ML20044D303

1992 Annual Rept for Toledo Edison Co.

ML20044D303
Person / Time
Site:	Beaver Valley
Issue date:	12/31/1992
From:	TOLEDO EDISON CO.
To:
Shared Package
ML20044D300	List: ML20044D299 ML20044D301 ML20044D303 ML20044D304 ML20044D308 ML20044D318
References
NUDOCS 9305180478
Download: ML20044D303 (25)

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• THE TOLEDO EDISBN COMPANY A Suh.sidiary of Centerior Energy Corporation I

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i ANNU AL REPOR T 2

. 9305180478 930506

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- Contents 8 About Toledo Edison l o I h Directors  !

8 Officers 8 Report ofIndependent Public Accountan ts (

O Summary of Significant ,

Accountmg Pohctes I

h Management's Fmancial Analysis, Fmancial 5tatements ,

and Sotes h Financial and Statistical Review .

InYeStor In[ormation 1

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- About Toledo Edison  !

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The Company, a wholly owned subsidiary of Centenor RobertJ. Farlmg. Chairman, President and Chief ,

" " Executive Officer of Centenor Energy Corporanon and Energy Corporatmn, provides electnc service to about 660.000 people in a 2,500-square mde area of Centerior Service Company. ,

northwestern Ohio includmg the City of Toledo The . .

Edgar H. Mangans, Vice President & Chief Fm.ancial  ;

Company also proudes electiic energy at wholesale to Officer of the Company and The Cleveland Electnc 13 municipa!!y owned distnbution systems and one Illuminating Company and Executive Vice President of rural electnc cooperative distnbution system in its Centenor Energy Corporation and Centerior Seruce service area The Company's 2.400 employees serve about 286,000 customers Company.

Lyman C. Philhps. Chairman and Chief Executive Officer of the Company. President and Chief Executive Officer of The Cleveland Electric illuminating Company and Executive Vice President of Centenor Energy

- Executive Offices- Corporanon and Centerior Seruce Company.

Donald H. Saunders, President of the Company and Vice

• The Toledo Edison Company President of Centerior Service Company.

O 300 Madison Avenue Toledo OH 43652-000)

(419)249-5000 Chairman and Chief

" Executive Officer . .Lyman C. Phdhrs President Donald H. Saunders Vice President & Chief Fmancial Officer Edgar H. Maugans Vice President . FredJ. lange,Jr Controller . Paul G. Busfy Treasurer . Gary M. Hawkmson Secretary E. Lyle IYpm 1

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Report of Independent Pub c Accountants ARTHUR ANDERSEN To the Share Owners of o The Toledo Edison Cornpany:

. We have audited the accompanying balance sheet and operations and its cash flows for each of the three statement of preferred stock of The Toledo Edison years in the period ended December 31,1992, in ,

Company (a wholly owned subsidiary of Centerior conformity with generally accepted accounting Energy Corporation) as of December 31,1992 and principles.

1991, and the related statements ofincome, retained . ..

earnings arid cash flows for each of the three years in As discussed further in the Summary of Sigmficant ,

the period ended December 31,1992. These financial Acc unting Policies, a change was made in the ,

statements are the responsibility of the Company's method of accountmg for nuclear plant depreciation '

management. Our responsibility is to express an o' pin- in 1991, retroactive to January 1,1991. ,

ion on these financial statements based on our audits. As discussed further in Note 3(c), the future of Perry We conducted our audits in accordance with generally Unit 2 is undecided. Construction has been sus-accepted auditing standards. Those standards require- pended since July 1985. Various options are being that we plan and perform the audit to obtain reason _ c nsidered, mcludm, g resummg construction, con-able assurance about whether the financial statements verting the unit to a nonnuclear design, sale of all or i are free of material misstatement. An audit includes part of the Company's ownership share, or canceling d

examining, on a test basis, evidence supporting the the um,t. Management can give no assurance when, amounts and disclosures in the financial statements. if ever, Pcrry Unit 2 will go in service or whether the  ;

An audit also includes assessing the accounting princi_ Company,s investment m, that unit and a return ples used and significant estimates made by manage _ thereon will ultimately be recovered.

ment, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. g In our opinion, the financial statements referred to above present fairly,in all material respects, the finan-a cial position of The Toledo Edison Company as of Cleveland, Ohio l

December 31,1992 and 1991, and the results of its February 12,1993 P

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i Summary of Significant Accounting Po cies GENERAL nuclear fuel disposal costs are being recovered The Toledo Edison Company (Company) is an elec_ through the base rates.

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

sion (FERC) and adopted by The Public Utilities Commission of Ohio (PUCO). As a rate-regulated utility, the Company is subject to Statement of Finan. DEEERRED CARRYING CHARGES cial Accounting Standards (SFAS) 71 which governs AND OPERATING EXPENSES accounting for the effects of certain types of rate As discussed in Note 6, the January 1989 PUCO rate regulation. order for the Company induded an approved rate The Company is a member of the Central Area Power phase-in plan for its investments in Perry Nudear Coordination Group (CAPCO). Other members in- Power Plant Unit 1 (Perry Unit 1) and Beaver Valley clude The Cleveland Electric illuminating Company P wer Station Unit 2 (Beaver Valley Unit 2). The (Cleveland Electric), Duquesne Iight Company (Du. plan called for the Company to begm deferring in

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quesne), Ohio Edison Company (Ohio Edison) and January 1989 operating expenses and both interest Ohio Edison's wholly owned subsidiary, Penn- and equity carrying charges on deferred rate-based sylvania Power Company. The members have con. myestment. These deferrals, called phase-m deferrals,

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structed and operate generation and transmission will be amortized and recovered by December 31, facilities for their use. Cleveland Electric is also a 1998. Previously, the PUCO authorized the Company -

wholly owned subsidiary of Centerior Energy. to defer operating expenses and carrying charges for Perry Unit 1 and Beaver Valley Unit .2 from their respective in-senice dates in 1987 through December RELATED PARTY TRANS4CTIONS 1988. The amortization and recovery of these defer-Operating revenues, operating expenses and interest rals, called pre-phase-in deferrals, also began in Janu-charges include those amounts for transactions with ary 1989 and will continue over the lives of the affiliated companies in the ordinary course of busi. related property.

ness operations. Beginning in January 1992, the Company deferred The Company's transactions with Cleveland Electric charges for depreciation, property taxes and interest are primanly for firm power, interchange power, carrying charges related to plant placed m service after transmission line rentals and jointly owned power February 29,1988 and not yet mduded m rate base.

plant operations and construction. See Notes 1 and 2. The PUCO authonzed these deferrals m,, October 1992 under a Rate Stabilization Program. Similar deferrals l Centerior Service Company (Service Company), the may be recorded through December 31,1995. Amorti-l third wholly owned subsidiary of Centerior Energy, zation and recovery of these deferrals will occur over l provides management, fmancial, administrative, engi- the average life of the assets and will commence I neering, legal and other services at cost to the Com- with future rate recognition. See Notes 6 and 13. The pany and other affiliated companies. The Service Company is also deferring operating expenses l Company billed the Company 560 million,561 mil- equivalent to an accumulated excess rent reserve for lion and $49 million in 1992,1991 and 1990, respec- Beaver Valley Unit 2 over a 39 month per;od com-tively, for such services. mencing October 1,1992. Amortization and recovery of this deferral will occur over the unit's remaining l REFENUES lease term beginning in 1996. See Note 6.

l Customers are billed on a monthly cycle basis for their energy consumption based on rate schedules or con. DEPRECIATION AND AAf0RTIZATION tracts authorized by the PUCO or on ordinances of

, The cost of property, plant and equipment is depreci-mdividual municipalities. An accnial is made at the ated over their estimated useful lives on a straight-end of each month to record the estimated amount of line basis. The annual straight-line depreciation pro-unbilled revenues for kilowatt-hours sold in the cut- vision for nonnudear property expressed as a per-rent month but not billed by the end of that month. cent of average depreciable utility plant in senice was A fuel factor is added to the base rates for electric 3.6% in 1992,3.4% in 1991 and 3.3% in 1990. Effective service. This factor is designed to recover from cus. January 1,1991, the Company, after obtaining tomers the costs of fuel and most purchased power. It PUCO approval, changed its method of accounting is reviewed and adjusted semiannually in a PUCO f r nudear plant depreciation from the uruts-of-pro-proceeding. duction method to the straight-line method at about a 3% rate. This change decreased 1991 depreciation expense $14 milli n and increased 1991 net income EUEL EXPENSE 511 million (net of 53 million of income taxes) from The cost of fossil fuel is charged to fuel expense based what they otherwise would have been. The PUCO on inventory usage. The cost of nuclear fuel, indud- subsequently approved in 1991 a change to lower the ing an interest component. is charged to fuel expense 3% rate to 2.5% retroactive to January 1,1991. See based on the rate of consumption Estimated future Note 13.

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l The Company uses extemal funding of future decom- INTEREST CHARCES I missioning costs for its operating nuclear units pursu-ant to a PUCO order. Cash contributions are made to Debt Interest reported in the Income Statement does the trust funds on a straight-line basis over the re- not include interest on obligations for nuclear fuel maining licensing period for each unit. The current under construction. That interest is capitalized. See level of expense being funded and recovered from Note 5. t customers over the remaining licensing periods of the '[

units is approximately $4 million annually. Amounts losses and gains realized upon the reacquisition or  ;

currently in rates are based on past estimates of redemption of long-term debt are deferred, consistent .

decommissioning costs of $59 m9 lion in 1986 dollars with the regulatory rate treatment. Such losses and for the Davis-Besse Nuclear Power Station (Davis- gains are either amortized over the remainder of the Besse) and $28 million in 1987 dollars each for Perry originallife of the debt issue retired or amortized Unit I and Beaver Valley Unit 2. Actual decommis- over the life of the new debt issue when the proceeds  ;

sioning costs are expected to significantly exceed of a new issue are used for the debt redemption. The l these estimates. We expect to complete our assess- amortizations are included in debt interest expense.  :

ment of these estimates in 1993 to update the decom- i missioning cost amounts and to continue to satisfy  !

the external funding requirements. It is expected that TEDERAL INCOAfE TAXES increases in the cost estimates will be recoverable in future rates. The present funding requirements for The Financial Accounting Standards Board (FASB)

Beaver Valley Unit 2 also satisfy a similar commitment issued a new standard for accounting for income taxes made as part of the sale and leaseback transaction (SFAS 109) in February 1992. We adopted the new ,

i discussed in Note 2. In the Balance Sheet at December standard in 1992. The new standard amends certain 31,1992, Accumulated Depreciation and Amortiza- provisions of SFAS 96 previously adopted in 1988. .

tion included $26 million for the cumulative total of Adoption of the new standard in 1992 did not materi- I decommissioning costs previously expensed and the ally affect our results of operations, but did affect  ;

earnings on the external funding. This amount ex- certain Balance Sheet accounts. See Note 7. j ceeds the Balance Sheet amount of the external Nu- ,

clear Plant Decommissioning Trusts because the The financial statements reflect the liability method of reserve began prior to the external trust funding. accounting for income taxes. This method requires that deferred taxes be recorded for all temporary i differences between the book and tax bases of assets PROPERTY, PLANT AND EQUIPAfENT and liabilities. The majority of these temporary dif- '

Property, plant and equipment are stated at original ferences are attributable to property-related basis dif-

cost less any amounts ordered by the PUCO to be ferences. Included in these basis differences is the

! written off. Construction costs include related payroll equity component of AFUDC, which will increase I taxes, pensions, fringe benefits, management and future tax expense when it is recovered through rates.

] general overheads and allowance for funds used dur. Since this component is not recognized for tax pur-  ;

ing construction (AFUDC). AFUDC represents the poses, we must record a liability for our tax obliga- )

)I estimated composite debt and equity cost of funds tion. The PUCO permits recovery of such taxes from ,

i used to fmance construction. This noncash allowance customers when they become payable. Therefore, l l is credited to income, except for certain AFUDC for the net amount due from customers through rates has l

) Perry Nuclear Power Plant Unit 2 (Perry Unit 2). See been recorded as a regulatory asset in deferred ,

Note 3(c). The AFUDC rate was 10.96% in both 1992 charges and will be recovered over the lives of the  !

and 1991 and 11.17% in 1990. related assets.

Maintenance and repairs are charged to expense as Investment tax credits are deferred and amortized  ;

incurred. The cost of replacing plant and equipment is over the estimated lives of the applicable property l

charged to the utility plant accounts. The cost of as a reduction of depreciation expense. See Note 6 '

j property retired plus removal costs, after deducting for a discussion of the amortization of certain any salvage value, is charged to the accumulated unrestricted excess deferred taxes and unrestricted  ;

provision for depreciation. investment tax credits available after 1998 under the 3 Rate Stabilization Program.  ;

DETERRED GAIN AND LOSS TROAf SALES DE UTILITY PLANT RECLASSITICATIONS The sale and leaseback transactions discussed in Note 2 resulted in a nct gain for the sale of the Bruce Certain reclassi6 cations were made to prior years  ;

i Mansfield Generating Plant (Mans 6 eld Plant) and a fmancial statements to make them comparable with  ;

• net loss for the sale of Beaver Valley Unit 2. The net the 1992 financial statements. A reserve for Perry Unit  !

gain and net loss were deferred and are being amor- 2 AFUDC, which was previously reported under ,

tized over the terms of leases. These amortizations Deferred Credits in the Balance Sheet, was reclassi-  !

i and the lease expense amounts are recorded as other f ed as an offset against the Perry Unit 2 asset balance. '

operation and maintenance expenses. See Note 6. See Note 3(c).

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

Overview 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 $4 million in 1994, increasing to 5101 PUCO in January 1989 and is described more fully million in 1998. In addition, we are still con-in Note 6. It established our rate phase-in plan to fronted with competitive threats from municipal recognize in rates our allowed investment in electric systems within our service territory and Perry Unit I and Beaver Valley Unit 2. The phase. from cities contemplating creation of their own in plan increased revenues and cash flows but was electric systems. Although the rate of iMlation has designed to have a relatively neutral impact on eased in recent years, we are still afft M oy even camings. Gains in revenues were to be initially modest inflation which causes increasu in the offset by a reduction in the deferral of operating unit cost of labor, materials and services.

expenses and carrying charges and subsequently To combat the forces described above, we have offset by the amortization of such deferrals. A key embarked on the following course. Reductions in assumption underlying the phase-m plan was that other operation and maintenance expenses and revenues would mcrease as a result of projected capital expenditures were implemented in 1991 and sales growth. When sales decreased primarily be-1992 and will be vigorously pursued in 1993 and cause of a sluggish econorny, earnings were ad- '

beyond. We will further reduce staffing levels and versely affected.

look to fmprove efficiency of operations wherever A number of other factors also exerted a negative p ssible. We are aggressively attempting to in-influence on earnings. These factors included the crease revenues by seekmg additional long-term recording of nuclear plant depreciaticn at levels in p wer sales agreements with wholesale customers i excess of that reflected in rates, the recording of and by exploring various corporate asset transac-depreciation and interest charges on facilities tions. The Energy Pohey Act of 1992 (Energy placed in service after February 1988 as current Act), which requires utihties to transmit electricity 1 expenses even though such items were not being from wholesale suppliers to wholesale customers, i recovered in rates and the effect of inflation on Will Provide new opportunities for us to make expenses. Also, the need to meet competitive wholesale power transactions. To counter munici-forces, coupled with a desire to encourage eco. pal electric system mitiatives, we have continued nomic growth in our service area, prompted us to Programs that demonstrate the value mherent m reduce rates for various communities and certain ur service, bey 9nd what one might expect from a  ;

municipal systerr Such programs mclude provid-industrial and commercial customers.

ing services to communities to help them retam We determined that the best solution to address and attract businesses, providing consulting ser-these factors was to delav rate increases and imple. vices to customers to improve their energy effi-ment cost-reduction and' revenue-enhancement ciency and developing demand-side management strategies. Furthermore, we sought PUCO ap- prograras.

proval of regulatory accounting measures designed increases in salec are expected to be modest with to recognize the effects of a delay in rate recovery annual sales growth projected at about 1-2% for the of certain costs and provide a better match of next several years, depending upon the economic current revenues and operating expenses. In 1991, climate in our service area. Recognizing the fact we obtained PUCO approval to change the method that costs can be reduced only so far and the and rate of accruing nuclear plant depreciation. In l limitations imposed by our sales forecasts and com-October 1992, the PUCO approved a Rate Stabih- petition in the wholesale power market, rate in-zat on Program, which was supported by certain creases will be necessary eventually to recognize customer representative groups, as discussed in the cost of our new capitalinvestment, including Note 6. Under the terms of the Rate Stabilization that being deferred under the Rate Stabilization Program, we agreed to freeze base rates until 1996 Program, and inflation.

and to limit rate increases through 1998. In ex-change, we are permitted to defer and subse- We believe that our Rate Stabilization Program and quently recover certain costs not currently our strategies to reduce costs and increase reve-recovered in rates and to accelerate amortization of nues give us the opportunity to improve our com-certain benehts. However, our ability to utilize petitive position and our earnings. Nevertheless, l these regulatory accountir g measures is dependent we operate in a changing industry and market. We i upon our taking signi6 cant actions to reduce costs must monitor the impact of these changes on our and increase revenues. It is also dependent upon an strategy and the continued appropriateness of the

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1 regulatory accounting provided by our various ing income increased primarily because of Rate j agreements. Stabilization Program carrying charge credits. In-  ;

terest charges decreased as a result of debt refmanc- l 7997 ,, yggy ings at lower interest rates and lower short-term i borrowing requirements. l Factors contributing to the 4.8% decrease in 1992  !

operating revenues are as follows: 7997 ps,1990 l Millions increase (Decrecsrp in Operatin_t Revenues of Dollars >

Operating revenues are as fe,llows: [

se R d i ella'neous . . .

Wholesale Sales . . 11

,,,,,,,, g o,,,,,, , ;, pp,,,,,,, y,,,, u ,, ,ff,},*,, i Base Rates and Miscellaneous . $20 Sales Volume and Mix 7 i Wh lesale Sales . ...

J) l The revenue decreases resulted primarily from the different weather conditions in both years and the Fi changes in the composition of the sales mix l among customer categories. Weather accounted for . . t approximately $22 million of the lower 1992 reve. A sig ficant factor accounting for the increase in  ;

nues. Winter and spring in 1992 were milder than operating revenues resulted from the January loS9 l in 1991. In addition, the 1992 summer was the PUCO rate order for the Company as discussed in [

coolest in 56 years in Northwestern Ohio as con. Note 6. Total kilowatt-hour sales mcreased 33%  ;

trasted with the summer of 1991 which was much in 1991. Residential and commercial sales increased i hotter than normal. Total kilowatt-hour sales in. 4.6% and 43%, respectively, as a result of higher [

creased 0.2% in 1992. Residential and commercial usage of coohng equipment m response to the  ;

sales decreased 4.9% and 3.8%, respectively, as unusually warm late spring and summer 1991 tem- i moderate temperatures in 1992 reduced electric peratures. The commercial sales increase was also heating and cooling demands. Industrial sales in. influenced by some improvement in the economy j creased 0.6% as increased sales to glass and metal for the commercial sector. Industrial sales declined '

manufacturers and to the broad-based, smaller in. 2% largely because of the recession-driven slump [

dustrial customer group offset lower sales to pe. in the auto, glass and metal industries. Other sales troleum refining and auto manufacturing increased 8.5% because of increased sales to whole- ,

customers. Other sales increased 5.2% because of sale customers. t increased sales to wholesale customers. Operating >

revenues in 1991 included the recognition of $24 Operating expenses increased 23% in 1991. The million of deferred revenues over the period of a increase was mitigated by a reduction of 517 t i refund to customers under a provision of the Janu- million in other operation and maintenance  ;

> ary 1989 rate order. No such revenues were re- expenses, resulting primarily from cost-cutting

! fh'cted in 1992 as the refund period ended in measures. Offsetting this decrease were an increase  ;

i December 1991. in federal income taxes because of higher pretax

• operating income; an increase in taxes, other than

Operating expenses decreased 4.4% in 1992. A re- federal income taxes, resulting from higher prop-  !

duction of 514 million in other operation and main- erty and gross receipt taxes and accruals for Penn- t j tenance expenses resulted primarily from cost- sylvania tax increases enacted in August 1991; an  ;

! cutting measures. Lower fuel and purchased power increase in fuel and purchased power expense expense resulted from less amortization of previ- resulting primarily from increased amortization of ,

ously deferred fuel costs than the amount amor- previously deferred fuel costs over the amount '

tized in 1991. These decreases were partially offset amortized in 1990; and lower operating expense ,

i bv higher depreciation and amortization, caused deferrals for Perry Unit 1 and Beaver Valley Unit 2 L p'rimarily by the adoption of SFAS 109 in 1992, and pursuant to the January 1989 rate order.  ;

by higher taxes, other than federal income taxes, l caused by increased Ohio property taxes. Deferred Credits for carrying charges recorded in  !

operating expenses increased as a result of the nonoperating income decreased in 1991 because a L deferrals under the Rate Stabilization Program as greater share of our investments and leasehold v l mentioned in Note 6. interests in Perry Unit 1 and Beaver Valley Unit 2 4 were recovered in rates. The federal income tax-  !

The federal income tax provision for nonoperating provision for nonoperating income increased l isome decreased because of a greater tax alloca- mainly because the 1990 provision was reduced 519 >

i tion of interest charges to nonoperating activities. million for unamortized investment tax credits on Credits for carrying charges recorded in nonoperat- the 1988 write-off of nuclear plant investment.

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• income Statement For the years ended December 31, 1 1992 1991 1990 i (milhons of dollars) ,

Operating Revenues (1) . . . $845 $887 5863 Operating Expenses ,

fuel and purchased power. . . 169 178 174 I Other operation and maintenance . . . . . 342 356 373 Total operation and maintenance . .. . .. 511 534 547 Depreciation and amortization . . . 77 72 73 Taxes, other than federal income taxes . . .. . 91 89 79 Deferred operating expenses, net .. .. .

(17) 1 (10) l Federal income taxes . . . ... . 33 32 21 695 728 710 Operating incorne . . . . . . 150 159 153 t Nonoperatirrg incorne j Allowance for equity funds used during construction 1 1 3 Other income and deductions, net . . 1 5 5 Deferred carrying charges. . .. ....... . . . . . 41 22 43  !

Federal income taxes - credit (expense) . .. .. . ..

(1) (6) 9 42 22 60 Incorne Before interest Charges . . . . . 192 181 213 i Interest Charges  !

Debt interest .. . .. . . 122 132 135 Allowance for borrowed funds used during construction ..

(1) (1) (3) 121 131 132 Net incorne . . . . 71 50 81 Preferred Dividend Requirernents . . 24 25 25 Earnings Available for Cornrnon Stock . S 47 5 25 5 56 (1) includes nvenues from all bulk power sales to Cleveland Electric of 5130 million, $128 million and $112 million ,

in 1992,1991 and 1990, respectively.

Retained Eamings i For the years ended December 31.

1992 1991 1990 (milhons of dollars)

• Balance at Beginning of Year . . S 90 $ 83 $100 Additions Net income . . . 71 50 81 Deductions Dividends declared:

Common stock . . -

(18) (73)

Preferred stock (24) (25) (25) l Net Increase (Decrease) , . . . . 47 7 (17)

Balance at End of Year . .. .. . $137 $ 90 $ 83 The accompanying notes and summary of signincant accounting policies are an integral part of these statements.

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Management's Financial Analysis i

CAPITAL RESOURCES AND LIQUIDITY ance with the Gean Air Act Amendments of 1990

" (Clean Air Act). Expenditures for our optimal We need cash for normal corporate operations, the plan are estimated to be approximately 536 million

mandatory retirement of securities and an ongoing over the 1993-2002 period. See Note 3(b).

program of constructing new facilities and modi- ,

j 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 two hazardous waste sites. How-service, comply with governmental regulations ever, we believe that the ultimate outcome of and protect the environment. 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 5530 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 external

, 5520 million of our securities. financing'needs, however, depends upon such We raised 5784 million through security issues and factors as financial market conditions and our credit ,

! term bank loans during the 1990-1992 period as ratings. Apparently, the market perceives the shown in the Cash Flows statement. During the Company as having a greater risk than its credit three-year period, the Company also utilized its ratings would indicate. Therefore, in 1992, the l short-term borrowing arrangements (explained in Company had to offer interest rates on certain of its Note 11) to help meet its cash needs. The Com. new debt securities which were significantly pany had $40 million of short-term borrowings higher than those that would be expected for secu-outstanding at December 31,1992. rities having the credit ratings of the Company.

Current securities ratings for the Company are as Estimated cash requirements for 1993-1995 for the foljows:

1 Company are 5203 million for its construction program and 5154 million for the mandatory re- Standard Moody's demption of debt and preferred stock. The Com- & Poor's Investors '

pany expects to fmance externally about 10% of its corporation service

total 1993 cash requirements of approximately First mortgage bonds BBB- Baa3 5118 million. About 40-50% of the Company's 1994 i

Unsecured notes BB+ Bal and 1995 requirements are expected to be fmanced preferred stock . . BB+ ba2 externally. If economical, additional securities may

• be redeemed under optional redemption provi- r A write-off of the Company's investment in Perry ,

sions. See Notes 10(c) and (d) for information ,

Unit 2, as discussed in Note 3(c), depending upon concerning limitations on the issuance of preferred the magnitude and timmg of such a wnte-off, could i

stock and debt.

reduce retained earnings sufficiently to impair its Our capital requirements after 1995 will depend on ability to declare dividends, but would not affect i

our implementation strategy to achieve compli- cash flow.

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.THE TOLEDO EDISON COMPANY l

For the years ended i December 31, l o 1992 1991 1990 Cash T!ows from Operating Activities (1)

Net Income. . . .. . . . . . 5 71 5 50 $ 81 Adjustments to Reconcile Net income to Cash from Operating Activities:

Depreciation and amortization . . . . .... .. . 77 72 73 q Deferred federal income taxes . ... . . 28 32 31 i investment t. credits, net . . .. . . .. .. .. . .

(5) 30 (17) l Deferred an . nbilled revenues. . . .. . 1 (26) (23) i Deferred fuel . . . . . . ... ..

(4) 4 -

Deferred carrying charges . . ... . . .

(41) (22) (43)  :

leased nuclear fuel amortization . . . .. .. . . 56 54 37 Deferred operating expenses, net. . . . . . .

(17) 1 (10)

Allowance for equity funds used during construction. . .,.. .. . (1) (1) (3)

Pension settlement gain.. . .. . . .

(6)

Changes in amounts due from customers and others, net . . .. .. ..

3 (9)

Changes in inventories. . . . . . .. .. . .. . (9) (7) (7) i Changes in accounts payable . . . . .

(8) (13) 7 Changes in working capital affecting operations . .. . . .. 7 (26) 1 i Other noncash items . . . . . .. . 13 14 15 '

Total Adjustments. . . .. . . . . . 97 115 46 '

Net Cash from Operating Activities . .. .. . 168 165 127 Cash Flows from Tinancing Activities (2) 1 Bank loans. commercial paper and other short. term debt . . . 40 (23) 23 Notes payable to affiliates. . .

(30) 14 16 Debt issues:

First mortgage bonds . .. . . 276 -

67 Secured medium-term notes . . . . 48 135 -

Term bank loans and other long-term debt. . . . . 135 108 15 Maturities, redemptions and sinking funds . . .

(531) (179) (183)

Nuclear fuel lease obligations. . ..

(52) (52) (43)

Dividends paid. . . .. .

(24) (43) (98)

Premiums, discounts and expenses . . .. . .

(8) (1) (2)

Net Cash from Financing Activities .

(146) (41) (205)

Cash Flows from investing Activities (2)

Cash applied to construction . . . . . . .

(48) (51) (81)

Interest capitalized as allowance for borrowed funds used during construction . (1) (1) (3) leans to affiliates . . .. 12 (12) 114 Sale and leaseback restructuring fees . . . .

(43) - -

Other cash applied . . . . . . .

(5) (3) (4)

Net Cash from Investing Activities . . . . .

(85) (67) 26 l Net Change in Cash and Temporary Cash investments . .

(63) 57 (52)

Cash and Temporary Cash investments at Beginning of Year . . . 79 22 74 Cash and Temporary Cash investments at End of Year. . . $ 16 $ 79 $ 22 \

(1) Interest paid (net of amounts capitalized) was $95 million, $120 million and $114 million in 1992,1991 and 1990, respectively. Income tases paid were $3 million, $9 million and $2 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.

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Balance Shbet i December 31, 1992 1991 (millions of dollars)

ASSETS i Property, Plant and Equipment Utility plant in service. . . . . .. . . 52,847 52,692 Less: accumulated depreciation and amortization . . . . . . . 760 709

, 2,087 1,983 7

i Construction work in progress ... . . . .. . . 37 54 ;

Perry Unit 2. . . . . . . . . .. . . . . . 243 254 l

4 2,367 2,291 i

Nuclear fuel, net of amortization . .. .. .. . . . . . .. 161 195 Other property, less accumulated depreciation . . . . . . .. 3 3 2,531 2.489 Current Assets Cash and temporary cash investments ... ... . . . .. . 16 79 Amounts due from customers and others, net . . . 60 60 Accounts receivable from affiliates . . .. .. . . .. . 23 22 Notes receivable from affiliates . . . .. . ... . . .. .

12 U..bdhd revenues . . .. . . . ... . 21 22 Materials and supplies, at average cost . . . . , 40 37 Fossil fuel inventory, at average cost . .. . .. . . 25 19 Taxes applicable to succeeding years. . . . .. 71 66 (3ther. . .. . . .. . . . ... .. . . . . . . 2 3 258 320

, Deferred Charges and Other Assets I Amounts due from customers for future federal income taxes. . . . . 391 4 72 Unamortized loss from Beaver Valley Unit 2 sale. . .. .. . .. 110 114 Unamortized loss on reacquired debt . . . 37 26 Carrying charges and operating expenses, phase.in . . .. 226 193 Carrying charges and operating expenses, other . . . .. . . 274 244

, Nuclear plant decommissioning trusts. . .. . 20 15 i Other. . . . . . 92 53 1,150 1.117 i

Total Assets . . . . . 53,939 $3,926 l

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

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

i THE TOLEDO EDISON COMPANY December 31, 1992 1991 (millions of dollars)

CAPITAUZATION AND UABIUTIES Capitalization Common shares,55 par value: 60.0 million authorized;  ;

39.1 million outstanding in 1992 and 1991 . .. . . .. . .. ... .... .. $ 196 $ 1%

Premium on capital stock . . . . . .. ......... .. . . .... . .. 481 481 l Other paid-in capital . . .. .... .. ..... ........... .. . . . . . . . . . .. 121 121 >

Retained earnings.. . .. .... . ... .. .... . .......... ... .. ..... 137 90 Common stock equity . . . . ... .. .. . . ..... . . ... . ... 935 888 i Preferred stock  !

With mandatory redemption provisions . . . . ..... . ... . . ..... . . . . 50 64 Without mandatory redemption provisions .. .. . ... ... ..... .. .. . .. 210 210 i Long-term debt . . ... . . . .. . .. . . . . .. . . ... .. . .. . ... 1.178 1,158 2.373 2,320  !

i Other Noncurrent Liabilities -

Nuclear fuel lease obligations . .... . . .. ... .. . . . .. ... . ... 126 143 ,

Other. . . . .. . .. .. . . . . .... ... .. . .. ... . 62 50 [

188 193 i

Current Liabilities ,

Current portion of long-term debt and preferred stock . . . . . . . . ..... . . . .. .. 58 123 i Current portion of nudear fuel lease obligations ... . ....... . .. .. . . .. . 51 64 ,

Notes payable to banks and others . .... . .. .... ..... ....... . ... 40 -

l Accounts payable . . . . . ... . .. .. .. . .. . .. 47 55  !

Accounts and notes payable to affiliates . . . . . . . . . . ... . ...... .. ... 16 40 Accrued taxes .. .. .. . . . . .... . . ......... .. ... . .. . .. 78 68 Accrued interest . . .. . . .. . . .. . .... ... .. . . .. .. 28 31 Other. . . . .. . . .... . . .. .. . . ... 14 16 [

332 397  :

Deferred Credits l Unamortized investment tax credits. . . .. . . . .. .. . 103 108 i Accumulated deferred federal income taxes . . . .... . . ....... . . 640 577  !

Unamortized gain from Bruce Mansfield Plant sale . .. .. 218 227 l

Accumulated deferred rents for Bruce Mansfield Plant and Beaver Valley Unit 2. 46 67 ,

Other. . . . . .. .. . . . . ... .. 39 37 l 1,046 1,016 ,

Total Capitalization and Uabilities. . .... . .. .. . . . .. .. .. 53,939 53,926 l

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"" "S " **

Statement of Preferred Stock Current Call o Price Per Decernber 31, 1992 Shares [

Outstandmg Share 1992 1991  !

(millions of dollars)

$100 par value,3,000,000 preferred shares authorized and

$25 par value, 12,000,000 preferred shares authorized Subject to mandatory redemption:

$100 par $11.00 . . . .. .. .

5- 5- $ 3 9.375 . . . 116,800 102.96 12 13 25 par 2.81 . 2,000,000 26.25 50 50 62 66 Less: Current maturities 12 2 ,

Total Preferred Stock, with Mandatory Redemption Provisions . . . .. . $ 50 $ 64 l Not subject to mandatory redemption:

$100 par 5 4.25 . 160,000 104.625 $ 16 5 16 4.56 .. 50,000 101.00 5 5 -

4.25 .. 100,000 102.00 10 10

8.32 . . . 100,000 102.46 10 10

! 7.76 .. . 150,000 102.437 15 15  ;

7.80 . . 150,000 101.65 15 15 10.00 .. . 190,000 101.00 19 19 25 par 2.21 1,000,000 25.25 25 25 2.365 . . . 1,400,000 27.75 35 35 Series A Adjustable .. 1,200,000 25.75 30 30 Series B Adjustable. 1,200,000 25.75 30 30 Total Preferred Stock, without Mandatory Redemption Provisions . .. . $210 $210 l

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

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Notes to the Financial Statements (1) PROPERTY OWNED WITH OTHER UTILTTIES AND INVESTORS The Company owns, as a tenant in common with other utilities and those investors who are owner-participants in various sale and leaseback transactions (Lessors), certain generating 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 unit equal to its ownership share. Each utility owner is obligated to pay for only its respective share of the construction and operating costs. Each Lessor has leased its capacity rights to a utility which is obligated tu pay for such Lessor's share of the construction and operating costs. The Company's share of the operating costs of these generating units is included in the Income Statement. Property, plant and equipment at December 31,1992 includes the following facilities owned by the Company as a tenant ir common with other utilities and lessors:

1 Construction \

Owner- Work in l In- Owner- ship Plant Progress i Service ship Mega- Power in and Accumulated Generating Unit Date Share watts Source Service Sumended Derreciation (rnillions of dollars)

In Sernce:

Davis-Besse . .. . 1977 48.62 % 429 Nuclear 5 672 5 8 5151 Perry Unit I and Common Fadtities . 1987 19.91 238 Nuclear 1,042 2 158 ,

Beaver Valley Unit 2 and Common Facilities I (Note 2) 1987 1.65 13 Wuclear 203 3 30 )

Construction Suspended.

Perry Unit 2 (Note 3(c)) . Uncertain 19.91 240 Nuclear -

243 -

$1.917 5256 5339 (2) UTILITY PLANT SALE AND LEASEBACK TRANSACTIONS The Company and Cleveland Electric are co-lessee.c As co-lessee with Cleveland Electric, the Company of 18.26% (150 megawatts) of Beaver Valley Unit 2 is also obligated for Cleveland Electric's lease pay-and 6.5% (51 megawatts),45.9% (358 megawatts) ments. If Cleveland Electric is unable to make its and 44.38% (355 megawatts) of Units 1,2 and 3 payments under the Mansfield Plant leases, the of the Mansfield Plant, respectively, all for terms of Company would be obligated to make such pay-about 29% years. These leases are the result of sale ments. No payments have been made on behalf of and leaseback transactions completed in 1987 Cleveland Electric to date.

Under these leases, the Company and Cleveland in April 1992, nearly all of the outstanding Secured Electric are responsible for paying all taxes, insur- Lease Obligation Bonds (SLOBS) issued by a spe-ance premiums, operation and maintenance costs cial purpose corporation 4 connection with fi-and all other similar costs for their interests in the nancing the sale and leaseback of Beaver Valley units sold and leased back. The Company and Unit 2 were refinanced through a tender offer for Cleveland Electric may incur additional costs in the outstanding SLOBS and the sale by another connection with capital improvements to the units. special purpose corporation of new bonds having a The Company and Cleveland Electric have options lower interest rate. As part of the refinancing trans-to buy the interests back at the end of the leases action, the Company paid $43 million as supple-for the fair market value at that time or to renew mental rent to fund transaction expenses and the leases. Additional lease provisions provide part of the tender premium. This amount has been j other purchase options along with conditions for deferred and is being amortized over the remain-mandatory termination of the leases (and possible ing lease term. The refmancing transaction reduced ,

repurchase of the leasehold interests) for events of the straight-line annual rental expense for the l default. These events include noncompliance with Beaver Valley Unit 2 lease by 59 million. l several financial covenants discussed in Note 10(d).

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Future minimum lease payments under the operat- greater use of low-sulfur coal at some of our units ing leases at December 31,1992 are summarized as and the banking of emission allowances. The plan

)

i follows: would require capital expenditures for the Com-i g, pany over the 1993-2002 period of approximately  !

ror the clere!and 536 million for nitrogen oxide control equipment, g co many nectric emission monitoring equipment and plant modifi-

, (miffions of dollars) cations. In addition, higher fuel and other opera- i Iw3. 5 103 5 63 tion and maintenance expenses would be i 1W4. 103 63 incurred. The anticipated rate increase associated i i Iws . 102 63 with the Company's capital expenditures and -  ;

tw6. 125 63 higher expenses would be less than 2% over the i ten-year period.

ears . 2 1 Total Future wnimum tease Our compliance plan will depend upon future envi-Payments . 52.658 51368 ronmental regulations and input from the PUCO, ,

other regulatory bodies and other concemed enti-ties. In ddition, we are continuing to monitor Rental expense is accrued on a straight-line basis developments m new technologies that may be over the terms of the leases. The amount recorded ine rp rated into our compliance strategy.1f a plan .

in 1992,1991 and 1990 as annual rental expense for ther than the least cost plan is reqmred, s,gmfi-i the Mansfield Plant leases was $45 million. The cantly higher capital expenditures could be re-amounts recorded in 1992 and both 1991 and 1990 ,

quired during the 1993-2002 penod. We believe as annual rental expense for the Beaver Valley Unit 2 lease were $66 million and 572 million, Ohio law permits the recovery of compliance costs ,

respectively. Amounts charged to expense in excess fmm cmtomers m rats. >

of the lease payments are classified as Accumu-lated Deferred Rents in the Balance Sheet. (c) PERRY UNIT 2 The Company is selling 150 megawatts of its Bea- Perry Unit 2, including its share of the common J ver Valley Unit 2 leased capacity entitlement to f cilities,is approximately 50% complete. Construc-i Cleveland Electric. We anticipate that this sale will tion of Perry Unit 2 was suspended m 1985 pend-  !

continue at least until 1998. Revenues recorded for ing future consideration of various options. These 4

this transaction were 5108 million,5107 million Ptions include resumption of full construction with a revised estimated cost, conversion to a non-and $103 million in 1992,1991 and 1990, respec- l tivelv. The future minimum lease payments associ- nuclear design, sale of all or part of our ownership

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ated with Beaver Valley Unit 2 aggregate 51.533 share, or cancellation. No option may be imple-billion' mented without the unanimous approval of the ,

owners. A request by Cleveland Electric, the com- l pany resp nsibse for the construction of Perry

' (3) CONSTRUCTION AND CONTINGENCIES Unit 2, for an extension of the construction license .

is pending with the Nuclear Regulatory Commis-(a) CONSTRUCTION PROGRAM sion (NRC). i The estimated cost of the Company's construction  ;

program for the 1993-1995 period is $213 million, The license extension request does not indicate any ,

j including AFUDC of 510 million and excluding Pl ans to resume construction of Perry Unit 2. It j

' nuclear fuel. was made to keep the various options open.  ;

If Perry Unit 2 were canceled, the net-of-tax invest- ,

, (b) CLEAN AIR LEGISLATION ment would have to be written off. Such a write- l f (based on the Company's investment as of the The Clean Air Act will require, among other things, l significant reductions in the emission of sulfur end of 1992) would be about 5171 million. Notes ,

dioxide in two phases over a ten-year period and 10(b) and (d) discuss more about the effects of a nitrogen oxides by fossil-fueled generating units.

If a decision were made to convert Perry Unit 2 to a Centerior Energy developed a compliance strategv for the Company and Cleveland Electric which ' n nnuclear design, we would expect to write off a  ;

p ri n ur invn ment for nuckar plant con- .

was submitted to the PUCO in 1992 for review.

structi n c sts not transferable to the nonnuclear  ;

Centericr Energy subsequently reached agreement c ns ru with intervenind parties and is awaiting formal n pmject. j PUCO approval Centerior Energy also is seeking Perry Unit 2 AFUDC was credited to a deferred l United States Environmental Protection Agency income account from July 1985 until January 1,  ;

approval of the Phase 1 plans. The compliance plan 1988, when the accrual was discontinued. The total l

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which results in the least cost and the greatest deferred AFUDC amount of 588 million is reflected flexibility provides for compliance with both in the Balance Sheet as a reduction in the Perry phases through at least 2005. The plan calls for Unit 2 investment.  ;

14  ;

I (d) SUPERTUND SITES share of such excess amount could have a material

. adverse effect on its financial condition :nd re-The Comprehensive Environmental Response, sults of operations.

Compensation and Liability Act of 1980 as amended (Superfund) established programs ad- The Company also has extra expense insurance dressing the cleanup of hazardous waste disposal coverage. It includes the incremental cost of any sites, emergency preparedness and other issues. replacement power purchased (over the costs The Company is aware of its potential involvement which would have been incurred had the units in the cleanup of two hazardous waste si+es. The been operating) and other incidental expenses after Company has recorded reserves based on esti- the occurrence of certain types of accidents at our mates of its proportionate responsibility for these nuclear units. The amounts of the coverage are sites. We believe that the ultimate outcome of these 100% of the estimated extra expense per week l matters will not have a material adverse effect on during the 52-week period starting 21 weeks after  ;

our financial condition or results of operations. an accident and 67% of such estimate per week for ,

the next 104 weeks. The amount and duration of l extra expense could substantially exceed the insur-(4) NUCLEAR OPERATIONS AND CONTINGENCIES ance coverage.

(a) OPERATING NUCLEAR UNITS The Company's interests in nuclear units may be (c) NUCLEAR DECONTAMINATION AND  ;

impacted by activities or events beyond our control. DECOMMISSIONING ASSESSMENT l

Operating nuclear generating units have exper- The Energy Act permits special assessments on I sented unplanned outages or extensions of sched- nvestor-owned electric utilities which own nuclear  !

uled outages because of equipment problems or generating plants for the decontamination and new regulatory requirements. A major accident at a decommissioning of nuclear enrichment facilities ,

nuclear facility anywhere m the world could cause operated by the Department of Energy. The assess- I the NRC to limit or prohibit the operation, con- ments to individual utilities are based upon the i struction or licensing of any nuclear unit. If one of amount of enrichment services used in prior years t our nuclear units is taken out of service for an and cannot be imposed for more than 15 years. At i extended period of time for any reason,includmg December 31,1992, the Company accrued a liabil-an accident at such unit or any other nuclear facil-ity of $15 million for its share of the total assess-ity, the Company cannot predict whether regula- ments. These costs are recorded as deferred charges tory authorities would impose unfavorable rate since, based on the legislation, the Company be-  !

treatment. Such treatment could mclude takmg our '

lieves the PUCO will allow the recovery of the affected unit out of rate base or disallowing certain assessments through the Company's fuel cost  !

construction or maintenance costs. An extended '"#' #5' outage of one of our nuclear units coupled with I unfavorable rate treatment could have a material adverse effect on our financial condition and results (5) NUCLEAR TUEL

' I"# "' The Company has inventories for nuclear fuel which should provide an adequate supply into the (b) NUCLEAR INSURANCE mid-1990s. Substantial additional nuclear fuel 1 The Price-Anderson Act limits the liability of the must be obtained to supply fuel for the remaining I' owners of a nuclear power plant to the amount useful lives of its nuclear generating units.

provided by private insurance and an industry assessment plan. In the event of a nuclear meident Nuclear fuel is fmanced for the Company and at any unit in the United States resulting in losses Cleveland Electric through leases with a special-

! in excess of the level of private insurance (cur- purp se c rporation. The total amount of financing rently $200 million), the Company's maximum currently available under these lease arrangements l

potential assessment under that plan would be $59 is $509 million ($309 million from mtermediate-million (plus any inflation adjustment) per inci- term n tes and $200 million from bank credit dent. The assessment is limited to $9 million per anangements). Financing in an amount up to $900 year for each nuclear incident. These assessment mdhon is permitted. The m, termediate-term notes iimits assume the other CAPCO companies con- mature m the period 1993-1997, with $77 m,llion i tribute their proportionate share of any assessment. maturing in September 1993. The bank credit arrangements terminate m October 1993 at which The CAPCO companies 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, $179 million of and Beaver Valley sites (including leased fuel and nuclear fuel was financed for the Company. The clean-up costs). Coverage amounted to $2.625 Company and Cleveland Electric severally lease billion for each site as of January 1,1993. Damage their 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-

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J mediate-term note rates, bank ra, .nd commer- The Company deferred $33 million, $28 million

, cial paper rates. and $60 million in 1992,1991 and 1990, respec-tively, of operating expenses and carrying charges The amounts financed m.clude nuclear fuel m. the pursuant to the phase-in plan. The amount of i Davis-Besse, Perry Unit 1 and Beaver Valley Unit 2 deferrals scheduled to be recorded in 1993 total $15 I reactors with remaining lease payments for the million. Beginning in the sixth year (1994) and  !

1 Company of $42 million, $39 million and $18 mil- continuing through the tenth year, the revenue

• J lion, respectively, as of December 31,1992. The levels authorized pursuant to the phase-in plan t nuclear fuel amounts financed and capitalized als were designed to be sufficient to recover that pe- I included interest charges incurred by the lessors riod's operating expenses, a fair return on the unre-  !

amounting to $6 million in 1992, $9 million in 1991 covered investments, and the amortization of the  :

and $14 million in 1990. The estimated future lease deferred operating expenses and carrying charges l amortization payments based on projected con- recorded during the first five years of the plan. The j sumption are $45 million in 1993,547 million in phase-in deferrals relating to these two units will 1994, $43 million in 1995, $40 million in 1996 and I total $241 million after 1993 which reflects an $11

$37 million in 1997. million reduction of deferrals for 1990 and 1991 pursuant to the plan. The deferrals are scheduled to (6) REGUL4 TORY AfATTERS be amortized and recovered as follows: $4 million in 1994, $25 million in 1995, $4B million in 1996,  :

On January 31,1989, the PUCO issued a rate order $74 million in 1997 and $101 million in 1998; how-which provided for three annual rate increases for ever, these amounts will be adjusted to reflect the ,

the Company of approximately 9%,7% and 6% $11 million reduction referred to in the preceding  !

effective with bills rendered on and after February sentence. These amortizations can be accelerated at i 1,1989,1990 and 1991, respectively. The 6% in- the option of the Company.  !

] crease effective February 1,1991 was reduced to [

! 2.74% as 50% of the savings identified by a manage- On October 22,1992, the PUCO approved a Rate  ;

i ment audit were used to reduce the rate increase. Stabilization Program as set forth in a joint recom- l 2

The Company waived its 2.74% rate increase for mendation 61ed by the Company, Cleveland Elec-  ;

residential and small commercial customers and tric and certain customer representative groups 4

reduced its residential rate by 3% effective in March involved in the 1989 rate case settlement. Under [

I 1991 and by an additional 1% effective in Septem- the Rate Stabilization Program, the Company  !

ber 1991 to improve its mmpetitive position in its agreed to freeze base rates until 1996 and limit j service area. The resulting annualized revenue subsequent rate increases to no more than $38  !

increases in 1990 and 1991 associated with the rate million in 1996, $28 million in 1997 and $23 million  :

j order were .$44 million and $2 million, respec- in 1998. For purposes of any rate increase proceed- i j tively. The increase in 1991 reflects the net of $19 ing in the 1996-1998 period, the Company agreed l 1 million of annualized revenues authorized for the to cap operation and maintenance expenses ,

j 2.74% increase less $17 million for the waiver and (other than fuel and purchased power) at $784 l

) rate reductions, million on a consolidated basis for Centerior En-

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! ergy, subject to adjustment for inflation and other j Under the January 1989 rate order, a phase-in plan specified expenses. During the 1996-1998 period, was designed so that the three rate increases,

] PUCO approval of any base rate increases and any i coupled with then-projected sales growth, would additional regulatory accounting measures would provide revenues over the ten years begmmng  !

be dependent upon our success in implementing  !

, January 1,1989 sufficient to recover all operating cost-reduction and revenue-enhancement initia-expenses and provide a fair rate of return on the tives. The Company agreed to seek authorization Company's allowed investments in Perry Unit 1 for acceleration of the post-1998 Mansheld Plant and Beaver Valley Unit 2. Revenues in the first unamortized gain in any rate increase proceeding l five years of the plan were expected to be less than

, in the 1996-1998 period. See Summary of Signih-l that required to recover operating expenses and cant Accounting Policies.

1 provide a fair return on investment. Therefore, the 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

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

ferred federal income taxes that result from the use stabilization by rescheduling the timing of rate i of accelerated tax depreciation. Therefore, the recovery of certain costs and the amortization of amount of revenues required to provide a fair certain benefits, thereby preventing what otherwise return also declines. This results in decr+asing 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- l 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-l 16 l

i termination that there will be probable recovery The Rate Stabilization Program provides for PUCO  !

of such deferrals and carrying charges in future regulatory approval of certain corporate transac- '

rates. The aggregate effect of these measures over tions, including major asset sales, after an evalua-this period could be as much as $179 million on an tion of the customer benefit of these transactions.  ;

after-tax basis dependent upon the Company's The Rate Stabilization Program may be renegoti-  !

success in implementing cost-reduction and other ated under certain force majeure and other revenue-enhancement initiatives, among other fac- events.

tors. Such regulatory accounting measures which are eligible to be recorded through December 31, Deferred Operating Expenses, Net, and Deferred i 1995 on an after-tax basis are as follows: Carrying Charges shown in the income Statement l c nsist of the following: j

. Deferral of up to $100 million of accrued post-in-service interest carrying charges, depreciation 1992 1991 1990-expense and property taxes on assets placed in (milhons of donars) service after February 29,1988. The deferrals Deferred Operatirg Expenses, Net:  ;

recorded m 1992 were retroactive to January 1, Phase-in . . . 5 (6) , 5 (6) 5(17) 1992. Deferral, are based on actual capital ex- Rate Stabilization . . (18) - -

penditures relating to assets placed in service Amortization of Pre-Phase-in D"'*l5 7 7 7 within the 1988-1995 period. Consequently, the - 1 deferrals will be lower than $100 million if the Tota . . . 5g2) 5 1 500) ,

Company continues to reduce capital expend'^

tures. Amortization and recovery of these defer-Deferred Carrying Charges: )

Phase-in: l rals will occur over the average life of the assets Debt. 5 10 5 7 5 21  !

and will commence with future rate Equity . . . 17 15 22 recognition. Total Phase-in 27 22 43 Rate Stabilization (Debt) . 14 - -

. Deferral of up to $19 million of operating ex- Total . 5 41 5 22 5 43 penses equivalent to an accumulated excess rent reserve for Beaver Valley Unit 2 which resulted from the April 1992 refmancing of SLOBS as discussed m Note 2. The deferral commenced (7) FEDERAL INCOME TAX October 1,1992. Amortization of this deferral will occur over the remaining term of the unit's lease Federal income tax, computed by multiplying in-beginning in 1996. come before taxes by the statutory rates, is recon-caled to the amount of federal income tax recorded

. Acceleration of the amortizations of an estimated on the books as follows:

532 million in unrestricted excess deferred taxes 399, 39,3 3,99 and $16 million in unrestricted investment tax credits available after 1998. The amortizations I"#U#"'#I##N W commenced October 1,1992. The amortization of Ik{' Ic me Bef re rederal in ome mvestment tax credits is reported as a reduction of depreciation expense. Tax on Book Income at statutory Rate . . 5 36 5 30 5 32

. Amortization of up to $12 million in interim Increase (Decrease) in Tax:

spent fuel storage accrual balances for Davis. Depreciation . . ...

.(6) 3 (1)

Besse. The amortization commenced October 1, b'[m*"r t$n 5 5 7 1992. Investment tax credits on disallowed nuclear plant - -

(19)

The Company is also allowed to defer and subse- Rate Stabilization . . .

(2) - -

quently recover the incremental expenses associ. Taxes, other than federalincome ated with adoption of the accounting standard for g,'hbms.

. I postretirement benefits other than pensions. See 5 38 Total Federal Income Tax Expense. 5 34 5 12 Note 8(b). = = =

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Federal income tax expense is recorded in the Millions of Dollars income Statement as follows:  ;

a 1992 1997 7990 Property, plant and equipment . $656 ,

Deferred carrying charges and operatmg expenses . 119 l

, (millions of dollars) Net operating loss carryforwards . . --

(56)

Operatmg Expenses: Investment tax credits . .

(58) .

Current Tax Provision.

Changes in Accumulated Deferred 5 26 $ 14 $ 17 Other. . . . g) '

Federal Income Tax: Net deferred tax liabihty. . 5640

=

Accelerated depreciation and amortization . 7 9 2 For tax purposes, net operating loss (NOL) car-Alternatwe minimum tax credit . (13) (44) (5)

Sale and leaseback transactions ryforwards of approximately $165 million are avail-and amortization . 4 13 5 able to reduce future taxable income and will

> Property tax expense. 5 -

(4) expire in 2003 through 2005. The 34% tax effect of  !

Rate Stsbilization . 2 Reacquired debt msts . . . . . 7 the NOLs is $56 million.

4 (1) '

Deferred construction work in The Tax Reform Act of 1986 provides for an alter-DeNEuNs s$ ~ l (!) () native minimum tax (AMT) credit to be used to. i Other items . . . . . . .

(3) 2 1 reduce the regular tax to the AMT level should the ,

4 investment Tax credits. -

27 1 regular tax exceed the AMT. AMT credits of 540 ,

Total Charged to Operating million are available to offset future regular tax.  !

Expenses . 33 32 21 The credits may be carried forward indefmitely. ,

Nonoperatmg income: ,

Current Tax Provision. . . . . . . (20) (38) (18) (8) RETIREAfENT AND POSTEAfPLOYAfENT Changes in Accumulated Deferred.

3 BENETITS I federal Income Tax:  !'

'jlg*,{$,,l,'*' '* ' ' ~

U*)

g 5 {a) RETIREMENT INCOME PLAN AFUDC and carrying charges . . 9 9 17 Net operating loss carryforward . -

35 - The Company sponsors a noncontributing pension  ;

Other items . - -

2 plan which covers all employee groups. The Total Expense (Credit) to amount of retirement benefits generally depends ,

Nonoperating Inmme . 1 6 _19) upon the length of service. Under certain circum-  ;

Total Federal Income Tax Expense. $ 34 $ 38 5 12 stances, benefits can begin as early as age 55. The  :

plan also provides certain death, medical and disa-  :

, The Company joins in the filing of a consolidated bility benefits. Our funding policy is to comply i

federal income tax return with its affiliated com, w th the Employee Retirement Income Security  ;

panies. The method of tax allocation reflects the Act of 1974 gmdelines.

j benefits and burdens realized by each company's In 1990, the Company offered a Voluntary Early l participation in the consolidated tax return, approx- Retirement Opportunity Program (VEROP). Oper-  !

imating a separate return result for each company. ating expenses for 1990 included 57 million of

• In 1990, adjustments for unamortized investment pensi n plan accruals to cover enhanced VEROP tax credits on the 1988 write-off of nuclear plant benefits and an additional 58 milhon of pension ,

investment decreased the federal income tax provi-costs for VEROP benefits paid to retirees from corporate funds. The 58 milhon is not mcluded m, sion for nonoperating income 519 million. Also in the pension data reported below. A credit of 55  ;

1990, the resolution of a property tax deduction ,

milli n resultmg from a settlement of pension obh,- j issue resulted in a reduction in federal income tax gati ns through lump sum payments to a substan-expense of 54 million.  !

tial number of VEROP retirees partially offset the  ;

The adoption of SFAS 109 in 1992 affected certain VEROP expenses.

Balance Sheet accounts. The most significant im-

, Net pension and VEROP costs for 1990 through pact was an increase in Utility Plant in Service and 1992 were comprised of the following components: i an offsetting increase in Accumulated Deferred  ;

. Federal Income Taxes.

m2 m mo (millions of dollars)  !

Under SFAS 109, temporary differences and car- Penskm Costs:

ryforwards gave rise to deferred tax assets of $154 Service wst for benents earned million and deferred tax liabilities of $794 million inteNc to jected benent ,

at December 31,1992. These are summarized as obligation . ... 11 n n  !

follows: Actual retum on plan assets . (5) (30) 2 Net amortization and deferral. .,,j10) 15 (15)

Net pension costs. I 1 3 YEROP cost. - -

7 Settlement gain . - -

(5)

Net costs . 5 1 $ 1 $ 5 18  !

i r

The following table presents a reconciliation of the actual adoption may be similar, although it could .

funded status of the plan at December 31,1992 and be significantly different because of changes in 1991, health care costs, the assumed health care cost necember 31. trend rate, work force demographics, plan provi- ,

1992 1991 sions or interest rates. Like the retirement income i g,,,my,,, ,f plan, these estimates reflect a discount rate assump- ,

dollars) tion of 8.5% per year. The annual health care cost l Actuarial present value of beneht obligations; trend assumption is 12% in 1992, reducing gradu- l Veued benehts . . . . 5 95 5 92 ally to an ultimate annual rate of 6% in 1996 and  ;

Nonvested benehts . . 12 10 later years. I Accumulated beneht obligation 107 102 1 Effect of future compensation levels . . 35 34 The PUCO authorized the Company to defer for ,

Total projected benent obbgation. 142 136 subsequent recovery postretirement benefit costs i Plan assets at fair market value . . 169 172 that exceed its actual payments for the period 1993-Surplus of plan assets over projected benent 1997. This provision was part of the Rate Stabili- '

obhgation . . . . . . 27 36 zation Program discussed in Note 6. The amount ss p sad enc we can defer will be determined by the extent to (33) (40)

Unrecogmzed prior service cost . .. . 5 5 which Centerior Energy is successful in reducing Transition asset at January 1,1987 being the added obligation on a consolidated basis by $37 amortized over 19 years . 117) _H) million or 25% of the incremental costs expected Net accrued pension liabihty included in when the Company got the order. The Company t Deferred Credits - Other in the and Centerior Energy have until December 31,1997 Balance Sheet . . gS) g) to make the reductions.

At December 31,1992 and 1991, the settlement (discount) rate and long-term rate of return on (c) POSTEMPLOYMENT BENEFITS plan assets assumptions were 8.5% and the long' In November 1992, the FASB issued a new account-term rate of annual compensation merease assump- ng standard for postemployment benefits (SFAS i tion was 5%. 112), such as severance pay, disability, worker's '

Plan assets consist primarily of investments in com- compensation and supplemental unemployment ,

mon stock, bonds, guaranteed investment con- benefits. The Company is required to adopt the 1 tracts, cash equivalent securities and real estate. new standard no later than 1994. We have not completed an analysis to determine the effect of (b) OTHER POSTRETIREMENT BENETITS adopting the new standard.

The FASB accounting standard for postretirement benefits other than pensions (SFAS 106) requires (9) GUARANTEES the accrual of the expected cost of such benehts during the employees years of service. The as- The Company has guaranteed certain loan and sumptions and calculations invohed in determin- of a s y under a long-term coal purchase arrangement. This ar-ing the accrual closely parallel pension accounting ,g g g requirements.

pany for any actual out-of-pocket idle mine The Company currently provides certain postretire- expenses (as advance payments for coal) when the ment health care, death and other benefits and mines are idle for reasons beyond the control of expenses such costs as these benefits are paid, the mining company. At December 31,1992, the which is consistent with current ratemaking prac- principal amount of the mining company's loan tices. Such costs totaled $4 million in 1992 and 1991 and lease obligations guaranteed by the Company and $3 million in 1990, which included medical was $22 million.

benefits of $3 million in 1992 and 1991 and $2 (10) CAPITAL 1Z.4 TION The Company will adopt the standard effective l I

January 1,1993. The Company plans to amortize (a) CAPITAL STOCK TRANSACTIONS the present value of the accumulated post-retirement benefit obligation to expense over a 20- Preferred stock shares retired during the three years  ;

year period. Based on our actuaries' review of 1992 ended December 31,1992 are listed in the follow- '

data, the accumulated postretirement benefit obli- ing table.

gation as of December 31,1992 is estimated to be in 1992 1991 1990 the range of $90 million to $110 million (pretax). (thousands of shares)

Had the standard been adopted in 1992, the addi. Subrect to Mandatory Redemption:

tional 1992 postretirement benefit cost would have 52 par s11m- (25) 00) 00) been in the range of $10 million to $13 million

5. g) g) g)

(pretax). The Cornpany believes the 1993 effect of Total . g) g) g) 19 i

l

.l

. 1 j

, I (b) EQUITY DISTRIBUTION RESTRICTIONS (d) LONG-TERM DEBT AND OTHER l BORROWING ARRANGEMENTS  !

j At December 31,1992, retained earnings were $137 Long-term debt,less current maturities, was as  !

j million. Substantially all of the retained eamings fgjjo,3 j i were available for the declaration of dividends on Actual or Ar crage the Company's preferred and common shares. Interest Ratt at  !

All of the Company's common shares are held by December 31, ourmon 31.

year omarunw 192 192 197 Centerior Energy. A write-off of the Company's l

investment in Perry Unit 2, depending upon the magnitude and tim;ng of such a write-off, could First mortgage bonds

("il1i""f 81 j ,,,

reduce retained earninga sufficiently to impair the Company's ability to declare dividends.

y6. y 5 g 51

, 1998. E

• _ 7.32 127 61 }

d 2003-2007 , 7.90 181 66  ;

i Any fmancing by the Company of any of its non- 2008-2012 2.90 31 52 i utility affiliates requires PUCO authorization un- 2018-2022 . 8.00 108 108 2023. 623

) less the financing is made in connection with 107 107 l transactions in the ordinary course of the Com-

, , Term bank loans due pany's pubhc utilities business operations in which 1994-1997 . . .... 8.65 113 116 I one company acts on behalf of another. Medium-term notes due (

1994-2021 . . . . . . . - 8.83 182 135 Notes due 1994-1997 . 9.69 60 102  !

(c) PREFERRED AND PREFERENCE STOCK Debentures due 2002 . . 8,70 135 - [

Debentures due 1997 . . . . - -

125  ;

Amounts to be paid for preferred stock which must Pollution control notes due i be redeemed during the five years 1993-1997 are 1994-2015 12.02 105 136 512 million in each year. Other - net . .

(2) (1)

Total tong Term Debt . 51.178 51.158 {

The annual preferred stock mandatory redemption provisions are as follows: Long-term debt matures during the next five years  :

Shares Price as follows: $46 million in both 1993 and 1994, $26

. To Be Beginning Per million in 1995,$91 million in 1996 and $84 mil- i j Rrdermed in Share lion in 1997.

5100 par 59.375 . 16.650 1985 5100 .

I 25 par 2E1 400,000 1993 25 The Company issued $182 million aggregate pr. mci-  !

pal amount of secured medium-term notes during .

The annualized preferred dividend requirement as 1991 and 1992. The notes are secured by first of December 31,1992 was $24 million. mortgage bonds. At December 31,1992, the Com-  ;

pany had $93 million aggregate principal amount of The prefened dividend rates on the Company's secured medium-term notes registered with the ,

Series A and B fluctuate based on prevailing inter- Securities and Exchange Commission and available est rates and market conditions. The dividend rates for issuance.

for these issues averaged 8.24% and 9 09%, respec-The Company's mortgage constitutes a direct first I tively, in 1992.

I en on substantially all property owned and i Under its articles of incorporation, the Company franchises held by the Company. Excluded from i cannot issue preferred stock unless certain earnings the lien, among other things, are cash, securities,  !

coverage requirements are met. Based on eamings accounts receivable, fuel, supplies and automotive j

. for the 12 months ended December 31,1992, the equipment. j i Company could not issue additional preferred Additional first mortgage bonds may be issued by  !

. stock. The issuance of additional preferred stock in the Company under its mortgage on the basis of I l the future will depend on earnings for any 12 bondable property additions, cash or substitution l

consecutive months of the 15 months preceding for refundable first mortgage bcnds. The issuance  !

l the date of issuance, the interest on all long-term of additional first mortgage bonds on the basis of  !

debt outstanding and the dividends on all preferred property additions is limited by two provisions of stock issues outstanding. our mortgage. One relates to the amount of l l

Preference stock authorized for the the Company is bondable property available and the other to earn- ,

5,000,000 shares with a $25 par value. No prefer _ ings cover ge of interest on the bonds. Under the l

ence shares are currently outstanding. There are no more restrictive of these provisions (currently, the ,

restrictions on the Company's ability to issue earnings coverage test), the Company would have j preference stock. been permitted to issue approximately $173 mil-  ;

lion of bonds at an assumed interest rate of 9.5% ,

With respect to dividend and liquidation rights, the based upon available bondable property at Decem- [

i Company's preferred stock is prior to its prefer- ber 31,1992. The Company also would have been l ence stock and common stock, and its preference permitted to issue approximately $266 million of

stock is prior to its common stock. bonds based upon refundable bonds at Decemicr i -

i 20 i

31,1992. If Perry Unit 2 had been canceled and os w ns fair written off as of December 31,1992, the amount of ^ *"""' "#'"

bonds which could have been issued by the Com- ("dli""' "I ddl*"I pany would not have changed. Nuclear Plant Decommissioning Trusts . 5 20 5 21 Preferred Stock, with Mandatory Redemption Provisions (induding Certain unsecured loan agreements of the Com- current portion) . . . . . 62 66 pany contain covenants relating to capitalization g[e{ Debt (including current ratios, earnings coverage ratios and limitations on secured financing other than through first mortgage The fair value of the nuclear plant decommission-bonds or certain other transactions. An agreement ing trusts is estimated based on the quoted market relating to a letter of credit issued in connection prices for the investment securities. The fair value with the sale and leaseback of Beaver Valley Unit 2 of the Company's preferred stock with mandatory contains several financial covenants affecting the redemption provisions and long-term debt is es-Company, Cleveland Electric and Centerior En- timated based on the quoted market prices for the ergy. Among these are covenants relating to earn- respective or similar issues or on the basis of the ings coverage ratios and capitalization ratios. The discounted value of future cash flows. The dis-Company, Cleveland Electric and Centerior En- counted value used current dividend or interest ergy are in compliance with these covenant provi- rates (or other appropriate rates) for similar issues sions. We believe these covenants can still be met and loans with the same remaining maturities.

in the event of a write-off of the Company's and . .

Cleveland Electric's investments in Perry Unit .2, The estimated fair values of all other financial ,

barring unforseen circumstances. instruments approximate their carrying amounts in the Balance Sheet at December 31,1992 because of their short-term nature.

(11) SHORT-TERA 1 BORROWING ARRANGEhfENTS (23) QUARTERLY RL'SULTS OF OPERATIONS The Company had 570 million of bank lines of (UNAUDITED) credit arrangements at December 31,1992. There were no borrowings under these bank credit ar- The following is a tabulation of the unaudited rangements at December 31,1992. quarterly results of operations for the two years ended December 31,1992.

0""*" f"#'#

Short-term borrowing capacity authorized by the M" " 3L I""'3"

• 3" U"'33-PUCO annually is $150 million for the Company.

The Company and Cleveland Electric are autho- ("dli""5 "I ddl8")

rized by the PUCO to borrow from each other on a ' hating Revenues.. 5207 5202 5225 5210 short-term basts. Operating Income. . 38 19 52 31 Net income . . . . 11 4 36 20 Most borrowing arrangements under the short-A ai e70r term bank lines of credit require a fee of 0.25% per common stock . 5 (3) 30 14 year to be paid on any unused portion of the lines tw1 of credit. For those banks without fee require. Operating Revenues. 5213 5228 5238 5208 ments, the average daily cash balance in the *' 3 Company's bank accounts satisfied informal com-73n("N"' **1 [ j2 j2 Earnings AvailaNe for pensating balances. Common Stock . 6 8 8 2 Earnings for the quarter ended September 30,1992 At December 31,1992, the Company had $40 mil- were increased by $15 million as a result of the I lion of short-term notes outstanding under an recording of deferred operating expenses and car-uncommitted financing facility. The Company can rying charges for the first nine months of 1992 borrow up to $40 million until the agreement is totaling 522 million under the Rate Stabilization canceled by either party. Program approved by the PUCO in October 1992.

See Note 6.

At December 31,1992, the Company had no com-mercial paper outstanding. If commercial paper Earnings for the quarter ended December 31,1991 we e outstanding. it would be backed by at least were increased by $7 million as a result of a year-l an equal amount of unused bank lines of credit. end adjustment of 59 million to reduce deprecia-l tion expense for the year for the change in the

! nuclear plant straight-line depreciation rate to 2.5%  ;

(12) TINANCIAL INSTRUAfENTS' TAIR FALUE (see Summary of Significant Accounting Polici-s),

which was partially offset by another adjustment i The estimated fair values at December 31,1992 of of 51 million to reduce phase-in carrying charges ,

financial instruments that do not approximate for an adjustment to 1991 cost deferrals (see l their carrying amounts are as follows: Note 6).

21 ,

l l

1 Financial and Stdtistical Review Operating Revenues (millions of dollars) o Steam Total Total Total Heatmg Operating lear Reudential Commercial Induerial Other Retail Wholesale Flectnc & Cas Revenues 1992. 5215 175 236 61 687 158 845 -

5845 1991. 230 184 236 90 740 147 887 -

887 1990. 224 175 236 78 713 150 863 -

863 1 1989. 216 164 227 99 706 160 866 -

866 1988. 201 143 200 34 578 72 650 -

650 1982. 154 102 159 37 452 34 486 9 495 Operating Expenses (millions of dollars)

Other Deferred Fuel & Operation Depreciation Taxes, Operatmg Federal Total Purchased & & Other Than Ergarnws, income Operatmg Year Power Mamtenance Amortizahon FIT Net lames Expenses 1992. $169 342 77 91 (17) 33 5695 1991. 178 356 72(a) 89 1 32 728 1990. 174 373 73 79 (10) 21 710 1989. 172 373 85 72 (16) 37 723 1988. 138 359 75 80 (84) 29 597 1982. 138 118 44 41 --

45 386 Income (Loss) (millions of dollars)

Federal Other Income Income income & Deferred Taxes- Before Operatmg AFUDC- Deductions, Carrying Credit Interest

) car income Equiry Net Charges (Expense) Charges 4 1992. 5150 1 1 41 (1) $192 1991. 159 1 5 22 (6) 181 1990- 153 3 5 43 9 213 1989. 143 9 20 82 (22) 232 1988. 53 5 (247)(b) 130 86 27 198'. 109 49 1 -

19 178 1

Income (Loss) (millions of dollars)

L income (bss) liefore Earninp 3

Cumulat:ve Cumulative (bas)

Effect of an Effect of an Net Preferred Avadable Debt AFUDC- Accountmg Accountmg income Stock for Common Year interest Debt Change Change (bas) Dmdends Stock 1992. 5122 (1) 71 -

71 24 5 47 P

1991. 132 (1) 50 -

50 25 25 1990. 135 (3) 81 -

81 25 56 1989. 145 (5) 92 -

92 25 67 1988. 150 (2) (121) 6(c) (115) 27 (142) 1982. 95 (22) 105 -

105 26 79 (a) In 1991, a change in accounting for nuclear plant depreciation was adopted, changing from the units-of-production method to the straight-line method at a 2.5% rate.

(b) includes wnte-off of nuclear costs in the amount of $277 million in 1988.

(c) In 19 fib, a change in the method of accounting for unbilled revenues was adopted.

22 I

- __ . .._._m - . . . _. _ __ . _ - m_ _ . - - .& _

THE TOLEDO EDISON COMPANY Electric Sales (millions of KWH) Electric Customers (year end) Residential Usage Average Average Average Price Revenue industnal KWH Fer Per Per Year Residential Commernal Industrial Wholesale Othee Total Residential Commercial & Other Total Customer KWH Customer 1992. I 941 1 619 3 563 2 753 478 10 354 255 299 25 870 4 372 285 541 7 632 11.08c 5845.99 1991. 2 041 1 683 3 543 2 587 482 10 336 254 500 26 044 4 444 2S4 988 7 990 11.26 897.41 1990. 1950 1 614 3 617 2 333 496 10 010 253 965 25 822 4 555 284 342 7 692 11.48 882.99 1989. 2 017 1 622 3 740 3 138 495 11 012 253 234 25 803 4 434 283 471 7 989 10.71 855.29 1988. 2 068 1 579 2 7Rn 2 044 474 9 945 251 590 25 526 4 102 281 218 8 264 9.72 802.87 1982. 1 911 1 326 2 873 929 413 7 452 241 492 23 495 3 815 268 802 7 906 8.04 635.82 Load (MW & %) Energy (millions of KWH) Fuel Operable load Company Generated fuelCost Peak Capacity Purchased TU r Year of Peak load Margm Factor Fansil Nuclear Total Power Total Per KWH KWH 1992. 1 727 1 514 12.3% 63.2 % 4 656 6 293 10 949 (82) 10 867 1.41c 10 284 l 1991 1 758 1 510 14.1 64.5 4 648 6 003 10 851 95 10 946 1.44 10 327

! 1990. 1 752 1 516 13.5 63.0 5 535 4 219 9 754 902 10 656 1.50 10 220 1989 . 1 894 1526 19.4 65.2 5 206 5 552 10 758 788 11 546 1.42 10 293 1988. 1057(d) 1 614 (52.7) 62.8 5 820 3 325 9 145 1 491 10 636 1.59 10 174 1982. I 790 1 355 24.3 61.8 5 306 1569 6 875 1 044 7 919 1.80 10 221 Investment (millions of dollars)

Construction work in Total Utahty Accumulated Progress Nuclear Proterty, Utility Plant in Deprenation & Net & Perry Fueland Plant and Plant Total T ear Service Amortizanon Plant Unit 2 Other Equipment Additions Assets 1992. 52 847 760 2 087 280 164 52 531 5 44 53 939 i 1991 2 692 709 19S3 308 198 2 489 54 3 926 1990. 2 604 640 1 964 349 224 2 537 87 3 913 l 1989. 2 528 565 1 963 342 237 2 542 73 4 051 1988. 2 439 488 1 951 371 263 2 585 132 4 046 l 1982. 1 294 285 1 009 856 119(e) 1 984 249 2 181 Capitalization (millions of dollars & %)

Preferred Stock, Preferred stock, with Mandatory without Mandatory

, Year Common stock Equity Redemption Provmons Redempnon Proviuons long-Term Debt Total l

l 1992 . 5935 39% 50 2% 210 9% 1178 50% $2 373 1991 888 38 64 3 210 9 1158 50 2 320 1990. 881 39 66 3 210 9 1 097 49 2 254 1989 . 898 38 69 3 210 9 1197 50 2 374 1988. 887 36 71 3 210 9 1 291 52 2 459 1982 . 617 35 96 5 170 10 876 50 1 759 (d) Capacity data reflects extended generating unit outage for renovation and improvements.

(e) Restated for effects of capitalization of nuclear fuel lease and financing arrangements pursuant to Statement of Financial Accounting Standards 71.

23 i

I i 1

l estor Informa on

$11ARE OWNER INI ORMATION 0 SilARE OWNER SERVICES DIVIDEND REIN \T.STMENT AND STOCK PURCllASE Commumcations regardmg stock transfer requirements, PLAN AND INDI\7 DUAL RETIREMENT ACCOUNT '

l lost certificates, dividends and changes of address (CX*1RA) j should be directed to Share Owner Services at Centener Centerior Energy Corporation has a Dividend Energy Corporation. Correspondence should be sent Remvestment and Stock Purchase Plan which provides to the address mdicated below for the Stock Transfer Toledo Edison share owners of record and other Agent. To reach Sharc Owner Services by phone, call. mvestors a convenient means of purchasing shares of In Cleveland area 642-6900 or 447-2400 Centerior common stock by investing all or a part of ,

their quarterly dividends as well as making cash Outside Cleveland area 1-800-433-7794 im estments. In addaion, indinduals may establish an Please have your account number ready when calhng. Individual Retirement Account (IRA) which invests in Centerior common stock through the Plan. Information STOCK TRANSFER AGENT relatmg to the Plan and the CX*1RA may be obtamed Centenor Energy Corporation from Share Owner Services l Share Owner Sernces PO. Box 94661 INDLPENDENTACCOUNTANTS l Cleveland Oli 44101-4661 Arthur Andersen & Co.  !

Stock transfers may be presented at 1717 East Ninth Street FNC Trust Company of New York Cleveland Oil 44114 EN\1RONMENTAL REPORT e r1 1 The Company wdl farmsh to share owners, without STOCK REGISTRAR charge, a copy of a report on its environmental Society Nanonal Bank performance, Requests should be directed to Share Corporate Trust Division Owner Services.

PO Box 6477 FORM 10-K Cleveland OH 44101 i

The Company will furmsh to share owners, without l INVESTOR RELATIONS charge, a copy ofits most recent annual report to the Inquines from secunty analysts and institutional Secunties and Exchange Comm:ssion. Requests should imestors should be directed to lerrence R. Moran, be directed to Sharc Owner Services.

Manager-investor Relatmns, at the address of the Stock Transfer Agent or by telephone at (216) 447-2882.

EXCIIANGE LISTINGS hefencd-525 par value-8 84%,52 365 and 52.81 senes, Adjustable Series A and Adjustable Senes B-New York Stock Exchange Prc/cned-5100 par value-4 %%,8 32%,7.70% and 10% senes- American Stock Exchange BOND AND DEBENTURE INFORMATION BOND TRUSTEE AND PAYING AGENT DEBENTURE TRUSTEE AND PAYING AGENT 1 he Chase Manhattan Bank, N.A. Fifth Third Bank Corporate Trust Administration Division Corporate Trust Admmistration 4 Chase Metrotech Center,3rd Floor 38 Fountain Square Plaa Brooklyn NY 11245 Cmcinnati 01145263 (718)242-7290 (513) 579-5132 24 ,