ML20207E586

Annual Rept 1998 for Toledo Edison

ML20207E586
Person / Time
Site:	Beaver Valley
Issue date:	12/31/1998
From:	TOLEDO EDISON CO.
To:
Shared Package
ML20207E531	List: L-99-089, Forwards Annual Financial Repts,Including Certified Financial Statements,Of Dqe,Firstenergy Corp,Ohio Edison Co,Pennsylvania Power Co,Cleveland Electric Illuminating Co & Toledo Edison Co,Iaw 10CFR50.71(b) ML20207E552 ML20207E560 ML20207E576 ML20207E586 ML20207E590
References
NUDOCS 9906070082
Download: ML20207E586 (28)

Text

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ANNUAL REPORT 1998 1

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9906070082 990528 PDR ADOCK 05000334 I i= __

i THE TOLEDO EDISON COMPANY I

1998 ANNUAL REPORT TO STOCKHOLDERS

' The Toledo Edison Company is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. It provides electric service in an area of 2,500 square miles of northwestern Ohio, inc!uding the City of Toledo. It also provides electric energy at wholesale to other electric companies and to certain municipalities and a rural cooperative in its service area.

Contents Paae Consolidated Financial and Operating Statistics . .. . .. . 1 Management's Discussion and Analysis.. . . . . . . . . . . . . . . . . . . . . 2-6 Consolidated Statements of income . . . . .. . . . . . . 7 Consolidated Balance Sheets. . . . . . . . . . .. 8 Consolidated Statements of Capitalization . . . . . . . . . . . 9-10 Consolidated Statements of Common Stockholder's Equity.. .. .. .. 11 Consolidated Statements of Preferred Stock.. . . . . . . . 11 Consolidated Statements of Cash Flows. .. .. ....... ... .. . . . . . . . . . 12 Consolidated Statements of Taxes.. .... . .. . . . ... . . . . ......... .. . . . . 13 Notes to Consolidated Financial Statements.. . . . . . . . . . . . . . . . . . . . . . 14-25 Report of Independent Public Accountants... .. ... . .. . . . . . . . 26 I

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THE TOLEDO EDlSON COMPANY CONSOLIDATED FINANCIAL AND OPERATING STATISTICS i

Nov.8 Jan.1 i Dec. 31.1997 Nov. 7.1997 1995 1994 1998 1996 (Dollars in thousands)

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GENERAL FINANCIAL INFORMATION:

Operating Revenues S 957.037 N $ 772.707 $ 897.259 5 873.657 5 864.647 Operating income $ 180.261 S 19.055 1_12].2.32 5 156.815 j,,,,,168&QQ $ 179 499 inmme Before Extraordinary item 1_1Q6.382 5 7.616 5 41.769 5 57.289 $ 96.762 5 82.531 Netincome (Loss) N $ 7.616 $(150132) $ 57.289 $ 96 762 5 82.531 Eamings (Loss) on Common Stock .. . S 92.972 5 7.616 $(169.567) $ 40.363 5 78.510 $ 62.311 Net Utility Plant 51.168.216 51.170.806 5 2.079.742 M $ 2.204.717 Total Assets . j,gJ,jg],gj l.2258112 5 3428.175 5 3 532.714 5 3 546 628 CAPITALIZATION: ,

Common Stockholder's Equity $ 575,692 $ 531.650 $ 803,237 $ 762.877 $ 684.568 i Preferred Stock-Not Subject to Mandatory Redempbon 210,000 210,000 210.000 210,000 210.000 Subjectto Mandatory Redempton - 1,690 3,355 5,020 6.685 )

Lon9-Term Debt 1.083.666 1.210.190 1.051.517 1.119.294 1.241.331 Total Capitalizabon. . . . . .

M S1 953.530 M 52 097.191 52.142 584 CAPITALIZATION RATIOS:

Common Stockholder's Equity 30.8 % 27.2 % 38.8 % 36.4 % 32.0%

Preferred Stock-Not Subject to Mandatory Redempton 11.2 10.8 10.2 10.0 9.8 Subject to Mandatory Redemption. - 0.1 0.2 0.2 0.3 Long-Term Debt . ,,$$J ,f12 .,,,5Q.3 _$3.4 .57_S Total Capitalization. ,1gg,g% @ g/. 3% 3%

KILOWATT-HOUR SALES (Millions):

Residenbal 2.252 355 1,718 2.145 2.164 2.056 Coramercial 2.425 264 1.498 1,790 1,748 1,711 I' industria! 5,317 647 4.003 4,301 4.174 4,099 Othet. . . 63 70 413 488 500 499 Total Retail. .. 10.057 1,565 7,632 8,724 8,586 8.365 Total Wholesale 1.617 435 2.218 2 330 2.563 2.548 Total . .

11.674 2.000 9.850 11.054 11.149 QQ13 CUSTOMERS SERVED (Year End):

Residential 265,237 262.501 261,541 260.007 256.998 Commercia! .. . .. ... 31,982 29.367 27,411 26.508 25.921 industrial - 1.954 1,835 1,839 1.846 1,839 Other ... 359 347 2.136 2.119 1.858 Total 299.532 294.050 A9.2Z 290 480 286.616 Average AnnualResidentialkWh Usage . . 8,554 7.937 8.284 8.384 8,044 Peak Load.Megswatts 1.978 1,813 1,758 1,738 1.620 Number of Employees (Year-End). 997 1,532 1,643 1,809 1,887 l

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J THE TOLEDO EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS .

AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to l management that are subject to certain risks and uncertainties. These statements typically contain, but are not

limited to, the terms anticipate, potential, expect, believe, estimate and similar words. Actual results may differ l materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy market prices, legislative and regulatory changes, and the availability and cost of capital and other similar factors.

Results of Operations 1

We continued to take steps in 1998 to better position our Company as competition continues to expand in the electric utility industry. Investments were made in new information systems with enhanced functionality which also address Year 2000 application deficiencies. We also contributed to the 1998 cash savings of FirstEnergy Corp.

l (FirstEnergy) totaling $173 million. These savings were captured from initiatives implemented during the year in l connection with merger-related economies made possible by FirstEnergy's formation through the merger of our former parent company, Centerior Energy Corporation, and Ohio Edison Company on November 8,1997.

Financial results reflect the application of purchase accounting to the merger. This accounting resulted in fair value adjustments, which were " pushed down" or reflected on the separate financial statements of Centerior's direct subsidiaries as of the merger date, including our financial statements. As a result, we recorded purchase accounting fair value adjustments to: (1) revalue our nuclear generating units to fair value, (2) adjust long-term debt to fair value, (3) adjust our retirement and severance benefit liabilities, and (4) record goodwill. Accordingly, the post-merger financial statements reflect a new basis of accounting, and separate financial statements are presented for the pre-merger and post-merger periods. For the remainder of this discussion, for categories substantially unaffected i by the merger and with no significant pre-merger or post-merger accounting events, we have combined the 1997 pre-merger and post-merger periods and have compared the total for 1997 to 1998 and 1996.

Eamings on common stock were $93.0 million in 1998. Results for 1998 were adversely affected by sharp increases in the spot market price for electricity occasioned by a constrained power supply and heavy customer demand in the latter part of June 1998, combined with unscheduled generating unit outages, which resulted in spot market purchases of power at prices which substantially exceeded amounts recovered from retail customers Pre-merger camings on common stock in 1997 included an October 1997 write-off of certain regulatory assets. Excluding this write-off, pre-merger eamings on common stock were $22.3 million. For the seven-week post-merger period, eamings on common stock were $7.6 million. Eamings on common stock were $40.4 million in 1996.

After experiencing a decline in operating revenues in 1997, compared to the previous year, we achieved record operating revenues in 1998. The following table summarizes the sources of changes in operating revenues for 1998 and 1997 as compared to the prior year.

1 1990 199Z (In millions)

Increase in retall kilowatt-hour sales $68.2 S 14.4 Decrease in average retail price (8.8) (23.4)

Wholesale sales- (6.6) 7.8 l Other.. 8.9 r0.7) l Net Chanoe.. $61.7 $ (1.9)

Total kiiowatt-hour sales were down in 1998 from the prior year after establishing a new record high in 1997. The decline was due to a 39.1% decrease in sales to wholesale customers. Several generating unit outages, described later in this report, reduced energy available for sale to the wholesale market. Retail sales were up for all -

customer groups; residential, commercial and industrial with increases of 8.6%,9.5% and 9.6%, respectively, compared to 1997. Retail kilowatt-hour sales benefited from growth in the customer base, which added almost 5,500 new customers during the year. Expanded production at the new North Star BHP Steel (North Star) facility was a major contributor to the increase in industrial kilowatt-hour sales. In 1997, North Star was also a major contributor to industrial

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I sales, which experienced a 12.8% increase, compared to 1996. This increase was offset in part by reduced kilowatt- ,

hour sales to residential and commercial customers, which declined 3.3% and 0.5%, respectively.

l Operation and maintenance expenses increased in 1998 compared to the prior year due to increased fuel and purchased power costs, offset in part by a cecrease in nuclear operating costs. Most of the increase in fuel and 1' purchased power occurred in the second quarter and resulted from a combination of factors. in late June 1998, the midwestem and southem regions of the United States experienced electricity shortages caused mainly by record temperatures and humidity and unscheduled generating unit outages. During this period, Beaver Valley Unit 2 was out of service and the Davis-Besse Plant was removed from service as a result of damage to transmission facilities caused by a tomado. As a result, we pun.hased significant amounts of power on the spot market at unusually high prices, causing the increase in purchased power costs. An increase in purchased power costs also contributed to the 1997 increase in fuel and purchased power costs, compared to 1996, which was offset in part by lower fuel costs caused by l an increase in the mix of nuclear generation to coal-fired generation. Nuclear operating costs were lower in 1998, j compared to 1997, reflecting a decrease in costs at the Perry Piant offset in part by higher costs at the B.ever Valley l and Davis-Besse plants. Nuclear operating costs in 1997 were relatively unchanged from 1996 with increased operating l costs e' the Beaver Valley Plant substantially offset by lower operating costs at the Peny and Davis-Besse plants. Other operating costs were higher in 1997 than the previous year principally due to a $9.3 million severance and early retirement charge in the 1997 pre-merger period. In 1998, other operating costs increased slightly, compared to 1997, despite the absence of the severance and eariy redrement charge recorded in 1997 primarily due to increased fossil plant costs.

Lower depreciable asset balances resulting from the purchase accounting adjustment reduced depreciation in the 1998 and 1997 post-merger period. These reductions were partially offset by the amortization of goodwill recognized with the application of purchase accounting. Depreciation in the 1997 pre-merger period increased i principally due to changes in depreciation rates approved in the April 1996 Public Utilities Commission of Ohio (PUCO) j rate order.

interest income on trust notes acquired in connection with the Bruce Mansfield Plant lease refinancing (see Note 2), which began in June 1997, was the principal cause of an increase in other income in 1998 and the 1997 post-merger period. In the pre-merger period of 1997, interest income on the trust notes was substantially offset by merger related expenses. Total interest charges decreased in 1998 principally due to the amortization of net premiums associated with the revaluation of long-term debt in connection with the merger, which also contributed to the decrease in interest charges in the post-merger period of 1997, in the pre-merger period of 1997, interest charges were higher because interest on new secured notes and short-term borrowings for the Bruce Mansfield Plant lease refinancing exceeded the expense reduction from the redemption and refinancing of debt securities.

Preferred stock dividend requirements in 1998 were reduced by $3 mi!! ion and in 1997 were increased by

$3 million due to the declaration of preferred dividends as of the merger date for dividends attributable to the post-merger period (see Note 3c).

Capital Resources and I.lquidity We continue to actively pursue economic refinancings and optional redemptions to reduce the cost of debt and preferred stock, and improve our financial position, in 1998, we completed $26 million of optional redemptions. We reduced total debt by approximately $66 million during 1998. Our common stockholder's equity percentage of capitaltzation increased to 31% at December 31,1998 from 27% at the end of the previous year. The merger resulted in improved credit ratings in 1997, which have lowered the cost of new issues.The following table summarizes changes in credit ratings resulting from the merger:

Pre-Mercer Post-Meraer Standard Moody's Standard Moody's investors & Poor's investorT,

& Poor's Corporation Service. Inc. Corooration Service. Inc.

Firstmortgage bonds BB Ba2 BB+ Ba1 B+ B1 BB- Ba3 Subordinated debt b2 BB- b1 Preferred Stock B Excluding the effect of the Bruce Mansfield Plant lease refinancing, interest costs on long-term debt were reduced by approximately $4 million in 1998, compared to 1997. Through economic refinancings and redemptions of higher cost debt we have reduced the average cost of outstanding debt from 9.19% in 1993 to 8.25% in 1997 and 8.08% in 1998. We continue to streamline our operations, as evidenced by a 50% increase in FirstEnergy's customer / employee ratio, which has increased from 165 at the end of 1993 to 247 as of December 31,1998. Merger-related savings through consolidation of activities have contributed to these results.

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I Our cash requirements in 1999 for operating expenses, construchon expenditures and scheduled debt maturities are expected to be met without issumg additional securlbes. We have cash requirements of approximately

$475.2 million for the 1999-2003 period to meet scheduled maturities of long-term debt and preferred stock. Of that ,

amount. approximately $105.9 miubn applies to 1999.

. We had about $105.4 mdhon of cash and temporary investments and no short-term indebtedness on December 31,1998. Upon complebon of the merger, apphcahon of purchase accoun'ing reduced bondable property

-L such that we are not currently able to issue addthonal first mortgage bonds, except in connechon with ro6nancing.

Together with The Cleveland Electric liluminabng Company, as of December 31,1998, we had unused borrowing capability of $*30 indlion under a FirstEnergy revolving line of credit.

Our capital spending for the penod 1999-2003 is expected to be about $257 minion (excluding nuclear fuel), of which approximately $58 million apphes to 1999. Investments in additional nucieer fuel during the 1999-2003 period are estimated to be approximately $102 mHlion, of which about $9 million apphes to 1999. During the same periods, our nuclear fuel investments are awpar4=d to be reduced by approximately $120 million and $26 mahon, respechvely, as the nuclear fuelis consumed. Also, we have operstmg lease commitments not of trust cash receipts of approximately $360 milhon for the 1999-2003 period, of which approximately $70 million relates to 1999. We recover the cost of nucisar fuel consumed and operating leases through our electnc rates.

Interest Rate Risk Our evpaanre to fluctuations in market interest rates is metigated since a significant portion of our debt has fixed interest rates, as noted in the table below. We are subject to the inherent interest rate risks related to refinancing matunng debt by issuing new debt securities. As discussed in Note 2, our investment in the Shippingport Capital Trust effochvely reduces future lease obligabons, also reducing interest rate risk. Changes in the merket velue of our nuclear decommiserung trust fuads are recognized by malung a conosponding change to the decommissioning liability, as described in Note 1.

The table below presents pnncipal amounts and related weighted average interest rates by year of matunty for our investment portfono, debt obhgations and preferred stock with mandatory redemption provisions.

Thero- Fair 1999 2000 2001 2002 2003 after Total , Value cm ; 3,, - xj investments other than Cash and

. Cash Equivalents:

Fixedincome . $ 15 315 517 5 20 $19 $241 $ 327 8 334 Averana interent rata _ 7.8% 7.8% 78% 7.8% 7.8% 7.3% 7.4%

Long-term Deoc Fixed rate.. . ...... $104 $76 $30 $165 $98 $594 51,067 $1,143 Average interest rate ....... 7.4% 7.3% 9.2% 8.6% 7.9% 7.8% 7.9%

Varleble rate.. .. . $ 31 $ 31 $ 31 Averaoe interest rata.. 3.1% 3.1%

Preferred Stock $ 2 $ 2 5 2 Avernos dividend rate . 9.4% 9.4%

Outlook We face many wi-;2Oc challenges in the years ahead as the electric utility industry undergoes significant changes, including regulabon and the entrance of more energy suppliers into the marketplace. Retail wheeling, which would allow retaR customers to purchase electncity from other energy producers, will be one of those chauenges. The FirstEnergy. Rate Reduchon and Economic D ;A-is,; Plan provides the foundabon to position us to meet the chobenges we are facing by significantly reducing fixed costs and lowering rates to a more unpia:We level The plan was approved by the PUCO in January 1997, and initially maintains current base electnc rates through December 31,2005. The plan also revised our fuel recovery method. N As part of the regulatory plan, the base rate freeze is to be followed by a $93 million base rate reduction in 2006; interim reductions which began in June 1998 of $3 per month will increase to $5 per month per residential .

customer by July 1,2001. Total savings of $111 million are anticipated over the term of the plan for our customers. We have committed $35 miulon for economic d @isa and energy efficiency programs.

We have been authorized by the PUCO to ' recognize, for regulatory accounting purposes, additional depreciabon related to our generating assets and addibonal amortization of regulatory assets during the regulatory plan penod of at least $647 milhon more than the amounts that would have been recognized if the regulatory plans were not 4

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in effect. For regulatory purposes these additional charges wHl be rollected over the rate plan period. Our regulatory plan does not provide for full recovery of nuclear operations. AM.,4, regulatory assets representing customer

. . receivables for future income taxes related to nuclear assets of $295 mimon were written off ($192 mHlion not of income taxes) prior to consummation of the merger since we ceased apphcation of Statement of Financial Accounting Standards No. 71 (SFAS 71),

• Accounting for the Eflects of Certain Types of Regulation" for our nuclear opershons when implementation of the FirstEnergy regulatory plan became probable Based on the current reguistory erwwonment and our regulatory plan, we believe we will conbnue to be able to bill and conect cost-based rates relating to our nonnuclear operations. As a result, we will continue the L apphcation of SFAS 71. Hosever, changes in the regulatory environment appear to be on the honzon for electne utWhos in Ohio. As further discussed below, the Ohio legislature is in the encunaba stages of restructuring the State's electnc utility industry.' Although we believe that regulatory changes are possible in 1999, we cannot cunently estimate the ultimate impact.

At the consummabon of the merger in November 1997,'we recognized a fair value purchase accounhng adjustment, which decreased the canying value of our nuclear assets by approxxnately $842 million based upon cash flow models. The fair value adlustment to nuclear plant recognized for finanoel reporting purposes will ultimately sabsfy the asset mduction commitment contained in our reguistory plan.

We consnue to actively pursue the eneciment of fair legislebon cahng for demguisbon of Ohio's investor-owned electne utsty industry. In earty 1998, a despuladon proposal was intmduced, leading to the cmahon of a worldng group to recommend legisladon. As mquested by legisia6ve leadership, investor-owned uWhos introduced a

- deregulation plan with objectives to (1) treet au major stakeholders in Ohio's electric system fairly; (2) protect public schools and local govemments from revenue loss; and (3) agow utWties an cpoortunity to recover costs of govemment-mandated investments. The uWhos have submmed proposals, which inmrporate these objechves and also recognize the complexity of restructunng the industry. The overlying obgoceve is to do the job right the first time. Cunendy, the worldng group, compneed of legelauwe leaders, representa8ves of the electric utsty companies and other interested stakeholders are meeting to discuss and maid these proposais. Most receney, placeholder bWs containing statements of principle (that will be replaced by specific proposals as they are agreed upon) have been introduced. Legislative leaders have placed a high priority on enacting a deregulabon bill by mid-year.

The Clean Air Act Amendments of 1990, docussed in Note 5, require additional emeston reductions by 2000. We are pursuing cost-ellecbve comphance strategies for meeting these reduchon requirements.

On September 24,1998, the Federal E. Wsww -@ Protection A0ency issued a final rule estabhshing tighter nitrogen oxide emission requirements for. fossil fuel-fired utsty boilers in Ohio, Pennsylvania and twenty other eastem states, includmg the Detrict of Columina (see "Ein.v . -M Matters"in Note 5). Controls must be in place by May 2003, with required reductons schoved during the five-rnonth summer ozone season (May through September).

The new rule is awpartad to increase the cost of producing electricity; however, we beheve that we are in a better position than a number of other utuibes to achieve comphance due to our nuclear generabon capacity.

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We are aware of our potential involvement in the cleanup of several sites containing hazardous waste.

l I Although these sites are not on the Superfund Nabonal Priortties List, they are generauy being administered by various govemmental enuties in the same menner as they would be admmistered if they were on such a list. Allegations that we disposed of hazardous waste at these sites, and the amount involved are often unsubstanbated and subject to dispute.

Federal law provides that all "i--f_4 responsible parties" for a parbcular site be held liable on a joint and several basis. lf we were held liable for 100% of the cleanup costs of all the sites relened to above, the cost could be as high as

$101 milhon. However, we beheve that the actual cleanup costs will be substanbauy less than 100% and that most of the I_

other perbes involved are financelly able to contribute their share. We have accrued a $1.1 million liability as of December 31,1998, beood on ashmates of the costs of cisanup and our proporbonate responsibility for such costs. We I

l believe that the ultimate outcome of these matters will not have a matenal adverse effect on our financial condition, cash l flows or results of operations.

1. in connection with FirstEnergy's regulatory plan to reduce fixed costs and lower rates, we continue to

. take steps to restructure our operobons. FirstEnergy announced plans to transfer our transmission assets into a new subsidiary, American Transmission Systems, Inc., with the transfer expected to be finalized in 1999. The new

'* ' subsidiary represents a first step toward the goal of establishing or becoming part of a larger independent transmission company (TransCo). We believe that a TransCo better addresses the Federal Energy Regulatory l Commission's (FERC) stated transmission objectives of providing non-discriminatory service, while providing for l

' stroomlined and cost-efficient operation. In working toward the goal of forming a larger regional transmission entity, l-FirstEnergy, Amencen Electric Power, Virginia Power and Consumers Energy announced in November 1998 that they would prepare a FERC filing dunng 1999 for such a regional transmission entity. The entity would be designed j 5

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to meet the goals of reducing transmission costs that ro6 ult when transferring power over several transmission systems, ensuring transmission reliability and providing non-discriminatory access to the transmission grid.

Year 2000 Readiness .

y The Year 2000 issue is the result of computer programs being written using two digits rather than four i to identify the applicable year. Any of our pr) grams that have date-sensitive software may recognize a date using  ; l "00* as the year 1900 rather than the year 2000. Because so many of our computer functions are date sensitive, this could cause far-reaching problems, such as system-wide computer failures and ~ miscalculations, if no remedial action is taken.

We have developed a multLphase program for Year 2000 compliance that consists of an assessment of our systems and operations that could be affected by the Year 2000 problem; remediation or replacement of noncompliant systems and components; and testing of systems and components following such remediation or replacement. We have focused our Year 2000 review on three areas: contrahzed system apphcotons, noncentralized systems and relationships with third parties (including supphers as well as end-use customers). Our review of system readiness extends to systems involving customer service, safety, shareholder needs and regulatory obligations.

We are committed to toldng appropriate actions to elimmate or lessen negative effects of the Year 2000 issue on our operatons. We have w,; 21 an inventory of all computer systems and hardware including equipment with embedded computer chips and have determined which systems need to be converted or replaced to become Year 2000-ready and are in the process of remediating them. Based on our timetable, we expect to have all identified repairs, replacements and upgrades wi-C : j to achieve Year 2000 readiness by September 1999.

Most of our Year 2000 issues will be resolved through system replacement. Of our major centralized systems, the general ledger system and inventory management, procurement and accounts payable systems were replaced at the end of 1998. Our payroll system was enhanced to be Year 2000 compliant in July 1998. The customer service system is due to be replaced in mid-1999.

We have Gi-;L :j formal communcations with most of our key suppliers to determme the extent to which we are vulnerable to those third parties' failure to resolve their own Year 2000 problems. For suppliers having potential compliana problems, we are developmg anomate sources and services in the event such noncompliance occurs. We are also identifying areas regumng higher inventory levels booed on compliance uncertainties. There can be no guarantee that the failure of comparues to resolve their own Year 2000 issue will not have a material adverse effect on our business, financial condition and results of operatens.

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' We are using both intomal and extemal resources to reprogram and/or replace and test our software for Year 2000 modifications. Of the $17 million total project cost, approximately $14 million will be capitalized since those costs are attributable to the purchase of new software for total system replacements because the Year 2000 soluten comprises only a portion of the benefits resulting from the system replacements. The remaining $3 million will be expensed as incuned. As of December 31,1998, we have spent $11 million for Year 2000 capital projects and had expensed approximately $2 million for Year 2000-related maintenance activities. Our total Year 2000 project cost, as well as our estimates of the time needed to complete remedial efforts, are based on currently available information and do ret include the estimated costs and time associated with the impact of third party Year 2000 leeues.

We believe we are managing the Year 2000 issue in such a way that our customers will not experience any interruption of servce. We believe the most Hkely worst-case scenario from the Year 2000 issue will be disruption in power plant monitonng systems, thereby producing inaccurate data and potenbal failures in electronic switching mechanisms at transmission junctions. This would prolong localized outages, as technicians would have to manuaNy activate switches. Such an event could have a material, but currently undeterminable, effect on our financial results. We are developing w,W,ww.cy plans to address the effects of any' delay in becoming Year 2000 compliant and expect to have w 2,vw.cy plans w,-L $ by June 1999. .

c The costs of the project and the dates on which we plan to complete the Year 2000 modifications are based on management's best eshmates, which were derived from numerous assumphons of future events including the .

contmuod availabluty of certain resources, and other factors. However, there can be no guerantee that this project will l .

be completed as piarmed and actual results could differ materiaDy from the estimates. Specia factors that might cause j material dillerences include but are not limbed to, the avaHability and cost of trained personra the ability to locate and correct au relevant computer code, and simHar uncertainbes.

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THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME I

I For the Year Forthe Year Ended Ended December 31, Nov. 8 - Jan.1 - December 31, 1998 Dec. 31.1997 Nov. 7.1997 1996 (in thousands)

OPERATING REVENUES (1) . S 957.037 $122.669 $ 772.707 $897 259 OPERATING EXPENSES AND TAXES:

Fuel and purchased power 202,239 22,926 158,027 177,517 Nuclear operating costs - 160,080 29,372 138.559 168,458 Other operating costs . 166.935 20.608 145.174 157.785 Total operation and maintenance expenses 529.254 72.906 441,760 503.760 Provmon for depreciation and amortization ... 94,703 13,133 98,986 115.083 Generaltaxes ... . . . . . 86.661 13,126 77,426 89,647 income taxes . 66.158 4.449 31.253 31.954 Total operating expenses and taxes 776.776 ,,.1Q2fdd 649.425 740.444 OPERATING INCOME . 180.261 19.055 123,282 156.815 OTHER INCOME (EXPENSE) . 12.225 2.153 2.153 (4.585)

INCOME BEFORE NETINTEREST CHARGES . 192.486 21.208 125.43.5 . 152.230 NET INTEREST CHARGES: .

Interest on long. term debt 83,364 13,689 74.264 85.535 )

Allowance for borrowed funds used during construction. . . . . (1,273) (138) (259) (827)

Otherinterest expense . (1.187) 41 9 001 10.233 l Netinterest charges 85 904 13.592 83.666 94.941 INCOME BEFORE EXTRAORDINARY ITEM.. 106,582 7,616 41,769 57.289 l I

EXTRAORDINARYITEM (NET OF INCOME TAXES)(Note 1). -

- - (191.901) -

106,582 7,616 (150,132) 57,289 NET INCOME (LOSS).- - .

PREFERRED STOCK DMDEND REQUIREMENTS. -. 1$ 010 194$5 16.926 ,

i EARNINGS (LOSS) ON COMMON STOCK - . . . . L92F_2 $ 7.616 M M (1) includes electric sales to associated companies of $123.6 million, $17.7 million $98.5 million and $105.0 million in 1998, the November 8. December 31,1997 period, the January 1. November 7,1997 penod and 1996, respectively.

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

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THE TOLEDO EDISON COMPANY CONSOLIDATED BALANCE SHEETS At December 31. 1998 1997 *

(in thousands) .

ASSETS UTILITY PLANT:

In service . .. $1,757.364 $1.763.495 Less-Accumulated provision for depreciation . 626.942 619.222 1.130.422 1.144.273 Construction work in progress-Electric plant .. 26,603 19,901 Nuclear fuel. .. _ . 11.19' 6.632 37.790 26 533 1.168.210 1.170.806 OTHER PROPERTY AND INVESTMENTS:

Shippingport Capital Trust (Note 2) 310.762 312.873 Nuclear plant decomrnissioning trusts . . . . . . 102.749 85,956 Other . 3.656 3.164 417.167 401.993 CURRENT ASSETS:

Cash and cash equivalents. . _ 4.140 22,170 Receivables-Customers .. .

36,710 19.071 Associated companies 30.006 15.199 Other _ 2.316 2.593 Notes receivable frorn associated companies .. . 101,236 40.802 Materials and supplies, at average cost-Owned . .  ? e 31.892 Under consignment. y4 9.538 Prepayments and other ,. e.> 647 26.437 243.948 167.702 DEFERRED CHARGES:

Regulatory assets 417.704 442,724 Goodwill 474.593 514,462 Property taxes .. . 42.842 45.338 Other _ ... 4.295 15.127 939.434 1.017.651

$2.768.765 $2.758.152 CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Consolidated Statements of Capitalization):

Common stockholder's equity . . . . . S 575.692 $ 531,650 Freferred stock-Not subject to mandatory redemption . . . . 210.000 210.000 Subject to mandatory redemptbn .

- 1,690 Long. term debt _ 1.083.666 1.210.12Q 1.869.358 1.953 530 CURRENT LIABILITIES:

Currently payable long-term debt and preferrad stod . .

130,426 69,979 Accounts payable-.

Associated companies 34.260 21.173 Other . . . . . . 61,587 60,756 Accrued taxes .. 62.288 34,441 Accruedinterest. - 24.965 26,633 Other. . .. 14.862 22.603 328.388 235.585 DEFERRED CREDirS:.

Accumulated deferred income taxes .. 151.321 104,543 Accumulated deferred investment tax credits 40.670 43.265 Pensions and other postretirement benefits . 122.314 113.254 .

Other . . . . 256.714 307.975 571.019 569.037 COMMITMENTS, GUARANTEES AND CONTINGENCtES

. (Notes 2 and 5) . .. . . ..

$2.768.765 The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

8

I THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION At December 31. 1998 1997 (Dollars in thousands, exceptper share amounts) ,

COMMON STOCKHOLDER *S EQUITY:

Common stock, $5 par value, authanzad 60,000,000 shares-39,133,887 shares outstandr .. $ 195,670 $ 195.670 Premium on capital stock -

328.559 328.364 Retained eamings (Note 3A) 51.463 7.616 Total common stockholder's equity . ._ 575.692 531.650 Number of Shares Optional O G.^ r,,L w Redemotion Price 1999 1921 Per Share Anorenate PREFERRED STOCK (Note 3C):

Cumulative,5100 par value.

Authorized 3,000,000 shares Not Subject to Mandatory Redemption:

$ 4.25 160,000 160,000 $104.63 5 16,740 16,000 16.000 5 4.56 50,000 50,000 101.00 5,050 5,000 5,000 5 4.25 100,000 100.000 102.00 10.200 10.000 10.000

$ 8.32 . . 100.000 100.000 102.46 10,246 10.000 - 10,000

$ 7.76 150,000 150,000 102.44 15,366 15,000 15.000

$ 7.80 150.000 150,000 101.65 15.248 15,000 15,000

$10.00 190.000 190.000 101.00- 19 190 19.000 19.000 900.000 900.000 92.040 90.000 90.000 Cumulative, $25 par value-Authorized 12,000.000 shares Not Subject to Mandatory Redemption:

$ 2.21 1,000.000 1,000.000 25.25 25,250 25,000 25,000

$ 2.365. 1,400,000 1.400,000 27.75 38,850 35,000 35,000 Adjustable Series A . 1,200,000 1,200,000 25.00 30,000 30,000 30.000 Adjustable Series B -

1.200.000 1.200.000 25.00 30.000 30.000 30.000 4_800.000 4_800.000 124.100 120.000 120.000 Total not subject to mandatory redemption . M M 1.21tL14Q 210.000 210.000 Cumulative, $100 par value-Subject to Mandatory Redemption (Note 30):

$9.375 16,900 33.550 100.00 $ 1,690 1.690 3,355 Redemption within one year (1ggg) (1.665)

Total subject to mandatory l redemption 16.900 33.550 @ - 1.690 LONG. TERM DEBT (Note 3E):

First rnortgage bands: I 7.250% due 1999.. -. 85,000 85,000  !

7.500% due 2002 .

35.325

- 26,000 35,725

)

a 8.000% due 2003 -

7.875% due 2004 . 145.000 145.000 Total first mortgage bonds- 265.325 291.725 l

t l unsecured notes and debentures:

l 3,600 3,900  !

5.750% due 1999-2003. . .

1,000 1,000 10.000% due 2000 2010. - l 135.000 135.000 .

8.700% due 2002 ._ i Total unsecured notes and debentures 139.600 139.900 i

l

1 i

THE TOLEDO EDISON COMPANY 1

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont.)

i l

At December 31- 1998 1997  !

' ' #n thousands)

LONG-TERM DEBT (ConL):

l Secured notes:

i 7.940% due 1998 -

5.000 8.000% due 1998 . - -

7M 9.300% due 1998 . . . ~ . ~ - . . -

20 M 10.000% due 1998 ~ - . -

650

~ ,

7.720% due 1999 15,000 15,000 l 8.470% due 1999 - 3.500 3.500 7.190% due 2000 ... 45,000 45,000 1 7.380% due 2000 . 14,000 14,000 l

! 7.460% due 2000 . 16,500 16,500 i 7.500% due 2000. 100 100 8.500% due 2001 . . 8.000 8.000 9.500% due 2001 21.000 21.000 )

8.180% due 2002 - 17,000 17.000 1 8.620% due 2002 . 7,000 7,000 I 8.650% due 2002 5.000 5.000 l 7.760% due 2003 . 5,000 5.000 1

7.780% due 2003 . . . . . 1,000 1,000 .

! 7.820% due 2003 38,400

- . 38.400 i 7.850% due 2003 . . . 15.000 15,000 )

7.910% due 2003 . - .. 3,000 3,000 7.670% due 2004. 70.000 70.000 7.130% due 2007 30,000 30,000 3.050% due 2011' - . . . - . 31,250 31,250 s 8.000% due 2019. .. . .; 67.300 67,300 l 7.625% due 2020 - 45,000 45,000 7.750% due 2020. . . 54,000 54,000 9.220% due 2021. - - -

15,000 15,000 i 10.000% due 2021 15,000 15,000  !

7.400% due 2022 - 30,900 30,900 6.875% due 2023 .

. 20,200 20,200

)

4 7.550% due 2023 37,300 37,300 8.000% due 2023.. . . 49,300 49,300 6.100% due 2027 . . . . 10,100 10,100 5.375% due 2028 . . 3.751 -

Total secured notes. . 693.601 728.500 Capitallease obligations (Note 2) . 67_453 64.843 Net unamortized premium on debt . 46 423 53 536 Long-term debt due within one year (128.736) (68.314)

Totallong. term debt . 1.083JQQ 1.210.190 TOTAL CAPITALIZATION M $1.953 530

• Denotes variable rate issue with December 31,1998 interest rate shown.

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

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10

i THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY '

Comprehensive Premium Other Retained

• income (Loss) Number Par on Capital Paid-in Eamings ,

(Note 38) of Shares Value Stock Capital (Deficit)

(Dollars in thousands)

Balance, January 1,1996 39.133,887 $195,687 $ 481,057 $ 121,059 $ (34,926) 57,289 Netincome @ (3)

Unrealized loss on secunbes Cash dividends on oreferred stock.. (16.926)

Baiana, December 31,1996 .

39,133,887 195,687 481,057 121,056 5,437 Sf150.132) (150,132)

Net (loss)..

Cash dividends on preferred stock (20,973)

(17) (152,693) (121,056) 165,668 Purchase accounting fair value adjustment .

Net inw,T. .. $ 7.616 7.616 Balance. Demmber 31,1997 39,133,887 195,670 328,364 - 7,616 Purthase aca)unting fair value adjust nent 195 Netincome . g 106,582 (12,252)

Cash dividends on preferred stock (50.4831 Cash dih-e on cnmmon stock..

Balance. r__ce.7,ter 31.1998.. 39 133.887 $195.670 5 328.559 $ - $ 51.463 CONSOLIDATED STATEMENTS OF PREFERRED STOCK Not Subject to Subject to Mandatory Redemotion Mandatory Redemotion Number Par Number Par of Shares Value of Shares Value (Dollars in thousands)

Balance, January 1,1996 5,700,000 $210,000 66,850 $ 6,685 Redemptions-

$100 oar 59 375. (16.650) (1 665)

Balance, Demmber 31,1996 5,700,000 210,000 50,200 5,020 Redemptions-

$100 par $9.375 .

(16,650) (1,665)

Baiana, December 31,1997 ...... 5,700,000 210,000 33,550 3,355 Redemptions.

$100 oar $9 375- (16.6S0) (1.665)

Balance. December 31.1998.. 5.700.000 $210.000 16 900 5 1.690 The acosmpanying Notes to Consolidated Financial Statements are an integral part of these staterrents.

11

l THE TOLEDO EDISON COMPANY

, CONSOLIDATED STATEMENTS OF CASH FLOWS For the Year For the Year Ended Ended December 31, Nov. 8 - Jan.1 - December 31, 1998 Dec. 31.1997 Nov. 7.1997 1996 (In thousands)

CASH FLOWS FROM OPERATING ACTMTIES:

Netinmme (Loss) $ 106,582 5 7,616 $(150,132) $ 57,289 Adjustments to remndie net inmme to net cash from operabng achvibes:

Provision for depredabon and amorbzation . . 94,703 13.133 98.986 115,083 -

Nudear fusi cnd ;,a:r.e amoruzabon 24,071 5,316 30,354 33.294 Deferred inmme thes, net 50,570 3,113 (121,002) 17,919 investment tax cred!:s, net . - (2,595) (400) (3,601) (4,321)

Allowance for equity funds used during :onstrucbon - -

(61) (776) (1,045)

EhG.&ry item ..

- - 295,233 -

Remivables (32,169) 1,923 317 (9.610)

Net proceeds from acmunts receivable securibzation - - - 78,411 Matenals and supplies - (2.463) (4,430) 6,543 5.697 Acmunts payable 31,871 (12.989) 18.679 (9,737)

Other . (8.140) (29.443) 55.233 (1.509)

Net cash provided from (used for) operabng achvities 262.430 (16.222) 229.834 281.521 CASH FLOWS FROM FINANCING ACTMTIES:

New Finandng-Long-term debt 3,629 - 149,804 (260)

Redemptions and Repayments-Preferred stock - 1,665 - 1,665 1,665 Long-term debt 90.929 - 85,419 110.108 Short-term borrowings, net - - - 20,950 Dividend Payments-Commonstock . - . 50,483 - -

Preferred stock. . 16.378 4.150 12.589 16.926 Net ash provided from (used for) finandng activibes.. .. (155.826) (4.156) 50.131 (149.909)

CASH FLOWS FROM INVESTING ACTMTIES:

Property additions.. 45,870 6,568 36,680 47,961 Loans to assosated companies - 60,434 - - 81,817 Loan payments from assodated companies - (15,297) (25,718) -

Capital trustinvestments (2,111) (7,314) 320,187 -

Other ..

20.441 (6.585) 10.350 14.049 Net cash used for (provided from) investing achvities 124.634 (22.628) 341.499 143,827 Net increase (decrease)in cash and cash equivalents - (18,030) 2.250 (61,534) (12.215)

Cash and cash equivalents at Mginning of period . 22.170 19.920 81.454 93.669 Cash and cash equivalents at end of period $ 4.140 M $ 19.920 $ 81.454

$UPPLEMENTAL CASH FLOWS INFORMATION:

Cash Paid During the Penod-Interest (net of amounts capitalized) 1 000 $ 73.000 4

,. Income taxes . . 5 25.300 ,

i1 The accompanying Notes to Consolidated Finandal Statements are an integral part of these statements.

12

THE TOLEDO EDlSON COMPANY CONSOLIDATED STATEMENTS OF TAXES .

For the Year For the Year

• Ended Ended . i December 31, Nov. 8 - Jan.1 - December 31, 1998 Dec. 31.1997 Nov. 7.1997 1996 (In thousands)

GENERAL TAXES: $ 5,998 $ 40,495 $ 45,446 Real and personal property $ 44,993 5,826 28,590 33,793 State gross receipts . 35.114 5.065 818 4.444 5.689 Sooal security and unemployment - . .

4.719 1.489 484 3.897 Other . _ $ 13.126 5 77.426 $_E2.647 Total general taxes Laf.fdl PROVISION FOR INCOME TAXES:

Currently payable- $ 55,192 $ 13,582 Federa! . . $ 22.767 5 2.859 -

. 1.954 209 -

State *- .

55.192 13.562 24.721 3.068 Deferred, net- 17,919 50.337 3.096 (121.002)

Federal. - 17 - -

State

• _ .

233

_. 50.570 3 113 (121.002) 17 919 (2.595) (400) (3.601) (4.321) investment tax credit amortizabon Total provision forinmme taxes . , . j_72,ggi 5 5.781 $ (69.411) @

INCOME STATEMENT CLASSIFICATION OF PROVISION FOR INCOMETAXES: 5 31,253 $ 31.954 Operating inmme $ 66,158 $ 4,449 6.538 1,332 2,667 (4,774)

Otherincome - - (103.331) -

Extraordinary item ..

$ (69.411) M M

Total provision forinmme taxes . . ..

$ 5.781 RECONCILIATION OF FEDERAL INCCME TAX EXPENSE AT STATUTORY RATETOTOTAL PROVISION FORINCOME TAXES: $(219.543) 4 Book income before provision for locame taxes 17 $ 13.397 4 5 4,689 $ (76,840) 9 Federal income tax expense at statutory rate.

Increases (reductions)in taxes resulting from-(2,595) (400) (3,601) (4.321)

Amoritzauon of investment tax credits

- - 3.428 (3.742)

Deprecia6on .

Amortizabon of tax regulatory assets . 5.728 955 -

Amortza6on of goodwm _ ..

4,421 670 -

2.395 (133) 7.602 5 $79 Other, net.

172 02g $ 5.781 $ (69 411) 1_2L1BQ Total provision forinmme taxes .

ACCUMULATED DEFERRED INCOMETAXES AT DECEMBER 31: 5 612.000 Property basis differenms $195,948 $ 190.636 79.355 83.052 84.000 Deferred nudear expense -

(20.623) (17,431)

Deferred sale and leaseback costs .

(44,000)

Unamorttzed investment tax credits (19.515) (20.960)

(66,322) (108,156) (99,837)

Unused attemative minimum tax credits . . . . .

13.437

_(1L522) (22.5981 Other .

11Q2.529 M

Not deferred inmme tax liability ) 104 543

• For periods prior to November 8,1997, state lncome taxes are induded in the General Taxes sedion above. These amounts are not material and no restatement was made.

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

13

NOTES TO CONSOUDATED FINANCIAL STATEMENTS

, 1. _ StNARAARY OF SIGNIFICANT ACCOUNTING POLICIES:

The consolidated financial statements include The Toledo Edison Company (Company) and its 90%

owned subedary, The Toledo Edison Capital Corporation (TECC). The subsdary was formed in 1997 to make equity

- investments in a business trust in connection with the financing transachons related to the Bruce Mansfield Plant sale and l===ahad (see Note 2). The Cleveland Electnc IHuminating Company (CEI), an affiliate, has a 10% interest in TECC. All significant intercompany transachons have been ehenated. The Company is a wholly owned subsidiary of FirstEnergy Corp. (F;if.i iyy). Prior to the merger in November 1997 (see Note 7), the Company and CEI were the pnncipal operating subsderies of Centenor Energy Corporshon (Centerior). The merger was accounted for using the purchase method of accounhng in accordance with generaNy accepted accounting principles, and the appbcable effects were reflected on the separate financel statements of Centerior's direct subsidiaries as of the merger date. Accordingly, the post-merger financial statements reflect a new basis of accounting and pre-merger penod and post-merger period financial resuus (separated by a heavy black line) are presented. The Company fobows the accounting policies and prachoes prescribed by the Public Utuities Commssion of Ohio (PUCO) and the Federal Energy Regulatory Commesion (FERC). The preparagon of financial staterrents in w,L,nay with generally accepted accounting pnnciples requires management to make periodic eshmates and assumphons that affect the reported amounts of assets, liabilibes, revenues and expenses. Certain prior year amounts have been reclassified to conform with the current year presentadon.

REVENUES-The Company's pnncipal bueness is providing electnc service to customers in northwestem Ohio. The -

Company's retail customers are motored on a cycle basis. Revenue is recognized for unbilled electnc service through the end of the year.

Receivabies from customers include sales to residenhal, commercel and industrial customers located in the Company's service area and sales to wholesale customers. There was rn matenal concentrabon of recorvables at December 31,1998 or 1997, with respect to any parbcular segment of the Company's customers.

In May 1996, the Company and CEI began to seg on a daily basis substantiaNy all of their retaH customer accounts recorvable to Cen:arior Fundmg Corporshon (Centerior Funding), a wholly owned subsidiary of CEl, under an asset-backed securitizabon agreement which expires in 2001, in July 1996 Centerior Funding sw;E j a public sale of $150 million of receivables-backed investor cer#Rcates in a transaction that quaRfied for sale accounhng treatment.

REGULATORY Pl.AN.

F;reCr isy's Rate Reduction and Econome Development Plan for the Company was approved in January 1997, to be effective upon consummaton of the merger. The regulatory plan initially maintains current base electric rates for the Company through December 31,2005. At the end of the regulatory plan period, the Company's bene rates wiH be reduced by $93 muhon (approximately 15 percent below current leveis). The regulatory plan also revised the Company's fuel cost recovery method. The Company formerly recovered fuel-related costs not otherwise included in base rates from retaN customers through a separate energy rate. In accordance with the regulatory plan, the Company's fuel rate wiR be frozen through the regulatory plan period, subject to limited penodic adjustments. As part of the regulatory plan, transition rate credits were implemented for customers, which are expected to reduce operating revenues for the Company by approximately $111 minion during the regulatory plan period All of the Company's regulatory assets related to its nonnuclear operations are being recovered under

, provissons of the regulatory plan (see "Ragulatory Assets"). The Company recognized a fair value purchase accounting adjustment to reduce nuclear plant by $842 muhon in connechon with the F;is,;Cc-igy merger (see Note 7); that fair value aquelmont recognized for financial reporting purposes wiH ultimately sabsfy the $647 million asset reduction

,- commitment contained in the regulatory plan. For regulatory purposes, the Company will recognize the $647 million of

^

accelerated amortizabon over the regulatory plan period.

Applicebon of Statement of Financial Accounting Standards (SFAS) No. 71," Accounting for the Effects of

. Certam Types of Regulabon" (SFAS 71), was discontinued in 1997 with respect to the Company's nuclear operations.

The Company's not assets included in utinty plant relating to the operations for which the application of SFAS 71 was discontinued were $579 milhon as of December 31,1998.

14

7

.. UTIUTY PLANT AND DEPRECIATION-

' Utility plant renects the original cost of construction (except for the Company's nuclear generating units ,

.which were adjusted to fair value in 1997), including payroH and related costs such as taxes, employee benoo admastrative and general costs, and interest oosts.

The Company provides for depreciaton on a straight-line basis at various rates over the estimated .Eve

• property included in plant in service. The annualized composite rate was approximately 3.4% (reRectin asset fair value adptment r*=r=w above) and 2.6% in 1998 and the post-merger period in 1997, is.p ddj. In its AprH 1996 rate order, the PUCO approved depreciation rates for the Company of 2.95% h nuclear prope

' for nonnuclear property.

Annual depreciabon expense includes approximately $9.8 miHon for future (+:- ,mff-#s costs -

appicable to the Company's ownership interests in these nuclear generstmg units. The Company's share obligation to decommission these units is approximately $348 miluon in current doners and (using a 4.0%

rate) approximately $896 mHuon in future donors. The asumated obliga i+~+,,,, -_ ' -as work begins. The Cornpeny has recovered approximately $91 mi on for decommissoning t electric rates from customers through December 31,1998. If the actual costs of Umw.im1 ' -Ws the units exceed funds accumuisted from investing amounts recovered from customers, the Compely expects that additional amoun be recoverable from its customers. The Company has approximately 502.7millon invested ,vc4;csin extemal i+ - ,m . ' as trust funds as of December 31,1998. Eamings on these funds are romvested with a w.

~-#s liability.The Company has also recognized an eshmated liability of approximately $8.7 incrosse to the C+1 ..- ' -Ws of nuclear ennchment faciuties operated rn;ilion at December 31,1998 reisted to decontaminaten and G+ s , f by the United States Department of Energy (DOE), as required by the Energy Policy Act of 1992.

The Financial Accounting Standards Board (FASB) issued a proposed accounting standard for nuclear J+ -: mf _ ~ -is costs in 1996, if the standard is adopted as proposed: (1) annual provisions for (+x- mM-Wis could increase; (2) the not present value of estimated decommissioning costs could be recorded as a liabHity;

' as trusts could be reported as investment income. The FASS subsequently income from the extemal deco.. .

expended the scope of the proposed standard to include other closure and removal obugations related to assets. A revised proposal may be issued by the FAS8 in 1999.

CORARAON OWNERSHIP OF GENERATING FACIUTIES-The Company, CEl, Duquesne Light Company, Ohio Edison Company (OE) and its wholly owned PCO).

ei*duasy, Pennsylvania Power Company (Penn), constitute the Central Area Power Coordinabon Group (CA The CAPCO companies own and/or leewe, as tenants in common, various power generating faciubes. Eac compenses is obhgated to pay a share of the costs associated with anyjointly owned facMity in the sam interest. The Company's portion of operabng expenses associated with jointly owned facilibes is included in th corresponding operating expenses on the Consondated Statements of income The amounts reRected on Consolidated Balance Sheet under utility plant at December 31,1998 include the fonowing.

Construeron Owriorship/

Utlitty Accumulated Provision for Workin Leeschold Plant Irearmat in th E_

^--

Preareas

z Units (hr mMone)

Bruce Manseeld 51.1 18.61 %

5 39.4 511.1 Unile 2 and 3 0.7 19.91 %

57.7 3.3 Beaver Vagey Unit 2 - 6.2 48.62 %

202.5 4.8 Davis.Besse. 16.4 4.0 19.91 %

h 332.7 1ste '4 1356 112.0 Total The Brum Mansneld Plant and Beaver Valley Unit 2 are being leased through sale and leaseback transactions (see Note 2) and the above-related amounts i. ping construction expenditures subsequent to th transaction.

i

'15

r NUCLEAR FUEL.

_ The Company leases its nucieer fuel and pays for the fuel as it is consumed (see Note 2). The Company amortizes the cost of nuclear fuel based on the rate of consumphon.The Company's electric rates include amounts for the future disposal of spent nucieer fuel bened upon the payments to the DOE.

INCOME TAXES-Deteds of the total provision for income taxes are shown on tha Consolidated Statements of Taxes.

Defened income taxes result from timing dWorences in the i ,v,4;i,r. of revenues and expenses for tax and accounung purposes, investment tax credits, which were deferred when utuired, are being amortized over the recovery period of the reisted property. The liability method is used to account for defened incorre taxed. Deferred income tax liabilities reisted to tax and accounung basis differences are recogruzed at the statutory income tax rates in effect when the liebdities are awpacend to be paid. Abometive mrumum tax credits of $66 million, which may be camed forward

)

indennuely, are available to reduce future federal income taxes. Since the Company became a wholly owned subsidiary of FrstEnergy on November 8,1997, the Company is included in F .;T.r rg/s consohdated federal income tax retum.

The conemated tax liebdity is allocated on e " stand-alone" company basis, with the Company recognizing any tax losses or credits it contributed to the consolidated retum.

RETIREMENT BENEFITS-Centenor had sponsored joindy with the Company, CEI and Centenor Serwce Company (Service Company) a in,. ,,,;, ,atory penson plan (Centenor Pension Plan) which covered au employee groups. Upon retroment, employees recorve a monthly pension generely based on the length of sorwce in 1998, the Centenor Penson Plan was merged into the FestEnergy pensen plans. In connechon with the OE Contenor merger, the l Company recorded fair value purchase accounnno adjustments to recognize the not gain, prior service cost, and not transition asset (obligation) associated with the pensen and ---C ...a benefit plans. The assets of the penson plans consist pnmergy of common stocks, United States govemment bonds and corporate bonds

' The Company provides a minsnum amount of r., ,,,;,.,atory life insurance to retired employees in addition to optonal contributo y insurance. HesRh care beneAts, v.hich include certain employee deductibles and copsyments, are also avedeble to retired employees, their dependents and, under certem circumstances, their survivors.

The Company pays insurance premiums to cover a porten of these benents in excess of set limits; all amounts up to the l limits are paid by the Company. The Company recognizes the expected cost of prowdmg other postrobrement benents to employees and their benonciones and covered dependents from the time employees are hired until they become eligible to receive those beneks.

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The following sets forth the funded status of the FirstEnergy plans in 1998 and the former Centerior plans in 1997 and amounts recognized on the Consolidated Balance Sheets as of December 31:

s Other Pension Benefita Pu.Lah.a nt Benefits 1998 1997 1998 1997 (in millions)

Change in benefit obligation:

Benefit obliganon as of January 1' $1.327.5 8 395.0 $ 534.1 $ 211.9 Service cost . 25.0 13.4 7.5 2.3 Interest cost . 92.5 31.5 37.6 16.3 Plan amendments... - .. 44.3 7.1 40.1 -

Early retirement program expense - - 27.8 - -

Actuartalloss - . - 101.6 74.8 10.7 51.9 Benefits oaid .. (90 B) (16.2) (28.7) (15 91 Bene 6t obMstion as of December 31.. 1 500.1 533 4 601.3 266.5 Change in plan assets:

Fair value of plan assets as of January 1* 1.542.5 420.8 2.8 -

Actual retum on plan assets 231.3 57.3 0.7 -

Company contribution . . .

- - 0.4 -

Benefits oaid.. (90 8) (16 2) - -

Fair value of otan assets as of December 31.. 1.683.0 461 9 39 -

Funded status of plan * .. . 182.9 (71.5) (597.4) (266.5)

Unrecognized actuarialloss (gain) . . - . (110.8) 3.0 30.6 -

Unrecognized prior service cost 63.0 - 27.4 -

Unrecoonized net transition oblication (asset) (18.0) - 129 3 -

Precaid (accrued) benefit cost.. $ 117 1 5 (68 5) $!4101) $(266 5)

Assumptions used as of December 31:

Otscount rate... ..... 7.00 % 7.25 % 7.00 % 7.25 %

Expected long-term retum on plan assets . 10.25 % 10.00 % 10.25 % 10.00 %

Rate of compensation increase . . 4.00 % 4.00 % 4.00 % 4.00 %

• 1998 beginning balanms represents 1998 merger of Centenor and OE plans into FirstEnergy plans.

The Consolidated Balance Sheet classification of Pensions and Other Postretirement Benefits at December 31,1998 and 1997 includes the Company's share of the net pension liability of $17.3 million and $18.1 million, respectively; and the Company's share of the accrued postretirement benefit liability of $105.0 million and $95.2 million, respectively. ,

Net pension and other postretirement benefit costs for the three years ended December 31,1998 (FirstEnergy plans in 1998 and Centerior plans in 1997 and 1996) were computed as follows:

Pensbn Benefits Other Postretirement Beneffts 1997 1997 Nov.8 Jan.1 Nov.8 Jan.1 1998 Dec. 31 Nov. 7 1996 1998 Dec.31 Nov. 7 1996 (In mimons)

Service cost. $ 25.0 $ 2.3 511.1 $ 12.6 57.5 $ 0.5 51.8 $ 2.1 Interest cost 92.5 6.1 25.4 27.9 37.6 2.8 13.5 17.8 Expected retum on plan assets (152.7) (7.7) (38.0) (43.0) (0.3) -

Arnorttzat6on cf transition obligation (asset) (8.0) -

(3.0) (3.5) 9.2 - 6.4 7.5 Arnorttzation of pnor service cost 2.3 - 1.1 1.3 (0.8) -

6.vy und not actuartalloss (gain) (2.6) -

(0.5) (2.7) - -

(0.9)

Voluntary earty retrement program exoense. - 23 0 48 - - - -

Net beneftt cost.. $ M3 5) $23 7 $ 09 $ (7 4) $ 53 2 $3.3 $20 8 $2r k .

j Company's snare of total plan costs - $ (11) $ 57 $ 35 $ (2 4) $ 7.5 $15 $ 89 $ 90 The FirstEnergy plans' health care trend rate assumption is 5.5% in the first year gradually decreasing to 4.0% for the year 2000 and later. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. An increase in the health care trend rate assumption by one percentage point would 17 l l

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increase the t-'al service and interest cost components by $4.0 rnillion and the postratirement benefit obligation by

$68.1 miHion. A decrease in the same assumption by one percentage point would decrease the total service and interest cost components by $3.2 million and the postratirement benefit obligation by $55.2 million.

TRANSACTIONS WITH AFFILIATED COMPANIES-

. Operating revenues, operating expenses and interest charges include amounts for transactions with affiliated companies in the ordinary course of business operations.

The Company's transactions with CEI and the other FirstEnergy operating subsidiaries (OE and Penn) from the November 8,1997 merger date are primarily for firm power, interchange power, transmission line rentals and jointly owned power plant operations und construction (see Note 7). Beginning in May 1996, Centerior Funding began serving as the transferor in connection with the accounts receivable securitization for the Company and CEl.

The Sennce Company (formerty a wholly owned subsidiary of Centerior and now a wholly owned subsidiary of FirstEnergy) provided support services at cost to the Company and other affiliated companies. The Service Company billed the Company $39.0 million, $13.9 million, $51.5 million and $59.8 million in 1998, the November 8-December 31,1997 period, the January 1-November '7,1997 period and 1996, respectively, for such services.

SUPPLEMENTAL CASH FLOWS INFORMATION.

i All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets. The Company reflects temporary cash investments at cost, which approximates their fair. market value. Noncash financing and investing activities included capital lease  ;

transactions amounting to $28 million, $2 million, $12 million and $32 million in 1998, the November 8-December 31, i 1997 period, the January 1-November 7,1997 period and 1996, respectively.

l All borrowings with initial maturities of less than one year are defined as financial instruments under generally accepted accounting principles and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following sets forth the approximate fair value and related canying amounts of all other long-term debt, preferred stock subject to mandatory redemption and inves+ments other than cash and cash equivalents as of December 31:

1998 1997 j Canying Fair Carrying Fair  ;

Value Value Value Valug, i (in mHHons) l Long4erm debt.. . . .. $1.098 $1.174 $1,160 $1.218 j Preferred stock .. $ 2 $ 2 5 3 $ 3 Investments other than cash and cash equivalents:

Debt secunties

-(Maturing in more than 10 years) . . $ 308 $ 301 $ 295 $ 303 Equity securttles .. . 3 3 3 3 All other - 103 105 86 85

$ 414 $ to9 $ 384 $ 391 l

The canying value of long-term debt was adjusted to fair value in connection with the OE-Centerior merger and reflects the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by a corporation with credit ratings similar to the Company's ratings.

The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on

.- financial instruments with similar characteristics and terms, investments other than cash and cash equivalents include decommissioning trusts investments. Unrealized gains and losses applicable to the decommissioning trusts have been recognized in the trust investments with a corresponding change to the decommissioning liability. The other debt and

. equity securities referred to above are in the heid-to-maturity category. The Company has no securities held for trading

! purposes.

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F REGULATORY ASSETS.

The Company recognizes, as regulatory assets, costs which the FERC and PUCO have authorized for .

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recovery from customers in future periods. Wrthout such authorization, the costs would have been charged to income as incurred. All regulatory assets related to nonnuclear operations are being recovered from customers under the l j

Company's regulatory plan. Based on the regulatory plan, at this time, the Company believes it will continue to be able '

to bill and collect cost-based rates (with the exception of the Company's nuclear operations as discussed below);

• accordingly, it is appropriate that the Company continues the application of SFAS 71 in the foreseeable future for its nonnuclear operations.

The Company discontinued the application of SFAS 71 for its nuclear operations in October 1997 when implementation of the regulatory plan became probable. The regulatory plan does not provide for full recovery of the Company's nuclear operations. In accordance with SFAS No.101,

• Regulated Enterprises - Accounting for the Discontinuation of Application of SFAS 71," the Company was required to remove from its balance sheet all regulatory assets and liabilities related to the portion of its business for which SFAS 71 was discontinued and to assess all other assets for impairment. Regulatory assets attributable to nuclear operations of $295.2 million ($191.9 rni!! ion after taxes) were wntten off as an extraordinary item in October 1997 The regulatory assets attributable to nuclear operations written off represent the net amounts due from customers for future federal income taxes when the taxes become payable, which, under the regulatory plan, are no longer recoverable from customers. The remainder of the Company's business continues to comply with the provisions of SFAS 71. All remaining regulatory assets of the Company will continue to be recovered through rates set for the nonnuclear portion of its business. For financial reporting purposes, the net book value of the nuclear generating units was not impaired as a result of the regulatory plan.

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

1998 1997 (in millions)

Nuclear unit expenses.. .... . $200.1 $207.4 Rate stabilization program deferrais 164.1 172.0 Sale and leaseback costs 41.3 40.2 Loss on reacquired debt .. 20.0 21.1 Other- (7.8) 2.0 Totat . $417.7 $442.7

2. LEASES: ,

The Company leases certain generating facilities, nuclear fuel, certain transmission facilities, office space and other property and equipment under cancelable and noncancelable leases.

The Company and CEl sold their ownership interests in Bruce Mansfield Units 1,2 and 3 and the Company sold a portion of its ownership interest in Beaver Valley Unit 2. In connection with these sales, which were completed in 1987, the Company and CEI entered into operating leases for lease terms of approximately 30 years as co-lessees. During the terms of the leases, the Company and CEI continue to be responsible, to the extent of their combined ownership and leasehold interest, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. The Company and CEI have the right, at the end of the respective basic lease terms, to renew the leases. The Company and CEI also have the right to purchase the facilities at the expiration of the basic lease term or renewal term (if elected) at a price equal to the fair market value of the facilities.

As co-lessee with CEl, the Company is also obligated for CEl's lease payments. If CEl is unable to make its payments under the Bruce Mansfie!d Plant lease, the Company would be obligated to make such payments. No such payments have been made on behalf of CEl. (CEl's future minimum lease payments as of December 31,1998 were approximately $1.1 billion.)

The Company is selling 150 megawatts of its Beaver Valley Unit 2 leased capacity entitlement to CEl.

Operating revenues for this transaction were $98.5 million, $16.8 million, $87.4 million and $99.4 million in 1998, the November 8-December 31,1997 period, the January 1-November 7,1997 period and 1996, respectively. This safe is expected to continue through the end of the lease period. The future minimum lease payments through 2017 associated with Beavor Valley Unit 2 are approximately $1.1 billion.

Nuclear fuel is currently financed for the Company and CEI through leases with a special-purpose corporation. As of December 31,1998, $156 million of nuclear fuel ($67 million for the Company) was financed under a 19

I lease financing arrangement totaling $175 million ($60 million of intermediate-term notes and $115 million from bank j

credit arrangements). The notes mature from 1999 through 2000 and the bank credit arrangements expire in September 2000. Lease rates are based on intermediate. term note rates, bank rates and commercial paper rates.

Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of income. Such costs for the three years ended December 31,

1998 are summartzed as follows

Nov. 8 - Jan.1 -

1998 Dec.31.1997 Nov. 7.1997 1996 (in mHons)

Operatingleases interest eiernent $ 59.2 $28.0 $ 57.4 5 82.5 Other. ._ 44.9 13.5 23.1 42.6 Capitallan Interestelement. . 4.9 1.0 6.0 7.5 Other.. - 25 1 5.3 30 4 38.6 Total rentals.. $134.1 $47 8 $116 9 $171.2 The future minimum lease payments as of December 31,1998 are:

c _;. i-Capital 1.mese Capital 8- --

"r..._ L Trust Not (in mMons) 1999 .. $28.7 $ 106.5 $ 36.3 $ 70.2 2000 . . 19.4 104.8 35.4 69.4 2001 . 12.0 108.0 36.4 71.6 2002 . 5.8 111.0 37.9 73.1 2003 . . 1.9 111.7 36.0 75.7 Years thereafter.. 04 1.318 4 321.4 997.0 Totalminimum lease payments 68.2 11JgQ 4 j,gg3 4, j,MgL2 Interest nortion.. 8.3 j Present value of not minimum lease payments 59.9 I aan current nortion .. 24.5 Noncurrent oo tion .. $35 4 The Company and CEI refinanced high-cost fixed obligations related to their 1987 sale and leaseback transaction for the Bruce Mansfield Plant through a lower cost transaction in June and July 1997. In a June 1997 offering (Offering), the two companies pledged $720 milhon aggregate principal amount ($145 million for the Company and $575 million for CEI) of first mortgage bonds due in 2000,2004 and 2007 to a trust as security for the issuance of a j like principal arnount of secured notes due in 2000,2004 and 2007. The obligations of the two companies under these secured notes are joint and several. Using available cash, short-term borrowings and the net proceeds frora the Offering, the two companies invested $906.5 million ($337.1 million for the Company and $569.4 million for CEI) in a business trust, in June 1997. The trust used these funds in July 1997 to purchase lease notes and redeem all l

$873.2 million aggregate principal arnount of 10-1/4% and 11-1/8% secured lease obligation bonds (SLOBS) due 2003 l and 2016. The SLOBS were issued by a speciayxJrpose funding corporation in 1988 on behalf of lessors in the two companies' 1987 sale and leaseback transaction. The Shippingport capital trust arrangement effectively reduce lease costs related to that transaction.

3. CAPITALIZATION:

(A) RETAINED EARNINGS. ,

l The Company has a provision in its rnortgage applicable to $35.325 million of its 8.00% First Mortgage Bonds due 2003 that requires common stock dividends to be paid out of its total balance of retained eamings. The

'. merger purchase accounting adjustments included resetting the retained eamings balance to zero at the November 8, 1997 merger date.

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(B) COMPREHENSIVEINCOME-in 1998, the Company adopted SFAS 130, " Reporting Comprehensive income," and applied the standard s

to all periods presented in the Consolidated Statements of Common Stockholders Equity. Comprehensive income includes net income as reported on the Consolidated Statements of income and all other changes in common stockholders equity except dividends to stockholders. Net income and comprehensive income are the same for each period presented.  ;

(C) PREFERRED AND PREFERENCE STOCK-Preferred stock may be redeemed by the Company in whole, or in part, with 30-90 days' notice.

The preferred dividend rates on the Company's Series A and Series B fluctuate based on prevailing interest rates and market conditions. The dividend rates for these issues averaged 7.00% and 7.07%, respectively, in 1998. ,

Preference stock authorized for the Company is 5,000,000 shares with a $25 par value. No preference shares are currently outstanding.

A liability of $5 million was included in the Company's net assets as of the merger date for preferred dividends declared attributable to the post-merger period. Accordingly, no accrual for preferred stock dividend requirements was included on the Company's November 8,1997 to December 31,1997 Consolidated Statement of income. This liability was subsequently reduced to zero in 1998.

(D) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION.

Annual sinking fund requirements for the next five years consist of $1.7 million in 1999.

(E) LONG-TERM DEST-The first rnortgage indenture and its supplements, which secure all of the Company's first mortgage bonds, serve as direct fw 'ortgage liens on substantially all property and franchises, other than specifically excepted property, owned by the Cvn any.

Based on the amount of bonds authenticated by the Trustees through December 31,1998, TE's annual sinking and improvement fund requirements for all bonds issued under the mortgage amounts to $0.4 million. TE expects to deposit funds in 1999 that will be withdrawn upon the surrender for cancellation of a like principal amount of bonds, which are specifically authenticated for such purposes against unfunded property additions or against previously retired bonds. This method can result in minor increases in the amount of the annual sinking fund requirement.

Sinking fund requirements for first mortgage bonds and maturing long-term debt (excluding capital leases) forthe next five years are:

fin millions) 1999 $104.2 2000 .. 76.3 2001 . 29.9 2002 165.4 2003.. 977 The Company's obligations to repay certain pollution control revenue bonds are secured by several series of first mortgage bonds. One pollution control revenue bond issue is entitled to the benefit of an irrevocable bank letter of credit of $32.1 million. To the extent that drawings are made under this letter of credit to pay principal of, or interest on, the pollution control revenue bonds, the Company is entitied to a credit against its obligation to repay those bonds. The Company pays an annual fee of 1.875% of the amount of the letter of credit to the issuing bank and is obligated to

• reimburse the bank for any drawings thereunder. .

The Company and CEI have letters of credit of approximately $225 million in connection with the sale and

• leaseback of Beaver Valley Unit 2 that expire in June 1999. The letters of credit are secured by first mortgage bonds of the Company and CEI in the proportion of 60% and 40%, respectively (see Note 2).

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4. SHORT TERM BORROWINGS:

FirstEnergy has a $100 million revolving credit facility that expires in May 1999. FirstEnergy may borrow e under the facility, with all borrowins jointly and severady guaranteed by the Company and CEl. FirstEnergy plans to j transfer any of its borrowed funds .s the Company and CEl. The credit agreement is secured with first mortgage bonds of the Company and CEI in the poportion of 60% arid 40%, respectively. The credit agreement also provides the

participating banks with a subordinate mortgage security interest in the properties of the Company and CEl. The banks' fee is 0.50% per annum payable quarterly in addition to interest on any borrowings. There were no bonowings under the j facility at December 31,1998. Also, the Company may borrow from its affiliates on a short-term basis.

5. COMMITMENTS, GUARANTEES AND CONTINGENCIES:

CAPITAL EXPENDITURES.

The Company's current forecast reflects expenditures of approximately $257 million for property additions and improvements from 1999-2003, of which approximately $58 million is applicable to 1999. Investments for additional nudear fuel during the 1999-2003 period are estimated to be approximately $102 milfon, of which approximately

$9 million applies to 1999. During the same periods, :he Company's nudear fuel investments are expected to be reduced by approximately $120 million and $26 million, respectively, as the nuclear fuel is consumed.

NUCLEAR INSURANCE.

The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to

$9.7 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan.

Based on its present ownership and leasehold interests in Beaver Valley Unit 2, the Davis-Besse Plant and the Peny i Plant, the Company's maximum potential assessment under the industry retrospective rating plan (assuming the other J co-owners contribute their proportionate share of any assessments under the retrospective rating plan) would be l

$77.9 million per incident but not more than $8.8 million in any one year for each incident.  :

I The Company is also insured as to its respective interests in Beaver Valley Unit 2, the Davis-Besse Plant and the Perry Plant under policies issued to the operating company for each plant. Under these policies, up to i $2.75 billion is provided for property damage and decontamination and decommissioning costs. The Company has also

! obtained approximately $354 million of insurance coverage for replacement power costs for its respective interests in Beaver Valley Unit 2, Davis-Besse and Perry. Under these policies, the Company can be assessed a maximum of approximately $10.5 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses.

The Company intends to maintain insurar,ce against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of the Company's plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Company's insurance policies, or to the extent such insurance becomes unavailable in the future, the Company would remain at risk for such costs.

GUARANTEE.

1 The Company, together with the other CAPCO companies, has severally guaranteed certain debt and lease obligations in connection with a coal supply contract for the Bruce Mansfield Plant. As of December 31,1998, the Company's shaie of the guarantee (which approximates fair market value) was $5.5 million. The price under the coal supply contract, which includes certain minimum payments, has been determined to be sufficient to satisfy the debt and lease obligations. The Company's total payments under the coal supply contract were $32.9 million, $29.9 million and

$31.4 million during 1998,1997 and 1996, respectively. The Company's minimum payment for 1999 is approximately i $9 million. The contract expires December 31,1999.

1 4 ENVIRONMENTAL MATTERS-

- Various federal, state and local authorities regulate the Company with regard to air and water quality and other environmental matters. The Company has estimated additional capital expenditures for environmental compliance of approximately $44 million, which is included in the construction forecast provided under " Capital Expenditures" for 1999 through 2003.

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The Company is in compliance with the current sulfur dioxide (SO 2 ) and nitrogen oxides (NO,) reduchon regurements under the Clean Air Act Amendments of 1990. SO: reduchons in 1999 will be schoved by buming lower-sulfur fuel, generating more electncity hom lower-emieng plants, and/or purchasing ermosen aNowances. Plans for

> complying with reductions required for the year 2000 and theresher have not been fineRzed. In September 19g8, the

• Environmental Protection A0ency (EPA) finaHzed regulebons requiring additional NO, reductions from the Company's -i Ohio and Pennsylvania faciuties by May 2003. The EPA's NO, Transport Rule imposes uniform reductions of NO, '

emissions across a region of twenty-two states and the Distnct of Columbia, including Ohio and Pennsylvana. based on -  ;

a conclusion that such NO, emissions are contribubng significandy to ozone poNution in the oestem United States. By -

September 1999, each of the ides states are required to submit revised State implementaten Plans (SIP) which comply with individual state NO, budgets estabhshed by the EPA. These state NO, budgets w. .-i'~ an 85%

reduchon in utl8ty plant NO, emesions from 1990 emissions. A proposed Federal implementabon Plan accompamed the NO, Transport Rule and may be implemented by the EPA in states which fail to revise their SlP. In another separate b related action, eight states fued pomions with the EPA under Seedon 126 Of the Clean Air Act seeldng reduchons of N emissions which are aneced to contribute to ozone pollution in the eight petitoning states. The EPA suggests that the Secdon 126 petitions win be adeopately addressed by the NO, Transport Program, but a September 1998 proposed rulemaione estabushed an anomative pmgram which would, require nearly identical 85% NO, reductions at the Company's Ohio and Pennsylvane plants by May 2003 in the event implementation of the NO, Transport Rule is delayed. Fk."J,wgy continues to evaluate its compilence plans and other complance options and currently estimates its addibonel capital expenditures for NO, reduchons may reach $500 miuion. ..

The Company is requred to meet federaHy approved SO: regulations. Vloistions of such reguisbons can -

result in shutdown of the generating unit involved and/or civH or criminal penalties of up to $25,000 for each day the unit is in vioistion. The EPA has an interim ordorcement policy for SO: regulations in Ohio that allows for comphance base on a 30 day averagmg penod.The Company cannet predict what action the EPA may take in the future with respe the interim enforcement policy.

1 In July 1997, the EPA promulgated changes in the National Ambient Air Quality Standard (NAAQS) for ozone and proposed a new NAAOS for provously unregulated ultra-fine parbculate matter. The cost of compliance these regulations may be substantial and depends on the manner in which they are implemented by the states the Company operates affected facilities The Company has been named as a "potentiauy responable party" (PRP) at wasta deposal sites which may requwe cleanup under the Comprehensive Envvonmental Response, Compensation and LisbNity A Allegsbons that the Company deposed of hazardous substances at hatorical sites and the hability involved unsubstantated and subject to depute. Federal law provides that au PRPs for a particular site be held liable on a and several basis. The Company has accrued a habuity of $1 miHion as of December 31,1998, based on estima the costs of cleanup and the proportonate responsibihty of other PRPs for such costs. The Company behoves that waste en.pnant costs win not have a matenal adverse effect on its financial conditen, cash flows or results of opers Legislative, admmistrative and judicial actons wHI conhnue to change the way that the Company mus operate in order to comply with environmental laws and regulabons. With respect to any such changes a Mo. . .a metters described above, the Company expects that while it remains regulated, any resuibng addibonal capital costs which may be required, as well as any required increase in operahng costs, would ultimatel fromits customers

6.

SUMMARY

OF QUARTERLY FINANCIAL DATA (UNAUDITED):

l The following summarizes certain consolidated operating results by quarter for 1998 and 1997.  !

June 30, September 30, December 31, March 31, iges it9s ines 1ess i Three Monthe ~ ^ ' (ht mlNiens) 5239.7 $253.3 - $243.0 Opersling Revenues - 3 221.1 203 7 1G0.1 201.9 2n2.1 $

P-- i. "' - and Tamas .. 51.2 39.3

. - 52.0 37.8 Operseng income - . .

3.1 2.7 2.6 3.8 21.1 Oter income.. 21.8 21 8 21.2 Not Inimmat Ci-n- .. $ 32.7 $ 20.8 f

$ 34.0 s 19.1 j Not ;.u _

5 15.0 5 25.5 5 15.9 T-i- s on Co.m.- "w* . . 5 32.5 f

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i Three Months Ended

l. Mer 31, - June 30, Sept. 30 Oct.1 - Nov. 8 -

1997 Nov. 7.1997 Dec.31.1997 1997 1997

,. (in millions)

Operseng Revenues $217.1 $222.1 . $241.3 $ 92.2 $122.7 Ocaranna Exnenses and Taxes .. 184.7 186.1 191.9 86.7 103.6 Operanng income .. 32.4 36.0 49.4 5.5 19.1

. Otherincome (Expense) (0.4) 0.4 5.0 (2.9) 2.1 Not Interest Charans 23.2 23.3 27.2 10.0 13.6

' income (Loss) Before Extraordinary item s 8.8 13.1 27.2 (7.4) 7.6 Extraordinarv item (Nat of income Taxas) (Note 1).. - - - (191.9) -

Not incrimm e -) .. S 8.8 $ 13.1 1 27.2 $(199.3) $ 7.6 Emmenos 6 m)on Common **.. I 4.5 5 B.9 5 230 5(206.2) 5 7.6

7. PRO FORMA COMBINED CONDENSED STATEMENTS OF INCOME (UNAUDITED):

FirstEnergy was formed on November 8,1997 by the merger of OE and Centerior. The merger was accounted for as a purchase of Centeriors net assets with 77,637,704 shares of FirstEnergy Common Stock through the conversion of each outstanding Centerior Common Stock share into 0.525 of a share of FirstEnergy Common

Stock (fractional shares were paid in cash). Based on an imputed value of $20.125 per share, the purchase price i

was approximately $1.582 billion, which also included approximately $20 million of merger related costs. Goodwill of approximately $2.0 billion was recognized (to be amortized on a straight-line basis over forty years), which represented the excess of the purchase pdce over Centeriors not assets after fair value adjustments.

Accumulated amortization of goodwill was approximately $15 million as of December 31,1998. The i

l merger purchase accounting adjustments included recognizing estimated severance and other compensation liabilities ($24 million). The amount charged against the liability in 1998 relating to the costs of involuntary employee separation was $11 million. The liability was subsequently reduced to zero as of December 31,1998. The liability adjustment was offset by a corresponding reduction to goodwill recognized in connection with the Centerior acquisition.

The following pro forma statements of income for the Company give effect to the OE-Centerior merger as if it had been consummated on January 1,1996, with the purchase accounting adjustments actually recognized in j the business combination.

l Year Ended December 31.

1997 1996 (In millions)

Operating Revenues _

$895 $897 Operating Expenses and Taxes.. .. . ... Zd2 _Z21 Opersengincome . . . 153 16e Other income (Expense) . .. 10 (3) l Not Interest Charges . . . . . . 21 _BS  ;

Not income S 72 S 77 l I

Pro forma adjustments reflected above include: (1) adjusting the Company's nuclear generating units to fair value based upon independent appraisals and estimated discounted future cash flows based on I management's estimate of cost recovery; (2) the effect of discontinuing SFAS 71 for the Company's nuclear l operations; (3) amortization of the fair value adjustment for long-term debt; (4) goodwill recognized representing the excess of the Company's portion of the purchase price over the Company's adjusted net assets; (5) the elimination of merger costs; and (6) adjustments for estimated tax effects of the above adjustments.

8.. PENDING MERGER OF THE COMPANY INTO CEl:

1. ' In March 1994, Centerior announced a plan to merge the Company into CEl. All necessary regulatory l l approvals have been obtained, except the approval of the Nuclear Regulatory Commission (NRC). This application was withdrawn at the NRC's request pending the decision whether to complete this merger. No final decision j'(

j regarding the proposed merger has been reached.

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3 in June 1995, the Company's prefened stockholders approved the merger and CEl's preferred i stockholders approved the authorization of additional shares of preferred stock. If and when the merger becomes i effective, the Company's preferred stockholders will exchange their shares for preferred stock shares of CEI having substantially the same terms. Debt holders of the merging companies will become debt holders of CEl. s For the merging companies, the combined pro forma operating revenues were $2.621 billion,

' $2.527 billion and $2.554 billion and the combined pro forma not income was $272 million, $220 million (excluding -

the extraordinary item docussed in Note 1 and a similar item for CEI) and $218 million for the years 1998,1997 and 1996, respectively.The pro forma data is based on accounting for the merger of the Company and CEI on a method similar to a pooling of interests and for 1997 and 1996 includes pro forma adjustments to reflect the effect of the OE -

. Centerior merger. The pro forma data is not necessarily indicative of the results of operations which would have been reported had the merger been in effect ouring those years or which may be reported in the future. The pro -

forma data should be read in conjunction with the audited financial statements of both the Company and CEl.

E 25

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V Report ofIndependent Public Accountants

~ To the Stockholders and Board of Directors of The Toledo Edison Company:

i We have audited the accompanying consolukted belance sheets and consolidated statements of capitalization of The Toledo Edison Company (an Ohio wwisun and wholly owned subsidiary of FirstEnergy Corp.) and subsidiary as of .  !

December 31,1998 and 1997, and the related coneohdated statements of income, common stockholder's equity, i preferred stock, cash flows and taxes for the year ended December 31,1996, the period from January 1,1997 to November 7,1997 (pre-merger), the period from November 8,1997 to December 31,1997 (post-merger), and the year onded December 31,1998. 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 generally accepted audstng standards. Those standards require that we plan ar'd perform the audit to obtain reasoimble assurance about whether the financial statements are free of material l misstatement. An audit includes examming, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting pnnciples used and significant estimates made by l- management, as well as evaluating the overall financial statement presentabon. We believe that our audits provide a - '

reasonable basis for our opinion.

( in our opinion, the financial statements referred to above present fairty, in all material respects, tho' financial position of The Toledo Edieon Company and subsidiary as of December 31,1998 and 1997, and the results of their operations and their cash flows for the year ended December 31,1996, the period from January 1,1997 to November 7,1997 (pre-merger), the period frorn November 0,1997 to December 31,1997 (post-merger), and the year ended December 31, 1998, in cxnJcn.4y with generally accepted accounting pnnciples

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.' b d a I-ARTHUR ANDERSEN LLP Cleveland, Ohio February 12,1999 I

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da FirstEnergy Corp..

. 76 South Main Street Akron, Ohio 44808 (800)786-8402 4

- 1998 Annual Report I

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