L-03-045, Firstenergy Corporation Retrospective Premium Guarantee

Firstenergy Corporation Retrospective Premium Guarantee

ML031130526
Person / Time
Site:	Beaver Valley, Davis Besse, Perry
Issue date:	04/04/2003
From:	Scilla R FirstEnergy Corp
To:	Dinitz I Office of Nuclear Reactor Regulation
References
-RFPFR, BV-No. L-03-045, DB-No.-2948, PY-CEI/NRR-2699L
Download: ML031130526 (61)

Text

fktmfierg 76 South Main Street Akron, Ohio 44308-1890 Randy ScIla

• 330384-5202 Assitant 7?easur& Fax: 330-384-3772 April 4, 2003 PY-CEI/NRR-2699L DB-No.-2948 BV-No. L-03-045 Mr. Ira Dinitz U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Washington, D.C. 20555 Dear Mr. Dinitz; Re: Docket Nos. 50-346, 50 440, 50412, 50-334 Retrospective Premium Guarantee Enclosed you will find the 2002 FirstEnergy Corp. Annual Report. This is in addition to the 2003 Internal Cash Flow Projection sent March 6, 2003 and completes the requirements for the Retrospective Premium Guarantee.

Very truly yours, I

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60 IIof FirstEnrgy

Electric Utility Operatig Companies El Ohio Edison Company

• Cleveland Electric Illuminating Company

• Toledo Edison Company

• Pennsylvania Power Company

• Pennsylvania Electric Company

• Metropolitan Edison Company

• Jersey Central Power & Light Company Corporate r fl FirstEnergy Corp. is a registered public utlity holding company headquartered in Akron, Ohio. FirstEnergy subsidiaries and affiliates - which produce approxtly $12 billion in annual revenues and own nearly

$34 billion in assets - are involved in the generation, transmission and distribution of electricity; exploration and production of oil and natural gas; transmission and markpting of natural gas;, energy management and other energy-related services.

FirstEnergy's seven electric utility operating companies comprise the nation's fourth largest investor-owned electric system, based on 4.3 million customers served within a 36,100-square-mile area that stretches from the Ohio-Indiana border to the New Jersey shore.

Contents 2 Message to Shareholders 8 Management's Discussion and Analysis 55 Shareholder Information 56 Officers 57 Directors

$12,152 $25.29 S24.25

$21.29

$7 999"

$7,029ad

[00 01 '02 '00 '01 '02 Total Revenues Book Value (Millions) Per Common Share Financial Highlights 2002 2001 (l (Dollars in thousands, except per share amounts)

Total revenues $12,151,997 $7,999,362 Income before cumulative effect of accounting changes' 2 ' $686,401 $654,946 Net income $629,280 $646,447 Basic earnings per common share:

Before cumulative effect of accounting changes $2.34 $2.85 After cumulative effect of accounting changes $2.15 $2.82 Diluted earnings per common share:

Before cumulative effect of accounting changes $2.33 $2.84 After cumulative effect of accounting changes $2.14 $2.81 Dividends per common share $1.50 $1.50 Book value per common share $24.25 $25.29 Net cash from operations $1,915,287 $1,281,684

"') Includes results from the former GPU, Inc., companies from November 7, 2001 - the effective date of the merger - through December 31, 2001.

(2) The 2002 accounting changes are described in Note 3 to the Consolidated Financial Statements under International Operations.

The 2001 accounting change is described in Note 2(J) to the Consolidated Financial Statements.

The following analysis reconciles basic earnings per share in 2002 and 2001 computed under generally accepted accounting principles (GAAP) to adjusted basic earnings per share excluding unusual charges in both years.

2002 2001 Adjusted basic earnings per share:

Basic earnings per share (GAAP) $2.15 $2.82 Cumulative effect of accounting changes 0.19 0.03 Davis-Besse extended outage impacts 0.47 Asset impairments 0.33 Retaining generating units planned for sale 0.15 Other unusual items (see Management's Discussion) 0.13 0.04 Adjusted basic earnings per share $3.42 $2.89 1

Message to Shareholders 2002 was a challenging year for "With the resolve of your Company, particularly related our employees and to costs associated with restart efforts at the Davis-Besse Nuclear Power a sound and focused Station and other unusual charges. business strategy, As a result, we did not realize we're confident that our earnings growth targets. However, we achieved solid results, including we'll deliver stronger continued debt reduction and record performance in 200VX H. Peter Burg, performance by our generating fleet, Chairman and CEO that are helping us realize our vision of being the leading retail energy and related services supplier in the Overcoming the Challenges at return to safe and reliable service so northeastern United States. Davis-Besse that it can provide long-term value For the year, basic earnings were A comprehensive inspection to our Company.

$2.15 per share, reflecting the $0 47 of Davis-Besse's reactor vessel head Recognizing that our success impact of Davis-Besse; $0.19 in charges during a refueling outage in March will depend as much on human related to planned sales of two inter- of 2002 revealed areas of corrosion performance as it will on equipment national assets that weren't completed; caused by boric acid that had leaked performance, we've strengthened

$0.15 for depreciation and transaction through cracks in control rod drive our nuclear management team and expenses associated with our decision mechanism nozzles, which pass oversight structure. We're taking to retain four coal-fired plants in Ohio; through the head. significant steps to enhance the plant's and $0 46 in other non-recurring Based on key industry measures, safety culture by rigorously implement-charges, descnbed in this report. Davis-Besse had been a strong ing a new safety policy and related Excluding these items, basic performer. However, as our own programs and procedures. And, we've earnings were $3 42 per share, under- investigation showed, former plant made key operational and system scoring that our foundation for management did not fully identify improvements, induding replacement growth is strong. With the resolve and address issues that we know, in of the damaged reactor head.

of our employees and a sound and hindsight, led to the corrosion prob- Physical work required for restart focused business strategy, we're lem at the plant. We're taking the is currently expected to be completed confident that we'll deliver stronger steps necessary to help ensure that this spring, but the final determination performance in 2003. this never happens again And we're of when Davis-Besse can return to encouraged by the progress we're service will be made by the Nuclear making in preparing Davis-Besse to Regulatory Commission. Your Board 2

of Directors is fully engaged in restart officer and an ethics policy in place, year annualized total shareholder efforts, and continues to dosely in addition to codes of business return - the market appreciation monitor changes we're making at the conduct that all employees must of common stock, induding the plant and throughout our FirstEnergy follow. And, we remain vigilant in reinvestment of dividends - of Nuclear Operating Company. And, I our commitment to ensure that you 19 percent ranked us ninth among have personally delivered to all nudear have accurate and complete informa- the 65 U.S. investor-owned electric employees the message that safety tion regarding the performance of utility companies that comprise the is our top priority, and it must your Company. Edison Electric Institute Index.

never be compromised for the sake Recognizing the Value of Delivering Results of production.

Our Strategy Enhancing our financial flexibility For the year 2002, incremental This past year certainly was a remains a key element of our strategy, operating and maintenance costs difficult one for our industry as and we delivered solid results in this necessary to prepare the plant for companies continued to change their important area in 2002. We retired, restart, plus replacement power costs, strategies for success in the evolving refinanced or repriced $2.6 billion in totaled $235 million. And, we incurred energy marketplace. We remain long-term debt and preferred stock,

$63 million in incremental capital confident that we've chosen the which will produce $125 million in costs, primarily for the reactor head right strategy for FirstEnergy. annual savings. Our debt reduction replacement.

We continue to be committed activity should help lower our debt The impact of Davis-Besse, to the generation, transmission and ratio to about 50 percent by the end which accounts for seven percent distribution of electricity and related of 2005. To help reach that goal, of our generating capacity, has been services. Our business model provides we'll continue reducing costs where significant. But we have not allowed for strong cash flow and financial appropriate and maximizing cash flow.

the problems that occurred at the flexibility, with approximately In 2002, we made steady progress plant to define our organization.

75 percent of our revenues derived toward those ends.

Enhancing Corporate Governance from our regulated businesses and We're on track to achieve our goal Your Company understands a diversified sales mix. of $150 million in annual merger-the importance of achieving success Our integrated approach gives related savings by the end of 2004.

with a steadfast commitment to ethics us the distinct competitive advantage By that time, we also expect to save and integrity - cornerstones of good of being better positioned to manage another $135 million annually through corporate governance. risks and unexpected developments, a cost reduction initiative we began As we all know, some businesses and to improve the value of your implementing in 2002. Cost reduc-lost sight of this important issue in investment. While 2002 was a tough tions are important, particularly as recent years, resulting in the financial year for utility stocks, FirstEnergy we - like other companies - face collapse of several companies once remains a solid long-term investment. rising health care and pension and considered leaders in their industries. For example, at year end, our three- other post-employment benefit costs.

We support recent changes to federal disclosure and corporate governance requirements designed to prevent unethical business practices. 4.9%

We've taken a number of steps to enhance corporate governance policies and practices throughout Generating our organization. Capacity Mix For example, we've revised and

• Coal enhanced Board committee charters El Nuclear and policies - now available on our

• Pumped-Storage Hydro Web site, unw.firstenergycorp.com/ir - E3 Gas & Oil to ensure your Company meets the highest standards for independent Board oversight. We have a chief ethics 3 COT2

Maximizing the Value of our Assets Consistent with our strategy, we remain focused on maximizing Distribution the value of our assets and divesting Electric Sales by non-core businesses, most of which Customer Class were acquired through the GPU merger.

• Residential Cl Commercial As you may recall, we sold M Industrial 31 79.9 percent of Avon Energy Partners Holdings in the United Kingdom to Aquila, Inc., in 2002. We continue to evaluate opportunities to sell our remaining 20.1 percent interest.

However, we'll likely receive less for our interest in Avon Energy than Reducing costs also is important plants, as well as our Perry and its original carrying value, and as to our ongoing efforts to maximize Beaver Valley nuclear plants, helped a result, recorded a $50 million, our free cash flow - cash flow after offset the decline in power production or $0.11 per share, non-cash charge the payment of common stock resulting from the extended outage in 2002.

dividends and capital expenditures. at Davis-Besse.

We also plan to divest Emdersa -

Free cash flow, which totaled about We also achieved a 7.9 percent a distribution company in Argentina -

$340 million in 2002, is projected increase in total kilowatt-hour sales, although difficult economic conditions to exceed $700 million in 2003. while again demonstrating our there have complicated our efforts.

The increase is based on Davis-Besse's commitment to safe operations.

Because we were unable to reach a anticipated return to service, expected Our company-wide Occupational sale agreement within one year of the growth and improvements in our core Safety and Health Administration merger, we could no longer classify electric business, a reduction in capital incident rate of 1.56 per 100 utility it as an asset pending sale. As a result, expenditures, and ongoing merger- employees ranks us among our we recorded in 2002 a one-time, non-related and financing cost savings. industry's leaders in safety.

cash cumulative effect of an accounting In addition, we made solid change that reduced net income by progress in our efforts to provide "More than 60 percent superior customer service. More than

$88.8 million, or $0.30 per share.

And, we're continuing to explore of customers surveyed 60 percent of customers surveyed rated opportunities to divest our other us a 9 or 10 on a 10-point scale rated us a 9 or 10 on a remaining international assets, which measuring our performance in key 10-point scale... 99 areas of service reliability and restora-include interests in four generating plants - one in Colombia and three tion, and employee performance.

Continued savings and debt reduction are key to our commitment to maintaining the investment grade ratings held by our holding company and all seven of its operating compa-I nies. These ratings are important because they improve our access to Electric Customers capital markets and reduce the cost Served of borrowing.

• Ohio Achieving Operational Excellence E Pennsylvania 1,250,084 ENew Jersey We continued to improve our operations in 2002, including the record output of 71.3 million megawatt-hours set by our generating units.

Strong performance by our coal-fired 4 C C 4ri

.. __ ..... .l

in Bolivia - also acquired through 46With the steady progress been issued, we remain confident the GPU merger. that all of our plants, including we're making to improve With respect to our core assets, Sammis, are in compliance.

in August we canceled an agreement operations, grow cash Committed to Delivering with NRG Energy, Inc., of Minneapolis, flow and further reduce Stronger Performance Minnesota, and its affiliate (NRG), debt, we're positioned Your Company faced many to sell four coal-fired power plants located along Lake Erie in Ohio for to build on the many challenges in 2002. However, we view the most significant ones - including

$1.5 billion based on an anticipatory performance gains of our those associated with Davis-Besse -

breach by NRG. We've reserved the core electric business. primarily as short term. With the right to pursue legal action against steady progress we're making to NRG and its parent, Xcel Energy, improve operations, grow cash flow and in February, received permission Protecting the Environment and further reduce debt, we're from the U.S. Bankruptcy Court in We're delivering on our commit-positioned to build on the many Minnesota to proceed to arbitration ment to protect the environment, performance gains of our core with NRG. while meeting customer needs for electric business.

We're also continuing to evaluate reliable and competitively priced For 2003, our primary goals the competitiveness of our other electricity. We've spent more than include further improving the generating assets. As a result, we $5 billion on environmental protection performance of our generating fleet, closed four small electric generating efforts since enactment of the Clean including returning Davis-Besse to units totaling 236 megawatts in Ohio. Air Act. And through the installation safe and reliable service, and continuing This decision is consistent with our of low-nitrogen-oxide (NOx) burners to enhance our credit profile and strategy to focus on larger baseload and other environmental protection financial flexibility.

plants and newer, higher-efficiency systems, we've reduced by more than And with a sound corporate peaking units, including our 340- one-half emissions of NOx and sulfur strategy, the hard work and dedication megawatt Sumpter Plant, which went dioxide since 1990.

of employees and your continued into service in 2002. Enhancing the We'll achieve further reductions in support, we're confident that we'll performance of our generating fleet is NOx emissions through state-of-the-achieve solid performance in 2003 critical to meeting customer demand art environmental protection systems that will lead to continued success and to effectively managing our that will begin operating at our largest in the years ahead.

commodity supply needs, including coal-fired generating units this summer.

those associated with meeting our Despite our progress, the Sincerely, provider of last resort obligations U.S. Environmental Protection in the states where we operate. Agency (U.S. EPA) is pursuing A 2002 ruling by the Pennsylvania installation of additional environ-Commonwealth Court denied two of our operating companies the ability mental controls in legal action against our W. H. Sammis Plant H. Peter Burg Chairman and c

to defer costs in excess of capped and more than 40 power plants in Chief Executive Officer generation rates incurred to serve the Midwest and South owned by customers in that state. As a result, other utility companies. The U.S.

March 24, 2003 we incurred a $56 million, or $0.11 EPA claims that routine maintenance, per share, charge during the year. repairs and replacements at Sammis The Pennsylvania Supreme Court - common industry practices for declined to hear our appeal of the decades that the agency was fully Commonwealth Court ruling. aware of - violated provisions of However, we remain well-positioned the Clean Air Act, even though to meet our provider of last resort capacity and emissions have not obligations through a combination increased. The U.S. EPA's allegations of our own generating capacity, were tried before the U.S. District which totals more than 13,000 Court in Columbus, Ohio, in February megawatts, and contracted supply. of this year. While a ruling has not 5

I i

Management Report The consolidated financial statements were prepared by the management of FirstEnergy Corp, who takes responsibility for their integrity and objectivity The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report PricewaterhouseCoopers LLP, independent public accountants, have expressed an unqualified opinion on the Company's 2002 consolidated financial statements.

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

The Audit Committee consists of six nonemployee directors whose duties indude. consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent public accountants and the internal auditors; appointment of independent accountants to conduct the normal annual audit and special purpose audits as may be required; reviewing and approving all services, induding any non-audit services, performed for the Company by the independent public accountants and reviewing the related fees; and reporting to the Board of Directors the Committee's findings and any recommendation for changes in scope, methods or procedures of the auditing functions The Committee reviews the independent accountants' internal quality control procedures and reviews all relationships between the independent accountants and the Company, in order to assess the auditors' independence The Committee also reviews management's programs to monitor compliance with the Company's policies on business ethics and risk management. The Audit Committee held nine meetings in 2002 Richard H. Marsh, Senior Vice Presidentand Chief FinancialOfficer Harvey L Wagner, Vice President, Controller and Chief Accounting Officer Report of Independent Public Accountants To the Stockholders and Board of Directors of FirstEnergy Corp.:

In our opinion, the accompanying consolidated balance sheet and consolidated statement of capitalization and the related consolidated statements of income, common stockholders' equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of FirstEnergy Corp. and subsidiaries as of December 31, 2002, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management, our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material mis-statement. An audit includes examining, on a test basis, evidence supporting the amounts and disciosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation We believe that our audit provides a reasonable basis for our opinion. The consolidated financial statements of FirstEnergy Corp and subsidianes as of December 31, 2001 and for each of the two years in the period ended December 31, 2001 were audited by other independent accountants who have ceased operations Those independent accountants expressed an unqualified opinion on those financial statements, before the revisions described in Notes 2 and 8 to the 2002 consolidated financial statements, in their report dated March 18, 2002 As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for goodwill in 2002.

As discussed in Note 3 to the consolidated financial statements, the Company changed its method of accounting for its investments in Avon Energy Partners Holdings and Emdersa in 2002.

As discussed above, the consolidated financial statements of FirstEnergy Corp and subsidiaries as of December 31, 2001 and for each of the two years in the period ended December 31, 2001 were audited by other independent accountants who have ceased operations. As described in Note 2 to the consolidated financial statements, revisions have been made to indude the transitional disclosures required by Statement of Finandal Accounting Standards No. 142, Gooduwll and Other IntangibleAssets, which was adopted by the Company as of January 1, 2002 In our opinion the transitional disclosures for 2001 and 2000 are appropriate. However, we were not engaged to audit, review, or apply any procedures to the 2001 and 2000 consolidated financial statements of the Company other than with respect to such disclosures and, accordingly, we do not express an opinion or any other form of assurance on the 2001 and 2000 consolidated financial statements taken as a whole. Additionally, as described in Note 8 to the consolidated financial statements, the Company changed the composition of its reportable segments in 2002 Accordingly, the corresponding 2001 and 2000 reportable segments disclosures have been revised to conform to the 2002 presentation We audited the revisions that were applied to the 2001 and 2000 reportable segments disclosures reflected in Note 8 to the 2002 consolidated financial statements. In our opinion, such revisions are appropriate and have been properly applied PLL2 0 - LLP1 PricewaterhouseCoopers LLP Cleveland, OH, February 28, 2003 The following report is a copy of a report preMously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP.

Report of Previous Independent Public Accountants To the Stockholders and Board of Directors of FirstEnergy Corp I 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 estimates 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 penod ended December 31, 2001, in conformity with accounting pnnciples 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 Ian ast L Lf Arthur Andersen LLP Cleveland, Ohio, March 18, 2002 6

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FirstEnergy Corp. 2002 SELECTED FINANCIAL DATA (In thousands, except per share amounts)

For the Years Ended December31, 2002 2001 2000 1999 1998 Revenues $12,151,997 $ 7,999,362 $ 7,028,961 $ 6,319,647 $ 5,874,906 Income Before Extraordinary Item and Cumulative Effect of Accounting Changes $ 686,401 $ 654,946 $ 598,970 $ 568,299 $ 441,396 Net Income $ 629,280 $ 646,447 $ 598,970 $ 568,299 $ 410,874 Basic Earnings per Share of Common Stock:

Before Extraordinary Item and Cumulative Effect of Accounting Changes $2.34 $2.85 $2.69 $2.50 $1.95 After Extraordinary Item and Cumulative Effect of Accounting Changes $2.15 $2.82 $2.69 $2.50 $1.82 Diluted Earnings per Share of Common Stock:

Before Extraordinary Item and Cumulative Effect of Accounting Changes $2.33 $2.84 $2.69 $2.50 $1.95 After Extraordinary Item and Cumulative Effect of Accounting Changes $2.14 $2.81 $2.69 $2.50 $1.82 Dividends Declared per Share of Common Stock $1.50 $1.50 $1.50 $1.50 $1.50 Total Assets $33,580,773 $37,351,513 $17,941,294 $18,224,047 $18,192,177 Capitalization at December 31:

Common Stockholders' Equity $ 7,120,049 $ 7,398,599 $ 4,653,126 $ 4,563,890 $ 4,449,158 Preferred Stock:

Not Subject to Mandatory Redemption 335,123 480,194 648,395 648,395 660,195 Subject to Mandatory Redemption 428,388 594,856 161,105 256,246 294,710 Long-Term Debt' 10,872,216 12,865,352 5,742,048 6,001,264 6,352,359 Total Capitalization* $18,755,776 $21,339,001 $11,204,674 $11,469,795 $11,756,422 12001 includes approximately $1.4 billion of long-term debt (excluding long-term debt due to be repaid within one year) included in "LiabilitiesRelated to Assets Pending Sale" on the Consolidated Balance Sheet as of December 31, 2001.

PRICE RANGE OF COMMON STOCK The Common Stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol "FE"and istraded on other registered exchanges.

2002 2001 First Quarter High-Low $39.12 $30.30 $31.75 $25.10 Second Quarter High-Low 35.12 31.61 32.20 26.80 Third Quarter High-Low 34.78 24.85 36.28 29.60 Fourth Quarter High-Low 33.85 25.60 36.98 32.85 Yearly High-Low 39.12 24.85 36.98 25.10 Prices are based on reports published in The Wall Street Journal for New York Stock Exchange Composite Transactions.

HOLDERS OF COMMON STOCK There were 163,423 and 162,762 holders of 297,636,276 shares of FirstEnergy's Common Stock as of December 31, 2002 and January 31, 2003, respectively. Information regarding retained earnings available for payment of cash dividends is given in Note 5A.

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MANAGEMENTS DISCUSSION AND ANALYSIS OF GPU Merger RESULTS OF OPERATIONS AND FINANCIAL CONDITION On November 7, 2001, the merger of FirstEnergy and GPU became effective with FirstEnergy being the surviving company.

This discussion includes forward-looking statements based on infor- The merger was accounted for using purchase accounting under mation currently available to management that is subject to certain the guidelines of Statement of Financial Accounting Standards risks and uncertainties Such statements typically contain, but are not No. (SFAS) 141, "Business Combinations.' Under purchase limited to, the terms anticipate, potential, expect, believe, estimate and accounting, the results of operations for the combined entity similarwords. Actual results may differ materially due to the speed are reported from the point of consummation forward. As a and nature of increased competition and deregulation in the electric result, our financial statements for 2001 reflect twelve months utility industry economic or weather conditions affectingfuture sales of operations for our pre-merger organization and seven weeks and margins, changes in markets for energy services, changing energy of operations (November 7, 2001 to December 31, 2001) for and commodity market prices, legislative and regulatory changes the former GPU companies. In 2002, our financial statements (including revised environmental requirements), the availability and indude twelve months of operations for both our pre-merger cost of capital, our ability to accomplish or realize anticipated benefits organization and the former GPU companies. Additional from strategic initiatives and other similarfactors. goodwill resulting from the merger ($2.3 billion) plus goodwill existing at CPU ($1.9 billion) at the time of the merger is not FirstEnergy Corp. is a registered public utility holding company being amortized, reflecting the application of SFAS 142, 'Goodwill that provides regulated and competitive energy services (see Results and Other Intangible Assets ' Goodwill continues to be subject of Operations - Business Segments) domestically and interna- to review for potential impairment (see Significant Accounting tionally. The international operations were acquired as part of Policies - Goodwill). As a result of the merger, we issued nearly FirstEnergy's acquisition of GPU, Inc. in November 2001. GPU 73.7 million shares of our common stock, which are reflected Capital, Inc and its subsidiaries provide electric distribution in the calculation of earnings per share of common stock in services in foreign countries. GPU Power, Inc and its subsidianes 2002 and for the seven-week period outstanding in 2001.

develop, own and operate generation facilities in foreign countries Sales are planned but not pending for all of the international Results of Operations operations (see Capital Resources and Liquidity) Prior to the Net income decreased to $629.3 million in 2002, compared GPU merger, regulated electric distribution services were provided to $646 4 million in 2001 and $599 0 million in 2000 Net income to poruons of Ohio and Pennsylvania by our wholly owned in 2002 included the net after-tax charge of $57.1 million subsidiaries - Ohio Edison Company (OE), The Cleveland Electric resulting from the cumulative effect of changes in accounting Illuminating Company (CEI), Pennsylvania Power Company resulting from divestiture activities discussed below Net income (Penn) and The Toledo Edison Company (TE) with American in 2001 included the cumulative effect of an accounting change Transmission Systems, Inc. (ATSI) providing transmission services. resulting in a net after-tax charge of $8 5 million (see Cumulative Following the GPU merger, regulated services are also provided Effect of Accounting Changes) Excluding the former GPU com-through wholly owned subsidiaries - Jersey Central Power & panies' results (and related interest expense on acquisition debt),

Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) net income decreased to $469 4 million in 2002 from $615.5 and Pennsylvania Electric Company (Penelec) - providing electric million in 2001 due in large part to the incremental costs related distribution and transmission services to portions of Pennsylvania to the extended Davis-Besse outage and a number of one-time and New Jersey. The coordinated delivery of energy and energy- charges summarized in the table on the following page. In addition, related products, including electricity, natural gas and energy SFAS 142, implemented January 1, 2002, resulted in the cessation management services, to customers in competitive markets is of goodwill amortization. In 2001, amortization of goodwill provided through a number of subsidiaries, often under master reduced net income by approximately $57 million ($0.25 per share of common stock). Excluding the former GPU companies' contracts providing for the delivery of multiple energy and energy-related services Prior to the GPU merger, competitive services results (and related interest expense on acquisition debt), net were principally provided by FirstEnergy Solutions Corp. (FES), income increased in 2001 due to reduced depreciation and FirstEnergy Facilities Services Group, LLC (FSG) and MARBEL amortization, general taxes and net interest charges The benefits Energy Corporation Following the GPU merger, competitive of these reductions were offset in part by lower retail electric services are also provided through MYR Group, Inc. sales, increased other operating expenses and higher gas costs.

Incremental costs related to the extended outage at the Davis-Besse nuclear plant (see Davis-Besse Restoration) reduced basic and diluted earnings per share of common stock by $0 47 in 2002 In addition, the table on the following page displays one-time charges that resulted in a comparative net reduction to basic and diluted earnings of $0 46 per share of common stock in 2002, compared to 2001.

The impact of domestic and world economic conditions on the electric power industry limited our divestiture program dunng 2002. By the end of 2001, we had successfully completed the sale of our Australian gas transmission companies, had reached agreement with Aquila, Inc. for the sale of our holdings of electric distribution facilities in the United Kingdom (UK) and executed an agreement with NRG Energy Inc. (NRG) for the sale of four coal-fired power plants. However, the UK transaction with Aquila closed on May 8, 2002 and reflected the March 2002 modification of Aquila's initial offer such that Aquila acquired a 79.9 percent equity interest in Avon Energy FirstEnergy 8

Partners Holdings (Avon) for approximately $1.9 billion (including the assumption of $1.7 billion of debt). In the Sources of Revenue Changes 2002 2001 fourth quarter of 2002, we recognized a $50 million impairment Increase (Decrease) (In millions) of our Avon investment. On August 8, 2002, we notified NRG Pre-Merger Companies:

that we were canceling our agreement with them for their purchase Electric Utilities (Regulated Services):

Retail electric sales $ (328.5) $ (240.5) of the four fossil plants because NRG had stated that it could Other revenues 18.4 (22.6) not complete the transaction under the original terms of the agreement. We were also actively pursuing the sale of an electric Total Electric Utilities (310.1) (263.1) distribution company in Argentina - CPU Empressa Distribuidora Unregulated Businesses (Competitive Services):

Electrica Regional S.A. and its affiliates (Emdersa). With the Retail electric sales 136.4 (19.9) deteriorating economic conditions in Argentina, no sale could Wholesale electric sales:

Nonaffiliated 140.0 254.4 be completed by December 31, 2002. Further information on Affiliated 345.3 32.7 the impact of the changes in accounting related to our divestiture Gas sales (171.7) 226.1 activities is available in the "Cumulative Effect of Accounting Other revenues (115.2) 106.5 Changes" section and in the discussion of depreciation charges Total Unregulated Businesses 334.8 599.8 in the "Expenses" section below.

One-time pre-tax charges to earnings before the cumulative Total Pre-Merger Companies 24.7 336.7 effect of accounting changes are summarized in the following table: Former GPU Companies:

Electric utilities 3,782.4 570.4 One-time Charges 2002 2001 Change Unregulated businesses 687.4 101.9 (In millions) Total Former GPU Companies 4,469.8 672.3 Investment impairments $100.7 - $100.7 Intercompany Revenues (341.9) (38.6)

Pennsylvania deferred energy costs 55.8 - 55.8 Net Revenue Increase $4,152.6 $ 970.4 Lake Plants - depreciation and sale costs 29.2 - 29.2 Long-term derivative contract adjustment 18.1 - 18.1 Electric Sales Generation project cancellation 17.1 - 17.1 Shopping by Ohio customers for alternative energy suppliers Severance costs-2002 11.3 - 11.3 combined with the effect of a sluggish national economy on Uncollectible reserve and regional business reduced retail electric sales revenues of our contract losses - 9.2 (9.2)

Early retirement costs - 2001 - 8.8 (8.8) pre-merger EUOCs by $328.5 million (or 7.1%) in 2002 compared Estimated claim settlement 16.8 - 16.8 to 2001. Since Ohio opened its retail electric market to competing generation suppliers in 2001, sales of electric generation by

$249.0 $18.0 $231.0 alternative suppliers in our franchise areas have risen steadily, providing 23.6% of total energy delivered to retail customers Reduction to earnings per share of common stock in 2002, compared to 11.3% in 2001. As a result, generation Basic $0.51 $0.05 $0.46 kilowatt-hour sales to retail customers by the EUOC were Diluted $0.51 $0.05 $0.46 14.2% lower in 2002 than the prior year, which reduced regulat-ed retail electric sales revenues by $230.6 million.

Revenue from distribution deliveries decreased by $11.7 million Previously reported variances of revenues, expenses, income in 2002 compared to 2001. Kilowatt-hour deliveries to franchise taxes and net income between 2001 as compared to 2000 customers were 0.5% lower in 2002 compared to the prior year.

included in Results of Operations - Business Segments have been The decrease resulted from the net effect of a 6.3% increase in reclassified as a result of segment information reclassifications kilowatt-hour deliveries to residential customers (due in large (see Note 8 for additional discussion). In addition, previously part to warmer summer weather in 2002) offset by a 3.2%

reported comparisons of sales of electricity between 2001 as decline in kilowatt-hour deliveries to commercial and industrial compared to 2000 have also been reclassified as a result of customers as a result of sluggish economic conditions.

adoption of Emerging Issues Task Force (EITF) Issue No. 02-03, The remaining decrease in regulated retail electric sales revenues "Issues Involved in Accounting for Derivative Contracts Held for resulted from additional transition plan incentives provided to Trading Purposes and Contracts Involved in Energy Trading and customers to promote customer shopping for alternative suppli-Risk Management Activities" (see Implementation of Recent ers - $86.0 million of additional credits in 2002 compared to Accounting Standard for additional disclosure). 2001. These reductions to revenue are deferred for future recovery under our Ohio transition plan and do not materially affect Revenues Total revenues increased $4.2 billion in 2002, which included current period earnings.

more than $4.5 billion incremental revenues for the former CPU Despite the decrease in kilowatt-hour sales by our pre-merger EUOC, total electric generation sales increased by 22.0% in companies in 2002 (twelve months), compared to 2001 (seven weeks). Excluding results from the former CPU companies, total 2002 compared to the prior year as a result of higher kilowatt-hour sales by our competitive services segment. Revenues from revenues increased $24.7 million following a $336.7 million increase in 2001. The additional sales in both years resulted from the wholesale market increased $501.4 million in 2002 from an expansion of our unregulated businesses, which more than 2001 and kilowatt-hour sales more than doubled. More than half of the increase resulted from additional affiliated company offset lower sales from our electric utility operating companies (EUOC). Sources of changes in pre-merger and post-merger sales by FES to Met-Ed and Penelec. FES assumed the supply companies' revenues during 2002 and 2001, compared to the obligation in the third quarter of 2002 for a portion of Met-Ed's prior year, are summarized in the following table: and Penelec's provider of last resort (PLR) supply requirements (see State Regulatory Matters - Pennsylvania). The increase also 9

included sales into the New Jersey market as an alternative sup- Our regulated and unregulated subsidiaries record purchase plier for a portion of New Jersey's basic generation service and sales transactions with PJM Interconnection ISO, an inde-(BGS). Retail sales by our competitive services segment increased pendent system operator, on a gross basis in accordance with by $136.4 million as a result of a 59 0% increase in kilowatt- Emerging Issues Task Force (EITF) Issue No. 99-19, 'Reporting hour sales in 2002 from 2001. That increase resulted from retail Revenue Gross as a Principal versus Net as an Agent ' This gross customers switching to FES, our unregulated subsidiary, under basis dassification of revenues and costs may not be comparable Ohio's electricity choice program The higher kilowatt-hour to other energy companies that operate in regions that have not sales in Ohio were partially offset by lower retail sales in markets established ISOs and do not meet EITF 99-19 criteria.

outside of Ohio The aggregate purchase and sales transactions for the three In 2001, our pre-merger EUOC retail revenues decreased by years ended December 31, 2002, are summarized as follows-

$240.5 million compared to 2000, principally due to lower generation sales volume resulting from the first year of customer 2002 2001 2000 choice in Ohio. Sales by alternative suppliers increased to (Inmillions) 11 3% of total energy delivered compared to 0 8% in 2000 Sales $453 $142 $315 Implementation of a 5% reduction in generation charges for Purchases 687 204 271 residential customers as part of Ohio's electric utility restructuring in 2001 also contnbuted $51.2 million to the reduced electric sales FirstEnergy's revenues on the Consolidated Statements of revenues Kilowatt-hour deliveries to franchise customers were Income indude wholesale electricity sales revenues from the down a more moderate 1 7% due in part to the decline in PJM ISO from power sales (as reflected in the table above) during economic conditions, which was a major factor resulting in a periods when we had additional available power capacity.

3.1% decrease in kilowatt-hour deliveries to commercial and Revenues also indude sales by FirstEnergy of power sourced from industrial customers Other regulated electric revenues decreased the PJM ISO (reflected as purchases in the table above) during by $22 6 million in 2001, compared to the prior year, due in periods when we required additional power to meet our retail part to reduced customer reservation of transmission capacity load requirements and, secondarily, to sell in the wholesale market Total electric generation sales increased by 2 7% in 2001 compared to the prior year with sales to the wholesale market Nonelectric Sales being the largest single factor contributing to this increase Nonelectric sales revenues dedined by $284.6 million in 2002 Kilowatt-hour sales to wholesale customers more than doubled from 2001 The elimination of coal trading activities in the second from 2000 and revenues increased $287 1 million in 2001 from half of 2001 and reduced natural gas sales were the primary factors the prior year The higher kilowatt-hour sales benefited from contributing to the lower revenues. Reduced gas revenues resulted increased availability of power to sell into the wholesale market, principally from lower prices compared to 2001. Despite a slight due to additional internal generation and increased shopping reduction in sales volume and lower prices in 2002, margins by retail customers from alternative suppliers, which allowed us from gas sales improved (see Expenses below). Reduced revenues to take advantage of wholesale market opportunities Retail from the facilities services group also contributed to the decrease kilowatt-hour sales by our competitive services segment increased in other sales revenue in 2002, compared to 2001 In 2001, by 3 6% in 2001, compared to 2000, primanly due to expanding nonelectric revenues increased $332.6 million, with natural gas sales within Ohio as a result of retail customers switching to revenues providing the largest source of increase. Beginning FES under Ohio's electricity choice program. The higher kilowatt- November 1, 2000, residential and small business customers in hour sales in Ohio were partially offset by lower sales in markets the service area of a nonaffiliated gas utility began shopping among outside of Ohio as some customers returned to their local alternative gas suppliers as part of a customer choice program distribution companies Despite an increase in kilowatt-hour FES's ability to take advantage of this opportunity to expand its sales in Ohio's competitive market, declining sales to higher- customer base contributed to the increase in natural gas revenues.

priced eastern markets contributed to an overall decdine in retail Expenses competitive sales revenue in 2001 from the prior year. Total expenses increased nearly $3.7 billion in 2002, which Changes in electric generation sales and distribution deliveries included more than $3.7 billion of incremental expenses for in 2002 and 2001 for our pre-merger companies are summarized the former GPU companies in 2002 (twelve months), compared in the following table to 2001 (seven weeks) For our pre-merger companies, total Changes in kilowatt-hour Sales 2002 2001 expenses increased $295.7 million in 2002 and $280.4 million in 2001, compared to the respective prior years Sources of Increase (Decrease) changes in pre-merger and post-merger companies' expenses Electnc Generation Sales in 2002 and 2001, compared to the prior year, are summarized Retail -

Regulated services (14 2)' (12 2)% in the following table:

Competitive services 59 0% 3 6%

Wholesale 122 6% 117 2%

Total Electric Generation Sales 22 0% 2 7%

EUQO Distribution Deliveries Residential 6.3% 1 7%

Commercial and industrial (3.2)% (31)%

Total Distribution Deliveries (0.5)% (17)%

FirstEnergy 10

$144.5 million of the increase in 2001. Additionally, higher Sources of Expense Changes 2002 2001 operating costs from the competitive services business segment Increase (Decrease) (In millions) due to expanded operations contributed $56.9 million to Pre-Merger Companies: the increase. Partially offsetting these higher other operating Fuel and purchased power $ 441.7 $ 48.7 expenses was a reduction in low-income payment plan cus-Purchased gas (227.9) 266.5 tomer costs and a $30.2 million decrease in nuclear operating Other operating expenses 178.5 178.2 Depreciation and amortization (125.1) (99.0) costs in 2001, compared to 2000, resulting from one less General taxes 28.5 (114.0) refueling outage.

Fossil operating costs increased $44.3 million in 2001 from Total Pre-Merger Companies 295.7 280.4 2000 due principally to planned maintenance work at the Bruce Former GPU Companies 3,713.8 542.4 Mansfield generating plant. Pension costs increased by $32.6 Intercompany Expenses (353.9) (32.6) million in 2001 from 2000 primarily due to lower returns on Net Expense Increase $3,655.6 $ 790.2 pension plan assets (due to significant market-related reductions in the value of pension plan assets), the completion of the 15-year amortization of OE's pension transition asset and changes to The following comparisons reflect variances for the pre-merger plan benefits. Health care benefit costs also increased by $21.4 companies only, excluding the incremental expenses for the million in 2001, compared to 2000, principally due to an former GPU companies in 2002 and 2001. increase in the health care cost trend rate assumption for computing Higher fuel and purchased power costs in 2002 compared post-retirement health care benefit liabilities.

to 2001 primarily reflect additional purchased power costs of Charges for depreciation and amortization decreased $125.1

$342.2 million. The increase resulted from additional volumes million in 2002 from the preceding year. This decrease resulted to cover supply obligations assumed by FES. These included from two factors: shopping incentive deferrals and tax-deferrals a portion of Met-Ed's and Penelec's PLR supply requirements under the Ohio transition plan ($108.5 million) and the cessation (which started in the third quarter of 2002), contract sales of goodwill amortization ($56.4 million) beginning January 1, including sales to the New Jersey market to provide BGS, and 2002. However, several items offset a portion of the above additional supplies required to replace Davis-Besse power dur- reduction. The start up of a new fluidized bed boiler in January ing its extended outage (see Davis-Besse Restoration). Fuel 2002, owned by Bayshore Power Company, a wholly owned expense increased $99.5 million in 2002 from the prior year subsidiary, resulted in higher depreciation expense in 2002.

principally due to additional internal generation (5.4% higher) Also, new combustion turbine capacity added in late 2001 and and an increased mix of coal and natural gas generation in 2002. two months of 2001 depreciation recorded in 2002 (for the The extended outage at the Davis-Besse nuclear plant produced four fossil plants we chose not to sell) increased depreciation a decline in nuclear generation of 14.6% in 2002, compared to expense in 2002.

2001. Purchased gas costs decreased by $227.9 million primarily In 2001, charges for depreciation and amortization decreased due to lower unit costs of natural gas purchased in 2002 compared by $99.0 million from the prior year. Approximately $64.6 million to the prior year resulting in a $48.4 million improvement in of the decrease resulted from lower incremental transition cost gas margins. amortization under our Ohio transition plan compared to In 2001, the increase in fuel expense compared to 2000 accelerated cost recovery in connection with OE's prior rate

($24.3 million) resulted from the substitution of coal and natural plan. The reduction in depreciation and amortization also gas fired generation for nuclear generation during a period of reflected additional cost deferrals of $51.2 million for recoverable reduced nuclear availability resulting from both planned and shopping incentives under the Ohio transition plan, partially unplanned outages. Higher unit costs for coal consumed also offset by increases associated with depreciation on completed contributed to the increase during that period. Purchased power combustion turbines in the fourth quarter of 2001.

costs increased early in 2001, compared to 2000, due to higher General taxes increased $28.5 million in 2002 from 2001 winter prices and additional purchased power requirements principally due to additional property taxes and the absence during that period, with the balance of the year offsetting all in 2002 of a one-time benefit of $15 million resulting from but $24.4 million of that increase as a result of generally lower the successful resolution of certain property tax issues in the prices and reduced external power needs compared to 2000. prior year. In 2001, general taxes declined $114.0 million from Purchased gas costs increased 48% in 2001 compared to 2000, 2000 primarily due to reduced property taxes and other state principally due to the expansion of FES's retail gas business. tax changes in connection with the Ohio electric industry Other operating expenses increased $178.5 million in restructuring. The reduction in general taxes was partially 2002 from the previous year. The increase principally resulted offset by $66.6 million of new Ohio franchise taxes, which from several large offsetting factors. Nuclear costs increased are classified as state income taxes on the Consolidated

$125.3 million primarily due to $115.0 million of incremental Statements of Income.

Davis-Besse costs related to its extended outage (see Davis-Besse Restoration). One-time charges, discussed above, added

$98.3 million and an aggregate increase in administrative and general expenses and non-operating costs of $127.4 million resulted in large part from higher employee benefit expenses.

Partially offsetting these higher costs were the elimination in the second half of 2001 of coal trading activities ($95.4 million) and reduced facilities service business ($58.9 million).

In 2001, other operating expenses increased by $178.2 million compared to the prior year. The significant reduction in 2001 of gains from the sale of emission allowances, higher fossil operating costs and additional employee benefit costs accounted for 11

Net Interest Charges The pension and OPEB expense increases are induded in various Net interest charges increased $390 6 million in 2002, compared cost categones and have contnbuted to other cost increases dis-to 2001. These increases induded interest on $4 billion of long- cussed above See 'Significant Accounting Policies - Pension and term debt issued by FirstEnergy in connection with the merger Other Postretirement Benefits Accounting' for a discussion of the Excluding the results associated with the former GPU companies impact of underlying assumptions on postretirement expenses and merger-related financing, net interest charges decreased and anticipated pension and OPEB expense increases in 2003.

$57 0 million in 2002, compared to a $39.8 million decrease Results of Operations - Business Segments in 2001 from 2000 Our continued redemption and refinancing We manage our business as two separate major business seg-of our outstanding debt and preferred stock during 2002, main-ments - regulated services and competitive services The regulated tained our downward trend in financing costs before the effects services segment designs, constructs, operates and maintains our of the CPU merger. Excluding activities related to the former regulated domestic transmission and distnbution systems. It also CPU companies, redemption and refinancing activities for 2002 provides generation services to frandhise customers who have not totaled $1 1 billion and $143 4 million, respectively, and are chosen an alternative generation supplier OE, CEI and TE (Ohio expected to result in annualized savings of $86 0 million We also Companies) and Penn obtain generation through a power supply exchanged existing fixed-rate payments on outstanding debt agreement with the competitive services segment (see Outlook (pnncipal amount of $593.5 million at year end 2002) for

- Business Organization). The competitive services segment short-term vanable rate payments through interest rate swap indudes all competitive energy and energy-related services induding transactions (see Market Risk Information - Interest Rate Swap commodity sales (both electncity and natural gas) in the retail Agreements below) Net interest charges were reduced by and wholesale markets, marketing, generation, trading and

$17 4 million in 2002 as a result of these swaps sourcing of commodity requirements, as well as other competitive Cumulative Effect of Accounting Changes energy application services. Competitive products are increasingly Earnings for 2002 were affected by two accounting changes. marketed to customers as bundled services, often under master As of the merger date, certain former CPU international contracts. Financial results discussed below include intersegment operations were identified as 'assets pending sale Avon and a revenue. A reconciliation of segment financial results to consoli-Emdersa were the two remaining operations identified for dated financial results is provided in Note 8 to the consolidated sale following the completed sale of Australian operations in financial statements Financial data for 2002 and 2001 for the December 2001 Subsequent to the merger date, results of major business segments include reclassifications to conform operations and incremental interest costs related to these inter- with the current business segment organizations and operations, national subsidiaries were not induded in our Consolidated which affect 2002 and 2001 results discussed below Statement of Income On February 6, 2002, discussions began Regulated Services with Aquila, Inc. on modifymg its initial offer for the acquisition Net income increased to $997 1 million in 2002, compared of Avon, which resulted in a change in accounting for this to $729.1 million in 2001 and $562 5 million in 2000.

investment, and a $31.7 million after-tax increase to earnings.

Excluding additional net income of $312 7 million associated Also, as of December 31, 2002, we had not reached a definitive with the fonmer CPU companies, net income decreased by agreement to sell Emdersa As a result, Emdersa could no longer

$44.7 million in 2002. The changes in pre-merger net income be considered as 'assets pending sale,' which resulted in a change are summanzed in the following table:

in accounting for this investment and an after-tax reduction to earnings of $88 8 million. The amount of this one-time, after- Regulated Services 2002 2001 tax charge was compnsed of $104.1 million in currency transaction Increase (Decrease) (In millions) losses ansing principally from U S dollar denominated debt Revenues $(529 5) $(1164) offset by $15 3 million of operating income In 2001, we adopted Expenses (346 6) (344.1)

SFAS 133, 'Accounting for Derivative Instruments and Hedging Income Before Interest and Income Taxes (182 9) 2277 Activities' resulting in an $8.5 million after-tax charge.

Net interest charges (128 0) (168)

Postretirement Plans Income taxes (10 2) 132 7 Sharp declines in equity markets since the second quarter of 2000 and a reduction in our assumed discount rate in 2001 have Net Income Change $ (44.7) S 111 8 combined to produce a negative trend in pension expenses -

moving from a net increase to earnings in 2000 and 2001 to a Lower generation sales, additional transition plan incentives reduction of earnings in 2002. Also, increases in health care pay- and a slight decline in revenue from distribution deliveries ments and a related increase in projected trend rates have led to combined for a $312 5 million reduction in external revenues higher health care costs The following table presents the pre-tax in 2002 from the prior year Shopping by Ohio customers from pension and other post-employment benefits (OPEB) expenses alternative energy suppliers combined with the effect of a sluggish for our pre-merger companies (excluding amounts capitalized) national economy on our regional business reduced retail electric sales revenues. In addition, a $188 0 million decline in revenues Postrelirement Expenses (Income) 2002 2001 2000 resulted from reduced sales to FES, due to the extended outage (Inmillions) of the Davis-Besse nuclear plant, which reduced generation Pension $ 164 $(11 1) $(406) available for sale. The $346 6 million decrease in expenses OPEB 991 866 655 resulted from three major factors a $179 8 million decrease in Total $1155 $755 $249 purchased power, a $35 6 million reduction in other operating expenses and a $141 8 million decrease in depreciation expense.

Lower generation sales reduced the need for purchased power and other operating expenses reflected reduced costs in jobbing and contracting work and decreased uncollectible accounts expense.

FirstEnergy 12

Reduced depreciation and amortization resulted from $108.5 regulated services segment. Expenses increased $351.1 million million of new deferred regulatory assets under the Ohio transition in 2002 from the prior year, due to additional purchased power plan and the cessation of goodwill amortization beginning ($342.2 million) to supply the incremental kilowatt-hour sales January 1, 2002. to wholesale and retail customers. Other operating expenses In 2001, distribution throughput was 1.7% lower, compared increased $207.2 million from the prior year as a result of higher to 2000, reducing external revenues by $245.7 million. Partially nuclear costs due to incremental Davis-Besse costs from its offsetting the decrease in external revenues were revenues from extended outage. One-time charges discussed above increased FES for the rental of fossil generating facilities and the sale of costs by $75.6 million. Offsetting these increases were reduced generation from nuclear plants, resulting in a net $116.4 million purchased gas costs ($227.9 million) primarily resulting from reduction to total revenues. Expenses were $344.1 million lower lower prices and reduced costs from FSG reflecting reduced in 2001 than 2000 due to lower purchased power, depreciation business activity.

and amortization and general taxes, offset in part by higher In 2001, sales to nonaffiliates increased $523.2 million, other operating expenses. Lower generation sales reduced the compared to the prior year, with electric revenues contributing need to purchase power from FES, with a resulting $267.8 million $299.8 million, natural gas revenues adding $226.1 million and dedine in those costs in 2001 from the prior year. Other operating the balance of the change from energy-related services. Reduced expenses increased by $178.5 million in 2001 from the previous power requirements by the regulated services segment reduced year reflecting a significant reduction in 2001 of gains from the internal revenues by $267.8 million. Expenses increased $392.5 sale of emission allowances, higher fossil operating costs and million in 2002 from 2001 primarily due to a $266.5 million additional employee benefit costs. Lower incremental transition increase in purchased gas costs and increases resulting from cost amortization and the new shopping incentive deferrals additional fuel and purchased power costs (see Results of under our Ohio transition plan as compared with the accelerated Operations above) as well as higher expenses for energy-related cost recovery in connection with OE's prior rate plan in 2000 services. Reduced margins for both major competitive product resulted in a $131.0 million reduction in depreciation and areas - electricity and natural gas - contributed to the reduction amortization in 2001. A $123.6 million decrease in general in net income, along with higher interest charges and the taxes in 2001 from the prior year primarily resulted from cumulative effect of the SFAS 133 accounting change. Margins reduced property taxes and other state tax changes in connection for electricity and gas sales were both adversely affected by with the Ohio electric industry restructuring. higher fuel costs.

Competitive Services Capital Resources and Liquidity Net losses increased to $119.0 million in 2002, compared Changes in Cash Position to $31.8 million in 2001 and net income of $39.1 million in The primary source of ongoing cash for FirstEnergy, as a holding 2000. Excluding additional net income of $2.6 million associated company, is cash dividends from its subsidiaries. The holding with the former GPU companies, net losses increased by company also has access to $1.5 billion of revolving credit facilities,

$89.8 million in 2002. The changes to pre-merger earnings which it can draw upon. In 2002, FirstEnergy received $447 are summarized in the following table:

million of cash dividends on common stock from its subsidiaries Competitive Services 2002 2001 and paid $440 million in cash dividends on common stock to its shareholders. There are no material restrictions on the issuance Increase (Decrease) (Inmillions)

Revenues $211.5 $289.3 of cash dividends by FirstEnergy's subsidiaries.

Expenses 351.1 392.5 As of December 31, 2002, we had $196.3 million of cash and cash equivalents (including $50 million that redeemed long-term Income Before Interest and Income Taxes (139.6) (103.2) debt in January 2003) on our Consolidated Balance Sheet. This Net interest charges 21.9 13.5 compares to $220.2 million as of December 31, 2001. The major Income taxes (63.2) (51.3) sources for changes in these balances are summarized below.

Cumulative effect of a change inaccounting 8.5 (8.5)

Net Loss Increase $ 89.8 $ 73.9 Cash Flows From Operating Activities Our consolidated net cash from operating activities is provided by our regulated and competitive energy services businesses (see The $211.5 million increase in revenues in 2002, compared Results of Operations - Business Segments above). Net cash flows to 2001, represents the net effect of several factors. Revenues from operating activities in 2002 reflect twelve months of cash from the wholesale electricity market increased $485.3 million flows for the former GPU companies while 2001 includes only in 2002 from the prior year and kilowatt-hour sales more than seven weeks of those companies' operations (November 7, 2001 doubled. More than half of the increase resulted from additional to December 31, 2001). Both periods indude a full twelve months sales to Met-Ed and Penelec to supply a portion of their PLR for the pre-merger companies. Net cash provided from operating supply requirements in Pennsylvania, as well as BGS sales in activities was $1.915 billion in 2002 and $1.282 billion in 2001.

New Jersey and sales under several other contracts. Retail kilowatt- The modest contribution to operating cash flows in 2002 by the hour sales revenues increased $136.4 million as a result of former GPU companies reflects in part the deferrals of purchased expanding kilowatt-hour sales within Ohio under Ohio's electricity power costs related to their PLR obligations (see State Regulatory choice program. Total electric sales revenue increased $621.7 Matters - New Jersey and - Pennsylvania below). Cash flows million in 2002 from 2001, accounting for almost all of the net provided from 2002 operating activities of our pre-merger increase in revenues. Offsetting the higher electric sales revenue companies and former GPU companies are as follows:

were reduced natural gas revenues ($171.7 million) primarily due to lower prices and less revenue from FSG ($65.5 million) reflecting the sluggish economy. Internal sales to the regulated services segment decreased $179.8 million in large part due to the impact of customer shopping reducing requirements by the 13

of 2002. CEI, Met-Ed and Penelec have no restrictions on the Operating Cash Flows 2002 2001 issuance of preferred stock (see Note 5G - Long-Term Debt (inmillions) for discussion of debt covenants)

Pre-merger companies At the end of 2002, our common equity as a percentage Cash earnings "I $1,149 $1,551 of capitalization stood at 38% compared to 35% and 42% at Working capital and other 315 21 the end of 2001 and 2000, respectively The lower common Total pre-merger companies 1,464 1,572 equity percentage in 2002 compared to 2000 resulted from Former GPU companies 563 166 the effect of the GPU acquisition. The increase in the 2002 Eliminations (112) (456) equity percentage from 2001 primarily reflects net redemptions Total $1,915 $1,282 of preferred stock and long-term debt, financed in part by short-term borrowings, and the increase in retained earnings.

(iVncludesnet income, depreciation and amortization, deferred costs recoverable as regulatory assets, deferred income taxes, Cash Flows From Investing Activities investment tax credits and major noncash charges.

Net cash flows used in investing activities totaled $816 million in 2002. The net cash used for investing principally resulted Excluding the former GPU companies, cash flows from from property additions Regulated services expenditures for operating activities totaled $1 464 billion in 2002 primarily due property additions primanly include expenditures supporting to cash earnings and to a lesser extent working capital and other the distnbution of electricity Expenditures for property additions changes In 2001, cash flows from operating activities totaled by the competitive services segment are principally generation-

$1 572 billion principally due to cash earnings.

related innduding capital additions at the Davis-Besse nud ear Cash Flows From Financing Activities plant dunng its extended outage. The following table summarizes In 2002, the net cash used for financing activities of $1 123 2002 investments by our regulated services and competitive billion primanly reflects the redemptions of debt and preferred services segments stock shown below In 2001, net cash provided from financing activities totaled $1 964 billion, primarily due to $4 billion of Summary of 2002 Cash Flows Used for Investing Activities Property long-term debt issued in connection with the GPU acquisition, Additions Investments Other Total which was partially offset by $2.1 billion of redemptions and (Inmillions) refinancings The following table provides details regarding Regulated Services $(490) $ 87 $(21) $(424) new issues and redemptions during 2002. Competitive Services (403) - 10 (393)

Other (105) 149' (54) (10)

Securities Issued or Redeemed 2002 Eliminations - - 11 11 (Inmillions) Total $(998) $236 $ (54) $(816)

New Issues Pollution Control Notes $ 143 *Includes $155 million of cash proceeds from the sale of Avon (see Note 3)

Transition Bonds (See Note 5H) 320 Unsecured Notes 210 In 2001, cash flows used in investing activities totaled $3 075 Other, principally debt discounts (4) billion, principally due to the GPU acquisition ($2 013 billion)

$ 669 and property additions ($852 million).

Redemptions Our cash requirements in 2003 for operating expenses, con-First Mortgage Bonds $ 728 Pollution Control Notes 93 struction expenditures, scheduled debt maturities and preferred Secured Notes 278 stock redemptions are expected to be met without increasing Unsecured Notes 189 our net debt and preferred stock outstanding Available borrowing Preferred Stock 522 capacity under short-term credit facilities will be used to manage Other, principally redemption premiums 21 working capital requirements Over the next three years, we

$1,831 expect to meet our contractual obligations with cash from operations Thereafter, we expect to use a combination of cash Short-term Borrowings, Net $ 479 from operations and funds from the capital markets Contractual Obligations We had approximately $1.093 billion of short-term indebted- Less More ness at the end of 2002 compared to $614.3 million at the end than 1-3 3-5 than of 2001 Available borrowing capability induded $177 million Total 1 Year Years Years 5 Years under the $1.5 billion revolving lines of credit and $64 million (Inmillions) under bilateral bank facilities. At the end of 2002, OE, CEI, TE Long-term debt $12,465 $1,073 $2,210 $1,654 $ 7,528 and Penn had the aggregate capability to issue $2 1 billion of Short-term borrowings 1,093 1,093 - - -

additional first mortgage bonds (FMB) on the basis of property Preferred stock!" 445 2 4 14 425 additions and retired bonds JCP&L, Met-Ed and Penelec no Capital leases"i 31 5 11 7 8 longer issue FMB other than as collateral for senior notes, since Operating leases' 2.697 153 365 349 1,830 their senior note indentures prohibit them (subject to certain Purchasesi'i 13,156 2,149 2,902 2,634 5,471 exceptions) from issuing any debt which is senior to the senior Total $29,887 $4,475 $5,492 $4,658 $15,262 notes As of December 31, 2002, JCP&L, Met-Ed and Penelec had the aggregate capability to issue $474 million of additional "'Subject to mandatory redemption

"'See Note 4 senior notes based upon FMB collateral Based upon applicable "'Fuel and powerpurchases under contracts with fixed or minimum earnings coverage tests and their respective charters, OE, Penn, quantities andapproximate timing TE and JCP&L could issue a total of $4 3 billion of preferred stock (assuming no additional debt was issued) as of the end First Energy 14

Our capital spending for the period 2003-2007 is expected to be plants from FirstEnergy and Fitch's expectation of subsequent about $3.1 billion (excluding nuclear fuel), of which approxi- delays in debt reduction. On August 1, 2002, S&P concluded mately $727 million applies to 2003. Investments for additional that while NRG's liquidity position added uncertainty to our nuclear fuel during the 2003-2007 period are estimated to be sale of power plants to NRG, our ratings would not be affected.

approximately $485 million, of which about $69 million applies S&P found our cash flows sufficiently stable to support a con-to 2003. During the same period, our nuclear fuel investments tinued (although delayed) program of debt and preferred stock are expected to be reduced by approximately $483 million and redemption. S&P noted that it would continue to closely monitor

$88 million, respectively, as the nuclear fuel is consumed. our progress on various initiatives. On January 21, 2003, S&P In May 2002, we sold a 79.9 percent equity interest in Avon, indicated its concern about our disclosure of non-cash charges our former wholly owned holding company of Midlands related to deferred costs in Pennsylvania, pension and other Electricity plc, to Aquila, Inc. (formerly UtiliCorp United) for post-retirement benefits, and Emdersa, which were higher than approximately $1.9 billion (including assumption of $1.7 billion anticipated in the third quarter of 2002. S&P identified the of debt). We received approximately $155 million in cash proceeds restart of the Davis-Besse nuclear plant ".. without significant and approximately $87 million of long-term notes (representing delay beyond April 2003... as key to maintaining our current the present value of $19 million per year to be received over debt ratings. S&P also identified other issues it would continue six years beginning in 2003). In the fourth quarter of 2002, to monitor including: our deleveraging efforts, free cash generated we recorded a $50 million charge to reduce the carrying value during 2003, the JCP&L rate case, successful hedging of our of our remaining Avon 20.1 percent equity investment. short power position, and continued capture of projected On August 8, 2002, we notified NRG that we were canceling a merger savings. While we anticipate being prepared to restart November 2001 agreement to sell four fossil plants for approxi- the Davis-Besse plant in the spring of 2003 (see Davis-Besse mately $1.5 billion ($1.355 billion in cash and $145 million in Restoration below), the Nuclear Regulatory Commission (NRC) debt assumption) to NRG because NRG had stated it could not must authorize the unit's restart following a formal inspection complete the transaction under the original terms of the agreement. process prior to our returning the unit to service. Significant delays In December 2002, we announced that we would retain owner- in the planned date of Davis-Besse's return to service or other ship of the plants after reviewing subsequent bids from other factors (identified above) affecting the speed with which we potential buyers. As a result of this decision, we recorded an reduce debt could put additional pressure on our credit ratings.

aggregate charge of $74 million ($43 million, net of tax) in the Other Obligations fourth quarter of 2002, consisting of $57 million ($33 million, Obligations not included on our Consolidated Balance Sheet net of tax) in non-cash depreciation charges that were not recorded primarily consist of sale and leaseback arrangements involving while the plants were pending sale and $17 million ($ 10 million, Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, net of tax) of transaction-related fees (see Note 3).

which are reflected in the operating lease payments disclosed We did not reach a definitive agreement to sell Emdersa, our above (see Note 4). The present value as of December 31, 2002, Argentina operations, as of December 31, 2002. Therefore, we of these sale and leaseback operating lease commitments, net of no longer classified its assets as "Assets Pending Sale" on our trust investments, total $1.5 billion. CEI and TE sell substantially Consolidated Balance Sheet and recorded its cumulative results all of their retail customer receivables, which provided $170 of operations from November 7, 2001 through October 31, million of off-balance sheet financing as of December 31, 2002 2002 as a one-time, after-tax charge of $88.8 million in our (see Note 2C - Revenues).

2002 Consolidated Statement of Income (see Cumulative Effect of Accounting Changes above). In addition, we began recogniz- Guarantees and Other Assurances ing Emdersa's results of operations beginning November 1, As part of normal business activities, we enter into various 2002 in our consolidated financial statements. We continue to agreements on behalf of our subsidiaries to provide financial seek opportunities to sell our foreign operations acquired in the or performance assurances to third parties. Such agreements 2001 merger with GPU. include contract guarantees, surety bonds, and rating-contingent On February 22, 2002, Moody's Investors Service changed its collateralization provisions.

credit rating outlook for FirstEnergy, Met-Ed and Penelec from As of December 31, 2002, the maximum potential future stable to negative. The change was based upon a payments under outstanding guarantees and other assurances decision by the Commonwealth Court of Pennsylvania to totaled $913 million, as summarized below:

remand to the Pennsylvania Public Utility Commission (PPUC) for reconsideration its decision on the mechanism for sharing Maximum Guarantees and Other Assurances Exposure merger savings and reversed the PPUC decisions regarding rate relief and accounting deferrals rendered in connection with its (Inmillions) approval of the GPU merger (see Note 2). On March 20, 2002, FirstEnergy Guarantees of Subsidiaries:

Energy and Energy-Related Contracts"' $670 Moody's changed its outlook for CEI and TE from stable to Financings"""3' 186 negative and retained a negative outlook for FirstEnergy based on the uncertain outcome of the Davis-Besse extended outage. 856 Surety Bonds 26 On April 4, 2002, Standard & Poor's (S&P) changed its outlook Rating-Contingent Collateralization"3 31 for our credit ratings from stable to negative citing recent devel-opments including: damage to the Davis-Besse reactor vessel Total Guarantees and Other Assurances $ 913 head, the Pennsylvania Commonwealth Court decision, and {"Issued for a one-year term, with a 10-day termination right by deteriorating market conditions for some sales of our remaining FirstEnergy non-core assets. On July 31, 2002, Fitch revised its rating outlook "'Includesparental guarantees of subsidiary debt and lease for FirstEnergy, CEL and TE securities to negative from stable. financing including our letters of credit supporting subsidiary debt

"'Issued for various terms.

The revised outlook reflected the adverse impact of the "'Estimated net liability under contracts subject to rating-contingent unplanned Davis-Besse outage, Fitch's judgment about NRG's collateralization provisions.

financial ability to consummate the purchase of four power 15

We guarantee energy and energy-related payments of our subsidiaries involved in energy marketing activities - principally Increase (Decrease) in the Fair Value of Commodity Derivative Contracts to facilitate normal physical transactions involving electricity, Non-Hedge Hedge Total gas, emission allowances and coal We also provide guarantees (Inmillions) to various providers of subsidiary financings principally for the Outstanding net asset (liability) acquisition of property, plant and equipment These agreements as of January 1, 2002 $ 99 $(76 3) $(66 4) legally obligate us and our subsidiaries to fulfill the obligations New contract value when entered - 22 22 of our subsidianes directly involved in these energy and energy- Additions/Increase in value of existing contracts 55 5 73 9 129 4 related transactions or financings where the law might otherwise Change in techniques/assumptions (201) - (201) limit the counterparties' dalms If demands of a counterparty Settled contracts 85 24 3 328 were to exceed the ability of a subsidiary to satisfy existing Outstanding net asset as of obligations, our guarantee enables the counterparty's legal claim December 31, 20020 53 8 24.1 77.9 to be satisfied by our other assets. The likelihood is remote that such parental guarantees will increase amounts otherwise paid Non-commodity net assets as of December 31, 2002 by us to meet our obligations incurred in connection with Interest Rate Swaps(' - 20 5 205 financings and ongoing energy and energy-related contracts.

Most of our surety bonds are backed by various indemnities Net Assets - Derivatives Contracts as of December 31, 200211 $ 538 $446 $98.4 common within the insurance industry. Surety bonds and related guarantees provide additional assurance to outside parties that Impact of Changes in Commodity contractual and statutory obligations will be met in a number Derivative Contracts(')

Income Statement Effects (Pre-Tax) $ 139 $ - $139 of areas induding construction contracts, environmental commit-Balance Sheet Effects ments and various retail transactions. Other Comprehensive Various contracts include credit enhancements in the form Income (OCI) (Pre-Tax) $ - $ 98 2 $ 98 2 of cash collateral, letters of credit or other security in the event Regulatory Liability $ 300 $ - $ 300 of a reduction in credit rating These provisions vary and typically Mincludes $34 2 million in non-hedge commodity denvative contracts which require more than one rating reduction to below investment are offset by a regulatory liabihty minterest rate swaps are pnmarily treated as fair value hedges. Changes In grade by S&P or Moody's to trigger additional collateralization derivative values of the fair value hedges are offset by changes in the hedged debts' premium or discount (see Interest Rate Swap Agreements below)

Market Risk Information "'Excludes $93 million of denvatve contract fair value decrease, as of We use various market risk sensitive instruments, including December 31, 2002, representing our 50% share of Great Lakes Energy derivative contracts, primarily to manage the risk of pnce and Partners, LLC

"'Representsthe increase in value of existing contracts, settled contracts interest rate fluctuations Our Risk Policy Committee, comprised and changes in techniques/assumptions of executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management Derivatives Included on the Consolidated Balance Sheet as of December 31, 2002:

policies and prudent risk management practices Non-Hedge Hedge Total Commodity Price Risk (Inmillions)

We are exposed to market risk pnmarily due to fluctuations Current-in electricity, natural gas and coal prices To manage the volatility Other Assets $ 312 $149 $ 461 Other Liabilities (16 2) (88) (25 0) relating to these exposures, we use a variety of non-denvative Non-Current-and derivative instruments, including forward contracts, options, Other Deferred Charges 39 6 39 4 79 0 futures contracts and swaps The derivatives are used principally Other Deferred Credits (08) (0 9) (1 7) for hedging purposes and, to a much lesser extent, for trading Net assets $53.8 $44 6 $ 98 4 purposes Most of our non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity The valuation of derivative contracts is based on observable derivative contracts related to energy production during 2002 market information to the extent that such information is available.

is summarized in the following table: In cases where such information is not available, we rely on model-based information The model provides estimates of future regional prices for electricity and an estimate of related price volatility We use these results to develop estimates of fair value for financial reporting purposes and for intemal management decision making Sources of information for the valuation of derivative contracts by year are summarized in the following table.

Source of Information - Fair Value by Contract Year 2003 2004 2005 2006 Thereafter Total (Inmillions)

Pricesactivelyquoted"' $160 $15 $ - $- $ - $175 Other external sources") 22 2 2 1 (09) - - 23 4 Prices based on models - - - 55 31 5 37 0 Total3 $38.2 $3 6 $(0.9) $5 5 $31 5 $77.9

"'Exchange traded

"'Broker quote sheets

"'Includes $34 2 million from an embedded option that is offset by a regulatory liability and does not affect earnings FirstEnergy 16

We perform sensitivity analyses to estimate our exposure to Interest Rate Swap Agreements the market risk of our commodity positions. A hypothetical During 2002, FirstEnergy entered into fixed-to-floating 10% adverse shift in quoted market prices in the near term on interest rate swap agreements, to increase the variable-rate both our trading and nontrading derivative instruments would component of its debt portfolio from 16% to approximately not have had a material effect on our consolidated financial 20% at year end. These derivatives are treated as fair value position or cash flows as of December 31, 2002. We estimate hedges of fixed-rate, long-term debt issues - protecting against that if energy commodity prices experienced an adverse 10% the risk of changes in the fair value of fixed-rate debt instruments change, net income for the next twelve months would decrease due to lower interest rates. Swap maturities, call options and by approximately $3.7 million. interest payment dates match those of the underlying obligations.

During the fourth quarter of 2002, in a period of steadily Interest Rate Risk declining market interest rates, we unwound swaps with a Our exposure to fluctuations in market interest rates is reduced total notional amount of $400 million that we had entered since a significant portion of our debt has fixed interest rates, into during the second and third quarters of 2002. Under fair-as noted in the table below.

value accounting, the swaps' fair value ($19.9 million asset)

We are subject to the inherent interest rate risks related was added to the carrying value of the hedged debt and will to refinancing maturing debt by issuing new debt securities.

be amortized to maturity. Offsets to interest expense recorded As discussed in Note 4 to the consolidated financial statements, in 2002 due to the difference between fixed and variable debt our investments in capital trusts effectively reduce future lease rates totaled $17.4 million. As of December 31, 2002, the debt obligations, also reducing interest rate risk. Changes in the market underlying FirstEnergy's outstanding interest rate swaps had a value of our nuclear decommissioning trust funds had been weighted average fixed interest rate of 7.76%, which the swaps recognized by making corresponding changes to the decommis-have effectively converted to a current weighted average variable sioning liability, as described in Note 2 to the consolidated interest rate of 3.04%. GPU Power (through a subsidiary) used financial statements. In conjunction with the adoption of SEAS 143 dollar-denominated interest rate swap agreements in 2002.

"Accounting for Asset Retirement Obligations," on January 1, 2003, In 2001, Penelec, GPU Power (through a subsidiary) and GPU we reclassified unrealized gains or losses to OCI in accordance Electric, Inc. (through GPU Power UK) used interest rate swaps with SEAS 115, "Accounting for Certain Investments in Debt and denominated in dollars and sterling. All of the agreements of Equity.' While fluctuations in the fair value of our Ohio EUOC's the former GPU companies convert variable-rate debt to fixed-trust balances will eventually affect earnings (affecting OCI rate debt to manage the risk of increases in variable interest initially) based on the guidance provided by SEAS 115, our rates. GPU Power's swaps had a weighted average fixed interest non-Ohio EUOC have the opportunity to recover from customers rate of 6.68% in 2002 and 6.99% in 2001. The following sum-the difference between the investments held in trust and their marizes the principal characteristics of the swap agreements:

decommissioning obligations. Thus, in absence of disallowed costs, there should be no earnings effect from fluctuations in Interest Rate Swaps their decommissioning trust balances. As of December 31, December 31, 2002 December 31, 2001 2002, decommissioning trust balances totaled $1.050 billion, Notional Maturity Fair Notional Maturity Fair with $698 million held by our Ohio EUOC and the balance Denomination Amount Date Value Amount Date Value held by our non-Ohio EUOC. As of year end 2002, trust balances (dollars/sterling in millions) included 51% of equity and 49% of debt instruments. Fixed to Floating Rate Dollar 444 2023 15.5 150 2025 5.9 Floating to Fixed Rate Dollar 16 2005 (0.9) 50 2002 (1.8) 26 2005 (1.1)

Sterling 125 2003 (2.3)

Comparison of Carrying Value to Fair Value Year of Maturity 2003 2004 2005 2006 2007 Thereafter Total Fair Value (Dollars in millions)

Assets Investments other than Cash and Cash Equivalents-Fixed Income $ 115 $327 $ 72 $ 90 $ 85 $1,843 $ 2,532 $ 2,538 Average interest rate 7.5% 7.8% 8.1% 8.1% 8.2% 6.3% 6.8%

Liabilities Long-term Debt:

Fixed rate $ 964 $939 $867 $1,401 $252 $6,386 $10,809 $11,119 Average-interest rate 77% 7.2% 8.1% 5.7% 6.7% 7.0% 7.0%

Variable rate $ 109 $399 $ 5 $ 1 $1,142 $ 1,656 $ 1,642 Average interest rate 5.4% 2.6% 6.7% 6.1% 2.7% 2.9%

Short-term Borrowings $1,093 $ 1,093 $ 1,093 Average interest rate 2.4% 2.4%

Preferred Stock $ 2 $ 2 $ 2 $ 2 $ 12 $ 425 $ 445 $ 454 Average dividend rate 7.5% 7.5% 7.5% 7.5% 7.6% 8.1% 8.1%

17

Equity Price Risk with our regional market focus, GPU's former international Included in nuclear decommissioning trusts are marketable companies do not. In December 2001, we divested GasNet, an equity securities carried at their market value of approximately Australian natural gas transmission company. In May 2002, we

$532 million and $568 million as of December 31, 2002 and 2001, sold a 79 9 percent interest in Avon's UK operations to Aquila respectively. A hypothetical 10% decrease in pnces quoted by for approximately $1 9 billion We and Aquila together own all stock exchanges, would result in a $53 million reduction in of the outstanding shares of Avon through a jointly owned sub-fair value as of December 31, 2002 (see Note 2J - Supplemental sidiary, with each company having a 50-percent voting interest.

Cash Flows Information) On August 8, 2002, we notified NRG that we were canceling our agreement with it for its purchase of four fossil plants because Foreign Currency Risk NRG had stated that it could not complete the sale transaction We are exposed to foreign currency risk from investments in under the original terms of the agreement Based on subsequent international business operations acquired through the merger bids received, we concluded that retaining the plants to serve our with GPU While such risks are likely to diminish over time as customers was in the best interest of our customers and our we sell our international operations, we expect such risks to shareholders Following our decision to retain the four plants, continue in the near term. In 2002, we experienced net foreign we performed a comprehensive fossil operations review and currency translation losses in connection with our Argentina subsequently decided to close the Ashtabula C-Plant (three 44 operations (see Note 3 - Divestitures) A hypothetical 20% adverse megawatt (MW), coal-fired boilers) This action is part of our change in our foreign currency positions in the near term would strategy to provide competitively priced energy - replacing less-not have had a material effect on our consolidated financial effident peaking generation in our portfolio of generation resources, position, cash flows or earnings as of December 31, 2002 with the development of new, higher-efficiency peaking plants.

Outlook While deteriorating economic conditions in Argentina delayed We continue to pursue our goal of being the leading regional our sale of Emdersa, we continue to pursue the sale of assets supplier of energy and related services in the northeastern quadrant that do not support our strategy in order to increase our financial of the United States, where we see the best opportunities for flexibility by reducing debt and preferred stock growth We believe that our strategy has received some measure State Regulatory Matters of validation by the major industry events of 2002 and we continue In Ohio, New Jersey and Pennsylvania, laws applicable to to build toward a strong regional presence. We intend to provide electric industry deregulation incduded similar provisions which competitively priced, high-quality products and value-added are reflected in our EUOC's respective state regulatory plans.

services - energy sales and services, energy delivery, power supply However, despite these similarities, the specific approach taken and supplemental services related to our core business As our by each state and for each of our EUOCs varies Those provi-industry changes to a more competitive environment, we have sions include taken and expect to take actions designed to create a larger,

• allowing the EUOC's electric customers to select their stronger regional enterprise that will be positioned to compete generation suppliers, in the changing energy marketplace

• establishing PLR obligations to non-shopping customers Business Organization in the EUOC's service areas, Beginning in 2001, Ohio utilities that offered both competitive

• allowing recovery of potentially stranded investment and regulated retail electric services were required to implement (or transition costs) not otherwise recoverable in a a corporate separation plan approved by the Public Utilities competitive generation market, Commission of Ohio (PUCO) - one which provided a clear . itemizing (unbundling) the price of electricity into separation between regulated and competitive operations Our its component elements - induding generation, transmission, business is separated into three distinct units - a competitive distribution and stranded costs recovery charges; services segment, a regulated services segment and a corporate

• deregulating the EUOC's electric generation businesses, and support segment FES provides competitive retail energy services

• continuing regulation of the EUOC's transmission and while the EUOC continue to provide regulated transmission distribution systems and distribution services FirstEnergy Generation Corp (FGCO), Regulatory assets are costs which the respective regulatory a wholly owned subsidiary of FES, leases fossil and hydroelectric agencies have authorized for recovery from customers in future plants from the EUOC and operates those plants We expect the penods and, without sudh authorization, would have been charged transfer of ownership of EUOC non-nuclear generating assets to to income when incurred All of the regulatory assets are expected FGCO will be substantially completed by the end of the market to continue to be recovered under the provisions of the respective development period in 2005 All of the EUOC power supply transition and regulatory plans as discussed below. The regulatory requirements for the Ohio Companies and Penn are provided assets of the individual companies are as follows:

by FES to satisfy their PLR obligations, as well as grandfathered wholesale contracts. Regulatory Assets as of December 31, Company 2002 2001 Optimizing the Use of Assets A significant step toward being the leading regional supplier (In millions)

OE $1,855 9 $2,025 4 in our target market was achieved when we merged with GPU CEI 939 8 8745 in November 2001, making us the fourth largest investor-owned TE 392 6 3888 electric system in the nation based on the number of customers Penn 156.9 208 8 served Through the merger we are creating a stronger enterprise JCP&L 3,199 0 3,324 8 with greater resources and more opportunities to provide value Met-Ed 1,1179.1 1,320 5 Penelec 599.7 769 8 to our customers, shareholders and employees. However, additional steps must be taken in order to deliver the full value of the merger Total $8,323.0 $8,912 6 While CPU's former domestic electric utility companies fit well FirstEnergy 18

Ohio deferred cost balance totaled approximately $549 million. The FirstEnergy's transition plan (which we filed on behalf of the NJBPU also allowed securitization of JCP&LIs deferred balance to Ohio Companies) included approval for recovery of transition the extent permitted by law upon application by JCP&L and a costs, including regulatory assets, as filed in the transition plan determination by the NJBPU that the conditions of the New through no later than 2006 for OE, mid-2007 for TE and 2008 Jersey restructuring legislation are met.

for CEI, except where a longer period of recovery is provided for In December 2001, the NJBPU authorized the auctioning of in the settlement agreement. The approved plan also granted BGS for the period from August 1, 2002 through July 31, 2003 preferred access over our subsidiaries to nonaffiliated marketers, to meet the electricity demands of all customers who have not brokers and aggregators to 1,120 MW of generation capacity selected an alternative supplier. The results of the February 2002 through 2005 at established prices for sales to the Ohio Companies' auction, with the NJBPU's approval, removed JCP&L's BGS obli-retail customers. Customer prices are frozen through a five-year gation of 5,100 MW for the period August 1, 2002 through market development period (2001-2005), except for certain July 31, 2003. In February 2003, the auctioning of BGS for the limited statutory exceptions including a 5% reduction in the period beginning August 1, 2003 took place. The auction covered price of generation for residential customers. In February 2003, a fixed price bid (applicable to all residential and smaller commer-the Ohio Companies were authorized increases in revenues cial and industrial customers) and an hourly price bid (applicable aggregating approximately $50 million (OE - $41 million, to all large industrial customers) process. JCP&L will sell all self-CEI - $4 million and TE - $5 million) to recover their higher supplied energy (NUGs and owned generation) to the wholesale tax costs resulting from the Ohio deregulation legislation. market with offsets to its deferred energy cost balances.

Our Ohio customers choosing alternative suppliers receive an Pennsylvania additional incentive applied to the shopping credit (generation Effective September 1, 2002, Met-Ed and Penelec assigned component) of 45% for residential customers, 30% for com-their PLR responsibility to FES through a wholesale power sale mercial customers and 15% for industrial customers. The amount which expires in December 2003 and may be extended for each of the incentive is deferred for future recovery from customers -

successive calendar year. Under the terms of the wholesale recovery will be accomplished by extending the respective agreement, FES assumed the supply obligation and the energy transition cost recovery period. If the customer shopping goals supply profit and loss risk, for the portion of power supply established in the agreement had not been achieved by the end requirements not self-supplied by Met-Ed and Penelec under of 2005, the transition cost recovery periods could have been their NUG contracts and other existing power contracts with shortened for OE, CEI and TE to reduce recovery by as much nonaffiliated third party suppliers. This arrangement reduces as $500 million (OE-$250 million, CEI-$170 million and Met-Ed's and Penelec's exposure to high wholesale power prices TE-$80 million). That goal was achieved in 2002. Accordingly, by providing power at or below the shopping credit for their FirstEnergy does not believe that there will be any regulatory uncommitted PLR energy costs during the term of the agreement action reducing the recoverable transition costs.

with FES. FES has hedged most of Met-Ed's and Penelec's New Jersey unfilled PLR obligation through 2005. Met-Ed and Penelec will Under New Jersey transition legislation, all electric distribution continue to defer those cost differences between NUG contract companies were required to file rate cases to determine the level rates and the rates reflected in their capped generation rates.

of unbundled rate components to become effective August 1, 2003. In its February 21, 2002 decision on Petitions for Review On August 1, 2002, JCP&L submitted two rate filings with the regarding the June 2001 PPUC orders which approved the New Jersey Board of Public Utilities (NJBPU). The first filing FirstEnergy/GPU merger and provided Met-Ed and Penelec requested increases in base electric rates of approximately $98 deferral accounting treatment for energy costs, the Commonwealth million annually. The second filing was a request to recover Court of Pennsylvania affirmed the PPUC merger decision, deferred costs that exceeded amounts being recovered under remanding the decision to the PPUC only with respect to the the current market transition charge (MTC) and societal benefits issue of merger savings. The Court reversed the PPUC's decision charge (SBC) rates; one proposed method of recovery of these regarding the PLR obligations of Met-Ed and Penelec, and costs is the securitization of the deferred balance. This securiti- denied the companies authority to defer for future recovery zation methodology is similar to the Oyster Creek securitization the difference between their wholesale power costs and the discussed below. Hearings began in February 2003. The amount that they collect from retail customers. FirstEnergy and Administrative Law Judge's recommended decision is due in June the PPUC each filed a Petition for Allowance of Appeal with 2003 and the NJBPU's subsequent decision is due in July 2003. the Pennsylvania Supreme Court in March 2002, asking it to JCP&L's regulatory plan provided for the ability to securitize review the Commonwealth Court decision. In September 2002, stranded costs associated with the divested Oyster Creek Nuclear FirstEnergy established reserves against Met-Ed's and Penelec's Generating Station. A February 2002 NJBPU order authorized PLR deferred energy costs which aggregated $287.1 million.

JCP&L to issue $320 million of transition bonds to securitize The reserves reflected the potential adverse impact of a pending the recovery of these costs and provided for a usage-based Pennsylvania Supreme Court decision whether to review the non-bypassable transition bond charge and for the transfer of Commonwealth Court ruling. FirstEnergy recorded an aggregate the bondable transition property to another entity. JCP&L sold non-cash charge to income of $55.8 million ($32.6 million net

$320 million of transition bonds through a wholly owned of tax) for the deferred costs incurred subsequent to the merger.

subsidiary, JCP&L Transition Funding LLC, in June 2002 - that The reserve for the remaining $231.3 million of pre-merger debt is recognized on the Consolidated Balance Sheet (see Note deferred costs increased goodwill by an aggregate net of tax 5). JCP&L is permitted to defer for future collection from cus- amount of $135.3 million. On January 17, 2003, the Pennsylvania tomers the amounts by which its costs of supplying BGS to Supreme Court denied further appeals of the Commonwealth non-shopping customers and costs incurred under nonutility Court's decision which effectively affirmed the PPUC's order generation (NUG) agreements exceed amounts collected through approving the merger between FirstEnergy and GPU, let stand BGS and MTC rates. As of December 31, 2002, the accumulated the Commonwealth Court's denial of PLR rate relief for Met-Ed and Penelec and remanded the merger savings issue back to the 19

PPUC. Because FirstEnergy had already reserved for the deferred Davis-Besse Restoration energy costs and FES has largely hedged the anticipated PLR energy On Apnl 30, 2002, the NRC initiated a formal inspection supply requirements for Met-Ed and Penelec through 2005, process at the Davis-Besse nuclear plant This action was taken FirstEnergy, Met-Ed and Penelec believe that the disallowance in response to corrosion found by FENOC in the reactor vessel of competitive transition charge recovery of PLR costs above head near the nozzle penetration hole during a refueling outage Met-Ed's and Penelec's capped generation rates will not have in the first quarter of 2002 The purpose of the formal inspection a future adverse financial impact process is to establish cnteria for NRC oversight of the licensee's performance and to provide a record of the major regulatory FERC Regulatory Matters and licensee actions taken, and technical issues resolved, leading On December 19, 2002, the Federal Energy Regulatory to the NRC's approval of restart of the plant Commission (FERC) granted unconditional Regional Restart activities indude both hardware and management Transmission Organization status to PJM Interconnection, LLC issues In addition to refurbishment and installation work at which indudes JCP&L, Met-Ed and Penelec as transmission the plant, we have made significant management and human owners Also, on December 19, 2002, the FERC conditionally performance changes with the intent of establishing the proper accepted GridAmerica's filing to become an independent safety culture throughout the workforce Work was completed transmission company within Midwest Independent System on the reactor head during 2002 and is continuing on efforts Operator, Inc (MISO). GridAmenca will operate ATSl's trans-designed to enhance the unit's reliability and performance. We mission facilities GridAmercia expects to begin operations are also accelerating maintenance work that had been planned in the second quarter of 2003 subject to approval of certain for future refueling and maintenance outages. At a meeting with compliance filings with the FERC Compliance filings were the NRC in November 2002, we discussed plans to test the made by the GndAmerica companies (including ATSI) on bottom of the reactor for leaks and to install a state-of-the-art January 31 and February 19, 2003.

leak-detection system around the reactor The additional main-Supply Plan tenance work being performed has expanded the previous We are obligated to provide generation service for an estimated estimates of restoration work We anticipate that the unit will 2003 peak demand of 18,450 MW. These obligations arise from be ready for restart in the spring of 2003 after completion of the customers who have elected to continue to receive generation additional maintenance work and regulatory reviews The NRC service from the EUOCs under regulated retail rate tanffs and must authorize restart of the plant following its formal inspection from customers who have selected FES as their alternate generation process before the unit can be returned to service. While the provider Geographically, approximately 11,000 MW of the additional maintenance work has delayed our plans to reduce obligations are in the East Central Area Reliability Agreement post-merger debt levels we believe such investments in the market and 7,450 MW are in the PIM ISO market area. These unit's future safety, reliability and performance to be essential obligations include approximately 1,700 MW of load that FES Significant delays in Davis-Besse's return to service, which depends obtained in New Jersey's BGS auction Additionally, if alternative on the successful resolution of the management and technical suppliers fail to deliver power to their customers located mn the issues as well as NRC approval, could trigger an evaluation for EUOCs' service areas, we could be required to serve an additional impairment of the nuclear plant (see Significant Accounting 1,400 MW as PLR. In the event we must procure replacement Policies below) power for an alternative supplier, the cost of that power would The actual costs (capital and expense) associated with be recovered under the applicable state regulatory rules the extended Davis-Besse outage in 2002 and estimated costs To meet their obligations, our subsidiaries have 13,101 MW in 2003 are of installed generating capacity, 1,540 MW of long-term power purchase contracts (exceeding one year), 2,800 MW under Costs of Davis-Besse Extended Outage short-term purchase contracts and approximately 800 MW of (In millions) interruptible and controllable load contracts. Any additional power 2002 - Actual requirements will be satisfied through spot market purchases Capital Expenditures:

Reactor head and restart $ 63 3 All utilities in New Jersey are required to participate in an annual auction through which the entire obligation for all of Incremental Expenses (pre-tax) their BGS requirements are auctioned to alternate suppliers Maintenance $115 0 Through this auction process, the 286 MW of JCP&L's installed Fuel and purchased power 119 5 capacity and approximately 800 MW of long-term purchases Total $2345 from NUGs are made available to the winning bidders. FES 2003 - Estimated participates in this annual auction as an alternate supplier and Primarily operating expenses (pre-tax) currently has an obligation to provide 1,700 MW of power Maintenance (including acceleration of programs) $50 for summer peak demand through July 31, 2003 Replacement power per month $12-18 We have fully hedged the on-peak replacement energy supply for Davis-Besse through the spring of 2003 and have completed some hedging for the balance of 2003 as well FirstEnergy 20

Environmental Matters costs and the financial ability of other nonaffiliated entities to We believe we are in compliance with the current sulfur dioxide pay. In addition, JCP&L has accrued liabilities for environmental (S02) and nitrogen oxide (NOx) reduction requirements under remediation of former manufactured gas plants in New Jersey; the Clean Air Act Amendments of 1990. In 1998, the Environmental those costs are being recovered by JCP&L through the SBC. The Protection Agency (EPA) finalized regulations requiring Companies have accrued liabilities aggregating approximately additional NOx reductions in the future from our Ohio and $54.3 million as of December 31, 2002.

Pennsylvania facilities. Various regulatory and judicial actions The effects of compliance on the Companies with regard to have since sought to further define NOx reduction requirements environmental matters could have a material adverse effect on (see Note 7D - Environmental Matters). We continue to evaluate our earnings and competitive position. These environmental our compliance plans and other compliance options. regulations affect our earnings and competitive position to the Violations of federally approved S02 regulations can result in extent we compete with companies that are not subject to such shutdown of the generating unit involved and/or civil or criminal regulations and therefore do not bear the risk of costs associated penalties of up to $31,500 for each day a unit is in violation. with compliance, or failure to comply, with such regulations.

The EPA has an interim enforcement policy for S02 regulations We believe we are in material compliance with existing regulations, in Ohio that allows for compliance based on a 30-day averaging but are unable to predict how and when applicable environmental period. We cannot predict what action the EPA may take in the regulations may change and what, if any, the effects of any such future with respect to the interim enforcement policy. change would be.

In 1999 and 2000, the EPA issued Notices of Violation Legal Matters (NOV) or a Compliance Order to nine utilities covering 44 Various lawsuits, claims and proceedings related to our normal power plants, including the W.H. Sammis Plant. In addition, business operations are pending against FirstEnergy and its the U.S. Department of Justice filed eight civil complaints subsidiaries. The most significant are described below against various investor-owned utilities, which included a Due to our merger with GPU, we own Unit 2 of the Three Mile complaint against OE and Penn in the U.S. District Court for Island Nuclear Plant (TMI-2). As a result of the 1979 TMI-2 the Southern District of Ohio, for which hearings began on accident, claims for alleged personal injury against JCP&L, Met-Ed, February 3, 2003. The NOV and complaint allege violations Penelec and CPU had been filed in the U.S. District Court for of the Clean Air Act (CAA). The civil complaint against OE and the Middle District of Pennsylvania. In 1996, the District Court Penn requests installation of 'best available control technology' granted a motion for summary judgment filed by the GPU as well as civil penalties of up to $27,500 per day. Although companies and dismissed the ten initial "test cases" which had unable to predict the outcome of these proceedings, we believe been selected for a test case trial. On January 15, 2002, the the Sammis Plant is in full compliance with the CAA and that District Court granted our motion for summary judgment on the NOV and complaint are without merit. Penalties could be the remaining 2,100 pending claims. On February 14, 2002, imposed if the Sammis Plant continues to operate without the plaintiffs filed a notice of appeal of this decision (see Note correcting the alleged violations and a court determines that 7E - Other Legal Proceedings). In December 2002, the Court the allegations are valid. The Sammis Plant continues to operate of Appeals for the Third Circuit refused to hear the appeal while these proceedings are pending.

which effectively ended further legal action for those claims.

In December 2000, the EPA announced it would proceed In July 1999, the Mid-Atlantic states experienced a severe heat with the development of regulations regarding hazardous air storm which resulted in power outages throughout the service pollutants from electric power plants. The EPA identified mercury areas of many electric utilities, including JCP&L. In an investiga-as the hazardous air pollutant of greatest concern. The EPA tion into the causes of the outages and the reliability of the established a schedule to propose regulations by December transmission and distribution systems of all four New Jersey 2003 and issue final regulations by December 2004. The future electric utilities, the NJBPU concluded that there was not a cost of compliance with these regulations may be substantial.

prima facie case demonstrating that, overall, JCP&L provided As a result of the Resource Conservation and Recovery unsafe, inadequate or improper service to its customers. Two class Act of 1976, as amended, and the Toxic Substances Control action lawsuits (subsequently consolidated into a single proceed-Act of 1976, federal and state hazardous waste regulations have ing) were filed in New Jersey Superior Court in July 1999 against been promulgated. Certain fossil-fuel combustion waste products, JCP&L, GPU and other GPU companies seeking compensatory such as coal ash, were exempted from hazardous waste disposal and punitive damages arising from the service interruptions of requirements pending the EPA's evaluation of the need for July 1999 in the JCP&L territory. In May 2001, the court denied future regulation. The EPA has issued its final regulatory deter-without prejudice the defendant's motion seeking decertification mination that regulation of coal ash as a hazardous waste is of the class. Discovery continues in the class action, but no trial unnecessary. In April 2000, the EPA announced that it will date has been set. In October 2001, the court held argument on develop national standards regulating disposal of coal ash the plaintiffs' motion for partial summary judgment, which under its authority to regulate nonhazardous waste.

contends that JCP&L is bound to several findings of the NJBPU The Companies have been named as "potentially responsible investigation. The plaintiffs' motion was denied by the Court in parties' (PRPs) at waste disposal sites which may require cleanup November 2001 and the plaintiffs' motion seeking permission under the Comprehensive Environmental Response, Compensation to file an appeal on this denial of their motion was rejected by and Liability Act of 1980. Allegations of disposal of hazardous the New Jersey Appellate Division. We have also filed a motion substances at historical sites and the liability involved are often for partial summary judgment that is currently pending before unsubstantiated and subject to dispute; however, federal law the Superior Court. We are unable to predict the outcome of provides that all PRPs for a particular site be held liable on a joint these matters.

and several basis. Therefore, potential environmental liabilities have been recognized on the Consolidated Balance Sheet as of December 31, 2002, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such 21

Implementation of Recent Accounting Standard assets to assess their ultimate recoverability within the approved In June 2002, the Emerging Issues Task Force (EITF) reached regulatory guidelines Impairment risk associated with these a partial consensus on Issue No 02-03, 'Issues Involved in assets relates to potentially adverse legislative, judicial or regulatory Accounting for Derivative Contracts Held for Trading Purposes actions in the future and Contracts Involved in Energy Trading and Risk Management Derivative Accounting Activities.' Based on the EITF's partial consensus position, for Determination of appropriate accounting for derivative periods after July 15, 2002, mark-to-market revenues and expenses transactions requires the involvement of management repre-and their related kilowatt-hour (KWVH) sales and purchases on senting operations, finance and risk assessment. In order to energy trading contracts must be shown on a net basis in the determine the appropriate accounting for denvative transactions, Consolidated Statements of Income We previously reported the provisions of the contract need to be carefully assessed in such contracts as gross revenues and purchased power costs accordance with the authoritative accounting literature and Comparative quarterly disclosures and the Consolidated management's intended use of the derivative New authoritative Statements of Income for revenues and expenses have been redas-guidance continues to shape the application of derivative sified for 2002 only to conform with the revised presentation (see accounting Management's expectations and intentions are Note 11 - Summary of Quarterly Financial Data) In addition, the key factors in determining the appropriate accounting for a related KNVH sales and purchases statistics described above under derivative transaction and, as a result, such expectations and Results of Operations were reclassified (7.2 billion KCH in intentions are documented. Derivative contracts that are 2002 and 3 7 billion KWH in 2001). The following table dis-determined to fall within the scope of SFAS 133, as amended, plays the impact of changing to a net presentation for our ener-must be recorded at their fair value Active market prices are gy trading operations not always available to determine the fair value of the later 2002 Impact of Recording Energy Trading Net years of a contract, requiring that various assumptions and Revenues Expenses estimates be used in their valuation We continually monitor (Inmillhons) our derivative contracts to determine if our activities, expectations, Total before adjustment $12,420 $10,238 intentions, assumptions and estimates remain valid. As part Adjustment (268) (268) of our normal operations, *weenter into significant commodity Total as reported $12,152 $ 9.970 contracts, as well as interest rate and currency swaps, which increase the impact of derivative accounting judgments Significant Accounting Policies Revenue Recognition We prepare our consolidated financial statements in accordance We follow the accrual method of accounting for revenues, with accounting pnnciples that are generally accepted in the recognizing revenue for KVH that have been delivered but not United States. Application of these pnnciples often requires a yet billed through the end of the accounting period The deter-high degree of judgment, estimates and assumptions that affect mination of unbilled revenues requires management to make financial results All of our assets are subject to their own specific vanous estimates including risks and uncertainties and are regularly reviewed for impair-

• Net energy generated or purchased for retail load ment. Assets related to the application of the policies discussed

• Losses of energy over transmission and distribution lines below are similarly reviewed with their risks and uncertainties

• Mix of KW1H usage by residential, commercial reflecting these specific factors Our more significant accounting and industrial customers policies are described below

• KMH of customers receiving electricity Purchase Accounting - Acquisition of GPU from alternative suppliers Purchase accounting requires judgment regarding the Pension and Other Postretirement Benefits Accounting allocation of the purchase pnce based on the fair values of the Our reported costs of providing non-contributory defined assets acquired (induding intangible assets) and the liabilities pension benefits and postemployment benefits other than assumed The fair values of the acquired assets and assumed pensions (OPEB) are dependent upon numerous factors liabilities for GPU were based primarily on estimates The more resulting from actual plan experience and certain assumptions.

significant of these induded the estimation of the fair value of Pension and OPEB costs are affected by employee demographics the international operations, certain domestic operations and (including age, compensation levels, and employment periods),

the fair value of the pension and other post-retirement benefit the level of contributions we make to the plans, and earnings assets and liabilities The purchase price allocations for the on plan assets Such factors may be further affected by business CPU acquisition were finalized in the fourth quarter of 2002 combinations (such as our merger with CPU, Inc in November (see Note 12) 2001), which impacts employee demographics, plan experience Regulatory Accounting and other factors. Pension and OPEB costs may also be affected Our regulated services segment is subject to regulation that by changes to key assumptions, including anticipated rates of sets the prices (rates) it is permitted to charge its customers return on plan assets, the discount rates and health care trend based on costs that the regulatory agencies determine we are rates used in determining the projected benefit obligations permitted to recover At times, regulators permit the future and pension and OPEB costs.

recovery through rates of costs that would be currently charged In accordance with SFAS 87, 'Employers' Accounting for to expense by an unregulated company This rate-making Pensions' and SFAS 106, "Employers' Accounting for Postretirement process results in the recording of regulatory assets based on Benefits Other Than Pensions,' changes in pension and OPEB anticipated future cash inflows As a result of the changing obligations associated with these factors may not be immediately regulatory framework in each state in which we operate, a recognized as costs on the income statement, but generally are significant amount of regulatory assets have been recorded - recognized in future years over the remaining average service

$8 3 billion as of December 31, 2002 We regularly review these period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB FirstEnergy 22

obligations and the varying market conditions likely to occur reverse in future periods to the extent the fair value of trust assets over long periods of time. As such, significant portions of pen- exceed the accumulated benefit obligation. The amount of pension sion and OPEB costs recorded in any period may not reflect the liability recorded as of December 31, 2002 increased due to the actual level of cash benefits provided to plan participants and lower discount rate assumed and reduced market value of plan are significantly influenced by assumptions about future market assets as of December 31, 2002. Our non-cash, pre-tax pension conditions and plan participants' experience. and OPEB expense under SEAS 87 and SFAS 106 is expected to In selecting an assumed discount rate, we consider currently increase by $125 million and $45 million, respectively - a total available rates of return on high-quality fixed income invest- of $170 million in 2003 as compared to 2002.

ments expected to be available during the period to maturity Long-Lived Assets of the pension and other postretirement benefit obligations.

In accordance with SEAS No. 144, "Accounting for the Due to the significant decline in corporate bond yields and Impairment or Disposal of Long-Lived Assets,' we periodically interest rates in general during 2002, we reduced the assumed evaluate our long-lived assets to determine whether conditions discount rate as of December 31, 2002 to 6.75% from 7.25%

exist that would indicate that the carrying value of an asset may used in 2001 and 7.75% used in 2000.

not be fully recoverable. The accounting standard requires that Our assumed rate of return on pension plan assets considers if the sum of future cash flows (undiscounted) expected to historical market returns and economic forecasts for the types result from an asset, is less than the carrying value of the asset, of investments held by our pension trusts. The market values an asset impairment must be recognized in the financial of our pension assets have been affected by sharp declines in statements. If impairment, other than of a temporary nature, the equity markets since mid-2000. In 2002, 2001 and 2000, has occurred, we recognize a loss - calculated as the difference plan assets have earned (11.3)%, (5.5)% and (0.3)%, respectively.

between the carrying value and the estimated fair value of the Our pension costs in 2002 were computed assuming a 10.25%

asset (discounted future net cash flows).

rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon our Goodwill projection of future returns and pension trust investment In a business combination, the excess of the purchase price allocation of approximately 60% large cap equities, 10% small over the estimated fair values of the assets acquired and liabilities cap equities and 30% bonds. assumed is recognized as goodwill. Based on the guidance provided Based on pension assumptions and pension plan assets as by SFAS 142, we evaluate our goodwill for impairment at least of December 31, 2002, we will not be required to fund our annually and would make such an evaluation more frequently pension plans in 2003. While OPEB plan assets have also been if indicators of impairment should arise. In accordance with the affected by sharp declines in the equity market, the impact is accounting standard, if the fair value of a reporting unit is less not as significant due to the relative size of the plan assets. than its carrying value including goodwill, an impairment for However, health care cost trends have significantly increased goodwill must be recognized in the financial statements. If and will affect future OPEB costs. The 2003 composite health impairment were to occur we would recognize a loss - calculated care trend rate assumption is approximately 10%-12% gradually as the difference between the implied fair value of a reporting decreasing to 5% in later years, compared to our 2002 assump- unit's goodwill and the carrying value of the goodwill. Our tion of approximately 10% in 2002, gradually decreasing to annual review was completed in the third quarter of 2002. The 4%-6% in later years. In determining our trend rate assumptions, results of that review indicated no impairment of goodwill -

we included the specific provisions of our health care plans, fair value was higher than carrying value for each of our reporting the demographics and utilization rates of plan participants, units. The forecasts used in our evaluations of goodwill reflect actual cost increases experienced in our health care plans, and operations consistent with our general business assumptions.

projections of future medical trend rates. The effect on our Unanticipated changes in those assumptions could have a sig-SFAS 87 and 106 costs and liabilities from changes in key nificant effect on our future evaluations of goodwill. As of assumptions are as follows: December 31, 2002, we had $5.9 billion of goodwill that primarily relates to our regulated services segment.

Increase in Costs from Adverse Changes inKey Assumptions Recently Issued Accounting Standards Not Yet Implemented Assumption Adverse Change Pension OPEB Total (Inmillions) SFAS 143, "Accounting for Asset Retirement Obligations" Discount rate Decrease by 0.2591 $10.3 $ 7.4 $17.7 In June 2001, the FASB issued SFAS 143. The new statement Long-term return provides accounting standards for retirement obligations associ-on assets Decrease by 0.25% $ 6.9 $ 1.2 $ 8.1 ated with tangible long-lived assets, with adoption required Health care trend rate Increase by 1% na $20.7 $20.7 by January 1, 2003. SEAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the Increase inMinimum Liability period in which it is incurred. The associated asset retirement Discount rate Decrease by 0.25% $99.4 na $99.4 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, As a result of the reduced market value of our pension plan resulting in a period expense. However, rate-regulated entities assets, we were required to recognize an additional minimum may recognize regulatory assets or liabilities if the criteria for liability as prescribed by SFAS 87 and SFAS 132, "Employers' such treatment are met. Upon retirement, a gain or loss would Disclosures about Pension and Postretirement Benefits," as of be recorded if the cost to settle the retirement obligation December 31, 2002. We eliminated our prepaid pension asset differs from the carrying amount.

of $286.9 million and established a minimum liability of We have identified applicable legal obligations as defined

$548.6 million, recording an intangible asset of $78.5 million under the new standard, principally for nuclear power plant and reducing OCI by $444.2 million (recording a related decommissioning. Upon adoption of SFAS 143, in January 2003, deferred tax benefit of $312.8 million). The charge to OCI will asset retirement costs of $807 million were recorded as part of 23

the carrying amount of the related long-lived asset, offset by FASB Interpretation (FIN) No. 45, "Guarantor's Accounting accumulated depreciation of $437 million Due to the increased and Disclosure Requirements for Guarantees, Including carrying amount, the related long-lived assets were tested for Indirect Guarantees of Indebtedness of Others - an interpre-impairment in accordance with SFAS 144. No impairment was tation of FASB Statements No. 5, 57, and 107 and rescission indicated The asset retirement liability at the date of adoption of FASB Interpretation No. 34" was $1 109 billion. As of December 31, 2002, FirstEnergy had The FASB issued FIN 45 in January 2003. This interpretation recorded decommissioning liabilities of $1 232 billion, including identifies minimum guarantee disciosures required for annual unrealized gains on decommissioning trust funds of $12 million periods ending after December 15, 2002 (see Guarantees and The change in the estimated liabilities resulted from changes Other Assurances) It also clanfies that providers of guarantees in methodology and various assumptions, including changes in must record the fair value of those guarantees at their inception the projected dates for decommissioning. This accounting guidance is applicable on a prospective basis to Management expects that substantially all nuclear decommis- guarantees issued or modified after December 31, 2002 We do sioning costs for Met-Ed, Penelec, JCP&L and Penn will be not believe that implementation of FIN 45 will be material but recoverable through their regulated rates Therefore, wve recog- wve will continue to evaluate anticipated guarantees.

nized a regulatory liability of $185 million upon adoption of SFAS 143 for the transition amounts related to establishing FIN 46, "Consolidation of Variable Interest Entities -

the asset retirement obligations for nuclear decommissioning an interpretation of ARB 51" The remaining cumulative effect adjustment to recognize the In January 2003, the FASB issued this interpretation of undepreciated asset retirement cost and the asset retirement lia- ARB No 51, 'Consolidated Financial Statements' The new bility offset by the reversal of the previously recorded decom- interpretation provides guidance on consolidation of variable missioning liabilities was a $298 million increase to income interest entities (VIEs), generally defined as certain entities in

($174 million net of tax) The $12 million of unrealized gains which equity investors do not have the characteristics of a

($7 million net of tax) included in the decommissioning liabili- controlling financial interest or do not have sufficient equity ty balances as of December 31, 2002, were offset against OCI at risk for the entity to finance its activities without additional upon adoption of SFAS 143 subordinated financial support from other parties This inter-pretation requires an enterprise to disciose the nature of its SFAS 146, "Accounting for Costs Associated with Exit involvement with a VIE if the enterprise has a significant variable or Disposal Activities" interest in the VIE and to consolidate a VIE if the enterprise is This statement, which was issued by the FASB in July 2002, the primary beneficiary VlEs created after January 31, 2003 are requires the recognition of costs associated with exit or disposal immediately subject to the provisions of FIN 46 VIEs created activities at the time they are incurred rather than when man- before February 1, 2003 are subject to this interpretation's pro-agement commits to a plan of exit or disposal. It also requires visions in the first interim or annual reporting period beginning the use of fair value for the measurement of such liabilities after June 15, 2003 (our third quarter of 2003) The FASB also The new standard supersedes guidance provided by EITF Issue identified transitional disclosure provisions for all financial No 94-3, 'Liability Recognition for Certain Employee statements issued after January 31, 2003 Termination Benefits and Other Costs to Exit an Activity FirstEnergy currently has transactions with entities in (Including Certain Costs Incurred in a Restructunng) ' This connection with sale and leaseback arrangements, the sale of new standard was effective for exit and disposal activities initiated preferred securities and debt secured by bondable property, after December 31, 2002 Since it is applied prospectively, there which may fall within the scope of this interpretation, and will be no impact upon adoption However, SFAS 146 could which are reasonably possible of meeting the definition of a change the timing and amount of costs recognized in connection VIE in accordance with FIN 46 with future exit or disposal activities We currently consolidate the majority of these entitles SFAS 148, "Accounting for Stock-Based Compensation - and believe wve will continue to consolidate following the Transition and Disclosure" adoption of FIN 46 In addition to the entities we are currently SFAS 148 provides alternative approaches for voluntanly tran- consolidating we believe that the PNBV Capital Trust, which sitioning to the fair value method of accounting for stock-based reacquired a portion of the off-balance sheet debt issued in compensation as descnbed by SFAS 123 "Accounting for Stock- connection with the sale and leaseback of OE's interest in Based Compensation.' Under current GAAP, wve do not intend the Perry Nuclear Plant and Beaver Valley Unit 2, would require to adopt fair value accounting It also amends SFAS 123 disclo- consolidation Ownership of the trust indudes a three-percent sure requirements for those companies applying APB 25, equity interest by a nonaffiliated party and a three-percent equity

'Accounting for Stock Issued to Employees' and FASB interest by OES Ventures, a wholly owned subsidiary of OE.

Interpretation 44, 'Accounting for Transactions involving Stock Full consolidation of the trust under FIN 46 would change Compensation - an interpretation of APB Opinion No. 44 'The the characterization of the PNBV trust investment to a lease amendment requires prominent display of differences between obligation bond investment. Also, consolidation of the outside the SFAS 123 fair-value approach and the intrinsic-value minonty interest would be required, which would increase approach described by APB 25 in a prescribed format SFAS 148 assets and liabilities by $12 0 million also amends APB 28, 'Intenm Financial Reporting,' to require that these disdosures be made on an interim basis The new disdosure requirements are effective for 2002 year-end report-ing (see Note 2B - Earnings Per Share) and for quarterly report-ing beginning in 2003 Application of the alternative transition approaches is effective in 2003.

FirstEnergy 24

FirstEnergy Corp. 2002 CONSOLIDATED STATEMENTS OF INCOME (In thousands, except per share amounts)

For the Years Ended December 31, 2002 2001 2000 REVENUES:

Electric utilities $ 9,165,805 $ 5,729,036 $ 5,421,668 Unregulated businesses 2,986,192 2,270,326 1,607,293 Total revenues 12,151,997 7,999,362 7,028,961 EXPENSES:

Fuel and purchased power 3,673,610 1,421,525 1,110,845 Purchased gas 592,116 820,031 553,548 Other operating expenses 3,947,855 2,727,794 2,378,296 Provision for depreciation and amortization 1,105,904 889,550 933,684 General taxes 650,329 455,340 547,681 Total expenses 9,969,814 6,314,240 5,524,054 INCOME BEFORE INTEREST AND INCOME TAXES 2,182,183 1,685,122 1,504,907 NET INTEREST CHARGES:

Interest expense 891,833 519,131 493,473 Capitalized interest (24,474) (35,473) (27,059)

Subsidiaries' preferred stock dividends 78,947 72,061 62,721 Net interest charges 946,306 555,719 529,135 INCOME TAXES 549,476 474,457 376,802 INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 686,401 654,946 598,970 CUMULATIVE EFFECT OFACCOUNTING CHANGES (NET OF INCOME TAXES (BENEFIT) OF$13,600,000 AND ($5,839,000), RESPECTIVELY) (Notes 2J and 3) (57,121) (8,499)

NET INCOME $ 629,280 $ 646,447 $ 598,970 BASIC EARNINGS PER SHARE OFCOMMON STOCK (Note 2J):

Income before cumulative effect of accounting changes $2.34 $2.85 $2.69 Cumulative effect of accounting changes (Notes 2J and 3) (.19) (.03)

Net income $2.15 $2.82 $2.69 WEIGHTED AVERAGE NUMBER OFBASIC SHARES OUTSTANDING 293,194 229,512 222,444 DILUTED EARNINGS PER SHARE OFCOMMON STOCK (Note 2J):

Income before cumulative effect of accounting changes $2.33 $2.84 $2.69 Cumulative effect of accounting changes (Notes 2J and 3) (.19) (.03)

Net income $2.14 $2.81 $2.69 WEIGHTED AVERAGE NUMBER OFDILUTED SHARES OUTSTANDING 294,421 230,430 222,726 DIVIDENDS DECLARED PER SHARE OFCOMMON STOCK $1.50 $1.50 $1.50 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

25

FirstEnergy Corp. 2002 CONSOLIDATED BALANCE SHEETS (Inthousands)

As of December 31, 2002 2001 ASSETS CURRENT ASSETS Cash and cash equivalents $ 196,301 $ 220,178 Receivables-Customers (less accumulated provisions of $52,514,000 and $65,358,000, respectively, for uncollectible accounts) 1,153,485 1074,664 Other (less accumulated provisions of $12,851,000 and $7,947,000, respectively, for uncollectible accounts) 473,106 473,550 Materials and supplies, at average cost-Owned 253,047 256,516 Under consignment 174,028 141,002 Prepayments and other 203,630 336,610 2,453,598 2,502,520 ASSETS PENDING SALE (Note 3) - 3,418,225 PROPERTY, PLANT AND EQUIPMENT In service 20,372,224 19,981,749 Less-Accumulated provision for depreciation 8,551,427 8,161,022 11,820,797 11,820,727 Construction work in progress 859,016 607,702 12,679,813 12,428,429 INVESTMENTS Capital trust investments (Note 4) 1,079,435 1,166,714 Nuclear plant decommissioning trusts 1,049,560 1,014,234 Letter of credit collateralization (Note 4) 277,763 277,763 Pension investments (Note 21) - 273,542 Other 918,874 898,311 3,325,632 3,630,564 DEFERRED CHARGES Regulatory assets 8,323,001 8,912,584 Goodwill 5,896,292 5,600,918 Other 902,437 858,273 15,121,730 15,371,775

$33,580,773 $37,351,513 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Currently payable long-term debt and preferred stock $ 1,702,822 $ 1,867,657 Short-term borrowings (Note 6) 1,092,817 614,298 Accounts payable 918,268 704,184 Accrued taxes 456,178 418,555 Other 1,000,415 1,064,763 5,170,500 4,669,457 LIABILITIES RELATED TOASSETS PENDING SALE (Note 3) - 2,954,753 CAPITALIZATION (See Consolidated Statements of Capitalization)

Common stockholders' equity 7,120,049 7,398,599 Preferred stock of consolidated subsidiaries-Not subject to mandatory redemption 335,123 480,194 Subject to mandatory redemption 18,521 65,406 Subsidiary-obligated mandatorily redeemable preferred securities (Note SF) 409,867 529,450 Long-term debt 10,872,216 11,433,313 18,755,776 19,906,962 DEFERRED CREDITS Accumulated deferred income taxes 2,367,997 2,684,219 Accumulated deferred investment tax credits 235,758 260,532 Nuclear plant decommissioning costs 1,254,344 1,201,599 Power purchase contract loss liability 3,136,538 3,566,531 Retirement benefits 1,564,930 838,943 Other 1,094,930 1,268,517 9,654,497 9,820,341 COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 4 and 7)

$33,580,773 $37,351,513 The accompanying Notes to Consolidated FinancialStatements are an integral part of these balance sheets 26

FirstEnergy Corp. 2002 CONSOLIDATED STATEMENTS OF CAPITALIZATION (Dollars in thousands, except per share amounts)

As of December 31, 2002 2001 COMMON STOCKHOLDERS' EQUITY:

Common stock, $0.10 par value - authorized 375,000,000 shares - 297,636,276 shares outstanding $ 29,764 $ 29,764 Other paid-in capital 6,120,341 6,113,260 Accumulated other comprehensive loss (Note 51) (663,236) (169,003)

Retained earnings (Note SA) 1,711,457 1,521,805 Unallocated employee stock ownership plan common stock-3,966,269 and 5,117,375 shares, respectively (Note 5B) (78,277) (97,227)

Total common stockholders' equity 7,120,049 7,398,599 Number of Shares Outstanding Optional Redemption Price 2002 2001 Per Share I Aggregate PREFERRED STOCK OF CONSOLIDATED SUBSIDIARIES (Note 5D):

Ohio Edison Company Cumulative, $100 par value-Authorized 6,000,000 shares Not Subject to Mandatory Redemption:

3.90% 152,510 152,510 $103.63 $ 15,804 15,251 15,251 4.40% 176,280 176,280 108.00 19,038 17,628 17,628 4.44% 136,560 136,560 103.50 14,134 13,656 13,656 4.56% 144,300 144,300 103.38 14,917 14,430 14,430 609,650 609,650 63,893 60,965 60,965 Cumulative, $25 par value- Authorized 8,000,000 shares Not Subject to Mandatory Redemption:

7.75% - 4,000,000 - - 100,000 Total Not Subject to Mandatory Redemption 609,650 4,609,650 $ 63,893 60,965 160,965 Pennsylvania Power Company Cumulative, $100 par value- Authorized 1,200,000 shares Not Subject to Mandatory Redemption:

4.24% 40,000 40,000 103.13 $ 4,125 4,000 4,000 4.25% 41,049 41,049 105.00 4,310 4,105 4,105 4.64% 60,000 60,000 102.98 6,179 6,000 6,000 7.75% 250,000 250,000 - 25,000 25,000 Total Not Subject to Mandatory Redemption 391,049 391,049 $ 14,614 39,105 39,105 Subject to Mandatory Redemption (Note SE):

7.625/ 142,500 150,000 103.81 $ 14,793 14,250 15,000 Redemption Within One Year (750) (750)

Total Subject to Mandatory Redemption 142,500 150,000 $ 14,793 13,500 14,250 Cleveland Electric Illuminating Company Cumulative, without par value- Authorized 4,000,000 shares Not Subject to Mandatory Redemption:

$ 7.40 Series A 500,000 500,000 101.00 $ SD,500 50,000 50000

$ 7.56 Series B - 450,000 - - 45,071 Adjustable Series L 474,000 474,000 100.00 47,400 46,404 46,404

$42.40 Series T - 200,000 - - 96,850 974,000 1,624,000 97,900 96,404 238,325 Redemption Within One Year - (96,850)

Total Not Subject to Mandatory Redemption 974,000 1,624,000 $ 97,900 96,404 141,475 Subject to Mandatory Redemption (Note SE):

$ 7.35 Series C 60,000 70,000 101.00 $ 6,060 6,021 7,030

$90.00 Series S - 17,750 - - 17,268 60,000 87,750 6,060 6,021 24,298 Redemption Within One Year (1,000) (18,010)

Total Subject to Mandatory Redemption 60,000 87,750 $ 6,060 5,021 6,288 27

FirstEnergy Corp 2002 CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)

(Dollars in thousands, except per share amounts)

As of December 31, 2002 2001 Number of Shares Outstanding Optional Redemption Price 2002 2001 Per Share l Aggregate PREFERRED STOCK OFCONSOLIDATED SUBSIDIARIES (Cont'd)

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

$ 425 160,000 160,000 $104 63 $ 16,740 $ 16,000 $ 16,000

$ 456 50,000 50,000 101 00 5,050 5,000 5,000

$ 425 100,000 100,000 102 00 10,200 10,000 10,000

$ 832 100,000 10,000

$ 776 150,000 15,000

$ 780 150,000 15,000

$10 00 190,000 19,000 310,000 900,000 31,990 31,000 90,000 Redemption Within One Year - (59,000) 310,000 900,000 31,990 31,000 31,000 Cumulative, $25 par value- Authorized 12,000,000 shares Not Subject to Mandatory Redemption

$2 21 - 1,000,000 - - 25,000

$2365 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 4,800,000 98,850 95,000 120,000 Redemption Within One Year - (25,000) 3,800,000 4,800,000 98,850 95,000 95,000 Total Not Subject to Mandatory Redemption 4,110,000 5,700,000 $ 130,840 126,000 126,000 Jersey Central Power & Light Company Cumulative, $100 stated value- Authorized 15,600,000 shares Not Subject to Mandatory Redemption 4 00% Series 125,000 125,000 106 50 $ 13,313 12,649 12,649 Subject to Mandatory Redemption 8 65% Series J - 250,001 $ - - 26,750 7 52%Series K - 265,000 _ - 28,951

- 515,001 _ _ 55,701 Redemption Within One Year - (10,833)

Total Subject to Mandatory Redemption - 515,001 $ - - 44,868 SUBSIDIARY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST OR LIMITED PARTNERSHIP HOLDING SOLELY SUBORDINATED DEBENTURES OFSUBSIDIARIES (NOTE SF)

Ohio Edison Co Cumulative, $25 stated value- Authonzed 4,800,000 shares 9 00% - 4,800,000 $ - _ 120,000 Cleveland Electric Illuminating Co Cumulative, $25 stated value- Authonzed 4,000,000 shares 9 00% 4,000,000 4,000,000 3 - 100,000 100,000 Jersey Central Power & Light Co Cumulative, $25 stated value- Authorized 5,000,000 shares 8 56% 5,000,000 5,000,000 2500 $ 125,000 125,244 125,250 Metropolitan Edison Co Cumulative, $25 stated value- Authorized 4,000,000 shares 7 35% 4,000,000 4,000,000 $ - 92,400 92,200 Pennsylvania Electric Co Cumulative, $25 stated value- Authorized 4,000,000 shares 7 34% 4,000,000 4,000,000 $ - 92,214 92,000 28

FirstEnergy Corp. 2002 CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)

LONG-TERM DEBT (Note 5G) (Interest rates reflect weighted average rates) (In thousands)

First Mortgage Bonds Secured Notes Unsecured Notes Total As of December 31, 2002 2001 2002 2001 2002 2001 2002 2001 Ohio Edison Co.-

Due 2002-2007 8.02% $ 230,000 $ 509,265 7.66% $ 186,549 $ 231,907 4.17% $441,725 $441,725 Due 2008-2012 - - - 7.00% 5,468 5,468 - - -

Due 2013-2017 - - - 5.09% 59,000 59,000 - _

Due 2018-2022 8.75% 50,960 50,960 7.01% 60,443 60,443 - -

Due 2023-2027 7.76% 168,500 168,500 - - - - _

Due 2028-2032 - - - 3.60% 249,634 249,634 - _

Due 2033-2037 - - 2.43% 71,900 71,900 - - -

Total-Ohio Edison 449,460 728,725 632,994 678,352 441,725 441,725 $1,524,179 $1,848,802 Cleveland Electric Illuminating Co. -

Due 2002-2007 8.97% 400,000 595,000 5.74% 680,175 713,205 5.58% 27,700 27,700 Due 2008-2012 6.86% 125,000 125,000 7.43% 151,610 151,610 - - -

Due 2013-2017 - - - 7.88% 300,000 378,700 6.00% 78,700 Due 2018-2022 - - - 6.24% 140,560 140,560 - -

Due 2023-2027 9.00% 150,000 150,000 7.64% 218,950 218,950 - -

Due 2028-2032 - - - 5.38% 5,993 5,993 - _

Due 2033-2037 - - - 1.60% 30,000 - - - -

Total-Cleveland Electric 675,000 870,000 1,527,288 1,609,018 106,400 27,700 2,308,688 2,506,718 Toledo Edison Co. -

Due 2002-2007 7.90% 178,725 179,125 6.19% 229,700 258,700 4.83% 91,100 226,130 Due 2008-2012 - - - - - - 10.00% 760 760 Due 2013-2017 - - - - - - - - -

Due 2018-2022 - - - 7.89% 114,000 129,000 - - -

Due 2023-2027 - - - 7.31% 60,800 60,800 - - -

Due 2028-2032 - - - 5.38% 3,751 3,751 - - -

Due 2033-2037 - - - 1.68% 51,100 30,900 - - -

Total-Toledo Edison 178,725 179,125 459,351 483,151 91,860 226,890 729,936 889,166 Pennsylvania Power Co.-

Due 2002-2007 7.19% 79,370 80,344 2.99% 10,300 10,300 4.39% 19,700 5,200 Due 2008-2012 9.74% 4,870 4,870 - - - - - -

Due 2013-2017 9.74% 4,870 4,870 3.12% 29,525 29,525 - - -

Due 2018-2022 8.58% 29,231 29,231 3.94% 31,282 31,282 - - -

Due 2023-2027 7.63% 6,500 6,500 6.15% 12,700 27,200 - - -

Due 2028-2032 - - - 5.79% 23,172 23,172 - - -

Total-Penn Power 124,841 125,815 106,979 121,479 19,700 5,200 251,520 252,494 Jersey Central Power

& Light Co. -

Due 2002-2007 6.90% 442,674 541,260 5.60% 241,135 150,000 7.69% 93 107 Due 2008-2012 7.13% 5,040 5,040 5.39% 52,273 - 7.69% 134 134 Due 2013-2017 7.10% 12,200 12,200 6.01% 176,592 - 7.69% 193 193 Due 2018-2022 8.62% 76,586 170,000 - - - 7.69% 280 280 Due 2023-2027 7.37% 365,000 365,000 - - - 7.69% 406 406 Due 2028-2032 - - - - - - 7.69% 588 588 Due 2033-2037 -- - - - 7.69% 851 851 Due 2038-2042 - - - - - - 7.69% 439 439 Total-Jersey Central 901,500 1,093,500 470,000 150,000 2,984 2,998 1,374,484 1,246,498 Metropolitan Edison Co. -

Due 2002-2007 6.71% 202,175 262,175 5.79% 150,000 100,000 7.69% 185 214 Due 2008-2012 6.00% 6,525 6,525 - - - 7.69% 267 267 Due 2013-2017 - - - - - - 7.69% 387 387 Due 2018-2022 7.86% 88,500 88,500 - - - 7.69% 560 560 Due 2023-2027 7.55% 133,690 133,690 - - - 7.69% 812 812 Due 2028-2032 - - - - - - 7.69% 1,176 1,176 Due 2033-2037 _- - - - 7.69% 1,703 1,703 Due 2038-2042 _- - - - - 7.69% 878 878 Total-Metropolitan Edison 430,890 490,890 150,000 100,000 5,98 5,997 586,858 596,887 29

FirstEnergy Corp. 2002 CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'c!

LONG-TERM DEBT (Interest rates reflect weighted average rates) (Cont'd) (In thousands)

First Mortgage Bonds Secured Notes Unsecured Notes Total As ot December 31, 2002 2001 2002 2001 2002 2001 2002 2001 Pennsylvania Electric Co -

Due 2002-2007 6 13% $ 3,905 $ 4,110 - S - - 5 86% $ 133,093 $ 183,107 Due 2008-2012 5 35% 24,310 24,310 - 6 55% 135,134 135,134 Due 2013-2017 - - - - _ _ 7 69% 193 193 Due 2018-2022 5 80% 20,000 20,000 - _ _ 6 63% 125,280 125,280 Due 2023-2027 6 05% 25,000 25,000 _ -- 7 69w' 406 406 Due 2028-2032 - - - - _ _ 7 69% 588 588 Due 2033-2037 _ _ _ _ _ _ 7 69% 851 851 Due 2038-2042 _ _ 7 69% 439 439 Total-Pennsylvania Electric 73,215 73,420 395,984 445,998 $ 469,199 $ 519,418 FirstEnergy Corp -

Due 2002-2007 _- - - - 5 28% 1,695,000 1,550,000 Due 2008-2012 - - - - _ _ 6 45% 1,500,000 1,500,000 Due 2013-2017 _ - - - - - - -

Due 2018-2022 - - - - _ _ _ _

Due 2023-2027 _ - - - - - - -

Due 2028-2032 - - - - 7 38% 1,500,000 1,500,000 Total-FirstEnergy - - 4,695,000 4,550,000 4,695,000 4,550,000 OES Fuel - - - - _ 81,515 - - - - 81,515 AFNFinanceCo No 1 - - - - _ 15,000 - - - - 15,000 AFN Finance Co No 3 - - - - - 4,000 - - - - 4,000 Bay Shore Power - - - 6 24% 143,200 145,400 - - - 143,200 145,400 MARBEL Energy Corp - - - - - - - - 569 - 569 Facilities Services Group - - - 4 86% 13,205 15,735 - - - 13,205 15,735 FirstEnergy Generation - - - - - - 5 00% 15,000 - 15,000 -

FirstEnergy Properties - - - 7 89% 9,679 9,902 - - - 9,579 9,902 Warrenton Rrver Terminal - - - 5 25% 634 776 - - - 534 776 GPU Capital* - - - - - - 5 78% 101,467 1,629,582 101,467 1,629,582 GPU Power - - - 714% 174,760 239,373 1 87% 67,372 56,048 242,132 295,421 Total $2,833,631 $3,561,475 $3,688,090 $3,653,701 $5,943,460 $7,392,707 12,465,181 14,607,883 Capital lease obligations 15,761 19,390 Net unamortized premium on debt* 92,346 213,834 Long-term debt due within one year* (1,701,072) (1,975,755)

Total long-term debt* 10,872,216 12,865,352 TOTAL CAPITALIZATION' 18,755,776 $21,339,001

' 2001 includes amounts in "Liabilities Related toAssets 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 30

FirstEnergy Corp. 2002 CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (Dollars in thousands)

Accumulated Unallocated Other Other ESOP Comprehensive Number Par Paid-In Comprehensive Retained Common Income of Shares Value Capital Income (Loss) Earnings Stock Balance, January 1, 2000 232,454,287 $23,245 $3,722,375 $ (195) $ 945,241 $(126,776)

Net income $598,970 598,970 Minimum liability for unfunded retirement benefits, net of

$85,000 of income taxes (134) (134)

Unrealized gain on investment in securities available for sale 922 922 Comprehensive income $599,758 Reacquired common stock (7,922,707) (792) (194,210)

Allocation of ESOP shares 3,656 15,044 Cash dividends on common stock (334,220)

Balance, December 31, 2000 224,531,580 22,453 3,531,821 593 1,209,991 (111,732)

GPU acquisition 73,654,696 7,366 2,586,097 Net income $646,447 646,447 Minimum liability for unfunded retirement benefits, net of

$(182,000) of income taxes (268) (268)

Unrealized loss on derivative hedges, net of $(1 16,521,000) of income taxes (169,408) (169,408)

Unrealized gain on investments, net of $56,000 of income taxes 81 81 Unrealized currency translation adjustments, net of $(1,000) of income taxes (1) (1)

Comprehensive income $476,851 Reacquired common stock (550,000) (55) (15,253)

Allocation of ESOP shares 10,595 14,505 Cash dividends on common stock (334,633)

Balance, December 31,2001 297,636,276 29,764 6,113,260 (169,003) 1,521,805 (97,227)

Net income $629,280 629,280 Minimum liability for unfunded retirement benefits, net of $(316,681,000) of income taxes (449,615) (449,615)

Unrealized gain on derivative hedges, net of $37,458,000 of income taxes 59,187 59,187 Unrealized loss on investments, net of $(8,721,000) of income taxes (12,357) (12,357)

Unrealized currency translation adjustments (91,448) (91,448)

Comprehensive income $135,047 Stock options exercised (8,169)

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

Balance, December 31, 2002 297,636,276 $29,764 $6,120,341 $(663,236) $1,711,457 $ (78,277)

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

31

FirstEnergy Corp. 2002 CONSOLIDATED STATEMENTS OF PREFERRED STOCK (Dollars in thousands)

Not Subject to Subject to Mandatory Redemption Mandatory Redemption Number Par or Stated Number Par or Stated of Shares Value of Shares Value Balance, January 1, 2000 12,324,699 $648,395 5,269,680 $294,710 Redemptions-8 45% Series (50,000) (5,000)

$7 35 Series C (10,000) (1,000)

$88 00 Series E (3,000) (3,000)

$91 50 Series 0 (10,714) (10,714)

$90 00 Series S (18,750) (18,750)

Amortization of fair market value adjustments-

$7 35 Series C (69)

$88 00 Series R (3,872)

$90 00 Series S (5,734)

Balance, December 31, 2000 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 a (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-775% Series (4,000,000) (100,000)

$7 56 Series B (450,000) (45,071)

$42 40 Series T (200,000) (96,850)

$8 32 Series (100,000) (10,000)

$7 76 Series (150,000) (15,000)

$7 80 Series (150,000) (15,000)

$10 00 Series (190,000) (19,000)

$2 21 Series (1,000,000) (25,000) 7 625% Series (7,500) (750)

$7 35 Series C (10,000) (1,000)

$90 00 Series S (17,750) (17,010) 8 65% Series J (250,001) (26,750) 7 52% Series K (265,000) (28,951) 9 00% Series (4,800,000) (120,000)

Amortization of fair market value adjustments-

$7 35 Series C (9)

$90 00 Series S (258) 856% Series (6) 735% Series 209 734% Series 214 Balance, December 31, 2002 6,209,699 $335,123 17,202,500 $430,138 The accompanying Notes to Consolidated FinancialStatements are an integral part of these statements 32

FirstEnergy Corp. 2002 CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)

For the Years Ended December 31, 2002 2001 2000 CASH FLOWS FROM OPERATING ACTIVITIES:

Net Income $ 629,280 $ 646,447 $ 598,970 Adjustments to reconcile net income to net cash from operating activities:

Provision for depreciation and amortization 1,105,904 889,550 933,684 Nuclear fuel and lease amortization 80,507 98,178 113,330 Other amortization, net (Note 2) (16,593) (11,927) (11,635)

Deferred costs recoverable as regulatory assets (362,956) (31,893)

Avon investment impairment (Note 3) 50,000 _

Deferred income taxes, net 91,032 31,625 (79,429)

Investment tax credits, net (27,071) (22,545) (30,732)

Cumulative effect of accounting change 43,521 14,338 Receivables (78,378) 53,099 (150,520)

Materials and supplies (29,557) (50,052) (29,653)

Accounts payable 214,084 (84,572) 118,282 Other (Note 9) 215,514 (250,564) 45,529 Net cash provided from operating activities 1,915,287 1,281,684 1,507,826 CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-Preferred stock - 96,739 Long-term debt 668,676 4,338,080 307,512 Short-term borrowings, net 478,520 - 281,946 Redemptions and Repayments-Common stock - (15,308) (195,002)

Preferred stock (522,223) (85,466) (38,464)

Long-term debt (1,308,814) (394,017) (901,764)

Short-term borrowings, net _ (1,641,484)

Common Stock Dividend Payments (439,628) (334,633) (334,220)

Net cash provided from (used for) financing activities (1,123,469) 1,963,911 (879,992)

CASH FLOWS FROM INVESTING ACTIVITIES:

GPU acquisition, net of cash _ (2,013,218)

Property additions (997,723) (852,449) (587,618)

Proceeds from sale of Midlands 155,034 Avon cash and cash equivalents (Note 3) 31,326 Net assets held for sale (31,326) _

Cash investments (Note 2) 81,349 24,518 17,449 Other (Note 9) (54,355) (233,526) (120,195)

Net cash provided from (used for) investing activities (815,695) (3,074,675) (690,364)

Net increase (decrease) in cash and cash equivalents (23,877) 170,920 (62,530)

Cash and cash equivalents at beginning of year 220,178 49,258 111,788 Cash and cash equivalents at end of year* $195,301 $ 220,178 $ 49,258 SUPPLEMENTAL CASH FLOWS INFORMATION:

Cash Paid During the Year-Interest (net of amounts capitalized) $ 881,515 $ 425,737 $ 485,374 Income taxes $ 389,180 $ 433,640 $ 512,182

'2001 excludes amounts in 'Assets Pending Sale' on the Consolidated Balance Sheet as of December 31, 2001.

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

33

FirstEnergy Corp. 2002 CONSOLIDATED STATEMENTS OF TAXES (In thousands)

For the Years Ended December 31, 2002 2001 2000 GENERAL TAXES Real and personal property $ 218,683 $ 176,916 $ 281,374 State gross receipts* 132,622 102,335 221,385 Kilowatt-hour excise* 219,970 117,979 -

Social security and unemployment 46,345 44,480 39,134 Other 32,709 13,630 5,788 Total general taxes $ 650,329 $ 455,340 $ 547,681 PROVISION FOR INCOME TAXES Currently payable-Federal $ 332,253 $ 375,108 $ 467,045 State 103,886 84,322 19,918 Foreign 20,624 108 -

455,763 459,538 486,963 Deferred, net-Federal 99,297 37,888 (60,831)

State 20,487 (6,177) (18,598)

Foreign 13,600 (86) 133,384 31,625 (79,429)

Investment tax credit amortization (27,071) (22,545) (30,732)

Total provision for income taxes $ 563,076 $ 468,618 $ 376,802 RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TOTOTAL PROVISION FOR INCOME TAXES Book income before provision for income taxes $1,192,356 $1,115,065 $ 975,772 Federal income tax expense at statutory rate $ 417,325 $ 390,273 $ 341,520 Increases (reductions) intaxes resulting from-Amortization of investment tax credits (27,071) (22,545) (30,732)

State income taxes, net of federal income tax benefit 80,842 50,794 1,133 Amortization of tax regulatory assets 27,455 30,419 38,702 Amortization of goodwill _ 18,416 18,420 Preferred stock dividends 13,534 19,733 18,172 Valuation reserve for foreign tax benefits 31,087 - -

Other, net 19,804 (18,472) (10,413)

Total provision for income taxes S 563,076 $ 468,618 $ 376,802 ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31 Property basis differences $2,052,594 $1,996,937 $1,245,297 Customer receivables for future income taxes 144,073 178,683 62,527 Competitive transition charge 1,234,491 1,289,438 1,070,161 Deferred sale and leaseback costs (99,647) (77,099) (128,298)

Nonutility generation costs (228,476) (178,393)

Unamortized investment tax credits (78,227) (86,256) (85,641)

Unused alternative minimum tax credits - (32,215)

Other comprehensive income (240,663) (115,395)

Other (Notes 2 and 9) (415,148) (323,696) (37,724)

Net deferred income tax liability- $2,367,997 $2,684,219 $2,094,107

• Collectedfrom customers through regulated rates and included in revenue on the Consolidated Statements of Income

-200l excludes amounts in "LiabilitiesRelated to Assets Pending Sale& on the Consolidated Balance Sheet as of December 31, 2001 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements 34

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS "Accounting for Investments in Real Estate Ventures," which specify a 3 to 5 percent threshold for the presumption of influence.

1. General:

For all remaining investments (excluding those within the scope The consolidated financial statements indude FirstEnergy Corp.,

of Statement of Financial Accounting Standards (SFAS) 115, a public utility holding company, and its principal electric utility FirstEnergy applies the cost method.

operating subsidiaries, Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), Pennsylvania Power (B) Earnings Per Share-Company (Penn), The Toledo Edison Company (TE), American Basic earnings per share are computed using the weighted Transmission Systems, Inc. (ATSI), Jersey Central Power & Light average of actual common shares outstanding as the denominator.

Company (JCP&L), Metropolitan Edison Company (Met-Ed) Diluted earnings per share reflect the weighted average of actual and Pennsylvania Electric Company (Penelec). ATSI owns and common shares outstanding plus the potential additional operates FirstEnergy's transmission facilities within the service common shares that could result if dilutive securities and agree-areas of OE, CEI and TE (Ohio Companies) and Penn. The utility ments were exercised in the denominator. In 2002, 2001 and subsidiaries are referred to throughout as "Companies." 2000, stock based awards to purchase shares of common stock FirstEnergy's 2001 results include the results of JCP&L, Met-Ed totaling 3.4 million, 0.1 million and 1.8 million, respectively, and Penelec from the period they were acquired on November 7, were excluded from the calculation of diluted earnings per share 2001 through December 31, 2001. The consolidated financial of common stock because their exercise prices were greater than statements also include FirstEnergy's other principal subsidiaries: the average market price of common shares during the period.

FirstEnergy Solutions Corp. (FES); FirstEnergy Facilities Services The numerators for the calculations of basic and diluted earnings Group, LLC (FSG); MYR Group, Inc.; MARBEL Energy Corporation; per share are Income Before Cumulative Effect of Changes in FirstEnergy Nuclear Operating Company (FENOC); GPU Accounting and Net Income. The following table reconciles Capital, Inc.; GPU Power, Inc.; FirstEnergy Service Company the denominators for basic and diluted earnings per share:

(FECO); and GPU Service, Inc. (GPUS). FES provides energy-related products and services and, through its FirstEnergy Denominator for Earnings per Share Calculations Years Ended December 31, Generation Corp. (FGCO) subsidiary, operates FirstEnergy's nonnuclear generation business. FENOC operates the Companies' 2002 2001 2000 nuclear generating facilities. FSG is the parent company of several (In thousands) heating, ventilating, air conditioning and energy management Denominator for basic earnings companies, and MYR is a utility infrastructure construction service per share (weighted average shares actually outstanding) 293,194 229,512 222,444 company. MARBEL is a fully integrated natural gas company. Assumed exercise of dilutive GPU Capital owns and operates electric distribution systems in securities or agreements to foreign countries and GPU Power owns and operates generation issue common stock 1,227 918 282 facilities in foreign countries. FECO and GPUS provide legal, Denominator for diluted financial and other corporate support services to affiliated earnings per share 294,421 230,430 222,726 FirstEnergy companies. Significant intercompany transactions have been eliminated in consolidation.

The Companies follow the accounting policies and practices (C) Revenues-prescribed by the Securities and Exchange Commission (SEC), The Companies' principal business is providing electric service to the Public Utilities Commission of Ohio (PUCO), the customers in Ohio, Pennsylvania and New Jersey. The Companies' Pennsylvania Public Utility Commission (PPUC), the New Jersey retail customers are metered on a cyde basis. Revenue is recognized Board of Public Utilities (NJBPU) and the Federal Energy for unbilled electric service provided through the end of the year.

Regulatory Commission (FERC). The preparation of financial See Note 9 - Other Information for discussion of reporting of statements in conformity with accounting principles generally Independent System Operator (ISO) transactions.

accepted in the United States (GAAP) requires management to Receivables from customers include sales to residential, com-make periodic estimates and assumptions that affect the reported mercial and industrial customers and sales to wholesale cus-amounts of assets, liabilities, revenues and expenses and the tomers. There was no material concentration of receivables as of disclosure of contingent assets and liabilities. Actual results December 31, 2002 or 2001, with respect to any particular seg-could differ from these estimates. Certain prior year amounts ment of FirstEnergy's customers.

have been reclassified to conform with the current year presen- CEI and TE sell substantially all of their retail customers' tation, as described further in Notes 8 and 9. receivables to Centerior Funding Corporation (CFC), a wholly

2. Summary of Significant Accounting Policies: owned subsidiary of CEI. CFC subsequently transfers the receiv-ables to a trust (an SFAS 140 "qualified special purpose entity")

(A) Consolidation- under an asset-backed securitization agreement. Transfers are FirstEnergy consolidates all majority-owned subsidiaries, made in return for an interest in the trust (41% as of December 31, after eliminating the effects of intercompany transactions. 2002), which is stated at fair value, reflecting adjustments for Non-majority owned investments, including investments in anticipated credit losses. The average collection period for billed limited liability companies, partnerships and joint ventures, receivables is 28 days. Given the short collection period after are accounted for under the equity method when FirstEnergy billing, the fair value of CFC's interest in the trust approximates is able to influence their financial or operating policies. the stated value of its retained interest in underlying receivables Investments in corporations resulting in voting control of after adjusting for anticipated credit losses. Accordingly, subse-20% or more are presumed to be equity method investments. quent measurements of the retained interest under SFAS 115 (as Limited partnerships are evaluated in accordance with SEC an available-for-sale financial instrument) result in no material Staff Guidance D-46, "Accounting for Limited Partnership change in value. Sensitivity analyses reflecting 10% and 20%

Investments" and American Institute of Certified Public increases in the rate of anticipated credit losses would not have Accountants (AICPA) Statement of Position (SOP) 78-9, 35

significantly affected FirstEnergy's retained interest in the pool Ohio of receivables through the trust. Of the $272 million sold to the In July 1999, Ohio's electric utility restructunng legislation, trust and outstanding as of December 31, 2002, FirstEnergy's which allowed Ohio electmc customers to select their generation retained interests in $111 million of the receivables are included suppliers beginning January 1, 2001, was signed into law Among as other receivables on the Consolidated Balance Sheets other things, the legislation provided for a 5% reduction on the Accordingly, receivables recorded on the Consolidated Balance generation portion of residential customers' bills and the opportu-Sheets were reduced by approximately $161 million due to nity to recover transition costs, induding regulatory assets, from these sales Collections of receivables previously transferred to January 1, 2001 through December 31, 2005 (market development the trust and used for the purchase of new receivables from period). The period for the recovery of regulatory assets only can CFC dunng 2002 totaled approximately $2 2 billion CEI and be extended up to December 31, 2010 The PUCO was authorized TE processed receivables for the trust and received servicing fees to determine the level of transition cost recovery, as well as the of approximately $3 8 million in 2002. Expenses associated recovery penod for the regulatory assets portion of those costs, in with the factonng discount related to the sale of receivables considering each Ohio electric utility's transition plan application.

were $4.7 million in 2002. In July 2000, the PUCO approved FirstEnergy's transition plan In June 2002, the Emerging Issues Task Force (EITF) reached for the Ohio Companies as modified by a settlement agreement a partial consensus on Issue No. 02-03, Issues Involved in with major parties to the transition plan The application of Accounting for Denvative Contracts Held for Trading Purposes SPAS 71, 'Accounting for the Effects of Certain Types of Regulation" and Contracts Involved in Energy Trading and Risk Management to OE's generation business and the nonnuclear generation Activities " Based on the EITF's partial consensus position, for businesses of CEI and TE was discontinued with the issuance penods after July 15, 2002, mark-to-market revenues and expenses of the PUCO transition plan order, as descnbed firther below.

and their related kilowatt-hour (KWH) sales and purchases on Major provisions of the settlement agreement consisted of energy trading contracts must be shown on a net basis in the approval of recovery of generation-related transition costs as Consolidated Statements of Income FirstEnergy has previously filed of $4 0 billion net of deferred income taxes (OE -$1 6 billion, reported such contracts as gross revenues and purchased power CEI- $1 6 billion and TE-$0 8 billion) and transition costs related costs. Comparative quarterly disdosures and the Consolidated to regulatory assets as filed of $2 9 billion net of deferred income Statements of Income for revenues and expenses have been taxes (OE-$1 0 billion, CEI-$1.4 billion and TE-$0 5 billion),

reclassified for 2002 only to conform with the revised presenta- with recovery through no later than 2006 for OE, mid-2007 for tion (see Note 11 - Summary of Quarterly Financial Data). In TE and 2008 for CEI, except where a longer period of recovery is addition, the related KWH sales and purchases statistics descnbed provided for in the settlement agreement. The generation-related under Management's Discussion and Analysis - Results of transition costs include $1 4 billion, net of deferred income Operations were reclassified (7.2 billion KWH in 2002 and taxes, (OE-$1.0 billion, CEI-$0 2 billion and TE-$0 2 billion) 3 7 billion KVH in 2001). The following table displays the of impaired generating assets recognized as regulatory assets impact of changing to a net presentation of FirstEnergy's as described further below, $2 4 billion, net of deferred income energy trading operations taxes, (OE-$1 2 billion, CEI-$0 4 billion and TE-$0 8 billion) of above market operating lease costs and $0 8 billion (CEI-2002 Impact of Recording Energy Trading Nel $0.5 billion and TE-$0 3 billion) of additional plant costs that Revenues Expenses were reflected on CEI's and TE's regulatory financial statements (Inmillions) Also as part of the settlement agreement, FirstEnergy is giving Total before adjustments $12,420 $10,238 preferred access over its subsidiaries to nonaffiliated marketers, Adjustments (268) (268) brokers and aggregators to 1,120 megawatts (MWV) of generation Total as reported $12,152 $ 9,970 capacity through 2005 at established pnces for sales to the Ohio Companies' retail customers Customer pnces are frozen through the five-year market development period except for (D) Regulatory Matters- certain limited statutory exceptions, including the 5% reduction In Ohio, Nev Jersey and Pennsylvania, laws applicable to elec- referred to above In February 2003, the Ohio Companies were tric industry deregulation included similar provisions which are authorized increases in annual revenues aggregating approxi-reflected in the Companies' respective state regulatory plans mately $50 million (OE-$41 million, CEI-$4 million and TE-

• allowing the Companies' electric customers to select their $5 million) to recover their higher tax costs resulting from the generation suppliers; Ohio deregulation legislation

• establishing provider of last resort (PLR) obligations to FirstEnergy's Ohio customers choosing alternative suppliers customers in the Companies' service areas, receive an additional incentive applied to the shopping credit

• allowing recovery of potentially stranded investment (generation component) of 45% for residential customers, 30%

(or transition costs), for commercial customers and 15% for industrial customers

• itemizing (unbundling) the price of electricity into its The amount of the incentive is deferred for future recovery from component elements - including generation, transmission, customers - recovery will be accomplished by extending the distribution and stranded costs recovery charges; respective transition cost recovery period If the customer shop-

• deregulating the Companies' electric generation businesses, ping goals established in the agreement had not been achieved and by the end of 2005, the transition cost recovery periods could

• continuing regulation of the Companies' transmission have been shortened for OE, CEI and TE to reduce recovery by and distribution systems. as much as $500 million (OE - $250 million, CEI - $170 million and TE - $80 million). The Ohio Companies achieved all of their required 20% customer shopping goals in 2002. Accordingly, FirstEnergy believes that there will be no regulatory action reducing the recoverable transition costs FirstEnergy 36

New Jersey price bid (applicable to all residential and smaller commercial JCP&L's 2001 Final Decision and Order (Final Order) with and industrial customers) and an hourly price bid (applicable respect to its rate unbundling, stranded cost and restructuring to all large industrial customers) process. JCP&L will sell all self-filings confirmed rate reductions set forth in its 1999 Summary supplied energy (NUGs and owned generation) to the wholesale Order, which remain in effect at increasing levels through July market with offsets to its deferred energy cost balances.

2003. The Final Order also confirmed the establishment of a Pennsylvania non-bypassable societal benefits charge (SBC) to recover costs The PPUC authorized 1998 rate restructuring plans for Penn, which include nuclear plant decommissioning and manufac-Met-Ed and Penelec. In 2000, the PPUC disallowed a portion of tured gas plant remediation, as well as a non-bypassable market the requested additional stranded costs above those amounts transition charge (MTC) primarily to recover stranded costs.

granted in Met-Ed's and Penelec's 1998 rate restructuring plan The NJBPU has deferred making a final determination of the orders. The PPUC required Met-Ed and Penelec to seek an IRS net proceeds and stranded costs related to prior generating ruling regarding the return of certain unamortized investment asset divestitures until JCP&L's request for an Internal Revenue tax credits and excess deferred income tax benefits to customers.

Service (IRS) ruling regarding the treatment of associated federal Similar to JCP&L's situation, if the IRS ruling ultimately supports income tax benefits is acted upon. Should the IRS ruling sup-returning these tax benefits to customers, there would be no port the return of the tax benefits to customers, there would effect to FirstEnergy's, Met-Ed's or Penelec's net income since be no effect to FirstEnergy's or JCP&L's net income since the the contingency existed prior to the merger.

contingency existed prior to the merger.

As a result of their generating asset divestitures, Met-Ed and In addition, the Final Order provided for the ability to securitize Penelec obtained their supply of electricity to meet their PLR stranded costs associated with the divested Oyster Creek Nuclear obligations almost entirely from contracted and open market Generating Station. In February 2002, JCP&L received NJBPU purchases. In 2000, Met-Ed and Penelec filed a petition with the authorization to issue $320 million of transition bonds to PPUC seeking permission to defer, for future recovery, energy securitize the recovery of these costs. The NJBPU order also costs in excess of amounts reflected in their capped generation provided for a usage-based non-bypassable transition bond rates; the PPUC subsequently consolidated this petition in charge and for the transfer of the bondable transition property January 2001 with the FirstEnergy/GPU merger proceeding.

to another entity. JCP&L sold $320 million of transition bonds In June 2001, the PPUC entered orders approving the through its wholly owned subsidiary, JCP&L Transition Funding Settlement Stipulation with all of the major parties in the LLC, in June 2002 - those bonds are recognized on the combined merger and rate relief proceedings which approved Consolidated Balance Sheet (see Note 5H).

the merger and provided Met-Ed and Penelec PLR deferred JCP&L's PLR obligation to provide basic generation service accounting treatment for energy costs. The PPUC permitted (BGS) to non-shopping customers is supplied almost entirely Met-Ed and Penelec to defer for future recovery the difference from contracted and open market purchases. JCP&L is permitted between their actual energy costs and those reflected in their to defer for future collection from customers the amounts by capped generation rates, retroactive to January 1, 2001.

which its costs of supplying BGS to non-shopping customers Correspondingly, in the event that energy costs incurred by and costs incurred under nonutility generation (NUG) agree-Met-Ed and Penelec would be below their respective capped ments exceed amounts collected through BGS and MTC rates.

generation rates, that difference would have reduced costs that As of December 31, 2002, the accumulated deferred cost balance had been deferred for recovery in future periods. This PLR totaled approximately $549 million. The NJBPU also allowed deferral accounting procedure was denied in a court decision securitization of JCP&L's deferred balance to the extent permit-discussed below. Met-Ed's and Penelec's PLR obligations extend ted by law upon application by JCP&L and a determination by the through December 31, 2010; during that period competitive NJBPU that the conditions of the New Jersey restructuring legis-transition charge (CTC) revenues would have been applied lation are met. There can be no assurance as to the extent, if to their stranded costs. Met-Ed and Penelec would have been any, that the NJBPU will permit such securitization.

permitted to recover any remaining stranded costs through Under New Jersey transition legislation, all electric distribution a continuation of the CTC after December 31, 2010 through companies were required to file rate cases to determine the level no later than December 31, 2015. Any amounts not expected of unbundled rate components to become effective August 1, to be recovered by December 31, 2015 would have been written 2003. On August 1, 2002, JCP&L submitted two rate filings with off at the time such nonrecovery became probable.

the NJBPU. The first filing requested increases in base electric Several parties had filed Petitions for Review in June and July rates of approximately $98 million annually. The second filing 2001 with the Commonwealth Court of Pennsylvania regarding was a request to recover deferred costs that exceeded amounts the June 2001 PPUC orders. On February 21, 2002, the Court being recovered under the current MTC and SBC rates; one pro-affirmed the PPUC decision regarding the FirstEnergy/ GPU posed method of recovery of these costs is the securitization of merger, remanding the decision to the PPUC only with respect the deferred balance. This securitization methodology is similar to the issue of merger savings. The Court reversed the PPUC's to the Oyster Creek securitization discussed above. Hearings decision regarding the PLR obligations of Met-Ed and Penelec, began in February 2003. The Administrative Law Judge's and rejected those parts of the settlement that permitted the recommended decision is due in June 2003 and the NJBPU's companies to defer for accounting purposes the difference subsequent decision is due in July 2003.

between their wholesale power costs and the amount that they In December 2001, the NJBPU authorized the auctioning of collect from retail customers. FirstEnergy and the PPUC each BGS for the period from August 1, 2002 through July 31, 2003 filed a Petition for Allowance of Appeal with the Pennsylvania to meet the electricity demands of all customers who have not Supreme Court on March 25, 2002, asking it to review the selected an alternative supplier. The auction results were approved Commonwealth Court decision. Also on March 25, 2002, by the NJBPU in February 2002, removing JCP&L's BGS obligation Citizens Power filed a motion seeking an appeal of the of 5, 100 MW for the period August 1, 2002 through July 31, 2003.

Commonwealth Court's decision to affirm the FirstEnergy and In February 2003, NJBPU approved the BGS auction results for GPU merger with the Pennsylvania Supreme Court. In September the period beginning August 1, 2003. The auction covered a fixed 37

2002, FirstEnergy established reserves for Met-Ed's and Penelec's PLR deferred energy costs which aggregated $287 I million SFAS 71 Dlscontinued Net Assets Total Assets The reserves reflected the potential adverse impact of a pending Pennsylvania Supreme Court decision whether to review the (Inmillions)

Commonwealth Court ruling FirstEnergy recorded an aggregate OE $ 947 $7,160 CEI 1,406 5,935 non-cash charge of $55.8 million ($32 6 million net of tax) to TE 559 2,617 income for the deferred costs incurred subsequent to the merger Penn 82 908 The reserve for the remaining $231.3 million of deferred costs JCP&L 44 8,053 increased goodwill by an aggregate net of tax amount of Met-Ed 17 3,565 Penelec - 3,163

$135 3 million.

On January 17, 2003, the Pennsylvania Supreme Court denied further appeals of the February 21, 2002 Pennsylvania Commonwealth Court decision, which effectively affirmed (E) Property, Plant and Equipment the PPUC's order approving the merger between FirstEnergy Property, plant and equipment reflects onginal cost (except and GPU, let stand the Commonwealth Court's denial of for nuclear generating units and the international properties PLR rate relief for Met-Ed and Penelec and remanded the which were adjusted to fair value), induding payroll and related merger savings issue back to the PPUC Because FirstEnergy costs such as taxes, employee benefits, administrative and general had already reserved for the deferred energy costs and FES has costs, and interest costs JCP&L holds a 50% ownership interest largely hedged the anticipated PLR energy supply requirements in Yards Creek Pumped Storage Facility - its net book value was for Met-Ed and Penelec through 2005 as discussed further approximately $21.3 million as of December 31, 2002 FirstEnergy below, FirstEnergy, Met-Ed and Penelec believe that the also shares ownership interests in various foreign properties disallowance of CTC recovery of PLR costs above Met-Ed's with an aggregate net book value of $154 million, representing and Penelec's capped generation rates will not have a future the fair value of FirstEnergy's interest FirstEnergy's accounting adverse financial impact policy for planned major maintenance projects is to recognize Effective September 1, 2002, Met-Ed and Penelec assigned liabilities as they are incurred their PLR responsibility to their FES affiliate through a whole- The Companies provide for depreciation on a straight-line sale power sale agreement The PLR sale, which initially ran basis at various rates over the estimated lives of property induded through the end of 2002, was extended through December in plant in service The respective annual composite rates for the 2003 and will be automatically extended for each successive Companies' electric plant in 2002, 2001 and 2000 (post merger calendar year unless any party elects to cancel the agreement periods only for JCP&L, Met-Ed and Penelec) are shown in the by November 1 of the preceding year Under the terms of the following table:

wholesale agreement, FES assumes the supply obligation and Annual Composite Depreciation Rate the energy supply profit and loss risk, for the portion of power 2002 2001 2000 supply requirements not self-supplied by Met-Ed and Penelec OE 2.7% 27% 2 8%

under their NUG contracts and other existing power contracts CEI 34 32 34 with nonaffiliated third party suppliers This arrangement TE 39 35 34 reduces Met-Ed's and Penelec's exposure to high wholesale Penn 2.9 29 26 power pnces by providing power at or below the shopping JCP&L 35 34 Met-Ed 30 30 credit for their uncommitted PLR energy costs during the term Penelec 3.0 29 of the agreement with FES FES has hedged most of Met-Ed's and Penelec's unfilled PLR obligation through 2005, the period during which deferred accounting was previously allowed under Annual depreciation expense in 2002 included approximately the PPUC's order Met-Ed and Penelec are authorized to $125 million for future decommissioning costs applicable to the continue deferring differences between NUG contract costs Companies' ownership and leasehold interests in five nuclear and amounts recovered through their capped generation rates generating units (Davis-Besse Unit 1, Beaver Valley Units 1 and 2, The application of SFAS 71 has been discontinued with Perry Unit 1 and Three Mile Island Unit 2 (TMI-2)), a demon-respect to the Companies' generation operations The SEC stration nuclear reactor (Saxton Nuclear Experimental Facility) issued interpretive guidance regarding asset impairment owned by a wholly-owned subsidiary of JCP&L, Met-Ed and measurement, concluding that any supplemental regulated Penelec, and decommissioning liabilities for previously divested cash flows such as a CTC should be excluded from the cash GPU nuclear generating units The Companies' share of the flows of assets in a portion of the business not subject to future obligation to decommission these units is approximately regulatory accounting practices If those assets are impaired, $2 6 billion in current dollars and (using a 4 0% escalation a regulatory asset should be established if the costs are rate) approximately $5.3 billion in future dollars The estimated recoverable through regulatory cash flows Consistent with obligation and the escalation rate were developed based on site the SEC guidance, $1 8 billion of impaired plant investments specific studies Decommissioning of the demonstration nuclear

($1 2 billion, $227 million, $304 million and $53 million reactor is expected to be completed in 2003, payments for for OE, Penn, CEI and TE, respectively) were recognized as decommissioning of the nuclear generating units are expected regulatory assets recoverable as transition costs through future to begin in 2014, when actual decommissioning work is expect-regulatory cash flows The following summarizes net assets ed to begin The Companies have recovered approximately included in property, plant and equipment relating to opera- $671 million for decommissioning through their electric rates tions for which the application of SFAS 71 was discontinued, from customers through December 31, 2002 The Companies have compared with the respective company's total assets as of also recognized an estimated liability of approximately $37 million December 31, 2002. related to decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy, as required by the Energy Policy Act of 1992 FirstEnergy 38

In June 2001, the FASB issued SEAS 143, "Accounting for regulated business segment. Prior to the adoption of SPAS 142, Asset Retirement Obligations'" The new statement provides FirstEnergy amortized about $57 million ($.23 per share of accounting standards for retirement obligations associated with common stock) of goodwill annually. There was no goodwill tangible long-lived assets, with adoption required by January 1, amortization in 2001 associated with the GPU merger under 2003. SFAS 143 requires that the fair value of a liability for an the provisions of the new standard.

asset retirement obligation be recorded in the period in which it The following table displays what net income and earnings is incurred. The associated asset retirement costs are capitalized per share would have been if goodwill amortization had been as part of the carrying amount of the long-lived asset. Over time excluded in 2001 and 2000:

the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period 2002 2001 2000 expense. However, rate-regulated entities may recognize a (In thousands, except per share amounts) regulatory asset or liability if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded Reported net income $629,280 $646,447 $598,970 Goodwill amortization (net of tax) - 54,584 54,138 if the cost to settle the retirement obligation differs from the carrying amount. Adjusted net income $629,280 $701,031 $653,108 FirstEnergy has identified applicable legal obligations as Basic earnings per common share:

defined under the new standard, principally for nuclear power Reported earnings per share $2.15 $2.82 $2.69 plant decommissioning. Upon adoption of SEAS 143, asset Goodwill amortization - 0.23 0.25 retirement costs of $807 million were recorded as part of the Adjusted earnings per share $2.15 $3.05 $2.94 carrying amount of the related long-lived asset, offset by accu-mulated depreciation of $437 million. Due to the increased Diluted earnings per common share:

Reported earnings per share $2.14 $2.81 $2.69 carrying amount, the related long-lived assets were tested Goodwill amortization - 0.23 0.24 for impairment in accordance with SFAS 144, "Accounting for Impairment or Disposal of Long-Lived Assets'. No impairment Adjusted earnings per share $2.14 $3.04 $2.93 was indicated.

The asset retirement liability at the date of adoption will The net change of $295 million in the goodwill balance as be $ 1.109 billion. As of December 31, 2002, FirstEnergy had of December 31, 2002 compared to the December 31, 2001 recorded decommissioning liabilities of $1.232 billion, balance primarily reflects the $135.3 million after-tax effect of including unrealized gains on decommissioning trust funds the Pennsylvania PLR reserve discussed in Note 2D - Regulatory of $12 million. The change in the estimated liabilities resulted Matters - Pennsylvania and finalization of the initial purchase from changes in methodology and various assumptions, price allocation for the CPU acquisition (see Note 12).

including changes in the projected dates for decommissioning.

Management expects that the ultimate nuclear decommis- (F) Nuclear Fuel-sioning costs for Met-Ed, Penelec, JCP&L and Penn will be Nuclear fuel is recorded at original cost, which includes tracked and recovered through their regulated rates. Therefore, material, enrichment, fabrication and interest costs incurred FirstEnergy recognized a regulatory liability of $185 million prior to reactor load. The Companies amortize the cost of upon adoption of SFAS 143 for the transition amounts related nuclear fuel based on the rate of consumption.

to establishing the asset retirement obligations for nuclear (G) Stock-Based Compensation-decommissioning for those companies. The remaining cumulative FirstEnergy applies the recognition and measurement effect adjustment to recognize the undepreciated asset retire-principles of Accounting Principles Board (APB) Opinion ment cost and the asset retirement liability offset by the reversal No. 25 (APB 25), "Accounting for Stock Issued to Employees" of the previously recorded decommissioning liabilities was a and related Interpretations in accounting for its stock-based

$298 million increase to income, or $174 million net of tax. The compensation plans (see Note 5C). No material stock-based

$12 million of unrealized gains, $7 million net of tax, included employee compensation expense is reflected in net income as in the decommissioning liability balances as of December 31, all options granted under those plans had an exercise price 2002, was offset against other comprehensive income (OCI) equal to the market value of the underlying common stock upon adoption of SFAS 143.

on the grant date, resulting in substantially no intrinsic value.

The FASB approved SFAS 141, "Business Combinations" and If FirstEnergy had accounted for employee stock options under SFAS 142, "Goodwill and Other Intangible Assets," on June 29, the fair value method, a higher value would have been assigned 2001. SPAS 141 requires all business combinations initiated after to the options granted. The weighted average assumptions used June 30, 2001, to be accounted for using purchase accounting.

in valuing the options and their resulting estimated fair values The provisions of the new standard relating to the determination would be as follows:

of goodwill and other intangible assets have been applied to the GPU merger, which was accounted for as a purchase transaction, 2002 2001 2000 and have not materially affected the accounting for this transac-Valuation assumptions:

tion. Under SFAS 142, amortization of existing goodwill ceased Expected option term (years) 8.1 8.3 7.6 January 1, 2002. Instead, goodwill is tested for impairment at Expected volatility 23.31% 23.45% 21.77%

least on an annual basis - based on the results of the transition Expected dividend yield 4.36% 5.00% 6.68%

analysis and the 2002 annual analysis, no impairment of Risk-free interest rate 4.60% 4.67% 5.28%

FirstEnergy's goodwill is required. The impairment analysis Fair value per option $6.45 $4.97 $2.86 includes a significant source of cash representing EUOC recovery of transition costs as described above under "Regulatory Matters."

FirstEnergy does not believe that completion of transition cost recovery will result in an impairment of goodwill relating to its 39

The effects of applying fair value accounting to FirstEnergy's other postretirement benefits to employees and their beneficiaries stock options would be to reduce net income and earnings per and covered dependents from the time employees are hired share The following table summarizes this effect until they become eligible to receive those benefits As a result of the reduced market value of FirstEnergy's pension 2002 2001 2000 plan assets, it was required to recognize an additional minimum (In thousands) liability as prescribed by SFAS 87 and SFAS 132, 'Employees' Net Income, as reported $629,280 $646,447 $598,970 Disclosures about Pension and Postretirement Benefits," as of Add back compensation December 31, 2002. FirstEnergy's accumulated benefit obligation expense reported in net income, net of tax of $3 438 billion exceeded the fair value of plan assets ($2 889 (based on APB 25) 166 25 144 billion) resulting in a minimum pension liability of $548 6 million Deduct compensation expense based FirstEnergy eliminated its prepaid pension asset of $286.9 million upon fair value, net of tax (8,825) (3,748) (1,736) and established a minimum liability of $548 6 million, recording Adjusted net income $620,621 $642,724 $597,378 an intangible asset of $78 5 million and reducing OCI by $444 2 million (recording a related deferred tax asset of $312.8 million)

Earnings Per Share of Common Stock -

Basic The charge to OCI will reverse in future penods to the extent the As Reported $215 $282 $269 fair value of trust assets exceed the accumulated benefit obligation Adjusted $211 $280 $269 The amount of pension liability recorded as of December 31, Diluted 2002, increased due to the lower discount rate and asset returns As Reported $214 $281 $269 assumed as of December 31, 2002 Adjusted $211 $279 $269 The following sets forth the funded status of the plans and amounts recognized on the Consolidated Balance Sheets as of (H) Income Taxes-December 31.

Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes Deferred income taxes result Other from timing differences in the recognition of revenues and expenses Postrelirement Pension Benefits Benefits for tax and accounting purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period 2002 2001 2002 2001 of the related property The liability method is used to account (Inmillions) for deferred income taxes Deferred income tax liabilities related Change in benefit obligation to tax and accounting basis differences are recognized at the Benefit obligation as of January 1 $3,547 9 $1,506 1 $1,581 6 $ 752 0 Service cost 58 8 34 9 28 5 183 statutory income tax rates in effect when the liabilities are expected Interest cost 249 3 133 3 113 6 64 4 to be paid. Valuation allowances of $465 million were estab- Plan amendments - 36 (121 1) -

lished and included in the Consolidated Balance Sheet as of Actuanal loss 268 0 123 1 440 4 73 3 December 31, 2002, primarily associated with certain fair value Voluntary early retirement program - - - 23 adjustments (see Note 12) and capital losses related to the divesti-GPU acquisition (Note 12) (11 8) 1,8783 1100 7169 tures of international assets owned by the former GPU, Inc. prior Benefits paid (245 8) (131 4) (83 0) (45 6) to its acquisition by FirstEnergy. Of the total valuation allowance, $325 million relates to capital loss carryfonvards Benefit obligation as of December 31 3,866 4 3,547 9 2,070 0 1,581 6 that expire at the end of 2007 Management is unable to predict whether sufficient capital gains will be generated to utilize all of Change infair value of plan assets these capital loss carryforwards. Any ultimate utilization of these Fair value of plan assets as of January 1 3,483 7 1,706 0 535 0 23 0 capital loss carryforwards for which valuation allowances have been Actual return on plan assets (348 9) 81 (571) 12 7 established would reduce goodwill Company contribution - - 37 9 43 3 GPU acquisition - 1,901 0 - 462 0 (I) Retirement Benefits- Benefits paid (245 8) (131 4) (42 5) (60)

FirstEnergy's trusteed, noncontributory defined benefit pension Fair value of plan assets plan covers almost all full-time employees Upon retirement, as of December 31 2,889 0 3,483 7 473 3 535 0 employees receive a monthly pension based on length of service and compensation On December 31, 2001, the GPU pension Funded status of plan (977 4) (64 2) (1,596 7) (1,046 6)

Unrecognized actuarial loss 1,185 8 222 8 751 6 212 8 plans were merged with the FirstEnergy plan FirstEnergy uses the Unrecognized prior service cost 78 5 87 9 (106 8) 17 7 projected unit credit method for funding purposes and was not Unrecognized net required to make pension contributions during the three years transition obligation - - 924 101 6 ended December 31, 2002 The assets of the pension plan consist Net amount recognized $ 2869 $ 2465 $ (8595) $ (7145) primarily of common stocks, United States government bonds and corporate bonds Costs for the year 2001 include the former Consolidated Balance Sheets GPU companies' pension and other postretirement benefit costs classification Prepaid (accrued) benefit cost $ (548 6) $ 2465 $ (8595) $ (714 5) for the period November 7, 2001 through December 31, 2001. Intangible asset 785 - - -

FirstEnergy provides a minimum amount of noncontributory Accumulated other life insurance to retired employees in addition to optional comprehensive loss 7570 - - -

contributory insurance. Health care benefits, which include Net amount recognized $ 286 9 $ 2465 $ (859 5) $ (714 5) certain employee contributions, deductibles and copayments, are also available to retired employees, their dependents and, Assumptions as of December 31 Discount rate 6 75% 7 25% 6 75% 7 25%

under certain circumstances, their survivors FirstEnergy pays Expected long-term return insurance premiums to cover a portion of these benefits in on plan assets 9 00% 10 25% 9 00% 10 25%

excess of set limits, all amounts up to the limits are paid by Rate of compensation increase 3 50% 4 00% 3 50X 4 00 FirstEnergy. FirstEnergy recognizes the expected cost of providing First En ergy 40

Net pension and other postretirement b enefit costs for the cash investments of $6 million. The amounts included in three years ended December 31, 2002 were computed as follows: "Other amortization, net" under Net cash provided from Other Operating Activities primarily consist of amounts from the Postretirement reduction of an electric service obligation under a CEI electric Pension Benefits Benefits service prepayment program.

2002 2001 2000 2002 2001 2000 All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on (Inmilli/

Service cost $ 58.8 $ 34.9 $ 27.4 $ 28.5 $18.3 $11.3 the Consolidated Balance Sheets at cost, which approximates their Interest cost 249.3 133.3 104.8 113.6 64.4 45.7 fair market value. The following sets forth the approximate fair Expected return value and related carrying amounts of all other long-term debt, on plan assets (346.1) (204.8) (181.0) (51.7) (9.9) (0.5) preferred stock subject to mandatory redemption and investments Amortization of other than cash and cash equivalents as of December 31:

transition obligation 2002 2001 (asset) - (2.1) (7.9) 9.2 9.2 9.2 Amortization of Carrying Fair Carrying Fair prior service Value Value Value Value cost 9.3 8.8 5.7 3.2 3.2 3.2 (In millions)

Recognized net actuarial loss Long-term debt* $12,465 $12,761 $12,897 $13,097 (gain) - - (9.1) 11.2 4.9 Preferred stock $ 445 $ 454 $ 636 $ 626 Voluntary early retirement Investments other than cash program - 6.1 17.2 - 2.3 - and cash equivalents:

Debt securities:

Net periodic benefit

-Maturity (5-10 years) $ 502 $ 471 $ 439 $ 402 cost (income) $(28.7) $(23.8) $(42.9) $114.0 $92.4 $68.9

-Maturity (more than 10 years) 927 1,030 990 1,009 Equity securities 15 15 15 15 The composite health care cost trend rate assumption is All other 1,668 1,669 1,730 1,734 approximately 10%-12% in 2003, 9% in 2004 and 8% in

$ 3,112 $ 3,185 $ 3,174 $ 3,160 2005, decreasing to 5% in later years. Assumed health care cost trend rates have a significant effect on the amounts reported for *Excluding approximately $1.75 billion of long-term debt in 2001 the health care plan. An increase in the health care cost trend related to pending divestitures.

rate assumption by one percentage point would increase the total service and interest cost components by $20.7 million The fair values of long-term debt and preferred stock reflect and the postretirement benefit obligation by $232.2 million. the present value of the cash outflows relating to those securities A decrease in the same assumption by one percentage point based on the current call price, the yield to maturity or the yield would decrease the total service and interest cost components to call, as deemed appropriate at the end of each respective year.

by $16.7 million and the postretirement benefit obligation The yields assumed were based on securities with similar char-by $204.3 million. acteristics offered by corporations with credit ratings similar to the Companies' ratings.

(J) Supplemental Cash Flows Information- The fair value of investments other than cash and cash All temporary cash investments purchased with an initial equivalents represent cost (which approximates fair value) maturity of three months or less are reported as cash equivalents or the present value of the cash inflows based on the yield to on the Consolidated Balance Sheets at cost, which approximates maturity. The yields assumed were based on financial instru-their fair market value. As of December 31, 2002, cash and cash ments with similar characteristics and terms. Investments other equivalents included $50 million used for the redemption of than cash and cash equivalents include decommissioning trust long-term debt in January 2003. Noncash financing and investing investments. The Companies have no securities held for trading activities included the 2001 FirstEnergy common stock issuance purposes. See Note 9 - Other Information for discussion of of $2.6 billion for the GPU acquisition and capital lease trans- SFAS 115 activity related to equity investments.

actions amounting to $3.1 million and $89.3 million for the The investment policy for the nuclear decommissioning trust years 2001 and 2000, respectively. There were no capital lease funds restricts or limits the ability to hold certain types of assets transactions in 2002. Commercial paper transactions of OES including private or direct placements, warrants, securities of Fuel, Incorporated (a wholly owned subsidiary of OE) that had FirstEnergy, investments in companies owning nuclear power initial maturity periods of three months or less were reported plants, financial derivatives, preferred stocks, securities convert-net within financing activities under long-term debt, prior to ible into common stock and securities of the trust fund's custodian the expiration of the related long-term financing agreement in or managers and their parents or subsidiaries. The investments March 2002, and were reflected as currently payable long-term that are held in the decommissioning trusts (included as "All debt on the Consolidated Balance Sheet as of December 31, other" in the table above) consist of equity securities, govern-2001. Net losses on foreign currency exchange transactions ment bonds and corporate bonds. Unrealized gains and losses reflected in FirstEnergy's 2002 Consolidated Statement of applicable to the decommissioning trusts have been recognized Income consisted of approximately $104.1 million from in the trust investment with a corresponding change to the FirstEnergy's Argentina operations (see Note 3 - Divestitures). decommissioning liability. In conjunction with the adoption of In the Consolidated Statements of Cash Flows, the amounts SEAS 143 on January 1, 2003, unrealized gains or losses were included in "Cash investments" under Net cash used for reclassified to OCI in accordance with SFAS 115. Realized gains Investing Activities primarily consist of changes in capital trust (losses) are recognized as additions (reductions) to trust asset investments of $(87) million (see Note 4 - Leases) and other balances. For the year 2002, net realized gains (losses) were 41

approximately $(15 6) mdllion and interest and dividend income quarter of 2002, FirstEnergy unwound $400 million of these totaled approximately $33.2 million swaps in the fourth quarter of 2002 during a period of steadily On January 1, 2001, FirstEnergy adopted SFAS 133, dedining market interest rates Gains recognized from unwinding "Accounting for Derivative Instruments and Hedging Activities', these swaps were added to the carrying value of the hedged debt as amended by SFAS 138, 'Accounting for Certain Derivative and will be recognized over the remaining life of the underlying Instruments and Certain Hedging Activities - an amendment debt (through November 2006) of FASB Statement No 133." The cumulative effect to January 1, FirstEnergy engages in the trading of commodity derivatives 2001 was a charge of $8 5 million (net of $5 8 million of income and periodically experiences net open positions. FirstEnergy's taxes) or $ 03 per share of common stock The reported results risk management policies limit the exposure to market risk of operations for the year ended December 31, 2000 would not from open positions and require daily reporting to management have been matenally different if this accounting had been in of potential financial exposures effect during that year (K) Regulatory Assets-FirstEnergy is exposed to financial risks resulting from the The Companies recognize, as regulatory assets, costs which fluctuation of interest rates and commodity prices, including the FERC, PUCO, PPUC and NJBPU have authorized for recovery electricity, natural gas and coal To manage the volatility relating from customers in future periods Without such authorization, to these exposures, FirstEnergy uses a variety of non-derivative the costs would have been charged to income as incurred. All and derivative instruments, induding forward contracts, regulatory assets are expected to continue to be recovered from options, futures contracts and swaps The derivatives are used customers under the Companies' respective transition and regu-principally for hedging purposes, and to a lesser extent, for trad-latory plans Based on those plans, the Companies continue ing purposes FirstEnergy's Risk Policy Committee, comprised of to bill and collect cost-based rates for their transmission and executive officers, exercises an independent risk oversight func-distribution services, which remain regulated, accordingly, it is tion to ensure compliance with corporate risk management appropriate that the Companies continue the application of policies and prudent risk management practices SFAS 71 to those operations OE and Penn recognized additional FirstEnergy uses derivatives to hedge the risk of price and cost recovery of $270 million in 2000 as additional regulatory interest rate fluctuations FirstEnergy's primary ongoing hedging asset amortization in accordance with their prior Ohio and cur-activity involves cash flow hedges of electricity and natural gas rent Pennsylvania regulatory plans. The Ohio Companies and purchases The maximum periods over which the variability of Penn recognized incremental transition cost recovery aggregating electncity and natural gas cash flows are hedged are two and three

$323 million in 2002 and $309 million in 2001, in accordance years, respectively Gains and losses from hedges of commodity with the current Ohio transition plan and Pennsylvania regula-price risks are included in net income when the underlying tory plan Regulatory assets which do not earn a current return hedged commodities are delivered Also, gains and losses are totaled approximately $475.2 million as of December 31, 2002.

included in net income when ineffectiveness occurs on certain Net regulatory assets on the Consolidated Balance Sheets are natural gas hedges The impact of ineffectiveness on earnings during 2002 was not material FirstEnergy entered into interest comprised of the following rate derivative transactions during 2001 to hedge a portion of 2002 2001 the anticipated interest payments on debt related to the GPU acquisition Gains and losses from hedges of anticipated interest (In millions)

Regulatory transition charge $7,365 3 $7,751 5 payments on acquisition debt will be included in net income Customer receivables for future income taxes 394 0 433 0 over the periods that hedged interest payments are made - 5, Societal benefits charge 143 8 166 6 10 and 30 years. Gains and losses from derivative contracts Loss on reacquired debt 73 7 80 0 are included in other operating expenses The current net Employee postretirement benefit costs 87 7 98 6 Nuclear decommissioning, decontamination deferred loss of $110 2 million induded in Accumulated Other and spent fuel disposal costs 98 8 80 2 Comprehensive Loss (AOCL) as of December 31, 2002, for Provider of last resort costs - 116 2 denvative hedging activity, as compared to the December 31, Property losses and unrecovered plant costs 87 8 104 1 2001 balance of $169 4 million in net deferred losses, resulted Other 71 9 82.4 from the reversal of $6 0 million of derivative losses related to Total $8,323 0 $8,912 6 the sale of Avon, a $33 0 million reduction related to current hedging activity and a $20 2 million reduction due to net hedge gains included in earnings during the year. Approximately $19 0 3. DIVESTITURES:

million (after tax) of the current net deferred loss on derivative instruments in AOCL is expected to be reclassified to earnings International Operations-during the next twelve months as hedged transactions occur FirstEnergy identified certain former GPU international However, the fair value of these derivative instruments will fluctu- operations for divestiture within one year of the merger. These ate from period to period based on various market factors and operations constitute individual 'lines of business' as defined will generally be more than offset by the margin on related sales in APB 30, 'Reporting the Results of Operations - Reporting the and revenues FirstEnergy also entered into fixed-to-floating Effects of Disposal of a Segment of a Business, and Extraordinary, interest rate swap agreements dunng 2002 to increase the variable- Unusual and Infrequently Occurring Events and Transactions, rate component of its debt portfolio from 16% to approximately with physically and operationally separable activities 20% at year end These denvatives are treated as fair value hedges Application of EITF Issue No 87-11, 'Allocation of Purchase of fixed-rate, long-term debt issues-protecting against the risk of Price to Assets to Be Sold," required that expected, pre-sale changes in the fair value of fixed-rate debt instruments due to cash flows, induding incremental interest costs on related lower interest rates Swap maturities, call options and interest acquisition debt, of these operations be considered part of the payment dates match those of the underlying obligations resulting purchase price allocation Accordingly, subsequent to the merger in no ineffectiveness in these hedge positions After reaching a date, results of operations and incremental interest costs related maximum notional position of $993 5 million in the third to these international subsidiaries were not included in FirstEnergy 42

FirstEnergy's 2001 Consolidated Statements of Income. On November 1, 2002, FirstEnergy began consolidating Additionally, assets and liabilities of these international the results of Emdersa's operations in its financial statements.

operations were segregated under separate captions on the In addition to the currency transaction losses of $104.1 million, Consolidated Balance Sheet as of December 31, 2001 as "Assets FirstEnergy recognized a currency translation adjustment in Pending Sale" and "Liabilities Related to Assets Pending Sale." other comprehensive income of $91.5 million as of December 31, Upon completion of its merger with GPU, FirstEnergy accepted 2002, which reduced FirstEnergy's common stockholders' equity.

an October 2001 offer from Aquila, Inc. (formerly UtiliCorp This adjustment represents the impact of translating Emdersa's United) to purchase Avon Energy Partners Holdings (Avon), financial statements from its functional currency to the U.S.

FirstEnergy's wholly owned holding company for Midlands dollar for GAAP financial reporting.

Electricity plc, for $2.1 billion (including the assumption of Sale of Generating Assets-

$1.7 billion of debt). The transaction closed on May 8, 2002 In November 2001, FirstEnergy reached an agreement to and reflected the March 2002 modification of Aquila's initial sell four coal-fired power plants totaling 2,535 MW to NRG offer such that Aquila acquired a 79.9 percent equity interest in Energy Inc. On August 8, 2002, FirstEnergy notified NRG that Avon for approximately $1.9 billion (including the assumption it was canceling the agreement because NRG stated that it could of $1.7 billion of debt). Proceeds to FirstEnergy included $155 not complete the transaction under the original terms of the million in cash and a note receivable for approximately $87 million agreement. FirstEnergy also notified NRG that FirstEnergy (representing the present value of $19 million per year to be reserves the right to pursue legal action against NRG, its affiliate received over six years beginning in 2003) from Aquila for its and its parent, Xcel Energy, for damages, based on the anticipatory 79.9 percent interest. FirstEnergy and Aquila together own all breach of the agreement. On February 25, 2003, the U.S.

of the outstanding shares of Avon through a jointly owned sub-Bankruptcy Court in Minnesota approved FirstEnergy's request sidiary, with each company having a 50 percent voting interest.

for arbitration against NRG.

Originally, in accordance with applicable accounting guidance, In December 2002, FirstEnergy decided to retain ownership the earnings of those foreign operations were not recognized in of these plants after reviewing other bids it subsequently received current earnings from the date of the GPU acquisition until from other parties who had expressed interest in purchasing the February 6, 2002, the date when Aquila began discussions to plants. Since FirstEnergy did not execute a sales agreement by revise its initial offer to purchase Avon. However, the revision year-end, it reflected approximately $74 million ($43 million to the initial offer by Aquila caused a reversal of this accounting net of tax) of previously unrecognized depreciation and other in the first quarter of 2002, resulting in the recognition of a transaction costs in the fourth quarter of 2002 related to these cumulative effect of a change in accounting which increased plants from November 2001 through December 2002 on its net income by $31.7 million. This resulted from the application Consolidated Statement of Income.

of guidance provided by EITF Issue No. 90-6, "Accounting for Certain Events Not Addressed in Issue No. 87-11 relating to an 4. LEASES:

Acquired Operating Unit to Be Sold," and accounting under The Companies lease certain generating facilities, office EITF Issue No. 87-11, recognizing the net income of Avon from space and other property and equipment under cancelable November 7, 2001 to February 6, 2002 that previously was not and noncancelable leases.

recognized by FirstEnergy in its consolidated earnings as discussed OE sold portions of its ownership interests in Perry Unit 1 and above. In the fourth quarter of 2002, FirstEnergy recorded a Beaver Valley Unit 2 and entered into operating leases on the

$50 million charge ($32.5 million net of tax) to reduce the portions sold for basic lease terms of approximately 29 years.

carrying value of its remaining 20.1 percent interest. CEI and TE also sold portions of their ownership interests in GPU's former Argentina operations were also identified Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 by FirstEnergy for divestiture within one year of the merger. and entered into similar operating leases for lease terms of FirstEnergy determined the fair value of its Argentina opera- approximately 30 years. During the terms of their respective tions, GPU Empresa Distribuidora Electrica Regional S.A. and leases, OE, CEI and TE continue to be responsible, to the extent affiliates (Emdersa), based on the best available information of their individual combined ownership and leasehold interests, as of the date of the merger. Subsequent to that date, a number for costs associated with the units including construction of economic events have occurred in Argentina which may have expenditures, operation and maintenance expenses, insurance, an impact on FirstEnergy's ability to realize Emdersa's estimated nuclear fuel, property taxes and decommissioning. They have fair value. These events include currency devaluation, restrictions the right, at the expiration of the respective basic lease terms, on repatriation of cash, and the anticipation of future asset to renew their respective leases. They also have the right to sales in that region by competitors. FirstEnergy did not reach a purchase the facilities at the expiration of the basic lease term definitive agreement to sell Emdersa as of December 31, 2002. or any renewal term at a price equal to the fair market value of Therefore, these assets were no longer classified as "Assets Pending the facilities. The basic rental payments are adjusted when Sale" on the Consolidated Balance Sheet as of December 31, applicable federal tax law changes.

2002 and Emdersa's results of operations were included in OES Finance, Incorporated, a wholly owned subsidiary of FirstEnergy's 2002 Consolidated Statement of Income. As a result, OE, maintains deposits pledged as collateral to secure reim-under EITF Issue No. 90-6, FirstEnergy recorded in the fourth bursement obligations relating to certain letters of credit supporting quarter a one-time, non-cash "Cumulative Effect of Accounting OE's obligations to lessors under the Beaver Valley Unit 2 sale Change" on its 2002 Consolidated Statement of Income related and leaseback arrangements. The deposits of approximately to Emdersa's cumulative results of operations from November 7, $278 million pledged to the financial institution providing 2001 through October 31, 2002. The amount of this one-time, those letters of credit are the sole property of OES Finance and after-tax charge was $88.8 million, or $0.30 per share of com- are investments which are classified as "Held to Maturity'.

mon stock (comprised of $104.1 million in currency transac- In the event of liquidation, OES Finance, as a separate corporate tion losses arising principally from U.S. dollar denominated entity, would have to satisfy its obligations to creditors before debt, offset by $15.3 million of operating income). any of its assets could be made available to OE as sole owner of OES Finance common stock.

43

Consistent with the regulatory treatment, the rentals for capital based on the shares allocated method The fair value of and operating leases are charged to operating expenses on the 3,966,269 shares unallocated as of December 31, 2002, was Consolidated Statements of Income. Such costs for the three approximately $130 8 million Total ESOP-related compensation years ended December 31, 2002, are summarized as follows expense was calculated as follows 2002 2001 2000 2002 2001 2000 (Inmillons) (Inmillions)

Operating leases Base compensation $34 2 $25 1 $18 7 Interest element $188 4 $194 1 $202 4 Dividends on common stock held by Other 135 9 120 5 ill 1 the ESOP and used to service debt (78) (61) (6 4)

Capital leases Interest element 24 80 123 Net expense $26 4 $19 0 $12 3 Other 25 35 5 64 2 Total rentals $329 2 $358 1 $390 0 (C) Stock Compensation Plans-In 2001, FirstEnergy assumed responsibility for two new The future minimum lease payments as of December 31, stock-based plans as a result of its acquisition of GPU No 2002, are further stock-based compensation can be awarded under the GPU, Inc Stock Option and Restricted Stock Plan for MYR Operating Leases Group Inc Employees (MYR Plan) or the 1990 Stock Plan Capital Lease Capital for Employees of GPU, Inc. and Subsidiaries (GPU Plan)

Leases Payments Trusts Net All options and restncted stock under both Plans have been (In millions) converted into FirstEnergy options and restricted stock Options 2003 $ 46 $3319 $ 178 8 5 1531 under the GPU Plan became fully vested on November 7, 2001, 2004 60 2938 1118 1820 and will expire on or before June 1, 2010. Under the MYR Plan, 2005 54 313 4 130 3 1831 2006 54 322 0 1418 1802 all options and restricted stock maintained their original vesting 2007 18 299 5 130 7 168 8 periods, which range from one to four years, and will expire Years thereafter 80 2,807 9 977 7 1,830 2 on or before December 17, 2006 Total minimum lease payments 31 2 $4,368 5 $1,671 1 $2,697 4 Additional stock-based plans administered by FirstEnergy include the Centerior Equity Plan (CE Plan) and the FirstEnergy Executory costs 71 Executive and Director Incentive Compensation Plan (FE Plan)

Net minimum lease payments 24 1 All options are fully vested under the CE Plan, and no further Interest portion 83 awards are permitted Outstanding options will expire on or before Present value of net February 25, 2007 Under the FE Plan, total awards cannot minimum lease payments 15 8 exceed 22 5 million shares of common stock or their equivalent.

Less current portion 18 Only stock options and restricted stock have been granted, with Noncurrent portion $14 0 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 OE invested in the PNBV Capital Trust, which was establish led as follows to purchase a portion of the lease obligation bonds issued on 2002 2001 2000 behalf of lessors in OE's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions CEI and TE established the Restricted common shares granted 36,922 133,162 208,400 Shippingport Capital Trust to purchase the lease obligation Weighted average market price $36 04 $35 68 $26 63 Weighted average vesting penod (years) 32 37 38 bonds issued on behalf of lessors in their Bruce Mansfield Dividends restricted Yes Yes Units 1, 2 and 3 sale and leaseback transactions The PNBV and Shippingport capital trust arrangements effectively reduce FE Plan dividends are paid as restrictedstock on 4,500 shares, MYR Plan dividends are paid as unrestricted cash on 128,662 shares lease costs related to those transactions 5.CAPITALIZATION: Under the Executive Deferred Compensation Plan (EDCP),

covered employees can direct a portion of their Annual (A) Retained Earnings- Incentive Award and/or Long-Term Incentive Award into an There are no restrictions on retained earnings for payment unfunded FirstEnergy Stock Account to receive vested stock of cash dividends on FirstEnergy's common stock. units. An additional 20% premium is received in the form of (B) Employee Stock Ownership Plan- stock units based on the amount allocated to the FirstEnergy An ESOP Trust funds most of the matching contribution Stock Account. Dividends are calculated quarterly on stock units for FirstEnergy's 401 (k) savings plan All full-time employees outstanding and are paid in the form of additional stock units eligible for participation in the 401 (k) savings plan are covered Upon withdrawal, stock units are converted to FirstEnergy by the ESOP The ESOP borrowed $200 million from OE and shares Payout typically occurs three years from the date of acquired 10,654,114 shares of OE's common stock (subsequently deferral, however, an election can be made in the year prior to converted to FirstEnergy common stock) through market pur- payout to further defer shares into a retirement stock account chases Dividends on ESOP shares are used to service the debt. that will pay out in cash upon retirement. As of December 31, Shares are released from the ESOP on a pro rata basis as debt 2002, there were 296,008 stock units outstanding.

service payments are made In 2002, 2001 and 2000, 1,151,106 See Note 9 - Other Information for discussion of stock-based shares, 834,657 shares and 826,873 shares, respectively, were employee compensation expense recognized for restricted stock allocated to employees with the corresponding expense recognized and EDCP stock units FirstEnergy 44

Stock option activities under the FE Programs for the past (F) Subsidiary-Obligated Mandatorily Redeemable Preferred three years were as follows: Securities of Subsidiary Trust or Limited Partnership Holding Number of Weighted Average Solely Subordinated Debentures of Subsidiaries-Stock Option Activities Options Exercise Price CEI formed a statutory business trust as a wholly owned financing subsidiary The trust sold preferred securities and Balance, January 1, 2000 2,153,369 $25.32 (159,755 options exercisable) 24.87 invested the gross proceeds in the 9.00% subordinated deben-tures of CEI and the sole assets of the trust are the applicable Options granted 3,011,584 23.24 subordinated debentures. Interest payment provisions of the Options exercised 90,491 26.00 Options forfeited 52,600 22.20 subordinated debentures match the distribution payment Balance, December 31, 2000 5,021,862 24.09 provisions of the trust's preferred securities. In addition, upon (473,314 options exercisable) 24.11 redemption or payment at maturity of subordinated debentures, Options granted 4,240,273 28.11 the trust's preferred securities will be redeemed on a pro rata Options exercised 694,403 24.24 basis at their liquidation value. Under certain circumstances, Options forfeited 120,044 28.07 the applicable subordinated debentures could be distributed to Balance, December 31, 2001 8,447,688 26.04 the holders of the outstanding preferred securities of the trust (1,828,341 options exercisable) 24.83 in the event that the trust is liquidated. CEI has effectively Options granted 3,399,579 34.48 provided a full and unconditional guarantee of payments due Options exercised 1,018,852 23.56 on its trust's preferred securities. Its trust preferred securities Options forfeited 392,929 28.19 Balance, December 31, 2002 10,435,486 28.95 are redeemable at 100% of their principal amount at CEI's (1,400,206 options exercisable) 26.07 option, beginning in December 2006.

Met-Ed and Penelec each formed statutory business trusts for substantially similar transactions as CEI. However, owner-As of December 31, 2002, the weighted average remaining ship of the respective Met-Ed and Penelec trusts is through contractual life of outstanding stock options was 7.6 years. separate wholly-owned limited partnerships, of which a wholly-No material stock-based employee compensation expense is owned subsidiary of each company is the sole general partner.

reflected in net income for stock options granted under the above In these transactions, each trust invested the gross proceeds plans since the exercise price was equal to the market value from the sale of its trust preferred securities in the preferred of the underlying common stock on the grant date. The effect securities of the applicable limited partnership, which in turn of applying fair value accounting to FirstEnergy's stock options invested those proceeds in the 7.35% and 7.34% subordinated is summarized in Note 2G - Stock-Based Compensation. debentures of Met-Ed and Penelec, respectively. In each case, the applicable parent company has effectively provided a full (D) Preferred and Preference Stock-and unconditional guarantee of its obligations under its trust's Penn's 7.75% series has a restriction which prevents early preferred securities. The Met-Ed and Penelec trust preferred redemption prior to July 2003. All other preferred stock may be securities are redeemable at the option of Met-Ed and Penelec redeemed by the Companies in whole, or in part, with 30-90 beginning in May 2004 and September 2004, respectively, at days' notice.

100% of their principal amount.

Met-Ed's and Penelec's preferred stock authorization consists JCP&L formed a limited partnership for a substantially similar of 10 million and 11.435 million shares, respectively, without transaction; however, no statutory trust is involved. That limited par value. No preferred shares are currently outstanding for the partnership, of which JCP&L is the sole general partner, invested two companies.

the gross proceeds from the sale of its monthly income preferred The Companies' preference stock authorization consists of securities (MIPS) in JCP&L's 8.56% subordinated debentures.

8 million shares without par value for OE; 3 million shares JCP&L has effectively provided a full and unconditional guarantee without par value for CEI; and 5 million shares, $25 par value of its obligations under the limited partnership's MIPS. The limited for TE. No preference shares are currently outstanding.

partnership's MIPS are redeemable at JCP&L's option at 100%

(E) Preferred Stock Subject to Mandatory Redemption- of their principal amount.

Annual sinking fund provisions for the Companies' preferred In each of these transactions, interest on the subordinated stock are as follows: debentures (and therefore the distributions on trust preferred securities or MIPS) may be deferred for up to 60 months, but the parent company may not pay dividends on, or redeem Series Shares Share or acquire, any of its cumulative preferred or common stock until deferred payments on its subordinated debentures are CEI $ 7.35 C 10,000 $ 100 Penn 7.625% 7,500 100 paid in full.

Annual sinking fund requirements for the next five years are

$1.8 million in each year 2003 through 2006 and $12.3 million in 2007.

45

The following table lists the subsidiary trusts and limited Included in the table above are amounts for vanous variable partnership and information regarding their preferred securities interest rate long-term debt which have provisions by which outstanding as of December 31, 2002 individual debt holders have the option to 'put backs or require the respective debt issuer to redeem their debt at Stated Subordinated those times when the interest rate may change prior to its Maturity Rate Value (a) Debentures maturity date These amounts are $626 million, $266 million (Inmillions) and $47 million in 2003, 2004 and 2005, respectively, which Cleveland Electric represents the next date at which the debt holders may Financing Trust (b) 2031 9 00% $100 0 $103 1 Met-Ed Capital Trust (c) 2039 7 35% $100 0 $103 1 exercise this provision.

Penelec Capital Trust (c) 2039 7 34% $100 0 $103 1 The Companies' obligations to repay certain pollution JCP&L, Capital LP(b) 2044 8 56% $125 0 $128 9 control revenue bonds are secured by several series of first (a)The liquidation value is $25 per security mortgage bonds Certain pollution control revenue bonds (b)The sole assets of the trust orlimited partnership arethe parent company's are entitled to the benefit of irrevocable bank letters of credit subordinated debentures with the same rate and maturity date as the of $287 6 million and noncancelable municipal bond insur-preferred securities ance policies of $544 1 million to pay principal of, or interest (c) The sole assets of the trust are the preferred securities of Met-Ed Capital If, on, the pollution control revenue bonds To the extent that LP and Penelec Capital 11, LP,respectively whose sole assets are the parent companys subordinated debentures with the same rate and matunty drawings are made under the letters of credit or policies, the date as the preferred secunties Companies are entitled to a credit against their obligation to repay those bonds. The Companies pay annual fees of 1 00%

to 1 375% of the amounts of the letters of credit to the issuing (G) Long-Term Debt- banks and are obligated to reimburse the banks for any Each of the Companies has a first mortgage indenture under drawings thereunder.

which it issues from time to time first mortgage bonds secured FirstEnergy had unsecured borrowings of $395 million as by a direct first mortgage lien on substantially all of its property of December 31, 2002, under its $500 million long-term and franchises, other than specifically excepted property revolving credit facility agreement which expires November 29, FirstEnergy and its subsidianes have various debt covenants under 2004. FirstEnergy currently pays an annual facility fee of their respective financing arrangements The most restrictive of 0 25% on the total credit facility amount The fee is subject the debt covenants relate to the nonpayment of interest and/or to change based on changes to FirstEnergy's credit ratings.

principal on debt and the maintenance of certain financial ratios CEI and TE have unsecured letters of credit of approximately The nonpayments debt covenant which could trigger a default $215 9 million in connection with the sale and leaseback of is applicable to financing arrangements of FirstEnergy and all Beaver Valley Unit 2 that expire in April 2005 CEI and TE are of the Companies. The maintenance of minimum fixed charge jointly and severally liable for the letters of credit. In connection ratios and debt to capitalization ratios covenants is applicable with its Beaver Valley Unit 2 sale and leaseback arrangements, to financing arrangements of FirstEnergy, the Ohio Companies OE has similar letters of credit secured by deposits held by its and Penn. There also exists cross-default provisions among subsidiary, OES Finance (see Note 4) financing arrangements of FirstEnergy and the Companies Based on the amount of bonds authenticated by the respective (H) Securitized Transition Bonds-mortgage bond trustees through December 31, 2002, the On June 11, 2002, JCP&L Transition Funding LLC (Issuer),

Companies' annual improvement fund requirements for all a wholly owned limited liability company of JCP&L, sold $320 bonds issued under the mortgages amounts to $61 5 million million of transition bonds to secuntize the recovery of JCP&L's OE and Penn expect to deposit funds with their respective mort- bondable stranded costs associated with the previously divested gage bond trustees in 2003 that will then be withdrawn upon Oyster Creek Nuclear Generating Station the surrender for cancellation of a like principal amount of JCP&L does not own nor did it purchase any of the transition bonds, specifically authenticated for such purposes against bonds, which are induded in long-term debt on FirstEnergy's unfunded property additions or against previously retired bonds and JCP&L's Consolidated Balance Sheets The transition bonds This method can result in minor increases in the amount of the represent obligations only of the Issuer and are collateralized annual sinking fund requirement JCP&L, Met-Ed and Penelec solely by the equity and assets of the Issuer, which consist expect to fulfill their sinking and improvement fund obligation primarily of bondable transition property The bondable by providing bondable property additions and/or retired bonds transition property is solely the property of the Issuer to the respective mortgage bond trustees Bondable transition property represents the irrevocable nght Sinking fund requirements for first mortgage bonds and of a utility company to charge, collect and receive from its cus-maturing long-term debt (excluding capital leases) for the tomers, through a non-bypassable transition bond charge, the next five years are: principal amount and interest on the transition bonds and other fees and expenses associated with their issuance. JCP&L, as servicer, (Inmillions) manages and administers the bondable transition property, 2003 $1,698 8 including the billing, collection and remittance of the transition 2004 1,603 8 bond charge, pursuant to a servicing agreement with the Issuer.

2005 918 5 JCP&L is entitled to a quarterly servicing fee of $100,000 that is 2006 1,402 2 payable from transition bond charge collections 2007 251 9 FirstEnergy 46

(I) Comprehensive Income- The Companies are also insured under policies for each nuclear Comprehensive income includes net income as reported on plant. Under these policies, up to $2.75 billion is provided for the Consolidated Statements of Income and all other changes property damage and decontamination costs. The Companies have in common stockholders' equity except those resulting from also obtained approximately $1.2 billion of insurance transactions with common stockholders. As of December 31, 2002, coverage for replacement power costs. Under these policies, the accumulated other comprehensive income (loss) consisted of a Companies can be assessed a maximum of approximately minimum liability for unfunded retirement benefits of $450.2 $68.4 million for incidents at any covered nuclear facility occurring million, unrealized losses on investments in securities available during a policy year which are in excess of accumulated funds for sale of $11.4 million, unrealized losses on derivative instrument available to the insurer for paying losses.

hedges of $110.2 million and unrealized currency translation The Companies intend to maintain insurance against nuclear adjustments of $91.4 million. See Note 9 - Other Information for risks as described above as long as it is available. To the extent that discussion of derivative instruments reclassifications to net income. replacement power, property damage, decontamination, repair and replacement costs and other such costs arising from a nuclear inci-(J) Stock Repurchase Program- dent at any of the Companies' plants exceed the policy limits of The Board of Directors authorized the repurchase of up to the insurance in effect with respect to that plant, to the extent a 15 million shares of FirstEnergy's common stock over a three-year nuclear incident is determined not to be covered by the period beginning in 1999. Repurchases were made on the open Companies' insurance policies, or to the extent such insurance market, at prevailing prices, and were funded primarily through the becomes unavailable in the future, the Companies would remain at use of operating cash flows. During 2001 and 2000, FirstEnergy risk for such costs.

repurchased and retired 550,000 shares (average price of $27.82 per share), and 7.9 million shares (average price of $24.51 per share), (C) Guarantees and Other Assurances-respectively. As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide

6. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT: financial or performance assurances to third parties. Such agree-Short-term borrowings outstanding as of December 31, 2002, ments include contract guarantees, surety bonds and rating-consisted of $933.1 million of bank borrowings and $159.7 contingent collateralization provisions. As of December 31, 2002, million of OES Capital, Incorporated commercial paper. OES outstanding guarantees and other assurances aggregated $913 mil-Capital is a wholly owned subsidiary of OE whose borrowings are lion.

secured by customer accounts receivable. OES Capital can borrow FirstEnergy guarantees energy and energy-related payments up to $170 million under a receivables financing agreement at of its subsidiaries involved in energy marketing activities -

rates based on certain bank commercial paper and is required to principally to facilitate normal physical transactions involving elec-pay an annual fee of 0.20% on the amount of the entire finance tricity, gas, emission allowances and coal. FirstEnergy also provides limit. The receivables financing agreement expires in August 2003. guarantees to various providers of subsidiary financing principally FirstEnergy and its subsidiaries have various credit facilities for the acquisition of property, plant and equipment. These agree-(including a FirstEnergy $1 billion short-term revolving credit facil- ments legally obligate FirstEnergy and its subsidiaries to fulfill the ity) with domestic and foreign banks that provide for obligations of those subsidiaries directly involved in energy and borrowings of up to $1.084 billion under various interest rate energy-related transactions or financing where the law might other-options. To assure the availability of these lines, FirstEnergy wise limit the counterparties' claims. If demands of a counterparty and its subsidiaries are required to pay annual commitment fees were to exceed the ability of a subsidiary to satisfy existing obliga-that vary from 0.125% to 0.20%. These lines expire at various tions, FirstEnergy's guarantee enables the counterparty's legal claim times during 2003. The weighted average interest rates on to be satisfied by other FirstEnergy assets. The likelihood that such short-term borrowings outstanding as of December 31, 2002 and parental guarantees of $856 million as of December 31, 2002 will 2001, were 2.41% and 3.80%, respectively. increase amounts otherwise to be paid by FirstEnergy to meet its obligations incurred in connection with financings and ongoing

7. COMMITMENTS, GUARANTEES AND CONTINGENCIES:

energy and energy-related contracts is remote.

(A) Capital Expenditures- Most of FirstEnergy's surety bonds are backed by various indem-FirstEnergy's current forecast reflects expenditures of approximate- nities common within the insurance industry. Surety bonds and ly $3.1 billion for property additions and improvements from 2003- related FirstEnergy guarantees of $26 million provide additional 2007, of which approximately $727 million is applicable to 2003. assurance to outside parties that contractual and statutory obliga-Investments for additional nuclear fuel during the 2003-2007 period tions will be met in a number of areas including construction jobs, are estimated to be approximately $485 million, of which approxi- environmental commitments and various retail transactions.

mately $69 million applies to 2003. During the same periods, the Various energy supply contracts contain credit enhancement pro-Companies' nuclear fuel investments are expected to be reduced by visions in the form of cash collateral or letters of credit in the event approximately $483 million and $88 million, respectively, as the of a reduction in credit rating below investment grade. These provi-nuclear fuel is consumed. sions vary and typically require more than one rating reduction to fall below investment grade by Standard &

(B) Nuclear Insurance- Poor's or Moody's Investors Service to trigger additional collateral-The Price-Anderson Act limits the public liability relative to ization by FirstEnergy. As of December 31, 2002, rating-a single incident at a nuclear power plant to $9.5 billion.

contingent collateralization totaled $31 million.

The amount is covered by a combination of private insurance and an industry retrospective rating plan. The Companies' maximum potential assessment under the industry retrospective rating plan would be $352.4 million per incident but not more than $40 million in any one year for each incident.

47

(D) Environmental Matters- outcome of these proceedings, FirstEnergy believes the Sammis Various federal, state and local authorities regulate the Plant is in full compliance with the Clean Air Act and the NOV Companies with regard to air and water quality and other and complaint are without merit Penalties could be imposed environmental matters FirstEnergy estimates additional capital if the Sammis Plant continues to operate without correcting the expenditures for environmental compliance of approximately alleged violations and a court determines that the allegations

$159 million, which is included in the construction forecast are valid The Sammis Plant continues to operate while these provided under "Capital Expenditures' for 2003 through 2007 proceedings are pending The Companies are required to meet federally approved In December 2000, the EPA announced it would proceed with sulfur dioxide (S02) regulations. Violations of such regulations the development of regulations regarding hazardous air pollu-can result in shutdown of the generating unit involved and/or tants from electric power plants The EPA identified mercury civil or cnminal penalties of up to $31,500 for each day the unit as the hazardous air pollutant of greatest concern The EPA is in violation The Environmental Protection Agency (EPA) has established a schedule to propose regulations by December an interim enforcement policy for S02 regulations in Ohio that 2003 and issue final regulations by December 2004 The future allows for compliance based on a 30-day averaging period. cost of compliance with these regulations may be substantial The Companies cannot predict what action the EPA may take As a result of the Resource Conservation and Recovery Act in the future with respect to the interim enforcement policy of 1976, as amended, and the Toxic Substances Control Act of The Companies believe they are in compliance with the 1976, federal and state hazardous waste regulations have been current S02 and nitrogen oxide (NOx) reduction requirements promulgated Certain fossil-fuel combustion waste products, under the Clean Air Act Amendments of 1990 S02 reductions such as coal ash, were exempted from hazardous waste disposal are being achieved by burning lower-sulfur fuel, generating requirements pending the EPA's evaluation of the need for future more electricity from lower-emitting plants, and/or using emis- regulation The EPA has issued its final regulatory determination sion allowances NOx reductions are being achieved through that regulation of coal ash as a hazardous waste is unnecessary combustion controls and the generation of more electricity at In April 2000, the EPA announced that it will develop national lower-emitting plants In September 1998, the EPA finalized standards regulating disposal of coal ash under its authonty to regulations requiring additional NOx reductions from the regulate nonhazardous waste.

Compames' Ohio and Pennsylvania facilities The EPA's NOx The Companies have been named as 'potentially responsible Transport Rule imposes uniform reductions of NOx emissions parties' (PRPs) at waste disposal sites which may require (an approximate 85% reduction in utility plant NOx emissions cleanup under the Comprehensive Environmental Response, from projected 2007 emissions) across a region of nineteen Compensation and Liability Act of 1980 Allegations of disposal states and the District of Columbia, including New Jersey, of hazardous substances at historical sites and the liability Ohio and Pennsylvania, based on a conclusion that such NOx involved are often unsubstantiated and subject to dispute, emissions are contributing significantly to ozone pollution in however, federal law provides that all PRPs for a particular site the eastern United States State Implementation Plans (SIP) be held liable on a joint and several basis Therefore, potential must comply by May 31, 2004 with individual state NOx environmental liabilities have been recognized on the budgets established by the EPA. Pennsylvania submitted a Consolidated Balance Sheet as of December 31, 2002, based SIP that requires compliance with the NOx budgets at the on estimates of the total costs of cleanup, the Companies' pro-Companies' Pennsylvania facilities by May 1, 2003 and Ohio portionate responsibility for such costs and the financial ability submitted a SIP that requires compliance with the NOx of other nonaffiliated entities to pay In addition, JCP&L has budgets at the Companies' Ohio facilities by May 31, 2004 accrued liabilities for environmental remediation of former In July 1997, the EPA promulgated changes in the National manufactured gas plants in New Jersey, those costs are being Ambient Air Quality Standard (NAAQS) for ozone emissions recovered by JCP&L through its SBC The Companies have and proposed a new NAAQS for previously unregulated ultra- total accrued liabilities aggregating approximately $54 3 million fine particulate matter In May 1999, the U S Court of Appeals as of December 31, 2002.

for the D C Circuit found constitutional and other defects in The effects of compliance on the Companies with regard to the new NAAQS rules In February 2001, the U S Supreme Court environmental matters could have a material adverse effect on upheld the new NAAQS rules regulating ultra-fine particulates FirstEnergy's earnings and competitive position. These environ-but found defects in the new NAAQS rules for ozone and decided mental regulations affect FirstEnergy's earnings and competitive that the EPA must revise those rules The future cost of compli- position to the extent it competes with companies that are not ance with these regulations may be substantial and will depend subject to such regulations and therefore do not bear the risk if and how they are ultimately implemented by the states in of costs associated with compliance, or failure to comply, which the Companies operate affected facilities with such regulations FirstEnergy believes it is in material In 1999 and 2000, the EPA issued Notices of Violation compliance with existing regulations but is unable to predict (NOV) or a Compliance Order to nine utilities covering 44 whether environmental regulations will change and what, power plants, including the W H Sammis Plant In addition, if any, the effects of such change would be.

the U S Department of Justice filed eight civil complaints (E) Other Legal Proceedings-against various investor-owned utilities, which included a complaint against OE and Penn in the U S Distnct Court for Various lawsuits, claims for personal injury, asbestos and the Southern District of Ohio, for which hearings began on property damage and proceedings related to FirstEnergy's normal business operations are pending against FirstEnergy and its February 3, 2003 The NOV and complaint allege violations subsidiaries. The most significant are described below.

of the Clean Air Act based on operation and maintenance of TMI-2 was acquired by FirstEnergy in 2001 as part of the merger the Sammis Plant dating back to 1984 The complaint requests with CPU As a result of the 1979 TMI-2 accident, claims for permanent injunctive relief to require the installation of "best alleged personal injury against JCP&L, Met-Ed, Penelec and available control technology" and civil penalties of up to CPU had been filed in the U S District Court for the Middle

$27,500 per day of violation Although unable to predict the FirstEnergy 48

District of Pennsylvania. In 1996, the District Court granted a 8. SEGMENT INFORMATION:

motion for summary judgment filed by GPU and dismissed the FirstEnergy operates under two reportable segments: regulat-ten initial "test cases" which had been selected for a test case ed services and competitive services. The aggregate "Other' seg-trial. On January 15, 2002, the District Court granted GPU's ments do not individually meet the criteria to be considered a July 2001 motion for summary judgment on the remaining reportable segment. "Other" consists of interest expense related 2,100 pending claims. On February 14, 2002, plaintiffs filed a to the 2001 merger acquisition debt; the corporate support notice of appeal to the United States Court of Appeals for the services operating segment and the international businesses Third Circuit. In December 2002, the Court of Appeals refused acquired in the 2001 merger. The international business assets to hear the appeal which effectively ended further legal action reflected in the 2001 "Other" assets amount included assets for those claims. in the United Kingdom identified for divestiture (see Note 3 -

In July 1999, the Mid-Atlantic states experienced a severe Divestitures) which were sold in 2002. As those assets were in heat storm which resulted in power outages throughout the the process of being sold, their performance was not being service territories of many electric utilities, including JCP&L's reviewed by a chief operating decision maker and in accordance territory. In an investigation into the causes of the outages and with SFAS 131, "Disclosures about Segments of an Enterprise the reliability of the transmission and distribution systems of and Related Information,' did not qualify as an operating all four New Jersey electric utilities, the NJBPU concluded that segment. The remaining assets and revenues for the corporate there was not a prima facie case demonstrating that, overall, support services and the remaining international businesses JCP&L provided unsafe, inadequate or improper service to its were below the quantifiable threshold for operating segments customers. Two class action lawsuits (subsequently consolidated for separate disclosure as "reportable segments." FirstEnergy's into a single proceeding) were filed in New Jersey Superior Court primary segment is its regulated services segment, which in July 1999 against JCP&L, CPU and other GPU companies includes eight electric utility operating companies in Ohio, seeking compensatory and punitive damages arising from the Pennsylvania and New Jersey that provide electric transmission July 1999 service interruptions in the JCP&L territory. In May and distribution services. Its other material business segment 2001, the court denied without prejudice the defendants' consists of the subsidiaries that operate unregulated energy motion seeking decertification of the class. Discovery continues and energy-related businesses.

in the class action, but no trial date has been set. In October The regulated services segment designs, constructs, operates 2001, the court held argument on the plaintiffs' motion for and maintains FirstEnergy's regulated transmission and distri-partial summary judgment, which contends that JCP&L is bution systems. It also provides generation services to regulated bound to several findings of the NJBPU investigation. The franchise customers who have not chosen a competing generation plaintiffs' motion was denied by the Court in November 2001 supplier. The regulated services segment obtains a portion of and the plaintiffs' motion to file an appeal of this decision was its required generation through power supply agreements with denied by the New Jersey Appellate Division. JCP&L has also the competitive services segment.

filed a motion for partial summary judgment that is currently The competitive services segment includes all domestic pending before the Superior Court. FirstEnergy is unable to unregulated energy and energy-related services including com-predict the outcome of these matters. modity sales (both electricity and natural gas) in the retail and wholesale markets, marketing, generation and sourcing of (F) Other Commitments and Contingencies-commodity requirements, as well as other competitive energy-GPU made significant investments in foreign businesses and application services. Competitive products are increasingly facilities through its GPU Capital and CPU Power subsidiaries.

marketed to customers as bundled services.

Although FirstEnergy will attempt to mitigate its risks related to Segment financial data in 2001 and 2000 have been reclassified foreign investments, it faces additional risks inherent in operat-to conform with the current year business segment organizations ing in such locations, including foreign currency fluctuations.

and operations. Changes in the current year methodology for El Barranquilla, a wholly owned subsidiary of GPU Power, computing revenues and expenses used in management reporting is a 28.67% equity investor in Termobarranquilla S.A., Empresa for the Competitive Services segment have been reflected in de Servicios Publicos (TEBSA), which owns a Colombian inde-reclassified 2001 and 2000 financial results. Methodology pendent power generation project. GPU Power is committed, changes included using a fixed rate revenues calculation for under certain circumstances, to make additional standby equity the Competitive Services segment's power sales agreement with contributions of $21.3 million, which FirstEnergy has guaran-the Regulated Services segment. This change, when applied to teed. The total outstanding senior debt of the TEBSA project is previously reported results, caused lower revenues, income

$254 million as of December 31, 2002. The lenders include taxes and net income as compared to prior calculated amounts the Overseas Private Investment Corporation, US Export Import and, correspondingly, reduced purchased power expenses and Bank and a commercial bank syndicate. FirstEnergy has guaranteed increased income taxes and net income for the Regulated the obligations of the operators of the TEBSA project, up to a Services segment. Financial data for these business segments maximum of $5.9 million (subject to escalation) under the are as follows:

project's operations and maintenance agreement.

49

SEGMENT FINANCIAL INFORMATION Regulated Competitive Reconciling Services Services Other Adjustments Consolidated (In millions) 2002 External revenues $ 8,794 $3,015 $ 330 $ 13 (a) $ 12,152 Internal revenues 1,052 1,666 478 (3,196) (b)

Total revenues 9,846 4,681 808 (3,183) 12,152 Depreciation and amortization 1,034 30 42 - 1,106 Net interest charges 591 46 367 (58) (b) 946 Income taxes 748 (85) (114) - 549 Income before cumulative effect of a change in accounting 997 (119) (192) - 686 Net income 997 (119) (249) - 629 Total assets 29,689 2,281 1,611 - 33,581 Total goodwill 5,611 285 - - 5,896 Property additions 490 403 105 - 998 2001 External revenues $ 5,729 $2,165 $ 11 $ 94 (a) $ 7,999 Internal revenues 1,645 1,846 350 (3,841) (b)

Total revenues 7,374 4,011 361 (3,747) 7,999 Depreciation and amortization 841 21 28 - 890 Net interest charges 571 25 74 (114) (b) 556 Income taxes 537 (23) (40) - 474 Income before cumulative effect of a change in accounting 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 2000 External revenues $ 5,415 $1,545 $ 1 $ 68 (a) $ 7,029 Internal revenues 1,222 2,114 306 (3,642) (b)

Total revenues 6,637 3,659 307 (3,574) 7,029 Depreciation and amortization 919 13 2 - 934 Net interest charges 558 10 19 (58) (b) 529 Income taxes 365 27 (15) - 377 Net income 563 39 (3) - 599 Total assets 14,682 2,685 574 - 17,941 Total goodwill 1,867 222 - - 2,089 Property additions 422 126 40 - 588 Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting (a)Prncipally fuel marketing revenues which arereflected as reductions to expenses for internal management reporting purposes (b)Elimination of intersegmenl transactions PRODUCTS AND SERVICES Energy Related Electricity Oil & Gas Sales and Year Sales Sales Services (In millions) 2002 $9,697 $620 $1,052 2001 6,078 792 693 2000 5,537 582 563 GEOGRAPHIC INFORMATION 2002 2001 Revenues Assets Revenues Assets (In millions)

United States $11,908 $32,823 $7,991 $32,187 Foreign countries' 244 758 8 5,165 Total $12,152 $33,581 $7,999 $37,352

'SeeNote 3 for discussion of future divestitures of international operations FirstEnergy 50

9. OTHER INFORMATION: FirstEnergy's revenues on the Consolidated Statements of The following financial data provides supplemental informa- Income include wholesale electricity sales revenues from the tion to the consolidated financial statements and notes previ- PJM ISO from power sales (as reflected in the table above) ously reported in 2001 and 2000: during periods when FirstEnergy had additional available power capacity. Revenues also include sales by FirstEnergy of power (A) Consolidated Statements of Cash Flows sourced from the PJM ISO (reflected as purchases in the table 2002 2001 2000 above) during periods when FirstEnergy required additional power to meet its retail load requirements and, secondarily, (In thousands) to make sales to the wholesale market.

Other Cash Flows from Operating Activities:

Accrued taxes $ 37,623 $ 8,915 $ (84) (D) Stock Based Compensation Accrued interest (25,444) 117,520 (8,853)

Retail rate refund obligation payments (43,016) - -

Stock-based employee compensation expense recognized for Interest rate hedge - (132,376) - the FE Programs' restricted stock during 2002, 2001 and 2000 Prepayments and other 132,980 (146,741) (21,975) totaled $2,259,000, $1,342,000 and $1,104,000, respectively.

All other 113,371 (97,882) 76,441 In addition, stock-based employee compensation expense of Total-Other $ 215,514 $(250,564) $ 45,529 $206,000, $1,637,000 and $1,646,000 during 2002, 2001 and 2000, respectively, was recognized for EDCP stock units (see Other Cash Flows From Investing Activities:

Note 5C - Stock Compensation Plans for further disclosure).

Retirements and transfers $ 29,619 $ 40,106 $(11,721)

Nonutility generation trusts investments 49,044 - (E) SFAS 115 Activity Nuclear decommissioning trust investments (86,221) (73,381) (30,704)

Aquila notes receivable (91,335) - -

All other investments included under Investments other than Other comprehensive income 8,745 (49,653) - cash and cash equivalents in the table in Note 2J - Supplemental Other investments (16,689) (116,285) (25,481) Cash Flows Information include available-for-sale securities, at All other 52,482 (34,313) (52,289) fair value, with the following results:

Total-Other $ (54,355) a233,526) $(120,195) 2002 2001 2000 (In thousands)

Unrealized holding gains $ 202 $2,236 $992 (B) Consolidated Statements of Taxes Unrealized holding losses 4,991 432 70 Proceeds from sales 7,875 25 66 2002 2001 2000 Gross realized gains 31 - 46 Gross realized losses - 3 -

(In thousands)

Accumulated Deferred Income Taxes at December 31:

Other consists of the following:

(F) Derivative Instruments Reclassificationsto Net Income Retirement Benefits $ (381,285) $ (133,282) $(60,491)

Oyster Creek securitization (Note 5H) 202,447 - - Comprehensive income includes net income as reported Purchase accounting basis differences (2,657) (147,450) - on the Consolidated Statements of Income and all other Sale of generation assets (11,786) 207,787 - changes in common stockholders' equity except those resulting Provision for rate refund (29,370) (46,942) - from transactions with common stockholders (see Note 51 -

All other (193,497) (203,809) 22,767 Comprehensive Income for further disclosure). Other compre-Total-Other $ (416,148) $ (323,696) $(37,724) hensive income (loss) reclassified to net income in 2002 and 2001 totaled $(9.9) million and $30.7 million, respectively.

These amounts were net of income taxes in 2002 and 2001 of (C) Revenues - Independent System Operator (ISO) $(6.8) million and $21.7 million, respectively. There were no Transactions reclassifications to net income in 2000.

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, 2002, are summarized as follows:

2002 2001 2000 (Inmillions)

Sales $453 $142 $315 Purchases 687 204 271 51

10. OTHER RECENTLY ISSUED ACCOUNTING STANDARDS 11.

SUMMARY

OF QUARTERLY FINANCIAL DATA (UNAUDITED):

FASB Interpretation (FIN) No. 45, "Guarantor's Accounting The following summarizes certain consolidated operating and Disclosure Requirements for Guarantees, Including results by quarter for 2002 and 2001.

Indirect Guarantees of Indebtedness of Others - an March31, June30, September30, December31, interpretation of FASB Statements No. 5, 57, and 107 Three Months Ended 2002 2002 2002 2002 and rescission of FASB Interpretation No. 34" (Inmillions, except per share amounts)

The FASB issued FIN 45 in January 2003. This interpretation Revenues (a) $2,762 0 $2,898 5 $3,451 2 $3,040 3 identifies minimum guarantee disclosures required for annual Expenses (a) 2,336 5 2,230 4 2,681 7 2,721 2 periods ending after December 15, 2002 It also clanfies that Income Before Interest and Income Taxes 4255 6681 7695 3191 providers of guarantees must record the fair value of those guar- Net Interest Charges 259 8 250 3 220 4 215 8 antees at their inception. This accounting guidance is applicable Income Taxes 80 9 184 5 238 8 45 3 on a prospective basis to guarantees issued or modified after Income Before Cumulative December 31, 2002 FirstEnergy does not believe that imple- Effect of Accounting Change 84 8 233 3 310 3 58 0 Cumulative Effect of Accounting mentation of FIN 45 vill be material but it will continue to Change (Net of Income evaluate anticipated guarantees Taxes) (Note 3) 31 7 - - (88 8)

Net Income (Loss) $ 1165 $ 2333 $ 3103 $ (308)

FIN 46, "Consolidation of Variable Interest Entities -

an interpretation of ARB 51" Basic Earnings (Loss) Per Share of Common Stock In January 2003, the FASB issued this interpretation of ARB Before Cumulative Effect of No 51, 'Consolidated Financial Statements. The new interpre- Accounting Change $ 29 $ 80 $ 1 06 $ 20 tation provides guidance on consolidation of variable interest Cumulative Effect of Accounting Change (Net entities (VIEs), generally defined as certain entities in which of Income Taxes) (Note 3) 11 - - (30) equity investors do not have the characteristics of a controlling Basic Earnings (Loss) Per financial interest or do not have sufficient equity at risk for the Share of Common Stock $ 40 $ 80 $ 106 $ (10) entity to finance its activities without additional subordinated Diluted Earnings (Loss) Per financial support from other parties This interpretation requires Share of Common Stock an enterprise to disclose the nature of its involvement with a Before Cumulative Effect of Accounting Change $ 29 $ 79 $ 1 05 $ 20 VIE if the enterprise has a significant vanable interest in the VIE Cumulative Effect of and to consolidate a VIE if the enterprise is the primary benefi- Accounting Change ciary VIEs created after January 31, 2003 are immediately sub- (Net of Income Taxes)

(Note 3) 11 - - ( 30) ject to the provisions of FIN 46 VIEs created before February 1, Diluted Earnings (Loss) Per 2003 are subject to this interpretation's provisions in the first Share of Common Stock $ 40 $ 79 $ 1 05 $ ( 10) interim or annual reporting period beginning after June 15, 2003 (our third quarter of 2003) The FASB also identified March31, June30, September30, December31, transitional disclosure provisions for all financial statements Three Months Ended 2001 2001 2001 2001(b) issued after January 31, 2003 (In millions, except per share amounts)

FirstEnergy currently has transactions with entities in Revenues $1,985 7 $1,804 1 $1,951 6 $2,257 9 Expenses 1,669 4 1,416 7 1,4121 1,816 0 connection with sale and leaseback transactions, the sale of Income Before Interest and preferred securities and debt secured by bondable property, Income Taxes 316 3 387 4 539 5 441 9 which may fall within the scope of this interpretation, and Net Interest Charges 126 3 121 0 1241 184 3 which are reasonably possible of meeting the definition of a Income Taxes 838 1204 181 3 890 VIE in accordance with FIN 46 Income Before Cumulative Effect of Accounting Change 106 2 146 0 2341 168 6 FirstEnergy currently consolidates the majority of these enti- Cumulative Effect of Accounting ties and believes it will continue to consolidate following the Change (Net of Income Taxes) adoption of FIN 46 In addition to the entities FirstEnergy is (Note 2J) (8 5) - - -

currently consolidating it believes that the PNBV Capital Trust, NetIncome $ 977 S 1460 $ 2341 $ 1686 reacquired a portion of the off-balance sheet debt issued in con- Basic Earnings Per Share of nection with the sale and leaseback of OE's interest in the Perry Common Stock Before Cumulative Effect of Nuclear Plant and Beaver Valley Unit 2, would require consoli- Accounting Change $ 49 $ 67 $ 107 $ 64 dation. Ownership of the trust includes a three-percent equity Cumulative Effect of interest by a nonaffiliated party and a three-percent equity Accounting Change (Net of Income Taxes) (Note 2J) (04) interest by OES Ventures, a wholly owned subsidiary of OE Full Basic Earnings Per Share of consolidation of the trust under FIN 46 would change the char- Common Stock $ 45 $ 67 $ 107 $ 64 acterization of the PNBV trust investment to a lease obligation Diluted Earnings Per Share of bond investment Also, consolidation of the outside minority Common Stock:

interest would be required, which would increase assets and lia- Before Cumulative Effect of Accounting Change $ 49 $ 67 $ 106 $ 64 bilities by $12 0 million Cumulative Effect of Accounting Change (Net of Income Taxes) (Note 2J) (04)

Diluted Earnings Per Share of Common Stock $ 45 $ 67 $ 106 $ 64 (a)2002 revenues and expenses related to trading activities reflect reclassitications as a result of implementing EITF Issue No 02-03 (see Note 2C - Revenues)

(b)Results for the former GPU companies are included from the November 7, 2001 acquisition date through December 31, 2001 FirstEnergy 52

12. PRO FORMA COMBINED CONDENSED FIRSTENERGY Under the purchase method of accounting, tangible and STATEMENTS OF INCOME (UNAUDITED): identifiable intangible assets acquired and liabilities assumed On November 7, 2001, the merger of FirstEnergy and GPU are recorded at their estimated fair values. The excess of the became effective pursuant to the Agreement and Plan of Merger, purchase price, including estimated fees and expenses related dated August 8, 2000 (Merger Agreement). As a result of the to the merger, over the net assets acquired (which included merger, GPU's former wholly owned subsidiaries, including existing goodwill of $1.9 billion), is classified as goodwill and JCP&L, Met-Ed and Penelec, (collectively, the Former GPU amounts to an additional $2.3 billion. The following table Companies), became wholly owned subsidiaries of FirstEnergy. summarizes the estimated fair values of the assets acquired Under the terms of the Merger Agreement, CPU shareholders and liabilities assumed on the date of acquisition.

received the equivalent of $36.50 for each share of GPU common stock they owned, payable in cash and/or FirstEnergy (In millions) common stock. CPU shareholders receiving FirstEnergy shares Current assets $ 1,027 received 1.2318 shares of FirstEnergy common stock for each Goodwill 3,698 share of CPU common stock they exchanged. The cash portion Regulatory assets 4,352 of the merger consideration was approximately $2.2 billion Other 5,595 and nearly 73.7 million shares of FirstEnergy common stock Total assets acquired 14,672 were issued to GPU shareholders for the share portion of the Current liabilities (2,615) transaction consideration. Long-term debt (2,992)

The merger was accounted for by the purchase method of Other (4,785) accounting and, accordingly, the Consolidated Statements Total liabilities assumed $(10,392) of Income include the results of the Former CPU Companies beginning November 7, 2001. The assets acquired and liabilities Net assets acquired pending sale 566 assumed were recorded at estimated fair values as determined Net assets acquired $ 4,846 by FirstEnergy's management based on information currently available and on current assumptions as to future operations.

The merger purchase accounting adjustments, which were During 2002, certain pre-acquisition contingencies and recorded in the records of GPU's direct subsidiaries, primarily other final adjustments to the fair values of the assets acquired consist of: (1) revaluation of GPU's international operations to and liabilities assumed were reflected in the final allocation fair value; (2) revaluation of property, plant and equipment; (3) of the purchase price. These adjustments primarily related to:

adjusting preferred stock subject to mandatory redemption and (1) final actuarial calculations related to pension and postretire-long-term debt to estimated fair value; (4) recognizing additional ment benefit obligations; (2) updated valuations of GPU's obligations related to retirement benefits; and (5) recognizing international operations as of the date of the merger; (3) estimated severance and other compensation liabilities. Other establishment of a reserve for deferred energy costs recognized assets and liabilities were not adjusted since they remain subject prior to the merger; and (4) return to accrual adjustments to rate regulation on a historical cost basis. The severance and for income taxes. As a result of these adjustments, goodwill compensation liabilities are based on anticipated workforce increased by approximately $290 million, which is attributable reductions reflecting duplicate positions primarily related to to the regulated services segment.

corporate support groups including finance, legal, communica- The following pro forma combined condensed statements tions, human resources and information technology. The work- of income of FirstEnergy give effect to the FirstEnergy/GPU force reductions represent the expected reduction of approxi- merger as if it had been consummated on January 1, 2000, mately 700 employees at a cost of approximately $140 million. with the purchase accounting adjustments actually recognized Merger related staffing reductions began in late 2001 and the in the business combination. The pro forma combined remaining reductions are anticipated to occur through 2003 condensed financial statements have been prepared to reflect as merger-related transition assignments are completed. the merger under the purchase method of accounting with The merger greatly expanded the size and scope of our electric FirstEnergy acquiring GPU. In addition, the pro forma adjust-business and the goodwill recognized primarily relates to the ments reflect a reduction in debt from application of the regulated services segment. The combination of FirstEnergy and proceeds from certain pending divestitures as well as the GPU was a key strategic step in FirstEnergy achieving its vision related reduction in interest costs.

of being the leading energy and related services provider in the region. The merger combined companies with the management, Year Ended December 31, employee experience and technical expertise, retail customer 2001 2000 base, energy and related services platform and financial resources (In millions, except per share amounts) to grow and succeed in a rapidly changing energy marketplace. Revenues $12,108 $11,703 The merger also allowed for a natural alliance of companies Expenses 9,768 9,377 with adjoining service areas and interconnected transmission Income Before Interest and Income Taxes 2,340 2,326 systems to eliminate duplicative costs, maximize efficiencies Net Interest Charges 941 977 and increase management and operational flexibility in order Income Taxes 561 527 to enhance operations and become a more effective competitor. $ 838 $ 822 Net Income Earnings per Share of Common Stock $ 2.87 $ 2.77 53

FirstEnergy Corp 2002 CONSOLIDATED FINANCIAL AND PRO FORMA COMBINED OPERATING STATISTICS (Unaudited) 2002 2001 2000 1999 1998 1997 1992 GENERAL FINANCIAL INFORMATION (Dollars inthousands)

Revenues $12,151,997 $ 7,999,362 $ 7,028,961 $ 6,319,647 $ 5,874,906 $ 2,961,125 $2,332,378 Net Income $ 629,280 $ 646,447 $ 598,970 $ 568,299 $ 410,874 $ 305,774 $ 253,060 SECRatio of Earnings to Fixed Charges 1 93 221 210 2 01 177 218 2 01 Net Property, Plant and Equipment $12,679,813 $12,428,429 $ 7,575,076 $ 9,093,341 $ 9,242,574 $ 9,635,992 $5,979,538 Capital Expenditures $ 903,606 $ 887.929 $ 568,711 $ 474,118 $ 305,577 $ 188,145 $ 252,592 Total Capitalization(a) $18,755,776 $21,339,001 $11,204,674 $11,469,795 $11,756,422 $12,124,492 $5,943,913 Capitalization Ratios (a)

Common Stockholders' Equity 37 9% 34 7% 41 5% 39 8% 37 9% 34 3% 40 57 Preferred and Preference Stock Not Subject to Mandatory Redemption 1.8 22 58 57 56 55 60 Subject to Mandatory Redemption 23 28 14 22 25 27 10 Long-Term Debt 5810 60 3 51 3 52 3 54 0 57 5 52 5 Total Capitalization 100 0% 100 0% 100 0% 100 0% 100 0% 100 0% 100 0%

Average Capital Costs Preferred and Preference Stock 7.50% 7 90% 7 92% 7 99% 8 01% 8 02% 7 32%

Long-Term Debt 6 56% 6 98% 7 84% 7 65% 7 83% 8 02% 8 53 COMMON STOCK DATA Earnings per Share (b)

Basic $2 34 $2 85 $2 69 $2 50 $1 95 $1 94 $1 70 Diluted $2 33 $2 84 $2 69 $2 50 $1 95 $1 94 $1 70 Return on Average Common Equity (b) 9.1% 12 9% 13 0% 12 7% 10 3% 11 0% 10 8%

Dividends Paid per Share $1 50 $1 50 $1 50 $1 50 $1 50 $1 50 $1 50 Dividend Payout Ratio (b) 64% 53% 56/ 60% 77% 77% 88%

Dividend Yield 4 5% 43% 4 8% 6 6% 46% 5 2% 65 Price/Earnings Ratio (b) 14.1 12 3 11 7 91 16 7 14 9 13 6 Book Value per Share $24 25 $25 29 $21 29 $20 22 $19 37 $18 71 $15 78 Market Price per Share $32.97 $34 98 $31 56 $22 69 $32 56 $29 00 $23 13 Ratio of Market Price to Book Value 136% 138% 148% 112% 168% 155% 147%

OPERATING STATISTICS (c)

Generation Kilowatt-Hour Sales (Millions)

Residential 31,937 32,708 32,519 32,616 31,220 30,653 28,076 Commercial 32,892 32,170 33,139 30,311 31,033 30,149 25,898 Industrial 32,726 33,024 31,140 30,422 36,683 36,531 33,202 Other 531 536 522 566 611 612 1,416 Total Retail 98,086 98,438 97,320 93,915 99,547 97,945 88,592 Total Wholesale 30,007 20,240 13,761 14,631 9,910 11,657 15,383 Total Sales 128,093 118,678 111,081 108,546 109,457 109,602 103,975 Customers Served Residential 3,868,499 3,833,013 3,798,716 3,767,534 3,735,308 3,708,760 3,550,043 Commercial 471,440 464,053 472,410 455,919 447,087 444,582 410,866 Industrial 18,416 18,652 18,996 19,549 19,902 21,028 22,033 Other 5,716 5,762 6,001 5,992 5,876 5,835 7,719 Total 4,364,071 4,321,480 4,296,123 4,248,994 4,208,173 4,180,205 3,990,661 Number of Employees 17,560 18,700 18,912 19,470 20,392 18,867 26,608 (a) 2001 capitalization includes approximately $1 4 billion of long-term debt (excluding long-term debt due to be repaid within one year) included in 'Liabilities Related to Assets Pending Sale' on the Consolidated Balance Sheet as of December31, 2001 (b) Before an accounting change in 2002 and 2001 and an extraordinary charge in 1998 (c) Reflects pro forma combined FirstEnergy and GPU statistics in the years 1998 to 2001 and pro forma combined Ohio Edison, Centenor and GPU statistics in years pnor to 1998 54

SHAREHOLDER INFORMATION Investor Services, Transfer Agent and Registrar Stock Investment Plan We act as our own transfer agent and registrar for all stock Shareholders and others can purchase or sell shares of issues of FirstEnergy and its subsidiaries. Shareholders wanting FirstEnergy common stock through the Company's Stock to transfer stock, or who need assistance or information, can Investment Plan. Investors who are not registered shareholders send their stock or write to Investor Services, FirstEnergy Corp., can enroll with an initial $250 cash investment. Participants 76 South Main Street, Akron, Ohio 44308-1890. Shareholders may invest all or some of their dividends or make optional also can call the following toll-free telephone number, which cash payments at any time of at least $25 per payment up is valid in the United States, Canada, Puerto Rico and the to $100,000 annually. To receive an enrollment form, Virgin Islands, weekdays between 8 a.m. and 4:30 p.m., Eastern contact Investor Services.

time: 1-800-736-3402. For Internet access to general share- Safekeeping of Shares holder information and useful forms, visit our Web site at Shareholders can request that the Company hold their shares http://www.firstenergycorp.com/ir. Former GPU registered of FirstEnergy common stock in safekeeping. To take advan-common shareholders should call Mellon Investor Services tage of this service, shareholders should forward their stock at 1-800-279-1228 for historical information on their certificate(s) to the Company along with a signed letter account prior to November 7, 2001. requesting that the Company hold the shares. They should Stock Listings and Trading also state whether future dividends for the held shares are Newspapers generally report FirstEnergy common stock under to be reinvested or paid in cash. The certificate(s) should the abbreviation FSTENGY, but this can vary depending upon not be endorsed, and registered mail is suggested. The shares the newspaper. The common stock of FirstEnergy and preferred will be held in uncertificated form and we will make certifi-stock of its electric utility subsidiaries are listed on the following cate(s) available to shareholders upon request at no cost.

stock exchanges: Shares held in safekeeping will be reported on dividend checks or Stock Investment Plan statements.

Company Stock Exchange Symbol Combining Stock Accounts FirstEnergy New York FE The Illuminating Company New York, OTC CVE If you have more than one stock account and want to Jersey Central New York JYP combine them, please write or call Investor Services and Ohio Edison New York OEC Pennsylvania Power Philadelphia PPC specify the account that you want to retain as well as the Toledo Edison New York, OTC TED registration of each of your accounts.

American Form 10-K Annual Report Dividends Form 10-K, the Annual Report to the Securities and Exchange Proposed dates for the payment of FirstEnergy common Commission, will be sent without charge by writing to stock dividends in 2003, which are subject to declaration David W. Whitehead, Corporate Secretary, FirstEnergy Corp.,

by the Board of Directors, are: 76 South Main Street, Akron, Ohio 44308-1890.

Ex-Dividend Date Record Date Payment Date Institutional Investor and Security Analyst Inquiries Institutional investors and security analysts should direct February 5 February 7 March 1 May5 May7 June 1 inquiries to: Kurt E. Turosky, Director, Investor Relations, August 5 August 7 September 1 330-384-5500.

November 5 November 7 December 1 Annual Meeting of Shareholders Direct Dividend Deposit Shareholders are invited to attend the 2003 Annual Meeting Shareholders can have their dividend payments automatically of Shareholders on Tuesday, May 20, at 10 a.m., at the deposited to checking and savings accounts at any financial John S. Knight Center in Akron, Ohio. Registered holders institution that accepts electronic direct deposits. Use of this of common stock not attending the meeting can appoint a free service ensures that payments will be available to you on proxy and vote on the items of business by telephone, the payment date, eliminating the possibility of mail delay Internet or by completing and returning the proxy card that or lost checks. To receive an authorization form, contact is sent to them. Shareholders whose shares are held in the Investor Services. name of a broker can attend the meeting if they present a letter from their broker indicating ownership of FirstEnergy common stock on the record date of March 25, 2003.

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FirstEnergy Officers FirstEnergy FirstEnergy FirstEnergy FirstEnergy Service Solutions Regional Corp. Company Corp. Officers H. Peter Burg H. Peter Burg Arthur R. Garfield Ohio Chairman and Chief Executive Officer President Chief Executive Officer Northern Region Anthony J. Alexander Douglas S. Elliott Dennis M. Chack Anthony J. Alexander President and Senior Vice President President President and Chief Chief Operating Officer Operating Officer Guy L. Pipitone Paul W. Allison Earl T. Carey Senior Vice President Vice President Richard H. Marsh* Senior Vice President Senior Vice President R. Joseph Hrach and Chief Financial Kevin J. Keough Vice President Eastern Region Officer Senior Vice President Thomas A. Clark and Regional President- Alfred G. Roth President Leila L. Vespoli* Central Ohio Vice President Senior Vice President Jeffrey A. Elser Carole B. Snyder Donald R. Schneider and General Counsel Vice President Senior Vice President Vice President Harvey L Wagner Trent A. Smith Vice President, Mary Beth Carroll Southern Region Vice President Vice President Controller and Ronald R Lantzy Chief Accounting Officer Harvey L. Wagner President Lynn M. Cavalier Vice President Vice President and David W. Whitehead Controller Corporate Secretary Central Region Mark T. Clark David W. Whitehead Kevin J. Keough Thomas C. Navin* Vice President Corporate Secretary President Treasurer Kathryn W. Dindo Paulette R. Chatman* Vice President and Assistant Controller Chief Risk Officer Western Region FirstEnergy James M. Murray Jeffrey R. Kalata* Michael J. Dowling Nuclear President Assistant Controller Vice President Operating Company Randy ScilIa* Terrance G. Howson Assistant Treasurer Vice President H. Peter Burg Pennsylvania Chairman and Edward J. Udovich* Ali Jamshidi Chief Executive Officer Eastern Region Assistant Corporate Vice President and Jack A. Kline Secretary Chief Information Officer Robert F.Saunders President President and

'Also holds the same Charles E. Jones Steven A. Schumacher Chief Nuclear Officer title with FirstEnergy Regional Vice President Vice President Service Company and - Operations Gary R. Leidich FirstEnergy Solutions Executive Vice President David C. Luff Weste, i Region Corp Vice President Lew W. Myers John E. Paganie Vice President, President Stephen E. Morgan Davis-Besse, and Vice President Chief Operating Officer Jacqueline L. Roth Vice President Stanley F. Szwed Mark B. Bezilla Vice President Vice President, Beaver Bradford F. Tobin Valley New Jersey Vice President and William R. Kanda Central Region Chief Procurement Vice President, Perry Donald M. Lynch Officer L. William Pearce President Harvey L. Wagner Vice President Vice President and Controller Northern Region Thomas M. Welsh Steven E. Strah Vice President President David W. Whitehead Stephen L. Feld Vice President, Vice President Corporate Secretary and Chief Ethics Officer Printed on recycled paper 0 56

FirstEnergy Board of Directors H. Peter Burg Anthony J. Dr. Carol A. William F. Robert B. Robert L. Russell W. John M.

Alexander Cartwright Conway Heisler, Jr. Loughhead Maier Pietruski Robert N. Paul J. Powers Catherine A. Robert C. George M. Carlisle A. H. Jesse T.

Pokelwaldt Rein Savage Smart Trost Williams, Sr.

H. Peter Burg, 56 Russell W. Maier, 66 Robert C. Savage, 65 Chairman of the Board and Chief President and Chief Executive Officer President and Chief Executive Officer of Executive Officer of FirstEnergy Corp. of Michigan Seamless Tube, South Lyon, Savage & Associates, Inc., Toledo, Ohio.

Director of FirstEnergy Corp. since 1997 Michigan. Member, Audit and Nuclear Member, Finance and Nuclear and of Ohio Edison from 1989-1997. Committees. Director of FirstEnergy Committees. Director of FirstEnergy Corp. since 1997 and of Ohio Edison Corp. since 1997 and of the former Anthony J. Alexander, 51 from 1995-1997. Centerior Energy from 1990-1997.

President and Chief Operating Officer of FirstEnergy Corp. Director of John M. Pietruski, 70 George M. Smart, 57 FirstEnergy Corp. since 2002. Chairman of the Board of Texas President of Sonoco-Phoenix, Inc., North Biotechnology Corporation, Houston, Canton, Ohio. Chair, Audit Committee; Dr. Carol A. Cartwright, 61 Texas. Chair, Compensation Committee; Member, Compensation Committee.

President, Kent State University, Kent, Member, Finance Committee. Director Director of FirstEnergy Corp. since 1997 Ohio. Chair, Corporate Governance of FirstEnergy Corp. since 2001 and of and of Ohio Edison from 1988-1997.

Committee; Member, Compensation the former GPU from 1989-2001.

Committee. Director of FirstEnergy Carlisle A. H. Trost, 72 Corp. since 1997 and of Ohio Edison Robert N. Pokelwaldt, 66 Admiral, United States Navy (Retired),

from 1992-1997. Retired, formerly Chairman of the Board former Chief of Naval Operations, and Chief Executive Officer of YORK Annapolis, Maryland. Member, William F. Conway, 72 International Corporation, York, Corporate Governance and Nuclear President of William F Conway & Pennsylvania. Member, Audit and Committees. Director of FirstEnergy Associates, Inc., Scottsdale, Arizona. Finance Committees. Director of Corp. since 2001 and of the former GPU Chair, Nuclear Committee; Member, FirstEnergy Corp. since 2001 and of the from 1990-2001.

Audit Committee. Director of former GPU from 2000-2001.

FirstEnergy Corp. since 1997 and of the Jesse T. Williams, Sr., 63 former Centerior Energy from 1994-1997. Paul J. Powers, 68 Retired, formerly Vice President of Retired, formerly Chairman of the Board Human Resources Policy, Employment Robert B. Heisler, Jr., 54 and Chief Executive Officer of Practices and Systems of The Goodyear Chairman of the Board and Chief Commercial Intertech Corp., Tire & Rubber Company, Akron, Ohio.

Executive Officer of KeyBank, Cleveland, Youngstown, Ohio. Chair, Finance Member, Corporate Governance and Ohio. Member, Compensation and Committee; Member, Compensation Nuclear Committees. Director of Corporate Governance Committees. Committee. Director of FirstEnergy FirstEnergy Corp. since 1997 and Director of FirstEnergy Corp. since 1998. Corp. since 1997 and of Ohio Edison of Ohio Edison from 1992-1997.

Robert L. Loughhead, 73 from 1992-1997.

Dr. Patricia K. Woolf, 68 Retired, formerly Chairman of the Board, Catherine A. Rein, 60 Consultant, Author, and Lecturer, in the President-and Chief Executive Officer President and Chief Executive Officer of Department of Molecular Biology at of Weirton Steel Corporation, Weirton, Metropolitan Property and Casualty Princeton University, Princeton, New West Virginia. Member, Audit and Insurance Company, Warwick, Rhode Jersey. Member, Corporate Governance Finance Committees. Director of Island. Member, Audit and and Nuclear Committees. Director of FirstEnergy Corp. since 1997 and Compensation Committees. Director of FirstEnergy Corp. since 2001 and of the of Ohio Edison from 1980-1997. FirstEnergy Corp. since 2001 and of the former GPU from 1983-2001.

former GPU from 1989-2001.

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Fr tIIwwfrI~Jy n W 76 SuhMain Street, Akron, Ohio 44308-1890 Sothnergycorpcorn PRESORTED STD US POSTAGE PAID AKRON, OHIO PERMIT NO 561 2002 Annual Report