L-04-037, Letter Forwarding 2003 Firstenergy Corp. Annual Report

Letter Forwarding 2003 Firstenergy Corp. Annual Report

ML041120421
Person / Time
Site:	Beaver Valley, Davis Besse, Perry
Issue date:	04/12/2004
From:	Scilla R FirstEnergy Corp
To:	Dinitz I Office of Nuclear Reactor Regulation
References
-RFPFR, 3039, L-04-037, PY-CEI/NRR-2776L
Download: ML041120421 (77)

Text

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-.I 76 South Main Street Akron. Ohio 44308-1890

• Randy Sdfla Assistant Treasurer 330-384-5202

. Fax:330-384-3772 April 12, 2004 P

PY-CEI/NRR-2776L

• DB-Serial No.-3039 BV-No. L-04-037 Mr. Ira Dinitz U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Washington, D.C. 20555. -

• Dear Mr. Dimitz; Re:

Docket Nos..50-346, 50-440,'50-412, 50-334 Retrospective Premium Guarantee Enclosed you will find the 2003 FirstEnergy Corp. Annual'Report: This is in addition to the 2004 Internai Cash Flow Projection sent March 11, 2004 and completes the requirements for the Retrospective Premium Guarantee.

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• *1 adp Enclosures S \\Treasury\\SHRTRS\\FinanciaLStudies\\UM\\N~RC Filing - Eth 2004\\NRC Filing Cover Letter 04 - annual reportdoc I. H. 009

FirstEnergy 2 0 0 3 A N N U A L R E P O R T N.

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H. PETER BURG 1946 - 2004 W

Ye were deeply saddened iby the unimely loss of FirstEnergy Chairman and Chief Executive Officer H. Peter Burg, who passed away on January 13, 2

Mr. Burg had been unhder-going treatment for leukemia.

Mr. Burg had an unwavering commitment to enhancinyg the value of your investment in FirstEnergy, and played a key role in helping yOur Company become the nations fifth largest electric system. Under his leadership, our market value increased W

$4 billion, and our customer base and assets doubled His contributions to customers and our ommurnities waere also significant, with his tireless support of many civic and business organi-ztons that provided substantial benefits to the peope we: seve.

Mr Burg was a man of the highest integrity who dedicated his lie to his familyt your Compang anM our communities. His legacy iriludeas the dedication and hard work of employes, Who continue to be inspired by his vision, leader-ship and huNanity.

ILLUMINATING COMPANY THE TOLEDO EDISON COMPANY PENNSYLVANIA ELECTRIC COMPANY JERSEY CENTRAL POWER

& LIGHT COMPANY 4Ie q,

PENNSYLVANIA POWER COMPANY OHIO EDISON COMPANY METROPOLITAN EDISON COMPANY C

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10 It A{ -5 E PR 0 F I 1 E

FirstEnergy Corp. (NYSE: FE) is a registered public utility holding company headquartered in Akron, Ohio. FirstEnergy subsidiaries and affiliates are involved in the generation, transmission and distribution of electricity; exploration and production of oil and natural gas; trans-mission and marketing of natural gas; and energy management and other energy-related services.

FirstEnergy's electric utility operating companies comprise the nation's fifth largest investor-owned electric system, based on 4.4 million customers served.

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he year 2003 was difficult for your Company.

We faced a number of challenges, including restart efforts at Davis-Besse, the August 14 power outage and others detailed in this report. And, clearly, earnings of $1.39 per share of common stock were disappointing.

My top priority as your new chief executive officer is to increase the value of your investment by enhancing our operational performance and financial strength. With several key challenges behind us, including approval to restart Davis-Besse, we're on track to deliver strong performance in 2004 and in the years ahead.

Providing High-Quality Customer Service With our electric business at the core, our road map to success continues to be our retail business strategy, which is disciplined, integrated and regional in scope.

Our seven electric operating companies generate strong and stable cash flow and remain our platform for growth.

While three-quarters of customers surveyed continue to give us high marks in key areas - such as service reliability and restoration, and employee performance

- we recognize we must continually work to ensure our service areas remain the preferred location for our customers to live and do business.

2

Among the steps we've taken are reorganizing and strengthening our Energy Delivery management team, providing an even greater focus on reliability, standardiz-ing practices across our service areas, and enhancing our responsiveness and accountability to customers.

We're also making prudent and targeted system improvements to help ensure that all of our companies match the strong performance we've historically achieved. For example, to enhance service in New Jersey, we accelerated the investment of $60 million in system improvements. In addition, we've implemented an enhanced vegetation management program system-wide to further support our efforts to provide reliable customer service.

We completed the conversion of our computer system to an SAP-based platform. This new system provides significant benefits, including more comprehen-sive information for customer service and outage management programs.

We're also installing a state-of-the-art computer control system for our transmission operations that offers redundant capabilities for our control centers in Ohio and Pennsylvania. This process started prior to the August 14 outage.

As became clear after the outage, the transmission grid is being used in ways for which it wasn't designed, including large-scale, long-distance transfers of power by others across our part of the system.

The U.S.-Canada Power System Outage Task Force's interim report pointed to events on our system - includ-ing several transmission line trips and problems with our computer monitoring system - as some of the contribut-ing factors. We have fully cooperated with the Task Force and various other reviews. However, we remain convinced, as do other experts, that the August 14 out-age cannot be explained by the events on our system alone or on any other single utility system.

Enhancing the Performance of Our Generating Fleet Our generating fleet delivered another year of strong performance in 2003, driven mainly by our baseload coal-fired plants. Capacity factors of these units reached a record 82 percent, and are on track to exceed that level in 2004.

We are optimizing our baseload units by operating them at more consistent output factors, instead of cycling them to follow customer load. This approach reduces wear and tear, lowers operating and maintenance costs, and improves our cost competitiveness.

Strong performance by our coal-fired plants helped offset last year's decline in nuclear power production resulting from the extended outage at Davis-Besse, and scheduled refueling outages at our Beaver Valley and Perry plants. However, with Davis-Besse's return to service and two fewer refueling outages scheduled in 2004, we expect to increase nuclear production by more CC s With our electric business at the core, our road map to success continues to be our retail business strategy, which is disciplined, integrated and regional in scope. 9 s

I II13L 4

4 The hard work and dedication of employees pulled us through a very difficult period in our history....

than one-third, which should help our generating fleet achieve record output this year.

During the extended outage at Davis-Besse, we replaced the damaged reactor vessel head; strengthened the management teams at the plant and within our FirstEnergy Nuclear Operating Company (FENOC) subsidiary; made numerous improvements to plant systems and equipment; and, most important, greatly enhanced the focus on safe operations by plant management and employees.

We invested a great deal of time and money to bring the 883-megawatt plant back on line because we believe that operating a baseload generating unit of this size will remain a competitive advantage. We're confident our nuclear fleet will achieve solid performance under FENOC's new business plan, which is designed to help our nuclear plants become top-quartile performers in the industry.

While strong performance by our generating fleet lowers our reliance on the wholesale market, we still are focused on ensuring sound risk management. In 2003, we enhanced our hedging strategy by implementing further protections against price volatility in the market that our Company and industry have faced in recent years.

Protecting the Environment We're continuing to fulfill our commitment to pro-tecting the environment, while meeting customer needs for reliable and affordable electricity.

Through the installation of selective catalytic reduc-tion and other environmental control systems, as well as other measures, we've made steady progress, reducing emissions of nitrogen oxides by 60 percent and sulfur dioxide by 52 percent since 1990. Despite these results, the U.S. Environmental Protection Agency continues to pursue legal action against our W. H. Sammis Plant and dozens of other plants in the U.S.

We strongly disagree with an August 2003 federal district court decision related to that action. It adopted the EPA's claim that routine maintenance, repairs and replacements at our plant - like those performed for decades at coal-fired power plants across the country -

triggered New Source Review provisions of the Clean Air Act, even though capacity and hourly emission rates did not increase. The remedy trial of the Sammis case is scheduled to begin in July. We continue to evaluate our legal options, which may include a resolution by the appellate courts because of conflicting judicial decisions in other cases.

4

Increasing Our Financial Strength and Flexibility Increasing our financial strength remains a key element of our business strategy. We're focusing on specific initiatives, which include continuing to generate strong and stable cash flow and reducing costs.

We're also taking aggressive actions to improve our credit quality. Our common equity offering completed during the third quarter was an important step. We issued 32 million common shares, generating net pro-ceeds of $935 million, which helped reduce net debt and preferred stock by $1.9 billion last year. These actions, along with refinancings and other activities to reduce interest costs during the year, are expected to produce approximately $155 million in annualized pre-tax savings.

At year-end, our adjusted debt ratio was 59 percent, and our goal is to lower that to about 50 percent by the end of 2005. We'll achieve that by continuing to dedicate our free cash flow - cash flow after the payment of common stock dividends and capital expenditures - to debt reduction.

We further strengthened our financial position by achieving savings of $120 million in 2003 related to our 2001 merger with the former GPU, Inc. We are on track to reach $150 million at the end of this year. We expect to save another $135 million by the end of 2004 through other cost-reduction initiatives.

And, we divested our remaining international holdings acquired through the GPU merger, as well as other non-core assets, consistent with our commitment to focus on our core electric business.

In addition, approval of our Ohio rate stabilization plan would provide a longer period of revenue and cash flow predictability for our Ohio operating companies and rate stability for customers.

While 2003 was a challenging year, our four-year annualized total shareholder return at year-end of 17.2 percent still ranked us 20th among the 64 U.S.

investor-owned electric utilities that comprise the Edison Electric Institute Index. This key measure represents the market appreciation of common stock, including the reinvestment of dividends.

Delivering Stronger Performance Our foundation for growth remains sound, and our commitment to delivering stronger performance is unwavering. The hard work and dedication of employees pulled us through a very difficult period in our history, which was compounded by the loss of our Chairman and CEO H. Peter Burg.

With their drive and resolve, and your support, we intend to enhance the value of your investment in FirstEnergy this year, and achieve continued success in the years ahead.

Sincerely, Anthony J. Alexander President and Chief Executive Officer March 19, 2004 5

FIRSTENERGY Paul T. Addison Anthony J. Alexander BOARD OF DIRECTORS

Dear Shareholders:

It is my honor to serve as chairman of FirstEnergy's Board of Directors. I want to assure you that your Board is continually reviewing its corporate governance policies and procedures in light of the challenges facing public companies today. Part of that effort has been to further enhance the already strong, independent oversight of the Board with my role as your Company's first non-executive chairman.

Your Board has taken additional actions related to corporate governance, including our recent decision on early termination of our Shareholder Rights Plan. We have implemented other policies, including holding executive sessions of independent directors following each regularly scheduled meeting of the Board, consistent with New York Stock Exchange guidelines.

We also have submitted for your vote at the 2004 Annual Meeting of Shareholders two other governance changes. The first would phase out the classified structure of the Board, meaning direc-tors would be elected annually as opposed to serving three-year terms. The other would reduce the percentage of affirmative votes from 80 percent to two-thirds of shares outstanding needed for mak-ing certain amendments to the Company's governing documents.

Your Board has been and remains fully committed to ensuring that appropriate and effective governance policies are in place to help your Company achieve continued success.

We all were saddened by the tragic loss of Chairman and CEO H. Peter Burg, who passed away in January. Pete's sound leader-ship helped guide the growth of FirstEnergy into one of the nation's largest investor-owned electric utility systems.

I also would like to extend the Board's sincere appreciation to directors Robert L. Loughhead and Robert B. Heisler, Jr., who are not standing for reelection, for their many contributions to your Company's growth and success.

Sincerely, George M. Smart Chairman of the Board Robert N. Pokelwaldt Paul J. Powers 1Iili i-Ž>;M57 Retired, formerly Managing Director of Salomon Smith Bamey (Citigroup).

Member, Audit and Finance Committees. Director of FirstEnergy Corp. since 2003.

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Chair, Nuclear Committee; Member, Corporate Governance Committee.

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FIRST ENERGY O F F I C E R S FirstEnergy Coro.

Anthony J. Alexander President and Chief Executive Officer Richard H. Marsh*

Senior Vice President and Chief Financial Officer Leila L Vespoli*

Senior Vice President and General Counsel Harvey L. Wagner Vice President, Controller and Chief Accounting Officer David W. Whitehead Corporate Secretary Thomas C. Navin*

Treasurer Paulette R. Chatman*

Assistant Controller Jeffrey R. Kalata Assistant Controller Randy Scilla*

Assistant Treasurer Edward J. Udovich Assistant Corporate Secretary Also holds the same title with FirstEnergy Service Company FirstEnergy Solutions Corp. and FirstEnergy Nuclear Operating Company.

FirstEnergy Service Company Anthony J. Alexander President and Chief Executive Officer Mark T. Clark Senior Vice President Charles E. Jones Senior Vice President Kevin J. Keough Senior Vice President Guy L. Pipitone Senior Vice President Carole B. Snyder Senior Vice President Thomas M. Welsh Senior Vice President Mary Beth Carroll Vice President Lynn M. Cavalier Vice President Kathryn W. Dindo Vice President and Chief Risk Officer Ralph J. DiNicola Vice President Michael J. Dowling Vice President Bradley S. Ewing Vice President Terrance G. Howson Vice President Ali Jamshidi Vice President and Chief Information Officer Mark A. Julian Vice President David C. Luff Vice President Stanley F. Szwed Vice President FirstEnergy Solutions Corp.

Mark T. Clark President Douglas S. Elliott Senior Vice President Alfred G. Roth Vice President Donald R. Schneider Vice President Trent A. Smith Vice President Harvey L. Wagner Vice President and Controller David W. Whitehead Corporate Secretary FirstEnergy Nuclear Operating Company Anthony J. Alexander Chief Executive Officer Gary R. Leidich President and Chief Nuclear Officer Joseph J. Hagan Senior Vice President Lew W. Myers Chief Operating Officer Mark B. Bezilla Vice President, Davis-Besse William R. Kanda Vice President. Perry L. William Pearce Vice President. Beaver Valley Frederick G. von Ahn Vice President Harvey L Wagner Vice President and Controller David W. Whitehead Corporate Secretary FirstEnergy Regional Operations Management Dennis M. Chack Regional President The Cleveland Electric Illuminating Company Paul W. Allison Regional Vice President The Cleveland Electric Illuminating Company Thomas A. Clark Regional President Ohio Edison Company Jeffrey A. Elser Regional Vice President Ohio Edison Company James M. Murray Regional President The Toledo Edison Company.

Charles H. Krueger Regional Vice President The Toledo Edison Company Stephen E. Morgan President Jersey Central Power & Light Company Donald M. Lynch Regional President Jersey Central Power & Light Company Steven E. Strah Regional President Jersey Central Power & Light Company Stephen L. Feld Regional Vice President Jersey Central Power & Light Company Ronald P. Lantzy Regional President Metropolitan Edison Company Steven A. Schumacher Regional Vice President Metropolitan Edison Company John E. Paganie Regional President Pennsylvania Electric Company Jacqueline L. Roth Regional Vice President Pennsylvania Electric Company Bradford F. Tobin Vice President and Chief Procurement Officer Harvey L. Wagner Vice President and Controller David W. Whitehead Vice President, Corporate Secretary and Chief Ethics Officer 8

MANAGEMENT REPORT REPORT OF INDEPENDENT AUDITORS

• The consolidated financial statements.

To the Stockholders and Board Xof Directors of FirstEnergy Corp.:`

were prepared by the management of

" 't i?

In our opinion, the accom'panying consolidated balance sheets and con-FirstEnergy Corp., who takes responsibility for

'solidated statements of capitalization and the related consolidated statements their integrity and objectivity. The statements

'of income,'common stockholders' equity, preferred stock, cash flows and -

were prepared in conformity with accounting taxes present fairly, in all material respects, the financial position of principles generally accepted in the United i

FirstEnergy Corp. and subsidiaries as of December 31, 2003 and 2002 and

'States and are consistent with other financial

the results of their operations and their cash flows for the years then ended information appearing elsewhere in this report..

in conformity with accounting principles generally accepted in the United l PricewaterhouseCoopers'LLP, independent :

States of America. These financial statements are the responsibility of the -

auditors, have expressed an unqualified opinion Company's management; our responsibility is to express an opinion on these on the Company's 2003 consolidated financial 'financial statements based on our audits. We conducted our audits of these statements.

statements in accordance with auditing standards generally accepted in the

-- The Company's internal auditors, who are United States of America, which require that we plan and perform the audit i-:

responsible to the Audit Committee of the to obtain reasonable assurance about whether the financial statements are Board of Directors, review the results and 'per-. free of material misstatement; An audit includes examining, on a test basis, formance of operating units within the evidence supporting the amounts and disclosures in the financial statements, Company for adequacy, effectiveness and relia-assessing the accounting principles used and significant estimates madeby bility of accounting and reporting systems, as A ok management, and evaluating the overall financial statement presentation

'well as managerial and operating controls. :

We'believe that our audits provide a reasonable basis for our opinion. The The Audit Committee consists of six inde-. consolidated financial statements of FirstEnergy Corp. and subsidiaries for pendent directors whose duties include:

the'year -ended December 31, 2001, prior to the revisions described in consideration of the adequacy of the internal Notes 2(F),2(L) and 8, were audited byother independent auditors who have I

controls of the Company'and the 'objectivity of ceased operations. Those independent auditors expressed an unqualified financial reporting; inquiry into the number opinion on those financial statements in their report dated March 18, 2002.*

lextent, adequacy and validity of regular and As discussed in Note 2(L) to the consolidated financial statements,-..

special audits conducted by independent audi-the Company changed its method of accounting for goodwill as of January.-

tors and the internal auditors; and reporting to 1-2002. As discussed in Note 2(F) to the consolidated financial statements,-

the Board of Directors the Committee's find-the Company.changed its method of accounting for asset retirement obliga-ings and any recommendation for changes in tions as of January 1, 2003. As discussed in Note 9 to the consolidated

'scope, methods or procedures of the auditing financial statements,'the.Company changed its method of accounting for

functions. The Commnitteelis directly responsi-the consolidation of variable interest entities as of December.31,;2003.-'

ble for appointing the Company's independent

-As discussed above, the consolidated financial siatements of auditors (subject to shareholder approval) and - FirstEnergy Corp. and subsidiaries for the year ended December 31,'

i is charged with reviewing and approving all 2001 :were audited by otherindependent auditors who have ceased oper-.

services performed for the Company by the

'ations'As described in Note 2(L) to the consolidated financial statements,'

independent auditors and for reviewing and the financial statements have been revised to include the transitional dis-approving the related fees.'The Committee closures required by Statement of Financial Accounting Standards No:

reviews the independent auditors' internal 1 42, Goodwill and Other intangible Assets, which was adopted by the quality control procedures and reviews all rela-.Company as of January 1, 2002. As described in Note 2(F) to the consoli-.'

tionships between the independent auditors :'

dated financial statements, the financial statements have been revised and the Company, in order to assess the'audi-.

to include the transitional disclosures required by Statement of Financial tors' independence.:The Committee also Accounting Standards'No: 143,;-Accounting for Asset Retirement

-reviews management's programs tomonitor -'- <Obligatiois, which was adopted by' th6 Company as of January 1, 2003.

compliance with the Company's policies on

".' As described in Note 8 to the consolidated financial statements, the

--business ethics and risk management. The Company changed the composition of its reportable segments in 2002.

l; Committee e

stablishes procedures to receive We audited -the transand 2(L) and respond to complaints received by the'.;-

and the adjustments that were applied to restate the 2001 reportable

-Company regarding accounting, internal segments disclosures discussed in Note 8. In our opinion, such adjust-accounting controls, or auditing matters and 'ments to the 'reportable segments disclosures are appropiate and have:

allows for the confidential, anonymous submis-been proery ppied adterniinldscoursfr20ae sion of concerns by employees. The Audit appropriate. However, we were not engaged to audit, review, or apply.,

Comrnittee held ten meetings in 2003 any procedures to the 2001 consolidated financial statements of the Company other~than with respect to such transitional disclosures'and adjustmenits to the reportable segments disclosures and, accordingly,'

we do not express an opinion 'or any other form of assurance on the Richard H. Marsh 2001 consolidated financial statements taken as a whole.

Senior Vice President and Chief Financial Officer I-

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'-' tPricewaterhouseCoopers LLP Harvey L Wagner CIeveland Ohio VicePresidentControllerandChiefAccounting Officer February 25 2004 FirstEnergy Corp. 2003 9

The following report is a copy of a report previously issued by Arthur Andersen LLP (Andersen). This report has not been reissued by Andersen and Andersen did not consent to the incorporation by reference of this report into any of the Company's registration statements.

As discussed in Note 2(L to the consolidated financial statements, the Company has revised its consolidated financial statements for the year ended December 31, 2001 to include the transitional disclosures required by Statement of Financial Accounting Standards No. 14Z "Goodwill and Other Intangible Assets. " As discussed in Note 2(F) to the consolidated financial statements, the Company has revised its consolidated financial statements for the year ended December 31, 2001 to include the transitional disclosures required by Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations. " Additionally, as discussed in Note 8 to the consolidated financial statements, the Company has revised its consolidated financial statements for the year ended December 31, 2001 to reflect changes in the composition of its reportable segments adopted in 2002. The Andersen report does not extend to these changes. The revisions to the 2001 financial statements related to these transitional disclosures and the revisions that were applied to restate the 2001 reportable segments disclosures were reported on by PricewaterhouseCoopers LLfP as stated in their report appearing herein.

REPORT OF PREVIOUS INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of FirstEnergy Corp.:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of FirstEnergy Corp. (an Ohio corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, common stockholders' equity.

preferred stock, cash flows and taxes for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant esti-mates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of FirstEnergy Corp. and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in con-formity with accounting principles generally accepted in the United States.

As explained in Note 1 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities by adopting Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended.

aAA4-La LLP Arthur Andersen LLP Cleveland, Ohio, March 18, 2002 10 FirstEnergy Corp. 2003

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

For the Years Ended December 31, 2002*

2001 2000 1999 Revenues i

12,307,407

$12,047,348

$7,999,362

$ 7,028,961

$ 6,319,647 Income Before Discontinued Operations and Cumulative Effect of Accounting Changes 421,996

$ 632,667 654,946 598,970 568,299 Net Income 422,764.

552,804

$ 646,447 598,970 568,299 Basic Earnings per Share of Common Stock:

Before Discontinued Operations and Cumulative Effect of Accounting Changes

- 1.39 2.16 2.85 2.69 2.50 After Discontinued Operations and Cumulative Effect of Accounting Changes

$ =.-711.39 1.89 2.82 2.69 2.50 Diluted Earnings per Share of Common Stock:

- g Before Discontinued Operations and i

Cumulative Effect of Accounting Changes i

-$1.39; 2.15 2.84 2.69 2.50 After Discontinued Operations and A

Cumulative Effect of Accounting Changes So 1.39 1.88 2.81 2.69 2.50 Dividends Declared perShare of Common Stock I S.:50 1.50 1.50 1.50 1.50 Total Assets

$32,909,948

$34,386,353

$37,351,513

$17,941,294

$18,224,047 Capitalization as of December 31:

Common Stockholders' Equity

. $ 8,289,341

$ 7,050,661

$ 7,398,599

$ 4,653,126

$ 4,563,890 Preferred Stock:

Not Subject to Mandatory Redemption 335,123 335,123 480,194 648,395 648,395 Subject to Mandatory Redemption 428,388 594,856 161,105 256,246 Long-Term Debt 9,789,066 10,872.216 12,865,352 5,742,048 6,001,264 Total Capitalization

$18,413,530

$18,686,388

$21,339,001

$11,204,674

$11,469,795 See Note 2(1) regarding reclassification of discontinued operations.

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.

.0 3

20012 First Quarter High-Low

$35.19

$27.04

$39.12

$30.30 Second Quarter High-Low 38.90 30.57 -

35.12 31.61 Third Quarter High-Low 38.75 25.82 34.78 24.85 Fourth Quarter High-Low 35.95 31.66 33.85 25.60 Yearly High-Low 38.90 25.82 -

39.12 24.85 Prices are based on reports published in The Wall Street Journal for New York Stock Exchange Composite Transactions.

I HOLDERS OF COMMON STOCK There were 153,020 and 152,288 holders of 329,836,276 shares of FirstEnergy's Common Stock as of December 31, 2003 and January 31, 2004, respectively. Information regarding retained earnings available for payment of cash dividends is given in Note 5(A).

FirstEnergy Corp. 2003 11

MANAGENIENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms "anticioate, " "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), adverse regulatory or legal decisions and the outcome of governmental investigations, availability and cost of capital, the continuing availability and operation of generating units, inability of the Davis-Besse Nuclear Power Station to restart (including because of an inability to obtain a favorable final determination from the Nuclear Regulatory Commission) in early 2004, the inability to accomplish or realize anticipated benefits from strategic goals, the ability to improve electric commodity margins and to experience growth in the distribution business, the ability to access the public securities market, 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, a denial of or material change to the Company's Application related to its Rate Stabilization Plan, and other similar factors.

FirstEnergy's Business FirstEnergy Corp. is a registered public utility holding company headquartered in Akron, Ohio that provides regu-lated and competitive energy services (see Results of Operations - Business Segments). Our vision is to become the leading retail energy and related services provider in the northeast and mid-Atlantic region of the United States.

Our eight electric utility operating companies (EUOC) com-prise the nation's fifth largest investor-owned electric system, serving 4.4 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey.

Transmission and Distribution Services Area Served Customers Served Ohio Edison Company IOEi Central and northeastern Ohio 1,019,280 Pennsylvania Power Company IPenn)

Western Pennsylvania 155,929 The Cleveland Electric Illuminating Company (CEII Northeastern Ohio 752,537 The Toledo Edison Company (TE)

Northwestern Ohio 307.893 Jersey Central Power &

Northern, western and Light Company (JCP&L) east central New Jersey 1,049,547 Metropolitan Edison Company (Met-Edi Eastern Pennsylvania 516,536 Pennsylvania Electric Company (Penelecl Western Pennsylvania 585,089 American Transmission Systems. Incorporated IATSI)

Service areas of OE, Penn, CEI and TE gate, the majority of FirstEnergy's revenues and earnings.

Beginning in 2001, Ohio utilities that offered both compet-itive and regulated retail electric services were required to implement a corporate separation plan approved by the Public Utilities Commission of Ohio (PUCO) - one which provided a clear separation between regulated and competitive opera-tions. FES provides competitive retail energy services while the EUOC provide regulated transmission and distribution serv-ices. FirstEnergy Generation Corp. (FGCO), a wholly owned subsidiary of FES, leases fossil and hydroelectric plants from the EUOC and operates those plants. Under the terms of the current corporate separation plan, the transfer of ownership of EUOC non-nuclear generating assets to FGCO would be sub-stantially completed by the end of the Ohio market development period. All of the EUOC power supply require-ments for the Ohio Companies (OE, CEI, and TE) and Penn are provided by FES to satisfy their provider of last resort (PLR) obligations, as well as their grandfathered wholesale contracts.

FirstEnergy acquired international assets in the merger with GPU, Inc. in November 2001. GPU Capital, Inc. and its subsidiaries had provided electric distribution services in for-eign countries (see Results of Operations - Discontinued Operations). GPU Power, Inc. and its subsidiaries owned and operated generation facilities in foreign countries. As of January 30, 2004, all of the international operations had been divested (see Note 3) because those assets were not consistent with the role we envision for FirstEnergy in the energy industry.

Orderly Transition of Leadership On January 13, 2004, FirstEnergy Chairman and Chief Executive Officer H. Peter Burg, passed away. Mr. Burg had taken a leave of absence beginning December 22, 2003, to undergo treatment for leukemia. At that time, the Board of Directors of FirstEnergy named President and Chief Operating Officer Anthony J. Alexander acting Chief Executive Officer.

On January 20, 2004, the Board of Directors elected Mr.

Alexander President and Chief Executive Officer, and also elected George M. Smart as Chairman. Mr. Smart was elect-ed to Ohio Edison Company's Board of Directors in 1988 and to FirstEnergy's Board of Directors in 1997. Mr. Smart will not hold an executive position with FirstEnergy.

Competitive services are principally provided by FirstEnergy Solutions Corp. (FES), FirstEnergy Facilities Services Group, LLC (FSG), MARBEL Energy Corporation, MYR Group, Inc., and our majority owned First Communications, LLC. Through its 50% interest in Great Lakes Energy Partners, LLC, MARBEL is involved in the exploration and production of oil and natural gas, and transmission and marketing of natural gas. Other subsidiaries provide a wide range of services, including heating, ventilating, air-condition-ing, refrigeration, process piping, plumbing, electrical and facility control systems and high-efficiency electrotechnologies.

Telecommunication services are also provided - local and long-distance phone service is provided to more than 65,000 customers. While competitive revenues have increased since 2001, regulated energy services continue to provide, in aggre-t2 Firs,Energy Co'o 2003

Strategy and Risks We continue to pursue our goal of being the leading regional supplier of energy and related services in the northeast and mid-Atlantic region, where we see the best opportunities for growth. Our fundamental business strate-gy remains stable and unchanged. While we continue to build toward a strong regional presence, key elements for our strategy are in place and management's focus contin-ues to be on execution. We intend to continue providing competitively priced, high-quality products and value-added services - energy sales and services, energy delivery, power supply and supplemental services related to our core business. As our industry changes to a more competi-tive environment, we have taken and expect to take actions designed to create a larger, stronger regional enter-prise that will be positioned to compete in the changing energy marketplace.

Our current focus includes: (1) minimizing unplanned extended generation outages; (2) improving our system relia-bility; (3) optimizing our generation portfolio; (4) effectively managing commodity supplies and risks; (5) reducing our cost structure; (6) enhancing our credit profile and financial flexibili-ty; (7) managing the skills and diversity of our workforce; and (8) satisfactory resolution of the pending Ohio rate plan.

Risks We face a number of industry and enterprise risks and challenges, among which include:

• Weather and other weather-related phenomena (short-term and long-term)

• General economic conditions and the resulting impact on our service-area economies

• Conditions in capital markets affecting availability of funds and interest rates

• Environmental laws and regulations

• Fluctuations in commodity prices

• Actions taken by regulatory agencies

• Changing competitive landscape

• Potential acts of terrorism Supply Plan Our affiliates are obligated to provide generation service with an estimated power supply of 100,000 gigawatt-hours for 2004. These obligations arise from customers who have elected to continue to receive generation service from our EUOCs under regulated retail rate tariffs and from customers who have selected FES as their alternate generation provider.

Geographically, approximately 64% of the total generation service obligation is for customers located in the Midwest Independent System Operator (ISO) market area and 36%

for customers located in the PJM Interconnection, LLC ISO market area. Included in the PJM ISO market area are obligations of FES to provide power to electric distribution companies in the state of New Jersey, including JCP&L.

FES incurred this obligation as a successful bidder in the State of New Jersey's auction of basic generation service (BGS).

Within the franchise territories of the EUOC, alterna-tive energy suppliers currently provide generation service for approximately 1,400 megawatts (MW) (summer peak) of load with an estimated energy requirement of 6,700 gigawatt-hours. If these alternate suppliers fail to deliver power to their customers located in the EUOC's service areas, the EUOC must procure replacement power in the role of PLR (See Note 2(D) for discussion of the auction of JCP&L's PLR obligation). The EUOC costs for any replace-ment power would be recovered under the applicable state regulatory rules.

To meet these generation service obligations, our affiliates own and operate 13,387 MW of installed generating capacity which for 2004 is expected to provide approxi-mately 75% of the power supply required. The balance of

,the power supply expected to be required in 2004 has been secured through a mix of long-term purchases (term of contract greater than one year) and short-term purchas-es (term of contract less than one year). Changes in power supply requirements will be met through spot market transactions.

Davis-Besse Restoration On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FirstEnergy Nuclear Operating Company (FENOC) in the reactor vessel head near the nozzle penetra-tion hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process is to establish criteria for NRC oversight of the licensee's per-formance and to provide a record of the major regulatory and licensee actions taken, and technical issues resolved, leading to the NRC's approval of restart of the plant.

Restart activities include both hardware and manage-ment issues. In addition to refurbishment and installation work at the plant, we made significant management and human performance changes with the intent of re-establish-ing the proper safety culture throughout the workforce.

Work was completed on the reactor head during 2002 and efforts continued in 2003 to focus on design enhancements to the unit's reliability and performance. We also accelerated maintenance work that had been planned for future refueling and maintenance outages. We installed a state-of-the-art leak-detection system around the reactor, as well as modi-fied high-pressure injection pumps. Testing of the bottom of the reactor for leaks was completed in October 2003 and no indication of leakage was discovered. The focus of activities now involves management and human performance issues.

As a result, incremental maintenance and capital expendi-tures declined in 2003 as emphasis shifted to performance issues; replacement power costs were higher in 2003. We anticipate that Davis-Besse will be ready for restart in the first quarter of 2004. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. Delays in Davis-Besse's return to service contributed to Standard & Poor's (S&P's) reduction in our credit rating in the fourth quarter of 2003 (see Cash Flows from Financing Activities below).

Incremental costs associated with the extended FirstEnergy Corp. 2003 13

Davis-Besse outage for 2003 and 2002 were as follows:

Costs of Davis-Busse Extended Outage 2003 Increase 2002 (Decrease)

(In millionsJ Incremental Expense Replacementpower

$196

$120

$76 Maintenance 93 115 (22)

Total

$289

$235

$ 54 Incremental Net of Tax Expense

$170

$138 S 32 Capital Expenditures

$21 S63 S(42)

We anticipate spending 510 million in 2004 for remain-ing non-capital restart activities, expected NRC inspection activities after Davis-Besse's return to service and other related activities. No additional capital expenditures related to the restoration are expected. Replacement power costs are expected to be approximately $15-20 million per month during the remaining period of the outage. We have hedged the on-peak replacement energy supply for Davis-Besse for the expected length of the outage. If there are significant delays in the NRC approval process, replace-ment power costs will continue to be incurred, adversely affecting FirstEnergy's cash flows and results of operations.

Power Outage On August 14, 2003, various states in the northeast United States and southern Canada experienced a wide-spread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area.

FirstEnergy continues to accumulate data and evaluate the status of its electrical system prior to and during the outage event, and continues to cooperate with the U.S.-Canada Power System Outage Task Force (Task Force) investigating the August 14th outage. The interim report issued by the Task Force on November 18, 2003 concluded that the prob-lems leading up to the outage began in FirstEnergy's service area. Specifically, the interim report concludes, among other things, that the initiation of the August 14th outage resulted from the coincidence on that afternoon of the following events: (1) inadequate situational awareness at FirstEnergy; (2) FirstEnergy's failure to adequately manage tree growth in its transmission rights of way; and (3) failure of the intercon-nected grid's reliability organizations (Midwest ISO and PJM Interconnection) to provide effective diagnostic support. We believe that the interim report does not provide a complete and comprehensive picture of the conditions that con-tributed to the August 14th outage and that it does not adequately address the underlying causes of the outage. We remain convinced that the outage cannot be explained by events on any one utility's system. On November 25, 2003, the PUCO ordered FirstEnergy to file a plan with the PUCO no later than March 1, 2004, illustrating how FirstEnergy will correct problems identified by the Task Force as events con-tributing to the August 14th outage and addressing how FirstEnergy proposes to upgrade its control room computer hardware and software and improve the training of control room operators to ensure that similar problems do not occur in the future. The PUCO, in consultation with the North American Electric Reliability Council, will review the plan before determining the next steps in the proceeding. On December 24, 2003, the Federal Energy Regulatory Commission (FERC) ordered FirstEnergy to pay for an inde-pendent study of part of Ohio's power grid. The study has commenced and will examine the stability of the grid in criti-cal points in the Cleveland and Akron areas; the status of projected power reserves during summer 2004 through 2008; and the need for new transmission lines or other grid projects. The FERC ordered the study to be completed with-in 120 days. At this time, we do not know how the results of the study will impact FirstEnergy.

Restatements and Reclassifications We filed an amended Form 10-K during 2003 to restate our consolidated financial statements for the year ended December 31, 2002 to reflect a change in the method of amortizing costs being recovered under the Ohio transition plan and to recognize above-market liabilities of certain leased generation facilities. In addition, the restated Consolidated Statement of Income for the year ended December 31, 2002 reflects reclassifying the results of divested businesses as discontinued operations (see Note 2(l)). Financial comparisons described below reflect the effect of these restatements and reclassifications of 2002 financial results. The 2001 results of the divested entities were not significant and the 2001 Consolidated Statement of Income was not reclassified to separately report discon-tinued operations.

Merger With GPU On November 7, 2001, the merger of FirstEnergy and GPU became effective with FirstEnergy as the surviving com-pany. The merger was accounted for using purchase accounting under the guidelines of Statement of Financial Accounting Standards No. (SFAS) 141, "Business Combinations." Under purchase accounting, the results of operations for the combined entity are reported from the point of consummation forward. As a result, our financial statements for 2001 reflect twelve months of operations for our pre-merg-er organization and seven weeks of operations (November 7, 2001 to December 31, 2001) for the former GPU companies.

In 2003 and 2002, our financial statements include twelve months of operations for both our pre-merger organization and the former GPU companies. Additional goodwill resulting from the merger ($3.8 billion) as of December 31, 2003, is not being amortized, reflecting the application of SFAS 142, "Goodwill and Other Intangible Assets." Goodwill is subject to review, at least annually, for potential impairment (see Critical Accounting Policies - Goodwill). As a result of the merger, we issued nearly 73.7 million shares of our common stock, which are reflected in the calculation of earnings per share of common stock in 2003 and 2002 and for the seven-week period outstanding in 2001.

Results of Operations Net Income and Earnings Per Share Net income decreased to $423 million in 2003, com-pared to $553 million in 2002 and $646 million in 2001. Net income in 2003 and 2002 included after-tax charges for dis-14 Firs:Ffnrgy Coqv 2703

continued operations of $101 million and $80 million, respectively, or $0.33 and $0.27 per share (basic and dilut-ed), primarily reflecting losses on the sale or abandonment of remaining international operations acquired through the merger with GPU (see Discontinued Operations below).

Results for 2003 also include an after-tax credit of $102 million from the cumulative effect of an accounting change (basic and diluted earnings per share of $0.33). The 2003 credit resulted from the January 2003 adoption of SFAS 143, "Accounting for Asset Retirement Obligations." Net income in 2001 also included the cumulative effect of an accounting change resulting in a net after-tax charge of $9 million (see Cumulative Effect of Accounting Change below).

Major factors reducing net income in 2003, compared to 2002, included the adverse impact from the JCP&L rate case decision to disallow costs of $109 million ($0.36 per share of common stock), a non-cash goodwill impairment charge of $81 million ($0.27 per share of common stock),

asset impairments of $47 million ($0.15 per share of common stock) and increased costs associated with the Davis-Besse extended outage of $32 million ($0.09 per share of common stock). Of the $81 million goodwill impairment charge, $3 million is included in the net of tax loss from discontinued operations. Partially offsetting these charges was a gain of $99 million or $0.33 per share of common stock representing net proceeds from the settlement of our claim against NRG Energy, Inc. relating to the terminated sale of four fossil power plants.

On September 17, 2003, we completed the issuance and sale of 32.2 million shares of common stock (see Cash Flows from Financing Activities below) which were includ-ed in the calculation of earnings per share on a weighted average basis in 2003. The additional shares reduced earn-ings per share of common stock by $0.04 (basic and diluted). If the shares had been outstanding for the entire year, basic and diluted earnings would have been reduced by $0.13 per share of common stock.

accounting changes are summarized in the following table:

! Uriusua IItems (pre-tax):

2D33

=2002 2001)(1

I:.

(lnmillions).

f Investment impaiments

$56 Si 01 '

Regulatoryassetsdisallowance'-JCP&L m185 a-A: Lake plants transaction net settlement proceeds 168-depreciation & sales costs 29 Goodwill impairment 117 Environmental liability, 15 r Long-term derivative contract adjustment 18 '

Generation project cancellation 17 Severance costs -

11

' Uncollectible reserve and contract losses 9

Early retirement costs- -

Estimated claim settlement 17 Decrease in Pre-tax Eamings,

$205 -

$193 -

$18 Reduction to earnings per share of common stock:

Basic-.

$0.47

$0.40

$0.05 Diluted 0.>,

$0.47

$0.40 -

$0.05 Results of Operations - 2003 Compared With 2002 Sources of changes in total revenues are summarized in the following table:

-.. : Increase Sources of Revenue Changes 2003 1..

,2002 (Decrease'

- :- :-(-

.-: In millions).

RetailElectric Sales-

.>'Regulated services

$7_926

" i$8,229

$1303)1

'Competitive services 566 348 218 Wholesale Electric Sales: '.

Regulated services 593 i

550 43 Competitive services 1,182 570-612

-Electric Sales 10267 9,697 :

. 570 Gas Sales 6'

624

- 513 v

711-Other Revenues:

' Regulated-principallytransmissionservices 459 ;

386.

73-

-t Competitive products and services 886 964 -

1781 International 25 i

294i (2691 i Other.:

46 ;- i 93 1471 7 Total Revenues,

$12,307 -

$12,047

$260 IF FirstEnergy' 2003 2002 2001

, millions)

Total revenues

$12307

$12047

$7999

.Income before interest and income taxes 1 640 i

2 115 1,685 i Income before discontinued operations 5

and cumulative effect of accounting changes 422 633 655 Discontinued operations 1101)

(801 Cumulative effect of accounting'changeis 102 -

(9)

Net Income

$ 423

$ 553

$ 646-Changes in electric generation sales and distribution deliveries in 2003 are summarized in the following table:

I Changesin KWH Sales Increase (Decrease)

FElectric Generation Sales:

t Retal

'i7-a >i ; -.,S j'.

i, Regulatedservices (7.21%

ic

.Competitive services, 53.0%

Wholesale 402%

' Total Electric Generation Sales 8.3%:

Basic Earnings Per Share:.-

i Income before discontinued operations and cumulative effect of accounting changes $ 1.39

$. 2.16

$2.85 Discontinued operations

'0.33)

. 10.271 Cumulative effect of accounting changes :.

0.33.'.

(.031.i Net Income '

$,1.39.

$ 1.89

$ 2.82 f Diluted Eamings Per Share:

-. Income before discontinued operations and e cumulativeeffectofaccountingchanges' $ 1.39

$ '2.15

$ 2.84 Discontinuedoperations 0.33)

(0.27) -'

Cumulative effect of accounting changes 0.33 0.03-NetIncome L.

$.1.39

$ p1.88

$ 2.81, -

EUOC Distribution Deliveries:'

(0 7-Residential 7

a%

i -

X - Commercial and industrial 0.3%

Total Distribution Deliveries

=

Retail electric sales from our regulated services segment declined principally due to increased sales by alternative suppliers in our franchise areas. Alternative suppliers provided 21.8% of the total energy delivered to retail customers in 2003, compared to 15.7% in 2002. As a result, generation kilowatt-hour sales to retail customers of our regulated services were 7.2% lower, which reduced retail electric sales revenues by $250 million. Additional credits provided to customers under the Ohio transition plan to promote customer shopping for alternative suppliers further reduced regulated retail electric sales revenues by Unusual Items Unusual charges (credits) included in income before discontinued operations and the cumulative effect of FirstEnergy Corp. 2003 15

$45 million. The latter decreases in revenues, are deferred for future recovery under our Ohio transition plan and do not materially affect current period earnings.

Revenues from distribution deliveries decreased $8 million with kilowatt-hour deliveries to franchise customers unchanged in 2003. The slight decrease in revenues result-ed from additional distribution deliveries to the commercial sector due to the strengthening in the service area econo-my toward the end of 2003 which nearly offset a slight decline in distribution deliveries to residential and industrial customers. Regulated retail revenues were reduced by the New Jersey Board of Public Utilities (NJBPU) decision in July 2003 (see State Regulatory Matters - New Jersey) that lowered JCP&L's base electric rates effective August 1, 2003, on an annualized basis, by approximately $62 million.

Retail sales by our competitive services segment increased by $218 million as a result of a 53% increase in kilowatt-hour sales. That increase primarily resulted from retail customers within our Ohio franchise areas switching to FES under Ohio's electricity choice program and from growth in competitive retail sales outside our franchise areas.

Revenues from the wholesale market increased signif-icantly by $655 million and kilowatt-hour sales rose by 40%. A majority of the increase was due to sales by our competitive services segment for a portion of New Jersey's BGS requirements and sales in the spot market.

Higher electric sales revenues were more than offset by increased fuel and purchased power costs. Purchased power costs increased by $889 million due to higher unit costs and additional quantities purchased. Increased vol-umes were required to supply obligations assumed by FES for BGS sales in New Jersey, as well as other wholesale commitments, and additional supplies were required to replace reduced nuclear generation (down 14%). Reduced nuclear generation output resulted from additional refueling outage work performed at the Perry and Beaver Valley plants in 2003. Reported purchased power costs in 2003 also included $153 million of power costs that were disal-lowed in the JCP&L rate case decision (see State Regulatory Matters - New Jersey). Electric sales revenues net of fuel and purchased power reduced income before interest and taxes by $328 million.

Other factors contributing to reduced income before inter-est and taxes in 2003 include:

Asset impairment charges of $56 million incurred in 2003 including a $26 million non-cash charge related to the divestiture of our interest in Termobarranquilla S.A., Empresa de Servicios Publicos (TEBSA),

a Colombian electric generation operation; a $13 million impairment on the monetization of the note received from the sale of our 79.9% interest in Avon Energy Partners Holding's (see Note 3); an additional

$5 million impairment upon the divestiture of our remaining interest in Avon; and $12 million related to the disposition of Northeast Ohio Natural Gas (see Note 2(l)) and the write down of our investment in Pantellos. an internet business-to-business marketplace serving the utility sector.

16 FirstEnerg y Corp. 2003

• A non-cash goodwill impairment charge of $117 million recorded in the third quarter of 2003 reducing the carrying value of FSG. This charge reflects the continued slow down in the development of competitive retail markets and depressed economic conditions that affect the value of FSG.

• Increased energy delivery costs of $86 million principally due to storm restoration expenses and an accelerated reliability program within JCP&Ls service territory.

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

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

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

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

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

Partially offsetting these higher costs were three factors:

• A settlement of our claim against NRG for the terminated sale of four fossil plants resulted in a

$168 million gain.

• Charges for depreciation and amortization decreased by $17 million due to: higher shopping incentive deferrals under the Ohio transition plan ($45 million);

lower charges resulting from the implementation of SFAS 143 i$61 million); revised service life assump-tions for nuclear generating plants ($28 million) and reduced depreciation rates resulting from the JCP&L rate case ($18 million). Partially offsetting these decreases were higher charges resulting from increased amortization of the Ohio transition regula-tory assets ($70 million), termination of tax related deferrals in 2003 ($36 million), and costs disallowed in the JCP&L rate case decision ($33 million).

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

Income before discontinued operations and the cumulative effect of accounting changes decreased $211 million from the prior period. The change also reflects reduced net interest charges ($146 million) and income taxes ($118 million), in addition to the changes discussed

above. The decrease in interest expenses reflects debt and preferred stock redemptions and financing activities and the sale of our 79.9% interest in Avon in 2002. Redemption and refinancing activities for debt and preferred stock aggre-gated approximately $2.582 billion during 2003. Proceeds from the issuance of 32.2 million shares of common stock in September 2003 accelerated the repayment of debt. The redemption and refinancing activities and pollution control note repricings are expected to result in annualized savings of $125 million. We also exchanged existing fixed-rate pay-ments on outstanding debt (notional amount of $1.15 billion at year end 2003) for short-term variable rate payments through interest rate swap transactions (see Market Risk Information - Interest Rate Swap Agreements below). Net interest charges were reduced by $27 million in 2003 as a result of these swaps. Counter parties called $594 million of our swaps during 2003 yielding total payments to FirstEnergy of $20 million. Interest expense in 2003 was reduced $4 mi-lion due to cancellation of the swaps related primarily to our unregulated generation capacity.

Discontinued Operations In 2003 and 2002, discontinued operations were reflected for GPU Empresa Distribuidora Electrica Regional S.A. and affiliates (Emdersa) and Empresa Guaracachi S.A.

(EGSA), as we substantially completed our exit from foreign operations acquired through the merger with GPU in 2001.

In addition, the results for the FSG subsidiaries, Colonial Mechanical, Webb Technologies and Ancoma, Inc. and the MARBEL subsidiary, Northeast Ohio Natural Gas Corp., which were divested in 2003, have been reported as discontinued operations for the years 2003 and 2002.

The following table summarizes the sources of losses from discontinued operations:

Discontinued Operations (Net of Tax) 2003

-2002

-in millions)

Emdersa-Abandonment,

$167)

EGSA Loss on sale 133)

Ancoma - Loss on sale (3)

Totallosses

.1103)

Reclassification of operating income (loss) to discontinued operations 2

i(80 Total

$1101)

$(80).

Cumulative Effect of Accounting Change Results in 2003 include an after-tax credit to net income of $102 million recorded upon the adoption of SFAS 143 in January 2003 (see discussion below).

FirstEnergy identified applicable legal obligations as defined under the new standard for nuclear power plant decom-missioning, reclamation of a sludge disposal pond at the Bruce Mansfield Plant and two coal ash disposal sites. As a result of adopting SFAS 143 in January 2003, asset retire-ment costs of $602 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $415 million. The asset retire-ment obligation (ARO) liability at the date of adoption was

$1.107 billion, including accumulated accretion for the peri-od from the date the liability was incurred to the date of adoption. As of December 31, 2002, FirstEnergy had recorded decommissioning liabilities of $1.244 billion.

FirstEnergy expects substantially all of its nuclear decom-missioning costs for Met-Ed, Penelec, JCP&L and Penn to be recoverable in raies over time. Therefore, FirstEnergy recognized a regulatory liability of $185 million upon adop-tion of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning for those companies. The remaining cumulative effect adjust-ment for unrecognized depreciation and accretion offset by the reduction in the existing decommissioning liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was a $175 million increase to income, or $102 million net of income taxes.

Earnings Effect of SFAS 143 The application of SFAS 143 (excluding the cumulative adjustment described above) resulted in the following changes to expense categories and net income in 2003:

Effect of SFAS 143

. i ncrease (Decrease)

-- X :

L - m ; kVn millions).,>

-Other operating expense:

Cost of removal expenditures Ipreviously included in depreciation)

$10 Depreciation:

Elimination of decomnmissioning expense (89) r -Depreciation of asset retirement cost 2

Accretion of asset retirement liability 42

'Elimination of removal cost component -

-116)

Net decrease to depreciation -'

(61)

- Incometaxes 21

-Netincomeeffect

$30 Results of Operations - 2002 Compared With 2001 Net income in 2002 included an after-tax loss of $80 million for discontinued operations. The loss primarily resulted from our divesting ownership of Emdersa through the abandonment of our shares in the parent company of the Argentina operation. We reclassified the results of Emdersa for the year ended December 31, 2002, recording its after-tax loss as discontinued operations. In the fourth quarter of 2002 we recognized a $50 million impairment charge on our remaining 20.1 % interest in Avon. Originally acquired as part of the merger with GPU, we previously sold a 79.9% equity interest in Avon to Aquila in May 2002.

As a result of our merger with GPU, results for 2002 include twelve months of operations for the former GPU companies compared to only seven weeks in 2001. The following table and related discussion excludes results for the former GPU companies in the 2002 and 2001 periods in order to provide a meaningful comparison.

Increase FirstEnergy (Pre-Merger) 2002 2001 (Decrease)

(In millions)

[.Total revenues i

j $7,235

$7,366.

$S1131)

V-Income before interest and income taxes j

1,171 1.561 13901 Income before discontinued operations and cumulative effect of accounting change 391 9 624

. 12331 Discontinued operations 2

2 Cumulative effect of accounting change (9) i 9

Net Income

$ 393, $ 615

$(222)

Sources of changes in pre-merger revenues are summarized in the following table:

FirstEnergy Corp. 2003 17

Increase Sources of Revenue Changes 2002 2001 (Decrease)

{In millions)

Retail Electric Sales:

Regulated services

$4,282

$4,610 S3281 Competitive services 348 212 136 Wholesale Electric Sales:

Regulated services 319 303 16 Competitive services:

Nonaffiliated 570 430 140 Affiliated (former GPU companies) 378 33 345 Electric Sales 5,897 5,588 309 Gas Sales 613 792 (1791 Other Revenues:

Regulated - principally transmission services 248 246 2

Competitive products and services 477 740 (2631 Total Revenues

$7,235

$7,366

$(131)j Changes in electric generation sales and distribution deliveries in 2002 for our pre-merger companies are summarized in the following table:

Increase Changes in KWH Sales (Decrease)

Electric Generation Sales:

Retail -

Regulated services (14.2)%

Competitive services 59.0%

Wholesale 122.6%

Total Electric Generation Sales 22.0%

EUOC Distribution Deliveries:

Residential 6.3%

Commercial and industrial 13.21%

Total Distribution Deliveries (0.5)1 tional affiliated company sales by FES to Met-Ed and Penelec. FES assumed the supply obligation in the third quarter of 2002 for a portion of Met-Ed's and Penelec's PLR supply requirements (see State Regulatory Matters -

Pennsylvania). The increase also included sales into the New Jersey market as an alternative supplier for a portion of New Jersey's BGS.

Reduced gas revenues resulted principally from lower prices combined with a slight decline in sales volume. The elimination of coal trading activities in the second half of 2001 also contributed to the reduction in other competitive revenues along with reduced revenues from FSG primarily reflecting the divestiture of Colonial Mechanical and Webb Technologies in early 2003.

Higher electric revenues were more than offset by increased fuel and purchased power costs. Purchased power costs increased by $332 million due to additional volumes to cover supply obligations assumed by FES. Fuel expense increased $100 million principally due to additional internal generation (5.4% higher) and an increased mix of higher cost coal and natural gas generation in 2002. The extended outage at the Davis-Besse nuclear plant pro-duced a 15% decline in nuclear generation. An increase in natural gas margins resulted from purchased gas costs (i.e.

lower unit costs) declining more than our gas sales prices.

Higher other operating expenses also reduced income before interest and income taxes. Nuclear operating costs increased $125 million primarily due to $115 million of incremental Davis-Besse costs related to its extended out-age (see Davis-Besse Restoration). An aggregate increase in administrative and general expenses and non-operating costs of $127 million resulted in large part from higher employee benefit expenses.

FSG revenues, net of related expenses, reduced income before interest and taxes by $13 million. A number of unusu-al charges further contributed to the decrease as follows:

Retail electric sales from our regulated services segment declined due in large part to increased sales by alternative suppliers in our franchise areas (23.6%

of total energy delivered in 2002 versus 11.3% in 2001).

Generation kilowatt-hour sales to retail customers were 14.2% lower in 2002 than the prior year, which reduced retail electric sales revenues by $230 million.

Revenue from distribution deliveries decreased by

$12 million or 0.4% in 2002 compared to 2001. Kilowatt-hour deliveries to franchise customers were lower due to a decline in kilowatt-hour deliveries to commercial and industrial cus-tomers as a result of sluggish economic conditions, offset in part by higher kilowatt-hour deliveries to residential customers primarily due to warmer summer weather in 2002.

The remaining decrease in regulated retail electric sales revenues resulted from additional transition plan incentives provided to customers to promote customer shopping for alternative suppliers - $86 million of additional credits. These reductions to revenues are deferred for future recovery under our Ohio transition plan and do not materially affect current period earnings.

Retail sales by our competitive services segment increased by $136 million as a result of a 59% increase in kilowatt-hour sales. That increase resulted from retail customers switching to FES, our unregulated subsidiary, under Ohio's electricity choice program. The higher kilowatt-hour sales in Ohio were partially offset by lower retail sales in markets outside of Ohio.

Revenues from the wholesale market increased $501 million in 2002 from 2001 as kilowatt-hour sales more than doubled. More than half of the increase resulted from addi-18 FirstEnergy Corp 20103 Unusual Charges-Pre-Merger Companies (pre-taxl Investment impairments Lake Plants - sales costs Long-term derivative contract adjustment Generation project cancellation Severance costs - 2002 Uncollectible reserve and contract losses Early retirement costs - 2001 Estimated claim settlement Increase 2002 2001 IDecrease)

(In millions)

$48 S-S48 17 17 18 18 17 17 11 11 9

(91 9

(91 5

5

$116

$18

$98 Charges for depreciation and amortization increased

$74 million. This increase resulted from several factors:

(1) higher amortization costs under the Ohio transition plan; (2) higher depreciation from the start-up of a new fluidized bed boiler in January 2002, owned by Bayshore Power Company, a wholly owned subsidiary; (3) new combustion turbine capacity added in late 2001; and (4) two months of 2001 depreciation ($12 million) recorded in 2002 (for the four fossil plants we chose not to sell) increased depreciation expense in 2002. However, two factors offset a portion of the above increase: shopping incentive deferrals and tax deferrals under the Ohio transition plan ($109 million) and

the cessation of goodwill amortization ($56 million) beginning January 1, 2002.

General taxes increased $28 million principally due to additional property taxes and the absence in 2002 of a benefit of $15 million resulting from the successful resolution of certain property tax issues in the prior year.

Partially offsetting these higher costs were the elimina-tion in the second half of 2001 of coal trading activities ($95 million) and the reversal of lease obligations related to the Bruce Mansfield fossil facility and Beaver Valley nuclear facility which reduced other operating expenses by $85 million.

Income before discontinued operations and cumulative effect of accounting changes decreased $233 million. The change reflects reduced net interest charges ($62 million) and income taxes ($95 million) in addition to the changes discussed above. Continued redemption and refinancing of our outstanding debt and preferred stock during 2002, maintained our downward trend in financing costs, before the effects of the merger with GPU. Excluding activities related to the former GPU companies, redemption and refi-nancing activities for debt and preferred stock aggregated approximately $1.2 billion during 2002 and is expected to result in annualized savings of $86 million. We also exchanged existing fixed-rate payments on outstanding debt (principal amount of $594 million at year end 2002) for short-term variable rate payments through interest rate swap transactions (see Market Risk Information - Interest Rate Swap Agreements below). Net interest charges for both pre-merger and post-merger companies were reduced by $17 million in 2002 as a result of these swaps. The related cash premiums will be recognized as a component of interest expense over the remaining maturity of each respective hedged security. The effective tax rate was 45.2% for 2002 compared to 42.0% in 2001. The increase in the effective tax rate was primarily attributable to new Ohio Franchise and Municipal income taxes implemented in 2002 as a result of Ohio Electric Restructuring.

Discontinued Operations The divestiture of Colonial, Webb, Ancoma and Northeast Ohio Natural Gas resulted in their revenues and expenses, with net after-tax earnings of $2 million, being reported as discontinued operations in 2002.

Cumulative Effect of Accounting Change In 2001, we adopted SFAS 133 (as amended),

"Accounting for Derivative Instruments and Hedging Activities" resulting in a $9 million after-tax charge.

Postretirement Plans Declines in equity markets in 2001 and 2002 and a reduction in our assumed discount rate in 2002 have com-bined to produce a negative trend in pension expenses.

Also, increases in health care payments and a related increase in projected trend rates have led to higher other post-employment benefits (OPEB). The following table includes the portion of postretirement costs that were expensed in 2003 and 2002:

Postretirement Expenses {Income)

- 2003 -

2002 : Increase 1"~~~~~~~~~~~~~i'1':i' ln millions) iPension

- '-.J4

$123

-$114)

$137

,;OPEB 156 102 54

• Tota

$279

$88 --

$191 The following table presents the pre-tax pension and OPEB expenses for 2002 and 2001 excluding the former GPU companies.

P st-ret ;I e t. e-e-nses (

mI

,. Postretirement Expenses (income)

'- 2002 2001 Increase,-

-~Pensi (X-.

-tIn millions)

Pension 16

$(111-:.

$27 LOPEB 99 87 12

- Total

$115

$76

$39 The pension and OPEB expense increases are includ-ed in various cost categories and have contributed to other cost increases discussed above. See "Critical Accounting Policies - Pension and Other Postretirement Benefits Accounting" for a discussion of the impact of underlying assumptions on postretirement expenses.

PJM Interconnection Transactions Our subsidiaries record purchase and sales transactions with PJM Interconnection ISO, an independent system opera-tor, on a gross basis in accordance with Emerging Issues Task Force (EITF) Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent." This gross basis classifica-tion of revenues and costs may not be comparable to other energy companies that operate in regions that have not estab-lished ISOs and do not meet EITF 99-19 criteria.

The aggregate purchase and sales transactions for the three years ended December 31, 2003, are summarized as follows:

2003

'2002 2001 -

X ~

(in millions); -

KSales

$990

$453

$142 F Purchases 1.019 687,

204 Our revenues on the Consolidated Statements of Income include wholesale electricity sales revenues from the PJM ISO for power sales (as reflected in the table above) during periods when we had additional available power for sale. Revenues also include our sales of power sourced from the PJM ISO (reflected as purchases in the table above) during periods when we required additional power to meet our retail load requirements and, secondari-ly, to sell in the wholesale market.

Results of Operations - Business Segments We manage our business as two separate major business segments - regulated services and competitive serv-ices. The regulated services segment operates and maintains our regulated domestic transmission and distribution systems and also provides generation services to franchise customers who have not chosen an alternative generation supplier. The Ohio Companies (OE, CEI and TE) and Penn obtain generation through a power supply agreement with the competitive serv-ices segment. The competitive services segment also FirstEnergy Corp. 2003 19

supplies a substantial portion of the PLR requirements for Met-Ed and Penelec through a wholesale contract. The com-petitive services segment includes all competitive energy and energy-related services including commodity sales (both elec-tricity and natural gas) in the retail and wholesale markets, marketing, generation, trading and sourcing of commodity requirements, as well as other competitive energy application services such as heating, ventilation and air-conditioning.

International operations, corporate support costs and interest costs on holding company debt are included in the aggregate "other" segment (see Note 8 for further discussion). Our two major business segments include all or a portion of the follow-ing business entities:

• Regulated operations include the regulated sale of electricity and distribution and transmission services by OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec and ATSI.

• Competitive operations include the operation of generation facilities owned by OE, CEI, TE and Penn, and all operations of FES, FSG, MYR, MARBEL and First Communications.

Financial results discussed below include revenues and expenses from transactions among our business seg-ments. A reconciliation of segment financial results to consolidated financial results is provided in Note 8 to the consolidated financial statements. Net income (loss) by business segment was as follows:

Increase Sources of Revenue Changes 2D03 2002 (Decrease)

(In millions)

Electric:

External sales S 8.519 S 8,779 S(2601 Internal sales 777 741 36 9,296 9.520 (2241 Other External sales 459 387 72 Internal sales 315 311 4

774 698 76 Total Revenues S10.070 S10.218 5(148)

Net Income (Lossl By Business Segment 2003 Regulated services Competitive services Other Total

$986 (210)

(353)

$423 2002 (In millions)

$928 (109)

(266) 5553 2001

$729 132)

(51)

External electric sales revenues declined $260 million, reflecting a $303 million decrease in retail revenues partially offset by a $43 million increase in sales to wholesale customers. The net decline in retail revenues resulted from the following factors:

• Reduced generation sales revenue of $250 million on a 7.2% reduction in kilowatt-hour sales (6.1 percentage point increase in generation provided to customers by alternative suppliers);

• Additional reductions to revenues from increased credits of $45 million provided to customers to promote shopping for alternative suppliers; and

• Lower revenues from distribution deliveries of $8 million.

The additional internal sales resulted from sales by the EUOC to FES.

Lower electric sales revenue due to reduced kilowatt-hour sales, an increase in purchased power costs and higher energy delivery and other costs, particularly employee bene-fit costs, combined to reduce income before interest and taxes by $391 million. The increase of $86 million in energy delivery costs was principally due to storm restoration expenses and an accelerated reliability plan within JCP&L's service territory. Partially offsetting these factors were:

• Settlement of our claim against NRG for the termi-nated sale of four fossil plants resulted in our recording a $168 million pre-tax credit to earnings.

• Charges for depreciation and amortization decreased

$25 million. This decrease resulted from several fac-tors: higher shopping incentive deferrals under the Ohio transition plan, lower charges resulting from the implementation of SFAS 143, revised service life assumptions for nuclear generating plants and reduced depreciation rates resulting from the JCP&L rate case. Partially offsetting these decreases were increased charges resulting from increased amortiza-tion of the Ohio transition regulatory assets, termination of tax related deferrals in 2003, and costs disallowed in the JCP&L rate case decision.

• The absence of unusual charges recognized in 2002 resulted in a further net reduction of other operating expenses ($35 million) from last year.

Excluding the results associated with the former GPU com-panies, comparable results for 2002 and 2001 are as follows:

Net Income (Loss) By Business Segment 2002 2001 (In millions)

Regulated services Competitive services Other Total S560 (114) 153) 5393

$674 (35)

(24)

Regulated Services 2003 versus 2002:

Financial results for 2003 and 2002 include an entire year of operations for the former GPU companies.

Regulated Services Total revenues Income before interest and income taxes Income before cumulative effect of accountir changes Net Income Increase 2003 2002 (Decrease)

(In millions) 510.070

$10.218 S(148) 2,034 2.214 (180) ig 885 928 (431 986 928 58 The change in operating revenues resulted from the following sources:

2002 versus 2001:

Excluding the results associated with the former GPU com-panies, comparable results for 2002 and 2001 are as follows:

20 Fas:Fnerqy CoJo 20)23

lRegulatedServices(Pre-Mergier) 2002 2D01 (Decrease; ta=n millions)

Total revenues

$5,870 :- $5,400

$(530)

S Income before interest and income taxes 1,407

- 1,713 (306)

Net Income

.- 560 674 iJ1141 Lower generation sales, additional transition plan incentives and a slight decline in revenue from distribution deliveries combined for a $312 million reduction in externa revenues in 2002 from the prior year. Shopping by Ohio i

customers for alternative energy suppliers together with the effect of a sluggish national economy on our regional business reduced retail electric sales revenues. In addition, a $188 million decline in revenues resulted from lower salE to FES, due to the extended outage of the Davis-Besse nuclear plant, which reduced generation available for sale.

A reduction in purchased power costs of $180 million reflects the impact of the lower generation kilowatt-hour sale discussed above. Excluding the net effect of lower electric revenues and purchased power, income before interest and taxes increased $44 million. The increase was caused by reduced operating costs ($114 million) offset in part by high(

depreciation ($59 million) and general taxes ($11 million). Thi increase in depreciation resulted from higher incremental tra sition costs partially offset by new deferred regulatory asset under the Ohio transition plan and the cessation of goodwill amortization beginning January 1, 2002.

Net income decreased $114 million. The change reflects decreased net interest charges ($132 million) and reduced income taxes ($60 million) in addition to the changes discussed above.

Competitive Services 2003 versus 2002:

Financial results for 2003 and 2002 include a full twelve months of operations for the former GPU companies.

The increase in external electric revenues resulted from:

• Retail sales increased by $218 million as a result of a 53% increase in kilowatt-hour sales. The increase primarily resulted from retail customers within our Ohio franchise areas switching to FES under Ohio's electricity choice program and from growth in com-petitive retail sales outside our franchise areas.

• Revenues from the wholesale market increased

$612 million and kilowatt-hour sales rose by 75%.

The increase reflects sales as an alternative supplier for a portion of New Jersey's BGS requirements.

Internal electric revenues increased from sales by FES to the EUOC to meet their energy requirements. Revenues from energy-related services declined 15% due to declines associated with weak economic conditions.

Electric revenue, net of purchased power costs and the absence of $69 million of unusual charges (representing the net of unusual changes in 2003 and 2002), contributed

$185 million to income before interest and taxes.

Offsetting these increases were:

• Recognition of a non-cash goodwill impairment charge of $117 million (excluding amount in discon-tinued operations) in the third quarter of 2003 reducing the carrying value of FSG. This charge reflects the continued slow down in the develop-ment of competitive retail markets and depressed economic conditions that affect the value of FSG.

• Nuclear production costs increased $54 million as a result of an additional nuclear refueling outage in 2003 and longer outages involving additional maintenance work, offset in part by reduced maintenance work at Davis-Besse.

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

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

• General taxes increased $15 million in 2003 com-pared to last year. Higher payroll and kilowatt-hour taxes in 2003 were the principal factors contributing to the increase.

• Higher depreciation and employee benefits costs also contributed to the decrease in income before interest and taxes.

Increase 1

Competitive Services 2003 2002 (Decrease)

(In millions)

Total revenues

$5,402

'$4,526

$876 Loss before interest and income tax benefit (267).

(154) a (133)

Loss before discontinued operations and cumulative effect of accounting changes -

205)

( 1111) f (94)-

Net loss (210) 1109)

(101)

The change in total revenues resulted from the following sources:

Increase Sources of Revenue Changes 2003 2002 (Decrease)

Elec:-

(,in millions) i Electric::'.:....-

i i9in:;-i=f External sales

$1,748 2.$918--'

$830 Internal sales -

2,168 2.044 9 : a124 J

3.916 X 2,962 954 Y )OtherExternal Natural Gas sales.,

624 613 -

11 Energy-related sales 766 E 904 (138)

Other 96 47

'7.

49 1,486

.,1,564 178)

TotalRevenues. '-2 C' '

$5,402

$4,526

$876' 2002 versus 2001:

Excluding the results associated with the former GPU com-panies, comparable results for 2002 and 2001 are as follows:

i Increase Competitive Services (Pre-Mergerd 2D02 2001 (Decrease)

(-In millions)

.Total revenues -,

$4,005

$3,948 5

$57

'Loss before interest and income tax benefit

'(162)

(27)

( (135)

Loss before discontinued operations and

Xcumulative effect of accounting changes (116) 126)

(90).D Net loss i (114)

(35)

- (79);

4-7 FirstEnergy Corp. 2003 21

The $57 million increase in revenues in 2002, compared to 2001, is the net effect of several factors. Kilowatt-hour sales in the wholesale market more than doubled in 2002, increasing revenues by $485 million. More than half of the increase resulted from additional kilowatt-hour sales to Met-Ed and Penelec to supply a portion of their PLR requirements in Pennsylvania, as well as BGS sales in New Jersey and sales under several other contracts. Retail revenues increased by $137 million as a result of additional kilowatt-hour sales within Ohio under Ohio's electricity choice program. Total electric sales revenue increased $622 million in 2002 from 2001, accounting for almost all of the net increase in revenues. Offsetting the higher electric sales revenue were reduced natural gas revenues ($179 million) primarily due to lower prices, and less revenue from FSG

($213 million) reflecting its reclassification to discontinued operations and the sluggish economy. Internal sales to the regulated services segment decreased $180 million in large part due to the impact of customer shopping reducing requirements by the regulated services segment.

Higher electric revenues were nearly offset by increased fuel and purchased power costs. Higher pur-chased power costs resulted from additional volumes to cover supply obligations assumed by FES. Fuel costs increased in part due to an increased mix of higher cost fossil generation in 2002. The extended outage at the Davis-Besse nuclear plant produced a 15% decline in nuclear generation. Lower purchased gas costs due to lower unit costs more than offset reduced gas revenues resulting in an improvement in gas margins.

Nuclear operating costs increased $125 million primarily due to S1 15 million of incremental Davis-Besse costs relat-ed to its extended outage (see Davis-Besse Restoration).

A number of unusual charges discussed above increased other expenses by $76 million in 2002.

Loss before discontinued operations and cumulative effect of accounting changes increased $90 million. The change reflects increased net interest charges ($20 million) and increased income tax benefit ($66 million), as well as the changes discussed above.

The divestiture of Colonial, Webb, Ancoma and Northeast Ohio Natural Gas resulted in their revenues and expenses, with net after-tax earnings of $2 million, being reported as discontinued operations in 2002.

Net income in 2001 also includes the cumulative effect of an accounting change from the adoption of SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" which resulted in an after-tax charge of $9 million.

Capital Resources and Liquidity Changes in Cash Position The primary source of ongoing cash for FirstEnergy, as a holding company, is cash dividends from its subsidiaries.

The holding company also has access to $1.25 billion through revolving credit facilities. In 2003, FirstEnergy received $864 million of cash dividends on common stock from its subsidiaries and paid $453 million in cash divi-dends on common stock to its shareholders. There are no material restrictions on the payments of cash dividends by FirstEnergy's subsidiaries.

As of December 31, 2003, we had S114 million of cash and cash equivalents, compared with S196 million as of December 31, 2002. Cash and cash equivalents as of December 31, 2003 included $32 million received in December 2003 which was included in the NRG settlement claim sold in January 2004 (see Note 3). Cash and cash equivalents as of December 31, 2002 included $50 million used for the redemption of long-term debt in January 2003.

The major sources for changes in these balances are summarized below.

Cash Flows From Operating Activities Our consolidated net cash from operating activities is provided by our regulated and competitive energy services businesses (see Results of Operations - Business Segments above). Net cash provided from operating activi-ties was $1.952 billion in 2003, $1.915 billion in 2002 and

$1.282 billion in 2001, summarized as follows:

Operating Cash Flows Cash earnings VI Working capital and other Tot a

_ _l_

2003 2002 2001 (In millions)

$1,829

$1.655

$1.294 123 260 (12) 51.952 S1,915 31.282

{" Includes net income, depreciation and amortization, deferred income taxes.

inestment tax credits and major noncash charges.

Net cash provided from operating activities increased

$37 million in 2003 compared to 2002 due to a $174 mil-lion increase in cash earnings and a $137 million decrease from changes in working capital. Net cash from operating activities in 2001 included seven weeks of results of the former GPU companies. Excluding the former GPU compa-nies, 2002 and 2001 cash flows from operating activities totaled $1.464 billion and S1.572 billion, respectively, with the decrease principally reflecting reduced cash earnings.

Cash Flows From Financing Activities In 2003 and 2002, the net cash used for financing activi-ties of $1.323 billion and $1.123 billion, respectively, primarily reflects the redemptions of debt and preferred stock shown below. The following table provides details regarding new issues and redemptions during 2003 and 2002:

Securities Issued or Redeemed New Issues Pollution Control Notes Transition Bonds (See Note 5(H)I Secured Notes Unsecured Notes Other, principally debt discounts Redemptions First Mortgage Bonds Pollution Control Notes Secured Notes Unsecured Notes Preferred Stock Other, principally redemption premiums Short-term Borrowings, Net 2003 2002 (In millions) 400 627 51,027 S1,483 238 323 85 127

$2.256 S 1575)

S 143 320 210

14)

S 728 93 278 189 522 21

$1,831 479 22 F;:stEre'gy Cc,;) 2.03

Net cash used for financing activities increased by

$199 million in 2003 as compared to 2002. The increase in funds used for financing activities resulted from an increase in net redemptions of debt and preferred securities of $1.1 billion partially offset by $934 million of common equity financing in 2003.

We had approximately $522 million of short-term indebtedness at the end of 2003 compared to approximately

$1.1 billion at the end of 2002. Available borrowing capability as of December 31, 2003 included the following:

firstEnergy Borrowing Capability Holding Company OE TE

.Total

' (In millions)

Long-Term Revolver S875

$375 s

$1250 Utilized 1270)

(

1401.

7

.310 i

Letters of Credit 184 1

4;.-

1184 Net 421 335

,756 Short-Term Facilities.-

Revolver 375

~125 500 Bank 34 70 104 1 ;-

375, ~

1.-159 -- r-70 > -

-6 j-J Utilized:.

3 i,

.04 Revolver 12801

,12801-:

Bank' 117)

(701 c..

187)

>Net-L

,i 95.-

,,142 l,,,,-9237,

-J4 AmountAvailable

$516

$477 1993 At the end of 2003, the Ohio Companies and Penn had the aggregate capability to issue approximately $3.1 billion of additional first mortgage bonds (FMB) on the basis of property additions and retired bonds, although unsecured senior note indentures entered into by OE and CEI in 2003 limit each company's ability to issue secured debt, including FMBs, subject to certain exceptions. JCP&L, Met-Ed and Penelec no longer issue FMB other than as collateral for senior notes, since their senior note indentures prohibit them (subject to certain exceptions) from issuing any debt which is senior to the senior notes. As of December 31, 2003, JCP&L, Met-Ed and Penelec had the aggregate capa-bility to issue $339 million of additional senior notes using FMB collateral. Based upon applicable earnings coverage tests in their respective charters, OE, Penn, TE and JCP&L could issue a total of $2.8 billion of preferred stock (assuming no additional debt was issued) as of the end of 2003. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock (see Note 5(E) - Long-Term Debt for discussion of debt covenants).

In March 2003, we filed a registration statement with the U.S. Securities and Exchange Commission covering securities in the aggregate of up to $2 billion. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securi-ties, and share purchase contracts and related share purchase units. In September 2003, we used approximately one-half of the amount available with a common stock issuance of 32.2 million shares at $30 per share for net proceeds of approximately $935 million.

At the end of 2003, our common equity as a percent-age of capitalization stood at 45% compared to 38% and 35% at the end of 2002 and 2001, respectively. The higher common equity percentage in 2003 compared to 2001 reflects net redemptions of preferred stock and long-term debt, the issuance of equity discussed above, and the increase in retained earnings.

In October:2003, FirstEnergy restructured its $1 billion 364-day revolving credit facility through a syndicated bank offering that was completed on October 23, 2003. The new syndicated FirstEnergy facilities consist of a $375 million 364-day revolving credit facility and a $375 million three-year revolving credit facility. Also on October 23, 2003, OE entered into a syndicated $125 million 364-day revolving credit facility and a syndicated $125 million three-year revolving credit facility. Combined with an existing syndicated $500 million three-year facility for FirstEnergy, maturing in November 2004, and an existing syndicated

$250 million two-year facility for OE, maturing in May 2005, FirstEnergy's primary syndicated credit facilities total $1.75 billion. These facilities are intended to provide liquidity to meet the short-term working capital requirements of FE and its subsidiaries. Available borrowing capacity under existing facilities totaled $993 million as of December 31, 2003.

Borrowings under these facilities are conditioned on FirstEnergy and/or OE maintaining compliance with certain financial covenants in the agreements. FirstEnergy, under its $375 million 364-day and $375 million three-year facili-ties, and OE, under its $125 million 364-day and $250 million two-year facilities, are each required to maintain a debt to total capitalization ratio of no more than 0.65 to 1 and a contractually-defined fixed (charge coverage ratio of no less than 2 to 1. Under its $500 million three-year facility, FirstEnergy is required to maintain a debt to total capitalization ratio of no more than 0.69 to 1 and a contrac-tually-defined fixed charge coverage ratio for the most recent fiscal quarter of no less than 1.5 to 1. FirstEnergy and OE are in compliance with all of these financial covenants. The ability to draw on each of these facilities is also conditioned upon FirstEnergy or OE making certain representations and warranties to the lending banks prior to drawing on their respective facilities, including a representation that there has been no material adverse change in its business, its condition (financial or otherwise),

its results of operations, or its prospects.

None of FirstEnergy's or OE's primary credit facilities contain provisions, whereby their ability to borrow would be restricted or denied, or repayment of outstanding loans under the facilities accelerated, as a result of any change in the credit ratings of FirstEnergy or OE by any of the nation-ally-recognized rating agencies. Borrowings under each of the primary facilities do contain "pricing grids", whereby the cost of funds borrowed under the facilities is related to the credit ratings of the company borrowing the funds.

Our regulated companies have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among our competitive companies. FirstEnergy Service Company administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and competitive subsidiaries, as well as proceeds available from bank borrowings. For the regulated companies, available bank FirstEnergy Corp. 2003 23

borrowings include $1.75 billion from FirstEnergy's and OE's revolving credit facilities. For the competitive compa-nies, available bank borrowings include only the $1.25 billion of FirstEnergy's revolving credit facility. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, together with accrued interest, within 364 days of borrowing the funds.

For the regulated and competitive money pools, the rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2003 was 1.47% for the regulated companies' pool and 1.90% for the competitive companies' pool.

Our access to capital markets and costs of financing are dependent on the ratings of our securities. The following table shows our securities' ratings following the downgrade by Moody's Investors Service in February 2004. The ratings outlook on all securities is stable.

Ratings of Securites Securities S&P Moody's Fitch FirstEnergy OE CEI TE Penn JCP&L Met-Ed Penelec Senior unsecured BB+

Baa3 BBB-Senior secured BBB Baal BBB+

Senior unsecured 86+

Baa2 BBB Preferred stock BB Bal BBB-

--Senior secured BBB-8aa2 BB6-Senior unsecured BB+

Baa3 86 Preferred stock BB Ba2 BB-Senior secured 6BBE Baa2 BBB-Senior unsecured BB+

Baa3 BB Preferred stock BB Ba2 BB-Senior secured BB6-Baal 6BB+

Senior unsecured 86 BB+

Baa2 BBB Preferred stock BB Bal BBB-Senior secured 868 Baal 6BB*

Preferred stock BB Bal BBB Senior secured BBB Baal BBB+

Senior secured 6BB Baal BBB+

Senior unsecured 86 Baa2 BBB sidiaries to "BBB-" from "BBB" and lowered FirstEnergy's senior unsecured debt rating to "BB+" from "BBB-".

Except for OE's senior secured issue rating, which was left unchanged, all other subsidiary ratings were lowered one notch as well (see table above). The ratings were removed from CreditWatch with negative implications, where they had been placed by S&P on August 18, 2003, and the Ratings Outlook returned to Stable. The rating action fol-lowed a revision in S&P's assessment of our consolidated business risk profile to '6' from '5' ('1' equals low risk, '10' equals high risk), with S&P citing operational and manage-ment challenges as well as heightened regulatory uncertainty for its revision of our business risk assessment score. S&P's rationale for its revisions in our ratings includ-ed uncertainty regarding the timing of the Ohio Rate Plan filing (see State Regulatory Matters), the pending final report on the August 14th power outage (see Power Outage), the outcome of the remedial phase of litigation relating to the Sammis plant (see Environmental Matters),

and the extended Davis-Besse outage and the related pending subpoena (see Davis-Besse Restoration). S&P fur-ther stated that the restart of Davis-Besse and a supportive Ohio Rate Plan extension will be vital positive develop-ments that would aid an upgrade of FirstEnergy's ratings.

S&P's reduction of our credit ratings in December 2003 triggered cash and letter-of-credit collateral calls (see Guarantees and Other Assurances below) in addition to higher interest rates for some outstanding borrowings.

On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed and Penelec to Baal from A2. Moody's also downgraded the preferred stock rating of JCP&L to Bal from Baa2 and the senior unsecured rating of Penelec to Baa2 from A2.

The ratings of OE, CEI, TE and Penn were confirmed.

Moody's said that the lower ratings were prompted by:

"1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a nar-rowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries."

Cash Flows From Investing Activities Net cash flows used in investing activities totaled

$712 million in 2003. The net cash used for investing was principally for property additions. Regulated services expenditures for property additions primarily include expenditures supporting the distribution of electricity.

Expenditures for property additions by the competitive services segment are principally generation-related, including

$21 million for capital additions at the Davis-Besse nuclear plant during its extended outage. The following table sum-marizes 2003 investments by our regulated services and competitive services segments:

I Penn s only senior unsecured debt obligations are pollution control revenue refunding bonds issued in the name of the Ohio Air Quality Development Authority to which this rating applies.

On September 30, 2003, Fitch Ratings lowered the senior unsecured ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior secured, senior unse-cured, and preferred stock ratings of Met-Ed, Penelec, CEI, and TE. In addition, Fitch affirmed the ratings of OE, Penn and JCP&L. Fitch announced that the Rating Outlook is Stable for the securities of FirstEnergy, and all of the secu-rities of its electric utility operating companies. Fitch stated that the changes to the long-term ratings were "driven by the high debt leverage of the parent, FirstEnergy. Despite management's commitment to reduce debt related to the GPU merger, subsequent cash flows have been vulnerable to unfavorable events, slowing the pace of FirstEnergy's debt reduction efforts. The Stable Outlook reflects the success of FirstEnergy's recent common equity offering and management's focus on a relatively conservative integrated utility strategy."

On December 23, 2003, S&P lowered its corporate credit ratings on FirstEnergy and its regulated utility sub-24 FirsrEnergv Co!p. 20(3

'1 Summary of 2003:

- Cash Flows Used for, Property investing iclivities OaOIUons Investments Uther 10otal

'Sources (Uses)

(In millions)

Regulated Services

)(434)'"

$)38)31.

$16 i $(455h Competitive Services (345)(21 0241 (13)

(13561 Other (77)

101(t5

'76

'.100.

Total

$1856)

'$65 r

'$79

$1712)

{w Property additions primarily for transmission and distribution facilities.

e21 Property additions to generation facilities.

PI Net of several items from cash and other investments and Penelecs nonutility generation (NUG) trust offset in part by investments in nuclear decommissioning trusts.

t 4

1 Netproceeds from sale of assets.

I Proceeds from Aquile Note.

defined benefit pension plans funding at a minimum required level as determined by government regulations. Amounts are subject to change based on the perform-ance of the assets in the plan as well as the discount rate used to determine the obligation. We are unable to estimate the projected contributions beyond 2007.

(4j Fuel and powerpurchases under contracts with fixed or minimum quantities and approximate timing.

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

As of December 31, 2003, the maximum potential future payments under outstanding guarantees and other assurances totaled approximately $1.9 billion, as summa-rized below:

K Guarantees and Other Assurances Maximum Exposure' (Inmillions)

In 2002, net cash flows used in investing activities totaled $816 million, principally due to property additions

($998 million) which were partially offset by proceeds from the sale of Midlands ($155 million).

Net cash used for investing activities decreased by $104 million in 2003 compared to 2002 primarily due to decreased capital expenditures partially offset by net changes in nuclear decommissioning and NUG trust investments and decreased proceeds from sale of assets.

Our cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met with-out increasing our net debt and preferred stock outstanding.

In addition, a refunding payment of $50 million was made to the NUG trust fund (see State Regulatory Matters -

Pennsylvania) in January 2004. Available borrowing capacity under existing credit facilities will be used to manage work-ing capital requirements. Over the next three years, we expect our cash requirements will be met with cash from operations and funds from the capital markets, if needed.

Our capital spending for the period 2004-2006 is expect-ed to be about $2.3 billion (excluding nuclear fuel), of which approximately $713 million applies to 2004. Investments for additional nuclear fuel during the 2004-2006 period are esti-mated to be approximately $323 million, of which about $90 million applies to 2004. During the same period, our nuclear fuel investments are expected to be reduced by approximately

$285 million and $93 million, respectively, as the nuclear fuel is consumed.

Contractual Obligations Our cash contractual obligations as of December 31, 2003 that we consider firm obligations are as follows:

E nerILLllgy UandEerg ated Cunrats I_

, I -8I n

otrcs 1

-Ene;I:

rgy and Energy-Related Iotatl).'.

-7 S $ 857 m: n L t

. 0

< } :. : at A uther

',- 17 SuretyBonds E

161 Letters of Credit3ll4' 678.

'.Total Guarantees and Other Assurances

$1,870 III Issued for a one-year tenm, with a 10-day termination right by FirstEnergy.

2) Issued for various terms.

31 Includes letters of credit of $184 million issued for various terms under letter of credit capacity available in FirstEnergys revolving credit agreement.

14)

Includes unsecured letters of credit of approximately $216 million pledged in con-nection with the sale and leaseback of Beaver Valley Unit 2 by CEI and TE/see Note 5(E), as well as collateralized letters of credit of $278 million pledged in con-nection with the sale and leaseback of Beaver Valley Unit 2 by OE (see Note 4).

We guarantee energy and energy-related payments of our subsidiaries involved in energy marketing activities -

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

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating-downgrade or "material adverse event" the immediate payment of cash col-lateral or provision of a letter of credit may be required. The following table summarizes collateral provisions as of December 31, 2003:

2105-2007-.

Contractual Obligations Total 2004 A 2D06 2008 Thereafter-

.r._

• t(In millions).-

t Long-term debt

$11,471

-$1,256

$1,964

$ 572 -$ 7,679 Short-term borrowings:

522' 522.

Preferred stock(ll 19 2

4 13 c

[.Capitalleases().

24-

.6

.10 2

6-Operating leasesm 2,545 182 363 358 1.642 Pension fundingl 83 546 289 Purchasesl 4) -

15,145

• 2,603 33,886 3325 5,331 Total.

$30,561

$4,571

$6,773

.$4,559

$14,658

°} Subject to mandatory redemption.

ta) See Note 4.

(3)Amounts represent our estimate of the contributions necessary to maintain our FirstEnergy Corp. 2003 25

Total Collateral Paid Remaining Collateral Provisions Exposure Cash Letters of Credit ExposureM)

(In millions)

Rating downgrade

$187

$68

$5

$114 Adverse event 235 65 170 Total

$422

$68 S70

$284

" As of February 11. 2004 wve had a remaining exposure of $282 million with $106 million of cash and $87 million of letters of credit provided as collateral.

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

We have guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $6.0 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. We have provided the TEBSA project lenders a $50 million letter of credit (LOG) (under our existing

$250 million LOC capacity available as part of our $1.25 billion credit facilities) to obtain TEBSA lender consent as substitute collateral for the release of the assets for us to abandon our Argentina operations, Emdersa (see Note 3). In December 2003, a replacement LOC was issued in the amount of $60 million, which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. This LOC granted us the ability to sell our remaining 20.1 % interest in Avon, as well as abandon the Argentina assets in April 2003.

resulted in any change in outstanding debt.

FirstEnergy has equity ownership interests in certain various businesses that are accounted for using the equity method. There are no undisclosed material contingencies related to these investments. Certain guarantees that we do not expect to have a material current or future effect on our financial condition, liquidity or results of operations are disclosed under contractual obligations above.

Market Risk Information We use various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. Our Risk Policy Committee, com-prised of executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices.

Commodity Price Risk We are exposed to market risk primarily due to fluctu-ations in electricity, natural gas and coal prices. To manage the volatility relating to these exposures, we use a variety of non-derivative and derivative instruments, including for-ward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes and, to a much lesser extent, for trading purposes. Most of our non-hedge derivative contracts represent non-trading posi-tions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during 2003 is sum-marized in the following table:

Off-Balance Sheet Arrangements We have obligations that are not included on our Consolidated Balance Sheets related to the sale and lease-back arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are reflected as part of the operating lease payments disclosed above (see Notes 4 and 9). The present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.4 billion as of December 31, 2003.

CEI and TE sell substantially all of their retail customer receivables to Centerior Funding Corporation (CFC), a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a "qualified special purpose entity")

under SFAS 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities,"

under an asset-backed securitization agreement. This provided $200 million of off-balance sheet financing as of December 31, 2003. See Note 2(C) for additional dis-cussion about this arrangement.

As of December 31, 2003, off-balance sheet arrange-ments include certain statutory business trusts created by CEI, Met-Ed and Penelec to issue trust preferred securities aggregating $285 million. These trusts were included in the consolidated financial statements of FirstEnergy prior to adoption of FASB Interpretation No. 46, "Consolidation of Variable Interest Entities", but have subsequently been deconsolidated under "FIN 46R" (see Note 9 - New Accounting Standards and Interpretations). This has not 26 FirstEnergy Corp 2)103 Increase (Decrease) in the Fair Value Derivative Contracts Non-Hedge Hedge Total (In millions)

Change in the fair value of commodity derivative contracts Outstanding net asset as of January 1, 2003 54 Additions/Increase in value of existing contracts 8

Change in techniques/assumptions 9

Settled contracts (41 Outstanding net asset as of December 31, 2003(1) 67 Non-commodity net assets as of December 31.2003:

Interest Rate Swaps(21 Net Assets - Derivatives Contracts as of December31, 2003 S 67 Impact of Changes in Commodity Derivative Contracts 1)

Income Statement Effects IPre-Tax) 5113)

Balance Sheet Effects:

OCI (Pre-Tax)

S -

Regulatory Liability

$ 26 S24

$78 35 43 9

(47)

(51)

(6)

(6)

S 6

$73

) -

SO13)

S1121 3112)

S -

S26

1) Includes S61 million in non-hedge commodity derivative contracts which are offset by a regulatory liability.

u2)

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

IN Excludes $17 million of derivative contract fair value decrease, representing our 50% share of Great Lakes Energy Partners, IIC.

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

Derivatives are included on the Consolidated Balance Sheet as of December 31, 2003 as follows:

Balance Sheet Classification Non Hedge Hg Total I

-. nmillions)

Current-OtherAssets

$3

$2 13

$15 Other Liabilities

-B)

.B)

Non-Current-.

.i Other Deferred Charges' 62 14 76 Other Noncurrent Liabilities (10)

(10 a Net assets

$67

$6

$.73 7 Comparison of Carrying Value to Fair Value There-i-

Fair

-Year ot Maturity 2004 2005 2006 2007 2008 ";after Total Value

-Assets (Dollars in millions)

Investments other.

a than Cash and Cash Equivalents-Fixed Income '

3326

$64 sa$82; $77

$57 $1,882 $2488 $2597 Average interest rate 7.5% 7.8%' 7 7.9% 7.7% : 6.2%. 6.6 Liabilities The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, we rely on model-based information. The model provides estimates of future regional prices for elec-tricity and an estimate of related price volatility. We use these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of com-modity derivative contracts by year are summarized in the following table:

,,Source of Intorination'.

=*

=:-2=;Zf..

is-i :-FairValue by Contract Year 2004 '2005 2006 2007 Thereafter Total (In millions)3 Prices actively quoted'"

$11

$1:.-$-

.$12 Other external sources 12 15 10 25 Prices based on models a

'I 10.

23 42

,' Total13)

-' $26

$11

$10 I 49

,$23 ~, $79: -

"' Exchange traded

/2) Broker quote sheets.

01 Includes $61 million from an embedded option that is offset by a regulatory liability and does not affect earnings.

We perform sensitivity analyses to estimate our expo-sure to the market risk of our commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on both our trading and nontrading derivative instruments would not have had a material effect on our consolidated financial position or cash flows as of December 31, 2003. We estimate that if energy commodi-ty prices experienced an adverse 10% change, net income for the next twelve months would decrease by approxi-mately $3 million.

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

Long-term Debt and Other

[

Long-Term Obligations:

[-Rednrte

$986 $547

'$1,377

$237- $335 $6,644 s11t26 $10,625

'Average interest rate' 7.3% 73%

5.7% 6.6% 5.3%'

6.7%

6.6%

Variablerate11l

$270

$40

$1,035 $1,345 $1,345

'Average interest 4te 2.4 2.3 2.3 i 2.4 Preferred Stock

-- Subject to Mandatory t-Redemrption

'.$2'$2

$2 S12

$1

$19

'19 Average dividend rate 7.5% 7.5% 7.5% 7.6 74%

7.6%

'Short-term Borrowings

$522 - -

$522 Average interest rate 2.1%,

. 2.1

01) Balarces and rates do not reflect the fied-to-floatig interestrate swap agreements discussed below We are subject to the inherent interest rate risks relat-ed to refinancing maturing debt by issuing new debt securities. As discussed in Note 4 to the consolidated financial statements, our investments in capital trusts effectively reduce future lease obligations, also reducing interest rate risk. While fluctuations in the fair value of our Ohio EUOC decommissioning trust balances will eventually affect earnings (affecting OCI initially) based on the guid-ance provided by SFAS 115, our non-Ohio EUOC have the opportunity to recover from customers the difference between the investments held in trust and their decom-missioning obligations. Thus, there is not expected to be an earnings effect from fluctuations in their decommissioning trust balances. As of December 31, 2003, decommissioning trust balances totaled $1.352 billion, with $797 million held by our Ohio EUOC and the balance held by our non-Ohio EUOC. As of year end 2003, trust balances of our Ohio EUOC included 62% of equity securities and 38% of debt instruments.

Interest Rate Swap Agreements We have entered into various fixed-to-floating interest rate swap agreements, as part of our ongoing effort to manage the interest rate risk of our debt portfolio. These.

derivatives are treated as fair value hedges of fixed-rate, long-term debt issues - protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. Reductions to interest expense recorded in 2003 and 2002 due to the difference between fixed and variable debt rates totaled $27 million and $17 million, respectively. As of December 31, 2003, the debt underlying the interest rate swaps had a weighted average fixed interest rate of 5.39%, which the swaps have effec-tively converted to a current weighted average variable interest rate of 2.06%. GPU Power (through a subsidiary) used existing dollar-denominated interest rate swap agree-ments in 2003. The swaps convert variable-rate debt to fixed-rate debt to manage the risk of increases in variable FirstEnergy Corp. 2003 27

interest rates. GPU Power's swaps had a weighted aver-age fixed interest rate of 6.68% in 2003 and 2002. The following summarizes the principal characteristics of the swap agreements:

December 31,2003 December 31,2002 Notional Maturity Fair Notional Maturity Fair Amount Date Value Amount Date Value (Dollars in milions)

Interest Rate Swaps Fixed to Floating Rate (Fair value hedges)

$200 50 100 100 350 150 150 50 2006 2008 2010 2011 2013 2015 2018 2019

$1 (1)

(I10) 10 l

S444 2023

$16 150 2025 6

Floating to Fixed Rate' (Cash flow hedges)

S 7 2005 -

S 16 2005 S11 FirstEnergy no longer had the cash flow hedges as of January 30, 2004 as a result of GPU Power divestiture (see Note 3).

Equity Price Risk Included in nuclear decommissioning trusts are mar-ketable equity securities carried at their market value of approximately $779 million and $532 million as of December 31, 2003 and 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges, would result in a $78 million reduction in fair value as of December 31, 2003 (see Note 2(M) - Cash and Financial Instruments).

Foreign Currency Risk Due to the disposition of foreign operations, we are no longer exposed to foreign currency risk from investments in international business operations. In 2002, we experi-enced net foreign currency translation losses in connection with our Argentina operations (see Note 3 - Divestitures).

Credit Risk Credit risk is the risk of an obligor's failure to meet the terms of any investment contract, loan agreement or other-wise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counter-party performance, whether reflected on or off the balance sheet. We engage in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry.

We maintain stringent credit policies with respect to our counterparties that management believes minimizes overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of our credit program, we aggressively manage the quality of our portfolio of energy contracts evidenced by a current weighted risk S&P rating for energy contract coun-terparties of "BBB." As of December 31, 2003, the largest credit concentration to any counterparty was 8 percent -

which is a currently rated investment grade counterparty.

State Regulatory Matters In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation included similar provisions which are reflected in our EUOC's respective state regula-tory plans. However, despite these similarities, the specific approach taken by each state and for each of our EUOCs varies. Those provisions include:

• allowing the EUOC's electric customers to select their generation suppliers;

• establishing PLR obligations to customers in the EUOC's service areas;

• allowing recovery of transition costs (sometimes referred to as stranded investment) not otherwise recoverable in a competitive generation market;

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

• deregulating the electric generation businesses;

• continuing regulation of the EUOC's transmission and distribution systems; and

• requiring corporate separation of regulated and unregulated business activities.

Regulatory assets are costs which the respective regulatory agencies have authorized for recovery from cus-tomers in future periods and, without such authorization, would have been charged to income when incurred. All of the regulatory assets are expected to continue to be recov-ered under the provisions of the respective transition and regulatory plans as discussed below. The regulatory assets of the individual companies are as follows:

Regulatory Assets As of December 31 2003 2002 (Decrease)

[In millions)

OE

$1,451 51,787

$(3361 CEI 1.056 1.145 1891 TE 459 545 1861 Penn 28 151 (1231 JCP&L 2.558 3.058 (5001 Met-Ed 1,028 1,179 11511 Penelec 497 600 11031 Total S7,077

$8,465

$41,3881 Regulatory assets by source are as follows:

Regulatory Assets By Source As of December 31 Regulatory transition charge Customer shopping incentives Customer receivables for future income taxes Societal benefits charge Loss on reacquired debt Postretirement benefits Nuclear decommissioning, decontamination and spent fuel disposal costs Component removal costs Property losses and unrecovered plant costs Other Total S

Increase 20033 2002 IDecrease)

(In millions)-

6,427

$7,608

$11.181) 371 188 183 340 394 (54) 81 144 (63) 75 74 1

77 88 (11) 196) 1321) 99 1195)

(288)

(33) 70 88 53 70

$7.077 S8,465 (18)

(17) i 51,388) 28 FtrsrEnergy Corp 200)3

Ohio FirstEnergy's transition plan for the Ohio EUOC included approval for recovery of transition costs, including regulatory assets, through no later than 2006 for OE, mid-2007 for TE and 2008 for CEI, except where a longer period of recovery is provided for in the settlement agree-ment; granting preferred access over our subsidiaries to nonaffiliated marketers, brokers and aggregators, to 1,120 MW of generation capacity through 2005 at established prices for sales to the Ohio EUOC's retail customers; and freezing customer prices through a five-year market devel-opment period (2001-2005), except for certain limited statutory exceptions including a 5% reduction in the price of generation for residential customers. In February 2003, the Ohio EUOC were authorized increases in revenues aggregating approximately $50 million (OE - $41 million, CEI - $4 million and TE - $5 million) to recover their higher tax costs resulting from the Ohio deregulation legislation.

Our Ohio customers choosing alternative suppliers receive an additional incentive applied to the shopping credit (generation component) of 45% for residential cus-tomers, 30% for commercial customers and 15% for industrial customers. The amount of the incentive is deferred for future recovery from customers. Subject to approval by the PUCO, recovery will be accomplished by extending the respective transition cost recovery period.

On October 21, 2003, the Ohio EUOC filed an applica-tion with the PUCO to establish generation service rates beginning January 1, 2006, in response to expressed concerns by the PUCO about price and supply uncertainty following the end of the market development period. The filing included two options:

• A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or

• A Rate Stabilization Plan, which would extend current generation prices through 2008, ensuring adequate generation supply at stable prices, and continuing our support of energy efficiency and economic development efforts.

Under the first option, an auction would be conducted to secure generation service for our Ohio EUOC's cus-tomers. Beginning in 2006, customers would pay market prices for generation as determined by the auction.

Under the Rate Stabilization Plan option, customers would have price and supply stability through 2008 - three years beyond the end of the market development period -

as well as the benefits of a competitive market. Customer benefits would include: customer savings by extending the current five percent discount on generation costs and other customer credits; maintaining current distribution base rates through 2007; market-based auctions that may be conducted annually to ensure that customers pay the lowest available prices; extension of our support of energy-efficiency programs and the potential for continuing the program to give preferred access to nonaffiliated entities to generation capacity if shopping drops below 20%.

Under the proposed plan, we are requesting:

• Extension of the transition cost amortization period for OE from 2006 to 2007; for CEI from 2008 to 2009 and for TE from mid-2007 to 2008;

• Deferral of interest costs on the accumulated shopping incentives and other cost deferrals as new regulatory assets; and

• Ability to initiate a request to increase generation rates under certain limited conditions.

On January 7, 2004, the PUCO staff filed testimony on the proposed rate plan generally supporting the Rate Stabilization Plan as opposed to the competitive auction proposal. Hearings began on February 11, 2004. On February 23, 2004, after consideration of PUCO staff com-ments and testimony as well as those provided by some of the intervening parties, FirstEnergy made certain modifica-tions to the Rate Stabilization Plan. A decision is expected from the PUCO in the Spring of 2004.

On November 25, 2003, the PUCO ordered FirstEnergy to file a plan with the PUCO no later than March 1, 2004, illustrating how FirstEnergy will address certain problems identified by the U.S.-Canada Power System Outage Task Force (in connection with the August 14, 2003 regional power outage) and addressing how FirstEnergy proposes to upgrade its control room computer hardware and software, improve its control room training procedures and improve the training of control room operators to ensure that similar problems do not occur in the future. The PUCO, in consultation with the North American Electric Reliability Council, will review the plan before determining the next steps in the proceeding.

New Jersey Under New Jersey transition legislation, all electric distribution companies were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003. JCP&L's two August 2002 rate filings requested increases in base electric rates of approximately $98 million annually and requested the recovery of deferred energy costs that exceeded amounts being recovered under the current market transition charge (MTC) and societal benefits charge (SBC) rates; one proposed method of recovery of these costs is th) securitization of the deferred balance. This securitization methodology is similar to the Oyster Creek securitization (see Note 5(H)).

On July 25, 2003, the NJBPU announced its JCP&L base electric rate proceeding decision which reduced JCP&L's annual revenues by approximately $62 million effective August 1, 2003. The NJBPU decision also provided for an interim return on equity of 9.5% on JCP&L's rate base for the next six to twelve months. During that period, JCP&L will initiate another proceeding to request recovery of addi-tional costs incurred to enhance system reliability. In that proceeding, the NJBPU could increase the return on equity to 9.75% or decrease it to 9.25%, depending on its assess-ment of the reliability of JCP&L's service. Any reduction would be retroactive to August 1, 2003. The revenue decrease in the decision consists of a $223 million decrease in the elec-tricity delivery charge, a $111 million increase due to the August 1, 2003 expiration of annual customer credits previ-FirstEnergy Corp. 2003 29

ously mandated by the New Jersey transition legislation, a

$49 million increase in the MTC tariff component, and a net

$1 million increase in the SBC charge. The MTC allows for the recovery of $465 million in deferred energy costs over the next ten years on an interim basis, thus disallowing $153 million of the S618 million provided for in a preliminary set-tlement agreement between certain parties. As a result, JCP&L recorded charges to net income for the year ended December 31, 2003, aggregating $185 million ($109 million net of tax) consisting of the $153 million deferred energy costs and other regulatory assets. JCP&L filed a motion for rehearing and reconsideration with the NJBPU on August 15, 2003 with respect to the following issues: (1) the disal-lowance of the $153 million deferred energy costs; (2) the reduced rate of return on equity; and (3) $42.7 million of dis-allowed costs to achieve merger savings. On October 10, 2003, the NJBPU held the motion in abeyance until the final NJBPU decision and order is issued. This is expected to occur in the first quarter of 2004.

On July 5, 2003, JCP&L experienced a series of 34.5 kilovolt sub-transmission line faults that resulted in outages on the New Jersey shore. The NJBPU instituted an investi-gation into these outages, and directed that a Special Reliability Master be hired to oversee the investigation.

On December 8, 2003, the Special Reliability Master issued his Interim Report recommending that JCP&L implement a series of actions to improve reliability in the area affected by the outages. The NJBPU adopted the findings and rec-ommendations of the Interim Report on December 17, 2003, and ordered JCP&L to implement the recommended actions on a staggered basis, with initial actions to be com-pleted by March 31, 2004. JCP&L expects to spend $12.5 million implementing these actions during 2004.

Pennsylvania In June 2001, the Pennsylvania Public Utility Commission (PPUC) approved the Settlement Stipulation with all of the major parties in the combined merger and rate proceedings which approved the FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy costs, permitting Met-Ed and Penelec to defer, for future recovery, energy costs in excess of amounts reflected in their capped generation rates retroactive to January 1, 2001. This PLR deferral accounting procedure was later reversed in a February 2002 Commonwealth Court of Pennsylvania decision. The court decision affirmed the PPUC decision regarding approval of the merger, remanding the decision to the PPUC only with respect to the issue of merger savings. FirstEnergy established reserves in 2002 for Met-Ed's and Penelec's PLR deferred energy costs which aggregated $287.1 million, reflecting the potential adverse impact of the then pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court decision. We recorded in 2002 an aggregate non-cash charge of $55.8 million (S32.6 mil-lion net of tax) to income for the deferred costs incurred subsequent to the merger. The reserve for the remaining S231.3 million of deferred costs increased goodwill by an aggregate net of tax amount of $135.3 million.

On April 2, 2003, the PPUC remanded the issue relating to merger savings to the Office of Administrative Law Judge (ALJ) for hearings, directed Met-Ed and Penelec to file a position paper on the effect of the Commonwealth Court order on the Settlement Stipulation and allowed other parties to file responses to the position paper. Met-Ed and Penelec filed a letter with the ALJ on June 11, 2003, voiding the Stipulation in its entirety and reinstating Met-Ed's and Penelec's restructuring settlement previously approved by the PPUC.

On October 2, 2003, the PPUC issued an order conclud-ing that the Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The PPUC directed Met-Ed and Penelec to file tariffs within thirty days of the order to reflect the competitive transition charge (CTCI rates and shopping credits that were in effect prior to the June 21, 2001 order to be effective upon one day's notice. In response to that order, Met-Ed and Penelec filed these supplements to their tariffs to become effective October 24, 2003.

On October 8, 2003, Met-Ed and Penelec filed a peti-tion for clarification relating to the October 2, 2003 order on two issues: to establish June 30, 2004 as the date to fully refund the NUG trust and to clarify that the ordered accounting treatment regarding the CTC rate/shopping credit swap should follow the ratemaking, and that the PPUC's findings would not impair their rights to recover all of their stranded costs. On October 9, 2003, ARIPPA (an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed and Penelec to reinstate accounting for the CTC rate/shopping credit swap retroactive to January 1, 2002. Several other parties also filed petitions. On October 16, 2003, the PPUC issued a reconsideration order granting the date requested by Met-Ed and Penelec for the NUG trust refund and, denying Met-Ed's and Penelec's other clarification requests and granting ARIPPA's petition with respect to the retroactive accounting treatment of the changes to the CTC rate/shopping credit swap. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse the PPUC's finding that requires Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. Met-Ed and Penelec are considering filing an appeal to the Commonwealth Court on the PPUC orders as well.

On October 27, 2003, one Commonwealth Court judge issued an Order denying Met-Ed's and Penelec's objection without explanation. Due to the vagueness of the Order, Met-Ed and Penelec, on October 31, 2003, filed an Application for Clarification with the judge. Concurrent with this filing, Met-Ed and Penelec, in order to preserve their rights, also filed with the Commonwealth Court both a Petition for Review of the PPUC's October 16 and October 22 Orders, and an application for reargument, if the judge, in his clarification order, indicates that Met-Ed's and Penelec's objection was intended to be denied on the merits. In addi-tion to these findings, Met-Ed and Penelec, in compliance with the PPUC's Orders, filed revised PPUC quarterly reports for the twelve months ended December 31, 2001 and 2002, and for the first two quarters of 2003, reflecting balances 30 FirstEnergy Corp 2L'03

consistent with the PPUC's findings in their Orders.

Effective September 1, 2002, Met-Ed and Penelec assigned their PLR responsibility to their FES affiliate through a wholesale power sale agreement. The PLR sale will be automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Undefthe terms of the wholesale agreement, FES assumed the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommit-ted PLR energy costs during the term of the agreement with FES. FES has hedged most of Met-Ed's and Penelec's unfilled PLR on-peak obligation through 2004 and a portion of 2005, the period during which deferred accounting was previ-ously allowed under the PPUC's order. Met-Ed and Penelec are authorized to continue deferring differences between NUG contract costs and current market prices.

In late 2003, the PPUC issued a Tentative Order imple-menting new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking

• r procedure to amend the Electric Service Reliability i

Regulations to implement these new benchmarks, and cre-ate additional reporting on reliability. Although neither the Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1; 2003. The comment period for both the Tentative Order and the Proposed Rulemaking Order has closed. We are currently awaiting the PPUC to issue a final order in both matters.

The order will determine (1) the standards and benchmarks to be utilized, and (2) the details required in the quarterly and annual reports. It is expected that these Orders will be finalized in March 2004.

On January 16, 2004, the PPUC initiated a formal investigation of Met-Ed's, Penelec's and Penn's levels of

.compliance with the Public Utility Code and the PPUC's regulations and orders with regard to reliable electric serv-ice. Hearings will be held in August in this investigation and the AU has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order before December 16, 2004. We are unable to predict the outcome of the investi-gation or the impact of the PPUC Order.

FERC Regulatory Matters On December 19, 2002, the FERC granted uncondi-tional Regional Transmission Organization status to PJM Interconnection, LLC which includes JCP&L, Met-Ed and Penelec as transmission owners. The FERC also condition-ally accepted GridAmerica's filing to become an independent transmission company within Midwest Independent System Operator, Inc. (MISO). GridAmerica will operate ATSI's transmission facilities. Effective October 1, 2003, MISO received operational control of ATSI's trans-mission facilities. Transmission service over the facilities of ATSI is now provided under the MISO Open Access Transmission Tariff. A settlement of all rate matters related to ATSI's integration into MISO was filed with the FERC on December 18, 2003 and has been certified to the Commission as an uncontested settlement.

PJM and MISOwere ordered by the FERC to develop a common market between the regions by October 31, 2004.

The FERC also initiated a Section 206 investigation into the reasonableness of the "through-and-out" transmission rates charged by PJM and MISO. By order issued November 17, 2003, MISO, PJM and certain unaffiliated transmission own-ers in the Midwest were directed to eliminate rates for point-to-point service between the two RTOs effective April 1, 2004. A settlement judge has been appointed by the FERC to resolve compliance filings by the affected transmis-sion providers. AEP, Commonwealth Edison and other utilities have appealed the FERC's November 17, 2003 order to the federal court of appeals for the District of Columbia.

Environmental Matters We believe we are in material compliance with current sulfur dioxide (S02) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions from the Companies' Ohio and Pennsylvania facilities.

Various regulatory and judicial actions have since sought to further define NOx reduction requirements (see Note 7(D)

- Environmental Matters). We continue to evaluate our compliance plans and other compliance options.

Clean Air Act Compliance Violations of federally approved S02 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The EPA has an interim enforcement policy for S02 regulations in Ohio that allows for compli-ance based on a 30-day averaging period. We cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

W. H. Sammis Plant In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 -

power plants, including the W. H. Sammis Plant. In addi-tion, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S.

District Court for the Southern District of Ohio. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability FirstEnergy Corp. 2003 31

phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently sched-uled to be ready for trial beginning July 19, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requir-ing the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penal-ties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on the Company's financial condition and results of operations.

Management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of December 31, 2003.

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

The EUOC have been named as "potentially responsible parties" (PRPs) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of dis-posal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dis-pute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis.

Therefore, environmental liabilities that are considered proba-ble have been recognized on the Consolidated Balance Sheet as of December 31, 2003, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable societal benefits charge.

The Companies have total accrued liabilities aggregating approximately $65 million as of December 31, 2003.

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

We cannot currently estimate the financial impact of cli-mate change policies although the potential restrictions on carbon dioxide (C02) emissions could require significant capi-tal and other expenditures. However, the C02 emissions per kilowatt-hour of electricity generated by FirstEnergy is lower than many regional competitors due to FirstEnergy's diversi-fied generation sources which includes the low or non-C02 emitting gas-fired and nuclear generators.

Other Legal Matters A number of legal and regulatory proceedings have been filed against FirstEnergy in connection with, among other things, the restatements of earnings, the August 14th regional outage described above, and the extended outage at Davis-Besse, alleging violations of federal securities laws, breaches of fiduciary duties by its directors and officers or damages as a result of one or more of those events. All shareholder derivative actions filed in federal court have been consolidated into one action, as have all federal securities actions. Three tort actions seeking damages allegedly caused by the August 14th power outage were filed in Ohio state court and were dismissed on jurisdictional grounds. Two of those decisions have been appealed and the third case was refiled at the PUCO. We were also named as a respondent in two regulatory proceedings initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service. Two tort actions relating to the power outage were preliminarily commenced in New York State court, but have not been pursued to date. We intend to defend all of these actions vigorously, but cannot predict the outcome of any of these pro-ceedings or whether any further regulatory proceedings or legal actions may be instituted against us. In particular, if we were ultimately determined to have legal liability in connection with any of these proceedings, it could have a material adverse effect on our financial condition and results of operations.

FENOC recently received a subpoena from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse plant. We are unable to predict the outcome of this investigation. In addition, FENOC remains subject to possible civil enforcement action by the NRC in connection with the events leading to the Davis-Besse outage. If it were ultimately determined that FirstEnergy has legal liability or is otherwise made subject to regulatory or civil enforcement action with respect to the Davis-Besse outage, it could have a material adverse effect on FirstEnergy's financial condition and results of operations.

Critical Accounting Policies We prepare our consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these princi-32 FirstEnergy Corp 20L03

ples often requires a high degree of judgment, estimates and assumptions that affect financial results. All of our assets are subject to their own specific risks and uncertain-ties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Our more significant accounting policies are described below.

Regulatory Accounting Our regulated services segment is subject to regulation that sets the prices (rates) it is permitted to charge its cus-tomers based on costs that the regulatory agencies determine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in each state in which we operate, a significant amount of regulatory assets have been recorded - $7.1 billion as of December 31, 2003. We regular-ly review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future.

l Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management rep-resenting operations, finance and risk assessment. In order to determine the appropriate accounting for derivative trans-actions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting lit-erature and management's intended use of the derivative.

New authoritative guidance continues to shape the applica-tion of derivative accounting. Management's expectations and intentions are key factors in determining the appropri-ate accounting for a derivative transaction and, as a result, such expectations and intentions are documented.

a Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used

• in their valuation. We continually monitor our derivative con-tracts to determine if our activities, expectations, intentions, assumptions and estimates remain valid. As part of our normal operations, we enter into a significant number of commodity contracts, as well as interest rate swaps, which increase the impact of derivative accounting judgments.

Revenue Recognition We follow the accrual method of accounting for rev-enues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including:

• Net energy generated or purchased for retail load

• Losses of energy over transmission and distribution lines

• Mix of Kilowatt - hour usage by residential, commercial and industrial customers

• Kilowatt - hour usage of customers receiving electricity frodm alternative suppliers Pension and Other Postretirement Benefits Accounting Our reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions.

Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions we make to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as our merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs.

Plan amendments to retirement health care benefits in 2003 and 2002, related to changes in benefits provided and cost-sharing provisions, reduced FirstEnergy's obligation by

$123 million and $121 million, respectively. In early 2004, FirstEnergy announced that it would amend the benefit pro-visions of its health care benefits plan and both employees and retirees would share in more of the benefit costs.

In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants.

SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long peri-ods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actu-al level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience.

In selecting an assumed discount rate, we consider currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obli-gations. Due to recent declines in corporate bond yields and interest rates in general, we reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% and 7.25% used as of December 31, 2002 and 2001, respectively.

Our assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by our pension trusts. In 2003, 2002 and 2001, plan assets actually earned 24.0%,

(11.3)% and (5.5)%, respectively. Our pension costs in 2003 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and FirstEnergy Corp. 2003 33

our pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1 % cash.

As a result of the increased market value of our pension plan assets, we reduced our minimum liability as prescribed by SFAS 87 as of December 31, 2003 by $253 million, recording a decrease of $6 million in an intangible asset and crediting OCI by $145 million (offsetting previously recorded deferred tax benefits by $102 million). The remaining bal-ance in OCI of $299 million will reverse in future periods to the extent the fair value of trust assets exceeds the accu-mulated benefit obligation. The accrued pension cost was reduced to $438 million as of December 31, 2003.

Based on pension assumptions and pension plan assets as of December 31, 2003, we will not be required to fund our pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. Pension and OPEB expenses in 2004 are expected to decrease by $38 million and $34 million, respectively. These reductions reflect the actual perform-ance of pension plan assets and amendments to the health care benefits plan announced in early 2004 which result in employees and retirees sharing more of the benefit costs.

The reduction in OPEB costs for 2004 does not reflect the impact of the new Medicare law signed by President Bush in December 2003 due to uncertainties regarding some of its new provisions (see Note 2(K)). The 2003 and 2002 composite health care trend rate assumptions are approxi-mately 10%-1 2% gradually decreasing to 5% in later years.

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

Increase in Costs from Adverse Changes in Key Assumptions Assumption Adverse Change Pension OPEB Total (In millions)

Discount rate Decrease by 0.25' S 10 S 5 S 15 Long-term return on assets Decrease by 0.25' S 8 S 1

$9 Health care trend rate Increase by 1' na

$26 S 26 includes only the portion of the transition revenues associ-ated with transition costs included on the balance sheet prepared under GAAR, Revenues collected for the off-bal-ance sheet costs and the return associated with these costs are recognized as income when received.

Long-Lived Assets In accordance with SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," we periodi-cally evaluate our long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impair-ment has occurred, we recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows).

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

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

Nuclear Decommissioning In accordance with SFAS 143, we recognize an ARO for the future decommissioning of our nuclear power plants. The ARO liability represents an estimate of the fair value of our current obligation related to nuclear decom-missioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. We used an expected cash flow approach (as discussed in FASB Concepts Statement No. 7, "Using Cash Flow Information and Present Value in Accounting Measurements") to meas-ure the fair value of the nuclear decommissioning ARO.

This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term.

Ircrease in Minimurn Liability Discount rate Decrease by025'

$104 na

$104 Ohio Transition Cost Amortization In connection with FirstEnergy's restructuring plan, the PUCO determined allowable transition costs based on amounts recorded on the regulatory books of the Ohio electric utilities. These costs exceeded those deferred or capitalized on FirstEnergy's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjust-ments). FirstEnergy uses an effective interest method for amortizing its transition costs, often referred to as a "mort-gage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for each respective company.

In computing the transition cost amortization, FirstEnergy Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, we evaluate goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impair-ment. When impairment is indicated we recognize a loss -

calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. Our annual review was completed in the third quarter of 2003. As a result of that review, a non-cash good-will impairment charge of $122 million was recognized in 34 ForsrEnergy Cobp. 2003

. i f',

!,1 the third quarter of 2003, reducing the carrying value of FSG. Of this amount, $117 million is reported as an operat-ing expense and $5 million is included, net of tax, in the loss from discontinued operations. The impairment charge reflects the continued slow down in the development of competitive retail markets and depressed economic condi-tions that affect the value of FSG. The'foreiasts used in our evaluations of goodwill reflect operations consistent with our general business assumptions. Unanticipated changes in those assumptions could have a significant effect on our future evaluations of goodwill. The impairment analysis includes a significant source of cash representing the EUOC recovery of transition costs as described in Note 2(D). A summary of the changes in our goodwill for the twelve months ended December 31, 2003 is shown below:

.Segments

-p Regulated Competitive.'Totall (In millions)-

t Balance as of December 31 2002

$5993

$285

$6 278 t Impairment charges

. 122) j122) 6r FSG divestitures (41)

(' (41)

Other 13 13 Balance as of December 31, 2003

$5,993

$135

$6,128 New Accounting Standards and Interpretations Adopted FIN 46 (revised December 2003), -Consolidation of Variable Interest Entities' In December 2003, the FASB issued a revised inter-pretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", referred to as FIN 46R, which requires the consolidation of a VIE by an enter-prise if that enterprise is determined to be the primary beneficiary of the VIE. As required, FirstEnergy adopted FIN 46R for interests in VIEs or potential VIEs commonly referred to as special-purpose entities effective December 31, 2003. We will adopt FIN 46R for all other types of enti-ties effective March 31, 2004.

FirstEnergy currently has transactions with entities in connection with sale and leaseback arrangements which fall within the scope of this interpretation and which meet the definition of a VIE in accordance with FIN 46R. Upon adop-tion of FIN 46R effective December 31, 2003, FirstEnergy consolidated the PNBV Capital Trust (PNBV) and the Shippingport Capital Trust (Shippingport) which were created in 1996 and 1997, respectively, to refinance debt in connec-tion with sale and leaseback transactions. Consolidation of PNBV changed the trust investment of $361 million to an investment in collateralized lease bonds of $372 million. The

$11 million increase represents the minority interest in the total assets of the trust. Prior to the adoption of FIN 46R, the assets and liabilities of Shippingport were included on a proportionate basis in the financial statements of CEI and TE. Adoption of FIN 46R did not impact FirstEnergy with respect to this trust, but did result in recording all of the trust assets and liabilities on CEI's financial statements.

As described in Note 5(G), CEI, Met-Ed and Penelec created statutory business trusts to issue trust preferred securities in the aggregate of $285 million. Application of the guidance in FIN 46R resulted in the holders of the pre-ferred securities being considered the primary beneficiaries of these trusts. Therefore, FirstEnergy has deconsolidated the trusts and recognized an equity investment in the trusts of $9 million ($3 million each for CEI, Met-Ed and Penelec) and subordinated debentures to the trusts of

$294 million ($103 million for CEI, $96 million for Met-Ed and $95 million for Penelec) as of December 31, 2003.

In August 1995, Los Amigos Leasing Company, Ltd. (Los Amigos) was formed as a consolidated subsidiary of GPU Power to own and lease to TEBSA equipment comprised of an 895 megawatt plant constructed and operated by TEBSA.

Upon application of FIN 46R, Los Amigos met the criteria of a VIE and FirstEnergy was determined not to be its primary ben-eficiary. Therefore, effective December 31, 2003 Los Amigos was deconsolidated, resulting in the removal of approximately

$243 million of total assets (primarily unbilled lease receivable) and liabilities (primarily senior and subordinated debt) from FirstEnergy's Consolidated Balance Sheets. Los Amigos was-sold as part of the TEBSA divestiture on January 30, 2004.

We have evaluated numerous entities with which the Companies have contractual, ownership,-or other financial interests and we continue to evaluate other entities that meet the deferral criteria and may be subject to consolida-tion under FIN 46R as of March 31, 2004. See Note 9 for further discussion of FIN 46R.

SFAS 150, 'Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity' In May 2003, the FASB issued SFAS 150, which estab-lishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both lia-bilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 was effective immediately for financial instruments entered into or modified after May 31, 2003 and effective at the begin-ning of the first interim period beginning after June 15, 2003 for all other financial instruments.

Upon adoption of SFAS 150, effective July 1, 2003, FirstEnergy reclassified as debt the preferred stock of con-solidated subsidiaries subject to mandatory redemption with a carrying value of approximately $18.5 million ($5.0 million for CEI and $13.5 million for Penn) as of December 31, 2003. Adoption of SFAS 150 had no impact on FirstEnergy's Consolidated Statements of Income because the preferred dividends were previously included in net interest charges and required no reclassification.

SFAS 143, "Accounting for Asset Retirement Obligations" In January 2003, FirstEnergy'implemented SFAS 143 which provides accounting standards for retirement obliga-tions associated with tangible long-lived assets. This statement requires recognition of the fair value of a liability for an asset retirement obligation in the period in which it is incurred. See "Cumulative Effect of Accounting Change" and "Earnings Effect of SFAS 143" discussed above and Notes 2(F) and 2(J) for further discussions of SFAS 143.

FirstEnergy Corp. 2003 35

CONSOLIDATED STATEMENTS OF INCOME fIn thousands, except per share amounts)

For the Years Ended December 31, Revenues:

Electric utilities Unregulated businesses Total revenues Expenses:

Fuel and purchased power Purchased gas Other operating expenses Provision for depreciation and amortization Goodwill impairment (Note 2(L1)

General taxes Total expenses Claim Settlement (Note 3)

Income Before Interest and Income Taxes Net Interest Charges:

Interest expense Capitalized interest Subsidiaries' preferred stock dividends Net interest charges Income Taxes Income Before Discontinued Operations and Cumulative Effect of Accounting Changes Discontinued operations (net of income taxes (benefit) of ($1,499,0001 and $4,635,000, respectively) (Note 2(1))

Cumulative effect of accounting change (net of income taxes (benefit) of S72,516.000 and (S5,839,000), respectively) (Note 2(J))

Net Income 2003.

$8,978,021 A 3,329,026 12,307,047 4,567,859 586,799 3,643,575 1,281,690 116,988 638,465 10,835,376 167,937 1,639,608 801,184 (31,900) 42,369 811,653 405,959 421,996 (101,379) 102,147 S 422,764 2002 (See Note 2I))

$9.165,805 2,881,543 12,047,348 3,670,844 587,860 3,725,587 1,298.290 649,898 9,932.479 2,114,869 906,970 (24,4741 75,647 958,143 524,059 632,667 2001

$5,729,036 2,270,326 7.999,362 1,421,525 820,031 2,727,794 889.550 455,340 6.314,240 1,685,122 519,131 (35,473) 72,061 555,719 474,457 654,946 (79,863)

(8,499)

$ 552.804 S 646,447 Basic Earnings Per Share of Common Stock:

Income before discontinued operations and cumulative effect of accounting changes Discontinued operations (Note 2(11)

Cumulative effect of accounting changes (Note 2(J))

Net income S

1.39 (0.33) 0.33 2.16 (0.27) 2.85 (0.03)

S Weighted Average Number of Basic Shares Outstanding 1.39 1.89 S

2.82 303,582 293,194 229,512 Diluted Earnings Per Share of Common Stock:

Income before discontinued operations and cumulative effect of accounting changes S

1.39 Discontinued operations (Note 2(1)1 (0.33)

Cumulative effect of accounting changes (Note 2(J))

0.33 Net income S

1.39 S

Weighted Average Number of Diluted Shares Outstanding 304,972 29



2.15 (0.27) 1.88 14.421 1.50 2.84 (0.03)

S 2.81 230,430 1.50 Dividends Declared Per Share of Common Stock S

1.50 S

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

36 F;rsrErve"gy Cams/ 'Q003

CONSOLIDATED BALANCE SHEETS (In thousands)

As of December 31,

.i2003 2002 ASS ETS Current Assets:

Cash and cash equivalents

$ 113,975 196,301 Receivables-Customers (less accumulated provisions of $50,247,000 and $52,514,000 respectively, for uncollectible accounts) 1,000,259 1,153,486 Other (less accumulated provisions of $18,283,000 and $12,851,000 respectively, for uncollectible accounts) 505,241, 469,606 Materials and supplies, at average cost-Owned 325,303 -

253,047 Under consignment 95,719'.

174,028 Prepayments and other

.202,814 203,630 2,243,311 2,450,098 Property, Plant and Equipment:

a: 5 746 In service 21,594,746.

20,372,224 Less - Accumulated provision for depreciation 9,105,303 8,264,075 12,489,443 12,108,149 Construction work in progress 779,479 859,016 13,268,922 12,967,165 Investments:

Nuclear plant decommissioning trusts 1,351,650 1,049,560 Investments in lease obligation bonds (Note 41 989,425 1,079,435 Letter of credit collateralization (Note 4) 277,763 277,763 Other 878,853 918,874 3,497,691 3,325,632 Deferred Charges:

Regulatory assets 7,076,923 8,464,549 Goodwill 6,127,883 6,278,072 Other 695,218 900,837 13,900,024 15,643,458

. $32,909,948

$34,386,353 LIABILITIES AND CAPITALIZATION Current Liabilities:

Currently payable long-term debt and preferred stock

$ 1,754,197--

$ 1,702,822 Short-term borrowings (Note 6) 521,540 1,092,817 Accounts payable 725,239 906,468 Accrued taxes 669,529 455,121 Lease market valuation liability 84,800; 84,800 Other 716,862 1,009,215

.4,472,167 5,251,243 Capitalization ISee Consolidated Statements of Capitalization):

Common stockholders' equity 8,289,341 -

7,050,661 Preferred stock of consolidated subsidiaries -

Not subject to mandatory redemption

-:335,123.

335,123 Subject to mandatory redemption 18,521 Subsidiary-obligated mandatorily redeemable preferred securities 409,867 Long-term debt and other long-term obligations -

Preferred stock of consolidated subsidiaries subject to mandatory redemption 16,764 Subordinated debentures to affiliated trusts 294,324 Other 9,477,978 10,872,216 18,413,530 18,686,388 Noncurrent Liabilities:

Accumulated deferred income taxes 2,178,075 2,069,682 Asset retirement obligations (Note 2(F))

1,179,493 Nuclear plant decommissioning costs 1,243,558 Power purchase contract loss liability

2,727,892 3,136,538 Retirement benefits 1,591,006 1,564,930 Lease market valuation liability 1,021,000 1,105,800 Other 1,326,785 1,328,214 10,024,251 10.448,722 Commitments, Guarantees and Contingencies (Notes 4 and 7)

$32,909,948

$34,386,353 The accompanying Notes to Consolidated Financial Statements are an integralpart of these balance sheets.

FirstEnergy Corp. 2003 37

CONSOLIDATED STATEMENTS OF CAPITALIZATION As of December 31, Common Stockholders' Equity:

Common stock, $0.10 par value -authorized 375,000,000 shares-329,836,276 and 297,636.276 shares outstanding, respectively Other paid-in capital Accumulated other comprehensive loss (Note 5(l))

Retained earnings (Note 5(A))

Unallocated employee stock ownership plan common stock-2,896,951 and 3,966,269 shares, respectively (Note 5IB))

Total common stockholders' equity Number of Shares Outstanding 2003 2002 (Dollars in thousands, except per share amounts)

'.::.003 -

2002 S 32.984

$ 29,764 7,062,825 135Z649) 1,604,385 6,120,341 (656,148) 1,634.981 (78,277) 7,050.661 (58,204) 8,289,341 Optional Redemption Price Per Share Aggregate Preferred Stock of Consolidated Subsidiaries (Note 5(0)):

Ohio Edison Company Cumulative, S1 00 par value-Authorized 6,000,000 shares Not Subject to Mandatory Redemption:

3.90%

4.40%

4.44%

4.56%

152,510 176,280 136,560 144,300 152.510 176,280 136,560 144,300 609,650 S103.63 108.00 103.50 103.38 S15.804 19.038 14,134 14,917 S63,893 15,251 17,628 13,656 14,430 15,251 17,628 13,656 14,430 Total Not Subject to Mandatory Redemption 609,650 Pennsylvania Power Company Cumulative, $100 par value-Authorized 1,200.000 shares Not Subject to Mandatory Redemption:

4.24%

4.25%

4.64%

7.75%

60,965 4,000 4,105 6,000 25,000 39,105 60,965 40,000 41,049 60,000 250,000 40,000 41,049 60,000 250,000 391,049 103.13 105.00 102.98 100.00 S4,125 4,310 6,179 25,000

$39,614 4,000 4,105 6,000 25,000 39,105 Total Not Subject to Mandatory Redemption 391,049 Subject to Mandatory Redemption (Note 5(F)):

7.625%'

Redemption Within One Year*

Total Subject to Mandatory Redemption*

Cleveland Electric Illuminating Company Cumulative, without par value-Authorized 4,000,000 shares Not Subject to Mandatory Redemption:

S7.40 Series A Adjustable Series L 142,500 142,500

.1 I - - -

14,250 1750) 13,500 500,000 500,000 474,000 474,000 101.00 100.00

$50,500 47,400

$97,900 50,000 46,404 96,404 50,000 46,404 96,404 Total Not Subject to Mandatory Redemption 974,000 974,000 Subject to Mandatory Redemption (Note 5F)):

S7.35 Series C*

Redemption Within One Year*

Total Subject to Mandatory Redemption' 60,000 60,000 6,021 (1,000) 5,021 38 rstEn:',v Cci;-.o00

CONSOLIDATED STATEMENTS OF CAPITALIZATION (CONT'D)

(Dollars in thousands, except per share amounts) 2002 Number of Shares Outstanding Optional Redemption Price As of December 31, 2003 2002 Per Share Aggregate Preferred Stock of Consolidated Subsidiaries (Cont'd)

Toledo Edison Company Cumulative, $100 par value-Authorized 3,000,000 shares Not Subject to Mandatory Redemption:

$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 Not Subject to Mandatory Redemption:

$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 I 1 95,000 95,000 Total Not Subject to Mandatory Redemption 4,110,000 4,110,000 Jersey Central Power & Light Company Cumulative, $100 stated value-Authorized 15,600,000 shares Not Subject to Mandatory Redemption:

4.00% Series 125,000 125,000 Subsidiary-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust or Limited Partnership Holding Solely Subordinated Debentures of Subsidiaries (NOTE 5(G)):

Cleveland Electric Illuminating Co.

Cumulative, $25 stated value-Authorized 4,000,000 shares 9.00%

4,000,000 Jersey Central Power & Light Co.

Cumulative, $25 stated value-Authorized 5,000,000 shares 8.56%

5,000,000 Metropolitan Edison Co.

Cumulative, $25 stated value-Authorized 4,000,000 shares 7.35%

4,000,000 Pennsylvania Electric Co.

Cumulative, $25 stated value-Authorized 4,000,000 shares 7.34%

4,000,000 106.50

$130,840

.126,000 126,000

$13,313 12,649.

12,649 100,000 125,244 92,409 92,214 FirstEnergy Corp. 2003 39

CONSOLIDATED STATEMENTS OF CAPITALIZATION (CONT'D)

Long-Term Debt (Note 5(E)) (Interest rates reflect weigh I

First Mortgage Bonds lted average rates)

As of December 31, Ohio Edison Co. -

Due 2003-2008 Due 2009-2013 Due 2014-2018 Due 2019-2023 Due 2024-2028 Due 2029-2033 Total-Ohio Edison Cleveland Electric Illuminating Co. -

Due 2003-2008 Due 2009-2013 Due 2014-2018 Due 2019-2023 Due 2024-2028 Due 2029-2033 Total-Cleveland Electric Toledo Edison Co. -

Due 2003-2008 Due 2009-2013 Due 2019-2023 Due 2024-2028 Due 2029-2033 Total-Toledo Edison Pennsylvania Power Co. -

Due 2003-2008 Due 2009-2013 Due 2014-2018 Due 2019-2023 Due 2024-2028 Due 2029-2033 Total-Penn Power Jersey Central Power & Light Co. -

Due 2003-2008 Due 2009-2013 Due 2014-2018 Due 2019-2023 Due 2024-2028 Due 2029-2033 Due 2034-2038 Due 2039-2043 Total-Jersey Central Metropolitan Edison Co. -

Due 2003-2008 Due 2009-2013 Due 2014-2018 Due 2019-2023 Due 2024-2028 Due 2029-2033 Due 2034-2038 Due 2039-2043 Total-Metropolitan Edison 2003 2002 Secured N 2003 6.88X

$80,000 7.99' 80.000 6.86':

125,000 9.001 125.000 7.88' 145,000 145,000 6.88' 39.370 9.74' 4,870 9.74' 4.870 8.37x 34.757 83.867 7.01' 251.575 7.13' 4,725 7.10' 12.200 7.75% 205,000 7.18' 200,000 673,500 6.44x 128,265 6.10' 28,500 5.95%

13,690 170,455

$230,000 5.62'

$227,761 6.98' 2,752 5.01' 59.000 219,460 7.01' 60,443 5.38' 13,522 3.10' 308,012 449,460 671,490 525.000 6.78'1 470,905 7,43%

151,580 6.03' 412,630 150,000 6.67' 186,660 7.59' 148.843 1.45' 30,000 675,000 1,400,618 lotes 2002 I S189,264 2,753 59.000 60,443 13.522 308,012 632,994 3.95 5.4E (In thousands)

Unsecured Notes Total 2003 2002 2003 2002 5x

$526,725 S441,725 55 150,000 676.725 441.725 S1.428.215

$1,524,179 ax 27,700 27.700 378,700 78,700 103,093 509,493 106.400 2.035,111 2.308.688 680,205 151,580 300,000 216,660 148.843 30.000 1,527.288 5.5E 5.72 9.0c 178,725 7.51' 7.92' 5.90' 1.43' 178.725 80,344 2.59' 4,870 5.40' 4,870 4.001 34.757 3.62' 5.796 5.95' 124,841 442,989 5.75' 4,725 5.64' 12,200 5.34%

241.586 200,000 901,500 208,700 5.79' 4.75' 208.500 13,690 430,890 100,000 144,500 13,851 51,100 309.451 10,300 1,000 45.325 27.182 22,934 238 106,979 217,336 130.024 248,841 596.201 150,000 250,000 400.000 229.700 4.88' 10.00' 164.700 13,851 51.100 459,351 10,300 3.40' 1,000 45,325 27,182 22,934 238 106,979 241,135 7.69g 130,024 7.69' 98,841 7.69%

7.69%

7.69%1 7.69%i 7.69' 7.69' 470,000 150,000 7.69' 7.69' 7.69' 7.69' 7.69' 7.69' 7.69%

7.98%

150.000 85,250 85,250 19,700 19,700 i

99 144 208 302 437 633 917 228 2,968 199 288 417 603 874 1,266 1,834 96,166 101,647 91,130 730 91,860 539,701 19.700 19.700 210,546 115 144 208 302 437 633 917 228 2,984 1,272.609 729,936 251,520 1,374,484 230 288 417 604 874 1,266 1,834 455 5.968 672,102 586,858 !

40 FirstEnergy Corp 2003

CONSOLIDATED STATEMENTS OF CAPITALIZATION (CONT'D)

Long-Term Debt (Interest rates reflect weighted average rates) (Cont'd)

(in thousands) i First Mortgage Bonds Secured Notes Unsecured Notes Total As of December 31, 2003 2002 2003 2002 2003 2002 0

2002 Pennsylvania Electric Co. -

Due 2003-2008 6.13

$3,700

$3905 5.86%

$133,099

$133,115 Due 2009-2013 5.35%

24,310 24,310 6.55%

135,144 135,144

§ -

Due 2014-2018 7.69%

208 208 Due 2019-2023 5.80%

20,000 20,000 6.63%

125,302 125,302 Due 2024-2028 6.05%

25,000 25,000 7.69%

437 437 Due 2029-2033 7.69%

633 633 Due 2034-2038 7.69%

917 917 Due 2039-2043 7.98%

95,748 228 Total-Pennsylvania Electric 73,010 73,215 491,488 395,984 564,498 469,199 FirstEnergy Corp. -

Due 2003-2008 5.58% 1,570,000 1,695,000 Due 2009-2013

-6.45%

1,500,000 1,500,000 C

Due 2029-2033 7.38% 1,500,000 1,500,000 Total-FirstEnergy 4,570,000 4,695,000 4,570,000 4,695,000 Bay Shore Power 6.24%

140,600 143,200 V

140,600 143,200 Facilities Services Group 6.72v 7,754 13,205 7,754 13,205 FirstEnergy Generation 5.00%

15,000 15,000

• - *15,000 15,000 FirstEnergy Properties 7.89%

9,438 9,679 9,438 9,679 Warrenton River Terminal 5.00%

410 634 410 634 First Communications 6.21%

5,407

<.5,407, GPU Capital 5.78%

101,467 101,467 GPU Power 7.14%

174,760 11.87%

67,372 242,132 Total

$1,350,832

$2,833,631

$3,642,941 $3,688,090

$6,477,678 $5,943,460 11,471,451 12,465,181 Preferred stock subject to mandatory redemption 18,514 Capital lease obligations 13,313 15,761 Net unamortized premium on debt 39,985 92,346 Long-term debt due within one year*

(1,754,197)

(1,701,0721 Total long-term debt*

9,789,066 10,872,216 Total Capitalization*

s18,413,530 $18,686,388 The December3, 2003 balance for PreferredStock Subject to Mandatory Redemption is classified as debt under SFAS 150 (see Note 91.

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

zI FirstEnergy Corp. 2003 41

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (ollars in thousands)

Comprehensive Income Number Par of Shares Value 224,531,580 $22,453 73,654,696 7,366 Other Paid-In Capital

$3,531,821 2,586,097 Accumulated Other Comprehensive' Retained Income (Loss)

Earnings 593

$1,209,991 Unallocated ESOP Common Stock

$(111,732)

Balance, January 1, 2001 GPU acquisition Net income Minimum liability for unfunded retirement benefits, net of S(182,000) of income taxes Unrealized loss on derivative hedges.

net of S(1 16,521,000) of income taxes Unrealized gain on investments, net of

$56,000 of income taxes Currency translation adjustments, net of

$1,000) of income taxes Comprehensive income Reacquired common stock Allocation of ESOP shares Cash dividends on common stock Balance, December 31, 2001 Net income Minimum liability for unfunded retirement benefits, net of V(316,681,000) of income taxes Unrealized gain on derivative hedges, net of $37,458,000 of income taxes Unrealized loss on investments, net of S(3,796,000) of income taxes Currency translation adjustments

$646,447 646,447 (268)

(169,408) 81 (1)

S476,851 (550,000)

! 297,636,276 5552,804 (449,615) 59,187 (268)

(169,408) 81 (1)

(55)

(15,253) 10,595 29,764 6,113,260 (169,003)

(334,633) 1,521,805 552,804 14,505 (97,227)

(449.615) 59,187 (5,269)

(91.448)

(5,269)

(91,448)

Comprehensive income Stock options exercised Allocation of ESOP shares Cash dividends on common stock Balance, December 31, 2002 Net income Minimum liability for unfunded retirement benefits, net of $101,950,000 of income taxes Unrealized loss on derivative hedges, net of $(241,000) of income taxes Unrealized gain on investments, net of $53,451,000 of income taxes Currency translation adjustments Comprehensive income Stock options exercised Common stock issued Allocation of ESOP shares Cash dividends on common stock

$ 65,659 297,636,276 29.764 (8,169) 15,250 6,120,341 (656,148)

(439,628) 1,634,981 422,764 18,950 (78,277)

$422,764 144,236 (347) 68,162 91,448

$726,263 144,236 (347) 68,162 91,448 (3,502) 32,200,000 3,220 930,918 15,068 20,073 (453,360)

Balance, December 31, 2003 329,836,276 S32,984

$7,062,825

$(352,6491 S1,604,385 S (58,204)

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

42 FrstEnei,'y Corp X003

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, 2001 12,324,699

$648,395 5,177,216

$246,571 GPU acquisition 125,000 12,649 13,515,001 365,151 Issues-9.00%

Series 4,000,000 100,000 Redemptions-8.45%

Series (50,000)

(5,000)

$7.35 Series C (10,000)

(1,000)

$88.00 Series R (50,000)

(50,000)

$91.50 Series Q (10,716)

(10,716)

$90.00 Series S (18,750)

(18,750)

Amortization of fair market value adjustments-

$7.35 Series C (11)

$88.00 Series R (1,128)

$90.00 Series S (668)

Balance, December 31, 2001 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)

(28,9511 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*

' The December 31, 2003 balance for Preferred Stock Subject to Mandatory Redemption is classified as debt under SFAS 150 (see Note 9).

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

FirstEnergy Corp. 2003 43

CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousandsJ For the Years Ended December 31, Cash Flows From Operating Activities:

Net Income Adjustments to reconcile net income to net cash from operating activities:

Provision for depreciation and amortization Nuclear fuel and capital lease amortization Other amortization and accruals, net (Note 2(M))

Deferred costs recoverable as regulatory assets Goodwill impairment (Note 2(1))

Disallowed purchased power costs Investment impairments (Note 3)

Deferred income taxes, net Investment tax credits, net Cumulative effect of accounting change Loss from discontinued operations (see Note 2111)

Receivables Materials and supplies Accounts payable Deferred lease costs Other (Note 101 Net cash provided from operating activities Cash Flows From Financing Activities:

New Financing-Common stock Preferred stock Long-term debt Short-term borrowings, net Redemptions and Repayments-Common stock Preferred stock Long-term debt Short-term borrowings, net Common Stock Dividend Payments Net cash provided from (used for) financing activities Cash Flows From Investing Activities:

GPU acquisition, net of cash Property additions Proceeds from sale of assets Avon cash and cash equivalents (Note 3)

Net assets held for sale Cash investments (Note 2(M))

Other (Note 10)

Net cash used for investing activities Net increase (decrease) in cash and cash equivalents Cash and cash equivalents at beginning of year Cash and cash equivalents at end of year*

2003 >-i S 422,764 1,281,690 66,072 (16,278)

(216,829) 116,988 152,500 43,803 80,043 (26,404)

(174,663) 101,379 66,311 5,399 (169,652)

(119,398) 338,737 1,952,462 934,138 1,027,312 2002 S 552,804 1,298,290 80,507 (16,593)

(362,956) 50,000 103,293 (26,507) 79,863 173,392)

(29,134) 218,226 (84,800) 125,686 1,915,287 668,676 478,520 (522,223)

(1,308,814)

(439,628)

(1,123,469) 2001

$ 646,447 889,550 98,178 (11,927)

(31,893) 31,625 (22,545) 14,338 53,099 (50,052)

(84,572)

(250.5641 1,281,684 96,739 4,338,080 (15,308)

(85,466)

(394,017)

(1,641,484)

(334,633) 1.963.911 (127,087)

(2,128,567)

(575,391)

(453,360)

(1,322,955)

(856,316) 78,743 52,884 12,856 (711,833)

(82,326) 196,301 (2,013,218)

(997,723)

(852,449) 155,034 31,326 (31,326) 81,349 24,518 i

(54,355)

(233.526)

(815,6951 (3,074,675)

(23,8771 170,920 220,178 49,258 S 196.301 S 220,178 S 113,975 Supplemental Cash Flows Information:

Cash Paid During the Year-Interest (net of amounts capitalized)

$ 730,277 S 881,515 Income taxes

$ 161,915 S 389,180

' 2001 excludes amounts in 'Assets Pending Sale' on the Consolidated Balance Sheet as of December31, 2001.

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

S 425,737 S 433,640 44 r',s.E'rnvy Co°'!. -

3'

CONSOLIDATED STATEMENTS OF TAXES (In thousands)

For the Years Ended December 31, 2002 2001 General Taxes:

Real and personal property

-1 83,694

$ 218,683

$ 176,916 State gross receipts*

130,244 132,622 102,335 Kilowatt-hour excise*

228,216 - J,-

219,970 117,979 Social security and unemployment 68,019 46,345 44,480 Other 28,292-32,709 13,630 Total general taxes

_$ 5,638,465

$ 650,329

$ 455,340 Provision For Income Taxes:

Currently payable-Federal

$ 306,347

$ 326,417

$ 375,108 State 118,155 104,867 84,322 Foreign (1.165) 20,624 108

-423.337 451,908 459,538 Deferred, net-Federal 71.910 81,934 37,888 State

-8,133 7,759 (6,177)

Foreign 13,600 (86) 80,043.,i 103,293 31,625 Investment tax credit amortization 26,404) -

(26,507)

(22,545)

Total provision for income taxes

$ 528,694

$ 468,618 Reconciliation of Federal Income Tax Expense at Statutory Rate To Total Provision for Income Taxes:

Book income before provision for income taxes

$ 899,740

$1,081,498

$1,115,065 Federal income tax expense at statutory rate

$ 314,909 -

$ 378.524

$ 390,273 Increases (reductions) in taxes resulting from-Amortization of investment tax credits (26,404)

(26,507)

(22,545)

State income taxes, net of federal income tax benefit

'82,088 73,207 50,794 Amortization of tax regulatory assets

'31,909 29,296 30,419 Amortization of goodwill 18,416 Preferred stock dividends 7,202 13,634 19,733 Reserve for foreign operations 44,305 48,587 Other, net so 22,967 11,953 (18,472)

Total provision for income taxes

-S 476,976

$ 528.694

$ 468,618 Accumulated Deferred Income Taxes at December 31:

Property basis differences

$2,293,209

$2,052,594

$1,996,937 Customer receivables for future income taxes 139,335 144,073 178,683 Regulatory transition charge 1.084 871 1,408,232 1,289,438 Deferred sale and leaseback costs (95,474)

(99,647)

(77,099)

Nonutility generation costs (221,063)

(228,476)

(178,393)

Unamortized investment tax credits (70,054)

(78,227)

(86,256)

Other comprehensive income (243.743)

(398,883)

(115,395)

Lease market valuation liability

(-*455,074)

(490,698)

Other (Note 10)

(253,932)

(239,286)

(323,696)

Net deferred income tax liability**

$2,178,075

$2,069,682

$2,684,219 Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income.

"2001 excludes amounts in 'Liabilities Relatedto Assets Pending Sale'on the ConsolidatedBalance Sheetas ofDecember3l, 2001.

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

FirstEnergy Corp. 2003 45

NOTES TO CONSOLIDATED FINANCIAL STATEIlMENTS

1. GENERAL:

The consolidated financial statements include FirstEnergy Corp., a registered public utility holding company, and its principal electric utility operating subsidiaries, Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), Pennsylvania Power Company (Penn), The Toledo Edison Company (TE), American Transmission Systems, Inc. (ATSI), Jersey Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). ATSI owns and operates FirstEnergy's transmission facilities within the serv-ice areas of OE, CEI and TE (Ohio Companies) and Penn. The operating utility subsidiaries are referred to throughout as "Companies." FirstEnergy's 2001 results include the results of JCP&L, Met-Ed and Penelec from the period they were acquired on November 7, 2001 through December 31, 2001. The consolidated financial statements also include FirstEnergy's other principal subsidiaries: FirstEnergy Solutions Corp. (FES); FirstEnergy Facilities Services Group, LLC (FSG); MYR Group, Inc.; MARBEL Energy Corporation; First Communications, LLC; FirstEnergy Nuclear Operating Company (FENOC); GPU Capital, Inc.; GPU Power, Inc.; and FirstEnergy Service Company (FESC). FES provides energy-related products and services and, through its FirstEnergy Generation Corp. (FGCO) subsidiary, operates FirstEnergy's nonnuclear generation business. FENOC operates the Companies' nuclear generating facilities. FSG is the parent company of several heating, ventilating, air conditioning and energy management companies, and MYR is a utility infra-structure construction service company. MARBEL holds FirstEnergy's interest in Great Lakes Energy Partners, LLC.

First Communications provides local and long-distance phone service. GPU Capital owned and operated electric distribution systems in foreign countries and GPU Power owned and operated generation facilities in foreign countries. FESC pro-vides legal, financial and other corporate support services to affiliated FirstEnergy companies.

The Companies follow the accounting policies and practices prescribed by the Securities and Exchange Commission (SEC), the Public Utilities Commission of Ohio (PUCO), the Pennsylvania Public Utility Commission (PPUC),

the New Jersey Board of Public Utilities (NJBPU) and the Federal Energy Regulatory Commission (FERC). The prepara-tion of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make periodic estimates and assumptions that affect the reported amounts of assets, lia-bilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. FirstEnergy's consolidated financial statements for the year ended December 31, 2002 were restated to reflect a change in the method of amortizing costs being recovered under the Ohio transition plan, recog-nition of above-market liabilities of certain leased generation facilities, Ohio transition plan regulatory assets and goodwill.

Certain prior year amounts have been reclassified to conform with the current year presentation, as described further in Notes 2(F), 2(l) and 8.

2.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES:

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

(B) Earnings Per Share-Basic earnings per share are computed using the weighted average of actual common shares outstanding as the denominator. Diluted earnings per share reflect the weighted average of actual common shares outstanding plus the potential additional common shares that could result if dilutive securities and agreements were exercised in the denominator. In 2003, 2002 and 2001, stock-based awards to purchase shares of common stock totaling 3.3 million, 3.4 million and 0.1 million, respectively, were exclud-ed from the calculation of diluted earnings per share of common stock because their exercise prices were greater than the average market price of common shares during the period. The numerators for the calculations of basic and diluted earnings per share are Income Before Discontinued Operations and Cumulative Effect of Accounting Changes and Net Income. The following table reconciles the denomi-nators for basic and diluted earnings per share:

Denominator for Earnings Years Ended December 31, per Share Calculations 2003 2002 2001

{In thousands)

Denominator for basic earnings per share (weighted average shares actually outstanding)

Assumed exercise of dilutive securities or agreements to issue common stock Denominator for diluted earnings per share 303,582 293,194 229.512 1,390 1,227 918 304.972 294,421 230,430 (C) Revenues-The Companies' principal business is providing electric service to customers in Ohio, Pennsylvania and New Jersey. The Companies' retail customers are metered on a cycle basis. Revenue is recognized for unbilled electric service provided through the end of the year. See Note 10

- Other Information for discussion of reporting of inde-pendent system operator (ISO) transactions.

Receivables from customers include sales to residential, commercial and industrial customers and sales to wholesale customers. There was no material concentration of receiv-ables as of December 31, 2003 or 2002, with respect to any particular segment of FirstEnergy's customers. Total cus-tomer receivables were $1.0 billion (billed - $664 million and unbilled - $336 million) and $1.2 billion (billed - $808 million and unbilled - $345 million) as of December 31, 2003 and 2002, respectively.

CEI and TE sell substantially all of their retail cus-46 C,'5

,:e t;::,.

7.3

tomers' receivables to Centerior Funding Corporation (CFC), a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a "qualified special purpose entity") under Statement of Financial Accounting Standards (SFAS) No. 140 "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities," under an asset-backed securitization agreement.

Transfers are made in return for an interest in the trust (19% as of December 31, 2003), which is stated at fair value, reflecting adjustments for anticipated credit losses.

l The average collection period for billed receivables is 28 days. Given the short collection period after billing, the fair value of CFC's interest in the trust approximates the stated value of its retained interest in underlying receivables after adjusting for anticipated credit losses. Accordingly, subse-quent measurements of the retained interest under SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," (as an available-for-sale financial instru-ment) result in no material change in value. Sensitivity analyses reflecting 10% and 20% increases in the rate of anticipated credit losses would not have significantly affected FirstEnergy's retained interest in the pool of receivables through the trust. Of the $250 million sold to the trust and outstanding as of December 31, 2003, FirstEnergy's retained interests in $48 million of the receiv-ables are included as other receivables on the Consolidated Balance Sheets. Accordingly, receivables recorded on the Consolidated Balance Sheets were reduced by approxi-mately $202 million due to these sales. Collections of receivables previously transferred to the trust and used for the purchase of new receivables from CFC during 2003 totaled approximately $2.4 billion. CEI and TE processed receivables for the trust and received servicing fees of approximately $3.6 million in 2003. Expenses associated with the factoring discount related to the sale of receiv-ables were $3.5 million, $4.7 million and $12.0 million in 2003, 2002 and 2001.

(D) Regulatory Matters-In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation contain similar provisions which are reflected in the Companies' respective state regulatory plans:

• allowing the Companies' electric customers to select their generation suppliers;

• establishing provider of last resort (PLR) obligations to customers in the Companies' service areas;

• allowing recovery of transition costs (sometimes referred to as stranded investment);

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

• deregulating the Companies' electric generation businesses;

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

• requiring corporate separation of regulated and unregulated business activities.

Ohio In July 1999, Ohio's electric utility restructuring legisla-tion, which allowed Ohio electric customers to select their generation suppliers beginning January 1, 2001, was signed into law. Among other things, the legislation provid-ed for a 5% reduction on the generation portion of residential customers' bills and the opportunity to recover transition costs, including regulatory assets, from January 1, 2001 through December 31, 2005 (market development period). The period for the recovery of regulatory assets only can be extended up to December 31, 2010. The recovery period extension is related to the customer shop-ping incentives recovery discussed below. The PUCO was authorized to determine the level of transition cost recov-ery, as well as the recovery period for the regulatory assets portion of those costs, in considering each Ohio electric utility's transition plan application.

In July 2000, the PUCO approved FirstEnergy's transi-tion plan for OE, CEI and TE (Ohio Companies) as modified by a settlement agreement with major parties to the transi-tion plan. The application of SFAS 71, "Accounting for the Effects of Certain Types of Regulation" to OE's generation business and the nonnuclear generation businesses of CEI and TE was discontinued with the issuance of the PUCO transition plan order, as described further below. Major pro-visions of the settlement agreement consisted of approval of recovery of generation-related transition costs as filed of

$4.0 billion net of deferred income taxes (OE-$1.6 billion, CEI-$1.6 billion and TE-$0.8 billion) and transition costs related to regulatory assets as filed of $2.9 billion net of.

deferred income taxes (OE-$1.0 billion, CEI-$1.4 billion and TE-$0.5 billion), with recovery through no later than 2006 for OE, mid-2007 for TE and 2008 for CEI, except where a longer period of recovery is provided for in the settlement agreement. The generation-related transition costs include $1.4 billion, net of deferred income taxes, (OE-$1.0 billion, CEI-$0.2 billion and TE-$0.2 billion) of impaired generating assets recognized as regulatory assets as described further below, $2.4 billion, net of deferred income taxes, (OE-$1.2 billion, CEI-$0.4 billion and TE-$0.8 billion) of above market operating lease costs and

$0.8 billion, net of deferred income taxes, (CEI-$0.5 billion and TE-$0.3 billion) of additional plant costs that were reflected on CEI's and TE's regulatory financial statements.

Also as part of the settlement agreement, FirstEnergy gives preferred access over its subsidiaries to nonaffiliated marketers, brokers and aggregators to 1,120 megawatts (MW) of generation capacity through 2005 at established prices for sales to the Ohio Companies' retail customers.

Customer prices are frozen through the five-year market development period, which runs through the end of 2005, except for certain limited statutory exceptions, including the 5% reduction referred to above. In February 2003, the Ohio Companies were authorized increases in annual revenues aggregating approximately $50 million (OE-$41 million, CEI-$4 million and TE-$5 million) to recover their higher tax costs resulting from the Ohio deregulation legislation.

FirstEnergy's Ohio customers choosing alternative suppliers receive an additional incentive applied to the shopping credit (generation component) of 45% for resi-dential customers, 30% for commercial customers and 15% for industrial customers. The amount of the incentive is deferred for future recovery from customers. Subject to approval by the PUCO, recovery will be accomplished by extending the respective transition cost recovery period.

On October 21, 2003, the Ohio Companies filed an application with the PUCO to establish generation service FirstEnergy Corp. 2003 47

rates beginning January 1, 2006, in response to expressed concerns by the PUCO about price and supply uncertainty following the end of the market development period. The filing included two options:

• A competitive auction, which would establish a price for generation that customers would be charged dur-ing the period covered by the auction, or

• A Rate Stabilization Plan, which would extend cur-rent generation prices through 2008, ensuring adequate supply and continuing our support of ener-gy efficiency and economic development efforts.

Under the first option, an auction would be conducted to secure generation service, including PLR responsibility, for the Ohio Companies' customers. Beginning in 2006, customers would pay market prices for generation as determined by the auction.

Under the Rate Stabilization Plan option, customers would have price and supply stability through 2008 - three years beyond the end of the market development period -

as well as the benefits of a competitive market. Customer benefits would include: customer savings by extending the current five percent discount on generation costs and other customer credits; maintaining current distribution base rates through 2007; market-based auctions that may be conducted annually to ensure that customers pay the lowest available prices; extension of the Ohio Companies' support of energy-efficiency programs and the potential for continuing the program to give preferred access to non-affiliated entities to generation capacity if shopping drops below 20%. Under the proposed plan, we are requesting:

• Extension of the transition cost amortization period for OE from 2006 to 2007; for CEI from 2008 to 2009 and for TE from mid-2007 to 2008;

• Deferral of interest costs on the accumulated shopping incentives and other cost deferrals as new regulatory assets; and

• Ability to initiate a request to increase generation rates under certain limited conditions.

On January 7, 2004, the PUCO staff filed testimony on the proposed rate plan generally supporting the Rate Stabilization Plan as opposed to the competitive auction proposal. Hearings began on February 11, 2004. On February 23, 2004, after consideration of PUCO Staff com-ments and testimony as well as those provided by some of the intervening parties, FirstEnergy made certain modifica-tions to the Rate Stabilization Plan. A decision is expected from the PUCO in the Spring of 2004.

On November 25, 2003. the PUCO ordered FirstEnergy to file a plan with the PUCO no later than March 1, 2004, illustrating how FirstEnergy will address certain problems identified by the U.S./Canada Power Outage Task Force (in connection with the August 14, 2003 regional power outage) and addressing how FirstEnergy proposes to upgrade its control room computer hardware and software, improve its control room training procedures and improve the training of control room opera-tors to ensure that similar problems do not occur in the future. The PUCO, in consultation with the North American Electric Reliability Council, will review the plan before determining the next steps in the proceeding.

New Jersey JCP&L's 2001 Final Decision and Order (Final Order) with respect to its rate unbundling, stranded cost and restructuring filings confirmed rate reductions set forth in its 1999 Summary Order, which had been in effect at increas-ing levels through July 2003. The Final Order also confirmed the establishment of a non-bypassable societal benefits charge (SBC) to recover costs which include nuclear plant decommissioning and manufactured gas plant remediation, as well as a non-bypassable market transition charge (MTC) primarily to recover stranded costs. The NJBPU has deferred making a final determination of the net proceeds and strand-ed costs related to prior generating asset divestitures until JCP&L's request for an Internal Revenue Service (IRS) ruling regarding the treatment of associated federal income tax benefits is acted upon. Should the IRS ruling support the return of the tax benefits to customers, there would be no effect to FirstEnergy's or JCP&L's net income since the con-tingency existed prior to the merger and there would be an adjustment to goodwill.

In addition, the Final Order provided for the ability to securitize stranded costs associated with the divested Oyster Creek Nuclear Generating Station. Under NJBPU authorization in 2002, JCP&L issued through its wholly owned subsidiary, JCP&L Transition Funding LLC, $320 million of transition bonds (recognized on the Consolidated Balance Sheet) which securitized the recovery of these costs and which provided for a usage-based non-bypass-able transition bond charge (TBC) and for the transfer of the bondable transition property to another entity.

Prior to August 1, 2003, JCP&L's PLR obligation to provide basic generation service (BGS) to non-shopping cus-tomers was supplied almost entirely from contracted and open market purchases. JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under nonutility generation (NUG) agreements exceed amounts collected through BGS and MTC rates. As of December 31, 2003, the accumulated deferred cost bal-ance totaled approximately $440 million, after the charge discussed below. The NJBPU also allowed securitization of JCP&L's deferred balance to the extent permitted by law upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. There can be no assurance as to the extent, if any, that the NJBPU will permit such securitization.

Under New Jersey transition legislation, all electric dis-tribution companies were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003. JCP&L's two August 2002 rate filings requested increases in base electric rates of approximately S98 million annually and requested the recovery of deferred costs that exceeded amounts being recovered under the current MTC and SBC rates; one pro-posed method of recovery of these costs is the securitization of the deferred balance. This securitization methodology is similar to the Oyster Creek securitization discussed above. On July 25, 2003, the NJBPU announced its JCP&L base electric rate proceeding decision, which reduced JCP&L's annual revenues by approximately $62 million effective August 1, 2003. The NJBPU decision also provided for an interim return on equity of 9.5% on JCP&L's rate base for six to twelve months. During that period, JCP&L will initiate another proceeding to request recovery 48 FirstEnergy Corp 2003

of additional costs incurred to enhance system reliability. In that proceeding, the NJBPU could increase the return on equity to 9.75% or decrease it to 9.25%, depending on its assessment of the reliability of JCP&L's service. Any reduc-tion would be retroactive to August 1, 2003. The net revenue decrease from the NJBPU's decision consists of a

$223 million decrease in the electricity delivery charge, a

$111 million increase due to the August 1 2003 expiration of annual customer credits previously mandated by the New Jersey transition legislation, a $49 million increase in the MTC tariff component, and a net $1 million increase in the SBC charge. The MTC allows for the recovery of $465 million in deferred energy costs over the next ten years on an interim basis, thus disallowing $153 million of the $618 million provided for in a preliminary settlement agreement between certain parties. As a result, JCP&L recorded charges to net income for the year ended December 31, 2003, aggregating $185 million ($109 million net of tax) con-sisting of the $153 million of disallowed deferred energy costs and other regulatory assets. JCP&L filed a motion for rehearing and reconsideration with the NJBPU on August 15, 2003 with respect to the following issues: (1) the disal-lowance of the $153 million deferred energy costs; (2) the reduced rate of return on equity; and (3) $42.7 million of dis-allowed costs to achieve merger savings. On October 10, 2003, the NJBPU held the motion in abeyance until the final NJBPU decision and order which is expected to be issued in the first quarter of 2004.

JCP&L's BGS obligation for the twelve month period beginning August 1, 2003 was auctioned in February 2003.

The auction covered a fixed price bid (applicable to all resi-dential and smaller commercial and industrial customers) and an hourly price bid (applicable to all large industrial cus-tomers) process. JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balances. The BGS auction for the subsequent period was completed in February 2004. The NJBPU adjusted the generation compo-nent of JCP&L's retail rates on August 1, 2003 to reflect the results of the BGS auction.

Pennsylvania The PPUC authorized 1998 rate restructuring plans for I

Penn, Met-Ed and Penelec. In 2000, the PPUC disallowed a portion of the requested additional stranded costs above those amounts granted in Met-Ed's and Penelec's 1998 rate restructuring plan orders. The PPUC required Met-Ed and Penelec to seek an IRS ruling regarding the return of certain unamortized investment tax credits and excess deferred income tax benefits to customers. Similar to JCP&L's situation, if the IRS ruling ultimately supports returning these tax benefits to customers, there would be no effect to FirstEnergy's, Met-Ed's or Penelec's net income since the contingency existed prior to the merger and would be an adjustment to goodwill.

In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties in the combined merg-er and rate relief proceedings which approved the FirstEnergy/

GPU merger and provided PLR deferred accounting treatment for energy costs, permitting Met-Ed and Penelec to defer, for future recovery, energy costs in excess of amounts reflected in their capped generation rates retroactive to January 1, 2001. This PLR deferral accounting procedure was later denied in a February 2002 Commonwealth Court of N

1

& i Pennsylvania decision. The court decision also affirmed the PPUC decision regarding approval of the merger, remanding the decision to the PPUC only with respect to the issue of merger savings. FirstEnergy established reserves in 2002 for Met-Ed's and Penelec's PLR deferred energy costs which aggregated $287.1 million, reflecting the potential adverse impact of the then pending Pennsylvania Supreme Court deci-sion whether to review the Commonwealth Court decision.

As a result, FirstEnergy recorded in 2002 an aggregate non-cash charge of $55.8 million ($32.6 million net of tax) to income for the deferred costs incurred subsequent to the merger. The reserve for the remaining $231.3 million of deferred costs increased goodwill by an aggregate net of tax amount of $135.3 million.

On April 2, 2003, the PPUC remanded the issue relat-ing to merger savings to the Office of Administrative Law for hearings, directed Met-Ed and Penelec to file a position paper on the effect of the Commonwealth Court order on the Settlement Stipulation and allowed other parties to file responses to the position paper. Met-Ed and Penelec filed a letter with the Administrative Law Judge (ALJ) on June 11, 2003, voiding the Stipulation in its entirety and reinstat-ing Met-Ed's and Penelec's restructuring settlement previously approved by the PPUC.

On October 2, 2003, the PPUC issued an order conclud-ing that the Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The PPUC directed Met-Ed and Penelec to file tariffs within thirty days of the order to reflect the competitive transition charge (CTC) rates and shopping credits that were in effect prior to the June 21, 2001 order to be effective upon one day's notice. In response to that order, Met-Ed and Penelec filed these supplements to their tariffs to become effective October 24, 2003.

On October 8, 2003, Met-Ed and Penelec filed a petition for clarification relating to the October 2,-2003 order on two issues: to establish June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that the ordered accounting treatment regarding the CTC rate/shopping credit swap should follow the ratemaking, and that the PPUC's findings would not impair their rights to recover all of their stranded costs. On October 9, 2003, ARIPPA (an intervenor in the pro-ceedings) petitioned the PPUC to direct Met-Ed and Penelec to reinstate accounting for the CTC rate/shopping credit swap retroactive to January 1, 2002. Several other parties also filed petitions. On October 16, 2003, the PPUC issued a reconsideration order granting the date requested by Met-Ed and Penelec for the NUG trust fund refund, denying Met-Ed's and Penelec's other clarification requests and granting ARIPPA's petition with respect to the accounting treatment of the changes to the CTC rate/shopping credit swap. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse the PPUC's finding that requires Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. Met-Ed and Penelec are consid-ering filing an appeal to the Commonwealth Court on the PPUC orders as well.

On October 27, 2003, a Commonwealth Court judge issued an Order denying Met-Ed's and Penelec's objection without explanation. Due to the vagueness of the Order, Met-Ed and Penelec, on October 31, 2003, filed an Application for Clarification with the judge. Concurrent with this filing, Met-Ed and Penelec, in order to preserve their rights, also filed with the Commonwealth Court both a FirstEnergy Corp. 2003 49

Petition for Review of the PPUC's October 16 and October 22 Orders, and an application for reargument, if the judge, in his clarification order, indicates that Met-Ed's and Penelec's objection was intended to be denied on the merits. In addi-tion to these findings, Met-Ed and Penelec, in compliance with the PPUC's Orders, filed revised PPUC quarterly reports for the twelve months ended December 31, 2001 and 2002, and for the first two quarters of 2003, reflecting balances consistent with the PPUC's findings in their Orders.

Effective September 1, 2002, Met-Ed and Penelec assigned their PLR responsibility to their FES affiliate through a wholesale power sale agreement. The PLR sale will be automatically extended for each successive calen-dar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES assumed the supply obliga-tion and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. FES has hedged most of Met-Ed's and Penelec's unfilled PLR on-peak obligation through 2004 and a portion of 2005, the period during which deferred accounting was previously allowed under the PPUC's order. Met-Ed and Penelec are authorized to continue deferring differences between NUG contract costs and current market prices.

In late 2003, the PPUC issued a Tentative Order imple-menting new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and cre-ate additional reporting on reliability. Although neither the Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. The comment period for both the Tentative Order and the Proposed Rulemaking Order has closed. Met-Ed, Penelec and Penn are currently awaiting the PPUC to issue a final order in both matters. The order will determine (1) the standards and benchmarks to be utilized, and (2) the details required in the quarterly and annual reports. It is expected that these Orders will be finalized in March of 2004.

On January 16, 2004, the PPUC initiated a formal investigation of Met-Ed's, Penelec's and Penn's levels of compliance with the Public Utility Code and the PPUC's reg-ulations and orders with regard to reliable electric service.

Hearings will be held in August in this investigation and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order before December 16, 2004. FirstEnergy is unable to predict the outcome of the investigation or the impact of the PPUC order.

Transition Cost Amortization -

OE, CEI and TE amortize transition costs (see Regulatory Matters - Ohio) using the effective interest method. Under the current Ohio transition plan, total transi-tion cost amortization is expected to approximate the following for 2004 through 2009.

2004 2005 2006 2007 2008 2009 (In millions)

$794 922 371 208 164 46 The decrease in amortization beginning in 2006 results from the termination of generation-related transition cost recovery under the Ohio transition plan.

Regulatory Assets-The Companies recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods. Without such authorization, the costs would have been charged to income as incurred. All regulatory assets are expected to continue to be recovered from customers under the Companies' respective transition and regulatory plans.

Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribu-tion services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations. Regulatory assets which do not earn a current return totaled approximately $625 million as of December 31, 2003.

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

2003 2002 (In millions)

Regulatory transition charge S6,427 S7,608 Customer shopping incentives 371 188 Customer receivables for future income taxes 340 394 Societal benefits charge 81 144 Loss on reacquired debt 75 74 Employee postrefirement benefit costs 77 88 Nuclear decommissioning, decontamination and spent fuel disposal costs (96) 99 Component removal costs (321) 12881 Property losses and unrecovered plant costs 70 88 Other 53 70 Total S7,077

$8,465 Regulatory Accounting for Generation Operations-The application of SFAS 71 was discontinued with respect to the Companies' generation operations. The SEC's interpretive guidance regarding asset impairment measure-ment providing that any supplemental regulated cash flows such as a CTC should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulato-ry asset should be established if the costs are recoverable through regulatory cash flows. Consistent with the SEC guid-ance, 51.8 billion of impaired plant investments ($1.2 billion,

$227 million, $304 million and $53 million for OE, Penn, CEI and TE, respectively) were recognized as regulatory assets recoverable as transition costs through future regulatory cash flows. The following summarizes net assets included in prop-erty, plant and equipment relating to operations for which the application of SFAS 71 was discontinued, compared with the respective company's total assets as of December 31, 2003.

50 FflstEt~egy Co'p. 2003

SFAS 71 Discontinued Net Assets Total Assets

.(In millions)

OE

$976

$6591

_TE 561 2 855 Penn

-:92

- 879 JCP&L 42

-7)579

'Met-Ed

.15 3,474 (E) Property, Plant and Equipment-Property, plant and equipment reflects original cost (except for nuclear generating assets which were adjusted to fair value), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service.

JCP&L holds a 50% ownership interest in Yards Creek Pumped Storage Facility - its net book value was approxi-mately $20.7 million as of December 31, 2003. FirstEnergy also had shared ownership interests in various foreign prop-erties - all such assets were divested by January 30, 2004.

FirstEnergy's accounting policy for planned major mainte-nance projects is to recognize liabilities as they are incurred.

The Companies provide for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite rates for the Companies' electric plant in 2003, 2002 and 2001 (post-merger periods only for JCP&L, Met-Ed and Penelec) are shown in the following table:

AnnualCompositeDepreciationRate 21003 2002 2001.:'

OE 28 2.71 t27%

' CEI 3.0 34 32 TE 30 3.9,

3.5' f Penn 26 2.9

- -29 JCP&L 28 3.5 3.4 r

- -l

-Met-Ed 27 3.0

-I3.0

Penelec o;

7 3,03',-2.-p mulated accretion for the period from the date the liability was incurred to the date of adoption. The ARO liability was $1.179 billion as of December 31, 2003 and included

$1.166 billion for nuclear decommissioning of the Beaver Valley, Davis-Besse:>Perry, and Three Mile Island Unit 2 (TMI-2) nuclear generating facilities (discussed below).

The Companies' share of the obligation to decommission these units was developed based on site specific studies performed by an independent engineer. FirstEnergy utilized an expected cash flow approach (as discussed in FASB Concepts Statement No. 7, "Using Cash Flow Information and Present Value in Accounting Measurements") to meas-ure the fair value of the nuclear decommissioning ARO.

The Companies maintain nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of December 31, 2003, the fair value of the decommissioning trust assets was

$1.352 billion. Payments for decommissioning of the nuclear generating units are expected to begin in 2014, when actual decommissioning work is expected to begin.

The following table provides the beginning and ending aggregate carrying amount of the total ARO and the changes to the balance during 2003.

ARO Reconciliation 2003 (In millions)

.Beginning balance as of January 1,2003

$1.107 LUabilities incurred ',

'Liabilities settled '

- Accretion in 2003 72

.Revisions in estimated cash flows Ending balance as of December 31,2003 1

,179

• The following table provides the year-end balance of the ARO for 2002, as if SFAS 143 had been adopted on January 1, 2002.

Nuclear Fuel -

Nuclear fuel is recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. The Companies amortize the cost of nuclear fuel based on the rate of consumption.

(F) Asset Retirement Obligation-In January 2003, FirstEnergy implemented SFAS 143, "Accounting for Asset Retirement Obligations,"which pro-vides accounting standards for retirement obligations associated with tangible long-lived assets. This statement requires recognition of the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability instead if the criteria for such treatment are met. Upon retirement, a gain or loss would be recognized if the cost to settle the retirement obligation differs from the carrying amount.

FirstEnergy identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond related to the Bruce Mansfield Plant, and closure of two coal ash disposal sites. The ARO liability as of the date of adoption of SFAS 143 was $1.107 billion, including accu-(In millions)

"Beginning balance as of January 1,2002

- 1$1,042 Accretio n 2002,-

5 Ending balance as of December 31, 2002

$1,107 In addition to the nuclear decommissioning ARO, FirstEnergy has also recognized estimated liabilities for post defueling monitored storage at TMI-2 of $26 million and decontamination and decommissioning of nuclear enrichment facilities of $28 million. Under terms of the NRC license, FirstEnergy is required to monitor and main-tain TMI-2 to ensure that there is no deterioration of the facility. As required by the Energy Policy Act of 1992, FirstEnergy participates in the decontamination and decom-missioning of nuclear enrichment facilities operated by the United States Department of Energy.

I In accordance with SFAS 143, FirstEnergy ceased the accounting practice of depreciating non-regulated generation assets using a cost of removal component in the deprecia-tion rates. That practice recognized accumulated depreciation in excess of the historical cost of an asset because the removal cost would exceed the estimated salvage value.

Beginning in 2003, the cost of removal related to non-regulat-ed generation assets is charged to expense rather than to the accumulated provision for depreciation. In accordance with SFAS 71, the cost of removal on regulated plant assets continues to be accounted for as a component of deprecia-FirstEnergy Corp. 2003 51

tion rates and is recognized as a regulatory liability.

The following table provides the effect on income as if SFAS 143 had been applied during 2002 and 2001.

If fair value accounting were applied to FirstEnergy's stock options, net income and earnings per share would be reduced as summarized below.

Effect of the Change in Accounting Principle Applied Retroactively 2002 2001 (In millions, except per share amounts)

Reported net income Increase (Decrease):

Elimination of decommissioning expense Depreciation of asset retirement cost Accretion of ARO liability Non-regulated generation cost of removal component. net Income tax effect Net earnings increase Net income adjusted S553

$646 88 (31 1381 15 (25) 37

$590 88 13) 135) 11 1251 36 S682 2003 2002 2001 (In thousands, except per share amounts)

Net Income, as reported

$422,764

$552,804 S646,447 Add back compensation expense reported in net income, net of tax (based on AP8

25) 163 166 25 Deduct compensation expense based upon estimated fair value, net of tax _

12,354)

(8.825) 13,748)

Adjusted net income

$410,573 S544,145

$642,724 Earnings Per Share of Common Stock -

Basic

=

=

Basic earnings per share of common stock:

Net income as previously reported

$1.89

$2.82 Adjustment for effect of change in accounting principle applied retroactively 0.12 0.16 Net income adjusted

$2.01 S2.98 Diluted earnings per share of common stock:

Net income as previously reported

$1.88 S2.81 Adjustment for effect of change in accounting principle applied retroactively 0.12 0.16 Net income adjusted

$2.00

$2.97 As Reported Adjusted Diluted As Reported Adjusted S1.39

$1.89 S2.82 S1.35

$1.86

$2.80

$1.39

$1.88 S2.81

$1.35

$1.85

$2.79 (G) Stock-based Compensation-FirstEnergy applies the recognition and measurement principles of Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock Issued to Employees" and related Interpretations in accounting for its stock-based compensation plans (see Note 5(C)). No material stock-based employee compensation expense is reflected in net income as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the grant date, resulting in substantially no intrinsic value.

If First Energy had elected to account for employee stock options under the fair value method (as provided under SFAS 123, "Accounting for Stock-Based Compensation") a higher value would have been assigned to the options granted. The weighted average assumptions used in valuing the options and their resulting estimated fair values would be as follows:

(H) Income Taxes-Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. The Company records income taxes in accordance with the lia-bility method of accounting. Deferred income taxes reflect the next tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purpos-es. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to tax and accounting basis differences and tax credit carry-forward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid.

FirstEnergy has capital loss carryforwards of approxi-mately $1.1 billion, most of which expire in 2007. The deferred tax assets associated with these capital loss car-ryforwards ($374 million) are fully offset by a valuation allowance as of December 31, 2003, since management is unable to predict whether sufficient capital gains will be generated to utilize all of these capital loss carryforwards.

Any ultimate utilization of capital loss carryforwards for which valuation allowances were established through pur-chase accounting would adjust goodwill.

The Company has also recorded valuation allowances of $92 million for deferred tax assets associated with impairment losses related to certain domestic assets and the divestiture of international assets acquired through the merger with GPU (see Note 12).

FirstEnergy has net operating loss carryforwards for state and local income tax purposes of approximately $693 million. A valuation allowance of $5 million has been recorded against the associated deferred tax assets of S30 million. These losses expire as follows:

2003 2002 2001 Valuation assumptions:

Expected option term (years) 7.9 8.1 8.3 Expected volatility 26.91' 23.31%

23.45' Expected dividend yield 5.095 4.36' 5.00%

Risk-free interest rate 3567%

4.60%

4.67%

Fair value per option S5.09 S6.45 S4.97 Expiration Period 2004-2008 2009-2013 2014-2018 2019-2022 Amount (in millions)

$102 147 130 314 S693 52 FirsrEnergV Co!p. 2023

(I) Discontinued Operations-FirstEnergy has included in "Discontinued Operations" on the Consolidated Statements of Income for the years ended December 31, 2003 and 2002 operating income and losses on sales of its international ope rationis in Argentina and Bolivia and certain domestic subsidiaries of FSG and MARBEL, all of which were sold in 2003. Discontinued operations in 2003 of $(1 01) million, net of tax benefits of

$2 million, included operating results of $2 million (revenues of $52 million and pre-tax income of $2 million) and losses on sales or abandonments of $103 million. A net operating loss of $80 million (revenues of $284 million and pre-tax loss of $75 million) attributable to these entities was included in discontinued operations in 2002. The 2001 results of the divested entities were not significant and the 2001 Consolidated Statement of Income was not reclassified to separately report discontinued operations.

i On April 18, 2003, FirstEnergy divested its ownership in Emdersa through the abandonment of its shares in Emdersa's parent company, GPU Argentina Holdings, Inc.

The abandonment was accomplished by relinquishing FirstEnergy's shares to the independent Board of Directors of GPU Argentina Holdings, relieving FirstEnergy of all rights and obligations relative to this business. FirstEnergy included in discontinued operations Emdersa's net income of $7 million and a $67 million charge for the abandonment in the second quarter of 2003 (no income tax benefit was, recognized). An after-tax loss of $87 million (including $109 million in currency transaction losses arising principally from U.S. dollar denominated debt) was included in discon-tinued operations in 2002.

In December 2003, Empresa Guaracachi S.A. (EGSA),

GPU Power's Bolivia subsidiary, was sold to Bolivia Integrated Energy Limited. FirstEnergy included in discontinued opera-tions a $33 million loss on the sale of EGSA in the fourth quarter of 2003 (no income tax benefit was realized) and an operating loss for the year of $2 million. Discontinued opera-tions in 2002 include EGSA's operating income of $6 million.

The FSG subsidiaries, Colonial Mechanical and Webb Technologies, were sold in January 2003 and Ancoma, Inc.

was sold in December 2003; the MARBEL subsidiary, Northeast Ohio Natural Gas Corp. was sold in June 2003.

The 2003 and 2002 results for these divested business operations included in discontinued operations for the years ended December 2003 and 2002 totaled $(3) million and $2 million, respectively.

The following table summarizes major assets and lia-bilities for all of these divestitures included in FirstEnergy's Consolidated Balance Sheets as of December 31, 2002.

asset retirement costs were recorded in the amount of

$602 million as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of

$415 million. The ARO liability on the date of adoption was

$1.107 billion, including accumulated accretion for the peri-od from the date the liability was incurred to the date of adoption. The remaining cumulative effect adjustment for unrecognized depreciation and accretion, offset by the reduction in the existing decommissioning liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was a $175 million increase to income, $102 million net of tax, or $0.33 per share of common stock (basic and diluted) in the year ended December 31, 2003 (see Note 9).

On January 1, 2001, FirstEnergy adopted SFAS 133 as amended, "Accounting for Derivative Instruments and Hedging Activities." The cumulative effect to January 1, 2001 was a charge of $9 million (net of $6 million of income taxes) or $0.03 per share of common'stock.

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

The trusteed plans provide defined benefits based on years of service and compensation levels. The Company's funding policy is based on actuarial computations using the project-ed unit credit method. No pension contributions were required during the three years ended December 31, 2003.

FirstEnergy provides a minimum amount of noncontribu-tory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. The Company recognizes the expected cost of providing other postretire-ment benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits..

Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as the merger with GPU, Inc. in November 2001), which impact employee demographics, plan experience and other factors.

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

Plan amendments to retirement health care benefits in 2003 and 2002, relate to changes in benefits provided and cost-sharing provisions, which reduced the Company's obli-gation by $123 million and $121 million, respectively. In early 2004, the Company announced that it would amend the benefit provisions of its health care benefits plan and both employees and retirees would share in more of the benefit costs.

On December 8, 2003, President Bush signed into law a bill that expands Medicare, primarily adding a pre-scription drug benefit for Medicare-eligible retirees starting in 2006. FirstEnergy anticipates that the benefits it pays

As of December31 202

=;a 5

-i: lmillioi~sJ.

-j

-Current assets

-i

$106w-$10 Property and investments

-175

-I Deferred charges Totalassets

$325 Current liabilities 6 45

= apitalization 205 Noncurrent liabilities -

.56

-Total liabilities and capitalization

$325 (J) Cumulative Effect of Accounting Change-As a result of adopting SFAS 143 in January 2003, FirstEnergy Corp. 2003 53

after 2006 will be lower as a result of the new Medicare provisions. Due to uncertainties surrounding some of the new Medicare provisions and a lack of authoritative accounting guidance about these issues. FirstEnergy deferred the recognition of the impact of the new Medicare provisions as provided by FASB Staff Position 106-1. The final accounting guidance could require changes to previously reported information.

Components of Net Pension Benefits Other Benefits Periodic Benefit Costs 2003 2002 2001 2003 2002 2001 (In millions)

Service cost S66

$59 Interest cost 253 249 Expected return on plan assets (2481 1346)

Amortization of prior service cost 9

9 Amortization of transition obligation (assetl Recognized net actuarial loss 62 Voluntary early retirement program Net periodic cost (income) $142 S(29)

$35

$43 S29

$18 133 137 114 65 1205)

(43)

(52) 110) 9 (9) 3 3

Pension Benefits Other Benefits Obligations and lFunded Status As of December :11 2003 2D02 20(3 2002 (In millions)

12) 9 9

40 11 9

5 6

2 W124 S177

$114 592 Change in benefit obligation Benefit obligation at beginning of year Service cost Interest cost Plan participants' contributions Plan amendments Actuarial loss GPU acquisition INote 121 Benefits paid Benefit obligation at end of year 53.866 $3.548 66 59 253 249 222 268 1121 (245)

(246)

$4,162 $3,866

$2,077 43 136 6

1123) 323 (941

$2.368

$1,582 28 114 1121) 440 110 (76)

$2,077 Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Pension Benefits Other Benefits Ended December 31 2003 2002 2001 2003 2002 2001 Discount rate 6.75% 7.25' 7.75' 6.75' 7.25' 7.75' Change in fair value of plan assets Fair value of plan assets at beginning of year S2,889 $3.484 S473 S535 Actual return on plan assets 671 1349) 88 157)

Company contribution 68 31 Plan participants' contribution 2

Benefits paid (245)

(246) 194)

(36)

Fair value of plan assets at end of year

$3.315 S2,889

$537

$473 Funded status S(847)

$(977) $11,831)

(1,604)

Unrecognized net actuarial loss 919 1,186 994 752 Unrecognized prior service cost (benefit) 72 78 (221)

(1071 Unrecognized net transition obligation 83 92 Net asset (liability) recognized S144

$287 S(9751 Sf867)

Amounts Recognized in the Consolidated Balance Sheets As of December 31 Accrued benefit cost

$1438) 5(548)

$1975)

S1867)

Intangible assets 72 78 Accumulated other comprehensive loss 510 757 Net amount recognized

$144

$287 S1975) $(867)

Increase (decrease) in minimum liability included in other comprehensive income (net of tax)

$11451 $444 Assumptions Used to Determine Benefit Obligations As of December 31 Discount rate 6.25' 6.75' 6.25' 6.75' Rate of compensation increase 3.50' 3.50' Allocation of Plan Assets As of December 31 Asset Category Equity securities 70%

61' 71' 58' Debt securities 27 35 22 29 Real estate 2

2 Cash 1

2 7

13 Total 100' 100' 100' 100' Information for Pension Plans With an Accumulated Benefit Obligation in Excess of Plan Assets 2003 202 (in millions)

Projected benefit obligation

$4.162

$3,866 Accumulated benefit obligation 3.753 3,438 Fair value of plan assets 3,315 2,889 Expected long-term return on plan assets 9.00' 10.25' 10.25' Rate of compensation increase 3.50' 4.00' 4.00' 9.00' 10.25' 10.25' In selecting an assumed discount rate, FirstEnergy con-siders currently available rates of return on high-quality fixed income investments expected to be available during the peri-od to maturity of the pension and other postretirement benefit obligations. The assumed rate of return on pension plan assets considers historical market returns and economic fore-casts for the types of investments held by the Company's pension trusts. The long-term rate of return is developed con-sidering the portfolio's asset allocation strategy.

Assumed Health Care Cost Trend Rates As of December 31 Health care cost trend rate assumed for next year (pre/post-Medicarel 1

Rate to which the cost trend rate is assumed to decline (the ultimate trend ratel Year that the rate reaches the ultimate trend rate (pre/post-Medicare) 20 2003 2002 0%-12%

10%-12%

5' 5'

09-2011 2008-2010 Assumed health care cost trend rates have a signifi-cant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

1-Percentage-1-Percentage-Point Increase Point Decrease (in millions)

Effect on total of service and irterest cost

$26 S119)

Effect on postretirement benefit obligation

$233 S(212)

FirstEnergy employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Furthermore, equity invest-ments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalizations.

Other assets such as real estate are used to enhance long-term returns while improving portfolio diversification.

Derivatives may be used to gain market exposure in an 54 Fusr5'e gvCorip 20)3

efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measure-ments, and periodic asset/liability studies.

As a result of the increased market value of its pension plan assets, FirstEnergy reduced its miinimum liability as prescribed by SFAS 87 as of December 31, 2003 by $253 million, recording a decrease of $6 million in an intangible asset and crediting OCI by $145 million (offsetting previously recorded deferred tax benefits by $102 million). The remaining balance in OCI of $299 million will reverse in future periods to the extent the fair value of trust assets exceeds the accu-mulated benefit obligation. The accrued pension cost was reduced to $438 million as of December 31, 2003.

FirstEnergy does not expect to contribute to its pension plans in 2004 and expects to contribute $16 million to its other postretirement benefit plans in 2004.

{L} Goodwill-In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Under SFAS 142, "Goodwill and Other Intangible Assets," amorti-zation of existing goodwill ceased January 1, 2002. Instead, FirstEnergy evaluates goodwill for impairment at least annu-ally and makes such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the good-will is tested for impairment. When impairment is indicated, FirstEnergy recognizes a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. FirstEnergy's annual review was completed in the third quarter of 2003. As a result of that review, a non-cash goodwill impairment charge of $122 million was recognized in the third quarter of 2003, reducing the carrying value of FSG. Of this amount, $117 million is reported as an operating expense and $5 million is included, net of tax, in the loss from dis-continued operations. The impairment charge reflects the continued slow down in the development of competitive retail markets and depressed economic conditions that affect the value of FSG. The fair value of FSG was estimat-ed using primarily the expected discounted future cash flows. The forecasts used in FirstEnergy's evaluations of goodwill reflect operations consistent with its general busi-ness assumptions. Unanticipated changes in those assumptions could have a significant effect on FirstEnergy's future evaluations of goodwill. As of December 31, 2003, FirstEnergy had $6.1 billion of goodwill that primarily relates to its regulated services segment. The impairment analysis includes a significant source of cash representing the Companies' recovery of transition costs as described above under Note 2 (D). FirstEnergy does not believe that comple-tion of transition cost recovery will result in an impairment of goodwill relating to its regulated business segment.

The following table displays what net income and earnings per share would have been if goodwill amortiza-tion had been excluded in 2001:

7

.2003 0

2001 f

.(In thousands, except per share amounts)

Reported net income

$422,764

$552,804 -$646,447 Goodwill amortization Inet of taxi

54,584 Adjusted net income

$422,764. $552,804

$701,031 Basic earnings per common share:

Reported earnings per share

$1.39

$1.89

$2.82 Goodwill amortization 0.23

^. Adjusted earnings per share

. $1.39

$1.89.: : $3.05 Diluted earnings per common share:

Reported earnings per share : :.

$1.39

$1.88

$2.81 Goodwill amortization 0.23 Adjusted earnings per share

$1.39

$1.88 -

$3.04 A summary of the changes in FirstEnergy's goodwill for the years ended December 31, 2002 and 2003 is shown below:

2003 2002 (In millions)

Balance as of January 1

$6,278

$5,983 Impairment charges.

(11.221 FSG divestitures (41) 286 GPU acquisition Isee Note 121 286 Dther 3

[rBalance as of December31

$5,128 -

$6,278 (M) Cash and Financial Instruments-All temporary cash investments purchased with an ini-tial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Cash and cash equivalents as of December 31, 2003 included $32 million received in December 2003 which was included in the NRG settlement claim sold in January 2004 (see Note 3).

Cash and cash equivalents as of December 31, 2002 included $50 million used for the redemption of long-term debt in January 2003. Noncash financing and investing activities in 2001 included $2.6 billion of common stock issued for the GPU acquisition and capital lease transac-tions amounting to $3 million. There were no capital lease transactions in 2003 or 2002. Net losses on foreign curren-cy exchange transactions reflected on FirstEnergy's 2002 Consolidated Statement of Income consisted of approxi-mately $104 million from FirstEnergy's Argentina operations (see Note 3 - Divestitures).

On the Consolidated Statements of Cash Flows, the amounts included in "Cash investments" under Cash Flows From Investing Activities primarily consist of changes in investments in collateralized lease bonds (see Note 4) of $85 million and other cash investments of $(32) million in 2003 and changes in investments in collateralized lease bonds of

$87 million and other cash investments of $(6) million in 2002. The amounts included in "Other amortization and accruals, net"under Cash Flows From Operating Activities include amounts from the reduction of an electric service obligation under a CEI electric service prepayment program.

All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following sets forth the approximate fair value and related carrying amounts of all other long-term debt, preferred stock sub-ject to mandatory redemption and investments other than cash and cash equivalents as of December 31:

FirstEnergy Corp. 2003 55

2003 2002 Carrying Fair Carrying Fair Value Value Value Value (In millions)

Long-term debt

$11,471

$11,970

$12,465

$12,761 Preferred stock' S

19 19 S 445 S 454 Investments other than cash and cash equivalents:

Debt securities:

-Maturity 15-10 years)

S 452 S 427 S 502 471

-Maturity (more than 10 years) 871 1.005 927 1,030 Equity securities 15 15 All other 1.944 1,944 1,668 1,669 S 3.267 S 3.376 S 3,112

$ 3,185 Fhe December 31, 2003 amount is classified as debt under SFAS 150.

The fair values of long-term debt and preferred stock reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by corpora-tions with credit ratings similar to the Companies' ratings.

The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instru-ments with similar characteristics and terms. Investments other than cash and cash equivalents include decommission-ing trust investments. The Companies have no securities held for trading purposes. See Note 10 for discussion of SFAS 115 activity related to available-for-sale securities.

The investment policy for the nuclear decommission-ing trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, war-rants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, pre-ferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries. The investments that are held in the decommissioning trusts (included as "All other" in the table above) consist of equity securities, ($779 mil-lion) and fixed income securities ($573 million) as of December 31, 2003. In 2001, unrealized gains and losses applicable to all of FirstEnergy's decommissioning trusts were recognized in the trust investment with a correspon-ding change to the decommissioning liability. In 2003 and 2002, unrealized gains and losses applicable to the decom-missioning trusts of FirstEnergy's Ohio Companies were reclassified to OCI in accordance with SFAS 115, as fluctu-ations in the fair value of these trust balances will eventually affect earnings. Realized gains (losses) are rec-ognized as additions (reductions) to trust asset balances.

For 2003 and 2002, net realized gains (losses) were approximately $6.0 million and $(15.6) million and interest and dividend income totaled approximately $37.0 million and $33.2 million, respectively.

The Board of Directors authorized the repurchase of up to 15 million shares of FirstEnergy's common stock over a three-year period beginning in 1999. Repurchases were made on the open market, at prevailing prices, and were funded primarily through the use of operating cash flows. During 2001, FirstEnergy repurchased and retired 550,000 shares (average price of $27.82 per share).

FirstEnergy is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including electricity, natural gas and coal. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, includ-ing forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging pur-poses, and to a lesser extent, for trading purposes.

FirstEnergy's Risk Policy Committee, comprised of execu-tive officers, exercises an independent risk oversight function to ensure compliance with corporate risk manage-ment policies and prudent risk management practices.

FirstEnergy uses derivatives to hedge the risk of price and interest rate fluctuations. FirstEnergy's primary ongoing hedging activity involves cash flow hedges of electricity and natural gas purchases. The maximum periods over which the variability of electricity and natural gas cash flows are hedged are two and three years, respectively. Gains and losses from hedges of commodity price risks are included in net income when the underlying hedged commodities are delivered. Also, gains and losses are included in net income when ineffectiveness occurs on certain natural gas hedges. The impact of ineffectiveness on earnings during 2003 was not material. FirstEnergy entered into interest rate derivative transactions during 2001 to hedge a portion of the anticipated interest payments on debt related to the GPU acquisition. Gains and losses from hedges of anticipat-ed interest payments on acquisition debt are included in net income over the periods that hedged interest payments are made - 5, 10 and 30 years. Gains and losses from deriva-tive contracts are included in other operating expenses.

Accumulated Other Comprehensive Loss (AOCL) as of December 31, 2003 includes a net deferred loss of $111 million for derivative hedging activity. The $1 million increase from the December 31, 2002 balance of $110 mil-lion includes a $3 million reduction related to current hedging activity and a S4 million increase due to net hedge gains included in earnings during the year. Approximately

$22 million (after tax) of the current net deferred loss on derivative instruments in AOCL is expected to be reclassi-fied to earnings during the next twelve months as hedged transactions occur. However, the fair value of these deriva-tive instruments will fluctuate from period to period based on various market factors.

During 2003, FirstEnergy and OE executed fixed-for-floating interest rate swap agreements with notional values of $950 million and $200 million, respectively, whereby FE and OE receive fixed cash flows based on the fixed coupons of the hedged securities and pay variable cash flows based on short-term variable market interest rates (6 month LIBOR index). These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues - protect-ing against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturi-ties, fixed interest rates received, and interest payment dates match those of the underlying obligations.

FirstEnergy entered into interest rate swap agreements on a $950 million notional amount of its and its subsidiaries' senior notes and first mortgage bonds with a weighted average fixed interest rate of 5.46%. OE entered into inter-est rate swap agreements on a $200 million notional amount of its senior notes with a weighted average fixed interest rate of 5.09%. In addition, the cancellation options (options with strike prices equivalent to that of the options embedded in the call feature of the securities), on $593.5 56 Firsffnergy Corp. 203

million notional amount of cancelable interest rate swaps on callable first mortgage bonds were exercised by swap counterparties. As a result of the counterparties exercising these options, FirstEnergy received $20.2 million in cash swap cancellation premiums during 2003. The amount of the cash premiums will be recognized over the remaining maturity of each respective hedged security. As of December 31, 2003 interest rate swap agreements with notional values totaling $1.15 billion were outstanding.

FirstEnergy engages in the trading of commodity deriv-atives and periodically experiences net open positions.

FirstEnergy's risk management policies limit the exposure to market risk from open positions and require daily report-ing to management of potential financial exposures.

3. DIVESTITURES:

International Operations-FirstEnergy completed the sale of its international assets subsequent to December 31, 2003 with the sales of its remaining 20.1 percent interest in Avon (parent of Midlands Electricity in the United Kingdom) on January 16, 2004, and its 28.67 percent interest in Termobarranquilla S.A., Empresa de Servicios Publicos (TEBSA) for $12 million on January 30, 2004. An impairment loss of $26 million related to TEBSA was recorded in December 2003 in Other Operating Expenses on the 2003 Consolidated Statement of Income and no gain or loss was recognized upon the sale in 2004. Avon, TEBSA and other international assets sold in 2003 were acquired as part of FirstEnergy's November 2001 merger with the former GPU, Inc. FirstEnergy no longer has ownership interests in international operating assets.

The divestiture in 2003 of international operations in Bolivia and Argentina included the sale of FirstEnergy's wholly owned subsidiary, Guaracachi America, Inc., a holding company with a 50.001 percent interest in EGSA, on December 11, 2003, and its ownership in Emdersa through the abandonment of its shares in Emdersa's parent company, GPU Argentina Holdings, Inc. on April 18, 2003 (see Note 2 (I)).

This resulted in a loss on sale of $33 million recognized in Discontinued Operations in the Consolidated Statement of Income for the year ended December 31, 2003.

FirstEnergy had sold a 79.9 percent equity interest in Avon on May 8, 2002 to Aquila, Inc. (formerly UtiliCorp United) for approximately $1.9 billion (including the assump-tion of $1.7 billion of debt). Proceeds to FirstEnergy included

$155 million in cash and a note receivable for approximately

$87 million (representing the present value of $19 million per year to be received over six years beginning in 2003) from Aquila for its 79.9 percent interest. After reaching agreement to sell its remaining 20.1 percent interest in the fourth quar-ter of 2003, FirstEnergy recorded a $5 million after-tax charge to reduce the carrying value. In the fourth quarter of 2002, FirstEnergy recorded a $50 million after-tax charge to reduce the carrying value of its remaining 20.1 percent interest.

In the second quarter of 2003, FirstEnergy recognized an impairment of $13 million ($8 million net of tax) related to the carrying value of the note FirstEnergy had with Aquila from the 2002 sale of the 79.9 percent interest in Avon. The changes in the fourth quarter of 2002 and sec-ond quarter of 2003 are included in Other Operating Expenses on the Consolidated Statements of Income for the years ended December 31, 2002 and 2003, respective-ly. After receiving the first annual installment payment of

$19 million in May 2003, FirstEnergy sold the remaining balance of its note receivable in the secondary market and received $63 million in proceeds on July 28, 2003.

Through 2002, FirstEnergy was unsuccessful in divest-ing of GPU's former Argentina operations and made the decision to abandon its interest in Emdersa in early 2003. A number of economic events occurred in Argentina that hin-dered FirstEnergy s ability to realize Emdersa's estimated fair value. These events included currency devaluation, restric-tions on repatriation of cash, and the anticipation of future asset sales in that region by competitors. The abandonment was accomplished by relinquishing FirstEnergy's shares to the independent Board of Directors of GPU Argentina Holdings, relieving FirstEnergy of all rights and obligations rel-ative to this business. As a result of the abandonment, FirstEnergy recognized a one-time, non-cash charge of $67 million, or $0.23 per share of common stock in the second quarter of 2003. This charge is the result of realizing the cur-rency translation adjustment (CTA) losses through current period earnings ($90 million, or $0.30 per share), partially off-set by the gain recognized from abandoning FirstEnergy's investment in Emdersa ($23 million, or $0.07 per share).

Since FirstEnergy had previously recorded $90 million of CTA adjustments in OCI, the net effect of the $67 million charge was an increase in common stockholders' equity of $23 mil-lion. In addition, FirstEnergy reflected Emdersa's 2002 results of an after-tax loss of $87 million (including $109 million in currency transaction losses arising principally from U.S. dollar denominated debt) as discontinued operations in the Consolidated Statement of Income for the year ended December 31, 2002. FirstEnergy also recognized a CTA of

$91 million in 2002 which reduced FirstEnergy's common stockholders' equity. This adjustment represented the impact of translating Emdersa's financial statements from its func-tional currency to the U.S. dollar for GAAP financial reporting.

The $67 million after-tax charge in 2003 does not include the expected income tax benefits related to the abandonment, which were fully reserved during the sec-ond quarter of 2003. FirstEnergy expects tax benefits of approximately $129 million, of which $50 million would increase net income in the period that it becomes probable those benefits will be realized. The remaining $79 million of tax benefits would reduce goodwill recognized in con-nection with the acquisition of GPU.

Generation Assets-In November 2001, FirstEnergy reached an agreement to sell four coal-fired power plants totaling 2,535 MW to NRG Energy Inc. On August 8, 2002, FirstEnergy notified NRG that it was canceling the agreement because NRG stated that it could not complete the transaction under the original terms of the agreement. NRG filed voluntary bank-ruptcy petitions in May 2003; subsequently FirstEnergy reached an agreement for settlement of its claim against NRG. Under NRG's proposed Plan of Reorganization, FirstEnergy, as an unsecured creditor, could receive an estimated settlement of approximately $198 million, with payment in the form of cash (12%), notes (15.2%) and new NRG common stock (72.8%). FirstEnergy sold its entire claim (including $32 million of cash proceeds received in December 2003) for $170 million in January 2004.

In December 2002, FirstEnergy decided to retain ownership of these plants after reviewing other bids it sub-sequently received from other parties who had expressed FirstEnergy Corp. 2003 57

interest in purchasing the plants. Since FirstEnergy did not execute a sales agreement by year-end, it reflected approx-imately $74 million ($43 million net of tax) of previously unrecognized depreciation and other transaction costs in the fourth quarter of 2002 related to these plants from November 2001 through December 2002 on its Consolidated Statements of Income.

Other Domestic Operations-Sales of domestic assets in 2003 included three FSG subsidiaries - Ancoma, Inc., a mechanical contracting company based in Rochester, New York, and Virginia-based Colonial Mechanical and Webb Technologies - and a MARBEL subsidiary - Northeast Ohio Natural Gas (see Note 2(l)).

4. LEASES:

The Companies lease certain generating facilities, office space and other property and equipment under can-celable and noncancelable leases.

OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years. CEI and TE also sold portions of their ownership inter-ests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 and entered into similar operating leases for lease terms of approximately 30 years. During the terms of their respective leases, OE, CEI and TE continue to be responsible, to the extent of their individual combined ownership and leasehold interests, for costs associated with the units including con-struction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning.

They have the right, at the expiration of the respective basic lease terms, to renew their respective leases. They also have the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair mar-ket value of the facilities. The basic rental payments are adjusted when applicable federal tax law changes.

OES Finance, Incorporated, a wholly owned subsidiary of OE, maintains deposits pledged as collateral to secure reimbursement obligations relating to certain letters of credit supporting DE's obligations to lessors under the Beaver Valley Unit 2 sale and leaseback arrangements.

The deposits of approximately $278 million pledged to the financial institution providing those letters of credit are the sole property of OES Finance and are investments which are classified as "Held to Maturity". In the event of liquida-tion, OES Finance, as a separate corporate entity, would have to satisfy its obligations to creditors before any of its assets could be made available to OE as sole owner of CES Finance common stock.

Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income.

Such costs for the three years ended December 31, 2003 are summarized as follows:

2003 2002 2001 (In millions)

Operating leases Interest element

$181

$188

$194 Other 150 136 120 Capital leases Interest element 2

2 8

Other 2

3 36 Total rentals S335

$329 S358 OE invested in the PNBV Capital Trust, which was established to purchase a portion of the lease obligation bonds issued on behalf of lessors in OE's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. CEI and TE established the Shippingport Capital Trust to pur-chase the lease obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. The PNBV and Shippingport Capital Trust arrangements effectively reduce lease costs related to those transactions (see Note 9).

The future minimum lease payments as of December 31, 2003, are:

Operating Leases Capital Lease Capital Leases Payments Trusts Net (In millions) 2004 S6

$294

$112

$182 2005 5

313 130 183 2006 5

322 142 180 2007 1

300 131 169 2008 1

294 105 189 Years thereafter 6

2,514 872 1,642 Total minimum lease paym ents 24

$4,037 $1,492 32,545 Executory costs 5

Net minimum lease payments 19 Interest portion 6

Present value of net minimum lease payments 13 Less current portion 2

Noncurrent portion S11 FirstEnergy has recorded above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant associated with the 1997 merger between OE and Centerior. The total above-market lease obligation of $722 million associated with Beaver Valley Unit 2 is being amor-tized on a straight-line basis through the end of the lease term in 2017 (approximately $37 million per year). The total above-market lease obligation of $755 million associated with the Bruce Mansfield Plant is being amortized on a straight-line basis through the end of 2016 (approximately

$48 million per year). As of December 31, 2003 the above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant totaled $1.1 billion, of which $85 million is current.

5. CAPITALIZATION:

(A) Retained Earnings-There are no restrictions on retained earnings for pay-ment of cash dividends on FirstEnergy's common stock.

(B) Employee Stock Ownership Plan (ESOP) -

An ESOP Trust funds most of the matching contribution for FirstEnergy's 401 (k) savings plan. All full-time employees eligible for participation in the 401(k) savings plan are cov-ered by the ESOP. The ESOP borrowed $200 million from OE and acquired 10,654,114 shares of OE's common stock (subsequently converted to FirstEnergy common stock) through market purchases. Dividends on ESOP shares are used to service the debt. Shares are released from the ESOP on a pro rata basis as debt service payments are made. In 2003, 2002 and 2001, 1,069,318 shares, 1,151,106 shares and 834,657 shares, respectively, were allocated to employees with the corresponding expense recognized 58 FistEnergy Corp. 2023

based on the shares allocated method. The fair value of 2,896,951 shares unallocated as of December 31, 2003, was approximately $102.0 million. Total ESOP-related com-pensation expense was calculated as follows:

1

.03 2002 2001

$$51 34 2

$251.

Base compensation

: 'NB-'

.i 35.1 '

I m.il$4.

'ions 51'":

'Dividends on common stock held by the ESOP and used to service debt (911 i781 (B 1 Netexpense

$260,$264

$19.0 discussion of stock-based employee compensation expense recognized for restricted stock and EDCP stock units.

Stock option activities under the FE Programs for the past three years were as follows:

Number of - Weighted Average~*

Stock Option Activities Options i:

ExercisePrice BalanceJanuary1,2001 5,021,862 24.09 (473,314 options exercisablel 24.11 Options granted 4,240,273 28.11 Options exercised 694,403 24.24 Options forfeited 120,044.28.07 Balance. December 31. 2001 8,447,688 26.04 (1,.28,341 options exercisable) 24.83 gOptions ranted 3399579

'34.48 ;

Options exercised 1,018 852 23.56 Options forfeited 392,929 28.19 JBalance, December31, 2002 10.435.486 28.95i (1,400,206 options exercisable) 26.07 2 Options granted 3,981,100 '

29.71 Optionsexercised'; '..;. :.i.-.:

455 986 "I 25.94

.-.Options forfeited 311 731

. 29.09 Balance, December 31. 2003 13,648,869 29.27 11,919,662 options exercisable) e 29.67.

(C) Stock Compensation Plans-In 2001, FirstEnergy assumed responsibility for two stock-based plans as a result of its acquisition of GPU. No further stock-based compensation can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both plans have been converted into FirstEnergy options and restrict-ed stock. Options under the GPU Plan became fully vested on November 7, 2001, and will expire on or before June 1, 2010. Under the MYR Plan, all options and restricted stock maintained their original vesting periods, which range from one to four years, and will expire on or before December 17, 2006.

Additional stock-based plans administered by FirstEnergy include the Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director Incentive Compensation Plan (FE Plan). All options are fully vested under the CE Plan, and no further awards are permitted.

Outstanding options will expire on or before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5 million shares of common stock or their equivalent. Only stock options and restricted stock have been granted, with vesting periods ranging from six months to seven years.

Collectively, the above plans are referred to as the FE Programs. Restricted common stock grants under the FE Programs were as follows:

t 0 --

'=7'--':

1. 2003

2002

. ' -2001 Restricted common shares granted 36,922 133,162

.Weightedaveragemarketprice nar/al :; $36.04 -

35.68-Weighted average vesting period (years) n/a 3.2 '..

-3.7 Dividends restricted n/a. i Yes

.E 21i ii) Not applicable since no restricted stock was granted M FE Plan dividends are paid as restricted stock on 4,500 shares; MYR Plan dividends are paid as unrestricted cash on 128,662 shares Under the Executive Deferred Compensation Plan (EDCP), covered employees can direct a portion of their Annual Incentive Award and/or Long-Term Incentive Award into an unfunded FirstEnergy Stock Account to receive vest-ed stock units. An additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy Stock Account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout typically occurs three years from the date of deferral; however, an election can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement. As of December 31, 2003, there were 410,399 stock units outstanding. See Note 10(D) for As of December 31, 2003, the weighted average remain-ing contractual life of outstanding stock options was 7.6 years.

Options outstanding by plan and range of exercvise price as of December 31, 2003 were as follows:

.=i-s-- -.--.;-;..

-t-ange

4 OCptions FU FirstEnergy Programs 2 Exercise Prices Outstanding FE plan.

$19.31 -$29.87 9,904,861

$35.15 3.214,601 Plans acquired through merger:..

____._'_____.._,_'______________'__._'=

GPUplan

• $2375-$35.92 501,734 Other plans 27673 Total 13,648.869.

No material stock-based employee compensation expense is reflected in net income for stock options grant-ed under the above plans since the exercise price was equal to the market value of the underlying common stock on the grant date. The effect of applying fair value account-ing to FirstEnergy's stock options is summarized in Note 2(G) - Stock-Based Compensation.

(D) Preferred and Preference Stock-All preferred stock may be redeemed by the Companies in whole, or in part, with 30-90 days' notice.

Met-Ed's and Penelec's preferred stock authorization consists of 10 million and 11.435 million shares, respec-tively, without par value. No preferred shares are currently outstanding for the two companies.

. The Companies' preference stock authorization consists of 8 million shares without par value for.OE; 3 million shares without par value for CEI; and 5 million shares, $25 par value for TE. No preference shares are currently outstanding.

(E) Long-Term Debt-Each of the Companies has a first mortgage indenture under which it issues first mortgage bonds secured by a direct first mortgage lien on substantially all of its property and franchises, other than specifically excepted property.

FirstEnergy and its subsidiaries have various debt covenants under their respective financing arrangements. The most restrictive of the debt covenants relate to the nonpayment FirstEnergy Corp. 2003 59

of interest and/or principal on debt and the maintenance of certain financial ratios. The nonpayments debt covenant which could trigger a default is applicable to financing arrangements of FirstEnergy and all of the Companies. The maintenance of minimum fixed charge ratios and debt to capitalization ratios covenants is applicable to financing arrangements of FirstEnergy, the Ohio Companies and Penn.

There also exist cross-default provisions among financing arrangements of FirstEnergy and the Companies.

Based on the amount of bonds authenticated by the respective mortgage bond trustees through December 31, 2003, the Companies' annual sinking fund requirements for all bonds issued under the various mortgage indentures of the Companies amounts to $61.9 million. OE and Penn expect to deposit funds with their respective mortgage bond trustees in 2004 that will then be withdrawn upon the surrender for cancellation of a like principal amount of bonds, specifically authenticated for such purposes against unfunded property additions or against previously retired bonds. This method can result in minor increases in the amount of the annual sinking fund requirement. JCP&L, Met-Ed and Penelec expect to fulfill their sinking fund obli-gations by providing bondable property additions and/or retired bonds to the respective mortgage bond trustees.

Sinking fund requirements for first mortgage bonds and maturing long-term debt (excluding capital leases) for the next five years are:

{In millions) 2004 S1.750 2005 683 2006 1,377 2007 237 2008 385 pays an annual facility fee of 0.50% on the total credit facil-ity amount. The fees are subject to change based on changes to FirstEnergy's credit ratings.

OE had unsecured borrowings of S40 million as of December 31, 2003 under a $250 million long-term revolv-ing credit facility agreement which expires May 12, 2005.

OE currently pays an annual facility fee of 0.20% on the total credit facility amount. OE had no unsecured borrow-ings as of December 31, 2003 under a $125 million long-term revolving credit facility which expires October 23, 2006. OE currently pays an annual facility fee of 0.25%

on the total credit facility amount. The fees are subject to change based on changes to OE's credit ratings.

CEI and TE have unsecured letters of credit of approxi-mately $216 million in connection with the sale and leaseback of Beaver Valley Unit 2 that expire in April 2005. CEI and TE are jointly and severally liable for the letters of credit. In con-nection with its Beaver Valley Unit 2 sale and leaseback arrangements, OE has similar letters of credit secured by deposits held by its subsidiary, OES Finance (see Note 4).

(F) Long-Term Debt: Preferred Stock Subject to Mandatory Redemption-Effective July 1, 2003, upon adoption of SFAS 150 (see Note 91, FirstEnergy reclassified as debt the preferred stock of consolidated subsidiaries subject to mandatory redemption.

Prior year amounts were not reclassified.

Annual sinking fund provisions for the Companies' pre-ferred stock are as follows:

Series Shares Redemption Price Per Share CEI

$7.35C 10,000

$100 Penn 7.625%

7,500 100 Annual sinking fund requirements for the next five years are $1.8 million in each year 2004 through 2006, S12.3 million in 2007 and S1.0 million in 2008.

(G) Long-Term Debt: Subordinated Debentures to Affiliated Trusts-CEI formed a wholly owned statutory business trust to sell preferred securities and invest the gross proceeds in the 9.00% subordinated debentures of CEI. The sole assets of the trust are the applicable subordinated debentures.

Interest payment provisions of the subordinated debentures match the distribution payment provisions of the trust's pre-ferred securities. In addition, upon redemption or payment at maturity of subordinated debentures, the trust's pre-ferred securities will be redeemed on a pro rata basis at their liquidation value. Under certain circumstances, the applicable subordinated debentures could be distributed to the holders of the outstanding preferred securities of the trust in the event that the trust is liquidated. CEI has effec-tively provided a full and unconditional guarantee of payments due on the trust's preferred securities. The trust's preferred securities are redeemable at 100% of their princi-pal amount at CEI's option beginning in December 2006.

Met-Ed and Penelec each formed statutory business trusts for substantially similar transactions to those of CEI.

However, ownership of the respective Met-Ed and Penelec trusts is through separate wholly owned limited partner-ships. In these transactions, each trust invested the gross proceeds from the sale of its preferred securities in the pre-ferred securities of the applicable limited partnership, which Included in the table above are amounts for various variable interest rate long-term debt which have provisions by which individual debt holders have the option to "put back" or require the respective debt issuer to redeem their debt at those times when the interest rate may change prior to its maturity date. These amounts are $494 million,

$97 million and $50 million in 2004, 2005 and 2008, respectively, which represents the next date at which the debt holders may exercise this provision.

The Companies' obligations to repay certain pollution control revenue bonds are secured by several series of first mortgage bonds. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank letters of credit of $220 million and noncancelable municipal bond insurance policies of $482 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the letters of credit or policies, the Companies are entitled to a credit against their obligation to repay those bonds. The Companies pay annual fees of 1.125% to 1.50% of the amounts of the let-ters of credit to the issuing banks and are obligated to reimburse the banks for any drawings thereunder.

FirstEnergy had unsecured borrowings of $270 million as of December 31, 2003, under its $500 million revolving credit facility agreement which expires November 29, 2004. FirstEnergy currently pays an annual facility fee of 0.425% on the total credit facility amount. FirstEnergy had no borrowings as of December 31, 2003 under a new

$375 million long-term revolving credit facility agreement which expires October 23, 2006. FirstEnergy currently 60 ForstEnergy Corp. 2003

in turn invested those proceeds in the 7.35% and 7.349 subordinated debentures of Met-Ed and Penelec, respei tively. In each case, Met-Ed and Penelec has effectively provided a full and unconditional guarantee of obligation under the trust's preferred securities. The trust's preferr securities are redeemable at the option of Met-Ed and Penelec beginning in May 2004 and September 2004, respectively, at 100% of their principal amount.

In each of these transactions, interest on the subo:

nated debentures (and therefore distributions on the trL preferred securities) may be deferred for up to 60 mon, but CEI, Met-Ed and Penelec may not pay dividends on redeem or acquire, any of its cumulative preferred or cc mon stock until deferred payments on its subordinated debentures are paid in full.

Upon adoption of FASB Interpretation No. 46 (revised December 2003), "Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 " (FIN 46R), the limited partnerships and statutory business tr discussed above are not consolidated on the financial statements of FirstEnergy, CEI, Met-Ed and Penelec as of December 31, 2003 (see Note 9).

The following table displays information regarding I ferred securities of statutory business trusts outstandin as of December 31, 2003:

Stated Subordin Maturity Rate Value Debenti e :i.lnmillions)

Cleveland Electric Financing Trust a) 2031 9.0O%

', $100.0

$103.

Met-Ed Capital Trust W

-2039 7.351

$100.0

-$103.

Penelec Capital TrustOl 2039 7*341- $100.0

$103.

lI' The sole assets of the trust are CEI's subordinated debentures with the sami and maturity date as the preferred securities.

0! The sole assets of the trust are the preferred securities of Met-Ed Capital 1, and Penefec Capital II, LP. respectively, whose sole assets are the subordim debentures of Met-Ed and Penelec, respectively, with the same rate and mai date as the preferred securities.

(H) Securitized Transition Bonds-On June 11, 2002, JCP&L Transition Funding LLC (Issuer), a wholly owned limited liability company of JCP&L, sold $320 million of transition bonds to securiti:

the recovery of JCP&L's bondable stranded costs assoc ed with the previously divested Oyster Creek Nuclear Generating Station.

JCP&L does not own nor did it purchase any of the transition bonds, which are included in long-term debt or FirstEnergy's Consolidated Balance Sheet. The transition bonds represent obligations only of the Issuer and are cc eralized solely by the equity and assets of the Issuer, wh consist primarily of bondable transition property. The bon able transition property is solely the property of the IssuE Bondable transition property represents the irrevoc right of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on the transition bonds ar other fees and expenses associated with their, issuance JCP&L, as servicer, manages and administers the bond transition property, including the billing, collection and remittance of the TBC, pursuant to a servicing agreemE with the Issuer. JCP&L is entitled to a quarterly servicin fee of $100,000 that is payable from TBC collections.

(I) Comprehensive Income-Comprehensive income includes net income as report-ed on the Consolidated Statements of Income and all other S

changes in common stockholders' equity except those ed resulting from transactions with common stockholders. As of December 31, 2003, accumulated other comprehensive income (loss) consisted of a minimum liability for unfunded retirement benrefits of $306 million, unrealized gains on rdi-investments in securities available for sale of $64 million,

)st's and unrealized losses on derivative instrument hedges of

ths,

$1 11 million. Other comprehensive income (loss) reclassi-or fied to net income in 2003, 2002 and 2001 totaled $29 om-million, $(10) million and $31 million, respectively. These amounts were net of income taxes in 2003, 2002 and 2001 of $20 million, $(7) million and $22 million, respectively.

6. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT:

usts Short-term borrowings outstanding as of December 31, 2003, consisted of $372 million of bank borrowings and

$150 million of OES Capital, Incorporated commercial paper.

OES Capital is a wholly owned subsidiary of OE whose bor-pre-rowings are secured by customer accounts receivable. OES 9

Capital can borrow up to $170 million under a receivables financing agreement at rates based on certain bank com-mercial paper and is required to pay an annual fee of 0.50%

on the amount of the entire finance limit. The receivables financing agreement expires in October 2004.

1 IFirstEnergy and its subsidiaries have various credit 1 :'

facilities (including a FirstEnergy $375 million short-term revolving credit facility) with domestic and foreign banks' that provide for borrowings of up to $604 million under var-irate ious interest rate options. To assure the availability of these L.

lines, FirstEnergy and its subsidiaries are required to pay ited annual commitment fees that vary from 0.20% to 0.375%.

tunlty These lines expire at various times during 2004. The weighted average interest rates on short-term borrowings outstanding as of December 31, 2003 and 2002 were 2.14% and 2.41 %, respectively.

7. COMMITMENTS, GUARANTEES ze AND CONTINGENCIES:

iat-(A) Capital Expenditures-FirstEnergy's current forecast reflects expenditures of approximately $2.3 billion for property additions and improvements from 2004-2006, of which approximately illat-

$713 million is applicable to 2004. Investments for additional ich nuclear fuel during the 2004-2006 period are estimated to be d-approximately $323 million, of which approximately $90 mil-d-

lion applies to 2004. During the same periods, the able Companies' nuclear fuel investments are expected to be reduced by approximately $285 million and $93 million, respectively, as the nuclear fuel is consumed.

(B) Nuclear Insurance-iable

• The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $10.9 billion.

nt The amount is covered by a combination of private insurance and an industry retrospective rating plan. The Companies' maximum potential assessment under the industry retro-spective rating plan would be $402 million per incident but not more than $40 million in any one year for each incident.

The Companies are also insured under policies for FirstEnergy Corp. 2003 61

each nuclear plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination costs. The Companies have also obtained approximately

$1.2 billion of insurance coverage for replacement power costs. Under these policies, the Companies can be assessed a maximum of approximately $64 million for inci-dents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds avail-able to the insurer for paying losses.

The Companies intend to maintain insurance against nuclear risks as described above as long as it is available.

To the extent that replacement power, property damage, decontamination, repair and replacement costs and other such costs arising from a nuclear incident at any of the Companies' plants exceed the policy limits of the insur-ance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Companies' insurance policies, or to the extent such insur-ance becomes unavailable in the future, the Companies would remain at risk for such costs.

(C) Guarantees and Other Assurances-As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third par-ties. Such agreements include contract guarantees, surety bonds and ratings contingent collateralization provisions.

As of December 31, 2003, outstanding guarantees and other assurances aggregated approximately S1.9 billion.

FirstEnergy guarantees energy and energy-related pay-ments of its subsidiaries involved in energy marketing activities - principally to facilitate normal physical transac-tions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisi-tion of property, plant and equipment. These agreements legally obligate FirstEnergy and its subsidiaries to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guar-antee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood that such parental guarantees of $1.0 billion (included in the $1.9 bil-lion discussed above) as of December 31, 2003 will increase amounts otherwise to be paid by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities is remote.

While guarantees are normally parental commitments for the future payment of subsidiary obligations, subse-quent to the occurrence of a credit rating-downgrade or "material adverse event" the immediate payment of cash collateral or provision of a letter of credit may be required.

The following table summarizes collateral provisions as of December 31, 2003:

Collateral Paid Remaining Collateral Provisions Exposure Cash Letters of Credit Exposure"'

(In millions)

Rating downgrade S187 S68

$5

$114 Adverse Event 235 65 170 Total 5422

$68

$70

$284

"' As of February 11. 2004, we had a remaining exposure of S282 million with $106 million of cash and $87 million of letters of credit provided as collateral 62 FirstEnergy Corp 20)3 Most of FirstEnergy's surety bonds are backed by vari-ous indemnities common within the insurance industry.

Surety bonds and related FirstEnergy guarantees of $161 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a num-ber of areas including construction jobs, environmental commitments and various retail transactions.

FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $6 mil-lion (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee.

FirstEnergy had provided the TEBSA project lenders a S50 million letter of credit (LOCI (under FirstEnergy's existing

$250 million LOC capacity available as part of a $1.25 billion FirstEnergy credit facility) to obtain TEBSA lender consent as substitute collateral for the release of the assets for FirstEnergy to abandon its Argentina operations, Emdersa (see Note 3). In December 2003, a replacement LOC was issued in the amount of $60 million, which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. This LOC granted FirstEnergy the ability to sell its remaining 20.1 % interest in Avon, as well as abandon the Argentina assets in April 2003.

(D) Environmental Matters-Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and com-petitive position. These environmental regulations affect FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, FirstEnergy believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $91 million for 2004 through 2006, which is included in the $2.3 billion of forecasted capital expenditures for 2004 through 2006 (see Note 7(A)). Additional estimated capital expenditures forecast of $481 million relating to pro-posed environment laws could be required after 2006.

Clean Air Act Compliance The Companies are required to meet federally approved sulfur dioxide (S02) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to

$31,500 for each day the unit is in violation. The Environmental Protection Agency (EPA) has an interim enforcement policy for S02 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

The Companies are complying with S02 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances.

NOx reductions required by the 1990 Amendments are being

achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reduc-tions from the Companies' Ohio and Pennsylvania facilities.

The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states {including Michig6an, New Jersey, Ohio and Pennsylvania) and the District of Columbia based sion a cantlytoon that such NOx emissions are contributing significantly to ozone pollution in the eastern United States.

State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets established by the EPA. New Jersey and Pennsylvania submitted a SIP that required compliance with the NOx budgets at the Companies' New Jersey and Pennsylvania facilities by May 1, 2003. Michigan and Ohio submitted a SIP that requires compliance with the NOx budgets at the Companies' Michigan and Ohio facilities by May 31, 2004.

National Ambient Air Quality Standards In July 1997, the EPA promulgated changes in the National Ambient Air Quality Standard (NAAQS) for ozone and proposed a new NAAQS for fine particulate matter. On December 17, 2003, the EPA proposed the "Interstate Air Quality Rule" covering a total of 29 states (including New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air pollution emissions from 29 eastern states and the District of Columbia signifi-cantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states.

The EPA has proposed the Interstate Air Quality Rule to "cap-and-trade" NOx and S02 emissions in two phases (Phase I in 2010 and Phase II in 2015). According to the EPA, S02 emissions would be reduced by approximately 3.6 million tons in 2010, across states covered by the rule, with reductions ultimately reaching more than 5.5 million tons annually. NOx emission reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in 2015.

The future cost of compliance with these proposed regula-tions may be substantial and will depend on whether and how they are ultimately implemented by the states in which the Companies operate affected facilities.

Mercury Emissions In December 2000, the EPA announced it would pro-ceed with the development of regulations regarding hazardous air pollutants from electric power plants, identi-fying mercury as the hazardous air pollutant of greatest concern. On December 15, 2003, the EPA proposed two different approaches to reduce mercury emissions from coal-fired power plants. The first approach would require plants to install controls known as "maximum achievable control technologies" (MACT) based on the type of coal burned. According to the EPA, if implemented, the MACT proposal would reduce nationwide mercury emissions from coal-fired power plants by fourteen tons to approximately thirty-four tons per year. The second approach proposes a cap-and-trade program that would reduce mercury emis-sions in two distinct phases. Initially, mercury emissions would be reduced by 2010 as a "co-benefits" from imple-mentation of S02 and NOx emission caps under the EPA's proposed Interstate Air Quality Rule. Phase II of the mercu-ry cap-and-trade program would be implemented in 2018 to cap nationwide mercury emissions from coal-fired power plants at fifteen tons per year. The EPA has agreed to choose between these two options and issue a final rule by December 15, 2004. The future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Conmpliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addi-tion, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S.

District Court for the Southern District of Ohio. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently sched-uled to be ready for trial beginning July 19, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the rul-ing, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act."

The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substan-tive remedial measures that may be required, could have a material adverse impact on FirstEnergy's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of December 31, 2003.

Regulation of Hazardous Waste I As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state haz-ardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash,;

were exempted from hazardous waste disposal require-ments pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regula-tion of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste.

The Companies have been named as "potentially responsible parties" (PRPs) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsub-stantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, environmental liabilities FirstEnergy Corp. 2003 63

that are considered probable have been recognized on the Consolidated Balance Sheet as of December 31, 2003, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable societal benefits charge. Included in Current Liabilities and Other Noncurrent Liabilities are accrued liabilities aggregating approximately $65 million as of December 31, 2003. The Companies accrue environmen-tal liabilities only when they can conclude that it is probable that they have an obligation for such costs and can reason-ably determine the amount of such costs. Unasserted claims are reflected in the Companies' determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

Climate Change In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the U.S.

Senate required for ratification. However, the Bush admin-istration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity - the ratio of emissions to economic output -

by 18% through 2012.

The Companies cannot currently estimate the financial impact of climate change policies although the potential restrictions on carbon dioxide (CO2) emissions could require significant capital and other expenditures. However, the C02 emissions per kilowatt-hour of electricity generated by the Companies is lower than many regional competitors due to the Companies' diversified generation sources which includes low or non-CO2 emitting gas-fired and nuclear generators.

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

(E) Other Legal Proceedings-Various lawsuits, claims for personal injury, asbestos and property damage and proceedings related to FirstEnergy's normal business operations are pending against FirstEnergy and its subsidiaries. The most signifi-cant not otherwise discussed above are described below.

Power Outages In July 1999, the Mid-Atlantic states experienced a severe heat storm which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmis-sion and distribution systems of all four New Jersey electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provid-ed unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently con-solidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service inter-ruptions in the JCP&L territory.

Since July 1999, this litigation has involved a substantial amount of legal discovery including interrogatories, request for production of documents, preservation and inspection of evidence, and depositions of the named plaintiffs and many JCP&L employees. In addition, there have been many motions filed and argued by the parties involving issues such as the primary jurisdiction and findings of the NJBPU, con-sumer fraud by JCP&L, strict product liability, class decertification, and the damages claimed by the plaintiffs. In January 2000, the NJ Appellate Division determined that the trial court has proper jurisdiction over this litigation. In August 2002, the trial court granted partial summary judg-ment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresen-tation, and strict products liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings have been appealed to the Appellation Division and oral argument is scheduled for May 2004. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of December 31, 2003.

On August 14, 2003, various states and parts of south-ern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. FirstEnergy continues to accumu-late data and evaluate the status of its electrical system prior to and during the outage event, and continue to cooperate with the U.S.-Canada Power System Outage Task Force (Task Force) investigating the August 14th outage. The inter-im report issued by the Task Force on November 18, 2003 concluded that the problems leading to the outage began in FirstEnergy's service area. Specifically, the interim report con-cludes, among other things, that the initiation of the August 14th outage resulted from the coincidence on that afternoon of the following events: (1) inadequate situational awareness at FirstEnergy; (2) FirstEnergy's failure to adequately manage tree growth in its transmission rights of way; and (3) failure of the interconnected grid's reliability organizations (Midwest Independent System Operator and PJM Interconnection) to provide effective diagnostic support. FirstEnergy believes that the interim report does not provide a complete and compre-hensive picture of the conditions that contributed to the August 14th outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. On November 25, 2003, the PUCO ordered FirstEnergy to file a plan with the PUCO no later than March 1, 2004, illustrating how FirstEnergy will correct problems identified by the Task Force as events contributing to the August 14th outage and addressing how FirstEnergy proposes to upgrade its control room computer hardware 64 F,5tEfnergy Corp. 2003

and software and improve the training of control room oper-ators to ensure that similar problems do not occur in the future. The PUCO, in consultation with the North American Electric Reliability Council, will review the plan before deter-mining the next steps in the proceeding. On December 24, 2003, the FERC ordered FirstEnergy to pay for an independ-ent study of part of Ohio's power grid. The study is to examine the stability of the grid in critical points in the Cleveland and Akron areas; the status of projected power reserves during summer 2004 through 2008; and the need for new transmission lines or other grid projects. The FERC ordered the study to be completed within 120 days. At this time, it is unknown what the cost of such study will be, or the impact of the results.

Davis-Besse FENOC recently received a subpoena from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the David-Besse plant. We are unable to predict the out-come of this investigation. In addition, FENOC remains subject to possible civil enforcement action by the NRC in connection with the events leading to the Davis-Besse out-age. If it were ultimately determined that FirstEnergy has legal liability or is otherwise made subject to regulatory or civil enforcement action with respect to the Davis-Besse outage, it could have a material adverse effect on FirstEnergy's financial condition and results of operations.

Other Legal Matters Various legal proceedings have been filed against FirstEnergy in connection with, among other things, the restatements in August 2003, by FirstEnergy and its Ohio utility subsidiaries of previously reported results, the August 14th power outage described above, and the extended out-age at Davis-Besse Nuclear Power Station. Depending upon the particular proceeding, the issues raised include alleged violations of federal securities laws, breaches of fiduciary duties under state law by FirstEnergy directors and officers, and damages as a result of one or more of the noted events. The securities cases have been consolidated into one action pending in federal court in Akron. The derivative actions filed in federal court likewise have been consolidat-ed as a separate matter, also in federal court in Akron.

There are also pending derivative actions in state court.

FirstEnergy's Ohio utility subsidiaries also were named as respondents in two regulatory proceedings initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14th power outage. FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory' proceedings or legal actions may be instituted against them. In particular, if FirstEnergy were ultimately deter-mined to have legal liability in connections with these proceedings, it could have a material adverse effect on its financial condition and results of operations.

be considered a reportable segment. "Other" consists of interest expense related to the 2001 merger acquisition debt; the corporate support services operating segment and the international businesses acquired in the 2001 merger. The international business assets reflected in the 2001 "Other" assets amount included assets in the United Kingdom identified for divestiture (see Note 3 -

Divestitures) which were sold in 2002. As those assets were in the process of being sold, their performance was not being reviewed by a chief operating decision maker and in accordance with SFAS 131, "Disclosures about Segments of an Enterprise and Related Information," did not qualify as an operating segment. The remaining assets and revenues for the corporate support services and the remaining international businesses were below the quan-tifiable threshold for operating segments for separate disclosure as "reportable segments." FirstEnergy's primary segment is its regulated services segment, whose opera-tions include the regulated sale of electricity and distribution and transmission services by its eight electric utility operating companies in Ohio, Pennsylvania and New Jersey (OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec and ATSI). The competitive services business segment consists of the subsidiaries (FES, FSG, MYR, MARBEL and First Communications) that operate unregulated energy and energy-related businesses, including the operation of gen-eration facilities of OE, CEI, TE and Penn resulting from the deregulation of the Companies' electric generation busi-ness (see Note 2(D) - Regulatory Matters).

The regulated services segment designs, constructs, operates and maintains FirstEnergy's regulated transmis-sion and distribution systems. It also provides generation services to regulated franchise customers who have not chosen a competing generation supplier. The regulated'-

services segment obtains a portion of its required genera-tion through power supply agreements with the competitive services segment.

-The competitive services segment includes all domestic unregulated energy and energy-related services including commodity sales (both electricity and natural gas) in the retail and wholesale markets, marketing, generation and sourcing of commodity requirements, as well as other com-petitive energy-application services. Competitive products are increasingly marketed to customers as bundled services.

Segment financial data in 2002 has been adjusted to reflect the reclassification of revenue, expense, interest expense and tax amounts of divested businesses reflected as discontinued operations (see Note 2(l)).

8. SEGMENT INFORMATION:

FirstEnergy operates under two reportable segments:

regulated services and competitive services. The aggregate "Other" segments do not individually meet the criteria to FirstEnergy Corp. 2003 65

Segment Financial Information Regulated Competitive Reconciling Services Services Other Adjustments Consolidated (In millions) 2003 External revenues

$8.978 S3.234

$ 71

$ 24 (a) 312.307 Internal revenues 1.092 2,168 547 (3,807) (b)

Total revenues 10,070 5.402 618 13.783) 12,307 Depreciation and amortization 1,209 33 40 1,282 Goodwill impairment 117 117 Net interest charges 499 44 344 (75) (b) 812 Income taxes 650 (126) 1118) 406 Income before discontinued operations and cumulative effect of accounting change 885 (205)

(258) 422 Discontinued operations

16)

(95)

(101) 2003 2002 Geographic Information' Revenues Assets Revenues Assets (In millions)

United States

$12,282 332.826 311.753

$333628 Foreign countries' 25 84 294 758 Total 12.307 i332910 312.047 S34.385 See Note 3 for discussion of divestitures of business operations and Note 2(1) for discussion of discontinued operations.

9. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS FASB Staff Position (FSP) 106-1 'Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Cumulative effect of accounting change Net income Total assets 29 Total goodwill 5

Property additions 2002 External revenues Internal revenues Total revenues Depreciation and amortization Net interest charges Income taxes Income before discontinued operations Discontinued operations Net income Total assets Total goodwill Property additions 39 10 Issued Janaury 12, 2004, FSP 106-1 permits a sponsor 986 (210)

(353) 423 of a postretirement health care plan that provides a pre-3789 2.335 766 32,910 scription drug benefit to make a one-time election to defer

.993 135 6,128 accounting for the effects of the Medicare Prescription 434 345 77 856 Drug, Improvement and Modernization Act of 2003 (the Act). The Company has elected to defer the effects of the

.166 52.482 S 336 8 13 (a) 312,047 Act due to the lack of specific guidance. Any measure of

.052 2.044 478 13.574) (b) the accumulated postretirement benefit obligation or net

.218 4,526 864 13.561) 12,047 periodic postretirement benefit cost in the financial state-

,235 28 35 1.298 ments or the accompanying notes do not reflect the impact 588 44 384 (58) (b) 958 of the Act on the plans. At this time, specific authoritative 598 (87)

(87) 524 guidance on the accounting for the federal subdsidy provid-ed by the Act is pending and that guidance could require 928 (111)

(184) 633 the Company to change previously reported information.

928 30,494 5,993 490 2

(109) 2,281 285 403 (82) 1266) 1,611 105 (80) 553 34.386 6.278 998 2001 Externalrevenues 35.729 32.165 3 11 S 94 (a)

S7.999 Internal revenues 1,645 1.846 350 13.841) lb)

Total revenues 7.374 4.011 361 13.747) 7.999 Depreciation and amortization 841 21 28 890 Net interest charges 571 25 74 1114) (b) 556 Income taxes 537 (23)

(40) 474 Income before cumulative effect of accounting change 729 (23)

(51) 655 Net income 729 (32)

(51) 646 Total assets 28,054 2.981 6,317 37.352 Total goodwill 5.325 276 5,601 Property additions 447 375 30 852 Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting:

la) Principally fuel marketing revenues which are reflected as reductions to expenses for internal management reporting purposes.

lb) Elimination of intersegment transactions.

Products and Services' Energy Related Year Electricity Sales Oil & Gas Sales Sales and Services (In millions) 2003 310,267 S624

$766 2002 9,697 613 904 2001 6,078 792 693 FIN 46 (revised December 2003), 'Consolidation of Variable Interest Entities' In December 2003, the FASB issued this revised inter-pretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements". This Interpretation, referred to below as "FIN 46R", requires the consolidation of a VIE by an enterprise if that enterprise either absorbs a majority of the VIE's expected losses or receives a majority of the VIE's expected residual returns as a result of owner-ship, contractual or other financial interests in the VIE. Prior to FIN 46R, entities were generally consolidated by an enterprise that had a controlling financial interest through ownership of a majority voting interest in the entity.

FIN 46R defines a VIE as an entity in which equity investors do not have the characteristics of a controlling financial interest nor have sufficient equity at risk for the enti-ty to finance its activities without additional subordinated financial support. Adoption of FIN 46R is required of public entities that have interests in VIEs or potential VlEs common-ly referred to as special-purpose entities for periods ending after December 15, 2003. Adoption by public entities for all other types of entities is required for periods ending after March 15, 2004 (FirstEnergy's first quarter of 2004).

FirstEnergy currently has transactions with entities in connection with sale and leaseback arrangements which fall within the scope of this interpretation and which meet the definition of a VIE in accordance with FIN 46R. Upon adoption of FIN 46R effective December 31, 2003, FirstEnergy consolidated two VlEs; the PNBV Capital Trust (PNBV) and the Shippingport Capital Trust were created in 1996 and 1997, respectively, to refinance debt in connec-tion with these sale and leaseback transactions.

PNBV issued equity and notes to fund the acquisition 66 Fi.stEne'gy Co;)

20'(tA

of a portion of the collateralized lease bonds that had been issued by certain owner trusts in connection with the sale and leaseback in 1987 of a portion of OE's interest in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issue6d by the PNBV Capital Trust. Ownership of the trust includes a three-per-cent equity interest by a nonaffiliated third party and a three-percent equity interest held by OES Ventures, a whol-ly owned subsidiary of OE. Consolidation of the trust as of December 31, 2003 changed the PNBV trust investment of

$361 million to an investment in collateralized lease bonds of $372 million. The increase in $11 million represents the minority interest in the total assets of the trust.

Shippingport was established to purchase all of the lease obligation bonds issued by the owner trusts in the Bruce Mansfield Plant sale and leaseback transactions in 1987. CEI and TE acquired all of the notes issued by Shippingport Capital Trust. Upon adoption of FIN 46R, this entity was consolidated on the books of CEI; the obligation to the trusts was previously recorded on the books of both CEI and TE. Consolidation of this entity therefore had no i

impact on the financial statements of FirstEnergy.

In addition to the two entities created to refinance debt discussed above, the Company evaluated its interest in the owner trusts that acquired the interests in the Perry Plant, Beaver Valley Unit 2 and the Bruce Mansfield Plant.

FirstEnergy concluded that the operating companies (OE, CEI and TE) were not the primary beneficiaries of these owner trusts and were therefore not required to consoli-date these entities. The leases are accounted for as operating leases in accordance with GAAP and their related obligations are disclosed in Note 4. The combined pur-chase price of $3.1 billion for all of the interests acquired by the owner trusts in 1987 was funded with debt of $2.5 billion and equity of $600 million.

FirstEnergy is exposed to losses under the sale-lease-back agreements upon the occurrence of certain contingent events that we consider unlikely to occur. The Company's maximum exposure to loss is currently estimated to be

$2.0 billion, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the plants worthless. Under the sale and leaseback agreements, FirstEnergy has minimum undis-counted net lease payments of $2.6 billion that would not be payable if the casualty value payments are made. In addition, the Company has recorded above market lease obligations of $1.1 billion, of which $85 million is current, related to the Bruce Mansfield Plant and Beaver Valley Unit 2 as of December 31, 2003 related to the acquisition by FirstEnergy of CEI and TE.

As described in Note 5(G), CEI, Met-Ed and Penelec created statutory business trusts to issue trust preferred securities in the aggregate of $285 million. Prior to the adoption of FIN 46R, these trusts had been consolidated by FirstEnergy and the respective operating company.

Application of the guidance in FIN 46R resulted in the hold-ers of the preferred securities being considered the primary beneficiaries of these trusts. Therefore, FirstEnergy, CEI, -Met-Ed and Penelec have deconsolidated the trusts. As of December 31, 2003, FirstEnergy reported subordinated debentures to the respective trusts of $294 million ($103 million for CEI, $96 million for Met-Ed and

$95 million for Penelec) within the balance sheet liability caption "Subordinated debentures to affiliated trusts" and the equity investment in the trusts of $9 million ($3 million each for CEI, Met-Ed and Penelec) within the balance sheet asset caption "Investments - Other."

In August 1995, Los Amigos Leasing Company, Ltd.

(Los Amigos) was formed as a consolidated subsidiary of GPU Power to own and lease to TEBSA equipment com-prised of an 895 megawatt plant constructed and operated by TEBSA. Upon application of FIN 46R, Los Amigos met the criteria of a VIE and FirstEnergy was determined not to be its primary beneficiary. Therefore, effective December 31, 2003 Los Amigos was deconsolidated, resulting in the removal of approximately $243 million of total assets (prima-rily unbilled lease receivable) and liabilities (primarily senior and subordinated debt) from FirstEnergy's Consolidated Balance Sheets. Los Amigos was sold as part of the TEBSA divestiture on January 30, 2004.

FirstEnergy is evaluating other entities that meet the deferral criteria and may be subject to consolidation under FIN 46 as of March 31, 2004. Included in this analysis are non-utility generators in which we have neither debt nor equity investments but are generally the sole purchaser of their power.

SFAS 132 (revised December 2003), 'Employers' Disclosures about Pensions and Other Postretirement Benefits - An amendment of FASB Statements No. 87, 88, and 106 Issued by the FASB in December 2003 and effective for financial statements with fiscal years ending after December 15, 2003, this revision to SFAS 132 revises employers' dis-closures about pension plans and other postretirement benefits plans. SFAS 132 (as revised) does not change the measurement or recognition of those plans as required by FASB Statements No. 87, 88, and 106, but requires addition-al disclosures about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans. FirstEnergy has included the additional disclosure requirements in Note 2(K) - Pension and Other Postretirement Benefit Plans.

EITF Issue No. 03-1 'The Meaning of Other-Than Temporary Impairment and its Application to Certain Investments" In November 2003, the EITF reached consensus that certain quantitative and qualitative disclosures are required for debt and equity securities classified as available-for-sale or held-to-maturity. The guidance requires the disclosure of the aggregate amount of unrealized losses and the aggre-gate related fair value for investments with unrealized losses that have not been recognized as other-than-tempo-rary impairments. FirstEnergy has adopted the disclosure requirements of EITF Issue No. 03-1 as of December 31, 2003 (See Note 10(E)).

EITF Issue No. 03-11, 'Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to SFAS No 133, Accounting for Derivative Instruments and Hedging Activities, and Not "Held for Trading Purposes" as Defined in EITF Issue 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities."

In July 2003, the EITF reached a consensus that deter-mining whether realized gains and losses on physically FirstEnergy Corp. 2003 67

settled derivative contracts not "held for trading purposes" should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the rele-vant facts and circumstances. The consideration of the facts and circumstances, including economic substance, should be made in the context of the various activities of the entity rather than based solely on the terms of the indi-vidual contracts. The Company adopted this consensus effective January 1, 2004. The impact on operating rev-enues and operating expenses has not been determined but is not expected to be material. The adoption of EITF C3-11 will have no impact on net income.

DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b)

Regarding Contracts with a Price Adjustment Feature' In June 2003, the FASB cleared DIG Issue C20 for implementation in fiscal quarters beginning after July 10, 2003. The issue supersedes earlier DIG Issue C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance regarding when the presence of a general index, such as the Consumer Price Index, in a contract would prevent that contract from qualifying for the normal purchases and nor-mal sales exception under SFAS 133, as amended, and therefore exempt from the mark-to-market treatment of certain contracts. Adoption of DIG Issue C20 did not have a material impact on the Companies' financial statements.

EITF Issue No. 0 1-8, 'Determining Whether an Arrangement Contains a Lease' In May 2003, the EITF reached a consensus regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if: (1) it identi-fies specific property, plant or equipment (explicitly or implicitly); and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus is to be applied prospectively to arrangements committed to, modified or acquired through a business combination after the effective date of the consensus. The adoption of this consensus as of July 1, 2003 did not affect FirstEnergy's financial statements.

dividends were previously included in net interest charges and required no reclassification.

SFAS 149, 'Amendment of Statement 133 on Derivative Instruments and Hedging Activities' Issued by the FASB in April 2003, SFAS 149 further clarifies and amends accounting and reporting for deriva-tive instruments. The statement amends SFAS 133 for decisions made by the Derivative Implementation Group (DIG), as well as issues raised in connection with other FASB projects and implementation issues. The statement was effective for contracts entered into or modified after June 30, 2003 except for implementation issues that were effective for reporting periods beginning before June 15, 2003, that continue to be applied based on their original effective dates. Adoption of SFAS 149 did not have a mate-rial impact on the Companies' financial statements.

SFAS 143, "Accounting for Asset Retirement Obligations" The Company adopted SFAS 143 effective January 1, 2003. The impact of this new accounting standard is discussed above under Notes 2(F) and 2(J).

FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57 and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpre-tation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002. It also clari-fies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guid-ance was applicable on a prospective basis to guarantees issued or modified after December 31, 2002. Adoption of FIN 45 for guarantees issued during 2003 did not have a material impact on FirstEnergy's financial statements.

SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which estab-lishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both lia-bilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 was effective immediately for financial instruments entered into or modified after May 31, 2003 and effective at the begin-ning of the first interim period beginning after June 15, 2003 for all other financial instruments.

Upon adoption of SFAS 150, effective July 1, 2003, FirstEnergy reclassified as debt the preferred stock of consolidated subsidiaries subject to mandatory redemption with a carrying value of approximately $19 million ($5 million for CEI and $14 million for Penn) as of December 31, 2003.

Adoption of SFAS 150 had no impact on FirstEnergy's Consolidated Statements of Income because the preferred 68 FirsErnergy Corp. 2203

10. OTHER INFORMATION:

The following provides supplemental unaudited infor-mation to the consolidated financial statements and notes previously reported in 2001:

(A) Consolidated Statements of Cash Flows (Unaudited) 2003 N2002 2X1

,,,,~~~~~~~~~~~~~.,fl,,,m

-. i,- --.{n Thotisands),==..--b,-

Other Cash Flows From Operating Activities:

in Thousands)

Accruedtaxes

$219,936

$ 35108

$ 8915

-Accrued interest

.57,509)

127420) 117520 Retail rate refund obligation payments 171 9841:

143.0161 Interest rate hedge 11322761 -

Prepayments and other 131,1551 A133,677 1146.7411 Accrued retirement benefit obligations 282,604

j124.678 19797 Accrued compensation, net

'(74.4011 192.197) 11183251 Tax refund related to pre-merger period 51,073 Energy derivative transactions 170.498: -

8,682):

Asset retirement obligation 97,820 72

'AII other 17.349)

'3538 646

.Total-Other

$338,737.

$125,686

$1250.564)

Other Cash Flo ws from Investing Activities:

Retirements and tansfers-

$ 37580

$ 29,619

$ 40106

-I Nonutility generation trusts withdrawals 66327 49044 '

Contributions to nuclear decommissionin9 trusts (1 01 11 2) 103,143) 190995)

Nuclear decommissioning trust investments (143.493)

.16,922 17,614 9-',

-Long-term notes receivable 82,250 '

191.335)

'Other investments

.: 29,137 ---

(7,944).11-65938-

-All other- -

4LW." j.

42,273 52.482 -

134313)

Total-Other

.-,..a'.

$ 12,856.

$154,355)

$(233,526)

(B) Consolidated Statements of Taxes

<:t-, '-,,'- --a,,'->

.;,' :- f.'.~.,,",i'

.X,., :,:-.. :>,(Unaudited) -'

2003:

2002 2001 (In Thousands)

Other Accumulated Deferred Income Taxes as of December 31:-

Retirement Benefits ;$1359 038)

$1223 065)

$(133,282)

-Oyster Creek securitization (Note 5(H))

193 558

'202 447 Loss carryforwards 1495,254).

(507,690 x1486.495) A -

Loss'carryforwards valuation reserve 470,813 '

482,061

':-459,170

Purchase accounting basis differences (2,6571 -

--12.657)

(147,450)

' Sale of generating assets (11.785)-

.11.786)

207,787 Provision for rate refund,

(29 370) "

(46 942)

All other (49,569)

(149.226). (176.484)

Total-Other -

$)253.932)

$(239,286)

$(323,696)

(C) Revenues - Independent System Operator (ISO) Transactions FirstEnergy's regulated and competitive subsidiaries record purchase and sales transactions with PJM Interconnection ISO, an independent system operator, on a gross basis in accordance with EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent." The aggregate purchase and sales transactions for the three years ended December 31, 2003, are summa-rized as follows:

revenues from the PJM ISO from power sales (as reflected in the table above) during periods when FirstEnergy had additional available power capacity. Revenues also include sales by FirstEnergy of power sourced from the PJM ISO (reflected as purchases in the table above) during periods when FirstEnergy required additional power to meet its retail load requirements and, secondarily, to make sales to the wholesale market.

(D) Stock Based Compensation (2001 Unaudited)

Stock-based employee compensation expense recog-nized for the FirstEnergy Programs' restricted stock during 2003, 2002 and 2001 totaled $1,747,000, $2,259,000 and

$1,342,000, respectively. In addition, stock-based employ-ee compensation expense of $2,312,000, $206,000 and

$1,637,000 during 2003, 2002 and 2001, respectively, was recognized for EDCP stock units (see Note 5(C) for further discussion).

(E) SFAS 115 Activity Investments other than cash and cash equivalents in' the table in Note 2(M) - Cash and Financial Instruments include available-for-sale securities, at fair value, with the following net results:

=,

n.

(si--j-

--;g J Unaudi red) 2003' 2002*-

..2001 (In millions)

Unrealized gains losses)

$116

$(48),

Proceeds from sales i.

516

.421 Realizedgains(losses) 3 (15)

• Includes the available-for-sale securities of FirstEnergy's Ohio Companies' decommissioning trusts.

As of December 31, 2003 accumulated other compre-hensive income (loss) for available-for-sale securities consisted of investments with net unrealized gains of $153 million and net unrealized losses of $45 million. The follow-ing table provides details for the available-for-sale securities with net unrealized losses as of December 31, 2003.

Less Than 12 Months 12 Months or More Total,:

Fair Unrealized - Fair, Unrealized-- Fair Unrealized' Security Type' ':Value, Losses.'.Value

.- Losses Value Losses i,-,

- ln millions)

Equity Securities

$17

'-$5

'$43-

$40 60

$45 Debt Securities 33 33

-Total '-

$50.

$5-'-. -$43

>$40

$93

-$45-. T All of the aggregate unrealized losses related to avail-able-for-sale securities in the table above are considered to be temporary in nature. These securities are primarily held by the nuclear decommissioning trusts of FirstEnergy's Ohio Companies. FirstEnergy has the ability and intent to hold these securities for the period necessary to fund their cost.

7'(Unaudited) 2003 2002

-2001 :

(In millions),-'

- Sales

$990

• $45321

$142'i

[Purchases. :-

1,019 687:.', '_204-'.

FirstEnergy's revenues on the Consolidated Statements of Income include wholesale electricity sales FirstEnergy Corp. 2003 69

11.

SUMMARY

OF QUARTERLY FINANCIAL DATA (UNAUDITED):

The following summarizes certain consolidated operating results by quarter for 2003 and 2002.

Three Months Er ded (a)

March 31 June 30 SepL 30 Dec. 31 2003 2003 2003 2003 (In millions, except per share amounts)

S3,221 S2.853

$3.434

$2.799 2,806 2,619 2,947 2,463 168 Revenues Expenses Claim Settlement (Note 3)

Income Before Interest and Income Taxes 415 234 487 504 Net Interest Charges 206 205 201 200 Income Taxes 94 19 135 158 Income Before Discontinued Operations and Cumulative Effect of Accounting Change 115 10 151 146 Discontinued Operations (Net of Income Taxesl 2

1681 1

(36)

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

S219

$1581

$152

$110 Basic Earnings (Loss) Per Share of Common Stock:

Before Discontinued Operations and Cumulative Effect of Accounting Change SO.39 S0.03

$0.51

$0.44 Discontinued Operations 10.23)

(0.11)

Cumulative Effect of Accounting Change 0.35 Basic Earnings (Lossl Per Share of Common Stock 50.74

$10.20)

$0.51

$0.33 Diluted Earnings (Lossl Per Share of Common Stock:

Before Discontinued Operations and CumulativeEffect of Accounting Change

$0.39

$0.03

$0.50

$0.44 Discontinued Operations (0.231 (0.11)

Cumulative Effect of Accounting Change 0.35 Diluted Earnings (Loss)

Per Share of Common Stock SO.74

$(0.20)

$0.50

$0.33 March31 June30 Sept.30 Dec.31 Three Months Ended (a) 2003 2003 2003 2003 (In millions, except per share amounts)

Revenues

$2,810

$2.854 S3,407

$2,976 Expenses 2.322 2.232 2.684 2.694 Income Before Interest and Income Taxes 488 622 723 282 Net Interest Charges 278 249 220 211 Income Taxes 93 167 220 44 Income Before Discontinued Operations 117 206 283 27 Discontinued Operations (Net of Income Taxes) 1 2

2 (85)

Net Income (Loss)

$118

$208 S285 5S(58)

Basic Earnings (Loss)

Per Share of Common Stock:

Before Discontinued Operations

$0.40 S0.71

$0.96

$0.09 Discontinued Operations 0.01 (0.29)

Basic Earnings (Loss)

Per Share of Common Stock S0.40 S0.71

$0.97 SI0.20)

Diluted Earnings (Loss)

Per Share of Common Stock:

Before Discontinued Operations 50.40 50.70

$0.96

$0.09 Discontinued Operations 0.01 (0.29)

Diluted Earnings (Loss)

Per Share of Common Stock

$0.40

$0.70

$0.97

$10.20)

(a) Revenues, expcnses, net interest charges and income faxes have been revised to reflect reclassifications of the results of discontinued operations.

Net income for the three months ended December 31, 2003, was increased by S7.4 million due to adjustments relating to the first nine months of 2003. After-tax income of S16.3 million resulted from adjustments for costs charged to expense in prior quarters of 2003 that were subsequently capitalized to regulated segment construction projects in the fourth quarter, partially offset by after-tax charges of S8.9 million for adjustments relating to prior quarters for the com-petitive segment. Management concluded that these adjustments were not material to the reported consolidated results of operations for any quarter of 2003 (after-tax amounts of S3.1 million, $0.6 million and $3.7 million for the first three quarters of 2003, respectively). However, the adjustments relating to the regulated segment were material to the separate reported results of JCP&L, Penelec and TE; accordingly, the reported results of operations for the first three quarters of 2003 for those subsidiaries will be restated in their separate financial statements. The impact of these adjustments was not material to FirstEnergy's consolidated balance sheets or consolidated statements of cash flows for any quarter of 2003.

The net loss for the second quarter of 2003 included a charge resulting fromr the NJBPU's decision to disallow recovery by JCP&L of $153 million in deferred energy costs and a S67 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 S33 mil-lion after-tax loss from the divestiture of assets in Bolivia included in discontinued operations and a $26 million impair-ment of the equity TEBSA investment in Columbia included in continuing operations. The fourth quarter results also include a $170 million gain ($168 million net of expenses) from the NRG Energy Inc. settlement claim.

The operating results in 2002 related to assets sold in 2003 have been reclassified as discontinued operations.

The fourth quarter discontinued operations include an $88 million loss from operations of the Argentina assets.

12. GPU MERGER (UNAUDITED):

On November 7, 2001, the merger of FirstEnergy and GPU became effective pursuant to the Agreement and Plan of Merger, dated August 8, 2000 (Merger Agreement). As a result of the merger, GPU's former wholly owned sub-sidiaries, including JCP&L, Met-Ed and Penelec, (collectively, the Forner GPU Companies), became wholly owned subsidiaries of FirstEnergy. Under the terms of the Merger Agreement, GPU shareholders received the equiva-lent of $36.50 for each share of GPU common stock they owned, payable in cash and/or FirstEnergy common stock.

GPU shareholders receiving FirstEnergy shares received 1.2318 shares of FirstEnergy common stock for each share of GPU common stock they exchanged. The cash portion of the merger consideration was approximately S2.2 billion and nearly 73.7 million shares of FirstEnergy common stock were issued to GPU shareholders for the share portion of the transaction consideration.

The merger was accounted for by the purchase method of accounting and, accordingly, the Consolidated Statements of Income include the results of the Former GPU Companies beginning November 7, 2001. The assets acquired and liabilities assumed were recorded at estimat-ed fair values as determined by FirstEnergy's management based on information currently available and on current assumptions as to future operations. The merger purchase 70 FrstEne'q, Cc:.).003

accounting adjustments, which were recorded in the records of GPU's direct subsidiaries, primarily consist of:

(1) revaluation of GPU's international operations to fair value; (2) revaluation of property, plant and equipment; (3) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair vaiue; (4) recognizing additional obligations related to retirement benefits; and (5) recognizing estimated severance and other compensation liabilities. Other assets and liabilities were not adjusted since they remain subject to rate regulation on a historical cost basis. The severance and compensation liabilities are based on anticipated workforce reductions reflecting dupli-cate positions primarily related to corporate support groups including finance, legal, communications, human resources and information technology. The workforce reductions rep-resented the expected reduction of approximately 700 employees at a cost of approximately $140 million. Merger related staffing reductions began in late 2001 and the remaining reductions occurred in 2003 as merger-related transition assignments were completed.

The merger greatly expanded the size and scope of FirstEnergy's electric business and the goodwill recognized primarily relates to the regulated services segment. The combination of FirstEnergy and GPU was a key strategic step in FirstEnergy achieving its vision of being the leading energy and related services provider in the region. The merger combined companies with the management, employee experience and technical expertise, retail cus-tomer base, energy and related services platform and financial resources to grow and succeed in a rapidly chang-ing energy marketplace. The merger also allowed for a natural alliance of companies with adjoining service areas and interconnected transmission systems to eliminate duplicative costs, maximize efficiencies and increase man-agement and operational flexibility in order to enhance operations and become a more effective competitor.

Under the purchase method of accounting, tangible and identifiable intangible assets acquired and liabilities assumed are recorded at their estimated fair values. The excess of the purchase price, including estimated fees and expenses related to the merger, over the net assets acquired is classified as goodwill and amounts to $3.8 bil-lion as of December 31, 2003. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed on the date of acquisition.

tions of GPU's international operations as of the date of the merger; (3) establishment of a reserve for deferred energy costs recognized prior to the merger; and (4) return to accru-al adjustments for income taxes. As a result of these and other minor adjustments, goodwill increased by approxi-mately $286 million as of December 31, 2002. The increase was attributable to the regulated services segment.

The following pro forma combined condensed state-ment of income of FirstEnergy give effect to the FirstEnergy/GPU merger as if it had been consummated on January 1, 2001, with the purchase accounting adjust-menrts actually recognized in the business combination.

The pro forma adjustments reflect a reduction in debt from application of the proceeds from certain pending divesti-tures as well as the related reduction in interest costs.

,':Year Ended December 31. 201 (In millions exceptpershareamounts)

IRevenues

$12,108-Expenses 9,768:-

Income Before Interest and Income Taxes 2,340 Net Interest Charges 941 Income Taxes 561

' Net Income -

$838 Earnings per Share of Common Stock -

$2.87 I

-

,
.. ;.

. t

7,. ",

i, 7 7 7

. (In millions)

,-

'
11 !
-
I

-1 ':
-,

Current assets a r

a-

,027-Goodwvill-;.

~ :,

00"=

3698'te,-,-

j

.Regulator assets;-.

3592 -,;

Other 5

,595 TJotal assetsacqui.red 14,672 Current liabilities

-: 12 615)

'Long-term debt 2 1(2.9921:-

2Other-;-:

-4,851

-Totalliabilitiesassumed -

110392)

Net assets acquired pending sale 566 Net assets acquired -:

=-

'$4,846 During 2002, certain pre-acquisition contingencies and other final adjustments to the fair values of the assets acquired and liabilities assumed were reflected in the final allocation of the purchase price. These adjustments primarily related to: (1) final actuarial calculations related to pension and postretirement benefit obligations; (2) updated valua-FirstEnergy Corp. 2003 71

CONSOLIDATED FINANCIAL AND PRO FORMA COMBINED OPERATING STATISTICS (UNAUDITED)

(Dollars in thousands)

I I i-i A

203 2002 2001 2000 1999 1998 1993 (see Note 2(lN)

GENERAL FINANCIAL INFORMATION Revenues

$12,307,047

$12,047,348

$7,999,362

$7,028,961

$6,319,647

$5,874,906

$2,399,794 Net Income

$422.764,.

$552,804

$646,447

$598,970

$568,299

$410,874

$59,017 SEC Ratio of Earnings to Fixed Charges 1.72 1.90 2.22 2.10 2.01 1.77 1.12 Capital Expenditures

$791,834

$903,606

$887,929

$568,711

$474,118

$305,577

$263,179 Total Capitalization(a)

$18,413,530

$18,686,388

$21,339,001

$11,204,674

$11,469,795

$11,756,422

$5,656,295 Capitalization Ratios (a):

Common Stockholders' Equity 45.0 37.7%

34.7%

41.5#

39.8%

37.9%

39.7%

Preferred and Preference Stock:

Not Subject to Mandatory Redemption 1.8 1.8 2.2 5.8 5.7 5.6 5.8 Subject to Mandatory Redemption 2.3 2.8 1.4 2.2 2.5 0.8 Long-Term Debt 532 58.2 60.3 51.3 52.3 54.0 53.7 Total Capitalization 100.0%

100.0%

100.0%

100.0%

100.0%

100.0%

100.0%

Average Capital Costs:

Preferred and Preference Stock 47%

7.50%

7.90%

7.92%

7.99%

8.01%

6.86%

Long-Term Debt 6.08%

6.56%

6.98%

7.84%

7.65%

7.83%

8.27%

COMMON STOCK DATA Earnings per Share (b):

Basic

$1.39

$2.16

$2.85

$2.69

$2.50

$1.95

$1.82 Diluted

$1.39

$2.15

$2.84

$2.69

$2.50

$1.95

$1.82 Return on Average Common Equity (b) 5.6%

8.4%

12.9%

13.0%

12.7%

10.3%

11.4%

Dividends Paid per Share

$1.50

$1.50

$1.50

$1.50

$1.50

$1.50

$1.50 Dividend Payout Ratio (b) 108%

69%

53%

56%

60%

77%

82%

Dividend Yield 43%

4.5%

4.3%

4.8%

6.6%

4.6%

6.6%

Price/Earnings Ratio (b) 25.3 15.3 12.3 11.7 9.1 16.7 12.5 Book Value per Share

$25.35

$24.01

$25.29

$21.29

$20.22

$19.37

$14.70 Market Price per Share

.. $35.20

$32.97

$34.98

$31.56

$22.69

$32.56

$22.75 Ratio of Market Price to Book Value 135%

137%

138%

148%

112%

168%

155%

OPERATING STATISTICS (c)

Genraon KilowallourSales(Millioris-Residential

. 31,322 31,937 32,708 32,519 32,616 31,220 29,709 Commercial 32,310 32,892 32,170 33,139 30,311 31,033 27,012 Industrial 32,451 32,726 33,024 31,140 30,422 36,683 33,261 Other 554 531 536 522 566 611 1,422 Total Retail 96,637 98,086 98,438 97,320 93,915 99,547 91,404 Total Wholesale 42.062 30,007 20,240 13,761 14,631 9,910 11,953 Total Sales 138,699 128,093 118,678 111,081 108,546 109,457 103,357 Customers Served:

Residential 3,874,052 3,868,499 3,833,013 3,798,716 3,767,534 3,735,308 3,582,998 Commercial 496,253 471,440 464,053 472,410 455,919 447,087 415,637 Industrial

.10,871 18,416 18,652 18.996 19,549 19,902 21,920 Other 5,635 5,716 5.762 6,001 5,992 5,876 7,512 Total

-4,386,811 4,364,071 4,321,480 4,296,123 4,248,994 4,208,173 4,028,067 Number of Employees

'15,905 17,560 18,700 18,912 19,470 20.392 24,689 (a) 2001 capitalization includesapproximately $1.4billion 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, 200J (b/ Before discontinued operations in 2002 and 2003. accounting changes in 2003 and 2001 and an extraordinary charge in 1998 ci Reflects pro forma combined firstEnergy and 6PU statistics in the years 1998 to 2001 andpro forma combined Ohio Edison, Centerior and GPU statistics in years prior to 1998.

72 FirstEnergy Corp. 2003 Printed on recycled paper G)

I-.

Investor Services, Tran ent an egistrar Stock Investment Plan Weata u w rnsfer aget wn isn::v omnsochog h Cmay tc t

Weac-t~asour own transfer agent and registrar for all stoc Shreholders and others can purchase or sell shares of issues of FirstEnergyadnd i s subsidiarles. Shareholde Frsn'0 gh taS ing to transfer stock,or who need assistace oriformtion,:

vestme nt Plan I nvestors who are not registered share-

=trstock -orwrite t

o I

rervices,-

FirstEnergy holders can enroll with an initial $250 cash investment

-Corp.,

76 South Main St t,'Akron, Ohio 44308-1890

'Participants may invest all or someof their dividends orr

Shareholdersaiso can call the f i toll-free telephon-make optional cash payments at any time'of at least $25 number, which is valid in the United States' anada Puerto per payment up to $100 000 annually; Contact Investor 1--

'.Rico and theVirginr Islands, weekdays between 8 a. m. and';8 =-*;Services to receive an enrollment form.'

4:30 p.m.-Eastern time: 1-800-736-3402. For Internet access togeneral shareholderinformationandusefulforms visit our-Safekeeping of Shares-.

-Web site at wwwfirstenergycorp.conlir.n/-

Sf-.

=

=-

Shareholders 'can request that the Company hold their shares of FirstEnerg common stock insafekeeping. To take Stock Listings and Trading advantage'of this seric, shareholdersshould foardtheir Newspapersgenerally'report FirstEnergyc6onimon'stock

'_-stock certificate(s e

nyaongwit a l

r u-tnder the abbreviation FSTENGY, but this can vary depending requesting that the Company hold the shares. Shareholders upon the newspaper. The comrmon stoick-of FirstEnergy and ' -

also should state whether future dividends for the held.-

preferred stock of its electric utility subsidiaries are lsted-on shares are to be reinvested or paid in cash The certificate(s) the following stock exchanges:

should not be endorsed,and registered mail is suggesed.:

Stok xcane ymol The shares'will be held in -uncertifica~ted form, and we willI m-ake certifite(s) available to shareholders upon request F

,-.irstEnerg-New York FE at no cost. Shares held in safekeeping will be reported on The 'Ill'umina-tingzC'o'mpany New-~,'~

York

'VE-dven-idividend checks or Stock Investment Plan statements.-'-

Jersey Central NewYokrk jp Ohio Edison

'ewYork X-E Pennsylvania ower Philadlphia PPC ombining Stock Accounts

-Toledo Edison

-:New York;OTC '

-TED.

~

If you have more'than one stock account and want to A

i p'l combine them, piease write or call ln'vestor Seices and specify the account that you want to retain as well as the registration'of each of your accounts.

jt

Dividends -

Proposed dates for the payment of FirstEnergy common

-stock dividends in 2004 are: -

~

r 10-K Annual Repor TForm 1 0-K the Annual Report to the Securities and Exchange' Ex Dividend Date.

Reco'rd Date P a tD te ommission, will be sent without charge by writing to F.ebruary 4 r February 6

' a arch 1

-' David W. Whitehead, Corporate Secretary, FirstEnergy Corp.,

76 South Main Street Akron, Ohio 44308-1890" August 4 Augst6 etme 3

vembe er--

Institutional I nvestor and Security Analyst Inquiries Institutional investors and security analysts should direct inquiries

-Al dividends are subject to declaration by the Board of to Kurt E. Turosky Director Investor Relations 330-384-5500.

Directors in its discretion.

AnnulI Meeting f hareh olders Direct Dividend Deposit Shareholders are invited to attend the 2004 Annual Meeting

'Shareholders can have their dividend 'payments automatically of Shareholders on Tuesday, May 18-at 10 a.m. Eastern

[$

deposited to checking and savings accounts at any financial time at the John S. Knight Center,77 East Mill Street, -

i institution.that accepts electronic direct deposits Use of this in Akron, Ohio. Registered shareholders not attending-free service ensures that payments will be available to you the meting can appoint a proxy and ote on the items on the payment date,- eliminating the possibility of mail delay of busiress byteiephone Internet or by completing arid-or lost checks. Contact Investor Services to receive an, rerning th e

proxy card that is sent to them. Shareholders t't '

authorization form.

-whose shares are hed it e

r

't--meet t

ing if they present a letter from their broker,

- indicating ownership of FirstEnergy common stock on the record date of March 23, 2004.

FrteryCorp. 2003 73 7-

i. --:

-\\

7

.j

FirstEnergy 76 South Main Street, Akron, OH 44308-1890 www. firstenergycorp. corn PRESORTED STD.

U.S. POSTAGE PAID AKRON, OHIO PERMIT NO. 561 2003 ANNUAL REPORT