt reduction. We delivered basic earnings per share of leading-edge capability to track outage history down to the

$2.91 on a non-GAAP* basis, exceeding our guidance to individual customer. Scheduled for full implementation in June the financial community of $2.70 to $2.85. Net cash from 2005, this system can pinpoint locations and causes of prob-operating activities also remained strong at $1.88 billion -

lems, enabling us to target our investments in improvements up from $1.75 billion in 2003 - and we met our target to that enhance reliability and customer satisfaction.

reduce debt by $1 billion.

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Our storm restoration process proved its effectiveness 18 billion KWH, topping its previous record by more than in response to a major storm event in May of 2004, as well 2 billion KWH. Its 88.9 percent capacity factor - the actual as during two ice storms this past winter. All three events amount of electricity generated compared with the amount caused interruptions to hundreds of thousands of customers. that could be generated at full power for the year - placed Despite severe damage to our system, we restored service its performance in the industry's top decile. Inthe fall of to all customers faster than at any time in our history, with 2005, we expect to initiate the plant's first capacity expan-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 />. sion program with a planned upgrade of Unit 1's turbine, Inaddition to the storm process work at home, some which should increase its output by about 50 MW. Similar 400 volunteer employees traveled to Florida and Alabama upgrades are planned for units 2 and 3 in coming years, to assist in restoring service in the aftermath of the multi- which would enable the plant to produce an additional ple hurricanes that ravaged those areas in 2004. Along 1 billion KWH annually.

with the hundreds of letters of thanks we received from Turning to our nuclear fleet, we completed a major reor-grateful residents, we are proud that the hard work and ganization of our FirstEnergy Nuclear Operating Company dedication of our employees were further recognized by (FENOC) subsidiary that added experienced nuclear man-EEI, which named FirstEnergy a recipient of the EEI agers and centralized managerial oversight of our nuclear Emergency Assistance Award. units; established a uniform organizational structure within the plants; and began implementing common procedures "Our financial performance and practices across the fleet. The capacity factor of our nuclear fleet reached 90.6 percent, a historic high, even in 2004 was strong, with Davis-Besse's return to service in March. Beaver Valley particularly in the key earned a Performance Improvement Award from the Institute of Nuclear Power Operations, and its Unit 2 has operated areas of earnings, cash for more than 500 consecutive days, establishing a plant flow and debt reduction." 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 Another highlight of 2004 was the performance of Perry Plant, where employees have worked 8.9 million hours our generation fleet, which produced a record 76 billion without a lost-time accident.

kilowatt-hours (KWH). The fossil generation fleet provided In2004 and early 2005, we also reached multi-year solid performance, producing more than 45 billion KWH, labor agreements with 8 union locals representing more while our nuclear fleet produced a record 29.9 billion KWH. than 3,250 workers. Employees represented by these

Our largest coal-based generating facility, the 2,360- unions have joined our new health care plan, providing megawatt (MW) Bruce Mansfield Plant, led the way for our them with competitive benefits while enabling the Company fossil fleet. The plant set a generation record of more than to better manage the increasing costs of health care.

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We accomplished these solid results while maintaining agreement, we will install additional environmental controls at our focus on safety. In2004, we achieved a Company-wide Sammis, as well as at a number of our other power plants.

OSHA rate of 1.44 incidents per 100 employees, a 9-percent For example, in the fall of 2005, we will begin a three-year reduction compared with 2003 results. This performance project to improve the existing scrubbers at the Mansfield typically would rank us in the top decile of our industry, Plant as part of our plans to further reduce S02 emissions.

although EEI has not yet published results for 2004. The new environmental controls also will provide the We expect to continue enhancing our operational foundation for achieving the emission reductions we will be performance under the leadership of our Executive Vice making to comply with the U.S. Environmental Protection President and Chief Operating Officer, Richard R. Grigg, who Agency's recently announced Clean Air Interstate and joined the Company in August. With 34 years of industry Clean Air Mercury rules.

experience, most recently as president and chief executive We're working on the development of cost-effective, officer of WE Generation, Mr. Grigg leads our Energy Delivery, new technologies to help achieve these additional Fossil Generation and Commodity Operations business units. reductions. One promising new technology is the TM Electro-Catalytic Oxidation' (ECO) system developed by Protecting the Environment Powerspan Corp. and currently being demonstrated at our We also delivered strong results in our efforts to protect R. E. Burger Plant. This technology is designed to reduce the environment. Last year, 40 percent of our electricity was NOx, SO2, fine particulates and mercury emissions, and, if produced from our non-emitting nuclear fleet. We also achieved successful, will be available for commercial application at continuing emission reductions from our coal-based plants. coal-based power plants across the country.

Since 1990, we've reduced nitrogen oxides (NOx) by more than 60 percent and sulfur dioxide (S02) by nearly one-half. Setting the Stage for the Future Inthe past three years, we've spent $196 million to install As a result of our successful efforts to reduce debt, selective catalytic reduction equipment on all three units of our control costs and enhance cash flow, your Board declared scrubber-equipped Bruce Mansfield Plant. This equipment is a new quarterly dividend of 41.25 cents per share of out-designed to reduce NOx emissions, a precursor to ozone, standing common stock, which represents a 10-percent by more than 8,000 tons during the summer ozone season. increase over the previous quarterly rate. The new indicated And, in March of this year, we announced plans to annual dividend is $1.65 per share, up from $1.50 per share.

significantly reduce emissions of NOx and S02 from current Your Board also adopted a dividend policy that targets levels at several of our power plants as part of a settlement sustainable annual dividend increases after 2005, generally agreement that resolves all issues related to the New Source reflecting an annual growth rate of 4 to 5 percent, and an Review case involving our W.H. Sammis Plant. Under the earnings payout ratio generally within the range of 50 to 60 percent. The Board will continue to review FirstEnergy's "Last year, 40 percent dividend policy regularly. The amount and timing of all dividend payments are subject to the Board's consideration of our electricity was of business conditons, results of operations, financial produced from our condition and other factors.

We also enhanced the value of your investment by non-emitting nuclear fleet." 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.

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"We expect to fill Preparing for Our Workforce of the Future approximately 1,600 We're also addressing a significant issue facing compa-positions system-wide nies throughout the U.S. - the need to replace experienced employees who will retire over the next several years. We in the next two years..." 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 The $1 billion in debt we eliminated brings the total to recruit talented and highly motivated people from outside

$3 billion since 2002, reducing our adjusted debt-to-capital-our Company who will help ensure our future success.

ization ratio to 57 percent from 65 percent three years The hiring will occur across the Company, including ago. At the same time, we were able to resolve funding generating plant and utility workers, as well as an array issues related to our pension program for the next several of technical and professional positions.

years by making a $500-million contribution to the plan Our business requires considerable skills and continu-in September. Even so, the total capacity of our primary ous attention to safety by our employees. We will work to credit facilities stood at $2.3 billion at year-end.

ensure that new employees receive on-thejob training, as Another significant accomplishment in 2004 - for our well as ongoing mentoring from the experienced and knowl-customers and for your Company - was gaining approval edgeable employees we're fortunate to have on staff now.

by the Public Utilities Commission of Ohio (PUCO) of our Rate Stabilization Plan. The plan will provide a longer Building on Our Progress period of predictable revenue from our three Ohio electric Executing our plan was critical to our progress in 2004, utility operating companies. In addition, it will provide and will serve as a solid foundation for future growth.

customers with more stable generation prices for three Certainly, challenges remain. However, I'm confident that, years following the end of Ohio's market development through the hard work of our skilled and dedicated employees period on December 31, 2005, under the state's electricity and your continued support, we will build on that progress deregulation law. An independent auction conducted last and enhance the long-term value of your investment.

fall at the direction of the PUCO confirmed that the price we offered under the plan was competitive.

Sincerely, 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 Anthony J. Alexander financial restatements related to changed accounting treat-President and Chief Executive Officer ments for transition assets being recovered in Ohio. Four March 18, 2005 customer damage cases related to the regional power outage remain in various venues in Ohio and New York.

' This letter to shareholders contains non-GAP earnings per share. This non-GMP measure excludes amounts that are not normally excluded in the most directly com-parable measure calculated and presented inaccordance with accounting principles generally accepted in the United States (GAAP). A reconciliation of GAAP basic earnings per share ($2.68 in 2004) to nonGWP basic earnings per share ($3.03 in 2004, before the reduction of $0.12 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.

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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-Paul I. Addison Anthony J.Alexander 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- Paul J. Powers Catherine A.Rein 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. Paul T. Addison, 58 We also elected to eliminate the Shareholder Rights Plan - a move Retired, formerly Managing Director in that a majority of our shareholders supported - and we agreed to put the Utilities Department of Salomon any future plan to a shareholder vote within one year of adoption.

Smith Barney (Citigroup). Member, These and other actions have helped make your Company a leader in an important corporate governance measurement devel- Audit and Finance Committees. Director oped by Institutional Shareholder Services (ISS) - the Corporate of FirstEnergy Corp. since 2003.

Governance Quotient (CGQ). At year-end, our CGQ index ranking was 96.9, reflecting the percentage of companies in the S&P 500 Index Anthony J. Alexander, 53 we outperformed. Our industry ranking of 95.7 reflected our per- President and Chief Executive Officer formance against companies in ISS's utility group. of FirstEnergy Corp. Director of In addition, we were pleased to raise your Company's common-FirstEnergy Corp. since 2002.

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. Dr. Carol A. Cartwright, 63 On a more personal note, I join the Board in expressing our President, Kent State University.

appreciation to recently retired Director John M. Pietruski for his Chair, Corporate Govemance Committee; many years of service to GPU, Inc., and FirstEnergy. Also, we welcome Member, Compensation Committee.

Ernest J. Novak, Jr., who was elected to the Board in May, and Director of FirstEnergy Corp. since 1997 Wesley M. Taylor, who was elected in September. Mr. Novak, retired and of Ohio Edison from 1992-1997.

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 William T. Cottle, 59 best interests of our shareholders, and we appreciate your continued Retired, formerly Chairman of the support as we consider new ways to enhance the value of your Board, President and Chief Executive investment in FirstEnergy. Officer of STP Nuclear Operating Company. Chair, Nuclear Committee; Sincerely, Member, Corporate Governance Cz r Committee. Director of FirstEnergy Corp.

since 2003.

George M. Smart Chairman of the Board 6

Dr.Carol A. Cartwright William T.Cottle Russell W.Maier Emest J. No~vak, Jr. Robert N.Pokelwalrdt Robert C.Savage George M.Smart Wesley M.Taylor Jesse 1 Williams, Sr. Dr.Patricia K.Woolf Russell W. Maier, 68 Compensation Committee. Director Wesley M. Taylor, 62 President and Chief Executive Officer of FirstEnergy Corp. since 1997 Retired, formerly President of TXU of Michigan Seamless Tube LLC. and of Ohio Edison from 1992-1997. Generation. Member, Nuclear Member, Compensation and Nuclear Committee. Director of FirstEnergy Committees. Director of FirstEnergy Catherine A. Rein, 62 Corp. since 2004.

Corp. since 1997 and of Ohio Edison Senior Executive Vice President from 1995-1997. and Chief Administrative Officer of Jesse T. Williams, Sr., 65 Metropolitan Life Insurance Company. Retired, formerly Vice President Ernest J. Novak, Jr., 60 Chair, Compensation Committee; of Human Resources Policy, Retired, formerly Managing Partner of Member, Audit Committee. Director Employment Practices and Systems of the Cleveland office of Ernst & Young of FirstEnergy Corp. since 2001 and The Goodyear Tire & Rubber Company.

LLP. Member, Audit and Finance of the former GPU, Inc., from Member, Corporate Governance and Committees. Director of FirstEnergy 1989-2001. Nuclear Committees. Director of Corp. since 2004. FirstEnergy Corp. since 1997 and Robert C. Savage, 67 of Ohio Edison from 1992-1997.

Robert N. Pokelwaldt, 68 Chairman of the Board of Savage Retired, formerly Chairman of the & Associates, Inc. Member, Finance Dr. Patricia K. Woolf, 70 Board and Chief Executive Officer of and Nuclear Committees. Director Consultant, author, and former Lecturer YORK International Corporation. of FirstEnergy Corp. since 1997 in the Department of Molecular Biology Member, Audit and Finance and of the former Centerior Energy at Princeton University. Member, Committees. Director of FirstEnergy Corporation from 1990-1997. Corporate Governance and Nuclear Corp. since 2001 and of the former Committees. Director of FirstEnergy GPU, Inc., from 2000-2001. George M. Smart, 59 Corp. since 2001 and of the former Non-executive Chairman of the GPU, Inc., from 1983-2001.

Paul J. Powers, 70 FirstEnergy Board of Directors.

Retired, formerly Chairman of the Retired, formerly President of Board and Chief Executive Officer Sonoco-Phoenix, Inc. Chair, Audit of Commercial Intertech Corp. Chair, Committee. Director of FirstEnergy Finance Committee; Member, Corp. since 1997 and of Ohio Edison from 1988-1997.

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FirstEnergy Officers FirstEnergy Corp.

Anthony J. Alexander Leila L. Vespoli* Thomas C. Navin* Jacqueline S. Cooper* ' Also holds the same title President and Senior Vice President Treasurer Assistant Corporate with FirstEnergy Service Chief Executive Officer and General Counsel Secretary Company, FirstEnergy Paulette R. Chatman* Solutions Corp. and Richard R. Grigg Harvey L. Wagner Assistant Controller Edward J. Udovich* FirstEnergy Nuclear Executive Vice President Vice President, Controller Jeffrey R. Kalata* Assistant Corporate Operating Company and Chief Operating and Chief Accounting Assistant Controller Secretary Officer Officer Randy Scilla*

Richard H. Marsh* David W. Whitehead Assistant Treasurer Senior Vice President Corporate Secretary and Chief Financial Officer FirstEnergy Service Company Anthony J. Alexander Charles E. Jones Mary Beth Carroll Bradley S. Ewing Bradford F.Tobin President and Senior Vice President Vice President Vice President Vice President and Chief Executive Officer Lynn M. Cavalier Terrance G. Howson Chief Information Officer Kevin J. Keough Richard R. Grigg Senior Vice President Vice President Vice President Harvey L. Wagner Executive Vice President Carole B. Snyder Kathryn W. Dindo All Jamshidl Vice President and and Chief Operating Senior Vice President Vice President and Vice President Controller Officer Chief Risk Officer David W.Whitehead Thomas M. Welsh Mark A. Julian Mark T. Clark Senior Vice President Ralph J. DiNicola Vice President Vice President, Senior Vice President Vice President Corporate Secretary and David M. Blank David C. Luff Chief Ethics Officer Douglas S. Elliott Vice President Michael J. Dowling Vice President Senior Vice President Vice President and Chief Lisa S. Wilson Stanley F. Szwed Assistant Controller Procurement Officer Vice President 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 James M. Murray Donald M. Lynch Ronald P. Lantzy Regional President Regional President Regional President Regional President The Cleveland Electric The Toledo Edison Jersey Central Power Metropolitan Edison Illuminating Company Company & Light Company Company Thomas A. Clark Stephen E. Morgan Steven E. Strah John E. Paganle Regional President President Regional President Regional President Ohio Edison Company Jersey Central Power Jersey Central Power Pennsylvania Electric

& Light Company & Light Company 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 FIN FASB Interpretation facilities FIN 46R FIN 46 Irevised December 2003). 'Consolidation of Variable Interest Entities' Avon Avon Energy Partners Holdings FMB First Mortgage Bonds CEI The Cleveland Electric Illuminating Company, an Ohio electric utility FSP FASB Staff Position operating subsidiary FSP EITF 03-1-1 FASB Staff Position No. EITF Issue 03-1-1. 'Effective Date of Paragraphs CFC Centerior Funding Corporation, a wholly owned finance subsidiary of CEI 10-20 of EITF Issue No. 03-1, The Meaning of Other-Than-Temporary Companies OE,CEI,TE.Penn, JCP&L, Met-Ed and Penelec Impairment and Its Application to Certain Investments' Emdersa Empresa Oistribuidora Electrica Regional SA. FSP 106-1 FASB Staff Position No.106-1, 'Accounting and Disclosure Requirements EUOC Electric Utility Operating Companies (OE. CEI.TE,Penn, JCP&L, Met-Ed, Related to the Medicare Prescription Drug. Improvement and Penelec, and ATSI) Modernization Act of 2003' FENOC FirstEnergy Nuclear Operating Company, operates nuclear generating FSP 106-2 FASB Staff Position No.106-2, 'Accounting and Disclosure Requirements facilities Related to the Medicare Prescription Drug. Improvement and FES FirstEnergy Solutions Corp., provides energy-related products and services Modernization Act of 2003' FESC FirstEnergy Service Company, provides legal, financial, and other FSP 109-1 FASB Staff Position No. 109-1, 'Application of FASB Statement No. 109, corporate support services Accounting for Income Taxes, to the Tax Deduction and Oualified FGCO FirstEnergy Generation Corp.. operates nonnuclear generating facilities Production Activities provided by the American Jobs Creation Act of 2004' FirstCom First Communications, LIC, provides local and long-distance telephone GAAP Accounting Principles Generally Accepted inthe United States service HVAC Heating, Ventilation and Air-conditioning FirstEnergy FirstEnergy Corp., a registered public utility holding company IRS Internal Revenue Service FSG FirstEnergy Facilities Services Group, LLC.the parent company of several ISO Independent System Operator heating, ventilation, air conditioning and energy management companies KWH Kilowatt-hours GLEP Great Lakes Energy Partners, LIC, an oil and natural gas exploration and LOC Letter of Credit production venture MACT Maximum Achievable Control Technologies GPU GPU. Inc.. former parent of JCP&L, Met-Ed and Penelec, which merged Medicare Act Medicare Prescription Drug. Improvement and Modernization Act of 2003 with FirstEnergy on November 7, 2001 MISO Midwest Independent System Transmission Operator, Inc.

GPU Capital GPU Capital, Inc.. owned and operated electric distribution systems in Moody's Moody's Investors Service foreign countries MTC Market Transition Charge GPU Power GPU Power, Inc.. owned and operated generation facilities in foreign MW Megawatts countries NAAOS National Ambient Air Ouality Standards JCP&L Jersey Central Power & Light Company. a New Jersey electric utility NERC North American Electric Reliability Council operating subsidiary NJBPU New Jersey Board of Public Utilities MARBEL MARBEL Energy Corporation, previously held FirstEnergy's interest in GLEP NOAC Northwest Ohio Aggregation Coalition Met-Ed Metropolitan Edison Company. a Pennsylvania electric utility operating NOV Notices of Violation subsidiary NOx Nitrogen Oxide MYR MYR Group, Inc., a utility infrastructure construction service company NRC Nuclear Regulatory Commission NED Northeast Ohio Natural Gas Corp., formerly a MARBEL subsidiary NUG Non-Utility Generation GE Ohio Edison Company, an Ohio electric utility operating subsidiary OCC Ohio Consumers' Counsel Ohio Companies CEI,OEand TE OCI Other Comprehensive Income Penelec Pennsylvania Electric Company, a Pennsylvania electric utility OPEB Other Post-Employment Benefits operating subsidiary PCAOB Public Company Accounting Oversight Board (United States)

Penn Pennsylvania Power Company, a Pennsylvania electric utility PJM PJM Interconnection L.LC.

operating subsidiary of OE PLR Provider of Last Resort PNBV PNBV Capital Trust, a special purpose entity created by OEin 1996 PPUC Pennsylvania Public Utility Commission Shippingport Shippingport Capital Trust, a special purpose entity created by CEIand PRP Potentially Responsible Party TE in 1997 PUCO Public Utilities Commission of Ohio TE The Toledo Edison Company, an Ohio electric utility operating PUHCA Public Utility Holding Company Act subsidiary RTC Regulatory Transition Charge TEBSA Termobarranquilla SA.. Empresa de Servicios Publicos S&P Standard & Poor's Ratings Service SBC Societal Benefits Charge The following abbreviations and acronyms are used to SEC United States Securities and Exchange Commission SFAS Statement of Financial Accounting Standards identify frequently used terms in this report: SFAS 71 SFAS No. 71, 'Accounting for the Effects of Certain Types of Regulation' SFAS B7 SFAS No. 87, 'Employers' Accounting for Pensions' AU Administrative Law Judge SFAS 101 SFAS No. 101, 'Accounting for Discontinuation of Application of SFAS 71' AOCL Accumulated Other Comprehensive Loss SFAS 106 SFAS No. 106, 'Employers' Accounting for Postretirement Benefits Other APB Accounting Principles Board Than Pensions' APB 25 APB Opinion No. 25. "Accounting for Stock Issued to Employees" SFAS 115 SFAS No. 115. 'Accounting for Certain Investments inDebt and Equity APB 29 APB Opinion No. 29. "Accounting for Nonmonetary Transactions" Securities' ARB 43 Accounting Research Bulletin No. 43. "Restatement and Revision of SFAS 123 SFAS No. 123. "Accounting for Stock-Based Compensation' Accounting Research Bulletins" SFAS 1231R)SFAS No. 123(R), 'Share-Based Payment' ARO Asset Retirement Obligation SFAS 131 SFAS No. 131, 'Disclosures about Segments of an Enterprise and ASLB Atomic Safety and Licensing Board Related Information' BGS Basic Generation Service SFAS 133 SFAS No. 133, 'Accounting for Derivative Instruments and Hedging CO2 Carbon Dioxide Activities' CTC Competitive Transition Charge SFAS 140 SFAS No. 140, 'Accounting for Transfers and Servicing of Financial ECAR East Central Area Reliability Coordination Agreement Assets and Extinguishment of Liabilities' EITF Emerging Issues Task Force SFAS 142 SFAS No. 142, 'Goodwill and Other Intangible Assets' EITF 03-1 EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its SFAS 143 SFAS No. 143, 'Accounting for Asset Retirement Obligations' Application to Certain Investments" SFAS 144 SFAS No. 144, 'Accounting for the Impairment or Disposal of Long-Lived EITF 03-16 EITFIssue No. 03-16, "Accounting for Investments in Limited Liability Assets' Companies" SFAS 150 SFAS No. 150, 'Accounting for Certain Financial Instruments with EITF 974 EITFIssue No. 97-4 'Deregulation of the Pricing of Electricity -Issues Characteristics of Both Liabilities and Equity' Related to the Application of FASB Statements No. 71 and 101' SFAS 151 SFAS No. 151, 'Inventory costs -an amendment of ARB No. 43, Chapter 4' EITF 99-19 EITF Issue No. 99-19. "Reporting Revenue Gross as a Principal versus S02 Sulfur Dioxide Net as an Agent" TBC Transition Bond Charge EPA Environmental Protection Agency TMI-1 Three Mile Island Unit 1 FASB Financial Accounting Standards Board TMI-2 Three Mile Island Unit 2 FERC Federal Energy Regulatory Commission VIE Variable Interest Entity FirstEnergy Corp. 2004 9

Management Reports Management's Responsibility for Financial Statements Management's Report on Internal Control The consolidated financial statements were prepared by Over Financial Reporting management who takes responsibility for their integrity and Management is responsible for establishing and main-objectivity. The statements were prepared in conformity taining adequate internal control over financial reporting as with accounting principles generally accepted in the United defined in Rule 13a-15(f) of the Securities Exchange Act of States and are consistent with other financial information 1934. Using the criteria set forth by the Committee of appearing elsewhere in this report. PricewaterhouseCoopers Sponsoring Organizations of the Treadway Commission in LLP, an independent registered public accounting firm, has Internal Control - Integrated Framework, management con-expressed an unqualified opinion on the Company's 2004 ducted an evaluation of the effectiveness of the Company's consolidated financial statements. internal control over financial reporting under the supervision FirstEnergy Corp.'s internal auditors, who are responsible of the chief executive officer and the chief financial officer.

to the Audit Committee of FirstEnergy's Board of Directors, Based on that evaluation, management concluded that the review the results and performance of operating units within Company's internal control over financial reporting was effec-the Company for adequacy, effectiveness and reliability of tive as of December 31, 2004. Management's assessment accounting and reporting systems, as well as managerial of the effectiveness of the Company's internal control over and operating controls. financial reporting, as of December 31, 2004, has been audit-FirstEnergy's Audit Committee consists of five inde- ed by PricewaterhouseCoopers LLP, an independent pendent directors whose duties include: consideration of the registered public accounting firm, as stated in their report adequacy of the internal controls of the Company and the which appears on page 11.

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.

10 FirstEnergy Corp. 2004

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 Internal control over financial reporting In our opinion, the accompanying Also, in our opinion, management's assessment, included in the accompany-consolidated balance sheets and the ing Management's Report on Internal Control Over Financial Reporting, that the related consolidated statements of Company maintained effective internal control over financial reporting as of income, capitalization, common stock- December 31, 2004 based on criteria established in Internal Control - Integrated holders' equity, preferred stock, cash Framework issued by the Committee of Sponsoring Organizations of the flows and taxes present fairly, in all Treadway Commission (COSO), is fairly stated, in all material respects, based material respects, the financial position on those criteria. Furthermore, in our opinion, the Company maintained, in all of FirstEnergy Corp. and its subsidiaries material respects, effective internal control over financial reporting as of at December 31, 2004 and 2003, and December 31, 2004, based on criteria established in Internal Control - Integrated the results of their operations and their Framework issued by the COSO. The Company's management is responsible cash flows for each of the three years for maintaining effective internal control over financial reporting and for its in the period ended December 31, 2004 assessment of the effectiveness of internal control over financial reporting. Our in conformity with accounting principles responsibility is to express opinions on management's assessment and on the generally accepted in the United States effectiveness of the Company's internal control over financial reporting based on of America. These financial statements our audit. We conducted our audit of internal control over financial reporting in are the responsibility of the Company's accordance with the standards of the Public Company Accounting Oversight management. Our responsibility is to Board (United States). Those standards require that we plan and perform the express an opinion on these financial audit to obtain reasonable assurance about whether effective internal control statements based on our audits. We over financial reporting was maintained in all material respects. An audit of inter-conducted our audits of these state- nal control over financial reporting includes obtaining an understanding of internal ments in accordance with the standards control over financial reporting, evaluating management's assessment, testing of the Public Company Accounting and evaluating the design and operating effectiveness of internal control, and Oversight Board (United States). Those performing such other procedures as we consider necessary in the circum-standards require that we plan and per- stances. We believe that our audit provides a reasonable basis for our opinions.

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

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

discussed in Note 7 to the consolidated financial statements, the Company changed its method of accounting for LL-A the consolidation of variable interest entities as of December 31, 2003. PricewaterhouseCoopers LLP Cleveland, Ohio, March 7, 2005 FirstEnergy Corp. 2004 11

SELECTED FINANCIAL DATA (inthousands, except per share amounts)

For the Years Ended December 31, 2004 2003 2002 2001 2000 Revenues S12,453,046 $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 $ 878,175 $ 422,764 $ 552,804 $ 646,447 $ 598,970 Basic Earnings per Share of Common Stock:

Before Discontinued Operations and Cumulative Effect of Accounting Changes S 2.67 $ 1.40 $ 2.11 $ 2.85 $ 2.69 After Discontinued Operations and Cumulative Effect of Accounting Changes S 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 S 2.66 $ 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* s 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 S18,937,766 $18,413,530 $18,686,388 $21,339,001 $11,204,674

• Dividends declared in each year include four quarterly dividends of $0.375 per share paid in those years. Inaddition, a quarterly dividend of S0.4 125 was declared in 2004 payable March 1,2005, 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 S35.24 $35.19 $27.04 Second Quarter High-Low $39.73 $36.73 $38.90 $30.57 Third Quarter High-Low $42.23 $37.04 $38.75 $25.82 Fourth Quarter High-Low $43.41 $38.35 $35.95 $31.66 Yearly High-Low $43.41 $35.24 $38.90 $25.82 Prices are based on reports published in The Wall Street Joumal 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.

12 FirstEnergy Corp. 2004

Management's Discussion and Analysis of Results of Operations and Financial Condition This discussion includes forward-looking statements displays the unusual items resulting in the difference based on information currently available to management. between GAAP and non-GAAP earnings.

Such statements are subject to certain risks and uncertainties.

These statements typically contain, but are not limited to,

' Non-GAAP Reconciliation the terms "anticipate, "potential." "expect," "believe," 2004 2003 2002 estimate" and similar words and include reference to an After-tax Basic After-tax Basic Alter-tax Basic indicated annual dividend. Actual results may differ materially Amount Earnings Amount Earnings Amount Earnings.

due to the speed and nature of increased competition and (Millions) PerShare (Millions) PerShare (Millions) PerShare deregulation in the electric utility industry, economic or Earnings Before Unusual items weather conditions affecting future sales and margins, WNon-GAAP) $991 $3.03 S736 $2.42 $889 $3.03 changes in markets for energy services, changing energy and Cumulative effect of accounting commodity market prices, replacement power costs being change 102 0.33 higher than anticipated or inadequately hedged, maintenance Discontinued international costs being higher than anticipated, legislative and regulatory operations (101) 10.33) (80) (0.27) changes (including revised environmental requirements), Non-core asset adverse regulatory or legal decisions and outcomes (including sales/impairments (60) (0.19) (125) 10.411 1621 10.211 Davis-Besse revocation of necessary licenses or operating permits, fines impacts (38) 10.12) (170) (0.56) (139) 10.47) or other enforcement actions and remedies) of government JCP&L disallowance (109) (0.36) investigations, including by the Securities and Exchange Litigation Commission, the United States Attorney's Office and the settlement 111) (0.03)

Nuclear Regulatory Commission as disclosed in our Securities Lake plants transaction (17) (0.06) and Exchange Commission filings, generally, and with respect NRG settlement 99 0.33 to the Davis-Besse Nuclear Power Station outage in particular, Long-term derivative contract adjustment (11) (0.04) the availability and cost of capital, the continuing availability Generation project and operation of generating units, our inability to accomplish cancellation (10) (0.04).

or realize anticipated benefits from strategic goals, our ability Other 14) 10.01) 19) (0.03) 117) (0.05)

Net Income to improve electric commodity margins and to experience IGAAP) $878 $2.68 $423 $1.39 $553 $1.89 growth in the distribution business, our ability to access the - I.- - _ . I , . , . .. . . , - .I . .I .. ,1. . . . . ..I ---. -- .. -

public securities and other capital markets, further investiga-tion into the causes of the August 14, 2003 regional power The Non-GAAP measure above, earnings before unusual outage and the outcome, cost and other effects of present items, is not calculated in accordance with GAAP because it and potential legal and administrative proceedings and claims excludes the impact of "unusual items." Unusual items reflect related to the outage, the final outcome in the proceeding the impact on earnings of events that are not routine, are relat-related to FirstEnergy's Application for a Rate Stabilization ed to discontinued businesses or are the cumulative effect of Plan in Ohio, the risks and other factors discussed from time an accounting change. We believe presenting normalized earn-to time in our Securities and Exchange Commission filings, ings calculated in this manner provides useful information to and other similar factors. Dividends declared from time to investors in evaluating the ongoing results of our businesses time during any annual period may in aggregate vary from and assists investors in comparing our operating performance the indicated amounts due to circumstances considered by to the operating performance of others in the energy sector.

the Board at the time of the actual declarations. FirstEnergy Under our debt paydown and refinancing program, we expressly disclaims any current intention to update any retired, refinanced, or restructured more than $2.8 billion in long-term debt during the year. These financing activities contributed forward-looking statements contained herein as a result of new information, future events, or otherwise. to the $143 million decrease in interest charges in 2004.

Sales for 2004 were up over the previous year, driven pri-EXECUTIVE

SUMMARY

marily by strong sales in the wholesale power market. This On a non-GAAP basis, earnings in 2004 increased to increase is largely reflective of a stronger economy and the

$991 million, or basic earnings of $3.03 per share of com- return of the Davis-Besse Nuclear Power Station to active sta-mon stock, from earnings of $736 million (basic earnings tus. Despite milder weather experienced over much of our of $2.42 per share) in 2003 and $889 million (basic earnings service area in 2004, our generating fleet produced a record of $3.03 per share) in 2002. On a GAAP basis, net income 76 billion KWH. Our fossil fleet produced 46 billion KWH and increased to $878 million, or basic earnings of $2.68 per our nuclear fleet produced a record 30 billion KWH.

share in 2004 from $423 million (basic earnings of $1.39 The Company made a voluntary $500 million contribu-per share) in 2003 and $553 million (basic earnings of $1.89 tion to its pension plan in order to help add security to per share) in 2002. The following Non-GAAP Reconciliation future plan benefits. The net after-tax cost of the contribu-tion was approximately $300 million. This contribution is FirstEnergy Corp. 2004 13

expected to reduce our overall risk profile, because it Beginning in 2001, Ohio utilities that offered both com-reduces uncertainty regarding the plan's unfunded liability. petitive and regulated retail electric services were required We continue to participate in meaningful settlement to implement a corporate separation plan approved by the negotiations with the parties to the New Source Review PUCO - one which provided a clear separation between reg-case involving our W. H. Sammis Plant (see Environmental ulated and competitive operations. FES provides generation Matters). As a result, the U.S. District Court judge hearing services while the EUOC provide regulated transmission the case has delayed without rescheduling the remedy and distribution services. FGCO, a wholly owned subsidiary phase of the trial, originally scheduled to begin in January of FES, leases and operates fossil and hydroelectric plants 2005. owned by the Ohio Companies and Penn. Under the terms In November 2004, the Board of Directors increased of the Ohio Rate Stabilization Plan, the deadline for achiev-our indicated annual dividend to $1.65 per share, payable ing structural separation by transferring the ownership of quarterly at a rate of $0.4125 per share. This action repre- applicable EUOC generating assets to a competitive affiliate sents a 10% increase over the previous quarterly rate and is was extended until twelve months after the termination of the first dividend increase since FirstEnergy was formed in the Rate Stabilization Plan, unless otherwise extended fur-1997. The Board also adopted a dividend policy that will tar- ther by the PUCO, or until December 31, 2008, whichever is get sustainable annual dividend increases after 2005 that earlier. All of the power supply requirements for the Ohio generally reflect an annual growth rate within the range of Companies and Penn are provided through FES.

4% to 5%, and an earnings payout ratio generally within the FirstEnergy acquired international assets in the merger range of 50% to 60%. with GPU in November 2001. GPU Capital and its sub-At the end of December 2004, accrued dividends of sidiaries had provided electric distribution services in foreign approximately $135 million were included in other current countries (see Results of Operations - Discontinued liabilities on the accompanying consolidated balance sheet. Operations). GPU Power and its subsidiaries owned and Dividends declared in 2004 were $1.9125 which included operated generation facilities in foreign countries. As of quarterly dividends of $0.375 per share paid in each quarter January 30, 2004, all of the international operations had of 2004 and a dividend of $0.4125 payable in the first quar- been divested because those assets were inconsistent with ter of 2005. The amount and timing of all dividend our vision for FirstEnergy.

declarations are subject to the discretion of the Board and its consideration of business conditions, results of opera- STRATEGY tions, financial condition and other factors. We continue to pursue our goal of being the leading regional supplier of energy and related services in the north-FIRSTENERGY'S BUSINESS east quadrant of the United States, where we see the best FirstEnergy is a registered public utility holding compa- opportunities for growth. Our fundamental business strate-ny headquartered in Akron, Ohio that provides regulated and gy remains stable and unchanged. While we continue to competitive energy services (see Results of Operations - build a strong regional presence, key elements for our strat-Business Segments). Our eight EUOC provide transmission egy are in place and management's focus continues to be and distribution services and comprise the nation's fifth on execution. We intend to continue providing competitively largest investor-owned electric system - based on serving priced, high-quality products and value-added services -

4.4 million customers within 36,100 square miles of Ohio, energy sales and services, energy delivery, power supply Pennsylvania and New Jersey. ATSI provides transmission and supplemental services related to our core business.

services to our Ohio Companies and Penn. The service Our current focus includes: (1) minimizing unplanned areas of our EUOC are highlighted below. extended generation outages; (2) enhancing our system reli-ability; (3)optimizing our generation portfolio; (4) effectively Operating Company Area Served Customers Served managing commodity supplies and risks; (5) preserving and OE Central and northeastern Ohio 1,031.066 enhancing appropriate margins; (6)enhancing our credit pro-Penn Western Pennsylvania 157,411 file and financial flexibility; and (7) managing the skills and CEI Northeastern Ohio 757,889 diversity of our workforce.

TE Northwestern Ohio 311,225 JCP&L Northern, western and east central New Jersey 1,061,764 RISKS Met-Ed Eastern Pennsylvania 526,380 We face a number of industry and enterprise risks and Penelec Western Pennsylvania

• 588,066 challenges, including:

ATSI . Service areas of OE,Penn. CEI and TE

• Changes in commodity prices, which could adversely Competitive energy services are principally provided by affect our margins; FES. FSG and MYR provide heating, ventilation, air-condi-

• Complex and changing government regulations, which tioning, refrigeration, process piping, plumbing, electrical could have a negative impact on results of operations; and facility control systems and high-efficiency electrotech-

• Costs of compliance with environmental laws, which nologies. While competitive revenues have increased since are significant, and the cost of compliance with future 2001, regulated energy services continue to provide the environmental laws, which could adversely affect majority of our revenues and earnings. cash flow and profitability; 14 FirstEnergy Cork,. 2004

• Financial performance risks related to the economic lative effect of an accounting change which offset some of cycles of the electric utility industry; the negative 2003 factors described above.

• The continuing availability and operation of generating The $130 million decrease in net income in 2003 com-units, which is dependent on retaining the necessary pared with 2002 reflected many of the factors described licenses, permits, and operating authority from govern- above. Additional costs were being incurred during the mental entities, including the NRC; extended outage at Davis-Besse for replacement power,

• Risks of nuclear generation, including uncertainties accelerated maintenance, extended-scope enhancements relating to health and safety, additional capital costs, to plant design and human performance and safety issues.

the adequacy of insurance coverage and nuclear plant Also, losses were being recorded on international opera-decommissioning; tions, alternative suppliers were expanding more rapidly

• Operational risks arising from the reliability of our power in our franchise areas, the economy negatively influenced plants and transmission and distribution equipment; financial results and we recorded our first impairment of

• Regulatory changes in the electric industry, which goodwill. In 2003, the NRG settlement gain and cumulative could affect our competitive position and result in effect of an accounting change offset the negative factors.

unrecoverable costs adversely affecting our business The financial results in 2004, 2003 and 2002 are and results of operations; summarized in the table below.

• Human resource risks associated with the availability of trained and qualified labor to meet our future F FirstEnergy 2004 2003 2002 staffing requirements; (Inmillions, except per share amounts) l Total revenues $12,453 $11,675 $11,453

• Weather conditions such as tornadoes, hurricanes, Income before discontinued operations storms and droughts, as well as seasonal tempera- and cumulative effect of accounting change 874 424 618 ture variations; Discontinued operations 4 1103) (65)

Cumulative effect of accounting change - 102 -

• A downgrade in credit ratings, which could negatively Net Income S 878 S 423 S 553 affect our ability to access capital; and Basic Earnings Per Share:

• We may ultimately incur liability in connection with Income before discontinued operations and federal proceedings described in Note 13 to the cumulative effect of accounting change $2.67 S1.40 $2.11 Discontinued operations 0.01 (0.34) (0.22) consolidated financial statements. Cumulative effect of accounting change - 0.33 -

Net Income $2.68 $1.39 $1.89 RECLASSIFICATIONS Diluted Earnings Per Share:

As discussed in Notes 1 and 14 to the consolidated Income before discontinued operations and cumulative effect of accounting change $2.66 $1.40 $2.10 financial statements, certain prior year amounts have been Discontinued operations 0.01 10.34) (0.22) reclassified to conform to the current year presentation. Cumulative effect of accounting change - 0.33 -

Revenues related to transmission activities previously Net Income $2.67 $1.39 $1.88 recorded as wholesale electric sales revenues were reclassi-fied as transmission revenues. Expenses (including transmission and congestion charges) were reclassified Results of Operations - 2004 Compared With 2003 among purchased power, other operating costs and amorti- Sources of changes in total revenues are summarized zation of regulatory assets to conform to the current year in the following table:

presentation of generation commodity costs. As further dis-cussed in Note 14 to the consolidated financial statements, Increase Sources of Revenue Changes 2004 2003 (Decrease) segment reporting in 2003 and 2002 was reclassified to tIn millions) conform to the 2004 business segment organizations and Retail Electric Sales:

operations. These reclassifications did not change previously EUOC - Wires S 4.701 S4,787 $186)

- Generation 3,158 3,139 19 reported earnings in 2003 and 2002. FES 637 566 71 Wholesale Electric Sales:

RESULTS OF OPERATIONS EUOC 512 570 158)

FES 1,823 1,143 680 The 2004 increase in net income of $455 million from Total Electric Sales 10,831 10,205 626 the prior year resulted from several factors. First, the number Transmission Revenues:

of unusual charges incurred in 2004 decreased as certain ini- EUOC 333 23 310 tiatives began to reach their conclusion in 2003 and early FES 39 59 120)

Other Revenues:

2004. Second, adverse operating results at FSG led to EUOC 361 443 182) impairment of its goodwill in 2003. Its remaining goodwill FES - Generation 35 10 25 and certain other assets were further impaired in 2004 as we FSG 398 327 71 International - 25 (25) prepared to sell the FSG operations. Finally, a positive turn in Miscellaneous 456 583 (127) the economy, moderation in the rate at which alternative Total Revenues S12A453 $11.675 $778 suppliers expanded their presence in our franchise areas, and reduced expenses enhanced 2004 financial results. Changes in electric generation sales and distribution Moderating those positive results was the absence in 2004 deliveries in 2004 are summarized in the following table:

of the NRG settlement gain recorded in 2003 and the cumu-FirstEnergy Corp. 2004 15

Changes in KWH Sales Increase (Decrease) the revenue increase from customers within our franchise Electric Generation Sales: areas switching to FES.

Retail:

EUOC 11.5)% The gross generation margin in 2004 improved by $402 FES 4.9% million compared to 2003, with electric generation revenue Wholesale 26.7% increasing more rapidly than the costs of fuel and purchased Total Electric Generation Sales 7.7%

power. Excluding the unusual charge resulting from the July EUOC Distribution Deliveries:

Residential ' 2.0% 2003 JCP&L rate decision, the gross generation margin Commercial' 2.6% improved by $249 million and the ratio of gross generation Industrial 0.6% margin to revenue increased from 26.1 % to 27.1 %, primari-Total Distribution Deliveries 1.6% ly reflecting additional lower-cost nuclear generation, offset in part by higher purchased power prices.

Retail sales by our EUOC remain the largest source of revenues, contributing more than 70% of electric revenues Gross Generation Margin 2004 2003 Increase and over 60% of total revenues. The following major factors (Inmillions) contributed to the $67 million decrease in retail electric Electric generation revenue $6,130 S5.418 $712 Fuel and purchased povver costs 4.469 4.159 310 revenues from our EUOC in 2004. Gross Generation Margin $1,661 $1,259 $402 Sources of the Changes in EUOC Retail Electric Revenue Increase (Decrease) Income before discontinued operations and the cumula-(Inmillions)

Changes in Customer Consumption:

tive effect of an accounting change increased $450 million Alternative suppliers $(771 in 2004. In addition to the impact of improved gross genera-Economy, weather and other 109 tion margin discussed above, the following factors 32 contributed to the change in earnings:

Changes in Price:

• Lower nuclear expenses of $169 million primarily as a Rate changes, 1191 Shopping incentives 151) result of one scheduled refueling outage at Beaver Rate mix and other 1291 Valley Unit 1 in 2004 compared to three scheduled 199) refueling outages in 2003 (Beaver Valley Unit 1, Net Decrease S567) Beaver Valley Unit 2 and Perry) and reduced incre-mental maintenance costs at the Davis-Besse Nuclear Lower prices were partially offset by increased energy Power Station related to its restart; use due to a strengthening economy. Although the demand

• Lower energy delivery expenses of $94 million due to for energy increased in all three customer groups - residen- reduced storm restoration costs in 2004, a higher tial, commercial and industrial - milder weather in 2004 level of construction activities in 2004 compared to a moderated the energy needs of residential and commercial higher level of maintenance activities in the prior year customers. Customers shopping in our franchise areas for and additional distribution reliability expenses incurred alternative energy suppliers remained a major factor con- in the third quarter of 2003; tributing to lower EUOC revenues with alternative suppliers

• Reduced fossil generation expenses of $49 million providing a larger portion of franchise customer energy due to less maintenance in 2004 compared to the requirements. prior year; Alternative suppliers provided 24.3% of the total energy

• A net $51 million decrease in employee benefits delivered to retail customers in our franchise areas in 2004, expense primarily as a result of reduced postretire-compared to 21.8% in 2003. Lower prices resulted from ment benefit plan expenses (see Postretirement three factors - a shopping credit rate increase, a change in Plans below), offset in part by higher incentive com-the mix of sales with fewer retail customers receiving pensation and severance costs; EUOC generation in Ohio, and lower base distribution rates

• Lower interest charges of $143 million primarily due at JCP&L. Partially offsetting JCP&Ls lower base distribu- to debt and preferred stock redemption and refinancing tion rates were higher energy, MTC and SBC rates. activities and pollution control note repricings; Additional credits provided to customers (primarily

• A net $81 million reduction in goodwill impairment under the Ohio transition plan) to promote customer shop- charges for FSG with $36 million (see Note 2(H))

ping for alternative suppliers reduced regulated retail electric and $117 million recognized in 2004 and 2003, sales revenues. Reductions from shopping incentives are respectively; and deferred for future recovery under our Ohio transition plan

• Additional deferrals of regulatory assets of $63 and do not affect current period earnings. million, due principally to Ohio shopping incentives.

Electric sales by FES increased by $751 million primarily from additional sales to the wholesale market that increased Partially offsetting the above sources of improved

$680 million in 2004. Higher electric sales to the wholesale earnings were five factors:

market were possible due in part to a 13% increase in gen-

• Reduced revenues of $86 million from distribution eration resulting from record production from our generating deliveries due to lower prices; fleet. Retail sales increased $71 million, with nearly half of

• Increased amortization of regulatory assets of $87 16 FirstEnergv Corp 2004

million primarily from additional Ohio transition plan Retail sales by our EUOC contributed more than 70%

amortization and a change in amortization resulting of electric revenues and over 60% of total revenues. The from the July 2003 JCP&L rate decision; following major factors contributed to the $303 million

• The absence in 2004 of the 2003 earriings benefit of decrease in retail eleciric revenues from our EUOC in 2003:

$168 million realized from the settlement of our claim against NRG for the terminated sale of four fossil Sources of the Changes in EUOC Retail Electric Revenue Increase (Decrease) plants; [in millions)

• An aggregate increase in Ohio property tax expense Changes in Customer Consumption:

and other state taxes of $40 million; and Alternative suppliers 5(2951 Economy, weather and other (16)

• Increased income taxes of $263 million primarily 1311) reflecting higher taxable earnings.

Changes in Price:

v Ratechanges 1111 Results of Operations - 2003 Compared With 2002 Shopping incentives (6)

Rate mix and other 25 Sources of changes in total revenues are summarized 8

in the following table:

jNet Decrease 5(303)

Increase Sources of Revenue Changes 2003 2002 (Decrease) The lower retail electric revenues resulted principally (Inmillions) from increased sales by alternative suppliers in our franchise Retail Electric Sales:

EUOC - Wires $4,787 $4,872 $(85) areas. Alternative suppliers provided 21.8% of the total

- Generation 3.139 3,357 (218) energy delivered to retail customers in our franchise areas in FES 566 348 218 2003, compared to 15.7% in 2002. As a result, generation Wholesale Electric Sales:

EUOC 570 511 59 kilowatt-hour sales to retail customers of our regulated FES 1.143 568 575 services were 7.2% lower. Additional credits provided to Total Electric Sales 10.205 9,656 549 customers (primarily under the Ohio transition plan) to pro-Transmission Revenues: mote customer shopping for alternative suppliers further EUOC 23 39 1161 FES 59 2 57 reduced regulated retail electric sales revenues. Reductions Other Revenues: from shopping incentives are deferred for future recovery EUOC 443 387 56 FES - Generation 10 39 (29) under our Ohio transition plan and do not materially affect FSG 327 383 156) current period earnings. The NJBPU decision in July 2003 International 25 294 (2691 that lowered JCP&L's base electric rates effective August 1, Miscellaneous 583 653 (70)

Total Revenues 511.675 $11453 $ 222 2003 contributed to lower rates.

Electric sales by FES increased by $793 million primarily from additional sales to the wholesale market that increased Changes in electric generation sales and distribution $575 million in 2003 on a 75% increase in kilowatt-hour deliveries in 2003 are summarized in the following table: sales. A majority of the increase was due to sales by our Changes in KWH Sales Increase (Decrease) competitive electric energy services segment for a portion Electric Generation Sales: of New Jersey's BGS requirements and sales in the spot Retail: market. Retail sales by FES increased by $218 million as a EUOC (7.21% result of a 53% increase in kilowatt-hour sales. That FES 53.0%

Wholesale 40.2% increase primarily resulted from retail customers within Total Electric Generation Sales 8.3; our Ohio franchise areas switching to FES under Ohio's EUOC Distribution Deliveries: electricity choice program and from growth in competitive Residential (0.71' retail sales outside our franchise areas.

Commercial 1.2%

Industrial (0.4)  : The gross generation margin in 2003 declined by $215 Total Distribution Deliveries -% 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 FirstEnergyCorp. 2004 17

reduced nuclear generation (down 14%). Reduced nuclear Partially offsetting these higher costs were five factors:

generation output resulted from additional refueling outage

• A settlement of our claim against NRG for the terminated work performed at the Perry and Beaver Valley plants in sale of four fossil plants resulted ina $168 million gain; 2003 and the Davis-Besse extended outage.

• Reduced depreciation resulting from several factors

- lower charges resulting from the implementation Increase of SFAS 143 ($61 million), revised service life assump-Gross Generation Margin 2003 2002 (Decrease) tions for nuclear generating plants ($28 million) and (Inmillions)

Electric generation revenue $5,418 $4,784 $634 reduced depreciation rates resulting from the JCP&L Fuel and purchased power costs 4,159 3,310 849 rate case ($18 million);

Gross Generation Margin $1,259 $1.474 $1215)

• Lower interest charges of $146 million primarily due to debt and preferred stock redemption and refinanc-Income before discontinued operations and the cumula- ing activities and pollution control note repricings; tive effect of an accounting change decreased $194 million

• The absence of unusual charges recognized in 2002 in 2003. In addition to the impact of reduced gross genera- resulted in a further net reduction of other operating tion margin and lower revenues from distribution deliveries expenses ($181 million) in 2003; and discussed above, the following factors contributed to the

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

• Asset impairment charges of $56 million incurred in 2003 including a $26 million non-cash charge related Cumulative Effect ofAccounting Change to the divestiture of our interest in TEBSA; a $13 mil- Results in 2003 included an after-tax credit to net income lion impairment on the monetization of the note of $102 million recorded upon the adoption of SFAS 143 in received from the sale of our 79.9% interest in Avon; January 2003 (see discussion below). We identified applicable an additional $5 million impairment upon the divesti- legal obligations as defined under the new standard for ture of our remaining interest in Avon; and $12 million nuclear power plant decommissioning, reclamation of a sludge related to the disposition of NEO and the write down disposal pond at the Bruce Mansfield Plant and two coal ash of our investment in Pantellos, an internet business- disposal sites. As a result of adopting SFAS 143 in January to-business marketplace serving the utility sector; 2003, asset retirement costs of $602 million were recorded

• A non-cash goodwill impairment charge of $117 mil- as part of the carrying amount of the related long-lived asset, lion recorded in the third quarter of 2003 reducing the offset by accumulated depreciation of $415 million. The ARO carrying value of FSG; liability at the date of adoption was $1.11 billion, including

• Increased energy delivery costs of $36 million princi- accumulated accretion for the period from the date the liability pally due to storm restoration expenses and an was incurred to the date of adoption. As of December 31, accelerated reliability program within JCP&L's service 2002, we had recorded decommissioning liabilities of $1.24 territory; billion. We expect substantially all of our nuclear decommis-

• Higher nuclear expenses of $54 million as a result of sioning costs for Met-Ed, Penelec, JCP&L and Penn to be an additional scheduled nuclear refueling outage in recoverable in rates over time. Therefore, we recognized a 2003 and unplanned work performed during the regulatory liability of $185 million upon adoption of SFAS 143 scheduled refueling outages at the Perry Plant and for the transition amounts related to establishing the ARO for Beaver Valley Unit 1. The higher production costs nuclear decommissioning for those companies. The remaining were partially offset by lower maintenance costs at cumulative effect adjustment for unrecognized depreciation the Davis-Besse Nuclear Power Station; and accretion, offset by the reduction in the existing decom-

• Planned maintenance outages at three of our fossil missioning liabilities and the reversal of accumulated generating plants during the fourth quarter of 2003 estimated removal costs for non-regulated generation assets, increased non-nuclear operating expenses by approxi- was a $175 million increase to income, or $102 million net of mately $25 million; income taxes. The application of SFAS 143 (excluding the

• Increased postretirement plan expenses (see cumulative adjustment described above) resulted in the follow-Postretirement Plans below) offset in part by lower ing changes to expense categories and net income in 2003:

incentive compensation costs contributed to a net Effect of SFAS 143 Increase (Decrease) cost increase of $94 million;

• Revenues less operating expenses for energy-related (Inmillions)

Other operating expense:

services declined $17 million due to general declines Cost of removal expenditures associated with economic conditions; (previously included in depreciation) S10 Depreciation:

• An estimated environmental liability of $15 million Elimination of decommissioning expense 189) was recognized in the fourth quarter of 2003; and Depreciation of asset retirement-cost 2 Accretion of asset retirement liability 42

• Increased amortization of regulatory assets of $138 Elimination of removal cost component (16) million due principally to additional Ohio transition Net decrease to depreciation 161) plan amortization and a July 2003 JCP&L rate case Income taxes 21 disallowance. Net income effect $30 I8 FirstEnergy Corp. 2004

DISCONTINUED OPERATIONS SUPPLY PLAN Discontinued operations for 2004, 2003 and 2002 Our affiliates are obligated to provide generation service include FES' natural gas business (see Note 2(J)) which with an estimated power supply of 99.5 billion KWH for management expects to sell within one year. In 2003 and 2005. These obligations arise from customers who have 2002, discontinued operations were reflected for Emdersa elected to continue to receive generation service from our and EGSA, as we substantially completed our exit from for- EUOCs under regulated retail rate tariffs and from cus-eign operations acquired through the merger with GPU in tomers who have selected FES as their alternate generation 2001. In addition, the results for the FSG subsidiaries, provider. Geographically, approximately 63% of the total Colonial Mechanical, Webb Technologies and Ancoma, Inc. generation service obligation is for customers located in the and the MARBEL subsidiary, NEO, which were divested in MISO market area and 37% for customers located in the 2003, have been reported as discontinued operations for the PJM market area. Included in the PJM market area are obli-years 2003 and 2002. The following table summarizes the gations of FES to provide power to electric distribution sources of income (losses) from discontinued operations: companies in the state of New Jersey, including JCP&L.

FES incurred this obligation as a successful bidder in the Discontinued Operations (Net of tax) 2004 2003 2002 State of New Jersey's auction of BGS.

(In millions) Within the franchise territories of the EUOC, alternative Emdersa - abandonment S- (67) £- energy suppliers currently provide generation service for EGSA - loss on sale - (33) -

Ancoma - loss on sale - 13) - approximately 1,800 MW (summer peak) of load with an Total losses - 1103) - estimated energy requirement of eight billion KWH. If these

' Reclassification of operating income (loss) to discontinued operations: alternate suppliers fail to deliver power to their customers FES' natural gas business 4 (2) 15 located in the EUOC's service areas, the EUOC must pro-Erndersa, EGSA. Colonial, Webb. Ancoma and NEO - 2 (801 cure replacement power in the role of PLR (see Note 2(D)

Total $ 4 $(1031 $(651 for discussion of the auction of JCP&L's PLR obligation).

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

Strengthened equity markets (reducing pension costs), To meet these generation service obligations, our affili-as well as amendments to our health care benefits plan in ates own and operate 13,387 MW of installed generating the first quarter of 2004 and the Medicare Act signed by capacity, which for 2005 is expected to provide approximate-President Bush in December 2003 (reducing OPEB costs) ly 75% of the required power supply. The balance has been combined to reduce postretirement benefits expenses by secured through a mix of long-term purchases (term of con-

$109 million in 2004 from the prior year. A $191 million tract greater than one year) and short-term purchases (term increase in benefits expenses in 2003 from 2002 resulted of contract less than one year). Changes in power supply from declines in equity markets in 2001 and 2002 and a requirements will be met through spot market transactions.

reduction in our assumed discount rate in 2002 which increased pension expenses. Also, higher health care pay- PJM INTERCONNECTION TRANSACTIONS ments and a related increase in projected trend rates led to FES engages in purchase and sale transactions in the higher OPEB expenses in 2003. The following table reflects PJM Market (see Note 2 (D)) to support the supply of end-the portion of postretirement costs that were charged to use customers, including its BGS obligation in New Jersey expense in 2004, 2003 and 2002. and PLR requirements in Pennsylvania. FES meets its supply commitments by transmitting energy into the PJM control Postretirement Expenses (Income) 2004 2003 2002 area and through bilateral purchased power contracts with (Inmillions) counterparties in PJM. FES schedules purchase and sale Pension S 83 S123 $(14)

OPEB 87 156 102 transactions for each hour in PJM on a day-ahead basis with Total $170 $279 588 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 Pension and OPEB expenses are included in various at the location of its demand (end-use customer load).

cost categories and have contributed to cost decreases in FES accounts for energy transactions in the PJM 2004, discussed above. The $500 million voluntary contribu-Market in accordance with EITF 99-19, recognizing purchas-tion made in 2004 is expected to result in a reduction in es and sales on a gross basis by recording each discrete pension costs in 2005, 2006 and 2007 compared to the transaction (see Note 2(D)). This presentation may not be level they would have been without the voluntary contribu-comparable to other energy companies that have dedicated tion. Including the effect of higher interest costs resulting generating capacity in ISOs or fail to meet the criteria for from funding the voluntary contribution, earnings per share gross presentation in EITF 99-19.

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.

Firs!Energy Corp. 2004 19

RESULTS OF OPERATIONS - BUSINESS SEGMENTS of reportable segments under SFAS 131, that change resulted We have three reportable segments: regulated services, in the revision of reportable segments to the separate competitive electric energy services and facilities (HVAC) reporting of competitive electric energy operations, facilities services. The aggregate "Other" segments do not individually services and including all other competitive services opera-meet the criteria to be considered a reportable segment. tions in the "Other" segment. Facilities services is being "Other" consists of international businesses that have disclosed as a reporting segment due to the subsidiaries subsequently been divested, MYR (aconstruction service qualifying as held for sale (see Note 2 (J)). In addition, cer-company); natural gas operations and telecommunications tain amounts (including transmission and congestion services. The assets and revenues for the other business charges) were reclassified among purchased power, other operations are below the quantifiable threshold for operating operating costs and depreciation and amortization to con-segments for separate disclosure as "reportable seg- form with the current year presentation of generation ments." FirstEnergy's primary segment is its regulated commodity costs. Interest expense on holding company services segment, whose operations include the regulated debt and corporate support services revenues and expenses sale of electricity and distribution and transmission services are now included in "Reconciling Items" and "Other" by its eight EUOC in Ohio, Pennsylvania and New Jersey. includes those operating segment results discussed above.

The competitive electric energy services business segment Financial results discussed below include revenues and primarily consists of the subsidiaries (FES, FGCO and expenses from transactions among our business segments.

FENOC) that sell electricity in deregulated markets and A reconciliation of segment financial results to consolidated operate the generation facilities of OE, CEI, TE and Penn financial results is provided in Note 14 to the consolidated resulting from the deregulation of the Companies' electric financial statements. Net income (loss) by business seg-generation business (see Note 2(A) - Accounting for the ment was as follows:

Effects of Regulation).

The regulated services segment designs, constructs, Net Income (Loss) By Business Segment 2004 2003 2002 operates and maintains our regulated transmission and (Inmillions) i distribution systems. Its revenues are primarily derived from electricity delivery and transition costs recovery. The Segments::i Regulated services Competitive electric energy services

$1,015 104 S1,164 13201 1170)

$962 I 1

regulated services segment assets include generating units Facilities services 136). 1811 3 Other 45 1160) (47) that are leased to the competitive electric energy services. Reconciling Items' 1250) (180) 1195)

Its internal revenues represent the rental revenues for the Total S 878 S 423 $553 generating unit leases. Includes interest expense on holding company debt corporate support services The competitive electric energy services segment has revenues and expenses ana orner reconcling Irems.

responsibility for our generation operations as discussed under Note 2(A) to the consolidated financial statements. Regulated Services - 2004 versus 2003 Its net income is primarily derived from revenues from all Financial results of the regulated services segment electric generation sales consisting of generation services were as follows:

to regulated franchise customers who have not chosen an

Increase alternative generation supplier, retail sales in deregulated Regulated Services .004 2003 (Decrease) markets and all domestic unregulated electricity sales in the tin millions) retail and wholesale markets and the related costs of elec- Total revenues S5.713 $5,572 $141 tricity generation and sourcing of commodity requirements. Income before cumulative effect of accounting .

change ' 1,015 1,063 148)

Its net income also reflects the expense of the interseg- Net income 1,015 1,164 1149) ment generating unit leases discussed above and property tax amounts related to those generating units.

The change in operating revenues resulted from the Segment reporting for 2003 and 2002 was reclassified following sources:

to conform with the current year business segment organi-zation and operations emphasizing our regulated electric Increase i businesses and competitive electric energy operations. Sources of Revenue Changes 2004 2003 (Decrease) '

A previous reportable segment was the more expansive (Inmillions) competitive services segment whose aggregate operations Electric sales 54.701 $4,787 S(86)

Other revenues:

consisted of our generation operations, natural gas com- External sales 694 466 228 modity sales, providing local and long-distance phone Internal sales . 318 319 (1) service and other competitive energy related businesses Total Revenues $5.713 S5,572 $141 such as facilities services and construction service (MYR) which was viewed as offering a comprehensive menu of The net increase in operating revenues resulted from:

energy related services. Management's focus is now on our

• A decrease of $86 million in retail sales - a $60 mil-core electric business. This has resulted in a change in per- lion reduction in revenues from distribution deliveries formance review analysis from an aggregate view of all and a $26 million increase in the credits for shopping competitive services operations to a focus on its competi- incentives to customers; and tive electric energy operations. During our periodic review

• A $228 million increase in other revenues primarily 20 FirstEnergy Corp 2004

due to higher transmission revenues and, to a lesser Income before discontinued operations and the cumula-extent, earnings recognized on decommissioning trust tive effect of an accounting change increased $101 million.

investments (see Note 5 - Investments). The following factors offset the lower revenues and con-tributed to the net increase in income:

Income before discontinued operations and the cumula-

• Settlement of our claim against NRG for the terminat-tive effect of an accounting change decreased $48 million. ed sale of four fossil plants which resulted in our In addition to the above changes in revenue, the following recording a $168 million pre-tax credit to earnings; factors contributed to the change:

• Lower interest charges of $95 million primarily related

• The absence in 2004 of the earnings benefit of the to debt and preferred stock redemption and refinanc-2003 settlement of our claim against NRG for the ter- ing activities and pollution control note repricings; and minated sale of four fossil plants, which resulted in a

• The absence of unusual charges recognized in 2002

$168 million gain; of $6 million.

• An aggregate increase in Ohio property tax expense and other state taxes of $32 million; and Partially offsetting the above sources of improved

• Additional MISO and PJM transmission costs of $238 earnings were four factors:

million related to the transmission component of

• Increased energy delivery costs of $41 million princi-other revenue discussed above. pally due to storm restoration expenses and an accelerated reliability program within JCP&L's service Partially offsetting those factors were: territory;

• Lower energy delivery expenses (net of refunds to

• A net increase in depreciation and amortization third-party suppliers) of $71 million due to reduced expense of $9 million resulting from additional amorti-storm restoration costs in 2004, a higher level of con- zation of regulatory assets offset in part by reduced struction activities in 2004 compared to a higher level of depreciation; maintenance activities in the prior year and distribution

• Additional MISO and PJM transmission costs of $29 reliability expenses incurred in the third quarter of 2003; million related to the transmission component of

• Lower interest charges of $130 million primarily related other revenue; and to debt and preferred stock redemption and refinancing

• Increased income taxes of $57 million primarily activities and pollution control note repricings; and reflecting higher taxable earnings.

• Reduced income taxes of $38 million primarily reflect-ing reduced taxable earnings. Competitive Electric Energy Services - 2004 versus 2003 Financial results for competitive electric energy services Regulated Services - 2003 versus 2002 were as follows:

Financial results for regulated services were as follows:

Competitive Electric Energy Services 2004 2003 Increase Increase (Inmillions)

Regulated Services 2003 2002 (Decrease) Total revenues $6,204 $5,487 $717

!. (In millions) Net income (loss) 104 1320) 424 i Total revenues $5,572 5,616 S(441

, Income before cumulative effect of accounting change 1,063 962 101 The change in total revenues resulted from the Net income 1,164 962 202 following sources:

The change in operating revenues resulted from the Sources of Revenue Changes 2004 2003 Increase following sources: (Inmillions)

Electric sales $6,130 $5.41B $712 Increase Other revenues 74 69 5 Sources of Revenue Changes 2003 2002 (Decrease) Total Revenues $6,204 $5,487 $717 (inmillions)

Electric sales $4.787 $4,872 $(851 Other revenues:

The net increase in electric sales resulted from:

External sales 466 426 40

• Higher retail generation sales from customer choice Internal sales 319 318 1 programs ($71 million) and EUOC regulated cus-Total Revenues $5,572 S.616 $(44) tomers ($19 million); and

• Increased FES wholesale revenues of $680 million The net decrease in operating revenues resulted from: offset in part by a $58 million decrease in sales to

• A decrease of $85 million in retail sales - a $40 million EUOC wholesale customers.

reduction in revenues from distribution deliveries and a $45 million increase in the credits for shopping The gross generation margin increased $402 million as incentives to customers; and electric generation revenues increased at a greater rate than

• A net $40 million increase in other revenues due in the related costs of fuel and purchased power. Higher elec-part to JCP&L TBC revenue and jobbing and contract- tric generation revenues resulted from increased sales to ing revenue. both retail and wholesale customers. Excluding the impact Firs tEnergy Corp. 2004 21

of the July 2003 JCP&L rate decision, the gross generation were partially offset by lower maintenance costs at margin increased $249 million, reflecting the benefit of the Davis-Besse Nuclear Power Station; and increased sales and the availability of additional lower-cost

• Planned maintenance outages at three of our fossil nuclear generation. generating plants during the fourth quarter of 2003 Net income increased $424 million. In addition to the increased non-nuclear operating expenses by approxi-improved gross generation margin discussed above, the fol- mately $25 million.

lowing factors contributed to the increase in earnings:

• Lower nuclear expenses of $169 million primarily as a Partially offsetting the above sources of lower earnings result of one scheduled refueling outage at Beaver were reduced income taxes of $134 million reflecting lower Valley Unit 1 in 2004 compared to three scheduled taxable income.

refueling outages in 2003 (Beaver Valley Unit 1, Beaver Valley Unit 2 and Perry) and reduced incre- Facilities Services - 2004 versus 2003 mental maintenance costs at the Davis-Besse Nuclear Financial results for facilities services were as follows:

Power Station related to its restart; and

• Reduced fossil generation expenses of $49 million Facilities Services 2004 2003 Increase (Decrease) due to less maintenance in 2004 compared to the ((Inmillions)

Total revenues $398 $327 $71 prior year. Net loss 36 81 (45)

Partially offsetting the above sources of improved earn-Revenue increased $71 million or 22% in 2004 com-ings were increased income taxes of $294 million reflecting pared to 2003 reflecting stronger market conditions. Losses higher taxable earnings.

from FSG goodwill impairment dominated financial results in 2004 and 2003 resulting in non-cash, pre-tax charges to earn-Competitive Electric Energy Services - 2003 versus 2002 ings of $36 million and $117 million, respectively (see Note 2 Financial results for competitive electric energy services (H)). The impairment in 2003 was identified during our annual were as follows:

assessment of goodwill and in 2004 from an analysis per-Competitive Electric Energy Services 2003 2002 Increase formed at year-end when a firm decision was made to divest (Inmillions) all FSG assets. Excluding the after-tax impact of the goodwill Total revenues $5.487 $4.825 S662 impairments FSG experienced net income in 2004 of $1 mil-Netloss 320 170 150 lion, following a $255,000 loss in 2003.

The change in total revenues resulted from the Facilities Services - 2003 versus 2002 following sources: Financial results for facilities services were as follows:

Sources of Revenue Changes 2003 2002 Increase Facilities Services 2003 2002 (Decrease)

(Inmillions) (Inmillions)

Electric sales $5,418 $4,784 $634 Total revenues $327 $383 $156)

Other revenues 69 41 28 Net income (loss) 181) 3 184)

$5,487 $4,825 $662 Revenues decreased $56 million or 15% in 2003 prima-The net increase in electric sales resulted from increased rily reflecting depressed market conditions and reduced FES wholesale revenues of $575 million and increased sales customer maintenance services due to mild weather. The to EUOC wholesale customers of $59 million. loss in 2003 resulted principally from the effect of the $117 The gross generation margin decreased $215 million as million pre-tax charge (discussed above). Excluding the fuel and purchased power costs increased more rapidly than effect of the goodwill impairment, after-tax earnings related electric generation revenue. Excluding the unusual decreased $3 million in 2003 compared to 2002.

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 CAPITAL RESOURCES AND LIQUIDITY increased due to higher unit costs and additional quantities Our cash requirements in 2004 for operating expenses, purchased. Increased volumes were required to supply obli- construction expenditures, scheduled debt maturities and pre-gations assumed and to replace reduced nuclear generation. ferred stock redemptions were met without increasing our In addition to the reduced gross generation margin dis- net debt and preferred stock outstanding. During 2005, we cussed above, the following factors contributed to the expect to meet our contractual obligations primarily with cash increase in the net loss: from operations. Thereafter, we expect to use a combination Higher nuclear expenses of $54 million as a result of of cash from operations and funds from the capital markets.

an additional scheduled nuclear refueling outage in 2003 and unplanned work performed during the Changes in Cash Position scheduled refueling outages at the Perry Plant and The primary source of ongoing cash for FirstEnergy, as a Beaver Valley Unit 1. The higher production costs holding company, is cash dividends from its subsidiaries. The 22 FirstEnergy Corp. 7004

holding company also has access to $1.375 billion through power contract restructuring transaction, partially offset by a revolving credit facilities. In 2004, FirstEnergy received $782 $237 million decrease in accrued tax balances. Net cash pro-million of cash dividends on common stock from its sub- vided from operating activities decreased $177 million in sidiaries and paid $491 million in cash dividends on common 2003 compared to 2002 due to a $362 million decrease in stock to its shareholders. There are no material restrictions working capital partially offset by a $185 million increase in on the payments of cash dividends by our subsidiaries. cash earnings, as described above under "Results of As of December 31, 2004, we had $53 million of cash Operations." The working capital decrease primarily resulted and cash equivalents, compared with $114 million as of from changes of $388 million in payables and $165 million in December 31, 2003. Cash and cash equivalents as of prepayments and other current assets, partially offset by a December 31, 2003 included $32 million received in $196 million increase in accrued tax balances.

December 2003 from the NRG settlement claim sold in January 2004. The major sources for changes in these bal- Cash Flows From Financing Activities ances are summarized below. In 2004, 2003 and 2002, net cash used for financing activities of $1.457 billion, $1.298 billion and $1.138 billion, Cash Flows From Operating Activities respectively, primarily reflected the redemptions of debt and Our consolidated net cash from operating activities is preferred stock shown below. The following table provides provided primarily by our regulated and competitive electric details regarding new issues and redemptions during 2004, energy businesses (see Results of Operations - Business 2003 and 2002:

Segments above). Net cash provided from operating activi- Securities Issued or Redeemed 2004 2003 2002 ties was $1.877 billion in 2004, $1.755 billion in 2003 and

{In millions)

$1.932 billion in 2002, summarized as follows: New Issues:

- Common stock S - $ 934 S -

Operating Cash Flows 2004 2003 2002 Pollution control notes 261 - 158 Increase (Decrease) (inmillions) Senior secured notes 300 400 370 Cash eamings(1 $2,168 $1,825 51.640 Unsecured notes 400 627 140 Pension trust contributionM 1300) - - $ 961 $1,961 $ 668 Working capital and other 9 (70) 292 Redemptions:

Total $1,877 $1,755 $1,932 First mortgage bonds S 589 $1.483 $ 728 Pollution control notes 80 238 93 i (i) Cash earnings are anon-GAAP measure (see reconciliation below). Senior secured notes 471 323 278 (2)Pension trust contribution net of $200 million of income tax benefits Long-term revolving credit 95 85 -

Unsecured notes 337 - 210 Preferred stock 2 127 522 Cash earnings (in the table above) is not a rneasure of

$1,574 $2,256 $1,831 performance calculated in accordance with GAPkP. We believe Short-term borrowings, net $1351) $15751 S 479 that cash earnings is a useful financial measure because it provides investors and management with an adriitionnal meansq of evaluating our cash-based operating perform~3nce. The fol- Net cash used for financing activities increased by $159 lowing table reconciles cash earnings with net income. million in 2004 from 2003. The increase resulted primarily from the absence of a $934 million common equity financ-l Reconciliation of Cash Earnings 2004 200a 2002 ing in 2003 and a $37 million increase in common stock (Inmirllions) dividends partially offset by an $840 million decrease in net i Net Income (GAAP) $ 878 $ 4:23 $ 553 redemption of preferred securities and debt. Net cash used Non-Cash Charges (Credits):

Provision for depreciation 590 61 07 722 ' for financing activities in 2003 increased $160 million from Amortization of regulatory assets 1,166 1.0i79 941 2002. The increase in cash used for financing activities Deferralofnewregulatoryassets (257) 111 M4) (184) resulted primarily from an increase in net redemptions of Nuclear fuel and lease amortization 96 I56 1 debt and preferred securities of $1.1 billion partially offset Deferred costs recoverable as regulatory assets 1417) (4;27) (,544) db n rfre euiiso 11blinprilyofe Deferred income taxes' 58 54 77 by the common equity financing in 2003.

Goodwill impairment 36 117 -

Disallowed regulatory assets - 1!53 - We had approximately $170 million of short-term Cumulative effect of accounting change - (175) - indebtedness at the end of 2004 compared to approximately Other non-cash expenses 18 1:22 (6) $522 million at the end of 2003. Available borrowing capabil-Cash Earnings (Non-GAAP) $2,168 $1.8:25 $1,640 ity as of December 31, 2004 included the following:

Excludes $200 million of deferred tax benefit from pension conti ribution in2004.

Bonrowing Capability FirstEnergy DE Total Net cash provided from operating activities increased (Inmillions)

$122 million in 2004 compared to 2003 due to a $343 mil- Long-term revolving credit $1.375 $375 $1,750 Utilized 1215) - 1215)

lion increase in cash earnings as described under "Results Letters of credit 11351 - 1135) of Operations" and a $79 million increase from changes in Net 1.025 375 1,400 working capital, partially offset by a $300 million after-tax Short-term bank facilities - 34 34

• voluntary pension trust contribution. The working capital Utilized - (211 121) increase resulted in part from changes of $88 million in Net - 13 13

• receivables, $78 million in prepayments and other current Total Unused Borrowing Capability $ 1,025 $388 $1.413 assets, $59 million in payables and a $53 million NUG FirstEnergy Corp. 2004 23

At the end of 2004, the Ohio Companies and Penn had 0.65 to 1 and a contractually defined fixed charge coverage the aggregate capability to issue approximately $4.4 billion ratio of no less than 2 to 1. As of December 31, 2004, of additional FMB on the basis of property additions and FirstEnergy's and OE's fixed charge coverage ratios, as retired bonds under the terms of their respective mortgage defined under the credit agreements, were 4.48 to 1 and indentures. The issuance of FMB by OE and CEI are also 7.15 to 1, respectively. FirstEnergy's and OE's debt to total subject to provisions of their senior note indentures general- capitalization ratios, as defined under the credit agreements, ly limiting the incurrence of additional secured debt, subject were 0.55 to 1 and 0.39 to 1, respectively. FirstEnergy and to certain exceptions that would permit, among other OE are in compliance with these financial covenants. The things, the issuance of secured debt (including FMB) (i) sup- ability to draw on each of these facilities is also conditioned porting pollution control notes or similar obligations, or (ii) as upon FirstEnergy or OE making certain representations and an extension, renewal or replacement of previously out- warranties to the lending banks prior to drawing on their standing secured debt. In addition, these provisions would respective facilities, including a representation that there has permit OE and CEI to incur additional secured debt not oth- been no material adverse change in their business, condition erwise permitted by a specified exception of up to $641 (financial or otherwise), results of operations, or prospects.

million and $588 million, respectively, as of December 31, Neither FirstEnergy's nor OE's primary credit facilities 2004. Under the provisions of its senior note indenture, contain any provisions that either restrict their ability to bor-JCP&L may issue additional FMB only as collateral for sen- row or accelerate repayment of outstanding advances as a ior notes. As of December 31, 2004, JCP&L had the result of any change in their credit ratings. Each primary capability to issue $644 million of additional senior notes facility does contain "pricing grids", whereby the cost of upon the basis of FMB collateral. Based upon applicable funds borrowed under the facility is related to the credit rat-earnings coverage tests in their respective charters, OE, ings of the company borrowing the funds.

Penn, TE and JCP&L could issue a total of $4.5 billion of Our regulated companies have the ability to borrow preferred stock (assuming no additional debt was issued) as from each other and the holding company to meet their of the end of 2004. CEI, Met-Ed and Penelec have no short-term working capital requirements. A similar but sepa-restrictions on the issuance of preferred stock (see Note rate arrangement exists among our unregulated companies.

10(C) - Long-Term Debt and Other Long-Term Obligations FESC administers these two money pools and tracks sur-for a discussion of debt covenants). plus funds of FirstEnergy and the respective regulated and As of December 31, 2004, approximately $1.0 billion unregulated subsidiaries, as well as proceeds available from remained under FirstEnergy's shelf registration statement, bank borrowings. For the regulated companies, available filed with the SEC in 2003, to support future securities bank borrowings include $1.75 billion from FirstEnergy's issues. The shelf registration provides the flexibility to issue and OE's revolving credit facilities. For the unregulated com-and sell various types of securities, including common panies, available bank borrowings include only FirstEnergy's stock, debt securities, and share purchase contracts and $1.375 billion of revolving credit facilities. Companies receiving related share purchase units. a loan under the money pool agreements must repay the At the end of 2004 and 2003, our common equity as a principal amount of the loan, together with accrued interest, percentage of capitalization stood at 45% compared to 38% within 364 days of borrowing the funds. The rate of interest at the end of 2002. The higher common equity percentage is the same for each company receiving a loan from their in 2004 and 2003 compared to 2002 reflects net redemptions respective pool and is based on the average cost of funds of preferred stock and long-term debt, and the increase in available through the pool. The average interest rate for retained earnings. borrowings in 2004 was 1.43% for the regulated companies' Our working capital and short-term borrowing needs are money pool and 1.55% for the unregulated companies' met principally with a syndicated $1 billion three-year revolv- money pool.

ing credit facility maturing in June 2007. Combined with our Our access to capital markets and costs of financing are syndicated $375 million three-year facility maturing in influenced by the ratings of our securities. The following October 2006, a $125 million three-year facility for OE table shows our securities ratings as of December 31, 2004.

maturing in October 2006, and a syndicated $250 million The ratings outlook from the ratings agencies on all securi-two-year facility for OE maturing in May 2005, our primary ties is stable.

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 24 FirstEnergy Corp. ,'004

Ratings of Securities Securities S&P Moody's Fitch Net cash used for investing activities in 2004 decreased FirstEnergy Senior unsecured B+ Baa3 BBB- by $88 million from 2003. The decrease was primarily due OE Senior secured BBB Baal BBB+ to $278 million in cash proceeds from certificates of deposit Senior unsecured B+ Baa2 BBB Preferred stock BB Bal BBB- received in the third quarter of 2004 partially offset by a CEI Senior secured BBB- Baa2 BBB- $117 million change in NUG trust activity. Net cash used for Senior unsecured BB+ Baa3 BB investing activities in 2003 decreased by $264 million from Preferred stock BB Ba2 BB- 2002. The decrease was primarily due to a $142 million TE Senior secured BB3- Baa2 BBB-Senior unsecured BB+ Baa3 BB decrease in property additions and a $174 million increase Preferred stock BB Ba2 BB- in cash payments on long-term notes receivable.

Penn Senior secured BBB Baal BBB+ Our capital spending for the period 2005-2007 is Senior unsecured 1X}B+ Baa2 BBB Preferred stock BB Bat BBB-expected to be about $3.3 billion (excluding nuclear fuel),

JCP&L Senior secured 8BB+ Baal BBB+ of which $979 million applies to 2005. Investments for Preferred stock BB Bal BBB additional nuclear fuel during the 2005-2007 period are Met-Ed Senior secured BBB Baal BBB+ estimated to be approximately $268 million, of which about Senior unsecured BBB- Baa2 BBB $53 million applies to 2005. During the same period, our Penelec Senior secured EBB Baal BBB+

Senior unsecured BBB- Baa2 BBB nuclear fuel investments are expected to be reduced by approximately $280 million and $90 million, respectively, 1tIPenn s only senior unsecured debt obligations are notes underlying pollution control revenue rehfnding bonds issued by the Ohio Air Quality Development as the nuclear fuel is consumed.

Authority to which bonds this rating applies.

CONTRACTUAL OBLIGATIONS On December 10, 2004, S&P reaffirmed our 'BBB-' corpo- Contractual Obligations rate credit rating and kept the outlook stable. S&P noted that As of December 31, 2004, our estimated cash the stable outlook reflects our improving financial profile and payments under existing contractual obligations that cash flow certainty through 2006. S&P stated that should the we consider firm obligations are as follows:

two refueling outages at the Davis-Besse and Perry nuclear plants scheduled for the first quarter of 2005 be completed suc- .2006- 2W08-cessfully without any significant negative findings and delays, Contractual Obligations Total 2005 2007 2009 Thereafter our outlook would be revised to positive. S&P also stated that a (Inmillions) ratings upgrade in the next several months did not seem likely, Long-termdebt to)10.890 $ 710 $1,565 S 622 $ 7,993 Short-term borrowings 170 170 - - -

as remaining issues of concern to S&P, primarily the outcome of Preferred stock l'1 17 2 14 1 -

environmental litigation and SEC investigations, are not likely to Capital leases m 19 5 6 2 6 Operating leases'2 Z362 183 349 376 1.454 be resolved in the short term. Pension funding 13v - - - - -

Fuel and purchased power 14 13,765 2,464 4,184 3,148 3.969 Cash Flows From Investing Activities Total $27.223 $3.534 $6.118 $4,149 S13.422 Net cash flows used in investing activities resulted principal- Vt)Subject to mandatory redemption.

ly from property additions. Regulated services expenditures for 0 See Note 6 to the consolidated financial statements.

property additions primarily include expenditures supporting the 1OWe estimate that no furtherpension contributions wil be required through 2009 to maintain ourdefinedbenefitpensionplans funding ata minimum distribution of electricity. Capital expenditures by the competitive required level as determined by government regulations. We are unable to electric energy services segment are principally generation-relat- estimate projected contributions beyond 2009. See Note 3 to the consolidated financial statements.

ed. The following table summarizes 2004 investments by our IJ4Amounts under contract with fixed or minimum quantities and approximate regulated services and competitive services segments: timing.

N Amounts reflected do not include interest on long-term debt Summary of Cash Flows Property Used for Investing Activities Additions Investments Other Total 2004 Sources {Uses) fin millions) Guarantees and Other Assurances Regulated services S(5721 $181 $1881 $(479) As part of normal business activities, we enter into Competitive electric energy services (2461 16 12) 1232) various agreements on behalf of our subsidiaries to provide Facilities services 131 - 2 1)

Other 14? 184 16) 174 financial or performance assurances to third parties. Such Reconciling items 121) (22) 100 57 agreements include contract guarantees, surety bonds, and Total S1846) $359 $ 6 S1481) LOCs. Some of the guaranteed contracts contain ratings 2003 Sources (Uses) contingent collateralization provisions.

Regulated services $1434) $105 $ 16 $(313)

Competitive electric energy services 1335) 132) 8 1359) As of December 31, 2004, our maximum exposure Facilities services (4) 61 170) 113) to potential future payments under outstanding guarantees Other (91) 46 116 153 Reconciling items 174) 28 9 (37) and other assurances totaled approximately $2.4 billion, Total $1856) $208 $ 79 $1569) as summarized below:

2002 Sources (Uses)

Regulated services $1490) $ 27 S 2 $1461)

Competitive electric energy services 1391) - 125) 1416)

Facilities services 16) - - (6)

Other (9) 96 43 130 Reconciling items (102) 140) 62 1801 Total $(9981 $83 S 82 $1833)

FirstEnergy Corp. 2004 25

Guarantees and Other Assurances Maximum Exposure agreement. In connection with the sale of TEBSA in January i;: t (Inmillionsl 2004, the purchaser indemnified FirstEnergy against any loss FirstEnergy Guarantees of Subsidiaries under this guarantee. We have also provided an LOC (current-Energy and Energy-Related Contracts (1t S 878 Othert21 2 149 ly at $47 million), which is renewable and declines yearly 1,027 based upon the senior outstanding debt of TEBSA.

Surety Bonds 279 LOC O3X4, 1,098 OFF-BALANCE SHEET ARRANGEMENTS Total Guarantees and Other Assurances $2,404 We have obligations that are not included on our

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

Consolidated Balance Sheets related to the sale and lease-a Issued for various terms.

• Includes S135 million issued for various terms under LOC capacity available in back arrangements involving Perry Unit 1, Beaver Valley Unit FlrstEnergy' revolving credit agreement and $299 million outstanding in support 2 and the Bruce Mansfield Plant, which are reflected as part of pollution control revenue bonds issued with various maturities. of the operating lease payments disclosed above (see Notes

(') Includes approximately$216million pledged in connection with the sale and 6 and 7). The present value of these sale and leaseback leaseback of Beaver Valley Unit 2 by CEI and T&$294 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $154 operating lease commitments, net of trust investments, million pledged in connection with the sale and leaseback of Perry Unit I by OE total $1.4 billion as of December 31, 2004.

CEI and TE sell substantially all of their retail customer We guarantee energy and energy-related payments of receivables to CFC, a wholly owned subsidiary of CEI. CFC our subsidiaries involved in energy commodity activities - subsequently transfers the receivables to a trust (a "qualified principally to facilitate normal physical transactions involving special purpose entity" under SFAS 140) under an asset-electricity, gas, emission allowances and coal. We also pro- backed securitization agreement. This arrangement provided vide guarantees to various providers of subsidiary financing $84 million of off-balance sheet financing as of December principally for the acquisition of property, plant and equip- 31, 2004. See Note 12 to the consolidated financial state-ment. These agreements legally obligate us to fulfill the ments for additional information regarding this arrangement.

obligations of our subsidiaries directly involved in these We have equity ownership interests in various busi-energy and energy-related transactions or financings where nesses that are accounted for using the equity method.

the law might otherwise limit the counterparties' claims. If There are no undisclosed material contingencies related to demands of a counterparty were to exceed the ability of a these investments. Certain guarantees that we do not subsidiary to satisfy existing obligations, our guarantee expect to have a material current or future effect on our enables the counterparty's legal claim to be satisfied by our financial condition, liquidity or results of operations are dis-other assets. The likelihood that such parental guarantees closed above as contractual obligations.

will increase amounts otherwise paid by us to meet our obli-gations incurred in connection with ongoing energy and MARKET RISK INFORMATION energy-related contracts is remote. We use various market risk sensitive instruments, While these types of guarantees are normally parental including derivative contracts, primarily to manage the risk commitments for the future payment of subsidiary obliga- of price and interest rate fluctuations. Our Risk Policy tions, subsequent to the occurrence of a credit rating Committee, comprised of members of senior management, downgrade or "material adverse event" the immediate post- provides general management oversight to risk manage-ing of cash collateral or provision of an LOC may be required ment activities throughout the company. They are of the subsidiary. The following table summarizes collateral responsible for promoting the effective design and imple-provisions in effect as of December 31, 2004: mentation of sound risk management programs. They also oversee compliance with corporate risk management poli-Total Collateral Paid Remaining cies and established risk management practices.

Collateral Provisions Exposure Cash LOC ExposureMfl oIn millions) 1 Commodity Price Risk Credit rating downgrade S34 $162 $ 18 $169 Adverse event 135 - 22 113 We are exposed to market risk primarily due to fluctua-Total $484 $162 $40 $282 tions in electricity, natural gas, coal, nuclear fuel and 01'As of February 7,2005. our total exposure decreased to $476 million and the emission allowance prices. To manage the volatility relating remaining exposure increased to $290 million - net of $146 million of cash to these exposures, we use a variety of non-derivative and collateral and $40 million of LOC collateral provided to counterparties.

derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used prin-Most of our surety bonds are backed by various indem- cipally for hedging purposes and, to a much lesser extent, nities common within the insurance industry. Surety bonds for trading purposes. Most of our non-hedge derivative con-and related guarantees provide additional assurance to out-tracts represent non-trading positions that do not qualify for side parties that contractual and statutory obligations will be hedge treatment under SFAS 133. The change in the fair met in a number of areas including construction contracts, value of commodity derivative contracts related to energy environmental commitments and various retail transactions. production during 2004 is summarized in the following table:

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 26 FIrstEnergy Corp. 2004

Increase 1Decrease) in the Fair the near term on both our trading and nontrading derivative Value of Derivative Contracts Non-Hedge Hedge Total instruments would not have had a material effect on our (Inmillions) consolidated financial position or cash flows as of Change in the fair value of commodity derivative contracts December 31, 2004. We estimate that if energy commodity Outstanding net asset as of January 1, 2004 S 67 S 12 $79 prices experienced an adverse 10% change, net income for New contract value when entered - - -

Additions/change in value of existing contracts 14) 6 2 the next twelve months would decrease by approximately Change in techniques/assumptions - - - $3 million.

Settled contracts 11) (16) 117)

Outstanding net asset Interest Rate Risk as of December 31, 2004 (1" 62 2 64 Non-commodity net assets Our exposure to fluctuations in market interest rates is as of December 31, 2004: reduced since a significant portion of our debt has fixed Interest rate swaps ra - 4 4 interest rates, as noted in the table below.

Net Assets - Derivatives Contracts as of December 31, 2004 $ 62 $ 6 $ 68 comparison of Carrying Value to Fair Value Impact of Changes in Commodity There- Fair Derivative Contracts (3) 1Year of Maturity 2005 2006 2007 2008 2009 after Total Value Income Statement Effects (Pre-Tax) S 1(5) - $ 15)

Balance Sheet Effects: Assets: . (inmillions)

DCI (Pre-Tax) 5- $110) $110) Investments other than Cash and Cash t1 Includes $61 million in non-hedge commodity derivative contracts, which are Eluivaents-FiedIrce $73 S82 S77 $ 57 $68 $1,729 $2,086 $2.243 offset by a regulatory liability Average interest rate 6.8% 7.8' 7.9' 737 7.8' 6.0% 6.3' I2) Interest rate swaps are primarily treated as fair value hedges. Changes in Liabilities:

derivative values of the fair value hedges are offset by changes in the hedged Long-term Debt and Other debts'premium or discount (see Interest Rate Swap Agreements below). Long-term Obligations:

n3) Represents the increase in value of existing contracts, settled contracts Fixed rate (1) $495 $1,327 $238 $338 $284 $6,674 $9.356 $9,915 and changes in techniques/assumptions. Average interest rate 7.4' 5.7% 6.6% 5.3' 6.8% 6.5x 6.4x Variable rate ti) $215 $1,319 $1,534 $1,538 I Average interest rate 3.6x 2.2' 2.4 Derivatives are included on the Consolidated Balance Preferred Stock Subject to Sheet as of December 31, 2004 as follows: Mandatory Redemption $2 $2 $12 S1 $17 $16 Average dividend rate 7.5% 7.5% 7.6' 7.4 7.6' Short-term Borrowings $170 $170 $170 Non-Hedge Hedge Total Average interest rate 2.4' 2.4' (Inmillions) tI Balances and rates do not reflect the fixed-to-floating interestrate swap Current- agreements discussed below Otherassets $2 $ 2 $ 4 Other liabilities 12) 11) 13)

Non-Current- We are subject to the inherent interest rate risks relat-Other deferred charges 62 15 77 Other noncurrent liabilities - (10) 110) ed to refinancing maturing debt by issuing new debt Net assets $62 S6 $68 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 The valuation of derivative contracts is based on observ-risk. While fluctuations in the fair value of our Ohio able market information to the extent that such information Companies' decommissioning trust balances will eventually is available. In cases where such information is not available, affect earnings (affecting OCI initially) based on the guid-we rely on model-based information. The model provides ance provided by SFAS 115, our non-Ohio EUOC have the estimates of future regional prices for electricity and an esti-opportunity to recover from customers, or refund to cus-mate of related price volatility. We use these results to tomers, the difference between the investments held in develop estimates of fair value for financial reporting purpos-trust and their decommissioning obligations. Thus, there is es and for internal management decision making. Sources of not expected to be an earnings effect from fluctuations in information for the valuation of commodity derivative con-their decommissioning trust balances. As of December 31, tracts by year are summarized in the following table:

2004, decommissioning trust balances totaled $1.583 billion, Source of Information- Fair Value by Contract Year with $975 million held by our Ohio Companies and the bal-2005 2006 2007 2008 Thereafter Total ance held by our non-Ohio EUOC. As of year-end 2004, trust (Inmillions) balances of our Ohio Companies were comprised of 64%

Pricesactivelyquotedll) $2 S1 5- S- 5- S3 equity securities and 36% debt instruments.

Other external sources (2) 17 10 - - - 27 Prices based on models - - 10 9 15 34 Total 3 $19 $11 $10 S9 $15 $64 Interest Rate Swap Agreements III Exchange traded. We have utilized fixed-to-floating interest rate swap d7)Broker quote sheets. agreements, as part of our ongoing effort to manage the Includes $61 million from an embedded option that is offset by a regulatory interest rate risk of our debt portfolio. These derivatives are liability and does not affect eamings. treated as fair value hedges of fixed-rate, long-term debt issues - protecting against the risk of changes in the fair We perform sensitivity analyses to estimate our expo- value of fixed-rate debt instruments due to lower interest sure to the market risk of our commodity positions. A rates. Swap maturities, call options, fixed interest rates and hypothetical 10% adverse shift in quoted market prices in FirstEnergy Corp. 2004 27

interest payment dates match those of the underlying obli- sented 7% of our total credit risk. Within our unregulated gations. During the fourth quarter of 2004, in a period of energy subsidiaries, 99% of credit exposures, net of collat-declining interest rates, we unwound swaps with a total eral and reserve, were with investment-grade counterparties notional amount of $400 million. We received $12 million in as of December 31, 2004.

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- REGULATORY MATTERS able debt rates, interest expense in 2004 and 2003 was In Ohio, New Jersey and Pennsylvania, laws applicable reduced by $37 million and $27 million, respectively. We to electric industry restructuring contain similar provisions increased the total notional amount of outstanding interest that are reflected in the Companies' respective state regula-rate swaps to $1.65 billion as of December 31, 2004, from tory plans. These provisions include:

$1.15 billion at the end of 2003 from cumulative swap activi-

• restructuring the electric generation business and ties. As of December 31, 2004, the debt underlying the allowing the Companies' customers to select a com-interest rate swaps had a weighted average fixed interest petitive electric generation supplier other than the rate of 5.53%, which the swaps have effectively converted to Companies; a current weighted average variable interest rate of 3.42%.

• establishing or defining the PLR obligations to cus-tomers in the Companies' service areas; Fixed to Floating Rate Interest Rate Swaps (Fair value hedges)

• providing the Companies with the opportunity to December 31, 2004 December 31, 2003  ! recover potentially stranded investment (or transition Notional Maturity Fair Notional Maturity Fair Amount Date Value Amount Date Value costs) not otherwise recoverable in a competitive (Dollars inmillions) generation market;

$200 2006 SIll $200 2006 S 1l

• itemizing (unbundling) the price of electricity into its 100 2008 (11 50 2008 - component elements - including generation, trans-100 2010 1 100 2010 1 100 2011 2 100 2011 1 mission, distribution and stranded costs recovery 400 2013 4 350 2013 (1) charges; 100 2014 2 - - -

150 2015 17) 150 2015 (101.

• continuing regulation of the Companies' transmission 200 2016 1 - - - , and distribution systems; and 150 2018 5 150 2018 l 50 2019 2 50 2019 1

• requiring corporate separation of regulated and unreg-10W 2031 (4) - - - ulated business activities.

Equity Price Risk The EUOC recognize, as regulatory assets, costs which Included in nuclear decommissioning trusts are mar- the FERC, PUCO, PPUC and NJBPU have authorized for recov-ketable equity securities carried at their current fair value of ery from customers in future periods or for which authorization approximately $951 million and $779 million as of December is probable. Without the probability of such authorization, costs 31, 2004 and 2003, respectively. A hypothetical 10% currently recorded as regulatory assets would have been decrease in prices quoted by stock exchanges would result charged to income as incurred. All regulatory assets are expect-in a $95 million reduction in fair value as of December 31, ed to be recovered from customers under the Companies' 2004 (see Note 5 - Fair Value of Financial Instruments). respective transition and regulatory plans. Based on those plans, the Companies continue to bill and collect cost-based CREDIT RISK rates for their transmission and distribution services, which Credit risk is the risk of an obligor's failure to meet the remain regulated; accordingly, it is appropriate that the terms of any investment contract, loan agreement or other- Companies continue the application of SFAS 71 to those opera-wise perform as agreed. Credit risk arises from all activities tions. Regulatory assets that do not earn a current return in which success depends on issuer, borrower or counter- totaled approximately $240 million as of December 31, 2004.

party performance, whether reflected on or off the balance sheet. We engage in transactions for the purchase and sale Regulatory Assets As of December 31 2004 lncrease 2003 (Decrease) 4 of commodities including gas, electricity, coal and emission (Inmillions) allowances. These transactions are often with major energy OE  : 1.116 $1,451 $ 1335)

CEI 959 1.056 197) companies within the industry. TE 375 459 1841 We maintain credit policies with respect to our counter- Penn' - 28 1281 JCP&L 2,176 2.558 (382) parties to manage overall credit risk. This includes Met-Ed 693 1,028 1335) performing independent risk evaluations, actively monitoring Penelec 200 497 1297) -

ATSI 13 - 13 portfolio trends and using collateral and contract provisions Total $5,532 $7,077 5(1.545) to mitigate exposure. As part of our credit program, we aggressively manage the quality of our portfolio of energy Changes in Penn's net regulatory asset components in 2004 resulted in net regulatory liabilities of approximately $18million includedin OtherNoncurrent contracts, evidenced by a current weighted average risk rat- Liabilities on the Consolidated Balance Sheet as of December 31, 2004.

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 FirstEnergyCorp. 2(104

Regulatory assets by source are as follows: take, no more often than annually, a similar competitive bid process to secure generation for the years 2007 and 2008. Any I Rel lulatory Assets By Source Increase acceptance of future competitive bid results would terminate I As of December 31 2004.. 2003 (Decrease)

I-i se (Inmillions) the Rate Stabilization Plan pricing, but not the related gulatory transition costs $4.889 56.427 5(1,5381 approved accounting, and not until twelve months after IrCusstomer shopping incentives' 612 371 241 i the PUCO authorizes such termination.

I Cusstomer receivables for future income taxes 246 340 (941 Soc ietal benefits charge 51 81 130) On December 30, 2004, the Ohio Companies filed an TLoss on reacquired debt 89 75 14 application with the PUCO seeking tariff adjustments to I Eml plyee postretirement benefitsn12) costs 65 77 recover increases of approximately $30 million in transmis-1 Nuc nd spent fuel disposal costs 11691 196) (73) sion and ancillary service-related costs beginning January 1, t Ass;et removal costs (3401 (3211 (19) 2006. The Ohio Companies also filed an application for i Pro perty losses and unrecovered plant costs 50 70 (20)

P i0ther 39 53 114) authority to defer costs such as those associated with MISO Totial 55.532 57,077 5(1,545) Day 1, MISO Day 2, congestion fees, FERC assessment fees, The Ohio Coimpanies are deferring customer shopping incentives and interest costs and the ATlI rate increase (described below), as applicable,

• as newregulatoryassers inaccordance with the transition and rate stabilization from October 1, 2003 through December 31, 2005.

• plans. These regulatory assets. totaling $612million as of December31. 2004 will be recovered through a surcharge rate equal to the RTC rate in effect when the See Note 9 to the consolidated financial statements transitioncosts have been fully recovered. Recovery of the new regulatory assets for further details and a complete discussion of regulatory will begin at that time and amortization of the regulatory assets for each accounting matters in Ohio.

period will be equal to the surcharge revenue recognized during that period New Jersey Ohio In July 2003, the NJBPU announced its JCP&L base On February 24, 2004, the Ohio Companies filed a electric rate proceeding decision, which reduced JCP&L's revised Rate Stabilization Plan to address PUCO concerns annual revenues effective August 1, 2003 and disallowed related to the original Rate Stabilization Plan that the Ohio

$153 million of deferred energy costs. The NJBPU decision Companies filed in October 2003. On June 9, 2004, the also provided for an interim return on equity of 9.5% on PUCO issued an order approving the revised Rate JCP&L's rate base. The decision ordered a Phase II proceed-Stabilization Plan, subject to conducting a competitive bid ing be conducted to review whether JCP&L is in compliance process. On August 5, 2004, the Ohio Companies accepted with current service reliability and quality standards. The the Rate Stabilization Plan as modified and approved by the BPU also ordered that any expenditures and projects under-PUCO on August 4, 2004. In the second quarter of 2004, taken by JCP&L to increase its system's reliability be the Ohio Companies implemented the accounting modifica-reviewed as part of the Phase II proceeding, to determine tions related to the extended amortization periods and their prudence and reasonableness for rate recovery. In that interest cost deferrals on the deferred customer shopping Phase II proceeding, the NJBPU could increase JCP&L's incentive balances. On October 1 and October 4, 2004, the return on equity to 9.75% or decrease it to 9.25%, depend-OCC and NOAC, respectively, filed appeals with the ing on its assessment of the reliability of JCP&L's service.

Supreme Court of Ohio to overturn the June 9, 2004 PUCO Any reduction would be retroactive to August 1, 2003.

order and associated entries on rehearing.

JCP&L recorded charges to net income for the year ended The revised Rate Stabilization Plan extends current gen-December 31, 2003, aggregating $185 million ($109 million eration prices through 2008, ensuring adequate generation net of tax) consisting of the $153 million of disallowed supply at stabilized prices, and continues the Ohio deferred energy costs and $32 million of other disallowed Companies' support of energy efficiency and economic regulatory assets. In its final decision and order issued on development efforts. Other key components of the revised May 17, 2004, the NJPBU clarified the method for calculat-Rate Stabilization Plan include the following:

ing interest attributable to the cost disallowances, resulting

• extension of the amortization period for transition in a $5.4 million reduction from the amount estimated in costs being recovered through the RTC for OE from 2003. JCP&L filed an August 15, 2003 interim motion for 2006 to as late as 2007; for CEI from 2008 to as late rehearing and reconsideration with the NJBPU and a June 1, as mid-2009 and for TE from mid-2007 to as late as 2004 supplemental and amended motion for rehearing and mid-2008; reconsideration. On July 7, 2004, the NJBPU granted limited

• deferral of interest costs on the accumulated customer reconsideration and rehearing on the following issues: (1) shopping incentives as new regulatory assets; and deferred cost disallowances (2) the capital structure includ-

• ability to request increases in generation charges dur-ing the rate of return (3) merger savings, including ing 2006 through 2008, under certain limited amortization of costs to achieve merger savings; and (4) conditions, for increases in fuel costs and taxes.

decommissioning. Management is unable to predict when a decision may be reached by the NJBPU.

On December 9, 2004, the PUCO rejected the auction On July 16, 2004, JCP&L filed the Phase II petition and price results from a required competitive bid process and testimony with the NJBPU requesting an increase in base issued an entry stating that the pricing under the approved rates of $36 million for the recovery of system reliability revised Rate Stabilization Plan will take effect on January 1, costs and a 9.75% return on equity. The filing also requests 2006. The PUCO may cause the Ohio Companies to under-an increase to the MTC deferred balance recovery of FirstEnergy Corp. 2004 29

approximately $20 million annually. The Ratepayer Advocate million. On January 28, 2005, the FERC accepted for filing filed testimony on November 16, 2004, JCP&L submitted the revised tariff sheets to become effective February 1, rebuttal testimony on January 4, 2005. Settlement confer- 2005, subject to refund, and ordered a public hearing be ences are ongoing. held to address the reasonableness of the proposal to elimi-See Note 9 to the consolidated financial statements for nate the voltage-differentiated rate design for the ATSI zone.

further details and a complete discussion of regulatory matters in New Jersey. ReliabilityInitiatives In 2004, we completed implementation of all actions Pennsylvania and initiatives related to enhancing area reliability, improving Met-Ed and Penelec purchase a portion of their PLR voltage and reactive management, operator readiness and requirements from FES through a wholesale power sale training, and emergency response preparedness as recom-agreement. The PLR sale is automatically extended for each mended by various governmental, industry and ad hoc successive calendar year unless any party elects to cancel reliability entities (PUCO, FERC, NERC and the U.S. -

the agreement by November 1 of the preceding year. Under Canada Power System Outage Task Force) for completion in the terms of the wholesale agreement, FES retains the sup- 2004. We certified to NERC on June 30, 2004, that we had ply obligation and the supply profit and loss risk, for the completed our initiatives with minor exceptions noted, and portion of power supply requirements not self-supplied by an independent team led by NERC verified the implementa-Met-Ed and Penelec under their NUG contracts and other tion. Further, we reported to NERC on December 28, 2004 power contracts with nonaffiliated third party suppliers. This that the minor exceptions were essentially complete.

arrangement reduces Met-Ed's and Penelec's exposure to We are proceeding with the implementation of the high wholesale power prices by providing power at a fixed recommendations that were to be completed subsequent price for their uncommitted PLR energy costs during the to 2004 and will continue to periodically assess the FERC-term of the agreement with FES. Met-Ed and Penelec are ordered Reliability Study recommendations for forecasted authorized to continue deferring differences between NUG 2009 system conditions recognizing revised load forecasts contract costs and current market prices. and other changing system conditions which may impact On January 12, 2005, Met-Ed and Penelec filed, before the recommendations. Thus far, implementation of the rec-the PPUC, a request for deferral of transmission-related ommendations has not required, nor is expected to require, costs beginning January 1, 2005 estimated to be approxi- substantial investment in new, or material upgrades to exist-mately $8 million per month. ing equipment. We note, however, that FERC or other See Note 9 to the consolidated financial statements for applicable government agencies and reliability coordinators further details and a complete discussion of regulatory may take a different view as to recommended enhance-matters in Pennsylvania. ments or may recommend additional enhancements in the future that could require additional, material expenditures.

Transmission Finally, the PUCO is continuing to review our filing that On September 16, 2004, the FERC issued an order that addressed upgrades to control room computer hardware imposed additional obligations on CEI under certain pre- and software and enhancements to the training of control Open Access transmission contracts among CEI and the room operators, before determining the next steps, if any, in cities of Cleveland and Painesville. Under the FERC's deci- the proceeding. See Note 9 to the consolidated financial sion, CEI may be responsible for a portion of new energy statements for a more detailed discussion of reliability initia-market charges imposed by MISO when its energy markets tives, including actions by the PPUC that impact Met-Ed, begin in the spring of 2005. CEI filed for rehearing of the Penelec and Penn.

order from the FERC on October 18, 2004. The impact of On July 5, 2003, JCP&L experienced a series of 34.5 the FERC decision on CEI is dependent upon many factors, kilovolt sub-transmission line faults that resulted in outages including the arrangements made by the cities for transmis- on the New Jersey shore. As a result of an investigation into sion service, the startup date for the MISO energy market, these outages, the NJBPU issued an order to JCP&L on July and the resolution of the rehearing request, and cannot be 23, 2004 to implement actions to improve reliability in accor-determined at this time. dance with a Special Reliability Master (SRM) report findings On November 1, 2004, ATSI requested authority from and an operations audit.

the FERC to defer approximately $54 million of vegetation See Note 9 to the consolidated financial statements for management costs ($13 million deferred as of December a more detailed discussion of reliability initiatives, including 31, 2004 pending authorization) estimated to be incurred actions by the PPUC, that impact Met-Ed, Penelec and Penn.

from 2004 through 2007. The FERC approved ATSI's request to defer those costs on March 4, 2005. ENVIRONMENTAL MATTERS ATSI and MISO filed with the FERC on December 2, We believe we are in compliance with current S02 and 2004, seeking approval for ATSI to have transmission rates NOx reduction requirements under the Clean Air Act established based on a FERC-approved cost of service for- Amendments of 1990. In 1998, the EPA finalized regulations mula rate included in Attachment 0 under the MISO tariff. requiring additional NOx reductions from the Companies' The ATSI Network Service net revenue requirement Ohio and Pennsylvania facilities. Various regulatory and judi-increased under the formula rate to approximately $159 cial actions have since sought to further define NOx 30 FirstEnergy Corp. 2004

reduction requirements (see Note 13(C) - Environmental Mercury Emissions Matters). We continue to evaluate our compliance plans and In December 2000, the EPA announced it would pro-

• other compliance options. ceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying Clean Air Act Compliance mercury as the hazardous air pollutant of greatest concern.

The Companies are required to meet federally approved On December 15, 2003, the EPA proposed two different S02 regulations. Violations of such regulations can result in approaches to reduce mercury emissions from coal-fired shutdown of the generating unit involved and/or civil or power plants. The first approach would require plants to criminal penalties of up to $32,500 for each day the unit is install controls known as MACT based on the type of coal in violation. The EPA has an interim enforcement policy for burned. According to the EPA, if implemented, the MACT S02 regulations in Ohio that allows for compliance based on proposal would reduce nationwide mercury emissions from a 30-day averaging period. The Companies cannot predict coal-fired power plants by 14 tons to approximately 34 tons what action the EPA may take in the future with respect to per year. The second approach proposes a cap-and-trade the interim enforcement policy. program that would reduce mercury emissions in two dis-The Companies believe they are complying with S02 tinct phases. Initially, mercury emissions would be reduced reduction requirements under the Clean Air Act Amendments by 2010 as a "co-benefit" from implementation of S02 and of 1990 by burning lower-sulfur fuel, generating more electrici- NOx emission caps under the EPA's proposed Interstate Air ty from lower-emitting plants, and/or using emission Quality Rule. Phase II of the mercury cap-and-trade program allowances. NOx reductions required by the 1990 would be implemented in 2018 to cap nationwide mercury Amendments are being achieved through combustion controls emissions from coal-fired power plants at 15 tons per year.

and the generation of more electricity at lower-emitting plants. The EPA has agreed to choose between these two options In September 1998, the EPA finalized regulations requiring and issue a final rule by March 15, 2005. The future cost of additional NOx reductions from the Companies' facilities. The compliance with these regulations may be substantial.

EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx W. H. Sammis Plant emissions from projected 2007 emissions) across a region of In 1999 and 2000, the EPA issued NOV or Compliance

• nineteen states (including Michigan, New Jersey, Ohio and Orders to nine utilities covering 44 power plants, including Pennsylvania) and the District of Columbia based on a conclu- the W. H. Sammis Plant, which is owned by OE and Penn.

sion that such NOx emissions are contributing significantly to In addition, the U.S. Department of Justice filed eight civil ozone levels in the eastern United States. The Companies complaints against various investor-owned utilities, which believe their facilities are also complying with NOx budgets included a complaint against OE and Penn in the U.S.

established under State Implementation Plans (SIP) through District Court for the Southern District of Ohio. These cases combustion controls and post-combustion controls, including are referred to as New Source Review cases. The NOV and Selective Catalytic Reduction and Selective Non-Catalytic complaint allege violations of the Clean Air Act based on

! Reduction systems, and/or using emission allowances. operation and maintenance of the W. H. Sammis Plant dat-ing back to 1984. The complaint requests permanent i National Ambient Air Quality Standards injunctive relief to require the installation of "best available

In July 1997, the EPA promulgated changes in the control technology" and civil penalties of up to $27,500 per NAAOS for ozone and proposed a new NAAQS for fine par- day of violation. On August 7, 2003, the United States ticulate matter. On December 17, 2003, the EPA proposed District Court for the Southern District of Ohio ruled that 11 the "Interstate Air Quality Rule" covering a total of 29 projects undertaken at the W. H. Sammis Plant between states (including Michigan, New Jersey, Ohio and 1984 and 1998 required pre-construction permits under the Pennsylvania) and the District of Columbia based on pro- Clean Air Act. The ruling concludes the liability phase of the

, posed findings that air pollution emissions from 29 eastern case, which deals with applicability of Prevention of states and the District of Columbia significantly contribute to Significant Deterioration provisions of the Clean Air Act. The nonattainment of the NAAQS for fine particles and/or the remedy phase of the trial to address any civil penalties and "8-hour" ozone NAAOS in other states. The EPA has pro- what, if any, actions should be taken to further reduce emis-posed the Interstate Air Quality Rule to "cap-and-trade" sions at the plant has been delayed without rescheduling by NOx and S02 emissions in two phases (Phase I in 2010 and the Court because the parties are engaged in meaningful Phase II in 2015). According to the EPA, S02 emissions settlement negotiations. The Court indicated, in its August would be reduced by approximately 3.6 million tons annually 2003 ruling, that the remedies it "may consider and impose by 2010, across states covered by the rule, with reductions involved a much broader, equitable analysis, requiring the ultimately reaching more than 5.5 million tons annually. NOx Court to consider air quality, public health, economic impact, emission reductions would measure about 1.5 million tons and employment consequences. The Court may also consid-

in 2010 and 1.8 million tons in 2015. The future cost of er the less than consistent efforts of the EPA to apply and compliance with these proposed regulations may be sub- further enforce the Clean Air Act." The potential penalties

stantial and will depend on whether and how they are that may be imposed, as well as the capital expenditures ultimately implemented by the states in which the necessary to comply with substantive remedial measures Companies operate affected facilities. that may be required, could have a material adverse impact FirstEnergy Corp 2004 31

on FirstEnergy's, OE's and Penn's respective financial condi- impact of climate change policies, although the potential tion and results of operations. While the parties are engaged restrictions on C02 emissions could require significant capi-in meaningful settlement discussions, management is tal and other expenditures. However, the C02 emissions unable to predict the ultimate outcome of this matter and per kilowatt-hour of electricity generated by the Companies no liability has been accrued as of December 31, 2004. is lower than many regional competitors due to the Companies' diversified generation sources which includes Regulation of Hazardous Waste low or non-C02 emitting gas-fired and nuclear generators.

As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Clean Water Act Act of 1976, federal and state hazardous waste regulations Various water quality regulations, the majority of which have been promulgated. Certain fossil-fuel combustion are the result of the federal Clean Water Act and its amend-waste products, such as coal ash, were exempted from haz- ments, apply to the Companies' plants. In addition, Ohio, ardous waste disposal requirements pending the EPA's New Jersey and Pennsylvania have water quality standards evaluation of the need for future regulation. The EPA subse- applicable to the Companies' operations. As provided in the quently determined that regulation of coal ash, as a Clean Water Act, authority to grant federal National Pollutant hazardous waste is unnecessary. In April 2000, the EPA Discharge Elimination System water discharge permits can announced that it will develop national standards regulating be assumed by a state. Ohio, New Jersey and Pennsylvania disposal of coal ash under its authority to regulate nonhaz- have assumed such authority.

ardous waste. On September 7, 2004, the EPA established new per-The Companies have been named as PRPs at waste dis- formance standards under Clean Water Act Section 316(b) posal sites, which may require cleanup under the for reducing impacts on fish and shellfish from cooling Comprehensive Environmental Response, Compensation and water intake structures at certain existing large electric gen-Liability Act of 1980. Allegations of disposal of hazardous sub- erating plants. The regulations call for reductions in stances at historical sites and the liability involved are often impingement mortality, when aquatic organisms are pinned unsubstantiated and subject to dispute: however, federal law against screens or other parts of a cooling water intake sys-provides that all PRPs for a particular site are liable on a joint tem and entrainment, which occurs when aquatic species and several basis. Therefore, environmental liabilities that are are drawn into a facility's cooling water system. The considered probable have been recognized on the Companies are conducting comprehensive demonstration Consolidated Balance Sheets as of December 31, 2004, based studies, due in 2008, to determine the operational meas-on estimates of the total costs of cleanup, the Companies' ures, equipment or restoration activities, if any, necessary proportionate responsibility for such costs and the financial for compliance by their facilities with the performance stan-ability of other nonaffiliated entities to pay. In addition, JCP&L dards. FirstEnergy is unable to predict the outcome of such has accrued liabilities for environmental remediation of former studies. Depending on the outcome of such studies, the manufactured gas plants in New Jersey; those costs are being future cost of compliance with these standards may require recovered by JCP&L through a non-bypassable SBC. Included material capital expenditures.

in Current Liabilities and Other Noncurrent Liabilities are accrued liabilities aggregating approximately $65 million as of OTHER LEGAL PROCEEDINGS December 31, 2004. The Companies accrue environmental Power Outages and Related Litigation liabilities only when they can conclude that it is probable that Three substantially similar actions were filed in various they have an obligation for such costs and can reasonably Ohio state courts by plaintiffs seeking to represent cus-determine the amount of such costs. Unasserted claims are tomers who allegedly suffered damages as a result of the reflected in the Companies' determination of environmental August 14, 2003 power outages. All three cases were dis-liabilities and are accrued in the period that they are both missed for lack of jurisdiction. One case was refiled at the probable and reasonably estimable. PUCO. The other two cases were appealed. One case was dismissed and no further appeal was sought. The remaining Climate Change case is pending. In addition to the one case that was refiled In December 1997, delegates to the United Nations' at the PUCO, the Ohio Companies were named as respon-climate summit in Japan adopted an agreement, the Kyoto dents in a regulatory proceeding that was initiated at the Protocol (Protocol), to address global warming by reducing PUCO in response to complaints alleging failure to provide the amount of man-made greenhouse gases emitted by reasonable and adequate service stemming primarily from developed countries by 5.2% from 1990 levels between the August 14, 2003 power outages.

2008 and 2012. The United States signed the Protocol in One complaint has been filed against FirstEnergy in the 1998 but it failed to receive the two-thirds vote of the New York State Supreme Court. In this case, several plain-United States Senate required for ratification. However, tiffs in the New York City metropolitan area allege that they the Bush administration has committed the United States suffered damages as a result of the August 14, 2003 power to a voluntary climate change strategy to reduce domestic outages. None of the plaintiffs are customers of any greenhouse gas intensity - the ratio of emissions to FirstEnergy affiliate. FirstEnergy filed a motion to dismiss economic output - by 18% through 2012. with the Court on October 22, 2004. No timetable for a deci-The Companies cannot currently estimate the financial sion on the motion to dismiss has been established by the 32 FirstEnergy Corp. 004

Court. No damage estimate has been provided and thus filed against FirstEnergy in connection with, among other potential liability has not been determined. things, the restatements in August 2003 by FirstEnergy and FirstEnergy is vigorously defending these actions, but the Ohio Companies of previously reported results, the cannot predict the outcome of any of these proceedings or August 14, 2003 power outages and the extended outage at whether any further regulatory proceedings or legal actions the Davis-Besse Nuclear Power Station. The settlement may be initiated against the Companies. In particular, if agreement, which does not constitute any admission of FirstEnergy or its subsidiaries were ultimately determined to wrongdoing, provides for a total settlement payment of have legal liability in connection with these proceedings, it $89.9 million. Of that amount, FirstEnergy's in urance carri-could have a material adverse effect on FirstEnergy's or its ers paid $71.92 million, based on a contractual subsidiaries' financial condition and results of operations. pre-allocation, and FirstEnergy paid $17.98 million, which resulted in an after-tax charge against FirstEnergy's second Nuclear PlantMatters quarter earnings of $11 million or $0.03 per share of com-In late 2003, FENOC received a subpoena from a grand mon stock (basic and diluted). On December 30, 2004, the jury in the United States District Court for the Northern court approved the settlement.

District of Ohio, Eastern Division requesting the production of On October 20, 2004, FirstEnergy was notified by the certain documents and records relating to the inspection and SEC that the previously disclosed informal inquiry initiated maintenance of the reactor vessel head at the Davis-Besse by the SEC's Division of Enforcement in September 2003 Nuclear Power Station. FirstEnergy is unable to predict the relating to the restatements in August 2003 of previously outcome of this investigation. On December 10, 2004, reported results by FirstEnergy and the Ohio Companies, FirstEnergy received a letter from the United States and the Davis-Besse extended outage, have become the Attorney's Office stating that FENOC is a target of the federal subject of a formal order of investigation. The SEC's formal grand jury investigation into alleged false statements relating order of investigation also encompasses issues raised dur-to the Davis-Besse Nuclear Power Station outage made to ing the SEC's examination of FirstEnergy and the the NRC in the Fall of 2001 in response to NRC Bulletin 2001- Companies under the PUHCA. Concurrent with this notifica-

• 01. The letter also said that the designation of FENOC as a tion, FirstEnergy received a subpoena asking for background target indicates that, in the view of the prosecutors assigned documents and documents related to the restatements and to the matter, it is likely that federal charges will be returned Davis-Besse issues. On December 30, 2004, FirstEnergy against FENOC by the grand jury. FirstEnergy is unable to pre- received a second subpoena asking for documents relating dict the outcome of this investigation. On February 10, 2005, to issues raised during the SEC's PUHCA examination.

FENOC received an additional subpoena for documents relat- FirstEnergy has cooperated fully with the informal inquiry ed to root cause reports regarding reactor head degradation and will continue to do so with the formal investigation.

• and the assessment of reactor head management issues at If it were ultimately determined that FirstEnergy or its Davis-Besse. In addition, FENOC remains subject to possible subsidiaries have legal liability or are otherwise made sub-civil enforcement action by the NRC in connection with the ject to liability based on the above matter, it could have a events leading to the Davis-Besse outage in 2002. material adverse effect on FirstEnergy's or its subsidiaries' On August 12, 2004, the NRC notified FENOC that it financial condition and results of operations.

will increase its regulatory oversight of the Perry Nuclear i Power Plant as a result of problems with safety system

equipment over the past two years. FENOC operates the CRITICAL ACCOUNTING POLICIES Perry Nuclear Power Plant, which is either owned or leased We prepare our consolidated financial statements in by OE, CEI, TE and Penn. Although the NRC noted that the accordance with GAAR Application of these principles often plant continues to operate safely, the agency has indicated requires a high degree of judgment, estimates and assump-that its increased oversight will include an extensive NRC tions that affect financial results. All of our assets are team inspection to assess the equipment problems and the subject to their own specific risks and uncertainties and are sufficiency of FENOC's corrective actions. The outcome of regularly reviewed for impairment. Our more significant these matters could include NRC enforcement action or accounting policies are described below.

other impacts on operating authority. As a result, these matters could have a material adverse effect on Regulatory Accounting FirstEnergy's or its subsidiaries' financial condition. Our regulated services segment is subject to regulation that sets the prices (rates) we are permitted to charge our Other Legal Matters customers based on costs that the regule tory agencies deter-Various lawsuits, claims (including claims for asbestos mine we are permitted to recover. At times, regulators permit exposure) and proceedings related to FirstEnergy's normal the future recovery through rates of costs that would be cur-business operations are pending against FirstEnergy and its rently charged to expense by an unregulated company. This subsidiaries. The most significant not otherwise discussed ratemaking process results in the recording of regulatory above are described below. assets based on anticipated future cash inflows. We regularly On July 27, 2004, FirstEnergy announced that it had review these assets to assess their ultimate recoverability reached an agreement to resolve pending lawsuits alleging within the approved regulatory guidelines. Impairment risk violations of federal securities laws and related state laws associated with these assets relates to potentially adverse FirsrEnergy Corp. 2004 33

legislative, judicial or regulatory actions in the future. 24.2% and (11.3)%, respectively. Our pension costs in 2004 were computed assuming a 9.0% rate of return on plan Revenue Recognition assets based upon projections of future returns and our We follow the accrual method of accounting for rev- pension trust investment allocation of approximately 68%

enues, recognizing revenue for electricity that has been equities, 29% bonds, 2% real estate and 1% cash.

delivered to customers but not yet billed through the end of In the third quarter of 2004, we made a $500 million the accounting period. The determination of electricity sales voluntary contribution to our pension plan. Prior to this to individual customers is based on meter readings, which contribution, projections indicated that cash contributions occur on a systematic basis throughout the month. At the of approximately $600 million would have been required end of each month, electricity delivered to customers since during the 2006 to 2007 time period under minimum the last meter reading is estimated and a corresponding funding requirements established by the IRS. Our election accrual for unbilled sales is recognized. The determination of to pre-fund the plan is expected to eliminate that funding unbilled sales requires management to make estimates requirement.

regarding electricity available for retail load, transmission As a result of our voluntary contribution and the and distribution line losses, demand by customer class, increased market value of pension plan assets, we reduced weather-related impacts, prices in effect for each customer our accrued benefit cost as of December 31, 2004 by $424 class and electricity provided by alternative suppliers. million. As prescribed by SFAS 87, we reduced our additional minimum liability by $15 million, recording a decrease in Pension and Other Postretirement Benefits Accounting an intangible asset of $9 million and crediting OCI by $6 Our reported costs of providing non-contributory defined million. The balance in AOCL of $296 million (net of $208 pension benefits and postemployment benefits other than million in deferred taxes) will reverse in future periods to the pensions are dependent upon numerous factors resulting extent the fair value of trust assets exceeds the accumulated from actual plan experience and certain assumptions. benefit obligation.

Pension and OPEB costs are affected by employee Health care cost trends have significantly increased and demographics (including age, compensation levels, and will affect future OPEB costs. The 2004 and 2005 composite employment periods), the level of contributions we make to health care trend rate assumptions are approximately 10%-

the plans, and earnings on plan assets. Such factors may be 12% and 9%-11 %, respectively, gradually decreasing to 5%

further affected by business combinations, which impact in later years. In determining our trend rate assumptions, employee demographics, plan experience and other factors. we included the specific provisions of our health care plans, Pension and OPEB costs are also affected by changes to the demographics and utilization rates of plan participants, key assumptions, including anticipated rates of return on actual cost increases experienced in our health care plans, plan assets, the discount rates and health care trend rates and projections of future medical trend rates. The effect on used in determining the projected benefit obligations for our pension and OPEB costs and liabilities from changes in pension and OPEB costs. key assumptions are as follows:

In accordance with SFAS 87, changes in pension and OPEB obligations associated with these factors may not be Increase inCosts from Adverse Changes inKey Assumptions immediately recognized as costs on the income statement, Assumption Adverse Change Pension .OPEB Total but generally are recognized in future years over the remain- (Inmillions)

Discount rate Decrease by 0.25* Slo $5 S15 ing average service period of plan participants. SFAS 87 and Long-term return on assets Decrease by 0.25* $10 S1 S11 SFAS 106 delay recognition of changes due to the long-term Health care trend rate Increase by 1% na $19 $19 nature of pension and OPEB obligations and the varying Increase inMinimum Liability market conditions likely to occur over long periods of time.

Discount rate Decrease by 0.25% $110 na S110 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- Ohio Transition Cost Amortization cantly influenced by assumptions about future market In connection with the Ohio Companies' transition plan, conditions and plan participants' experience. the PUCO determined allowable transition costs based on In selecting an assumed discount rate, we consider cur- amounts recorded on the regulatory books of the Ohio rently available rates of return on high-quality fixed income Companies. These costs exceeded those deferred or capi-investments expected to be available during the period to talized on FirstEnergy's balance sheet prepared under GAAP maturity of the pension and other postretirement benefit obli- since they included certain costs which had not yet been gations. Due to recent declines in corporate bond yields and incurred or that were recognized on the regulatory financial interest rates in general, we reduced the assumed discount statements (fair value purchase accounting adjustments).

rate as of December 31, 2004 to 6.00% from 6.25% and FirstEnergy uses an effective interest method for amortizing 6.75% used as of December 31, 2003 and 2002, respectively. its transition costs, often referred to as a "mortgage-style" Our assumed rate of return on pension plan assets con- amortization. The interest rate under this method is equal to siders historical market returns and economic forecasts for the rate of return authorized by the PUCO in the transition the types of investments held by our pension trusts. In plan for each respective company. In computing the transi-2004, 2003 and 2002, plan assets actually earned 11.1 %, tion cost amortization, FirstEnergy includes only the portion 34 FirstEnergy Corp. 2004

of the transition revenues associated with transition costs 2004, the FSG subsidiaries qualified as held for sale in included on the balance sheet prepared under GAAR accordance with SFAS 144. As required by SFAS 142, the Revenues collected for the off-balance sheet costs and goodwill of FSG was tested for impairment, resulting in a the return associated with these costs are recognized as non-cash charge of $36 million in the fourth quarter of 2004.

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

Long-LivedAssets Unanticipated changes in those assumptions could have a In accordance with SFAS 144, we periodically evaluate significant effect on our future evaluations of goodwill.

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 NEW ACCOUNTING STANDARDS that if the sum of future cash flows (undiscounted) expect- AND INTERPRETATIONS ed to result from an asset is less than the carrying value of SFAS 123 (revised 2004) "Share-Based Payment' the asset, an asset impairment must be recognized in the In December 2004, the FASB issued this revision to financial statements. If impairment has occurred, we recog- SFAS 123, which requires expensing stock options in the nize a loss - calculated as the difference between the financial statements. Important to applying the new stan-carrying value and the estimated fair value of the asset (dis- dard is understanding how to (1) measure the fair value of counted future net cash flows). stock-based compensation awards and (2) recognize the The calculation of future cash flows is based on related compensation cost for those awards. For an award assumptions, estimates and judgment about future events. to qualify for equity classification, it must meet certain crite-The aggregate amount of cash flows determines whether ria in SFAS 123(R). An award that does not meet those an impairment is indicated. The timing of the cash flows is criteria will be classified as a liability and remeasured each critical in determining the amount of the impairment. period. SFAS 123(R) retains SFAS 123's requirements on accounting for income tax effects of stock-based compensa-Nuclear Decommissioning tion. The effective date for FirstEnergy is July 1, 2005 and In accordance with SFAS 143, we recognize an ARO for the Company will be applying modified prospective applica-the future decommissioning of our nuclear power plants. tion, without restatement of prior interim periods. Any The ARO liability represents an estimate of the fair value of potential cumulative adjustments have not been deter-our current obligation related to nuclear decommissioning mined. FirstEnergy uses the Black-Scholes option pricing and the retirement of other assets. A fair value measure- model to value options and will continue to do so upon ment inherently involves uncertainty in the amount and adoption of SFAS 123(R). The impacts of the fair value timing of settlement of the liability. We used an expected recognition provisions of SFAS 123 on FirstEnergy's net cash flow approach to measure the fair value of the nuclear income and earnings per share for 2002 through 2004 are decommissioning ARO. This approach applies probability disclosed in Note 4 to the consolidated financial statements.

weighting to discounted future cash flow scenarios that FirstEnergy is considering alternative compensation strate-reflect a range of possible outcomes. The scenarios consid- gies in conjunction with the adoption of SFAS 123(R).

er settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an EITF Issue No. 03-1, "The Meaning of Other-Than-extended license term. Temporary Impairment and its Applicationto Certain Investments" Goodwill In March 2004, the EITF reached a consensus on the In a business combination, the excess of the purchase application guidance for EITF 03-1, which provides a model price over the estimated fair values of the assets acquired for determining when investments in certain debt and equi-and liabilities assumed is recognized as goodwill. Based on ty securities are considered other than temporarily impaired.

the guidance provided by SFAS 142, we evaluate goodwill When an impairment is other-than-temporary, the invest-for impairment at least annually and make such evaluations ment must be measured at fair value and the impairment more frequently if indicators of impairment arise. In accor- loss recognized in earnings. The recognition and measure-dance with the accounting standard, if the fair value of a ment provisions of EITF 03-1, which were to be effective for reporting unit is less than its carrying value (including good- periods beginning after June 15, 2004, were delayed by the will), the goodwill is tested for impairment. If an impairment issuance of FSP EITF 03-1-1 in September 2004. During the is indicated we recognize a loss - calculated as the differ- period of delay, FirstEnergy will continue to evaluate its ence between the implied fair value of a reporting unit's investments as required by existing authoritative guidance.

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 FirstEnergy Corp. 2004 35

CONSOLIDATED STATEMENTS OF INCOME (Inthousands, except per share amounts)

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

Electric utilities S9,064,853 S8,962,201 $9,165,805 Unregulated businesses 3,388,193 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 677.757 637,967 649,400 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 666,777 809,380 955,870 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 $72,516,000) (Note 2(K)) - 102,147 Net Income S 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 S 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 S 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 Consolidated Financial Statements are an integral part of these statements.

36 FirstEnergy Corp. 2004

CONSOLIDATED BALANCE SHEETS (Inthousands)

As of December 31, 2004 2003 ASSETS Current Assets:

Cash and cash equivalents $ 52Z941 $ 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 Inservice 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 inprogress 678,868 779,479 13,478,356 13,268,922 Investments:

Nuclear plant decommissioning trusts 1,582,588 1,351,650 Investments inlease 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 S32,909,948 LIABILITIES AND CAPITALIZATION Current Liabilities:

Currently payable long-term debt S 940,944 S 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 S32,909,948 The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

FirstEnergy Corp. 2004 37

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

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

Common stock, SO.10 par value -authorized 375,000,000 shares- 329,836,276 shares outstanding S32,984 $ 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 2,896,951 shares, respectively (Note 4(B)) (43,117) (58,204)

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,D00 6,000 7.75% 250,000 250,000 100.00 25,000 25,W0 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 125,000 125,000 106.50 13.313 1Z649 12,649 38 FirstEnergy Corp. 2004

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Continued)

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

First Mortgage Bonds Secured Notes Unsecured Notes Total As of December31, 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 85,250 382,701 539,701 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 FirstEnergy Corp. 2004 39

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Continued)

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

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 _ S18,937,766 $18,413,530 The accompanying Notes to ConsolidatedFinancial Statements are an integral part of these statements.

40 FirstEnergyCorp. 2004

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (Dollars inthousands)

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 5(3,796,000) of income taxes 15,269) (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 1439.628)

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) 1347)

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 (453,3601 Balance, December 31, 2003 329,836,276 32,984 7,062,825 (352,649) 1,604,385 158,204)

Net income $ 878,175 878,175 Minimum liability for unfunded retirement benefits, net of $(4,698,000) of income taxes (6,256) 16,256)

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 in2004 payable in 2005 (135,168)

Cash dividends on common stock (490,529)

Balance, December 31, 2004 329,836,276 $32,984 $7,055,676 $ (313,112) S1,856,863 $ (43,117)

The accompanying Notes to ConsolidatedFinancialStatements are an integralpart of these statements.

FirstEnergy Corp. 2004 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 December 3?.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 FirstEnergy Corp. 2004

CONSOLIDATED STATEMENTS OF CASH FLOWS (Inthousands)

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 (256,795) (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)) 36,471 116,968 -

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) inoperating 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) inoperating liabilities:

Accounts payable (110,947) (169,652) 218,226 Accrued taxes (15,011) 221,500 25,183 Accrued interest (41,656) (59,782) (29,6931 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) 1101,218) (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 incash 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 $ 52,941 $ 113,975 $ 225.932 Supplemental Cash Flows Information:

Cash Paid During the Year-Interest (net of amounts capitalized) S 704,067 $ 730,277 $ 881,515 Income taxes S 512,419 $ 161,915 $ 389,180 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

FirstEnergy Corp. 2004 43

CONSOLIDATED STATEMENTS OF TAXES (Inthousands)

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 S 677,852 $ 638,465 $ 650,329 Provision For Income Taxes:

Currently payable-Federal $ 283,341 $ 306,347 $ 326,417 State 132,356. 118,155 104,867 Foreign . (1,165) 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 (26,672) (26,404) (26,507)

Total provision for income taxes $ 673,960 $ 476,976 $ 528,694 Reconciliation of Federal Income Tax Expense at Statutory Rate to Total Provision For Income Taxes:

Book income before provision for income taxes $ 1,552,135 $ 899,740 $ 1,081,498 Federal income tax expense at statutory rate $ 543,247 $ 314,909 $ 378,524 Increases (reductions) intaxes 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 3Z683 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 S 673,960 $ 476,976 $ 528,694 Accumulated Deferred Income Taxes at December 31:

Property basis differences S2,451,213 $ 2,293,209 S2,052,594 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 (9Z417) (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 (185,573) (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) (2,657)

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 $ 2,324,097 $ 2,178,075 $ 2,069,682

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

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

44 FirstEnergy Corp. 2004

Notes To Consolidated Financial Statements

1. Organization and Basis of Presentation costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those FirstEnergy's principal business is the holding, directly costs will be recovered in future revenue. SFAS 71 is or indirectly, of all of the outstanding common stock of its applied only to the parts of the business that meet the eight principal electric utility operating subsidiaries: OE, CEI, above criteria. If a portion of the business applying SFAS 71 TE, Penn, ATSI, JCP&L, Met-Ed and Penelec. Penn is a no longer meets those requirements, previously recorded wholly owned subsidiary of OE. FirstEnergy's consolidated regulatory assets are removed from the balance sheet in financial statements also include its other subsidiaries: accordance with the guidance in SFAS 101.

FENOC, FES and its subsidiary FGCO, FESC, FirstCom, In Ohio, New Jersey and Pennsylvania, laws applicable FSG, GPU Capital, GPU Power and MYR. to electric industry restructuring contain similar provisions, FirstEnergy and its subsidiaries follow GAAP and com- that are reflected in the Companies' respective state regula-ply with the regulations, orders, policies and practices tory plans. These provisions include:

prescribed by the SEC, FERC and, as applicable, the PUCO,

• restructuring the electric generation business and allow-PPUC and NJBPU. The preparation of financial statements ing the Companies' customers to select a competitive in conformity with GAAP requires management to make electric generation supplier other than the Companies; periodic estimates and assumptions that affect the reported

• establishing or defining the PLR obligations to amounts of assets, liabilities, revenues and expenses and customers in the Companies' service areas; the disclosure of contingent assets and liabilities. Actual

• providing the Companies with the opportunity to recover results could differ from these estimates. potentially stranded investment (or transition costs) not FirstEnergy consolidates all majority-owned subsidiaries otherwise recoverable ina competitive generation market; over which the Company exercises control and, when applica-

• itemizing (unbundling) the price of electricity into its ble, entities for which the Company has a controlling financial component elements - including generation, transmis-interest. Intercompany transactions and balances are eliminated sion, distribution and stranded costs recovery charges; in consolidation. Investments in nonconsolidated affiliates (20-50

• continuing regulation of the Companies' transmission percent owned companies, joint ventures and partnerships) and distribution systems; and over which the Company has the ability to exercise significant

• requiring corporate separation of regulated and influence, but not control, are accounted for on the equity basis. unregulated business activities.

Certain prior year amounts have been reclassified to con-form to the current year presentation. Revenue amounts Regulatory Assets related to transmission activities previously recorded as whole- The EUOC recognize, as regulatory assets, costs which sale electric sales revenues were reclassified as transmission the FERC, PUCO, PPUC and NJBPU have authorized for recov-revenues. Expenses (including transmission and congestion ery from customers in future periods or for which authorization charges) were reclassified among purchased power, other is probable. Without the probability of such authorization, costs operating costs and amortization of regulatory assets to con- currently recorded as regulatory assets would have been

form to the current year presentation of generation commodity charged to income as incurred. All regulatory assets are expect-costs. FES' natural gas business has been classified as discon- ed to be recovered from customers under the Companies' tinued operations on the Consolidated Statements of Income respective transition and regulatory plans. Based on those (See Note 2(J)). As discussed in Note 14, segment reporting in plans, the Companies continue to bill and collect cost-based 2003 and 2002 was reclassified to conform to the 2004 busi- rates for their transmission and distribution services, which ness segment organization and operations. remain regulated; accordingly, it is appropriate that the Unless otherwise indicated, defined terms used herein have Companies continue the application of SFAS 71 to those opera-the meanings set forth in the accompanying Glossary of Terms. 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

2. Summary of Significant Sheets are comprised of the following:

Accounting Policies 2004 2003 (A) ACCOUNTING FOR THE EFFECTS OF REGULATION (Inmillions)

Regulatory transition costs $4,889 $6,427 FirstEnergy accounts for the effects of regulation Customer shopping incentives 612 371 through the application of SFAS 71 to its operating utilities I Customer receivables for future income taxes 246 340 I Societal benefits charge 51 81 when their rates: i Loss on reacquired debt 89 75

• are established by a third-party regulator with the Employee postretirement benefit costs 65 77 authority to set rates that bind customers; Nuclear decommissioning, decontamination and spentfueldisposalcosts (169) 1961

• are cost-based; and Asset removal costs (3401 (3211

• can be charged to and collected from customers. Property losses and unrecovered plant costs 50 70 Other 39 53 Total $5,532 $7.077 An enterprise meeting all of these criteria capitalizes FirstEnergy Corp. 2004 45

The Ohio Companies are deferring customer shopping TE, respectively) were recognized as regulatory assets incentives and interest costs as new regulatory assets in recoverable as transition costs through future regulatory accordance with the transition and rate stabilization plans. cash flows. The following summarizes net assets included These regulatory assets (OE - $228 million, CEI - $295 mil- in property, plant and equipment relating to operations for lion, TE - $89 million, as of December 31, 2004) will be which the application of SFAS 71 was discontinued, com-recovered through a surcharge rate equal to the RTC rate in pared with the respective company's total assets as of effect when the transition costs have been fully recovered. December 31, 2004.

Recovery of the new regulatory assets will begin at that time and amortization of the regulatory assets for each accounting SFAS 71 Discontinued Net Assets Total Assets period will be equal to the surcharge revenue recognized dur- (Inmillions) ing that period. OE, TE and CEI expect to recover these OE 31,059 55.814 CEI 1,263 6.690 deferred customer shopping incentives by August 31, 2008, TE 652 2.834 September 30, 2008 and August 31, 2010, respectively. Penn 263 921 JCP&L 39 7.291 Met-Ed 13 3.245 Transition Cost Amortization OE, CEI and TE amortize transition costs (see Regulatory Matters - Ohio) using the effective interest (B) CASH AND SHORT-TERM FINANCIAL INSTRUMENTS method. Under the Rate Stabilization Plan, total transition All temporary cash investments purchased with an cost amortization is expected to approximate the following initial maturity of three months or less are reported as cash for 2005 through 2009. equivalents on the Consolidated Balance Sheets at cost, FirstEnergy GE CEI TE which approximates their fair market value.

(Inmillions) 2005 5828 3467 3222 3139 (C) REVENUES AND RECEIVABLES 2006 404 193 126 85 The Companies' principal business is providing electric 2007 327 93 139 95 2008 159 - 159 - service to customers in Ohio, Pennsylvania and New Jersey.

2009 54 - 54 - The Companies' retail customers are metered on a cycle basis. Electric revenues are recorded based on energy deliv-The decrease in amortization beginning in 2006 results ered through the end of the calendar month. An estimate of from the termination of generation-related transition cost unbilled revenues is calculated to recognize electric service recovery under the Ohio transition plan. provided between the last meter reading and the end of Regulatory transition costs as of December 31, 2004 for the month. This estimate includes many factors including JCP&L, Met-Ed and Penelec are approximately $2.2 billion, estimated weather impacts, customer shopping activity, his-

$0.7 billion and $0.1 billion, respectively. Deferral of above- torical line loss factors and prices in effect for each class of market costs from power supplied by NUGs to JCP&L are customer. In each accounting period, the Companies accrue approximately $1.2 billion and are being recovered through the estimated unbilled amount receivable as revenue and BGS and MTC revenues. Met-Ed and Penelec have deferred reverse the related prior period estimate.

above-market NUG costs totaling approximately $0.5 billion Receivables from customers include sales to residential, and $0.1 billion, respectively. These costs are being recovered commercial and industrial customers and sales to wholesale through CTC revenues. The regulatory asset for above-market customers. There was no material concentration of receivables NUG costs and a corresponding liability are adjusted to fair as of December 31, 2004 or 2003, with respect to any par-value at the end of each quarter. Recovery of the remaining ticular segment of FirstEnergy's customers. Total customer regulatory transition costs is expected to continue under the receivables were $979 million (billed - $672 million and provisions of the various regulatory proceedings for New unbilled - $307 million) and $1.0 billion (billed - $664 million Jersey and Pennsylvania discussed in Note 9. and unbilled - $336 million) as of December 31, 2004 and 2003, respectively.

Accounting for Generation Operations Other receivables include amounts due from customers The application of SFAS 71 was discontinued prior to for unregulated sales and CEl's retained interest in customer 2001 with respect to the Companies' generation operations. receivables sold to CFC (see Note 12).

The SEC's interpretive guidance regarding asset impairment measurement provided that any supplemental regulated (D) ACCOUNTING FOR CERTAIN WHOLESALE cash flows such as a CTC should be excluded from the ENERGY TRANSACTIONS cash flows of assets in a portion of the business not subject FES engages in purchase and sale transactions in the to regulatory accounting practices. If those assets are PJM Market to support the supply of end-use customers, impaired, a regulatory asset should be established if the including its BGS obligation in New Jersey and PLR require-costs are recoverable through regulatory cash flows. ments in Pennsylvania. FES meets its supply commitments Consistent with the SEC guidance and EITF 97-4, $1.8 by transmitting energy into the PJM control area and through billion of impaired plant investments ($1.2 billion, $227 bilateral purchased power contracts with counterparties in million, $304 million and $53 million for OE, Penn, CEI and PJM. FES schedules purchase and sale transactions for each 46 FirstEnergy Corn 2004

hour in PJM on a day-ahead basis with system balancing taxes, employee benefits, administrative and general costs, occurring real-time. FES sells energy to the PJM Market at and interest costs incurred to place the assets in service.

the location of its supply (transmitted and contracted energy) The costs of normal maintenance, repairs and minor and purchases energy from the PJM Market at the location replacements are expensed as incurred. FirstEnergy's of its demand (end-use customer load). accounting policy for planned major maintenance projects is FES accounts for energy transactions in the PJM Market to recognize liabilities as they are incurred.

in accordance with EITF 99-19, recognizing purchases and The Companies provide for depreciation on a straight-sales on a gross basis by recording each discrete transaction. line basis at various rates over the estimated lives of This presentation may not be comparable to other energy property included in plant in service. The respective annual companies that have dedicated generating capacity in ISOs or composite rates for the Companies' electric plant in 2004, fail to meet the criteria for gross presentation in EITF 99-19. 2003 and 2002 are shown in the following table:

FES' purchase and sale transactions in the PJM Market for the three years ended December 31, 2004 are summa- Annual Composite Depreciation Rate 2004 2003 2002 OE 2.3% 2.2% 2.4w rized as follows: CEI 2.8 2.8 3.6 TE 2.8 2.8 3.8 2004 2003 2002 Penn 2.2 2.2 2.3 JCP&L 2.1 2.8 3.5 (Inmillions)

Met-Ed 2.4 2.6 3.0 Sales $1,182 S665 5 272 Penelec 2.5 2.7 3.0 Purchases 1,107 B26 376 Jointly-Owned Generating Stations (E) EARNINGS PER SHARE JCP&L holds a 50 percent ownership interest in Yards Basic earnings per share are computed using the weight- Creek Pumped Storage Facility - its net book value was ed average of actual common shares outstanding during the approximately $19.2 million as of December 31, 2004. All respective period as the denominator. The denominator for other generating units are owned and/or leased by the diluted earnings per share reflects the weighted average of Companies individually or together as tenants in common.

common shares outstanding plus the potential additional common shares that could result if dilutive securities and Asset Retirement Obligations other agreements to issue common stock were exercised. In FirstEnergy recognizes a liability for retirement obliga-2004, 2003 and 2002, stock-based awards to purchase tions associated with tangible assets in accordance with shares of common stock totaling 0.1 million, 3.3 million and SFAS 143. This standard requires recognition of the fair 3.4 million, respectively, were excluded from the calculation value of a liability for an ARO in the period in which it is of diluted earnings per share of common stock because their incurred. The associated asset retirement costs are capital-exercise prices were greater than the average market price of ized as part of the carrying value of the long-lived asset and common shares during the period. The following table recon- depreciated over time, as described further in Note 11, ciles the denominators for basic and diluted earnings per "Asset Retirement Obligations".

share from Income Before Discontinued Operations and Cumulative Effect of Accounting Change: Nuclear Fuel Property, plant and equipment includes nuclear fuel Reconciliation of Basic and Diluted recorded at original cost, which includes material, enrich-Earnings per Share 2004 2003 2002 ment, fabrication and interest costs incurred prior to reactor (inthousands)

Income Before Discontinued Operations load. The Companies amortize the cost of nuclear fuel and Cumulative Effect of based on the units of production method.

Accounting Change 5873.779 $424,249 $618,385 Average Shares of Common Stock Outstanding: (G) STOCK-BASED COMPENSATION Denominator for basic earnings per share FirstEnergy applies the recognition and measurement (weighted average shares outstanding) 327.387 303,582 293.194 Assumed exercise of dilutive stock principles of APB 25 and related Interpretations in account-options and awards 1.595 1,390 1.227 ing for its stock-based compensation plans (see Note 4).

Denominator for diluted earnings per share 328,982 304,972 294,421 No material stock-based employee compensation expense Income Before Discontinued is reflected in net income for options as all options granted Operations and Cumulative Effect of Accounting Change under those plans had an exercise price equal to the market per common share: value of the underlying common stock on the grant date, Basic $2.67 $1.40 $2.11 resulting in substantially no intrinsic value. FirstEnergy will Diluted $2.66 $1.40 $2.10 apply the recognition and measurement principles of SFAS 123R effective July 1, 2005 (see Note 15).

IF) PROPERTY, PLANT AND EQUIPMENT (H) ASSET IMPAIRMENTS Property, plant and equipment reflects original cost Long-Lived Assets (except for nuclear generating assets which were adjusted FirstEnergy evaluates the carrying value of its long-lived to fair value), including payroll and related costs such as assets when events or circumstances indicate that the car-FirstEnergy Corp. 2004 47

rying amount may not be recoverable. In accordance with representing the Companies' recovery of transition costs as SFAS 144, the carrying amount of a long-lived asset is not described in Note 9. FirstEnergy estimates that completion recoverable if it exceeds the sum of the undiscounted cash of transition cost recovery will not result in an impairment of flows expected to result from the use and eventual disposi- goodwill relating to its regulated business segment.

tion of the asset. If an impairment exists, a loss is A summary of the changes in FirstEnergy's goodwill for recognized for the amount by which the carrying value of the years ended December 31, 2004 and 2003 is shown the long-lived asset exceeds its estimated fair value. Fair below by segment (See Note 14 - Segment Information):

value is estimated by using available market valuations or the long-lived asset's expected future net discounted cash Competitive Electric flows. The calculation of expected cash flows is based on Regulated Energy Facilities estimates and assumptions about future events. Services Services Services Other Consolidated; (Inmillions)

Goodwill Balance as of Jan. 1.2003 $5.993 S24 $196 $65 $6,278 Impairment charges (122) 1122)

In a business combination, the excess of the purchase FSG divestitures 141) (41) price over the estimated fair values of assets acquired and Other 3 10 13 liabilities assumed is recognized as goodwill. Based on the BalanceasofDec. 31.2003 5.993 24 36 75 6.128 Impairment charges 136) 136) guidance provided by SFAS 142, FirstEnergy evaluates its Adjustments related to goodwill for impairment at least annually and makes such GPU acquisition 142) (42) evaluations more frequently if indicators of impairment arise. Balance as of Dec. 31, 2004 S5.951 $24 S- $75 S6,050 In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including Investments goodwill), the goodwill is tested for impairment. If an impair- The Companies periodically evaluate for impairment ment is indicated, FirstEnergy recognizes a loss - calculated investments that include available-for-sale securities held by as the difference between the implied fair value of a report- their nuclear decommissioning trusts. In accordance with ing unit's goodwill and the carrying value of the goodwill. SFAS 115, securities classified as available-for-sale are eval-FirstEnergy's 2003 annual review resulted in a non-cash uated to determine whether a decline in fair value below the goodwill impairment charge of $122 million in the third quar- cost basis is other than temporary. If the decline in fair value ter of 2003, reducing the carrying value of FSG. Of this is determined to be other than temporary, the cost basis of amount, $117 million was reported as an operating expense the security is written down to fair value. FirstEnergy con-and $5 million was included in the results from discontinued siders, among other factors, the length of time and the operations. The impairment charge reflected the slow down extent to which the security's fair value has been less than in the development of competitive retail markets and cost and the near-term financial prospects of the security depressed economic conditions that affected the value of issuer when evaluating investments for impairment. The fair FSG. The fair value of FSG was estimated using primarily its value and unrealized gains and losses of the Companies' expected discounted future cash flows. investments are disclosed in Note 5.

FirstEnergy's 2004 annual review was completed in the third quarter of 2004 with no impairment indicated. In (I) COMPREHENSIVE INCOME December 2004, the FSG subsidiaries qualified as held for Comprehensive income includes net income as reported sale in accordance with SFAS 144. SFAS 142 requires the on the Consolidated Statements of Income and all other goodwill of a reporting unit to be tested for impairment if changes in common stockholders' equity except those there is a more-likely-than-not expectation that the reporting resulting from transactions with common stockholders.

unit or a significant asset group within the reporting unit will As of December 31, 2004, AOCL consisted of a minimum be sold. As required by SFAS 142, the goodwill of FSG was liability for unfunded retirement benefits of $312 million, tested for impairment, resulting in a non-cash charge of $36 unrealized gains on investments in securities available for million in the fourth quarter of 2004. FSG's fair value was sale of $91 million, and unrealized losses on derivative estimated using current market valuations. instrument hedges of $92 million. As of December 31, The forecasts used in FirstEnergy's evaluations of good- 2003, AOCL consisted of a minimum liability for unfunded will reflect operations consistent with its general business retirement benefits of $306 million, unrealized gains on assumptions. Unanticipated changes in those assumptions investments in securities available for sale of S64 million, could have a significant effect on FirstEnergy's future evalu- and unrealized losses on derivative instrument hedges of ations of goodwill. FirstEnergy's goodwill primarily relates to $111 million. Other comprehensive income of $8 million its regulated services segment. In the year ended was reclassified to net income in 2004, including an $8 December 31, 2004, FirstEnergy adjusted goodwill related million loss on derivative instrument hedges ($5 million to the former GPU companies for interest received on a pre- net of tax) and a $22 million gain on available-for-sale merger income tax refund and for the reversal of tax securities ($13 million net of tax). Other comprehensive valuation allowances related to income tax benefits realized income (loss) reclassified to net income in 2003 and 2002 attributable to prior period capital loss carryforwards that totaled $29 million and $(10) million, respectively. These were used to offset capital gains generated in 2004. The amounts were net of income taxes in 2003 and 2002 of impairment analysis includes a significant source of cash $20 million and $(7) million, respectively.

48 FirstEnergy Corp 2004

J) ASSETS HELD FOR SALE AND these divested businesses included in discontinued operations DISCONTINUED OPERATIONS ("Other" in the table below) for the years ended December In December 2004, the FSG subsidiaries qualified as 2003 and 2002 totaled $(6) million and $5 million, respectively.

held for sale in accordance with SFAS 144. Management Revenues associated with discontinued operations anticipates that the transfer of FSG assets,:with a carrying were $496 million, $655 million and $878 million for 2004, value of $57 million as of December 31, 2004, will qualify 2003 and 2002, respectively. The following table summa-for recognition as completed sales within one year. As rizes the net income (loss) included in 'Discontinued required by SFAS 142, the goodwill of FSG was tested for Operations" on the Consolidated Statements of Income for impairment, resulting in a non-cash charge of $36 million in the three years ended December 31, 2004:

the fourth quarter of 2004 (See Note 2(H)). As of December 31, 2004, the FSG subsidiaries classified as held for sale did 2004 2003 2002 not meet the criteria for discontinued operations. The carry- i (Inmillions)

FES'natural gas business S4 S (2) S 15 ing amounts of FSG's assets and liabilities held for sale are EGSA - (35) 5 not material to and have not been classified as assets held Emdersa - (60) 187) for sale on FirstEnergy's Consolidated Balance Sheets. See Other - (16) 2 Discontinued operations income (loss) $4 $(103) $165)

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 (K) CUMULATIVE EFFECT OF ACCOUNTING CHANGE short-term and long-term supply agreements. In December As a result of adopting SFAS 143 in January 2003, 2004, FES' natural gas business qualified as held for sale in FirstEnergy recorded a $175 million increase to income, accordance with SFAS 144. Management expects to complete $102 million net of tax, or $0.33 per share of common the sale within one year. As required by SFAS 142, goodwill stock (basic and diluted) in the year ended December 31, associated with FES' natural gas business was tested for 2003. Upon adoption of the accounting standard, impairment as of December 31, 2004 with no impairment indi- FirstEnergy reversed accrued nuclear plant decommissioning cated. Financial results are included in discontinued operations costs of $1.24 billion and recorded an ARO of $1.11 billion, on the Consolidated Statements of Income and classified as including accumulated accretion of $507 million for the peri-

"Other" in the segment financial information (See Note 14). od from the date the liability was incurred to the date of FES' natural gas purchases and sales for the three years adoption. FirstEnergy also recorded asset retirement costs ended December 31, 2004 are summarized as follows: of $602 million as part of the carrying amount of the related long-lived asset and accumulated depreciation of $415 mil-2004 2003 2002 lion. FirstEnergy recognized a regulatory liability of $185 (Inmillions) million for the transition amounts subject to refund through Natural gas sales S496 S603 S594 rates related to the ARO for nuclear decommissioning. The Natural gas purchases 480 583 544 cumulative effect adjustment also included the reversal of

$60 million of accumulated estimated removal costs for In December 2003, EGSA, GPU Power's Bolivia non-regulated generation assets.

subsidiary, was sold to Bolivia Integrated Energy Limited.

FirstEnergy included in discontinued operations a $33 million IL) INCOME TAXES loss on the sale of EGSA in the fourth quarter of 2003 Details of the total provision for income taxes are (no income tax benefit was realized) and an operating loss shown on the Consolidated Statements of Taxes. FirstEnergy for the year of $2 million. Discontinued operations in 2002 records income taxes in accordance with the liability method include EGSA's operating income of $10 million. of accounting. Deferred income taxes reflect the net tax In April 2003, FirstEnergy divested its ownership in effect of temporary differences between the carrying Emdersa through the abandonment of its shares in Emdersa's amounts of assets and liabilities for financial reporting purposes parent company, GPU Argentina Holdings, Inc. The abandon- and the amounts recognized for tax purposes. Investment ment was accomplished by relinquishing FirstEnergy's shares tax credits, which were deferred when utilized, are being to the independent Board of Directors of GPU Argentina amortized over the recovery period of the related property.

Holdings, relieving FirstEnergy of all rights and obligations Deferred income tax liabilities related to tax and accounting relative to this business. FirstEnergy included in discontinued basis differences and tax credit carryforward items are rec-operations Emdersa's operating income of $11 million and ognized at the statutory income tax rates in effect when the a $67 million charge for the abandonment in the second liabilities are expected to be paid. Deferred tax assets are quarter of 2003 (no income tax benefit was recognized). An recognized based on income tax rates expected to be in after-tax loss of $87 million (including $109 million in currency effect when they are settled.

transaction losses arising principally from U.S. dollar denomi- FirstEnergy has capital loss carryforwards of approximately nated debt) was included in discontinued operations in 2002. $1.1 billion, most of which expire in 2007. The deferred tax The FSG subsidiaries, Colonial Mechanical and Webb assets associated with these capital loss carryforwards Technologies, were sold in January 2003 and Ancoma, Inc. was ($364 million) are fully offset by a valuation allowance as of sold in December 2003. The MARBEL subsidiary, NEO was December 31, 2004, since management is unable to predict sold in June 2003. The 2003 and 2002 operating results for FirstEnergy Corp. 2004 49

whether sufficient capital gains will be generated to utilize employee demographics, plan experience and other factors.

all of these capital loss carryforwards. Any ultimate utiliza- Pension and OPEB costs may also be affected by changes tion of capital loss carryforwards for which valuation in key assumptions, including anticipated rates of return on allowances were established through purchase accounting plan assets, the discount rates and health care trend rates would adjust goodwill. used in determining the projected benefit obligations and The Company has also recorded valuation allowances of pension and OPEB costs. FirstEnergy uses a December 31

$51 million for deferred tax assets associated with impair- measurement date for the majority of its plans.

ment losses related to certain domestic assets and the divestiture of international assets acquired through the Obligations and Funded Status As of December 31 merger with GPU (see Note 8). - Pension Benefits Other Benefits FirstEnergy has net operating loss carryforwards for 2004 2003 2004 2003 state and local income tax purposes of approximately $884 (Inmillions) million. A valuation allowance of $5 million has been record- Change in benefit obligation ed against the associated deferred tax assets of $48 Benefit obligation as of January 1 $4,162 $3,866 S 2.368 $ 2,077 Service cost 77 66 36 43 million. These losses expire as follows: Interest cost 252 253 112 136 Plan participants' contributions - - 14 6 Expiration Period Amount Plan amendments - - 1281) (1231 Actuarial Igain) loss 134 222 1211) 323 (inmillions) Benefits paid 1261) 1245) 1108) 194) 2005-2009 5260 2010-2014 46 Benefit obligation as of December31 $4,364 $4.162 S.1,930 32.368 2015-2019 217 2020-2023 361 Change in fair value of plan assets

$884 Fair value of plan assets as of January I S3,315 $2,689 S 537 S 473 Actual return on plan assets 415 671 57 88 l Company contribution 500 - 64 68 Plan participants' contribution - - 14 2

3. Pension and Other Benefits paid 1261) (2451 1108) (94)

Fair value of plan assets Postretirement Benefit Plans asof December31 , $3.969 $3,315 $ 564 S 537 FirstEnergy provides noncontributory defined benefit Funded status S1395) $18471$ 11.366) 5(1,831)

Unrecognized net actuarial loss 885 919 730 994 pension plans that cover substantially all of its employees. Unrecognized prior service cost Ibenefit) 63 72 1378) (221)

The trusteed plans provide defined benefits based on years Unrecognized net transition obligation - - - 83 of service and compensation levels. The Company's funding Net asset (liability) recognized $ 553 S 144 S11,014) S (975) policy is based on actuarial computations using the project-Amounts Recognized in the ed unit credit method. In the third quarter of 2004, Consolidated Balance Sheets FirstEnergy made a $500 million voluntary contribution to its As of December 31 pension plan. Prior to this contribution, projections indicated Accrued benefit cost $114) S(438) 5(1.014) $ (975)

Intangible assets 63 72 - -

that cash contributions of approximately $600 million would Accumulated other comprehensive loss 504 510 - -

have been required during the 2006 to 2007 time period Net amount recognized $553 $ 144 $11,014) $ (975) under minimum funding requirements established by the Increase Idecrease) inminimum liability IRS. The election to pre-fund the plan is expected to elimi- included inother comprehensive income (net of tax) S 14) $1145) nate that funding requirement. Since the contribution is deductible for tax purposes, the after-tax cash impact of the Assumptions Used to Determine voluntary contribution was approximately $300 million. Benefit Obligations As of December31 FirstEnergy provides a minimum amount of noncontrib- Discount rate 6.00' 6.25' 6.00' 6.25%

utory life insurance to retired employees in addition to Rate of compensation increase 3.50' 3.50; optional contributory insurance. Health care benefits, which Allocation of Plan Assets include certain employee contributions, deductibles and As of December 31 copayments, are also available to retired employees, their Asset Category dependents and, under certain circumstances, their sur- Equity securities 68% 70' 74% 71' Debt securities 29 27 25 22 vivors. The Company recognizes the expected cost of Real estate 2 2 - -

providing other postretirement benefits to employees and Cash 1 1 1 7 their beneficiaries and covered dependents from the time Total 100' 100' 100' 100' employees are hired until they become eligible to receive Information for Pension Plans those benefits. With an Accumulated Benefit Pension and OPEB costs are affected by employee Obligation in Excess of Plan Assets 2004 2003 demographics (including age, compensation levels, and employment periods), the level of contributions made to the (Inmillionsl Projected benefit obligation $4,364 $4,162 plans and earnings on plan assets. Such factors may be fur- Accumulated benefit obligation 3.983 3.753 ther affected by business combinations which impact Fair value of plan assets 3,969 3,315 50 FirstEnergy Corp. .'004

Components of Net Periodic Benefit Costs 1-Percentage 1-Percentage Pension Benelits Other Benefits Point Increase Point Decrease 2004 2003 2002 2004 2003 2002 fIn millions) iEffect on total of service and interest cost $ 19 $ (16)

(Inmillions) Effect on postretirement benefit obligation $205 S1179)

Servicecost $77 S 66 $ 59 $ 36 $ 43 S 29 Interest cost 252 253 249 112 137 114 Expected return on plan assets (286) 1248) (346) (44) (43) (52) Pursuant to FSP 106-1 issued January 12, 2004, Amortization of prior service cost 9 9 9 (40) (9) 3 Amortization of transition FirstEnergy began accounting for the effects of the obligation (asset) - - - - 9 9 Medicare Act effective January 1, 2004 because of a plan Recognized net actuarial loss 39 62 - 39 40 11 amendment during the quarter, which required remeasure-Netperiodiccostlincome) $91 $142 S(29) $103 $177 $114 ment of the plan's obligations. The plan amendment, which Weighted-Average Assumptions Used to Determine Net Periodic increases cost sharing by employees and retirees effective Benefit Cost for Years Ended December 31 January 1, 2005, reduced postretirement benefit costs by Pension Benefits Other Benefits $51 million during 2004.

2004 2003 2002 2004 2003 2002 Consistent with the guidance in FSP 106-2 issued on Discount rate 6.25' 6.75' 7.25' 6.25' 6.75' 7.25' May 19, 2004, FirstEnergy recognized a reduction of $318 Expected long-term return on plan assets 9.00% 9.00' 10.25% 9.00% 9.00% 10.25% million in the accumulated postretirement benefit obligation Rate of compensation increase 3.50% 3.50' 4.00% as a result of the federal subsidy provided under the Medicare Act related to benefits for past service. This In selecting an assumed discount rate, FirstEnergy con- reduction was accounted for as an actuarial gain in 2004 siders currently available rates of return on high-quality fixed pursuant to FSP 106-2. The subsidy reduced net periodic income investments expected to be available during the peri- postretirement benefit costs by $48 million during 2004.

od to maturity of the pension and other postretirement As a result of its voluntary contribution and the benefit obligations. The assumed rate of return on pension increased market value of pension plan assets, FirstEnergy plan assets considers historical market returns and economic reduced its accrued benefit cost as of December 31, 2004 forecasts for the types of investments held by the Company's by $424 million. As prescribed by SFAS 87, FirstEnergy pension trusts. The long-term rate of return is developed con- reduced its additional minimum liability by $15 million, sidering the portfolio's asset allocation strategy. recording a decrease in an intangible asset of $9 million and FirstEnergy employs a total return investment approach crediting OCI by $6 million. The balance in AOCL of $296 whereby a mix of equities and fixed income investments are million (net of $208 million in deferred taxes) will reverse in used to maximize the long-term return of plan assets for a future periods to the extent the fair value of trust assets prudent level of risk. Risk tolerance is established through exceeds the accumulated benefit obligation.

careful consideration of plan liabilities, plan funded status, Taking into account estimated employee future service, and corporate financial condition. The investment portfolio FirstEnergy expects to make the following benefit payments contains a diversified blend of equity and fixed-income from plan assets:

investments. Furthermore, equity investments are diversi-Pension Benefits Other Benefits fied across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalizations. Other assets such P (Inmillions) 2005 $ 228 S111 as real estate are used to enhance long-term returns while 2006 228 106 improving portfolio diversification. Derivatives may be used 2007 236 109 2008 247 112 to gain market exposure in an efficient and timely manner; 2009 264 115 however, derivatives are not used to leverage the portfolio Years 2010-2014 1.531 627 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. 4. Stock-Based Compensation Plans Assumed Health Care Cost Trend Rates FirstEnergy has four stock-based compensation pro-As of December 31 2004 2003 grams: Long-term Incentive Program (LTIP); Executive Health care cost trend rate assumed for next Deferred Compensation Plan (EDCP); Employee Stock year (pre/post-Medicare) 9%-11% 10'-12' Rate to which the cost trend rate isassumed to Ownership Plan (ESOP); and the Deferred Compensation decline Ithe ultimate trend rate) 5% 5% Plan for Outside Directors (DCPD). FirstEnergy has also Year that the rate reaches the ultimate trend rate (pre/post-Medicare) 2009-2011 2009-2011 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 Assumed health care cost trend rates have a significant acquisition of GPU. No further stock-based compensation effect on the amounts reported for the health care plans. A can be awarded under GPU's Stock Option and Restricted one-percentage-point change in assumed health care cost Stock Plan for MYR Group Inc. Employees (MYR Plan) or trend rates would have the following effects:

1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock FirstEnergy Corp. 2004 51

under both plans have been converted into FirstEnergy Number of Weighted Average Stock Option Activities Options Exercise Price options and restricted stock. Options under the GPU Plan Balance, January 1,2002 8,447,688 $26.04 became fully vested on November 7, 2001, and will expire on (1,828.341 options exercisablel 24.83 or before June 1, 2010. Under the MYR Plan, all options and Options granted 3,399,579 34.48 restricted stock maintained their original vesting periods, Options exercised 1,018,852 23.56 Options forfeited 392.929 28.19 which range from one to four years, and will expire on or Balance, December 31, 2002 10,435,486 28.95 before December 17, 2006. The Centerior Equity Plan (CE (1,400,206 options exercisable) 26.07 Options granted 3,981,100 29.71 Plan) is an additional stock-based plan administered by Options exercised 455,986 25.94 FirstEnergy for which it assumed responsibility as a result of Options forfeited 311,731 29.09 the acquisition of Centerior Energy Corporation in 1997. All Balance, December 31. 2003 13,648,869 29.27 (1.919.662 options exercisable) 29.67 options are fully vested under the CE Plan, and no further Options granted 3.373.459 38.77 awards are permitted. Outstanding options will expire on or Options exercised 3,622,148 26.52 Options forfeited 167,425 32.58 before February 25, 2007. Balance, December 31, 2004 .13,232,755 32.40 (3,175,023 options exercisable) 29.07 (A) LTIP FirstEnergy's LTIP includes three stock-based compen- Options outstanding by plan and range of exercise price sation programs - restricted stock, stock options, and as of December 31. 2004 were as follows:

performance shares.

Under FirstEnergy's LTIP, total awards cannot exceed Options Options 22.5 million shares of common stock or their equivalent. Outstanding Exercisable Only stock options and restricted stock have currently been Weighted Weighted I Range of Avg. Remaining Avg.

designated to pay out in common stock, with vesting periods Exercise Exercise Contractual Exercise, ranging from two months to seven years. Performance share FEProgram Prices Shares Price Life Shares Price awards are currently designated to be paid in cash rather FEplan S19.31-$29.87 6,972,940 $28.82 7.0 1,903.790 $26.72 S30.17-$39.46 5,907,710 $36.89 -8.3 919.128 $34.37 than common stock and therefore do not count against the Plans acquired limit on stock-based awards. As of December 31, 2004, 4.5 Through merger million shares were available for future awards. GPU plan $23.75-S35.92 341,455 $28.35 4.4 341,455 $28.35 MYR plan S 9.35-S14.23 8.550 $12.70 4.5 8.550 $12.70 CEplan $25.14-S25.15 2,100 $25.14 2.2 2.100 $25.14 Restricted Stock Total 13,232.755 $32.40 7.5 3,175,023 $29.07 Eligible employees receive awards of FirstEnergy com-mon stock subject to restrictions. Those restrictions lapse The weighted average fair value of options granted over a defined period of time or based on performance. in 2004, 2003 and 2002, respectively, are estimated below Dividends are received on the restricted stock and are rein- using the Black-Scholes option-pricing model and the vested in additional shares. Restricted common stock grants following assumptions:

under the FE Plan were as follows:

204 2003 2002 2004 2003* 2002 Fair value per option $6.72 $5.09 $6.45 Restricted common shares granted 62.370 36,922 Weighted average valuation assumptions:

Weighted average market price $40.69 $36.04 Expected option term (years) 7.6 7.9 8.1 Weighted average vesting period (years) 7 3.2 Expected volatility 26.25w 26.91% 23.31%

Dividends restricted Yes Yes Expected dividend yield 3.881 5.09% 4.36%

' No restricted stock was granted Risk-free interest rate 1.99% 3.67% 4.60%

Compensation expense recognized for restricted stock Compensation expense for FirstEnergy stock options is during 2004, 2003 and 2002 totaled $1,982,000, $1,747,000 based on intrinsic value, which equals any positive differ-and $2,259,000, respectively. ence between FirstEnergy's common stock price on the option's grant date and the option's exercise price. The exer-Stock Options cise prices of all stock options granted in 2004, 2003 and Stock option grants are provided to eligible employees 2002 equaled the market price of FirstEnergy's common allowing them to purchase a specified number of common stock on the options' grant dates. If fair value accounting shares at a fixed grant price over a defined period of time. were applied to FirstEnergy's stock options, net income and Stock option activities under the FE Programs for the past earnings per share would be reduced as summarized below.

three years were as follows:

52 FirstEnergy Corp 2004

2004 2003 2002 (C) EDCP (Inthousands, except per share amounts) Under the EDCP, covered employees can direct a portion Net Income, as reported $878.175 $422,764 $552.804 of their compensation, including annual incentive awards and/or Add back compensation expense -.

reported in net income, net of tax  ; long-term incentive awards, into an unfunded FirstEnergy stock (based on APB 25)' 21,177 23,625 22,981 account to receive vested stock units. An additional 20 percent Deduct compensation expense based upon estimated fair value, net of tax' (35.660) (35,816) (31,640) premium is received in the form of stock units based on the Proforma net income $863,692 $410,573 $544,145 amount allocated to the FirstEnergy stock account. Dividends Earnings Per Share of Common Stock - are calculated quarterly on stock units outstanding and are paid Basic in the form of additional stock units. Upon withdrawal, stock As Reported $2.68 $1.39 $1.89 Proforma $2.64 $1.35 $1.86 units are converted to FirstEnergy shares. Payout typically Diluted occurs three years from the date of deferral; however, an elec-As Reported $2.67 $1.39 $1.88 tion can be made in the year prior to payout to further defer Proforma $2.63 $1.35 $1.85 shares into a retirement stock account that will pay out in cash

'Includes restricted stock. stock options, performance shares, ESOP EDCP and DCPO. upon retirement. Of the 1.3 million EDCP stock units author-ized, 776,072 stock units were available for future award as of FirstEnergy anticipates reducing its use of stock options December 31, 2004. Compensation expense recognized on beginning in 2005 and increasing its use of performance-EDCP stock units in 2004, 2003 and 2002 totaled $2,31 1,000, based, restricted stock units. Therefore, the pro forma

$2,312,000 and $206,000, respectively.

effects of applying SFAS 123 may not be representative of its future effect. FirstEnergy has not and does not expect to

{D) DCPD accelerate out-of-the-money options in anticipation of imple-Under the DCPD, directors can elect to allocate all or a menting revisions to SFAS 123 on July 1, 2005 (see Note 15 portion of their cash retainers, meeting fees and chair fees to

- "New Accounting Standards and Interpretations").

a deferred stock or deferred cash accounts. If the funds are deferred into the stock account, a 20 percent match is added Performance Shares to the funds allocated. The 20 percent match and any appreci-Performance shares are share equivalents and do not ation on it are forfeited if the director leaves the Board within have voting rights. The shares track the performance of three years from the date of deferral for any reason other than FirstEnergy's common stock over a three-year vesting peri-retirement, disability, death, upon a change in control, or when od. During that time dividend equivalents are converted into a director is ineligible to stand for re-election. Compensation additional shares. The final account value may be adjusted expense is recognized for the 20 percent match over the based on the ranking of FirstEnergy stock to a composite of three-year investing period. Directors may also elect to defer peer companies. Compensation expense recognized for per-their equity retainers into the deferred stock account, however, formance shares during 2004, 2003 and 2002 totaled they do not receive a 20 percent match for this deferral.

$4,924,000, $7,131,000 and $6,757,000, respectively.

DCPD expenses recognized in 2004, 2003, and 2002 were

$3,556,000, $2,233,000 and $2,728,000, 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- 5. Fair Value of Financial Instruments ered by the ESOP. The ESOP borrowed $200 million from OE and acquired 10,654,114 shares of OE's common stock Long-term Debt and Other Long-term Obligations (subsequently converted to FirstEnergy common stock) All borrowings with initial maturities of less than one through market purchases. Dividends on ESOP shares are year are defined as financial instruments under GAAP and used to service the debt. Shares are released from the are reported on the Consolidated Balance Sheets at cost, ESOP on a pro rata basis as debt service payments are which approximates their fair market value. The following made. In 2004, 2003 and 2002, 864,151 shares, 1,069,318 table provides the approximate fair value and related carry-shares and 1,151,106 shares, respectively, were allocated to ing amounts of long-term debt and other long-term employees with the corresponding expense recognized obligations as of December 31:

based on the shares allocated method. The fair value of 2004 2003 2,032,800 shares unallocated, as of December 31, 2004, Carrying Fair Carrying Fair was approximately $80 million. Total ESOP-related compen- Value Value Value Value sation expense was calculated as follows: (Inmillions)

Long-term debt $10,787 $11,341 $11,177 $11,648 2D04 2003 2D02 Subordinated debentures toaffiliatedtrusts 103 112 294 322

/Inmillions) Preferred stock subject to Base compensation $32 $35 $34 mandatory redemption 17 16 19 19 Dividends on common stock held by the ESOP and used to service debt (91 (9) (8) $10,907 $11,469 $11,490 $11,989 Net expense $23 $26 $26 The fair values of long-term debt and other long-term FirstEnergy Corp 2004 53

obligations reflect the present value of the cash outflows losses on nuclear decommissioning trust investments that are relating to those securities based on the current call price, the deemed to be temporarily impaired as of December 31, 2004:

yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were Less Than 12 Months 12 Months or More Total Fair Unrealized Fair Unrealized Fair Unrealized based on securities with similar characteristics offered by cor- Value Losses Value Losses Value Losses porations with credit ratings similar to the Companies' ratings.

(Inmillions)

Debt securities $175 S3 $20 $- $195 S3 Investments Equity securities 129 12 39 7 168 19 The carrying amounts of cash and cash equivalents $304 $15 S59 $7 $363 $22 approximate fair value due to the short-term nature of these investments. The following table provides the approximate The Companies periodically evaluate the securities held fair value and related carrying amounts of investments other by their nuclear decommissioning trusts for other-than-tem-than cash and cash equivalents as of December 31: porary impairment. FirstEnergy considers the length of time and the extent to which the security's fair value has been 2004 2003 less than its cost basis and other factors to determine Carrying Fair Carrying Fair Value Valt la Value Value whether impairment is other than temporary. Unrealized (inmillionsl gains and losses applicable to the decommissioning trusts Debt securities: (} of FirstEnergy's Ohio Companies are recognized in OCI in

-Government obligations S 797 S 797 S 707 S 707 accordance with SFAS 115, as fluctuations in fair value will

-Corporate debt securities a 1,205 1,362 1,492 1,601

-Mortgage-backed securities 2 2 - - eventually affect earnings. The decommissioning trusts of 2,004 2,161 2,199 2,308 FirstEnergy's Pennsylvania and New Jersey Companies are Equity securities (ll 1,033 1,033 1,068 1,068 subject to regulatory accounting in accordance with SFAS

$3.037 $3,194 $3.267 $3,376 71. Net unrealized gains and losses are recorded as regula-II Includes nuclear decommissioning, nuclear luel disposalandNNUG Mst investments. tory liabilities or assets since the difference between 0 Includes investments inlease obligation bonds (See Note 6). investments held in trust and the decommissioning liabilities are recovered from, or refunded to, customers.

The fair value of investments other than cash and cash The investment policy for the nuclear decommissioning equivalents represent cost (which approximates fair value) trust funds restricts or limits the ability to hold certain types of or the present value of the cash inflows based on the yield assets including private or direct placements, warrants, securi-to maturity. The yields assumed were based on financial ties of FirstEnergy, investments in companies owning nuclear instruments with similar characteristics and terms. power plants, financial derivatives, preferred stocks, securities Investments other than cash and cash equivalents convertible into common stock and securities of the trust include held-to-maturity securities and available-for-sale secu- fund's custodian or managers and their parents or subsidiaries.

rities. Decommissioning trust investments are classified as available-for-sale. The Companies have no securities held for Derivatives trading purposes. The following table summarizes the amor- FirstEnergy is exposed to financial risks resulting from the tized cost basis, unrealized gains and losses and fair values fluctuation of interest rates and commodity prices, including for decommissioning trust investments as of December 31: prices for electricity, natural gas and coal. To manage the volatility 2004 2003 relating to these exposures, FirstEnergy uses a variety of non-Un- Un- Un-i Un- derivative and derivative instruments, including forward contracts, Cost realized rearized Fair Cost realized realized Fair options, futures contracts and swaps. The derivatives are used Basis Gains Losses Value Basis Gains Losses Value principally for hedging purposes, and to a lesser extent, for trading (Inmillions) purposes. FirstEnergy's Risk Policy Committee, comprised of Debtsecurities S 616 S19 $ 3 $ 632 S 548 $ 26 S 1 $ 573 Equity securities 763 207 19 951 593 217 31 779 members of senior management, provides general management

$1,379 $226 $22 31.583 31.141 $243 $32 $1,352 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 Proceeds from the sale of decommissioning trust oversee compliance with corporate risk management policies and investments, realized gains and losses on those sales, and established risk management practices.

interest and dividend income for the three years ended How derivative instruments are used and classified deter-December 31, 2004 were as follows:

mines how they are reported in FirstEnergy's financial 2004 2003 2002 statements. FirstEnergy accounts for derivative instruments on (Inmillions) its Consolidated Balance Sheet at their fair value unless they Proceeds from sales $1,234 S758 $599 meet the normal purchase and normal sales criteria. The Realized gains 144 38 32 changes inthe fair value of a derivative instrument are recorded Realized losses 43 32 47 Interest and dividend income 45 37 33 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 The following table provides the fair value of and unrealized of the hedge transaction. FirstEnergy's primary ongoing hedging 54 FirstEnergy Corp. 2904

activity involves cash flow hedges of electricity and natural gas OE sold portions of its ownership interests in Perry Unit 1 purchases. The maximum periods over which the variability of and Beaver Valley Unit 2 and entered into operating leases on electricity and natural gas cash flows are hedged are two and the portions sold for basic lease terms of approximately 29 three years, respectively. Gains and losses from hedges of com- years. CEI and TE also sold portions of their ownership inter-modity price risks are included in net income when the ests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 underlying hedged commodities are delivered. Also, gains and and 3 and entered into similar operating leases for lease terms losses are included in net income when ineffectiveness occurs of approximately 30 years. During the terms of their respec-on certain natural gas hedges. The impact of ineffectiveness on tive leases, OE, CEI and TE continue to be responsible, to the

.. earnings during 2004 was not material. FirstEnergy entered into extent of their individual combined ownership and leasehold interest rate derivative transactions during 2001 to hedge a por- interests, for costs associated with the units including con-tion of the anticipated interest payments on debt related to the struction expenditures, operation and maintenance expenses, GPU acquisition. Gains and losses from hedges of anticipated insurance, nuclear fuel, property taxes and decommissioning.

interest payments on acquisition debt are included in net income They have the right, at the expiration of the respective basic over the periods that hedged interest payments are made - 5, lease terms, to renew their respective leases. They also have 10 and 30 years. Gains and losses from derivative contracts are the right to purchase the facilities at the expiration of the basic included in other operating expenses. AOCL as of December 31, lease term or any renewal term at a price equal to the fair mar-2004 includes a net deferred loss of $92 million for derivative ket value of the facilities. The basic rental payments are hedging activity. The $19 million decrease from the December adjusted when applicable federal tax law changes.

31, 2003 balance of $111 million includes an $11 million reduction Consistent with the regulatory treatment, the rentals for capi-due to the sale of GLEP, a $3 million reduction related to current tal and operating leases are charged to operating expenses on the hedging activity and a $5 million decrease due to net hedge Consolidated Statements of Income. Such costs for the three losses included in earnings during the year. Approximately $14 years ended December 31, 2004 are summarized as follows:

million (after tax) of the current net deferred loss on derivative instruments in AOCL is expected to be reclassified to earnings 2004 2003 2002 during the next twelve months as hedged transactions occur. [In millions)

Operating leases The fair value of these derivative instruments will continue to Interest element $172 $181 $188 fluctuate from period to period based on various market factors. Other 126 150 136 During 2004, FirstEnergy executed fixed-for-floating interest Capital leases Interest element 1 2 2 rate swap agreements, whereby FirstEnergy receives fixed cash Other 3 2 3 flows based on the fixed coupons of the hedged securities and Total rentals $302 $335 $329 pays variable cash flows based on short-term variable market inter- .. . . ... . * * . *.. . . ~.......

est rates (3and 6 months LIBOR index). These derivatives are OE invested in the PNBV Capital Trust, which was treated as fair value hedges of fixed-rate, long-term debt issues - established to purchase a portion of the lease obligation protecting against the risk of changes inthe fair value of fixed-rate bonds issued on behalf of lessors in OE's Perry Unit 1 and debt instruments due to lower interest rates. Swap maturities, Beaver Valley Unit 2 sale and leaseback transactions. CEI fixed interest rates received, and interest payment dates match and TE established the Shippingport Capital Trust to pur-those of the underlying obligations. FirstEnergy entered into inter- chase the lease obligation bonds issued on behalf of lessors est rate swap agreements on a $900 million notional amount of in their Bruce Mansfield Units 1, 2 and 3 sale and leaseback subsidiaries' senior notes and subordinated debentures with a transactions. The PNBV and Shippingport Capital Trust weighted average fixed interest rate of 5.67%. Inaddition, arrangements effectively reduce lease costs related to FirstEnergy unwound swaps with a total notional amount of $400 those transactions (see Note 7).

million from which it received $12 million incash gains during The future minimum lease payments as of 2004. The gains will be recognized over the remaining maturity of December 31, 2004 are:

each respective hedged security as reduced interest expense. As

-. DOperating Leases of December 31, 2004, the aggregate notional value of interest rate Capital Lease Capital swap agreements outstanding was $1.65 billion. Leases Payments Trusts Net FirstEnergy engages in the trading of commodity deriva- (Inmillions) tives and periodically experiences net open positions. 2005 $5 $ 313 $ 130 $ 183 FirstEnergy's risk management policies limit the exposure to 2006 5 322 142 180 2007 1 299 130 169 market risk from open positions and require daily reporting to 2008 1 294 105 189 management of potential financial exposures. Discretionary trad- 2009 1 298 111 187 ing in 2004 resulted in a $2 million gain. Years thereafter 6 2.217 763 1,454 Total minimum lease payments 19 * $3,743 $1.381 $2,362 Executory costs 4 Net minimum lease payments 15

6. Leases Interest portion 4

! The Companies lease certain generating facilities, office Present value of net minimum space and other property and equipment under cancelable lease payments 11 Less current portion 2 and noncancelable leases. Noncurrent portion S9 FirstEnergyCorp. 2004 55

FirstEnergy has recorded above-market lease liabilities CE, CEI and TE are exposed to losses under the appli-for Beaver Valley Unit 2 and the Bruce Mansfield Plant asso- cable sale-leaseback agreements upon the occurrence of ciated with the 1997 merger between OE and Centerior. certain contingent events that each company considers The total above-market lease obligation of $722 million asso- unlikely to occur. OE, CEI and TE each have a maximum ciated with Beaver Valley Unit 2 is being amortized on a exposure to loss under these provisions of approximately $1 straight-line basis through the end of the lease term in 2017 billion, which represents the net amount of casualty value (approximately $37 million per year). The total above-market payments upon the occurrence of specified casualty events lease obligation of $755 million associated with the Bruce that render the applicable plant worthless. Under the appli-Mansfield Plant is being amortized on a straight-line basis cable sale and leaseback agreements, OE, CEI and TE have through the end of 2016 (approximately $48 million per net minimum discounted lease payments of $673 million, year). As of December 31, 2004 the above-market lease lia- $115 million and $570 million, respectively, that would not bilities for Beaver Valley Unit 2 and the Bruce Mansfield be payable if the casualty value payments are made.

Plant totaled S1.0 billion, of which $85 million is current.

Power Purchase Agreements

7. Variable Interest Entities 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 FIN 46R, addresses the consolidation of VIEs, including spe-of its output to the Companies and the contract price for cial-purpose entities, that are not controlled through voting interests or in which the equity investors do not bear the residual power is correlated with the plant's variable costs of produc-economic risks and rewards. FirstEnergy adopted FIN 46R for tion. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and special-purpose entities as of December 31, 2003 and for all Penelec, maintains approximately 30 long-term power pur-other entities in the first quarter of 2004. The first step under FIN chase agreements with NUG entities. The agreements were structured pursuant to the Public Utility Regulatory Policies 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 Act of 1978. FirstEnergy was not involved in the creation of, subsidiaries consolidate VIEs where they have determined that and has no equity or debt invested in, these entities.

they are the primary beneficiaries as defined by FIN 46R. 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 Leases Included in FirstEnergy's consolidated financial state- not-for-profit organizations not within the scope of FIN 46R.

ments are PNBV and Shippingport, two VIEs created in JCP&L, Met-Ed or Penelec may hold variable interests in the 1996 and 1997, respectively, to refinance debt originally remaining nine entities, which sell their output at variable issued in connection with the sale and leaseback transac- prices that correlate to some extent with the operating tions discussed above in Note 6. PNBV and Shippingport costs of the plants.

financial data are included in the consolidated financial state- As required by FIN 46R, FirstEnergy requests, on a quarterly basis, the information necessary from these nine ments of OE and CEI, respectively.

entities to determine whether they are VIEs or whether PNBV was established to purchase a portion of the lease obligation bonds issued in connection with OE's 1987 sale JCP&L, Met-Ed or Penelec is the primary beneficiary.

and leaseback of its interests in the Perry Plant and Beaver FirstEnergy has been unable to obtain the requested infor-Valley Unit 2. OE used debt and available funds to purchase mation, which in most cases was deemed by the requested the notes issued by PNBV. Ownership of PNBV includes a entity to be proprietary. As such, FirstEnergy applied the three-percent equity interest by a nonaffiliated third party and scope exception that exempts enterprises unable to obtain a three-percent equity interest held by OES Ventures, a whol- the necessary information to evaluate entities under FIN ly owned subsidiary of OE. Shippingport was established to 46R. The maximum exposure to loss from these entities purchase all of the lease obligation bonds issued in connec- results from increases in the variable pricing component tion with CEl's and TE's Bruce Mansfield Plant sale and under the contract terms and cannot be determined without leaseback transaction in 1987. CEI and TE used debt and the requested data. The cost of power purchased from available funds to purchase the notes issued by Shippingport. these entities during 2004, 2003 and 2002 was $210 mil-Through its investment in PNBV, OE has, and through lion, $194 million and $184 million, respectively.

their investments in Shippingport, CEI and TE have, variable FirstEnergy is required to continue to make exhaustive interests in certain owner trusts that acquired the interests efforts to obtain the necessary information in future periods in the Perry Plant and Beaver Valley Unit 2, in the case of and is unable to determine the possible impact of consoli-OE, and the Bruce Mansfield Plant, in the case of CEI and dating any such entity without this information.

TE. FirstEnergy concluded that OE, CEI and TE were not the primary beneficiaries of the relevant owner trusts and were 8. Divestitures therefore not required to consolidate these entities. The combined purchase price of $3.1 billion for all of the inter- International Operations ests acquired by the owner trusts in 1987 was funded with FirstEnergy completed the sale of its international oper-debt of $2.5 billion and equity of $600 million. ations in January 2004 with the sales of its remaining 20.1 56 FirstEnergy Corp. 2)04

percent interest in Avon (parent of Midlands Electricity in settlement of its claim against NRG. FirstEnergy sold its the United Kingdom) on January 16, 2004, and its 28.67 entire claim (including $32 million of cash proceeds received percent interest in TEBSA for $12 million on January 30, in December 2003) for $170 million in January 2004.

2004. Impairment charges related to TEBSA and Avon (included in Other Operating Expenses on the Consolidated Other Domestic Operations Statements of Income) were recorded in the fourth quarter FirstEnergy sold its 50 percent interest in GLEP on of 2003 and no gain or loss was recognized upon the sales June 23, 2004. Proceeds of $220 million included cash of in 2004. Avon, TEBSA and other international assets sold in $200 million and the right, valued at $20 million, to partici-2003 were originally acquired as part of FirstEnergy's pate for up to a 40% interest in future wells in Ohio. This November 2001 merger with GPU. transaction produced an after-tax loss of $7 million, or $0.02 International operations in Bolivia were divested by the per share of common stock, including the benefits of prior December 2003 sale of FirstEnergy's wholly owned sub- tax capital losses that had been previously fully reserved, sidiary, Guaracachi America, Inc., a holding company with a which offset the capital gain from the sale. In 2003, 50.001 percent interest in EGSA, resulting in a loss on sale FirstEnergy sold three FSG subsidiaries - Ancoma, Inc., a of S33 million (recognized in Discontinued Operations in the mechanical contracting company based in Rochester, New Consolidated Statement of Income for the year ended York, and Virginia-based Colonial Mechanical and Webb December 31, 2003). International operations in Argentina Technologies - and a MARBEL subsidiary - Northeast Ohio represented by FirstEnergy's ownership in Emdersa were Natural Gas (see Note 2(J)).

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-

9. Regulatory Matters ognized a one-time, non-cash charge of $67 million, or $0.23 Reliability Initiatives per share of common stock in the second quarter of 2003. In late 2003 and early 2004, a series of letters, reports The charge did not include the expected income tax bene- and recommendations were issued from various entities, fits related to the abandonment, which were fully reserved including governmental, industry and ad hoc reliability enti-during the second quarter of 2003. FirstEnergy expects tax ties (PUCO, FERC, NERC and the U.S. - Canada Power benefits of approximately $129 million, of which $50 million System Outage Task Force) regarding enhancements to would increase net income in the period that it becomes regional reliability. With respect to each of these reliability probable those benefits will be realized. The remaining $79 enhancement initiatives, FirstEnergy submitted its response million of tax benefits would reduce goodwill recognized in to the respective entity according to any required response connection with the acquisition of GPU. dates. In 2004, FirstEnergy completed implementation of all FirstEnergy had sold a 79.9 percent equity interest in actions and initiatives related to enhancing area reliability, Avon in May 2002 to Aquila, Inc. for approximately $1.9 bil-improving voltage and reactive management, operator readi-lion (consisting of the assumption of $1.7 billion of debt, ness and training, and emergency response preparedness

$155 million in cash and a $87 million note receivable). In recommended for completion in 2004. Furthermore, the fourth quarter of 2002, FirstEnergy recorded a $50 mil- FirstEnergy certified to NERC on June 30, 2004, with minor lion after-tax charge to reduce the carrying value of its exceptions noted, that FirstEnergy had completed the rec-remaining 20.1 percent interest. After reaching agreement ommended enhancements, policies, procedures and actions to sell its remaining 20.1 percent interest in the fourth quar- it had recommended be completed by June 30, 2004. In ter of 2003, FirstEnergy recorded a $5 million after-tax addition, FirstEnergy requested, and NERC provided, a tech-charge to reduce the carrying value. These charges were nical assistance team of experts to assist in implementing included in Other Operating Expenses on the Consolidated and confirming timely and successful completion of various Statements of Income for the years ended December 31, initiatives. The NERC-assembled independent verification 2002 and 2003, respectively. In the second quarter of 2003, team confirmed on July 14, 2004, that FirstEnergy had FirstEnergy recognized an impairment of $13 million ($8 mil- implemented the NERC Recommended Actions to Prevent lion net of tax) related to the carrying value of the note and Mitigate the Impacts of Future Cascading Blackouts receivable from Aquila. After receiving the first annual required to be completed by June 30, 2004, as well as NERC installment payment of $19 million in May 2003, recommendations contained in the Control Area Readiness FirstEnergy sold the remaining balance of its note receivable Audit Report required to be completed by summer 2004, and in the secondary market and received $63 million in pro-recommendations in the U.S. - Canada Power System ceeds in July 2003.

Outage Task Force Report directed toward FirstEnergy and required to be completed by June 30, 2004, with minor Generation Assets exceptions noted by FirstEnergy. On December 28, 2004, In August 2002, FirstEnergy cancelled a November FirstEnergy submitted a follow-up to its June 30, 2004 2001 agreement to sell four coal-fired power plants (2,535 Certification and Report of Completion to NERC addressing MW) to NRG Energy Inc. because NRG stated that it could the minor exceptions, which are now essentially complete.

not complete the transaction under the original terms of the FirstEnergy is proceeding with the implementation of agreement. NRG filed voluntary bankruptcy petitions in May the recommendations that were to be completed subse-2003; subsequently, FirstEnergy reached an agreement for FirstEnergv Corp 2004 57

quent to 2004 and will continue to periodically assess the ment systems following restructuring. Evidentiary hearings FERC-ordered Reliability Study recommendations for fore- have been scheduled for September 2005. FirstEnergy is casted 2009 system conditions, recognizing revised load unable to predict the outcome of this proceeding.

forecasts and other changing system conditions which may On January 16, 2004, the PPUC initiated a formal inves-impact the recommendations. Thus far, implementation of tigation of whether Met-Ed's, Penelec's and Penn's "service the recommendations has not required, nor is expected to reliability performance deteriorated to a point below the require, substantial investment in new, or material upgrades, level of service reliability that existed prior to restructuring" to existing equipment. FirstEnergy notes, however, that in Pennsylvania. Hearings were held in early August 2004.

FERC or other applicable government agencies and reliability On September 30, 2004, Met-Ed, Penelec and Penn filed a coordinators may take a different view as to recommended settlement agreement with the PPUC that addresses the enhancements or may recommend additional enhance- issues related to this investigation. As part of the settle-ments in the future that could require additional, material ment, Met-Ed, Penelec and Penn agreed to enhance service expenditures. Finally, the PUCO is continuing to review the reliability, ongoing periodic performance reporting and com-FirstEnergy filing that addressed upgrades to control room munications with customers and to collectively maintain computer hardware and software and enhancements to the their current spending levels of at least $255 million annually training of control room operators, before determining the on combined capital and operation and maintenance expen-next steps, if any, in the proceeding. ditures for transmission and distribution for the years 2005 On July 5, 2003, JCP&L experienced a series of 34.5 through 2007. The settlement also outlines an expedited kilovolt sub-transmission line faults that resulted in outages remediation process to address any alleged non-compliance on the New Jersey shore. On July 16, 2003, the NJBPU ini- with terms of the settlement and an expedited PPUC hear-tiated an investigation into the cause of JCP&L's outages of ing process if remediation is unsuccessful. On November 4, the July 4, 2003 weekend. The NJBPU selected an SRM to 2004, the PPUC accepted the recommendation of the ALJ oversee and make recommendations on appropriate cours- approving the settlement.

es of action necessary to ensure system-wide reliability.

Additionally, pursuant to the stipulation of settlement that Ohio was adopted in the NJBPU's Order of March 13, 2003 in its In October 2003, the Ohio Companies filed an applica-docket relating to the investigation of outages in August tion for a Rate Stabilization Plan with the PUCO to establish 2002, the NJBPU, through an independent auditor working generation service rates beginning January 1, 2006, in under direction of the NJBPU Staff, undertook a review and response to PUCO concerns about price and supply uncer-focused audit of JCP&L's Planning and Operations and tainty following the end of the Ohio Companies' transition Maintenance programs and practices (Focused Audit). plan market development period. On February 24, 2004, the Subsequent to the initial engagement of the auditor, the Ohio Companies filed a revised Rate Stabilization Plan to scope of the review was expanded to include the outages address PUCO concerns related to the original Rate during July 2003. Stabilization Plan. On June 9, 2004, the PUCO issued an Both the independent auditor and the SRM submitted order approving the revised Rate Stabilization Plan, subject interim reports primarily addressing improvements to be to conducting a competitive bid process. On August 5, made prior to the next occurrence of peak loads in the sum- 2004, the Ohio Companies accepted the Rate Stabilization mer of 2004. On December 17, 2003, the NJBPU adopted Plan as modified and approved by the PUCO on August 4, the SRM's interim recommendations related to service relia- 2004. In the second quarter of 2004, the Ohio Companies bility. With the assistance of the independent auditor and the implemented the accounting modifications related to the SRM, JCP&L and the NJBPU staff created a Memorandum extended amortization periods and interest costs deferral on of Understanding (MOU) that set out specific tasks to be the deferred customer shopping incentive balances. On performed by JCP&L and a timetable for completion. On October 1 and October 4, 2004, the OCC and NOAC, March 29, 2004, the NJBPU adopted the MOU and respectively, filed appeals with the Supreme Court of Ohio endorsed JCP&L's ongoing actions to implement the MOU. to overturn the June 9, 2004 PUCO order and associated On June 9, 2004, the NJBPU approved a Stipulation that entries on rehearing.

incorporates the final report of the SRM and the Executive The revised Rate Stabilization Plan extends current gen-Summary and Recommendation portions of the final report eration prices through 2008, ensuring adequate generation of the Focused Audit. A Final Order in the Focused Audit supply at stabilized prices, and continues the Ohio docket was issued by the NJBPU on July 23, 2004. JCP&L Companies' support of energy efficiency and economic continues to file compliance reports reflecting activities asso- development efforts. Other key components of the revised ciated with the MOU and Stipulation. Rate Stabilization Plan include the following:

In May 2004, the PPUC issued an order approving the

• extension of the transition cost amortization period for revised reliability benchmark and standards, including OE from 2006 to as late as 2007; for CEI from 2008 revised benchmarks and standards for Met-Ed, Penelec and to as late as mid-2009 and for TE from mid-2007 to as Penn. Met-Ed, Penelec and Penn filed a Petition for late as mid-2008; Amendment of Benchmarks with the PPUC on May 26,

• deferral of interest costs on the accumulated cus-2004 seeking amendment of the benchmarks and standards tomer shopping incentives as new regulatory assets; due to their implementation of automated outage manage- and 58 FirstEnergy Corp. ;'004

• ability to request increases in generation charges dur- deferred cost disallowances (2)the capital structure ing 2006 through 2008, under certain limited including the rate of return (3) merger savings, including conditions, for increases in fuel costs and taxes. amortization of costs to achieve merger savings; and (4) decommissioning costs. Management is unable to predict On December 9, 2004, the PUCO rejected the auction when a decision may be reached by the NJBPU.

price results from a required competitive bid process and On July 16, 2004, JCP&L filed the Phase II petition and issued an entry stating that the pricing under the approved testimony with the NJBPU, requesting an increase in base revised Rate Stabilization Plan will take effect on January 1, rates of $36 million for the recovery of system reliability

! 2006. The PUCO may cause the Ohio Companies to under- costs and a 9.75% return on equity. The filing also requests take, no more often than annually, a similar competitive bid an increase to the MTC deferred balance recovery of process to secure generation for the years 2007 and 2008. approximately $20 million annually. The Ratepayer Advocate Any acceptance of future competitive bid results would ter- filed testimony on November 16, 2004, and JCP&L submit-

minate the Rate Stabilization Plan pricing, but not the related ted rebuttal testimony on January 4, 2005. Settlement approved accounting, and not until twelve months after the conferences are ongoing.

PUCO authorizes such termination. JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits New Jersey to its deferred energy balance with the exception of 300 JCP&L is permitted to defer for future collection from MW from JCP&L's NUG committed supply currently being customers the amounts by which its costs of supplying BGS used to serve BGS customers pursuant to NJBPU order.

to non-shopping customers and costs incurred under NUG The BGS auction for periods beginning June 1, 2004 was agreements exceed amounts collected through BGS and completed in February 2004 and new BGS tariffs reflecting MTC rates. As of December 31, 2004, the accumulated the auction results became effective June 1, 2004. The deferred cost balance totaled approximately $446 million. NJBPU decision on the BGS post transition year three New Jersey law allows for securitization of JCP&L's process was announced on October 22, 2004, approving deferred balance upon application by JCP&L and a determi- with minor modifications the BGS procurement process nation by the NJBPU that the conditions of the New Jersey filed by JCP&L and the other New Jersey electric distribu-restructuring legislation are met. On February 14, 2003, tion companies and authorizing the continued use of NUG JCP&L filed for approval of the securitization of the deferred committed supply to serve 300 MW of BGS load. The auc-balance. There can be no assurance as to the extent, if any, tion for the supply period beginning June 1, 2005 was that the NJBPU will permit such securitization. completed in February 2005.

In July 2003, the NJBPU announced its JCP&L base In accordance with an April 28, 2004 NJBPU order, electric rate proceeding decision, which reduced JCP&L's JCP&L filed testimony on June 7, 2004 supporting a contin-annual revenues effective August 1, 2003 and disallowed uation of the current level and duration of the funding of

! $153 million of deferred energy costs. The NJBPU decision TMI-2 decommissioning costs by New Jersey customers also provided for an interim return on equity of 9.5% on without a reduction, termination or capping of the funding.

JCP&L's rate base. The decision ordered a Phase II proceed- On September 30, 2004, JCP&L filed an updated TMI-2 ing be conducted to review whether JCP&L is in compliance decommissioning study (see Note 11 - Asset Retirement with current service reliability and quality standards. The Obligations). This study resulted in an updated total decom-BPU also ordered that any expenditures and projects under- missioning cost estimate of $729 million (in 2003 dollars) taken by JCP&L to increase its system's reliability be compared to the estimated $528 million (in 2003 dollars) reviewed as part of the Phase II proceeding, to determine from the prior 1995 decommissioning study. The Ratepayer their prudence and reasonableness for rate recovery. In that Advocate filed comments on February 28, 2005. A schedule Phase II proceeding, the NJBPU could increase JCP&L's for further proceedings has not yet been set.

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. Pennsylvania Any reduction would be retroactive to August 1, 2003. In June 2001, the PPUC approved the Settlement JCP&L recorded charges to net income for the year ended Stipulation with all of the major parties in the combined December 31, 2003, aggregating $185 million ($109 million merger and rate relief proceedings, which approved the net of tax) consisting of the $153 million of disallowed FirstEnergy/GPU merger and provided Met-Ed and Penelec deferred energy costs and $32 million of other disallowed PLR deferred accounting treatment for energy costs. A regulatory assets. In its final decision and order issued on February 2002 Commonwealth Court of Pennsylvania deci-May 17, 2004, the NJPBU clarified the method for calculat- sion affirmed the PPUC decision regarding approval of the ing interest attributable to the cost disallowances, resulting merger, remanded the issue of quantification and allocation in a $5.4 million reduction from the amount estimated in of merger savings to the PPUC and denied the PLR deferral 2003. JCP&L filed an August 15, 2003 interim motion for accounting treatment. In October 2003, the PPUC issued an rehearing and reconsideration with the NJBPU and a June 1, order concluding that the Commonwealth Court reversed 2004 supplemental and amended motion for rehearing and the PPUC's June 2001 order in its entirety. In accordance reconsideration. On July 7, 2004, the NJBPU granted limited with the PPUC's direction, Met-Ed and Penelec filed supple-reconsideration and rehearing on the following issues: (1) ments to their tariffs which were effective October 2003 FirstEnergy Corp 2004 59

that reflected the CTC rates and shopping credits in effect voltage-differentiated rate design for the ATSI zone.

prior to the June 21, 2001 order. On December 30, 2004, the Ohio Companies filed an In response to its October 8, 2003 petition, the PPUC application with the PUCO seeking tariff adjustments to approved June 30, 2004 as the date for Met-Ed's and recover increases of approximately $30 million in transmis-Penelec's NUG trust fund refunds and denied their account- sion and ancillary service costs beginning January 1, 2006.

ing request regarding the CTC rate/shopping credit swap by The Ohio Companies also filed an application for authority to requiring Met-Ed and Penelec to treat the stipulated CTC defer costs associated with MISO Day 1, MISO Day 2, con-rates that were in effect from January 1, 2002 on a retroac- gestion fees, FERC assessment fees, and the ATSI rate tive basis. Met-Ed and Penelec subsequently filed with the increase, as applicable, from October 1, 2003 through Commonwealth Court, on October 31, 2003, an Application December 31, 2005.

for Clarification with the judge, a Petition for Review of the On January 12, 2005, Met-Ed and Penelec filed, before PPUC's October 2 and October 16 Orders, and an applica- the PPUC, a request for deferral of transmission-related tion for reargument if the judge, in his clarification order, costs beginning January 1, 2005, estimated to be approxi-indicates that Met-Ed's and Penelec's Objection was intend- mately $8 million per month.

ed to be denied on the merits. The Reargument Brief before Various parties have intervened in each of the cases the Commonwealth Court was filed January 28, 2005. above.

In accordance with PPUC directives, Met-Ed and On September 16, 2004, the FERC issued an order that Penelec have been negotiating with interested parties in an imposed additional obligations on CEI under certain pre-attempt to resolve the merger savings issues that are the Open Access transmission contracts among CEI and the subject of remand from the Commonwealth Court. These cities of Cleveland and Painesville. Under the FERC's deci-companies' combined portion of total merger savings is esti- sion, CEI may be responsible for a portion of new energy mated to be approximately $31.5 million. If no settlement market charges imposed by MISO when its energy markets can be reached, Met-Ed and Penelec will take the position begin in the spring of 2005. CEI filed for rehearing of the that any portion of such savings should be allocated to order from the FERC on October 18, 2004. The impact of customers during each company's next rate proceeding. the FERC decision on CEI is dependent upon many factors, Met-Ed and Penelec purchase a portion of their PLR including the arrangements made by the cities for transmis-requirements from FES through a wholesale power sale sion service, the startup date for the MISO energy market, agreement. The PLR sale is automatically extended for each and the resolution of the rehearing request, and cannot be successive calendar year unless any party elects to cancel determined at this time.

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

10. Capitalization portion of power supply requirements not self-supplied by (A) COMMON STOCK Met-Ed and Penelec under their NUG contracts and other Retained Earnings and Dividends power contracts with nonaffiliated third party suppliers. This Under applicable federal law, FirstEnergy (as a regis-arrangement reduces Met-Ed's and Penelec's exposure to tered holding company) and its subsidiaries can pay high wholesale power prices by providing power at a fixed dividends only from retained, undistributed or current earn-price for their uncommitted PLR energy costs during the ings, unless the SEC specifically authorizes payment from term of the agreement with FES. Met-Ed and Penelec are other capital accounts. As of December 31, 2004, authorized to continue deferring differences between NUG FirstEnergy's unrestricted retained earnings were $1.9 bil-contract costs and current market prices. lion. Provisions within the articles of incorporation, indentures and various other agreements relating to the Transmission long-term debt and preferred stock of certain FirstEnergy On November 1, 2004, ATSI requested authority from subsidiaries contain provisions that could restrict the pay-the FERC to defer approximately $54 million of vegetation ment of dividends on their common and preferred stock. As management costs ($13 deferred as of December 31, 2004 of December 31, 2004, there were no material restrictions pending authorization) estimated to be incurred from 2004 on retained earnings under these agreements for payment through 2007. The FERC approved ATSl's request to defer of cash dividends on FirstEnergy's common stock.

those costs on March 4, 2005.

On November 30, 2004, the Board of Directors ATSI and MISO filed with the FERC on December 2, increased the indicated annual dividend to $1.65 per share, 2004, seeking approval for ATSI to have transmission rates payable quarterly at a rate of $0.4125 per share, and established based on a FERC-approved cost of service - for-declared the first quarter 2005 dividend. At December 31, mula rate included in Attachment 0 under the MISO tariff.

2004, accrued dividends of approximately $135 million were The ATSI Network Service net revenue requirement included in other current liabilities on the Consolidated increased under the formula rate to approximately $159 mil-Balance Sheet. Dividends declared in 2004 were $1.9125 lion. On January 28, 2005, the FERC accepted for filing the which included quarterly dividends of $0.375 per share paid revised tariff sheets to become effective February 1, 2005, in each quarter of 2004 and a dividend of $0.4125 payable in subject to refund, and ordered a public hearing be held to the first quarter of 2005. Dividends declared in 2003 were address the reasonableness of the proposal to eliminate the 60 FirstEnergy Corp O004

$1.50, which included quarterly dividends of $0.375 per redeemed on a pro rata basis at their liquidation value. Under share paid in each quarter of 2003. The amount and timing certain circumstances, the applicable subordinated deben-of all dividend declarations are subject to the discretion of tures could be distributed to the holders of the outstanding the Board and its consideration of business conditions, preferred securities of the trust in the event that the trust is results of operations, financial conditions and other factors. liquidated. CEI has effectively provided a full and uncondi-tional guarantee of payments due on the trust's preferred (B)PREFERRED AND PREFERENCE STOCK securities. The trust's preferred securities are redeemable at All preferred stock may be redeemed by the 100 percent of their principal amount at CEI's option begin-Companies in whole, or in part, with 30-90 days' notice. ning in December 2006. Interest on the subordinated CEI will exercise its option to redeem all outstanding debentures (and therefore distributions on the trust's pre-shares of two series of preferred stock during the first quar- ferred securities) may be deferred for up to 60 months, but ter of 2005 as follows: CEI may not pay dividends on, or redeem or acquire, any of its cumulative preferred or common stock until deferred pay-Series Outstanding Shares Call Price ments on its subordinated debentures are paid in full.

7.40A 500.000 101.00 Met-Ed and Penelec had each formed statutory busi-L 474.000 100.00 ness trusts for substantially similar transactions to those of CEI, with ownership of the respective Met-Ed and Penelec Met-Ed's and Penelec's preferred stock authorizations trusts through separate wholly owned limited partnerships.

consist of 10 million and 11.435 million shares, respectively, In June 2004 and September 2004, respectively, Met-Ed without par value. No preferred shares are currently out- and Penelec extinguished the subordinated debentures held standing for those companies. by their respective trusts, who in turn redeemed their The Companies' preference stock authorization consists respective preferred securities.

of 8 million shares without par value for OE; 3 million shares without par value for CEI; and 5 million shares, $25 par value Securitized Transition Bonds for TE. No preference shares are currently outstanding. 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-(C) LONG-TERM DEBT AND OTHER ery of JCP&L's bondable stranded costs associated with the LONG-TERM OBLIGATIONS previously divested Oyster Creek Nuclear Generating Station.

Preferred Stock Subject to Mandatory Redemption JCP&L does not own nor did it purchase any of the SFAS 150 requires financial instruments issued in the transition bonds, which are included in long-term debt on form of shares that are mandatorily redeemable to be classi- FirstEnergy's Consolidated Balance Sheets. The transition fied as long-term debt. Annual sinking fund provisions for bonds represent obligations only of the Issuer and are collat-the Companies' preferred stock are as follows: eralized solely by the equity and assets of the Issuer, which Redemption Price consist primarily of bondable transition property. The bond-Series Shares Per Share able transition property is solely the property of the Issuer.

CEI $ 7.35C 10.000 $100 Bondable transition property represents the irrevocable Penn 7.625% 7,500 100 right of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal Annual sinking fund requirements will be satisfied by amount and interest on the transition bonds and other fees the end of 2008 and consist of $1.8 million in 2005 and and expenses associated with their issuance. JCP&L, as 2006, $12.3 million in 2007 and $1.0 million in 2008. servicer, manages and administers the bondable transition property, including the billing, collection and remittance of Subordinated Debentures to AffiliatedTrusts the TBC, pursuant to a servicing agreement with the Issuer.

As of December 31, 2004, CEl's wholly owned statuto-ry business trust, Cleveland Electric Financing Trust, had Other Long-term Debt

$100 million of outstanding 9.00% preferred securities Each of the Companies has a first mortgage indenture maturing in 2031. The sole assets of the trust are CEI's sub- under which it issues FMBs secured by a direct first mort-ordinated debentures with the same rate and maturity date gage lien on substantially all of its property and franchises, as the preferred securities. other than specifically excepted property. FirstEnergy and its CEI formed the trust to sell preferred securities and subsidiaries have various debt covenants under their respec-invest the gross proceeds in the 9.00% subordinated tive financing arrangements. The most restrictive of the debentures of CEI. The sole assets of the trust are the appli- debt covenants relate to the nonpayment of interest and/or cable subordinated debentures. Interest payment provisions principal on debt and the maintenance of certain financial of the subordinated debentures match the distribution pay- ratios. The fixed charge ratio and debt-to-capitalization ratio ment provisions of the trust's preferred securities. In covenants are applicable to only financing arrangements of addition, upon redemption or payment at maturity of subordi- FirstEnergy, the Ohio Companies and Penn. There also exist nated debentures, the trust's preferred securities will be cross-default provisions among financing arrangements of FrstEnergyCorp 2004 61

FirstEnergy and the Companies. 2004 under a $250 million long-term revolving credit facility Based on the amount of FMBs authenticated by the agreement, which expires May 12, 2005. OE currently pays an respective mortgage bond trustees through December 31, annual facility fee of 0.20% on the total credit facility amount.

2004, the Companies' annual sinking fund requirements for OE had no unsecured borrowings as of December 31, 2004 all FMBs issued under the various mortgage indentures under a $125 million long-term revolving credit facility, which amounts to $71 million. OE and Penn expect to deposit expires October 23, 2006. OE currently pays an annual facility funds with their respective mortgage bond trustees in 2005 fee of 0.25% on the total credit facility amount. The fees are that will then be withdrawn upon the surrender for cancella- subject to change based on changes to OE's credit ratings.

tion of a like principal amount of FMBs, specifically OES Finance, Incorporated, a wholly owned subsidiary authenticated for such purposes against unfunded property of OE, had maintained certificates of deposits pledged as additions or against previously retired FMBs. This method collateral to secure reimbursement obligations relating to can result in minor increases in the amount of the annual certain LOCs supporting OE's obligations to lessors under sinking fund requirement. JCP&L, Met-Ed and Penelec the Beaver Valley Unit 2 sale and leaseback arrangements.

expect to fulfill their sinking fund obligations by providing In June 2004, these LOCs were replaced by a new LOC, bondable property additions and/or previously retired FMBs which did not require the collateral deposits. OE entered to the respective mortgage bond trustees. into a Credit Agreement pursuant to which a standby LOC Sinking fund requirements for FMBs and maturing long- was issued in support of the replacement LOCs and the term debt (excluding capital leases) for the next five years are: issuer of the standby LOC obtained the right to pledge or assign participations in OE's reimbursement obligations to a (Inmillions), trust. The trust then issued and sold trust certificates to 2005 S 937 institutional investors that were designed to be the credit 2006 1,327 2007 453 equivalent of an investment directly in OE. The certificates 2008 470 of deposit were cancelled and FirstEnergy received cash 2009 285 proceeds of $278 million in the third quarter of 2004.

CEI and TE have unsecured LOCs of approximately $216 Included in the table above are amounts for various vari- million in connection with the sale and leaseback of Beaver able interest rate pollution control bonds which have Valley Unit 2 that expire in April 2005. CEI and TE are jointly provisions by which individual debt holders have the option to and severally liable for such LOCs. OE has LOCs of $294 mil-

"put back" or require the respective debt issuer to redeem lion and $154 million in connection with the sale and leaseback their debt at those times when the interest rate may change of Beaver Valley Unit 2 and Perry Unit 1, respectively.

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.

11. Asset Retirement Obligations The Companies' obligations to repay certain pollution In January 2003, FirstEnergy implemented SFAS 143, control revenue bonds are secured by several series of which provides accounting guidance for retirement obligations FMBs. Certain pollution control revenue bonds are entitled associated with tangible long-lived assets. This standard to the benefit of irrevocable bank LOCs of $299 million or requires recognition of the fair value of a liability for an ARO in noncancelable municipal bond insurance policies of $922 the period in which it is incurred. The associated asset retire-million to pay principal of, or interest on, the applicable pol-ment costs are capitalized as part of the carrying amount of lution control revenue bonds. To the extent that drawings the long-lived asset. Over time the capitalized costs are depre-are made under the LOCs or the policies, the Companies ciated and the present value of the ARO increases, resulting in are entitled to a credit against their obligation to repay those a period expense. However, rate-regulated entities may recog-bonds. The Companies pay annual fees of 1.0% to 1.7% of nize a regulatory asset or liability instead of an expense if the the amounts of the LOCs to the issuing banks and 0.20% to criteria for such treatment are met. Upon retirement, a gain or 0.55% of the amounts of the policies to the insurers and are loss would be recognized if the cost to settle the retirement obligated to reimburse the banks or insurers, as the case obligation differs from the carrying amount.

may be, for any drawings thereunder.

FirstEnergy has identified applicable legal obligations as FirstEnergy had unsecured borrowings of $215 million defined under the standard for nuclear power plant decom-as of December 31, 2004, under its $1 billion revolving cred-missioning, reclamation of a sludge disposal pond related to it facility agreement which expires June 22, 2007.

the Bruce Mansfield Plant and closure of two coal ash dispos-FirstEnergy currently pays an annual facility fee of 0.30% on al sites. The ARO liability was $1.078 billion as of December the total credit facility amount. FirstEnergy had no borrow-31, 2004 and included $1.063 billion for nuclear decommis-ings as of December 31, 2004 under a $375 million sioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 long-term revolving credit facility agreement, which expires nuclear generating facilities. The Companies' share of the October 23, 2006. FirstEnergy currently pays an annual facil-obligation to decommission these units was developed based ity fee of 0.50% on the total credit facility amount. The fees on site specific studies performed by an independent engi-are subject to change based on changes to FirstEnergy's neer. FirstEnergy utilized an expected cash flow approach to credit ratings.

measure the fair value of the nuclear decommissioning ARO.

OE had no unsecured borrowings as of December 31, 62 FirstEnergy Corp. 2004

In the third quarter of 2004, FirstEnergy revised the ARO 12. Short-Term Borrowings associated with TMI-2 as the result of a recently completed study and the anticipated operating license extension for TMI- and Bank Lines of Credit:

1. The abandoned TMI-2 is adjacent to TMI-1 and the units arc expected to be decommissioned concurrently. The decrease Short-term borrowings outstanding as of December 31, in the present value of estimated cash flows associated with 2004, consisted of $29 million of OE bank borrowings and the license extension of $202 million was partially offset by $142 million of OES Capital, Incorporated borrowings. OES the $26 million present value of an increase in projected Capital is a wholly owned subsidiary of OE whose borrow-decommissioning costs. The net decrease in the TMI-2 ARO ings are secured by customer accounts receivable purchased liability and corresponding regulatory asset was $176 million. from OE. OES Capital can borrow up to $170 million under a The Companies maintain nuclear decommissioning trust receivables financing arrangement at rates based on certain funds that are legally restricted for purposes of settling the bank commercial paper and is required to pay an annual fee nuclear decommissioning ARO. As of December 31, 2004, of 0.25% on the amount of the entire finance limit. The the fair value of the decommissioning trust assets was receivables financing agreement expires in October 2005.

$1.583 billion. Penn, Met-Ed and Penelec have, through separate wholly The following table describes the changes to the ARO owned subsidiaries, receivables financing arrangements that balances during 2004 and 2003. provide a combined borrowing capability of up to $180 mil-lion at rates based on bank commercial paper rates. The ARO Reconciliation 2004 2003 financing arrangements require payment of an annual facility (Inmillions) fee of 0.30% on the entire finance limit. The receivables Balance at beginning of year $1,179 $1,109 financing agreements for Penn, Met-Ed and Penelec expire Liabilities incurred - -

Liabilities settled - - in March 2005. These receivables financing arrangements Accretion 75 70 are expected to be renewed prior to expiration.

Revisions inestimated cash flows (1761 -

OE has various bi-lateral credit facilities with domestic Balance at end of year S1.078 $1,179 banks that provide for borrowings of up to $34 million under various interest rate options. To assure the availability of The following table describes the changes to the ARO for these lines, OE is required to pay annual commitment fees 2002, as if SFAS 143 had been adopted on January 1, 2002. that vary from 0.20% to 0.25% of total lender commit-

, Adjusted ARO Reconciliation 2002 ments. These lines expire at various times during 2005. The (Inmillions) weighted average interest rates on short-term borrowings Beginning balance as of January 1,2002 $1,042 outstanding as of December 31, 2004 and 2003 were Accretion 67 2.35% and 2.14%, respectively.

Ending balance as of December 31. 2002 $1,109 CEI and TE sell substantially all of their retail customer receivables to CFC, a wholly owned subsidiary of CEI. CFC The following table provides the effect on income as if subsequently transfers the receivables to a trust under an SFAS 143 had been applied during 2002. asset-backed securitization agreement. The trust is a "quali-fied special purpose entity" under SFAS 140, which Effect of the Change in Accounting provides it with certain rights relative to the transferred Principle Applied Retroactively (Inmillions) assets. Transfers are made in return for an interest in the Reported net income $553 trust (62% as of December 31, 2004), which is stated at fair Increase IDecrease): value, reflecting adjustments for anticipated credit losses.

Elimination of decommissioning expense B8 Depreciation of asset retirement cost (3) The fair value of CFC's interest in the trust approximates the Accretion of ARO liability (38) stated value of its retained interest in the underlying receiv-Non-regulated generation cost of removal component. net 15 Income tax effect (25) ables, after adjusting for anticipated credit losses, because Net earnings increase 37 the average collection period is 27 days. Accordingly, subse-Net income adjusted $590 quent measurements of the retained interest under SFAS Basic earnings per share of common stock: 115, (as an available-for-sale financial instrument) result in Net income as previously reported S1.89 no material change in value. Sensitivity analyses reflecting Adjustment for effect of change in accounting principle applied retroactively 0.12 10% and 20% increases in the rate of anticipated credit Net income adjusted $2.01 losses would not have significantly affected FirstEnergy's Diluted earnings per share of common stock: retained interest in the pool of receivables through the trust.

Net income as previously reported $1.88 Of the $222 million sold to the trust and outstanding as Adjustment for effect of change in accounting principle applied retroactively 0.12 of December 31, 2004, FirstEnergy retained interests in Net income adjusted $2.00 $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 FirstEnergy Corp. 2004 63

and TE processed receivables for the trust and received existing obligations, FirstEnergy's guarantee enables the servicing fees of approximately $4.8 million in 2004. counterparty's legal claim to be satisfied by other Expenses associated with the factoring discount related to FirstEnergy assets. The likelihood is remote that such the sale of receivables were $3.5 million in 2004. parental guarantees of $0.9 billion (included in the $1.0 bil-lion discussed above) as of December 31, 2004 will increase

13. Commitments, Guarantees amounts otherwise to be paid by FirstEnergy to meet its obligations incurred in connection with financings and ongo-and Contingencies: ing energy and energy-related activities.

While these types of guarantees are normally parental (A) NUCLEAR INSURANCE- commitments for the future payment of subsidiary obliga-The Price-Anderson Act limits the public liability relative tions, subsequent to the occurrence of a credit rating to a single incident at a nuclear power plant to $10.8 billion. downgrade or "material adverse event" the immediate post-The amount is covered by a combination of private insurance ing of cash collateral or provision of an LOC may be required and an industry retrospective rating plan. The Companies' of the subsidiary. The following table summarizes collateral maximum potential assessment under the industry retro- provisions as of December 31, 2004:

spective rating plan would be $402 million per incident but not more than $40 million in any one year for each incident.  ; Collateral Paid Remaining Collateral Provisions Exposure Cash LOC ExposureW The Companies are also insured under policies for each nuclear plant. Under these policies, up to $2.75 billion is provid- (Inmillions)

Credit rating downgrade 3349 3162 318 3169 ed for property damage and decontamination costs. The Adverse Event 135 - 22 113 Companies have also obtained approximately $1.5 billion of Total 5484 $162 $40 5282 insurance coverage for replacement power costs. Under these i')As of February 7,2005, the total exposure decreased to $476 million and the policies, the Companies can be assessed a maximum of remaining exposure increased to $290 million - net of $146 million of cash approximately $67.5 million for incidents at any covered nuclear collateral and $40 million of LOC collateral provided by counterparties.

facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses. Most of FirstEnergy's surety bonds are backed by vari-The Companies intend to maintain insurance against ous indemnities common within the insurance industry.

nuclear risks as long as it is available. To the extent that Surety bonds and related FirstEnergy guarantees of $279 replacement power, property damage, decontamination, repair million provide additional assurance to outside parties that and replacement costs and other such costs arising from a contractual and statutory obligations will be met in a number nuclear incident at any of the Companies' plants exceed the of areas including construction jobs, environmental commit-policy limits of the insurance in effect with respect to that ments and various retail transactions.

plant, to the extent a nuclear incident is determined not to be FirstEnergy has also guaranteed the obligations of the covered by the Companies' insurance policies, or to the extent operators of the TEBSA project, up to a maximum of $6 mil-such insurance becomes unavailable in the future, the lion (subject to escalation) under the project's operations Companies would remain at risk for such costs. and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified (B)GUARANTEES AND OTHER ASSURANCES- FirstEnergy against any loss under this guarantee.

As part of normal business activities, FirstEnergy enters FirstEnergy has also provided an LOC (currently at $47 mil-into various agreements on behalf of its subsidiaries to pro- lion), which is renewable and declines yearly based upon vide financial or performance assurances to third parties. the senior outstanding debt of TEBSA.

Such agreements include contract guarantees, surety bonds and ratings contingent collateralization provisions. As of (C) ENVIRONMENTAL MATTERS December 31, 2004, outstanding guarantees and other Various federal, state and local authorities regulate the assurances aggregated approximately $2.4 billion and includ- Companies with regard to air and water quality and other ed contract guarantees ($1.0 billion), surety bonds ($0.3 environmental matters. The effects of compliance on the billion) and LOC ($1.1 billion). Companies with regard to environmental matters could have FirstEnergy guarantees energy and energy-related pay- a material adverse effect on FirstEnergy's earnings and ments of its subsidiaries involved in energy commodity competitive position. These environmental regulations affect activities - principally to facilitate normal physical transac- FirstEnergy's earnings and competitive position to the tions involving electricity, gas, emission allowances and extent that it competes with companies that are not subject coal. FirstEnergy also provides guarantees to various to such regulations and therefore do not bear the risk of providers of subsidiary financing principally for the acquisi- costs associated with compliance, or failure to comply, with tion of property, plant and equipment. These agreements such regulations. Overall, FirstEnergy believes it is in com-legally obligate FirstEnergy to fulfill the obligations of those pliance with existing regulations but is unable to predict subsidiaries directly involved in energy and energy-related future change in regulatory policies and what, if any, the transactions or financing where the law might otherwise effects of such change would be. FirstEnergy estimates limit the counterparties' claims. If demands of a counterpar- additional capital expenditures for environmental compliance ty were to exceed the ability of a subsidiary to satisfy of approximately $430 million for 2005 through 2007.

64 FirstErergy Corp. 2004

Clean Air Act Compliance ceed with the development of regulations regarding haz-The Companies are required to meet federally approved ardous air pollutants from electric power plants, identifying S02 regulations. Violations of such regulations can result in mercury as the hazardous air pollutant of greatest concern.

shutdown of the generating unit involved and/or civil or On December 15, 2003, the EPA proposed two different criminal penalties of up to $32,500 for each day the unit is approaches to reduce mercury emissions from coal-fired in violation. The EPA has an interim enforcement policy for power plants. The first approach would require plants to S02 regulations in Ohio that allows for compliance based on install controls known as MACT based on the type of coal a 30-day averaging period. The Companies cannot predict burned. According to the EPA, if implemented, the MACT what action the EPA may take in the future with respect to proposal would reduce nationwide mercury emissions from the interim enforcement policy. coal-fired power plants by 14 tons to approximately 34 tons The Companies believe they are complying with S02 per year. The second approach proposes a cap-and-trade reduction requirements under the Clean Air Act Amendments program that would reduce mercury emissions in two dis-of 1990 by burning lower-sulfur fuel, generating more elec- tinct phases. Initially, mercury emissions would be reduced tricity from lower-emitting plants, and/or using emission by 2010 as a "co-benefit" from implementation of S02 and allowances. NOx reductions required by the 1990 Amend- NOx emission caps under the EPA's proposed Interstate Air ments are being achieved through combustion controls and Quality Rule. Phase II of the mercury cap-and-trade program the generation of more electricity at lower-emitting plants. would be implemented in 2018 to cap nationwide mercury In September 1998, the EPA finalized regulations requiring emissions from coal-fired power plants at 15 tons per year.

additional NOx reductions from the Companies' facilities. The EPA has agreed to choose between these two options The EPA's NOx Transport Rule imposes uniform reductions and issue a final rule by March 15, 2005. The future cost of of NOx emissions (an approximate 85 percent reduction in compliance with these regulations may be substantial.

utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New W. H. Sammis Plant Jersey, Ohio and Pennsylvania) and the District of Columbia In 1999 and 2000, the EPA issued NOV or Compliance based on a conclusion that such NOx emissions are con- Orders to nine utilities covering 44 power plants, including tributing significantly to ozone levels in the eastern United the W. H. Sammis Plant, which is owned by OE and Penn.

States. The Companies believe their facilities are also com- In addition, the U.S. Department of Justice filed eight civil plying with the NOx budgets established under State complaints against various investor-owned utilities, which Implementation Plans (SIPs) through combustion controls included a complaint against OE and Penn in the U.S.

and post-combustion controls, including Selective Catalytic District Court for the Southern District of Ohio. These cases Reduction and Selective Non-Catalytic Reduction systems, are referred to as New Source Review cases. The NOV and and/or using emission allowances. complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dat-National Ambient Air Quality Standards ing back to 1984. The complaint requests permanent In July 1997, the EPA promulgated changes in the injunctive relief to require the installation of "best available NAAQS for ozone and proposed a new NAAQS for fine par- control technology" and civil penalties of up to $27,500 per ticulate matter. On December 17, 2003, the EPA proposed day of violation. On August 7, 2003, the United States the "Interstate Air Quality Rule" covering a total of 29 District Court for the Southern District of Ohio ruled that 11 states (including Michigan, New Jersey, Ohio and projects undertaken at the W. H. Sammis Plant between Pennsylvania) and the District of Columbia based on pro- 1984 and 1998 required pre-construction permits under the posed findings that air pollution emissions from 29 eastern Clean Air Act. The ruling concludes the liability phase of the states and the District of Columbia significantly contribute case, which deals with applicability of Prevention of to nonattainment of the NAAQS for fine particles and/or Significant Deterioration provisions of the Clean Air Act. The the "8-hour" ozone NAAQS in other states. The EPA has remedy phase of the trial to address civil penalties and proposed the Interstate Air Quality Rule to "cap-and-trade" what, if any, actions should be taken to further reduce emis-NOx and S02 emissions in two phases (Phase I in 2010 sions at the plant has been delayed without rescheduling by and Phase II in 2015). According to the EPA, S02 emissions the Court because the parties are engaged in meaningful would be reduced by approximately 3.6 million tons annually settlement negotiations. The Court indicated, in its August by 2010, across states covered by the rule, with reductions 2003 ruling, that the remedies it "may consider and impose ultimately reaching more than 5.5 million tons annually. involved a much broader, equitable analysis, requiring the NOx emission reductions would measure about 1.5 million Court to consider air quality, public health, economic impact, tons in 2010 and 1.8 million tons in 2015. The future cost and employment consequences. The Court may also consid-of compliance with these proposed regulations may be er the less than consistent efforts of the EPA to apply and substantial and will depend on whether and how they further enforce the Clean Air Act." The potential penalties are ultimately implemented by the states in which the that may be imposed, as well as the capital expenditures Companies operate affected facilities. necessary to comply with substantive remedial measures that may be required, could have a material adverse impact Mercury Emissions on FirstEnergy's, OE's and Penn's respective financial condi-In December 2000, the EPA announced it would pro- tion and results of operations. While the parties are engaged FirstEnergy Corp. 2004 65

in meaningful settlement discussions, management is lower than many regional competitors due to the unable to predict the ultimate outcome of this matter and Companies' diversified generation sources which includes no liability has been accrued as of December 31, 2004. low or non-C02 emitting gas-fired and nuclear generators.

Regulation of Hazardous Waste Clean Water Act As a result of the Resource Conservation and Recovery Various water quality regulations, the majority of which Act of 1976, as amended, and the Toxic Substances Control are the result of the federal Clean Water Act and its amend-Act of 1976, federal and state hazardous waste regulations ments, apply to the Companies' plants. In addition, Ohio, have been promulgated. Certain fossil-fuel combustion waste New Jersey and Pennsylvania have water quality standards products, such as coal ash, were exempted from hazardous applicable to the Companies' operations. As provided in the waste disposal requirements pending the EPA's evaluation of Clean Water Act, authority to grant federal National Pollutant the need for future regulation. The EPA subsequently deter- Discharge Elimination System water discharge permits can mined that regulation of coal ash as a hazardous waste is be assumed by a state. Ohio, New Jersey and Pennsylvania unnecessary. In April 2000, the EPA announced that it will have assumed such authority.

develop national standards regulating disposal of coal ash On September 7, 2004, the EPA established new per-under its authority to regulate nonhazardous waste. formance standards under Clean Water Act Section 316(b) for The Companies have been named as PRPs at waste reducing impacts on fish and shellfish from cooling water disposal sites, which may require cleanup under the Compre- intake structures at certain existing large electric generating hensive Environmental Response, Compensation and Liability plants. The regulations call for reductions in impingement mor-Act of 1980. Allegations of disposal of hazardous substances at tality, when aquatic organisms are pinned against screens or historical sites and the liability involved are often unsubstantiat- other parts of a cooling water intake system and entrainment, ed and subject to dispute; however, federal law provides that all which occurs when aquatic species are drawn into a facility's PRPs for a particular site are liable on a joint and several basis. cooling water system. The Companies are conducting compre-Therefore, environmental liabilities that are considered probable hensive demonstration studies, due in 2008, to determine the have been recognized on the Consolidated Balance Sheet as of operational measures, equipment or restoration activities, if December 31, 2004, based on estimates of the total costs of any, necessary for compliance by their facilities with the per-cleanup, the Companies' proportionate responsibility for such formance standards. FirstEnergy is unable to predict the costs and the financial ability of other nonaffiliated entities to outcome of such studies. Depending on the outcome of such pay. In addition, JCP&L has accrued liabilities for environmental studies, the future cost of compliance with these standards remediation of former manufactured gas plants in New Jersey; may require material capital expenditures.

those costs are being recovered by JCP&L through a non-(D) OTHER LEGAL PROCEEDINGS-bypassable SBC. Included inCurrent Liabilities and Other Noncurrent Liabilities are accrued liabilities aggregating approxi- Power Outages and Related Litigation mately $65 million as of December 31, 2004. The Companies In July 1999, the Mid-Atlantic States experienced a accrue environmental liabilities only when they conclude that it severe heat wave, which resulted in power outages is probable that they have an obligation for such costs and can throughout the service territories of many electric utilities, reasonably determine the amount of such costs. Unasserted including JCP&L's territory. In an investigation into the caus-claims are reflected inthe Companies' determination of environ- es of the outages and the reliability of the transmission and mental liabilities and are accrued in the period that they are both distribution systems of all four New Jersey electric utilities, probable and reasonably estimable. the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inade-Climate Change quate or improper service to its customers. Two class action In December 1997, delegates to the United Nations' lawsuits (subsequently consolidated into a single proceed-climate summit in Japan adopted an agreement, the Kyoto ing) were filed in New Jersey Superior Court in July 1999 Protocol (Protocol), to address global warming by reducing against JCP&L, GPU and other GPU companies, seeking the amount of man-made greenhouse gases emitted by compensatory and punitive damages arising from the July developed countries by 5.2% from 1990 levels between 1999 service interruptions in the JCP&L territory.

2008 and 2012. The United States signed the Protocol in In August 2002, the trial court granted partial summary 1998 but it failed to receive the two-thirds vote of the judgment to JCP&L and dismissed the plaintiffs' claims for United States Senate required for ratification. However, consumer fraud, common law fraud, negligent misrepresenta-the Bush administration has committed the United States tion, and strict product liability. In November 2003, the trial to a voluntary climate change strategy to reduce domestic court granted JCP&L's motion to decertify the class and greenhouse gas intensity - the ratio of emissions to eco- denied plaintiffs' motion to permit into evidence their class-nomic output - by 18 percent through 2012. wide damage model indicating damages in excess of $50 The Companies cannot currently estimate the financial million. These class decertification and damage rulings were impact of climate change policies, although the potential appealed to the Appellate Division. The Appellate Court restrictions on C02 emissions could require significant capi- issued a decision on July 8, 2004, affirming the decertification tal and other expenditures. However, the C02 emissions per of the originally certified class but remanding for certification kilowatt-hour of electricity generated by the Companies is of a class limited to those customers directly impacted by the 66 FirstEnergyCorp. 2004

outages of transformers in Red Bank, New Jersey. On Three substantially similar actions were filed invarious Ohio September 8, 2004, the New Jersey Supreme Court denied state courts by plaintiffs seeking to represent customers who the motions filed by plaintiffs and JCP&L for leave to appeal allegedly suffered damages as a result of the August 14, 2003 the decision of the Appellate Court. FirstEnergy is unable to power outages. All three cases were dismissed for lack of juris-predict the outcome of these matters and no liability has diction. One case was refiled at the PUCO. The other two cases been accrued as of December 31, 2004. were appealed. One case was dismissed and no further appeal On August 14, 2003, various states and parts of southern was sought. The remaining case is pending. In addition to the Canada experienced widespread power outages. The outages one case that was refiled at the PUCO, the Ohio Companies affected approximately 1.4 million customers in FirstEnergy's were named as respondents in a regulatory proceeding that service area. On April 5, 2004, the U.S. - Canada Power was initiated at the PUCO in response to complaints alleging System Outage Task Force released its final report on the out- failure to provide reasonable and adequate service stemming ages. In the final report, the Task Force concluded, among primarily from the August 14, 2003 power outages.

other things, that the problems leading to the outages began in One complaint has been filed against FirstEnergy in the FirstEnergy's Ohio service area. Specifically, the final report New York State Supreme Court. In this case, several plain-concludes, among other things, that the initiation of the August tiffs in the New York City metropolitan area allege that they 14, 2003 power outages resulted from an alleged failure of suffered damages as a result of the August 14, 2003 power both FirstEnergy and ECAR to assess and understand per- outages. None of the plaintiffs are customers of any ceived inadequacies within the FirstEnergy system; inadequate FirstEnergy affiliate. FirstEnergy filed a motion to dismiss situational awareness of the developing conditions; and a per- with the Court on October 22, 2004. No timetable for a deci-ceived failure to adequately manage tree growth in certain sion on the motion to dismiss has been established by the transmission rights of way. The Task Force also concluded that Court. No damage estimate has been provided and thus there was a failure of the interconnected grid's reliability organi- potential liability has not been determined.

zations (MISO and PJM) to provide effective real-time FirstEnergy is vigorously defending these actions, but diagnostic support. The final report is publicly available through cannot predict the outcome of any of these proceedings or the Department of Energy's website (www.doe.gov). whether any further regulatory proceedings or legal actions FirstEnergy believes that the final report does not provide a may be initiated against the Companies. In particular, if complete and comprehensive picture of the conditions that FirstEnergy or its subsidiaries were ultimately determined to contributed to the August 14, 2003 power outages and that it have legal liability in connection with these proceedings, it does not adequately address the underlying causes of the out- could have a material adverse effect on FirstEnergy's or its ages. FirstEnergy remains convinced that the outages cannot subsidiaries' financial condition and results of operations.

be explained by events on any one utility's system. The final report contains 46 "recommendations to prevent or minimize Nuclear Plant Matters the scope of future blackouts." Forty-five of those recommen- FENOC received a subpoena in late 2003 from a grand dations relate to broad industry or policy matters while one, jury sitting in the United States District Court for the Northern including subparts, relates to activities the Task Force recom- District of Ohio, Eastern Division requesting the production of mends be undertaken by FirstEnergy, MISO, PJM, ECAR, and certain documents and records relating to the inspection and other parties to correct the causes of the August 14, 2003 maintenance of the reactor vessel head at the Davis-Besse power outage. FirstEnergy implemented several initiatives, Nuclear Power Station. On December 10, 2004, FirstEnergy both prior to and since the August 14, 2003 power outages, received a letter from the United States Attorney's Office which are consistent with these and other recommendations stating that FENOC is a target of the federal grand jury inves-and collectively enhance the reliability of its electric system. tigation into alleged false statements made to the NRC in the FirstEnergy certified to NERC on June 30, 2004, completion of Fall of 2001 in response to NRC Bulletin 2001-01. The letter various reliability recommendations and further received inde- also said that the designation of FENOC as a target indicates pendent verification of completion status from a NERC that, in the view of the prosecutors assigned to the matter, it verification team on July 14, 2004 with minor exceptions noted is likely that federal charges will be returned against FENOC by FirstEnergy (see Note 9). FirstEnergy's implementation of by the grand jury. On February 10, 2005, FENOC received an these recommendations included completion of the Task Force additional subpoena for documents related to root cause recommendations that were directed toward FirstEnergy. As reports regarding reactor head degradation and the assess-many of these initiatives already were in process, FirstEnergy ment of reactor head management issues at Davis-Besse.

does not believe that any incremental expenses associated In addition, FENOC remains subject to possible civil with additional initiatives undertaken during 2004 will have a enforcement action by the NRC in connection with the material effect on its continuing operations or financial results. events leading to the Davis-Besse outage in 2002. If it were FirstEnergy notes, however, that the applicable government ultimately determined that FirstEnergy or its subsidiaries has agencies and reliability coordinators may take a different view legal liability or is otherwise made subject to enforcement as to recommended enhancements or may recommend addi- action based on the Davis-Besse outage, it could have a tional enhancements in the future that could require additional, material adverse effect on FirstEnergy's or its subsidiaries' material expenditures. FirstEnergy has not accrued a liability as financial condition and results of operations.

of December 31, 2004 for any expenditures in excess of those On August 12, 2004, the NRC notified FENOC that it will actually incurred through that date. increase its regulatory oversight of the Perry Nuclear Power Firs tEnergy Corp. 2004 67

Plant as a result of problems with safety system equipment 14. Segment Information:

over the past two years. FENOC operates the Perry Nuclear Power Plant, which is either owned or leased by OE, CEI, TE FirstEnergy has three reportable segments: regulated and Penn. Although the NRC noted that the plant continues to services, competitive electric energy services and facilities operate safely, the agency has indicated that its increased over- (HVAC) services. The aggregate "Other" segments do not sight will include an extensive NRC team inspection to assess individually meet the criteria to be considered a reportable the equipment problems and the sufficiency of FENOC's correc- segment. "Other" consists of international businesses that tive actions. The outcome of these matters could include NRC have subsequently been divested, MYR (aconstruction service enforcement action or other impacts on operating authority. As company); natural gas operations and telecommunications a result, these matters could have a material adverse effect on services. The assets and revenues for the other business FirstEnergy's or its subsidiaries' financial condition. operations are below the quantifiable threshold for operating segments for separate disclosure as "reportable segments."

Other Legal Matters FirstEnergy's primary segment is its regulated services seg-There are various lawsuits, claims (including claims for ment, whose operations include the regulated sale of electricity asbestos exposure) and proceedings related to FirstEnergy's and distribution and transmission services by its eight EUOC in normal business operations pending against FirstEnergy and its Ohio, Pennsylvania and New Jersey. The competitive electric subsidiaries. The most significant not otherwise discussed energy services business segment primarily consists of the above are described below. subsidiaries (FES, FGCO and FENOC) that sell electricity in Various legal proceedings alleging violations of federal secu- deregulated markets and operate the generation facilities of rities laws and related state laws were filed against FirstEnergy OE, CEI, TE and Penn resulting from the deregulation of the in connection with, among other things, the restatements in Companies' electric generation business (see Note 2(A) -

August 2003 by FirstEnergy and the Ohio Companies of previ- Accounting for the Effects of Regulation).

ously reported results, the August 14, 2003 power outages The regulated services segment designs, constructs, oper-described above, and the extended outage at the Davis-Besse ates and maintains FirstEnergy's regulated transmission and Nuclear Power Station. The lawsuits were filed against distribution systems. Its revenues are primarily derived from elec-FirstEnergy and certain of its officers and directors. On July 27, tricity delivery and transition costs recovery. The regulated services 2004, FirstEnergy announced that it had reached an agreement segment assets include generating units that are leased to the to resolve these pending lawsuits. The settlement agreement, competitive electric energy services. Its internal revenues repre-which does not constitute any admission of wrongdoing, pro- sent the rental revenues for the generating unit leases.

vides for a total settlement payment of $89.9 million. Of that The competitive electric energy services segment has amount, FirstEnergy's insurance carriers paid $71.92 million, responsibility for FirstEnergy generation operations as discussed based on a contractual pre-allocation, and FirstEnergy paid under Note 2(A). Its net income is primarily derived from rev-

$17.98 million, which resulted in an after-tax charge against enues from all electric generation sales revenues consisting of FirstEnergy's second quarter 2004 earnings of $11 million or generation services to regulated franchise customers who have

$0.03 per share of common stock (basic and diluted). On not chosen an alternative generation supplier, retail sales in December 30, 2004, the court approved the settlement. deregulated markets and all domestic unregulated electricity On October 20, 2004, FirstEnergy was notified by the SEC sales in the retail and wholesale markets and the related costs of that the previously disclosed informal inquiry initiated by the electricity generation and sourcing of commodity requirements.

SEC's Division of Enforcement in September 2003 relating to Its net income also reflects the expense of the intersegment the restatements inAugust 2003 of previously reported results generating unit leases discussed above and property tax by FirstEnergy and the Ohio Companies, and the Davis-Besse amounts related to those generating units.

extended outage, have become the subject of a formal order of Segment reporting for 2003 and 2002 was reclassified to investigation. The SEC's formal order of investigation also conform with the current year business segment organization encompasses issues raised during the SEC's examination of and operations emphasizing FirstEnergy's regulated electric busi-FirstEnergy and the Companies under the PUHCA. Concurrent nesses and competitive electric energy operations. A previous with this notification, FirstEnergy received a subpoena asking for reportable segment was the more expansive competitive servic-background documents and documents related to the restate- es segment whose aggregate operations consisted of ments and Davis-Besse issues. On December 30, 2004, FirstEnergy generation operations, natural gas commodity sales, FirstEnergy received a second subpoena asking for documents providing local and long-distance phone service and other com-relating to issues raised during the SEC's PUHCA examination. petitive energy related businesses such as facilities services and FirstEnergy has cooperated fully with the informal inquiry and construction service (MYR) which was viewed as offering a com-will continue to do so with the formal investigation. prehensive menu of energy related services. Management's If it were ultimately determined that FirstEnergy or its sub- focus is on its core electric business. This has resulted ina sidiaries have legal liability or are otherwise made subject to change in performance review analysis from an aggregate view liability based on the above matter, it could have a material of all competitive services operations to a focus on its competi adverse effect on FirstEnergy's or its subsidiaries' financial con- tive electric energy operations. During FirstEnergy's periodic dition and results of operations. review of reportable segments under SFAS 131, that change resulted inthe revision of reportable segments to the separate reporting of competitive electric energy operations, facilities serv-6S FirsrEnergyCorp. .?004

ices and including all other competitive services operations in th 6& Products and Services' "Other" segment. Facilities services is being disclosed as a Energy Related Year Electricity Sales Sales and Services reporting segment due to the subsidiaries qualifying as held for sale (see Note 2 (H)). In addition, certain amounts (including (Inmillions) 2004 $10.831 $745 transmission and congestion charges) were reclassified among 2003 10.205 766 purchased power, other operating costs and depreciation and 2002 9,656 904 amortization to conform with the current year.presentation of

• See Note 2(J) for discussion of discontinued operations.

generation commodity costs. Interest expense on holding com-pany debt and corporate support services revenues and Geographic Information expenses are now included in "Reconciling Items" and "Other' Following the sales of international operations in 2002 includes those operating segment results described above. through January of 2004, less than one percent of FirstEnergy's revenues and assets were in foreign countries Segment Financial Information in 2003 and 2004. See Note 8 for a discussion of the Corpetitive EIbctvic divestitures.

Regulated EnergyFscilites Reconciling Services Services Services Other Adiupxneets Cmnsolidated (Inmillions) 15. New Accounting Standards 2004 External revenues $5.395 $6,204 $398 $451 S5 $12,453 and Interpretations Internal revenues 318 - - (318)

Total revenues 5,713 6,204 398 451 (3131 12,453 SFAS 153, 'Exchanges of Nonmonetary Assets -

Depreciation and amortization 1.422 35 5 3 34 1,499 an amendment of APB Opinion No. 29" Goodwill impairment 36 36 In December 2004, the FASB issued this Statement Net interest charges 363 37 14 252 667 Income taxes 740 72 1101 (24) (107) 671 amending APB 29, which was based on the principle that Income before nonmonetary assets should be measured based on the fair discontinued operations 1,015 104 136) 41 (250) 874 Discontinued operations 4 4 value of the assets exchanged. The guidance in APB 29 Net income 1,015 104 136) 45 (2501 878 included certain exceptions to that principle. SFAS 153 Total assets 28,341 1,488 135 625 479 31,068 eliminates the exception from fair value measurement for Total goodwill 5.951 24 75 6,050 Property additions 572 245 3 4 21 846 nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have r 2003 commercial substance. This Statement specifies that a non-External revenues 55,253 $55487 $327 5564 $44 511,675 Internal revenues 319 (3191 monetary exchange has commercial substance if the future Total revenues 5.572 5,487 327 564 (2751 11,675 cash flows of the entity are expected to change significantly Depreciation and as a result of the exchange. The provisions of this state-amortization 1.423 29 - 2 38 1.492 Goodwill impairment 117 - 117 ment are effective for nonmonetary exchanges occurring Net interest charges 493 44 1 107 164 809 in fiscal periods beginning after June 15, 2005 and are to Income taxes 779 (2221 135) (18) 196) 408 Income before discontinu be applied prospectively. FirstEnergy is currently evaluating operations and cumulativ this standard but does not expect it to have a material effect of accounting change 1.063 (320) 175) (64) (180) 424 impact on the financial statements.

Discontinued operations - - (6) 197) 1103)

Cumulative effect of SFAS 123 (revised 2004) 'Share-Based Payment" accounting change 101 - - 1 102 Net income 1.164 (320) (81) (160) (180) 423 In December 2004, the FASB issued this revision to Total assets 29.789 1,423 166 912 620 32,910 SFAS 123, which requires expensing stock options in the Total goodwill 5.993 24 36 75 6,128 Property additions 434 335 4 9 74 856 financial statements. Important to applying the new stan-dard is understanding how to (1)measure the fair value of 2002 stock-based compensation awards and (2) recognize the External revenues $55298 $4.825 $383 $907 $40 $11,453 related compensation cost for those awards. For an award Internal revenues 318 - - - (318) -

Total revenues 5.616 4.825 383 907 (278) 11.453 to qualify for equity classification, it must meet certain crite-Depreciation and ria in SFAS 123(R). An award that does not meet those amortization 1,413 24 6 2 34 1,479 Net interest charges 588 43 2 134 189 956 criteria will be classified as a liability and remeasured each Income taxes 722 (88) 2 114) (1081 514 period. SFAS 123(R) retains SFAS 123's requirements on Income before discontinued operations 962 (170) - 21 (1951 618 accounting for income tax effects of stock-based compensa-Discontinued operations - - 3 168) - (65) tion. The effective date for FirstEnergy is July 1, 2005 and Net income 962 (170) 3 147) (1951 553 the Company will be applying modified prospective applica-Total assets 30,494 1,340 402 1.606 544 34,386 Total goodwill 5.993 24 196 65 - 6.278 tion, without restatement of prior interim periods. Any Property additions 490 391 6 9 102 998 potential cumulative adjustments have not been deter-Reconciling adjustments to segment operating results from internal management mined. FirstEnergy uses the Black-Scholes option-pricing reporting to consolidated external financial reporting primarily consists of interest model to value options and will continue to do so upon expense related to holding company debt corporate support services revenues and expenses, fuel marketing revenues, which are reflected as reductions to adoption of SFAS 123(R). The impacts of the fair value expenses for internal management reporting purposes and elimination of recognition provisions of SFAS 123 on FirstEnergy's net intersegment transactions.

FirstEnergv Corp. 2004 69

income and earnings per share for 2002 through 2004 are duction activities. The Act includes a tax deduction of up to 9 disclosed in Note 4. FirstEnergy is considering alternative percent (when fully phased-in) of the lesser of (a) "qualified compensation strategies in conjunction with the adoption of production activities income," as defined in the Act, or (b)

SFAS 123(R). taxable income (after the deduction for the utilization of any net operating loss carryforwards). This tax deduction is limit-SFAS 151, 'Inventory Costs - an amendment of ARB ed to 50 percent of W-2 wages paid by the taxpayer. The No. 43, Chapter 4" FASB believes that the deduction should be accounted for as In November 2004, the FASB issued this statement to a special deduction in accordance with SFAS No. 109, clarify the accounting for abnormal amounts of idle facility "Accounting for Income Taxes." FirstEnergy is currently eval-expense, freight, handling costs and wasted material uating this FSP but does not expect it to have a material (spoilage). Previous guidance stated that in some circum- impact on the Company's financial statements.

stances these costs may be "so abnormal" that they would require treatment as current period costs. SFAS 151 requires FSP 106-2, "Accounting and Disclosure Requirements abnormal amounts for these items to always be recorded as Related to the Medicare Prescription Drug, current period costs. In addition, this Statement requires that Improvement and Modernization Act of 2003" allocation of fixed production overheads to the cost of con- Issued in May 2004, FSP 106-2 provides guidance on version be based on the normal capacity of the production accounting for the effects of the Medicare Act for employ-facilities. The provisions of this statement are effective for ers that sponsor postretirement health care plans that inventory costs incurred by FirstEnergy after June 30, 2005. provide prescription drug benefits. FSP 106-2 also requires FirstEnergy is currently evaluating this standard but does not certain disclosures regarding the effect of the federal sub-expect it to have a material impact on the financial statements. sidy provided by the Medicare Act. The effect of the federal subsidy provided under the Medicare Act on FirstEnergy's EITF Issue No. 03-1, "The Meaning of Other-Than- consolidated financial statements is described in Note 3.

Temporary Impairment and its Application to Certain Investments' 16. Summary of Quarterly Financial In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model Data (Unaudited):

1 for determining when investments in certain debt and equity securities are considered other than temporarily impaired. The following summarizes certain consolidated operating When an impairment is other-than-temporary, the investment results by quarter for 2004 and 2003. Certain financial results must be measured at fair value and the impairment loss have been reclassified from amounts previously reported due recognized in earnings. The recognition and measurement to FES' natural gas business qualifying as held for sale in provisions of EITF 03-1, which were to be effective for accordance with SFAS 144 as discussed in Note 2(J).

periods beginning after June 15, 2004, were delayed by March 31, June 30, Sept 30. Dec. 31, the issuance of FSP EITF 03-1-1 in September 2004. During Three Months Ended 2004 2004 2004 2004 1 the period of delay, FirstEnergy will continue to evaluate its {In millions, except per share ame ufnts) i investments as required by existing authoritative guidance. Revenues 53.027 $3,041 $3.435 $2,950 Expenses 2,568 2,481 2,771 2,421 EITF Issue No. 03-16, "Accounting for Investments in Income Before Interest and Income Taxes 459 560 664 529 Limited Liability Companies- Net Interest Charges 171 180 151 165 In March 2004, the FASB ratified the final consensus on Income Taxes 115 177 215 163 Issue 03-16. EITF 03-16 requires that an investment in a lim- Income Before Discontinued Operations 173 203 298 201 ited liability company that maintains a "specific ownership Discontinued Operations account" for each investor should be viewed as similar to INet of Income Taxes) 1 1 1 1 an investment in a limited partnership for determining Net Income $174 $204 $299 S202 whether the cost or equity method of accounting should be Basic Earnings used. The equity method of accounting is generally required Per Share of Common Stock:

Before Discontinued Operations S0.53 SO.62 $0.91 $0.61 for investments that represent more than a three to five Discontinued Operations percent interest in a limited partnership. EITF 03-16 was Basic Earnings Per Share adopted by FirstEnergy in the third quarter of 2004 and did of Common Stock SO.53 $0.62 $0.91 $0.61 not affect the Companies' financial statements. Diluted Earnings Per Share of Common Stock:

Before Discontinued Operations. $0.53 $0.62 $0.91 $0.61 FSP 109-1, 'Application of FASB Statement No. 109, Discontinued Operations - - - -

Accounting for Income Taxes, to the Tax Deduction Diluted Earnings Per Share of Common Stock $0.53 $0.62 $ 0.91 $0.61 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-70 FrustEnergyCorp 2004

March 31. June 30, Sept 30. Dec. 31, ThreeMonthsEnded . 2003 .2003 2003 *2003 (Inmillions. except per share amounts)

Revenues 52.981 52.728 -3.317 S2.649 Expenses 2.571 2,488 2,833 2,310 Claim Settlement (Note 8) - - - . 168 I Income Before Interest and Income Taxes 410 240 484 507 Net Interest Charges 205 205 200 199 IncomeTaxes 93 21 . 134 160 Income Before Discontinued Operations and Cumulative Effect of Accounting Change 112 14 150 148 Discontinued Operations (Net of Income Taxes) 5 (72) 2 (38)

Cumulative Effect of Accounting Change (Net of Income Taxes) 102 - - -

Net Income (Loss) S 219 S (58) . $ 152 S 110 Basic Earnings (Loss) Per Share of Common Stock:

Before Discontinued Operations and Cumulative Effect of Accounting Change S 0.38 S 0.05 $ 0.51 S 0.45 Discontinued Operations 0.01 (0251 - (0.121 Cumulative Effect of

• Accounting Change 0.35 - - -

Basic Earnings (Lossl Per Share of Common Stock S 0.74 510.20) S 0.51 $ 0.33 Diluted Earnings (Loss)

Per Share of Common Stock:

Before Discontinued Operations and Cumulative Effect of Accounting Change S 0.38 $ 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 S 0.74 5(0.20) S 0.50 $ 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.

FirstEnergy Corp. 2004 71

CONSOLIDATED FINANCIAL AND PRO FORMA COMBINED OPERATING STATISTICS (Unaudited) (see Note 2(J))

(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 S 6,470,488 $ 6,130,004 $2,390,957 Net Income $ 878,175 S 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 S21,339,001 $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% 7.99x 7.15' Long-Term Debt 5.93x 6.08% 6.56% 6.98% 7.84% 7.65X 8.17%

Common Stock Data Earnings per Share Ibl 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 Equity Ib) 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 S1.50 $1.50 Dividend Payout Ratio(b) 56% 107% 71% 53% 56% 60% 76%

Dividend Yield 3.8% 43% 4.5% 4.3% 4.8% 6.6% 8.1' Price/Earnings Ratio bl 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 (0 Generation iGlfwatt-Hour Sales (Millonsk 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 Id 2001 capitalization includes approximately S1.4 billion of long-term debt (excluding long-term debt due to be repaid within one year) included in 'Liabilities Related to Assets Pending Sale' on the Consolidated Balance Sheet as of December 31. 2001.

lb Before discontinued operations in2004, 2003 and 2002 and accounting changes in 2003 and 2001.

IcdReflects pro forma combined FirstEnergy and 6PU statistics in the years 1999 to 2001 and pro forma combined Ohio Edison, Centerior and GPU statistics in years prior to 1999.

72 FirstEnergy Corp. 2004

Shareholder Information Shareholder Services, Transfer Agent and Registrar Combining Stock Accounts FirstEnergy Securities Transfer Company, a subsidiary of FirstEnergy, If you have more than one stock account and want to combine acts as our own transfer agent and registrar for all stock issues of them, please write or call Shareholder Services and specify the FirstEnergy and its subsidiaries. Shareholders wanting to transfer account that you want to retain as well as the registration of each stock, or who need assistance or information, can send their stock of your accounts.

or write to Shareholder Services, FirstEnergy Corp., 76 South Main Street, Akron, Ohio 44308-1890. Shareholders also can call the Stock Investment Plan following tollfree telephone number, which is valid inthe United Shareholders and others can purchase or sell shares of FirstEnergy States, Canada, Puerto Rico and the Virgin Islands, weekdays common stock through the Company's Stock Investment Plan.

between 8 a.m. and 4:30 p.m., Eastern Time: 1-800-736-3402. Investors who are not registered shareholders can enroll with an For Internet access to general shareholder information and useful initial $250 cash investment. Participants may invest all or some forms, visit our Web site at www.frstenergycorp.conmlr. of their dividends or make optional cash payments at any time of at least S25 per payment up to $100,000 annually. Contact Stock Listings and Trading Shareholder Services to receive an enrollment form.

Newspapers generally report FirstEnergy common stock under the abbreviation FSTENGY, but this can vary depending upon the news- Safekeeping of Shares paper. The common stock of FirstEnergy and preferred stock of its Shareholders can request that the Company hold their shares of electric utility subsidiaries are listed on the following stock exchanges: FirstEnergy common stock in safekeeping. To take advantage of this service, shareholders should forward their common stock certifi-Company Stock Exchange Symbol ' cate($) to the Company along with a signed letter requesting that the Company hold the shares. Shareh6lders also should state FirstEnergy New York FE whether future dividends for the held shares are to be reinvested Jersey Central New York JYP or paid incash. The certificate(s) should not be endorsed, and Ohio Edison New York OEC registered mail is suggested. The shares will be held in uncertificated Pennsylvania Power Philadelphia PPC form, and we will make certificate(s) available to shareholders upon Toledo Edison New York, OTC TED request at no cost. Shares held insafekeeping will be reported on American dividend checks or Stock Investment Plan statements.

Form 10-K Annual Report Dividends Form 10-K, the Annual Report to the Securities and Exchange Proposed dates for the payment of FirstEnergy common stock Commission, will be sent without charge by writing to David W.

dividends in 2005 are:

Whitehead, Corporate Secretary, FirstEnergy Corp., 76 South Main Street, Akron, Ohio 44308-1890.

I Ex-Dividend Date Record Date Payment Date j February 3 February 7 March 1 . i Institutional Investor and Security Analyst Inquiries May 4 May 6 June 1 A Institutional investors and security analysts should direct inquiries to:

August 3 August 5 September 1 Kurt E.Turosky, Director, Investor Relations, 330-384-5500.

iNovember 3 November 7 December 1 i Annual Meeting of Shareholders All dividends are subject to declaration by the Board of Directors Shareholders are invited to attend the 2005 Annual Meeting of at its discretion. 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.

Direct Dividend Deposit Registered shareholders not attending the meeting can appoint Shareholders can have their dividend payments automatically a proxy and vote on the items of business by telephone, Internet deposited to checking and savings accounts at any financial institu- or by completing and returning the proxy card that is sent to them.

ton that accepts electronic direct deposits. Use of this free service Shareholders whose shares are held in the name of a broker can ensures that payments will be available to you on the payment date, attend the meeting if they present a letter from their broker eliminating the possibility of mail delay or lost checks. Contact indicating ownership of FirstEnergy common stock on the record Shareholder Services to receive an authorization form. date of March 22, 2005.

FirstEnergy has included as Exhibit 31 to its Annual Report on Form 10-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. ForstEnergy's Chief Executive Officer has also submitted to the New York Stock Exchange (NYSE) a certificate certifying that he was not aware of any violation by FrstEnergy of the NYSE corporate governance listing standards as of the date of the certification.

@Printed on recycled paper firstEneTy Corp. 2004 73

FirstEqpjy 76 South Main Street, Akron, OH 44308-1890 www.firstenergycorp.com PRESORTED STD.

U.S. POSTAGE PAID AKRON, OHIO PERMIT NO. 561 2004 Annual Report