ML20044D304

1992 Annual Rept for Cleveland Electric Illuminating Co.

ML20044D304
Person / Time
Site:	Beaver Valley
Issue date:	12/31/1992
From:	CLEVELAND ELECTRIC ILLUMINATING CO.
To:
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ML20044D300	List: ML20044D299 ML20044D301 ML20044D303 ML20044D304 ML20044D308 ML20044D318
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NUDOCS 9305180482
Download: ML20044D304 (25)

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! . THE CLEVELAND ELECTRIC ILLUMINATING COMPANY  !

A Subsidiary of Centerior Energy Corporation I

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j ANNUAL REPORT 9305180482 930506

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$ About Clneland Electric o 1 O Directors l 4 $ Officers

$ Report ofIndependent Public Accountants O Summary of Significant Accountmg ibhcies O Management's Financial Analysis, financial Statements and Notes

$ hnancialand Statistical Review

$ Investorinformation i

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- About Cleveland Electric 1he Company. a wholly owned subsidiary of Centenor PAert] farhng, Chairman, President and Chief o

Energy Corporation provides electnc service to an "

Executive Ofhcer of Centenor Energy Corporation and area of northeastern Ohio extendmg 100 miles along Centenor Service Company the southern shore of Lake Ene from Pennsylvania on the east through the aty of Avon 12ke on the west. The Edgar H. Maugans, Vice President & Chief Financial southern boundary of the service area is approximately Officer of the Company and The Toledo Edison Company and Executive Vice President of Centerior 1, miles south of Lake Ene. The complete boundary prescubes an area of about 1,700 square miles. Total Energy Corporation and Centerior Service Company populatmn served is about 1210.000. Although the Lyman C. Phdhrs, President and Chief Executive Officer pnncipal city m the service area is Cleveland, the of the Company, Chairman and Chief Execuuve Officer Company derives about 75% of its total electnc revenue of The Toledo Edison Company and Executive Vice from customers outside of the city The Company's President of Centerior Energy Corporation and 4,500 ernployees sene about 749,000 customers. Centerior Service Company

- Executive Offices l

The Cleveland Electric liluminatmg Company President and Chief o 55 Pubhc Square o Executive Ofhcer . . Iyman C. Phtihrs Cleseland OH Vice President &

(216)622-9800 Chief Financial Ofhcer Edgar H. Maugans Vice President Fred]. Ienge,Jr l

Controller . Paul G. IlusFv Treasurer Gary M HaEkinson

_ g Sectetary. E. Lyle Pepin PO Iiox 5000 o Cleseland CH 44101 1

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Report of Independent Public Accountants ARTHUR l ANDERSEN  !

To the Share Owners of '

o The Cleveland Electric Illuminating Company:

We have audited the accompanying consolidated bal- Company and subsidiaries as of December 31,1992 ,

ance sheet and consolidated statement of preferred and 1991, and the results of their operations and their r stock of The Cleveland Electric Illuminating Com- cash flows for each of the three years in the period pany (a wholly owned subsidiary of Centenor Energy ended December 31,1992,in conformity with gener-Corporation) and subsidiaries as of December 31, ally accepted accounting principles. t 1992 and 1991, and the related consolidated state- . ..

As discussed further m. the Summary of Sigmficant ments of income, retained earnings and cash flows for Acc unting Policies, a change was made m the each of the three years in the period ended December method of accounting for nuclear plant depreciation >

31,1992. These financial statements are the wsponsi-in 1991, retroactive to January 1,1991.

bility of the Company's management. Our responsi, bility is to express an opinion on these fmancial As discussed further in Note 3(c), the future of Perry statements based on our audits. Unit 2 is undecided. Construction has been sus-We conducted our audits in accordance with generally Pended since July 1985. Various options are being c nsidered, including resuming construction, con- 1 i accepted auditing standards. Those standards require verting the unit to a nonnuclear design, sale of all or that we plan and perform the audit to obtain reason, part of the Company's ownership share, or canceling able assurance about whether the financial statements the uru,t. Management can give no assurance when, are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the if ever, Perry Unit 2 will, go in service or whether the amounts and disclosures in the financial statements. Company s investment m that umt and a return An audit also includes assessing the accounting princi- thereon will ultimately be recovered.

ples used and significant estimates made by manage-ment, as well as evaluating the overall financial statement presentation. We believe that our audits @,

provide a reasonable basis for our opmion.

, in our opinion, the fmancial statements referred to i 2

above present fairly, in all material respects, the finan- Cleveland, Ohio cial position of The Cleveland Electric illuminating February 12,1993

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. Summary of Significant Accounting Po cies '

t GENERAL nuclear fuel disposal costs are being recovered The Cleveland Electric illuminating Company (Com. through the base rates.

o pany) is an electric utility and a wholly owned The Company defers the differences between actual subsidiary of Centerior Energy Corporation (Center- fuel costs and estimated fuel costs currently being ior Energy). The Company follows the Uniform recovered from customers through the fuel factor. This System of Accounts prescribed by the Federal Energy matches fuel expenses with fuel-related revenues.

Regulatory Commission (FERC) and adopted by The Public Utilities Commission of Ohio (PUCO). As DfffRRED CARR17NG CHARGES a rate-regulated utility, the Company is subject to AND OPERATING EXPENSES Statement of Financial Accounting Standards (SFAS) 71 which governs accounting for the effects of certain As discussed in Note 6, the January 1989 PUCO rate types of rate regulation. The hnancial statements order for the Company meluded an approved rate include the accounts of the Company's wholly owned phase-m plan for its mvestments m Perry Nuclear subsidiaries, which in the aggregate are not material. Power Plant Unit 1 (Perry Unit 1) and Beaver Valley l Power Station Unit 2 (Beaver Valley Unit 2). The

, The Company is a member of the Central Area Power plan called for the Company to begin deferring in Coordination Group (CAPCO). Other members in- January 1989 operating expenses and both interest clude The Toledo Edison Company (Toledo Edison), and equity carrying charges on deferred rate-based "

Duquesne Light Company (Duquesne), Ohio investment. These deferrals, called phase-in deferrals, Edison Company (Ohio Edison) and Ohio Edison's will be amortized and recovered by December 31, r wholly owned subsidiary, Pennsylvania Power Com- 1998. Previously, the PUCO authorized the Company pany (Pennsylvania Power). The members have to defer operating expenses and carrying charges for constructed and operate generation and transmission Peny Unit I and Beaver Valley Unit 2 from their facilities for their use. Toledo Edison is also a wholly i respective in-service dates in 1987 through December owned subsidiary of Centerior Energy. 1988. The amortization and recovery of these defer-rals, called pre-phase-in deferrals, also began in Janu-RffATfD PARTY TRANSACTIONS ary 1989 and will continue over the lives of the Operating revenues, operating expenses and interest related property.

charges include those amounts for transactions with Beginning in January 1992, the Company defened affiliated companies in the ordinary course of busi- charges for depreciation, property taxes and interest i ness operations.

carrying charges related to plant placed in service after The G .npany's transactions with Toledo Edison are February 29,1988 and not yet included in rate base.

primanly for firm power, interchange power, trans- The PUCO authorized these deferrals in October 1992 mission line rentals and jointly owned power plant under a Rate Stabilization Program. Similar deferrals operations and construction. See Notes 1 and 2. may be recorded through December 31,1995. Amorti- i Centerior Service Company (Service Company), the zati n and recovery of these deferrals will occur over  ;

the average life of the assets and will commence third wholly owned subsidiary of Centerior Energy, .

with future rate recogmtion. See Notes 6 and 13.

provides management, financial, administrative, engi-neering, legal and other services at cost to the Com-  ;

pany and other affiliated companies. The Service DEPRECIATION AND AAf0RTIZATION  ;

Company billed the Compariy $150 million, $138 The cost of property, plant and equipment is depreci- '

million and $106 million in 1992,1991 and 1990, ated over their estimated useful lives on a straight-respectively, for such sersices. line basis. The annual straight-line depreciation pro- ,

vision for nonnuclear property expressed as a per- '

RfrENUES cent of average depreciable utility plant in sersice was Customers are billed on a monthly cycle basis for their 3A% in both 1992 and 1991 and 3.3% in 1990. Effec- I energy consumption based on rate schedules or con- tive January 1,1991, the Company, after obtaining tracts authorized by the PUCO. An accrual is made PUCO approval, changed its method of accountmg at the end of each' month to record the estimated f r nuclear plant depreciation from the umts-of-pro-amount of unbilled revenues for kilowatt-hours sold duction method to the straight-line method at about in the current month but not billed by the end of that a 3% rate. This change decreased 1991 depreciation month' expense $22 milhon and mereased 1991 net mcome

$17 million (net of $5 million of income taxes) from A fuel factor is added to the base rates for electric what they otherwise would have been. The PUCO service. This factor is designed to recover from cus- subsequently approved in 1991 a change to lower tomers the costs of fuel and most purchased power. It the 3% rate to 2.5% retroactive to January 1,1991. See is reviewed and adjusted semiannually in a PUCO Note 13.

proceeding.

The Company uses external funding of future decom-missioning costs for its operating nuclear units pursu-Tuff EXPENSE ant to a PUCO order. Cash contributions are made to The cost of fossil fuel is charged to fuel expense based the trust funds on a straight-line basis over the re-on inventory usage. The cost of nuclear fuel, includ- maining licensing period for each unit. The current ing an interest component, is charged to fuel expense level of expense being funded and recovered from based on the rate of consumption. Estimated future customers over the remaining licensing periods of the 3

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units is approximately 54 million annually. Amounts - under construction. That interest is capitalized. See l q currently in rates are based on past estimates of Note 5. ,

decommissioning costs of $63 million in 1996 dollars  !

for the Davis-Besse Nudear Power Station (Davis- Losses and gains realized upon the reacquisition or  !

. Besse) and 544 million and 535 million in 1987 dollars redemption of long-tenn debt are deferred, consistent j l for Perry Unit 1 and Beaver Valley Unit 2, respec. with the regulatory rate treatment. Such losses and j 1 tively. Actual decommissioning costs are expected to gains are either amortized over the remainder of the i significantly exwed these estimates. We expect to original life of the debt issue retired or amortized f complete our assessment of these estimates in 1993 to over the life of the new debt issue when the proceeds l update the decommissioning cost amounts and to of a new issue are used for the debt redemption. The i

! continue to satisfy the external funding requirements. amortizations are included in debt interest expense. l

, it is expected that increases in the cost estimates will j be recoverable in future rates. In the Balance Sheet at

, December 31,1992, Accumulated Depreciation and IEDERAL INCOAfE TAXES j Amortization included $32 million for the cumulative The Financial Accounting Standards Board (FASB) i total of decommissioning costs previously expensed '

issued a new standard for accounting for income taxes and the earnings on the external fundmg. This amount '

(SFAS 109) in February 1992. We adopted the new

exweds the Balance Sheet amount of the external Nudear Plant Decommissioning Trusts because the standard in 1992. The new standard amends certain .

3 reserve began prior to the extemal trust funding.

provisions of SFAS 96 previously adopted in 1988. I

Adoption of the new standard in 1992 did not materi-ally affect our results of operations, but did affect l PROPERTY, PLANT AND EQUIPhfENT certain Balance Sheet accounts. See Note 7. y t

Property, plant and equipment are stated at original The financial statements reflect the hability method of  ;

cost less any amounts ordered by the PUCO to be accounting for income taxes. This method requires l

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written off. Construction costs indude related payroll that deferred taxes be wcorded for all temporary J j taxes, pensions, fringe benefits, management and differences between the book and tax bases of assets [

general overheads and allowance for funds used dur- and liabilities. The majority of these temporary dif-  ;

j ing construction ( AFUDC). AFUDC represents the ferences are attributable to property-related basis dif-  ;

, estimated composite debt and equity cost of funds ferences. Included in these basis differences is the  !

1 used to fmance construction. This noncash allowance equity component of AFUDC, which willincrease  !

is credited to income, except for certain AFUDC for future tax expense when it is recovered through rates.  ;

Perry Nudear Power Plant Unit 2 (Perry Unit 2). See Since this component is not recognized for tax pur-  !

Note 3(c). The AFUDC rate was 10.56% in 1992, poses, we must record a liability for our tax obliga- i a

10.47% in 1991 and 10.48% in 1990. tion. The PUCO permits recovery of such taxes from i

! customers when they become payable. Therefore, i j Maintenanw and repairs are charged to expense as. the net amount due from customers through rates has i

] mcurred. The cost of replacmg plant and equipment is been recorded as a regulatory asset in deferred '

charged to the utility plant accounts. The cost of charges and will be recovered over the lives of the

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property retired plus removal costs, after deducting related assets. ,

any salvage value, is charged to the accumulated  ;

i provision for depreciation. Investment tax credits are deferred and amortized I over the estimated lives of the applicable property as a reduction of depreciation expense. See Note 6 j DETERRED GAIN TROhf f r a discussion of the amortization of certam SALE Of UTILITY PLANT unrestricted excess deferred taxes and unrestricted ,

. The sale and leaseback transaction discussed in Note 2 investment tax credits available after 1998 under the j resulted in a net gain for the sale of the Bruce Rate Stabilization Program.  !

! Mansfield Generating Plant (Mansfield Plant). The

net gain was deferred and is being amortized over the RECLASSITICATIONS  !

4 term of leases. The amortization and the lease ex-

) pense amounts are recorded as other operation and Certain reclassifications were made to prior years 3

mamtenance expenses. See Note 6. financial statements to make them comparable with ,

1 the 1992 financial statements. A reserve for Perry Unit i INTEREST CHARGES 2 AFUDC, which was previously reported under l Deferred Credits in the Balance Sheet, was redassi- l l Debt Interest reported in the income Statement does fied as an offset against the Perry Unit 2 asset balance.  !

1 not indude interest on obligations for nuclear fuel See Note 3(c). l

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i Management's Financial Analysis l RESULTS Of OPERATIONS ongoing determination that recovery of the de-ferred costs in rates is probable.

Overn.ew We face further challenges in the years to come, in -

In recent years, our efforts to add our substantial 1994, expense deferrals provided in the 1989 agree-nuclear investment to rate base while maintaining a ment will cease. The amortization of the deferrals competitive rate structure have resulted in a series taken from 1989 through 1993 will also begin and  !

of agreements with the major intervenors in our continue through 1998. The amortization schedule rate cases. One agreement was approved by the provides for $23 million in 1994, increasing to $217 PUCO in January 1989 and is described more fully million in 1998. An additional $50 million of in Note 6. It established our rate phase-in plan to expense deferrals for 1990 and 1991, related to recognize in rates our allowed investment in certain provisions of the phase-in plan, will be Perry Unit 1 and Beaver Valley Unit 2. The phase- amortized and recovered by December 31,1998. In in plan increased revenues and cash flows but was addition, we are still confronted with competitive designed to have a relatively neutral impact on threats from municipal electric systems within our earnings. Gains in revenues were to be initially service territory and from cities contemplating offset by a reduction in the deferral of operating creation of their own electric systems. Although the expenses and carrying charges and subsequently rate of inflation has eased in recent years, we are offset by the amortization of such deferrals. A key still affected by even modest inflation which causes  !

assumption underlying the phase-in plan was that increases in the unit cost of labor, materials and revenues would increase as a result of projected services. 1 sales growth. When sales decreased primarily be- l cause of a sluggish economy, earnings were ad- To combat the forces described above, we have .

versely affected. embarked on the following course. Reductions in j other operation and maintenance expenses and A number of other factors also exerted a negative capital expenditures were implemented in 1991 and influence on earnings. These factors included the 1992 and will be vigorously pursued in 1993 and recording of nuclear plant depreciation at levels in beyond. We will further reduce staffing levels and excess of that reflected in rates, the recording of look to improve efficiency of operations wherever depreciation and interest charges on facilities possible. We are aggressively attempting to in-placed in service after February 1988 as current crease revenues by seeking additional long-term expenses even though such items were not being power sales agreements with wholesale customers recovered in rates and the effect of inflation on and by exploring various corporate asset transac-expenses. Also, the need to meet competitive tions. The Energy Policy Act of 1992 (Energy forces, coupled with a desire to encourage eco. Act), which requires utilities to transmit electricity nomic growth in our service area, prompted us to from wholesale suppliers to wholesale customers, reduce rates for certain industrial and commercial will provide new opportunities for us to make customers. wholesale power transactions. To counter munici-pal electric system initiatives, we have continued We determined that the best solution to address programs that demonstrate the value inherent in these factors was to delay rate increases and imple_ our service, beyond what one might expect from a ment cost-reduction and revenue-enhancement municipal system. Such programs include provid-strategies. Furthermore, we sought PUCO ap- ing services to communities to help them retain proval of regulatory accounting measures designed and attract businesses, providing consulting ser-to recognize the effects of a delay in rate recovery Vices to customers to improve their energy effi-of certain costs and provide a better match of ciency and developing demand-side management current revenues and operating expenses. In 1991, programs.

we obtained PUCO approval to change the method increases in sales are expected to be modest with and rate of accrumg nuclear plant depreciation. In annual sales growth projected at about 1-2% for the October 1992, the PUCO approved a Rate StabiL-next several years, depending upon the economic zation Program, which was supported by certain climate in our service area. Recognizing the fact customer representative groups, as discussed in that costs can be reduced only so far and the Note 6. Under the terms of the Rate Stabilization limitations imposed by our sales forecasts and com-Program, we agreed to freeze base rates until 1996 petition in the wholesale power market, rate in-and to limit rate increases through 1998. In ex- creases will be necessary eventually to recognize change, we are permitted to defer and subse- the cost of our new capital investment, including quently recover certam costs not currently that being deferred under the Rate Stabilization recovered m rates and to accelerate amortization of Program, and inflation.

certain benefits. However, our ability to utilize these regulatory accounting measures is dependent We believe that our Rate Stabilization Program and upon our taking significant actions to reduce costs our strategies to reduce costs and increase reve-and increase revenues. It is also dependent upon an nues give us the opportunity to improve our com-5

petitive position and our earnings. Neverthelens, charge credits and a greater tax allocation of inter-we operate in a changing industry and market. We est charges to nonoperating activities. Credits for must monitor the impact of these changes on our carrying charges recorded in nonoperating income  :

strategy and the continued appropriateness of the . decreased primarily because of lower phase-in car- l

regulatory accounting provided by our various rying charge credits. Interest charges decreased as a result of debt refinancings at lower interest rates  !

agreements.

and lower short-term borrowing requirements.

I 1992 vs.1991 i Factors contributing to the 4.5% decrease in 1992 1991 vs.1990 l operating revenues are as follows:  ;

Decrease in Operating Revenues e s Factors contributing to the 8% increase in 1991 l perating revenues are as follows:

Sales Volume and Mix . 550 l Base Rates and Miscellaneous . - 23 Increase in Operatine Revenues of Dottars Fuel Cost Recovery Revenues . J Base Rates and Miscellaneous . . . $ 74

. $ Wholesale Sales . . .

Sales Volume and Mix .

. 40 21 l l The revenue decreases resulted primarily from the 5135

! different weather conditions in both years and the ,

changes in the composition of the sales mix among customer categories. Weather accounted for The increases in base rates and miscellaneous approximately 555 million of the lower 1992 reve- revenues resulted primarily from rate increases in nues. Winter and spring in 1992 were milder than the January 1989 PUCO rate order for the Com- ,

in 1991. In addition, the 1992 summer was the pany as discussed in Note 6. Total kilowatt-hour coolest in 56 years in Northeastem Ohio as con- sales increased 4.3% in 1991. Residential and com-trasted with the summer of 1991 which was much mercial sales increased 4.8% and 4.9%, respec- '

hotter than normal. As a result, total kilowatt. tively, as a result of higher usage of cooling a hour sales decreased 3.5% in 1992. Residential and equipment in response to the unusually warm late  ;

. commercial sales decreased 4.4% and 0.5%, respec- spring and summer 1991 temperatures. The com-  ;

tively, as moderate temperatures in 1992 reduced mercial sales increase was also influenced by some i electric heating and cooling demands. Industrial improvement in the economy for the commercial sales declined 0.4% as an 8.1% decrease in sales to sector. Industrial sales declined 6.3% largely be-the broad-based, smaller industrial customer cause of the recession-driven slump in the steel, -

1 group completely offset an 8.8% increase in sales auto and chemical industries. Other sales increased  !

to the larger industrial customer group. Sales to 45.3% because of increased sales to wholesale cus-steel producers and auto manufacturers within the tomers and pubhc authonties. ,

, large industrial customer group rose 10.9% and 7%,

respectively. Other sales decreased 16.1% because Operating expenses increased 4.9% in 1991. The i of decreased sales to wholesale customers and increase was mitigated by a reduction of $44 j public authorities. The decrease in 1992 fuel cost million in other operation and maintenance

recovery revenues resulted primarily because of the expenses, resulting primarily from cost-cutting l good performance of our generating units, which measures. Offsetting this decrease were an increase in tum decreased our fuel cost factors. The in fuel and purchased power expense resulting

, weighted averages of these factors decreased ap- primarily from increased purchased power costs 4

proximately 3%. and increased amortization of previously deferred r

! fuel costs over the amount amortized in 1990; an Operating expenses decreased 3.6% m. 1992. Lower increase in federal income taxes because of higher fuel and purchased power expense resulted from pretax operating income; an increase in taxes,

! Iower generation requirements stemming from less other than federal income taxes, resulting frora t electric sales and less amortization of previously higher property and gross receipt taxes and accru-l deferred fuel costs than the amount amortized in als for Pennsylvania tax increases enacted in 1991. Federal income taxes decreased because of August 1991; and lower operating expense deferrals j the Rate Stabilization Program's amortization of for Perry Unit 1 and Beaver Valley Unit 2 pursuant certam tax beneflts and the effects of adopting to the January 19t3 rate order.

SFAS 109 m 1992. These decreases were partially offset by higher depreciation and amortization, J

caused primarily by the adoption of SFAS 109, and Credits for carrying charges recorded m.

n n peratmg mcome decreased m 1991 because a by higher taxes, other than federal income taxes,

-i caused by increased Ohio property and gross re- greater share of our mvestments m Perry Unit I ceipts taxes. Deferred operating expenses increased and Beaver Valley Unit 2 were recovered in rates.

The federal income tax provision for nonoperatmg  ;

i as a result of the deferrals under the Rate Stabili_

zation Program as mentioned in Note 6. inc me increased mainly because the 1990 provi-l sion was reduced 519 million for unamortized m-l The federal income tax provision for nonoperating vestment tax credits on the 1988 write-off of nuclear a

income decreased because of lower carrying plant investments. ,

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r g gg THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES For the years ended December 31, 1992 1991 1990 (millions of dollars) f Operating Revenues . .. .. . 51,743 $1.826 $1.691  !

Operating Expenses Fuel and purchased power (1) . .. .... . .. .. . . ... 434 455 412 Other operation and maintenance . ... .. . .. . . 465 470 514 Total operation and maintenance . . ... . 899 925 926 ,

Depreciation and amortization . . . . . .. 179 171 170 Taxes, other than federal income taxes . . . . ... .. 226 216 197  ;

Deferred operating expenses, net . . ..

(35) (7) (24)

Federal income taxes . . . . . . 89 106 75 1,358 1,411 1,344 Operating income . .. . .. . .. . 385 415 347  ;

Nonoperating in.-.... .

Allowance for equity funds used during construction . . . 1 8 5 Other income and deductions, net . . , .. ... . 8 6 1 Deferred carrying charges. .. .. . . 59 88 162 Federal income taxes - credit (expense) . . . ..

(5) (24) (20) ,

63 78 148 Income Before Interest Charges . . . . . 448 493 495 l Interest Charges Debt interest . . 243 251 255 Allowance for borrowed funds used during construction ..

(4) (3) 243 247 252 Net income .. . . . 205 246 243 Pr im ed Dividend Requirements. . . . . . 41 36 37 i l'arnung Available for Common Stock . . .. 5 164 $ 210 $ 206 l

(1) Includes purchased power expense of $130 million, $128 million and $112 million in 1992,1991 and 1990, respectively, for all purchases frorr Toledo Edison.

Retained Eamings For the years ended December 31, 1992 1991 1990

' (millions of dollars)

Balance at Beginning of Year. . . 5 578 5 564 $ 507 Additions Net income ... . . . . . 205 246 243 Deductions Dividends declared:

Common stock . . . . . .

(195) (194) (149) ,

Preferred stock . .

(41) (36) (36) l Other, primarily preferred stock redemption expenses .

(2) (2) (1) l Net Increase (Decrease) . . . . .

(33) 14 57 Balance at End of Year .. . . S 545 5 578 5 564 The accompanying notes and summary of signincant accounting policies are an integral part of these statements. j l

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Management's Financial Analysis l CAPITAL RESOURCES AND LIQUIDITY ance with the Clean Air Act Amendments of 1990 (Clean Air Act). Expenditures for our optimal We need cas.h for normal corporate operations, the plan are estimated to be approximately 5172 mil-mandatory retirement of securities and an ongoing lion over the 1993-2002 period. See Note 3(b).

program of constructing new facilities and modi- ',

fying existing facilities. The construction program The Company is aware of its potential involvement is needed to meet anticipated demand for electric in the cleanup of seven hazardous waste sites.

service, comply with governmental regulations However, we believe that the ultimate outcome of and protect the emironment. Over the three-year these matters will not have a material adverse period of 1990-1992, these construction and effect on our liquidity. See Note 3(d).

mandatory retirement needs totaled approximately 5760 million. In addition, we exercised various We expect to be able to raise cash as needed. The options to redeem and purchase approximately availability and cost of capital to meet our extemal

• 5500 million of our securitics. financing needs, however, depends upon such factors as financial market conditions and our credit We raised SL2 billion through security issues and ratings. Apparently, the market perceives the term bank Lans during the 1990-1992 period as Company as having a greater risk than its credit shown in the Cash Flows statement. During the ratings would indicate. Therefore, in 1992, the  !

three-year period, the Company also utilized its Company had to offer interest and dividend rates short-term borrowing arrangements (explained in on certain of its new debt and preferred stock

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Note 11) to help meet its cash needs. The Com- securities which were significantly higher than pany had 521 million of short-term borrowings those that would be expected for securities hasing outstanding at December 31,1992, including $11 the credit ratings of the Company. Current securi- ,

million of notes payable to affiliates. ties ratings for the Company are as follows: i d

Estimated cash requirements for 1993-1995 for the {'p"d#'.d Company are 5658 million for its coastmetion screice Correration a program and 5627 million for the mandatory re-demption of debt and preferred stock. The Com- First mongage bonds BBB- Baa3 pany expects to finance externally about 85% of its Unsecured notes BB+ Bal I total 1993 cash requirements of approximately Preferred stock . BB+ bal 5530 million. About 50-60% of the Compaay's 1994 and 1995 requirements are expected to be financed The ratings of Moody's Investors Service, Inc. set extemally. If economical, additional securities may forth above reflect a downgrade in February 1993.

be redeemed under optional redemption pro i- '

sions. See Note 10(d) for information conceming A write-off of the Company's investment in Perry limitations on the issuance of debt. Unit 2, as discussed in Note 3(c), would not l reduce retained earnings sufficiently to impair its i Our capital requirements after 1995 will depend on ability to declare dividends and would not affect our implementation strategy to achieve compli- cash flow.

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THE CLEVELAND ELECTRIC Il1UMINATING COMPANY AND SUBSIDIARIES For the years ended j December 31, n 1992 1991 1990 )

(millions of dollars)

Cash Flores from Operating Activities (1)

Net income . ... . ... . ..... .. . .. ... . 5 205 5 246 5 243 Adjustments to Reconcile Net income to Cash from Operating Activities:

Depreciation and amortization . . . .. . . ... . . . 179 171 170 Deferred federal income taxes . . . .. .. .. . .... . 66 51 111 Investment tax credits, net . . . . .. . .

(8) 13 (17)

Deferred and unbilled revenues. . . . .. . . .. (7) (25) (38)

Deferred fuel . .. . .. . . ... . . 6 13 (11)

Deferred carrying charges . ... . . .. ..... . . . . ... .. . (59) (88) (162)

Leased nuclear fuel amortization . .. ..... ... .. . .. . 70 69 47 l Deferred operating expenses, net. .. . . . . .. .. . . (35) (7) (24) l Allowance for equity funds used during construction. . .. .. .. (1) (8) (5) i Pension settlement gain.. . ... .. ... . . . .. .

(35)

Changes in amounts due from customers and others, net . . ... .. . 6 12 (17)

Changes in inventories. . . . . . .. . .

(2) (15) (22)

Changes in accounts payable . . . . . . .... .... . .. 7 (24) 32 Changes in working capital affecting operations . . . . . . .. .

(4) 37 (5)

Other noncash items . . ... . ... . (11) (13) (10)

Total Adjustments. . . . . ... . . 207 186 14 Net Cash from Operating Activities . . .. . . . 412 432 257 Cash Flotes from Tinancing Activities (2)

Bank loans, commercial paper and other short-tenn debt . . .. . 10 (87) 87 l Notes payaNe to affiliates. . . .

(13) 7 (157)

Debt issues:

First mortgage bonds .. . .. . .. . . 324 -

100 Secured rnedium-term notes . . . .. . . 90 150 333 Term bank loans . . .. . .. .

16 Preferred stock issues . . . . . 74 125 -

Maturities, redemptions and sinking funds . . .. .

(481) (133) (212)

Nuclear fuel lease obligations. .. . . . ... . .. .

(65) (64) (56)

Dividends paid. . . . .. . ..

(235) (230) (186)

Premiums, discounts and expenses . . .

(7) (5) (6)

Net Cash from Financing Activities . . .. .

(303) (237) (76) l l Cash Flores from Investing Activities (2)

Cash applied to construction . . .. . . .. (152) (138) (157)

Interest capitalized as allowance for borrowed funds used during construction . -

(4) (3)

Loans to affiliates . . . . . .

11 (11)

Other cash received (applied) . . . . . . . . . . . .... .

(20) 2 (7)

Net Cash from Investing Activities . . . . . . . . . (172) (129) (178)

Net Change in Cash and Temporary Cash investments . . .. .

(63) 66 3 Cash and Temporary Cash investments at Beginning of Year .. 97 31 28 Cash and Temporary Cash investments at End of Year . . . . ... . . 5 34 5 97 5 31 (1) Interest paid (net of amounts capitalized) was $205 million,5221 million and 5189 million in 1992,1991 and 1990, respectively. Income taxes paid were 528 million,550 million and $19 million in 1992,1991 and 1990, respectively.

(2) Increases in Nuclear Fuel and Nuclear Fuel Lease Obligations in the Balance Sheet resulting from the noncash capitalizations under nuclear fuel agreements are excluded from this statement.

The accompanying notes and summary of significant accounting policies are an integral part of this statement.

l 9

December 31,  :

I 1992 1991 -

U (millions of dollars) ;

ASSETS  !

Property, Plant and Equipment Utility plant in service. . . . .. . . . ... . .. . 56,602 56,196  ;

Less: accumulated depreciation and amortization . . . . . . . ... . . 1.728 1,565 -

4,874 4,631 >

Construction work in progress .. . .... . . 130 162 Perry Unit 2. . . . . . . . .. .. . . . .

__ 371 383 5,375 5,176 i Nuclear fuel, net of amortization .... . . . .. .. . . 224 263 Other property,less accumulated depruiation . . .. .. ... . 37 42 5,636 5.481 Current Assets Cash and temporary cash investments . . ... . 34 97 Amounts due from customers and others, net .. . .. . . 161 167 Amounts due from af'iliates . . . . . 10 4 Unbilled revenues .. . . . .. . . . 93 S6 Materials and supplies, at average cost . . . . . 90 89 Fossil fuel inventory, at average cost . . . . . . . 40 39 Taxes applicable to succeeding years. . . .. . . .. . . . 17t> 168 Other. .. . . . . 3 5 607 655 Deferred Charges and Other Assets Amounts due from customers for future federalincome taxes. 583 674 Unamortized loss on reacquired debt . . . . 64 50 i

Carrying charges and operating expenses, phase-in . . . .. 620 568 Carrying charges and operating expenses, other . . . . 413 368 Nuclear plant decommissioning trusts. . . . 23 17 ,

Other. . . . 177 129  !

' 1,880 1.806 I  !

1  ;

Total Assets . . . . . 58.123 57,942 1

The accompanying notes and summary of significant accounting policies are an integral part of this statement.

l l \

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10

l l

i THE CLEVELAND E11CTRIC ILLUMINATING COMPANY AND SUBSIDIARIES l December 31, 1992 1991 (millions of dollars)

CAPITALIZATION AND LIABILITIES Capitali:ation Common shares, without par value: 105.0 million authorized:

79.6 million outstanding in 1992 and 1991 .. . . . . .. . .. $1,241 $1,241 Other paid-in capital . . .. .. . . . .. . . . . 79 79 Retained earnings. . . .. . .. . . . .. .. .. 545 578 Common stock equity .. . . .. . ... .. . .. . . . 1,865 1,898 Preferred stock With mandatory redemption provisions . . . . .. . 314 268 Without mandatory redemption provisions ... .. . .. ... . .. ...... 144 217 Long-ierm debt . . . ... ... . . . . . .. ... .. ... . 2.515 2,683 j 4,838 5,066 l l

Other Noncurrent Liabilitses i Nuclear fuel lease obligations . . . . . . ... . .. . . 177 197 l Other. . . . . .. . . ... .. . . .. . 57 34 234 231 l Current Liabilities

! Current portion of long-term debt and preferred stock . . . .. . . . 310 93 Current portion of nuclear fuel lease obligations . . 67 81 Notes payable to banks and others . .. .. . . . . 10 -

Accounts payable . . . . .. . . .. 104 97

Accounts and notes payable to affiliates. . ... .... 50 59 Accrued taxes . . . . . .. . . . . 291 282 l Accrued interest . . . . . . . . . . 55 53 l Other. .. . . . . . . .. 37 34 924 699 Deferred Credits l Unamortized investment tax credits. .. . . .... .. 250 258 i Accumulated deferred federal income taxes . .. . . . . . 1,392 1,204 l Unamortized gain from Bruce Mansfield Plant sale . . . 359 3 75 Accumulated deferred rents for Bruce Mansfield Plant . .. . . 70 64 Other. . . .... . . . . .. . ... . 56 45 i

' 127 1.946 Total Capitalization and Liabilities. . .. . 58.123 57,942 l

l 1

1 l 11

i Statement of Preferred Stock "* * "IC* *** ^" " ^ * * * " " ^ * "

l Current Call Price De&rnber 31,

1992 Shares '

o Outstanding Per Share 1942 1991 (milhons of doHars)

Without par value,4,000,000 preferred shares authorized  ;

Subject to mandatory redemption: ,

5 7.35 Series C. . 160,000 5 101.00 5 16 5 17 88.00 Series E . . . 24,000 1,026.78 24 27 Adjustable Series M .. 300,000 101.00 30 39 9.125 Series N . ... . . 750,000 104.06 74 74 9150 Series Q . ... . . 75,000 -

75 75 88.00 Series R. . 50,000 -

50 50 90.00 Series S. . . 75,000 ~4 -

343 282 Less: Current maturities 29 14 Total Preferred Stock, teith Mandatory Redemption Provisions . .. . . 5314 5268 Not subject to mandatory redemption:

5 7.40 Series A . . . 500,000 10L00 $ 50 5 50 7.56 Series B . . .. 450,000 102.26 45 45 Adjustable Series L.. . . 500,000 103.00 49 49 Remarketed Series P. 97 100,000.00 9 73 153 217 1

Less: Current maturities 9 Total Preferred Stock, teithout Mandatory Redernption Provisions . S144 5217 The accompanying notes and summary of significant accounting policies are an integral part of this statement.

i i

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i

Notes to the Financial Statements (1) PROPERTY OWNED 1VITH OTHER UTILETIES AND INVESTORS l o t The Company owns, as a tenant in common with other utilities and those investors who are owner-participants in j various sale and leaseback transactions (Lessors), certain generatmg units as listed below. Each owner owns an '

undivided share in the entire unit. Each owner has the right to a percentage of the generating capability of each l unit equal to its ownership share. Each utility owner is obligated to pay for only its respective share of the l

construction and operating costs. Each Lessor has leased its capacity rights to a utility which is obligated to pay for ,

such Lessor's share of the construction and operating costs. The Company's share of the operating costs of these i generating units is included in the Income Statement. Property, plant and equipment at December 31,1992 i includes the following facilities owned by the Company as a tenant in common with other utilities and Lessors: l Construction Owner- Work in in- Owner- ship Plant Progress Service ship Mega- Power in and Accumulated Generating Unit Date Share watts Source Sernce Suspended Derreciation (millions of dollars) l In Service:

i Seneca Pumped Storge. 1970 80.00% 351 Hydro S 62 5 1 5 20 {

Eastlake Umt 5 - 1972 69.80 411 Coal 155 1 -

Davis-Besse . . 1977 51.38 454 Nuclear tv92 9 163 Perry Urut 1 and Common Facilmes . 1987 31.11 371 Nuclear 1,775 5 249 Beaver Valley Unit 2 and Common Facilities I (Note 2) 1987 24.47 201 Nura 1.277 2 185 l Construction Suspended-.

Perry Unit 2 (Note 3(c)) . Uncertain 44.85 540 Nuclear -

371 -

l i

$3 461 $389 $617 Depreciation for Eastlake Unit 5 has been accumulated with all other ni w depreciable property rather than by specific units of depreciable property.

l l (2) UTILITY PLANT SALE AND LEASEBACK TRANSACTIONS The Company and Toledo Edison are co-lessees of Plant leases, the Company would be obligated to 18.26% (150 megawatts) of Beaver Valley Unit 2 make such payments. No payments have been and 6.5% (51 megawatts), 45.9% (358 megawatts) made on behalf of Toledo Edison to date.

and 44.38% (355 megawatts) of Units 1,2 and 3 of the Mansfield Plant, respectively, all for terms of Future minimum lease payments under the operat-ing leases at December 31,1992 are summarized as about 29% vears. These leases are the result of

' " *S sale and leaseback transactions completed in 1987. 7,,

Under these leases, the Company and Toledo F '

Edison are responsible for paying all taxes, msur-y,,,

- cl'ra d s is l l

{,i77wn, o7,,7,,,,,

ance prermums, operation and maintenance costs 1993. 5 63 5 103 and all other similar costs for their interests in the 1994. 63 103 units sold and leased back. The Company and 1995. 63 102 Toledo Edison may incur additional costs in con _ 1996. 63 125 nection with capital improvements to the units. The Company and Toledo Edison have options to buy

[7l g7, ,

, j ]

the mterests back at the end of the leases for the Payments . 51.768 52.658 fair market value at that time or to renew the i leases. Additionallease provisions provide other purchase options along with conditions for Rental expense is accmed on a straight-line basis mandatory termination of the leases (and possible over the terms of the leases. The amount recorded repurchase of the leasehold interests) for events of in 1992,1991 and 1990 as annual rental expense for default. These events include noncompliance with the Mansfield Plant leases was $70 million.

several financial covenants discussed in Note Amounts charged to expense in excess of the lease 10(d). payments are classified as Accumulated Deferred Rents in the Balance Sheet.

As co-lessee with Toledo Edison, the Company is also obligated for Toledo Edison's lease payments. The Company is buying 150 megawatts of Toledo if Toledo Edison is unable to make its payments Edison's Beaver Valley Unit 2 leased capacity under the Beaver Valley Unit 2 and Mansfield entitlement. We anticipate that this purchase will 13

- - - - .--. . . - _ _ _ = _ _ _ - . - - - - .

i

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< t continue at least until 1998. Purchased power ex- (c) PERRY UNIT 2 pense for this transaction was 5108 million,5107  !

million and 5103 million in 1992,1991 and 1900, Perry Unit 2, including its share of the common ,

1 respectively. The future minimum lease payments facilities,is approximately 50% complete. Construc-  !

i associated with Beaver Valley Unit 2 aggregate tion of Perry Unit 2 was suspended in 1985 pend-  !

51.533 billion. ing future consideration of various options. These l options include resumption of full construction (3) CONSTRUCTION AND CONTINGENCIES with a revised estimated cost, conversion to a non-nuclear design, sale of all or part of our ownership l

(a) CONSTRUCTION PROGRAAf share, or cancellation. No option may be imple-  !

. mented without the unanimous approval of the  !

The estimated cost of the Company,s constructwn owners. A request by the Company, which is re- r program for the 1993-1995 period is 5697 million, sponsible fer the construction of Perry Unit 2, for i including AFUDC of 539 million and excluding an extension of the construction license is pending I l nuclear fuel. with the Nuclear Regulatory Commission (NRC).

4 (b) CLEAN AIR LEGISL4T10N In February 1992, the Company purchased Du- l 1

quesne's 13.74% ownership share of Perry Unit 2 l

The Clean Air Act will require, among other things, and all Perry real property for $3.3 million. This i j sigmficant reductions in the emission of sulfur

, purchase increased the Company's ownership I e dioxide m two phases over a ten year period and share of the unit to 44.85%. The remainder is owned nitrogen oxides by fossil-fueled generating units.

by Toledo Edison, Ohio Edison and Pennsylvania  ;

Power.

~

Centerior Energy developed a compliance strategy for the Company and Toledo Edison which was .

submitted to the PUCO in 1992 for review. Center. The license extension request and the purchese of i

) ior Energy subsequently reached agreement with Duquesne*s share do not indicate any plans to I

) intervening parties and is awaiting formal PUCO resume construction of Perry Unit 2. They were j i approval. Centerior Energy also is seeking United made to keep the Company's options open. j l States Environmental Protection Agency ap- t i proval of the Phase 1 plans. The compliance plan if Perry Unit 2 were canceled, the net-of-tax invest- i i which results in the least cost and the greatest ment would have to be written off. Such a write- r

! flexibility provides for compliance with both ff (based on the Company's investment as of the ,

phases through at least 2005. The plan calls for end of 1992) would be about 5263 million. Note -

greater use of low-sulfur coal at some of our units 10(d) discusses more about the effects of a write- l and the banking of emission allowances. The plan ff-would require capital expenditures for the Com~

If a decision were made to convert Perry Unit 2 to a  !

l pany over the 1993-2002 period of approximately nonnuclear design, we would expect to write off a q $172 million for mtrogen oxide control equipment, portion of our investment for nuclear plant con-emission monitoring equipment and plant modifi-struction costs not transferable to the nonnuclear l

cations. In addition, higher fuel and other opera-construction project. .

, tion and maintenance expenses would be incurred. t i The least cost plan also calls for the Company t Perry Unit 2 AFUDC was credited to a deferred l j place a scrubber or other sulfur emission control income account from July 1985 until January 1, l l technology in service at one of its generating plants 1988, when the accrual was discontinued. Tfie total  !

sometime after 2004 with expenditures beginning deferred AFUDC amount of 5124 million is re-  !

in 2001. The anticipated rate increase associated flected in the Balance Sheet as a reduction in the t with the Company's capital expenditures and Perry Unit 2 investment.

higher expenses would be about 1-2% in the late i i

i 1990s. Another increase would be needed after the year 2000, for an aggregate rate increase in the (d) SUPERTUND SITES  !

i range of 3-6%. l

. The Comprehensive Environmental Response, -

Our compliance plan will depend upon future envi- Compensation and Liability Act of 1980 as l ronmental regulations and input from the PUCO, amended (Superfund) established programs ad-  !

! other regulatory bodies and other concerned enti- dressing the cleanup of hazardous waste disposal ,

ties. In addition, we are continuing to monitor sites, emergency preparedness and other issues.  ;

i developments in new technologies that may be The Company is aware of its potential involvement i

! incorporated into our compliance strategy. If a plan in the cleanup of seven hazardous waste sites. The -  !

other than the least cost plan is required, signifi- Company has recorded reserves based on esti-  !

cantly higher capital expenditures could be re- mates of its proportionate responsibility for these l quired during the 1993-2002 period. We believe sites. We believe that the ultimate outcome of these  !

i Ohio law permits the recovery of compliance costs matters will not have a material adverse effect on f l from customers in rates. our financial condition or results of operations.  ;

r 14 I

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(d) NUCLEAR OPERATIONS AND CONTINGENCIES the next 104 weeks. The amount and duration of extra expense could substantially exceed the insur-(a) OPERATING NUCLEAR UNITS ance coverage.

The Company's interests in nuclear units may be impacted by activities or events beyond our control. (c) NUCLEAR DECONTAAflNATION AND Operating nudear generating units have exper- DECOAfMISSIONING ASSESSAfENT ienced unplanned outages or extensions of sched-uled outages because of equipment problems or The Energy Act permits special assessments on new regulatory requirements. A major accident at a investor-owned electric utilities which own nuclear nuclear facility anywhere in the world could cause generating plants for the decontamination and the NRC to limit or prohibit the operation, con. decommissioning of nuclear enrichment facilities struction or licensing of any nuclear unit. If one of operated by the Department of Energy. The assess-our nuclear units is taken out of service for an ments to individual utilities are based upon the extended period of time for any reason, including amount of enrichment services used in prior years an accident at such unit or any other nudear facil- and cannot be imposed for more than 15 years. At ity, the Company cannot predict whether regula. December 31,1992, the Company accrued a liabil-tory authoritics would impose unfavorable rate ity of $19 million for its share of the total assess-treatment. Suh treatment could indude taking our ments. These costs are recorded as deferred charges affected unit out of rate base or disallowing certain since, based on the legislation, the Company be-construction er maintenance costs. An extended lieves the PUCO will allow the recovery of the outage of one of our nudear units coupled with assessments through the Company's fuel cost unfavorable rate treatment could have a material factors.

adverse effect on our fmancial condition and results j of operations. (S) NUCLEAR FUEL The Company has inventories for nudear fuel  ;

(b) NUCLEAR INSURANCE which should provide an adequate supply mio the i The Price-Anderson Act limits the liability of the mid-1990s. Substantial additional nuclear fuel  ;

owners of a nuclear power plant to the amount must be obtained to supply fuel for the remaining i provided by private insurance and an industry useful lives of its nudear generating units. l assessment plan. In the event of a nuclear incident l at any unit in the United States resulting in losses Nudear fuel is financed for the Company and l l in excess of the level of private insurance (cur- Toledo Edison through leases with a special-pur- 3 rently 5200 million), the Company's maximum po. pose corporation. The tal amount of financing i tential assessment under that plan would be 571 currently available under these lease anangements million (plus any inflation adjustment) per inci- s $509 million (5309 million from intermediate-dent. The assessment is limited to $11 million per term notes and $200 million from bank credit ar-year for each nudear incident. These assessment rangements). Financing in an amount up to 5900 iimits assume the other CAPCO companies con _ milhon is permitted. The intermediate-term notes tribute their proportionate share of any ature m the period 1993-1997, with 577 million assessment.

maturing in September 1993. The bank credit  ;

arrangements terminate in October 1993 at which  !

The CAPCO com; anies have insurance coverage time the corporation will obtain alternate financ-for damage to property at the Davis-Besse, Perry ing. As of December 31,1992,5246 million of and Beaver Valley sites (induding leased fuel and nuclear fuel was financed for the Company. The clean-up costs). Coverage amounted to 52.625 Company and Toledo Edison severally lease their billion for each site as of January 1,1993. Damage respective portions of the nuclear fuel and are to property could exceed the insurance coverage obligated to pay for the fuel as it is consumed in a by a substantial amount. If it does, the Company's reactor. The lease rates are based on various inter-share of such excess amount could have a material mediate-term note rates, bank rates and commer-adverse effect on its financial condition and re- cial paper rates.

suits of operations.

The amounts fmanced include nudear fuel in the The Company also has extra expense insurance Davis-Besse, Perry Unit I and Beaver Valley Unit 2 coverage. It includes the incremental cost of any reactors with remaining lease payments for the replacement power purchased (over the costs Company of $46 million,564 million and 523 mil-which would have been incurred had the units lion, respectively, as of December 31,1992. The been operating) and other incidental expenses after nudear fuel amounts fmanced and capitalized also the occurrence of certain types of accidents at our induded interest charges incurred by the lessors nuclear units. The amounts of the coverage are amounting to 59 million in 1992,512 million in 100% of the estimated extra expense per week 1991 and 519 million in 1990. The estimated future during the 52-week period starting 21 weeks after lease amortization payments based on projected an accident and 67% of such estimate per week for consumption are 558 million in 1993,559 million in 15

1 i

1994,556 million in 1995, 554 million in 1996 and amortizations can be accelerated at the option of 550 million in 1997. the Company.

On October 22,1992, the PUCO approved a Rate '

(6) REGUL4TORMfATTERS Stabilization Program as set forth in a joint recom-mendation Sled by the Company, Toledo Edison '

On January 31,1989, the PUCO issued a rate order and certain customer representative groups in-  !

which provided for three annual rate increases for volved in the 1989 rate case settlement. Under the the Company of approximately 9%,7% and 6% Rate Stabilization Program, the Company agreed i effective with bills rendered on and after February to freeze base rates until 1996 and limit subsequent

1,1989,1990 and 1991, respectively. The 6% in- rate increases to no more than 593 million in 1996, crease effective February 1,1991 was reduced to 569 million in 1997 and 554 million in 1998. For 4.35% as 50% of the savings identified by a manage- purposes of any rate increase proceeding in the ment audit were used to reduce the rate increase- 1996-1998 period, the Company agreed to cap op-

The resulting annualized revenue increases in cration and maintenance expenses (other than 1990 and 1991 associated with the rate order were fuel and purchased power) at 57S4 million on a  !

5106 million and 571 million, respectively. consolidated basis for Centerior Energy, subject to

. adjustment for inflation and other specihed ex-  !

Under the January 1989 rate order, a p. nase-m plan penses. During the 1996-1998 period, PUCO ap-was designed so that the three rate mereases, proval of any base rate increases and any j coupled witn tnen-projected sa,ies growth, would additional regulatory accounting measures would provide revenues over the ten years beginning be dependent upon our success in implementing January 1,1989 sufficient to recover all operating cost-reduction and revenue-enhancement initia- i expenses and provide a fair rate of return on the tives. The Company agreed to seek authorization ,

Company s allowed m, vestments m, Perry Unit 1 for acceleration of the post-1998 Mansfield Plant

)

and Beaver Valley Unit 2. Revenues m the nrst unamortized gain in any rate increase proceeding  ;

hve years of the plan were expected to be less than in the 1996-1998 period. See Summary of Signifi-

~

that required to recover operating expenses and cant Accounting Policies.

provide a fair retum on investment. Therefore, the 3 amounts of operating expenses and return on As part of the Rate Stabilization Program, the Com-  !

! investment not currently recovered are deferred pany is allowed to defer and subsequently recover ,

and capitalized as deferred charges. The unrecov- certain costs not currently recovered in rates and '

j ered investment will decline over the period of the to accelerate amortization of certain benefits. Such i phase-in plan because of depreciation and de- regulatory accounting measures provide for rate  !

i ferred federal income taxes that result from the use stabilization by rescheduling the timing of rate >

1 of accelerated tax depreciation. Therefore, the recoverv of certain costs and the amortization of i amount of revenues required to provide a fair certain benefits, thereby preventing what otherwise '

return aiso declines. This results in decreasing would be an erosion in earnings during the 1992-amounts of annual deferrals in the early years of 1995 period. The continued use of these regula-  !

the plan and then increasing amounts of amortiza- tory accounting measures during this period will be ,

tion and recovery in the later years of the plan. dependent upon a continuing assessment and de-i The Company deferred 551 million,5104 million termination that there will be probable recovery i and $196 million in 1992,1991 and 1990, respec- of such deferrals and carrying charges in future j tively, of operating expenses and carrymg charges rates. The aggregate effect of these measures over  ;

pursuant to the phase-in plan. The amount of this period could be as much as $316 million on an  !

) deferrals scheduled to be recorded in 1993 total 516 after-tax basis dependent upon the Company's million. Beginning in the sixth year (1994) and success in implementing cost-reduction and other continuing through the tenth year, the revenue revenue-enhancement initiatives, among other fac-  ;

i levels authorized pursuant to the phase-in plan tors. Such regulatory accounting measures which  ;

were designed to be sufficient to recover that pe- are eligible to be recorded through December 31, i riod's operating expenses, a fair return on the unre- 1995 on an after-tax basis are as follows:

covered investments, and the amortization of the  ;

deferred operating expenses and carrying charges . Deferral of up to $227 million of accrued post-in-  !

recorded during the hrst five years of the plan. The service interest carrying charges, depreciation l phase-in deferrals relating to these two units will expense and property taxes on assets placed in j total $586 million after 1993 and are scheduled to service after February 29,1988. The deferrals ,

be amortized and recovered as follows: $23 million recorded in 1992 were retroactive to January 1, in 1994,566 million in 1995, $114 million in 1996, 1992. Deferrals are based on actual capital ex- {

5166 million in 1997 and 5217 million in 1998. penditures relating to assets placed in service l Additional carrying charges totaling $50 million within the 1988-1995 period. Consequently, the i I

deferred for 1990 and 1991 pursuant to certain deferrals will be lower than $227 million if the  !

provisions of the phase-in plan will also be amor- Company continues to reduce capital expendi-tized and recovered by December 31,1998. These tures. Amortization and recovery of these defer- .

16 i

l rals will occur over the average life of the assets 1992 1991 1990 and will commence with future rate (minins opan-)

recognition. Book income Before Federal Income Tax . . 5299 5376 5338

+ Acceleration of the amortizations of an estimated

$57 million in unrestricted excess deferred taxes T'g"B f 3"' "' 5'"' 'Y 9 02 ms n15 and 518 milhon m unrestricted mvestment tax gocre,,, (o,c,,,,,) in 7,x:

credits available after 1998. The amortizations Depreciation . ,. . (3) (2) 7 commenced October 1,1992. The amortization of Investment tax credits on investment tax credits is reported as a reduction disallowed nuclear plant . - -

(19)

Rate Stabilization . ..

(5) - -

of depreciat. ion expense. Taxes, other than federal income

. Amortization of up to 514 million in interim g1[,,,,, ,

,} 3 T f spent fuel storage accrual balances for Davis-T tal Fednal Income Tax Expense. g gg 51g 5=gg Besse. The amortization commenced October 1, 1992^

Federal income tax expense is recorded in the In-The Company is also allowed to defer and subse- come Statement as follows:

quently recover the incremental expenses associ- 1992 1991 1990 ated with adoption of the accounting standard for (minions of donars) postretirement benefits other than pensions. See Operating Espenses:

Note 8(b). Current Tax Provision. . . . . 5 47 5 75 5 27 Changes in Accumulated Deferred I The Rate Stabilization Program provides for PUCO Federal income Tax: I regulatory approval of certain corporate transac- Accelerated depreciation and tions, including major asset sales, after an evalua- amortizatmn . 32 9 40 i tion of the customer benefit of these transactions. Alternative minimum tax credit . (18) (3) (19)

The Rate Stabilization Program may be renegoti- S'[n[am nI* n 3 l 4 (9) ated under certain force majeure and other Property tax empense. 14 -

(11)

, events. Rate Stabilization . 2 Reacquired debt costs . ... 6 16 2 Deferred Operating Expenses, Net, and Deferred Deferred construction work in Carrying Charges shown in the income Statement progress revenues . -

(2) 11 consist of the following: Deinred fuel asts. (2) (5) 5 Other items . . . . . 4 14 15 1992 1991 1990 Investment Tax Credits. - 11 2 (minions of danars) Total Charged to Operating Deferred Operatmg Expenses. Net: Expenses . 89 106 75 Phase-in . 5(11) $(16) 5(34) Nonoperating Income:

Rate Stabihzation . (33) - -

Current Tax Provision. . (19) (S) (25)

Amortization of Pre-Phase in Changes in Accumulated Deferred Deferrals 9 9 10 Federal Income Tax:

Total . ~)

5(35 ~)

5 (7 ~)

5(24 Wnte-off of nuclear costs.

Rate Stabilization . .

7 6

(12)

Deferred Carrying Charges: AIUDC and carrying charges . 14 32 57 Phase-in: Other items - (3) - -

j Debt . 5 15 5 24 5 52 Total Expense Charged to l

Equity . 25 64 110 Nonoperatmg income . . 5 24 20 Total Phase-in . . . . . 40 88 162 Total Federal Income Tax Expense. 5 94 5130 5 95 Rate Stabilization (Debt) . 19 - -

Total . 5 59 5 88 5162 The Company joins in the filing of a consolidated  !

federal income tax return with its affiliated com- l (7) TEDERAL INCOME TAX panies. The method of tax allocation reflects the benefits and burdens realized by each company's Federal income tax, computed by multiplying in- participation in the consolidated tax return, approx-come before taxes by the statutory rates, is recon- imating a separate return result for each company.

ciled to the amount of federal income tax recorded on the books as follows: In 1990, adjustments for unamortized investment tax credits on the 1988 write-off of nuclear plant investments decreased the federal income tax pro-vision for nonoperating income 519 million. Also in 1990, the resolution of a property tax deduc-tion issue resulted in a reduction in federal income i tax expense of $10 million.

17 i

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4 The adoption of SFAS 109 in 1992 affected certain Net pension and VEROP costs (credits) for 1990 t j Balance Sheet accounts. The most significant im- through 1992 were comprised of the following i pact was an increase in Utility Plant in Service and components: i an offsetting increase in Accumulated Deferred 399, 3 ,93 ,,,g l Federal Income Taxes.

(millions of dollars)  ;

Under SFAS 109, temporary differences and car- ",c d

('g*x[tsearned 5

, ryforwards gave rise to deferred tax assets of $415 during the renod. ... .. $ 10 $9 5 10 (

million and deferred tax liabilities of 51.807 billion Interest cost on prolected beneht

! at December 31,1992. These are summarized as oNigation . 27 25 26 d

follows.* Actual return on plan assets . (19) (99) .3  ;

Net amortization and deferral. . g) _ 50 g) y Millions of Net pension costs (credits) . (17) (15) (11)  !

Dollar 8 VEROP cost, - -

8 )

Property, plant and equipment . . 51.468 ~ ***"' E'I" ^ ~ ~

EI Deferred carrying charges and operating expenses. 249 Net costs (credits) . 52) 52 ) p)

S Sale and leasebacL transactions. (123)

Net operating loss carryforwards . (79) ment tas credits . The following table presents a reconciliation of the [

(13 )

4 funded status of the plan at December 31,1992 and  ;

4 1991.

Net deferred tax liabihty . $1.392 4 December 31.

4 For tax purposes, net operating loss (NOL) car- 1992 299'  !

j r ryforwards of approximately $234 million are avail- (millim of  ;

able to reduce future taxable income and will Actuarial present value of bene 6t obligations-. i

, expire in 2003 through 2005. The 34% tax effect of vested bene 6ts . 5 215 5 209 j the NOLs is 579 million. Nonvested benehts . 28 23 Accumulated beneht obligation 243 232

} The Tax Reform Act of 1986 provides for an alter- Effect of future compensation levels . 86 79 l native minimum tax ( Ah1T) credit to be used to Total projected beneht obligation. 329 311 i reduce the regular tax to the Ah1T level should the Plan assets at fair market value . sss 585 l regular tax exceed the Ah1T. Ah1T credits of 574 surplus of plan assets over projected benent i

million are available to offset future regular tax. obligation . .. 256 274 i The credits may be canied forward indefinitely. Unrecogruzed net gain from varienw l a

between assumptions and experience . (107) (137)  :

Unrecognized prior service cost . . 7 8 i (S) RETIREMENT AND POSTEMPLOYMENT Transition asset at lanuary 1.1987 being l BENETITS amortized over 10 years . (82) (88)

! Net prepaid pension cost . $ 74 5 57 l (a) RETIREMENT INCOA1E PLAN At December 31,1992 and 1991, the settlement The Company and Service Company jointly spon.

! sor a noncontributing penuon plan which covers (discount) rate and long-term rate of return on all employee groups. The amount of retirement plan assets assumptions were 8.5% and the long- ,

benefits generally depends upon the length of ser. term rate f annual compensation mcrease assump- l vice. Under certain circumstances, benefits can ti n was 5%.  ;

begin as early as age 55. The plan also provides Plan assets consist primarily of investments in com-  !

l certain death, medical and disability benefits. The mon stock, bonds, guaranteed investment con-  !

funding policy of the Company and the Service tracts, cash equivalent securities and real estate.

Company is to comply with the Employee Retire- ,

ment Income Security Act of 1974 guidelines.

(b) OTHER POSTRETIREMENT BENETITS [

! In 1990, the Company and Service Company of- The FASB accounting standard for post etirement i fered a Voluntary Early Retirement Opportunity f benefits other than pensions (SFAS 106) requires Program (VEROP). Operating expenses for both the accrual of the expected cost of such benefits companies for 1990 included 58 million of pen- during the employees' vears of service. The as-sion plan accruals to cover enhanced VEROP bene- sumptions and calculations involved in determin-l fits and an additional 520 million of pension costs ing the accrual closely parallel pension accounting i for VEROP bene 6ts paid to retirees from corpo- requirements.

rate funds. The 520 million is not included in the pension data reported below. A credit of 536 mil- The Company currently provides certain postretire-lion resulting from a settlement of pension obli- ment health care, death and other benefits and f gations through lump sum payments to a expenses such costs as these benents are paid, substantial number of VEROP retirees partially off- which is consistent with current ratemaking prac-  !

set the VEROP expenses for both companies. tices. Such costs totaled 55 million in 1992,-56  !

l 18 }

t

. - .-- ., - - . .-- . .~. .

I I

million in 1991 and 55 million in 1990, which (70) CAPITAllZATION l included medical benefits of 54 million in 1992,55 '

million in 1991 and 54 million in 1990. (a) CAPITAL STOCK TRANSACTIONS The Company will adopt the standard effective Preferred stock shares sold and retired during the January 1,1993. The Company plans to amortize three years ended December 31,1992 are listed in i the present value of the accumulated post- the following table. l retirement benefit obligation to expenst over a 20- iggy 199; 3999 l year period. Based on our actuaries' review of 1992 psards of sharn) t data, the accumulated postretirement benent obli- subject to Mandatory Redemnon:

gation as of December 31,1992 is estimated to be in Sales the range of $110 million to $140 million (pretax). 5 yy[ [ $ [ .

Had the standard been adopted in 1992, the addi- 90.00 series S . 75 - -

i tional 1992 postretirement benent cost would have Retirements been in the range of $10 million to 514 million (pretax). The Company believes the 1993 effect of 5gy{ ]j ]j ]jj '

75.00 senes F . . -

p) -

actual adoption may be similar, although it could 80.00 series G . - -

0)  ;

be significantly different because of changes in 14510 series R - -

04) j health care costs, the assumed health care cost $ N I{ , _ Z h] [  ;

trend rate, work force demographics, plan e Adjustable Series M (100) 000) -

f sions or interest rates. Like the retiremen* ma.ne Not subject to Mandatory Redemption: f plan, these estimates reflect a discount rate assump- Retirements tion of 8.5% per year. The annual health care cost Remarketed senes P . J) - -

trend assumption is 12% in 1992, reducing gradu- Net change. J39) J1,4) ,p2)

- ly to an ultimate annual rate of 6% in 1996 and ,

'Y'

(b) EQUITY DISTRIBUTION RESTRICTIONS The PUCO authorized the Company to defer for t subsequent recovery postretirement' beneht costs At December 31,1992, consolidated retained earn-that exceed its actual payments for the period 1993_ ings were 5545 million. The retained earnings 1 1997. This provision was part of the Rate Stabil _ were available for the declaration of dividends on zation Program discussed in Note 6. The amount the Company's preferred and common shares. All we can defer will be determined by the extent to of the Company's common shares are held by j which Centerior Energy is successful in reducing Centerior Energy.  !

the added obligation on a consolidated basis by $37 Any 14nancing by the Company of any of its non-million or 25% of the incremental costs expected ~

utility affiliates requirm PUCCiauthorizztion un-  :

when the Company got the order. The Company less the fmancing is n.ade in connection with and Centerior Energy have until December 31,1997 transactions in the ordinary course of the Com-to make the reductions.

pay's public utilities business operations in which  !

" ' ' "P#"Y " ~ " "

(c) POSTEMPLOYMENT BENETITS In November 1992, the FASB issued a new account- (c) PRETERRED AND PREFERENCE STOCK l ing standard for postemployment benefits (SFAS t 112), such as severance pay, disability, worker's Amounts to be paid for preferred stock which must compensation and supplemental unemplovment be redeemed d ating the next hve years are $38 benefits. The Company is required to adopt the

~

million in 1993,529 million in 1994,540 million in new standard no !ater than 1994. We have not 1995 and $30 million in both 1996 and 1997.

completed an analysis to determine the effect of The annual preferred stock mandatory redemption adopting the new standard. provisions are as follows:

(9) GUARANTEES Sh"'" Pn" To Be Beginnmg Per The Company has guaranteed certain loan and Redermed m share lease obligations of two mining companies under 5 7.35 senes C . 10,000 1984 $ 100 two long-term coal purchase arrangements. One of 88.00 senes E 3.000 1981 1.0Co these arrangements requires payments to the min- Adiustable senes M. 100,000 1991 100 ing company for any actual out-of-pocket idle mme expenses (as advance payments for coal) 9[sfnesQ 1 8810 series R , 50,000 200l* 1,0(o when the mines are idle for reasons beyond the n00 senes s 18.750 1999 1,0(o control of the mining company. At Decernber 31, . All outstanding shares to be redeemed on December 1,2001.

1942, the principal amount of the mining compa-nies' loan and lease obligations guaranteed by the The Company has called for redemption the re-Company was 571 million. maining 97 outstanding shares of its Serial Pre-19

l ferred Stock, Remarketed Series P,in August 1993 The Company issued 5578 million aggregate princi-at a redemption price of 5100,000 per share. pal amount of secured medium term notes during the 1990-1992 period. The notes are secured by i The annualized preferred dividend requirement as hrst mortgage bonds. At December 31,1992, the j of December 31,1992 was 542 million. Company had 535 million aggregate principal i amount of secured medium-term notes registered The preferred dividend rates on the Company's with the Securities and Exchange Commission and j Series L, M and P fluctuate based on prevailing available for issuance.

! interest rates and market conditions. The dividend rates for these issues averaged 7.59%, 7.04% and The Company's mortgage constitutes a direct first

• 6.73%, respectively, in 1992. lien on substantially all property owned and franchises held by the Company. Excluded from Preference stock authorized for the Company is the lien, among other things, are cash, securities, 3,000,000 shares without par value. No preference accounts receivable, fuel and supplies. )

i shares are currently outstanding. There are no

• restrictions on the Company's ability to issue pre- Additional first mortgage bonds may be issued by ferred or preference stock. the Company under its mortgage on the basis of l bondable property additions, cash or substitution With respect to dividend and liquidation rights, the for refundable hrst mortgage bonds The issuance  !

Company's preferred stock is prior to its prefer. of additional first mortgage bonds on the basis of  :

ence stock and common stock, and its preference Property additions is limited by two provisions of  !

stock is prior to its cemmon stock. our mortgage. One relates to the amount of bondable property available and the other to earn-(d) LONG-TERM DEBT AND OTHER "E' ' * E' *' *" '

m re restrictive f these provisions (currently,'the BORROWING ARRANGEMENTS amount of bondable property available), the Com-Long-term debt, less current maturities, was as pany would have been permitted to issue approx-follows: imately 5329 million of bonds based upon available bondable property at December 31,1992.

,77,'h The Company also would have been permitted to -

J interest issue approximately 5432 million of bonds based Rate at upon refundable bonds at December 31,1992. If '

purmber 31. D"'*h" 31-Perry Unit 2 had been canceled and written off as Year of Matunty 1992 1992 1991 of December 31,1992, the Company would not

(**"5 "I have been permitted to issue any bonds based ,

H upon available bondable property, but would have First mortgage bonds:

1993 . 3.875 % 5 - 5 30 been permitted to issue approximately 5432 mil-l 1993 8.55 -

50 lion of bonds based upon refundable bonds.

3 1993 . 13.75 -

4 tw4 4.375 25 25 .

An agreement relating to a letter of credit issued in 7

$, $ j j connection with the sale and leaseback of Beaver l 1

1995 . 7.00 1 1 Valley Unit 2 contains several financial covenants  !

1946 . 13.75 4 4 affecting the Company, Toledo Edison and Center- t Q- [g' [ [ ior Energy. Among these are covenants relating to 1997 . 13.75 4 4 earnings coverage ratios and capitalization ratios.

1997 ..... 7.00 1 1 The Company, Toledo Edison and Centerior En-3 1

$$ N 2008-2012.

8.20 b

310 IN 410

• rgy are in compliance with these covenant provi-sions. We believe these convenants can still be met .

2013 2017. 8MO 538 663 in the event of a write-off of the Company's and  !

2018-2022. 7.84 337 337 Toledo Edison's investments in Perry Unit 2, bar-2023 . 5E5 1 ring unforeseen circumstances.

Term bank loans due 1494-1996. ... 7.31 8 81 (n) SHORT-TERM BORROWING ARRANGEMENTS +

Medium-term notes due 1944-2021. .... .... 8.95 678 700 The Company had 5137 million of bank lines of ronution amtrol notes due credit arrangements at December 31,1992. This othIr et . Y included a 530 million line of credit which provided Total long-Term Debt . 52.515 52.683 a 15 million line of credit to be available to the Service Company if unused by the Company.

There were no borrowings under these bank credit long-term debt matures during the next five years arrangements at December 31,1992.

as follows: 5272 million in 1993,542 million in 4

1994,5206 million in 1995,5151 million in 1996 and Short-term borrowing capacity authorized by the

555 million in 1997. PUCO annually is $300 million for the Company.

20

~

j The Company and Toledo Edison are authorized rates (or other appropriate rates) for similar issues by the PUCO to borrow from each other on a and loans with the same remaining maturities.

short-term basis.

The estimated fair values of all other financial  ;

Most borrowing arrangements under the short- instruments approximate their carrying amounts in term bank lines of credit require a fee of 0.25% the Balance Sheet at December 31,1992 because of per year to be paid on any unused portion of the their short-term nature.

lines of credit. For those banks without fee requirements, the average daily cash balance in the Company's bank accounts satisfied informal (13) QUARTERLY RESULTS OF OPERATIONS compensating balances. (UNAUDITED)

At December 31,1992, the Company had $10 mil- The following is a tabulation of the unaudited lion of short-term notes outstanding under an quarterly results of operations for the two years uncc,mmitted financing facility. The Company can ended December 31,1992.

borrow up to $40 million until the agreement is p,,,,,,,sEnded canceled by either party. Maa 31. Me 3a v 30, Dec 3L At December 31,1992, the Company had no com- (minwns of.tonars) I I

mercial paper outstanding. If commercial paper 1992 were outstanding, it would be backed by at least Operating Revenues. $422 5415 $479 $427 an equal amourit vi unused bank lines of credit. *jEn " . 7 3 Earnings Available for (12) TINANCIAL INSTRUAfENTS'TAIR VALUE Common Stock . 17 23 92 32 1991 The estimated fair values at December 31,1992 of Operating Revenues. $431 $456 $513 $421 i financial instruments that do not approximate Operating income. 90 102 139 84 l their carrying amounts are as follows: Net Inmme . . . 38 52 95 61 l Earnmgs Available for Carrving Tsi' Common Stock . . 29 43 66 52 A mount Value (minions of Earnings for the quarter (nded September 30,1992 l 4 nors) were increased by $26 million as a result of the l Nuclear riant Decomnusuorung Trusts . 5 23 5 24 recording of deferred operating expenses and car-Preferred Stock with Mandatory rying charges for the first nine months of 1o92 tNrtiInN " "

1.ong-Term Debt (including current 343 342 totaling $39 million under the Rate Stabilization Program approved by the PUCO in October 1992.

portion) . 2.793 2Ss6 See Note 6.

The fair value of the nuclear plant decommission- Eamings for the quarter ended December 31,1991 ing trusts is estimated based on the quoted market were increased by $33 million as a result of year-prices for the investment securities. The fair value end adjustments of $18 million to r(duce depreci-of the Company's preferred stock with mandatory ation expense for the year for the change in the redemption provisions and long-term debt is es- nuclear plant straight-line depreciation rate to 2.5%

timated based on the quoted market prices for the (see Summary of Significant Accounting Policies) respective or similar issues or on the basis of the and $29 million to increase phase-in c4rrying discounted value of future cash flows. ihe dis- charges for an adjustment to 1991 cost deferrals counted value used current dividend or interest (see Note 6). ]

l l

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I

i Financial and Statistical Review Operating Revenues (millions of dollars) l' Total Total Total Steam Operanng lear Residential Commercial Industnal Other Retail W1.nlesale Dertne Heaung Revenues 1992. 5517 531 530 101 1 679 64 1 743 -

51 743 1991. 547 540 547 117 1 751 75 1 826 -

1 826 1990. 495 494 544 123 1 656 35 1 691 -

1 691 1989. 470 453 520 117 1 560 74 1 634 -

1 634 1988. 436 395 476 60 1 367 86 1 453 -

1 453 a

1982. 349 305 394 35 1 083 17 1 100 18 1 118 Operating Expenses (millions of dollars)

Other Deferred Iuel & Operaten Depreciation Taxes, Operanng Federal Total Purchami & & Other Than Expenses, Income Operaung icar Power Mamtenance Amornzanon l'It Net Taxes I xpenses 1992. 5434 465 179 226 (35) 89 51 358 1991. 455 470 171(a) 216 (7) 106 1 411 1990. 412 514 170 197 (24) 75 1 344 1989. 427 508 188 183 (42) 85 1 349 1950. 308 524 190 185 (104) 95 1198 1982. 339 250 87 107 -

106 889  ;

income (millions of dollars)  ;

Federal Other income income income & Deferred Iases- Before i Operaung AFUDC- Deductmns. Carrymg Credit Interest (

) ear hcome Equerv Net Charges (1 upenw ) Charges

{

1992. 5385 1 8 59 (5) 5448  !

1991. 415 8 6 88 (24) 493 1990. 347 5 1 162 (20) 495 l 1989. 285 8 9 235 (56) 481 1988. 255 8 (243)(b) 225 53 298 ,

1982. 229 77 (2) -

22 326 income (millions of dollars) ,

Income Before Cumulative Cumulative Preferred & Earnmgs Effect of an Effect of an Preference Available for Debt AFUDC- A counung Accountmg Net Stock Common har Interest Debt Change Change income Dmdends Sta k 1992. 5243 -

205 -

205 41 5164 j l'91. 251 (4) 246 -

246 36 210 1990. 255 (3) 243 -

243 37 206 <

1989. 23S (7) 250 -

250 40 210 1988. 229 (4) 73 22(c) 95 42 53 1982. 144 (27) 209 -

209 38 171 i (a) In 1991 a change in accounting for nucicar plant depteciation was adopted, changing from the units-of-production method to the straight-line l method at a 2.5% rate.

l (b) Includes write-off of nudcar costs in the amount of $257 milhon in 1988.

(c) in 1988, a change in the method of accounting for unbilled revenues was adopted.

I l

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1 I

i THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES l

Electric Sales (millions of KWH) Electric Customers (year end) Residential Usage Average Average Average Pnce Revenue Industnal KWH Per Per Per Rendential Commernal & Other Year Rendential Commernal Industnal Wholesale Other Total Total Customer KWH Customer l

1992. 4 725 5 467 7 988 1989 533 20 702 669 800 70 943 8 375 749 118 7 071 10.94c $773.77 1991. 4 940 5 493 8 017 2 442 565 21 457 667 495 70 405 8 398 746 298 7 170 11.08 797.25 t

1990. 4 716 5 234 8 551 1 607 463 20 571 665 000 68 700 8 351 742 051 6 867 10.53 723.15 1989. 4 789 5 208 8 780 2 132 501 21 410 660 786 68 030 8 329 737 145 7 025 9.81 691.83 1988. 4 852 4 998 9 013 749 472 20 034 657 592 66 606 8 203 732 401 7 152 8.99 646.35 1982. 4 336 4 194 7 082 687 414 16 713 641 705 61 861 7 656 711 222 6 490 8.08 524.63 j Load (MW & %) Energy (millions of KWH) Fuel l Operable Capaary Ifficiency-

! Company C.enerated I

at Time Peak Capaaty Inad Purthased Fuel Cost BTU Per Year of Peak tread Margm f actor Fouil Nuclear Total Power Total Per KWH 5:WH 1992. 4 703 3 605 23.3 % 63.0 % 12 715 7 521 20 236 1 649 21 885 1.47c 10 456 l 1991 4 695 3 886 17.2 61.8 13 193 7 451 20 644 2 144 22 788 1.49 10 503 1000 . 4 685 3 778 19.4 63.3 15 579 5 262 20 841 964 21 805 1.52 10 417 1989. 4 536 3 666 14.8 65.2 14 968 6 570 21 538 1 268 22 806 1.49 10 506 1988- 4 46S(d) 4 067 9.0 59.8 15 756 4 480 20 236 1 359 21 595 1.59 10 517 1982 . 4 649 3 090 34.2 65.3 15 576 1 650 17 226 766 17 992 1.83 10 475 Investment (rnillions of dollars)

Constructmn h ork in Total Utibry Acrumulated Progress Nuclear Property. Unlity Plant In Deprenation & Net & Perry Fueland Plant and Plant Total T ear Servue Amoruzanon Plant Umt 2 Other Egnpment Additions Assets 1992. 56 602 1 728 4 874 501 261 55 636 5156 58 123 1991 6 196 1 565 4 631 545 305 5 481 150 7 942 l

1990. 6 032 1 398 4 634 572 344 5 550 165 7 821 1989 . 5 869 1 259 4 610 603 354 5 567 144 7 546 1988. 5 705 1 082 4 623 639 381 5 643 211 7 332 1982. 2 725 680 2 045 1 286 158(e) 3 489 422 3 974 Capitalization (millions of dollars & %)

l Preferred & Preference Preferred Stock without

! Stock, with Mandatory Mandatory Redempton

) ear Common Stock I.quity Redempton Proviuuns Provisicms 14mg Term Debt Total 1992. 51 865 39% 314 6% 144 3% 2 515 52% 54 838 1991 - 1898 38 268 5 217 4 2 683 53 5 066 1990 . . 1 884 38 1 71 3 217 4 2 632 55 4 904 1989. 1 828 40 212 4 217 5 2 336 51 4 593 1988 . 1 780 40 233 5 217 5 2 260 50 4 490 1982 . 1227 40 322 10 95 3 1 442 47 3 086 (d) Capaaty data reflects extended generating unit outage for renovation and improvements.

(e) Restated for effects of capitalization of nuclear fuel lease and fmancing arrangements pursuant to Statement of Dnancial Accounting Standards 71 23

i l

Investor informa on SilARE OWNER INFORMATION o SilARE OWNER SER\1CES INDEPENDENTACCOUNTANTS Communications regarding stock transfer requirements, Arthur Andersen & Co i lost certificates, dividends and changes of address 1717 East Ninth Street should be directed to Share Owner Services at Centenor Cleveland OH 44114 Energv Corporation Correspondence should be sent to the address mdicated below for the Stock Transfer ENrlRONhfENTAL REPORT Agent, To reach Share Owner Sen ices by phone, call: The Company will furnish to share owners. without charge, a copy of a report on its environmental In Cleveland area 642-6900 or 447-2400 a be dacctd to %are mmana equens Outside Cleveland area 1-800-433-7794 Owner Serv ces.

Please have your account number ready when calhng' FORAf 10-K  ;

STOCK TRANSEER AGENT The Company will furnish to share owners, without Centerior Energv Corporanon c harge, a c opy of its most recent annual report to the Share owner serv ces Secunties and Exchange Commission Requests should PO. Box 94661 be directed to Share Owner Services.

Cleveland OH 94101-4061 Stock transfers may be presented at BONDlIOLDER INEORMATION PNC Trust Company of New York BOND TRUSTEE 40 Broad Street. Fifth Floor Morgan Guaranty Trust Company of New York New York NY 10004 Corporate Trust Admmistranon 60 Wall Street i STOCK PEGISTRAR New Yotk NY 10260 l Society . 'anonal Bank (212)235-0602 Corporatt Trust Division .

PO. Box 641.' BOND PAYING AGENT Cleveland OH 44101 Inqumes regardmg mierest paymer:ts should be INVESTOR RELATIONS 0 " b '* ' '*' " ' '"

inquines from secunty analysts and msntunonal duc 1994 or Morgan Guaranty Trust Company of N,ew T rk for all other series of bonds investors should be directed' to Terrence R Moran, Manager-Investor Relanons. at the address of the stock Chemical Bank .

Transfer Agent or by telephone at (216) 447-2882. Bondho! der Relations (

450 W. 33rd Street,8th Floor r EXCilANGE LISTINGS New Tork NY 10001 Preferred Stock Senes A B and L are listed on the 1.g00 648-8380 New York stock Exchange {

Morgan Guaranty Trust Company of N,ew York  ;

Securityholder Relatmns ,

Di\TDEND REIN \T.SThfENT AND STOCK PURCllASE '

60 Wall Sircet PLAN AND INDi\1 DUAL RLTIREhfENT ACCOUNT Newyork Ny 10260 (CX *1RA) (212) 235 0602 l Centerior Energy Corporation has a Dividend  ;

l Reinvestment and Stock Purchase Plan which provides

! Cleveland Electnc share owners of record and other investors a convenient means of purchasing shares of Centerior common stock by mvestmg all or a part of L their quarterly dividends as well as makmg cash mvestments. In addition, individuals may estabhsh an Individual Rentement Account (IRA) which invests m j Centerior common stock through the Plan. Information relating to the Plar and the CX* IRA may be obtamed from Share Owner Services.

f 1

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