ML20035G264

Toledo Edison Co 1992 Annual Rept, for Davis-Besse Nuclear Power Station & Perry Nuclear Power Plant,Unit 1, Respectively

ML20035G264
Person / Time
Site:	Davis Besse, Perry
Issue date:	12/31/1992
From:	TOLEDO EDISON CO.
To:
Shared Package
ML20035G237	List: ML20035G252 ML20035G258 ML20035G264 PY-CEI-NRR-1628, Forwards 1992 Annual Financial Repts for Davis-Besse Nuclear Power Station & Perry Nuclear Power Plant,Unit 1, Respectively
References
NUDOCS 9304270058
Download: ML20035G264 (26)

Text

.

I

?

= THE TOLEDO EDISBN COMPANY A Subsidiary of Centerior Energy Corporation i

i 1

i I

l

-l 3

i i

i

!i 3

{

i f

vk x

i k

k 11g a

{l f

/

e ANNUAL REPORT 9304270058 930421 PDR ADOCK 05000346 I

PDR

i i

1

- Contents

. h About Toledo Edison f

O i

O Directors.

i h Officers O Report ofIndependent Public f

Accountants O Summary of Significant Accounting Pohcies h Management's Fmancial Analysis, Finantial Statements and Notes t

$ Financialand Statistical Review f

@ InvestorInformanon i

i I

i L

i I'

I h

k t

i i

P i

l h

t r

s

I l

son The Company, a wholly owned subsidiary of Centerior Pobcn], Farhng, Chairman, President and Chief.

Energy Corporation, provides electric service to Execuuve Officer of Centerior Energy Corporation and o

about 660.000 people in a 2,500-square mile area of Centerior Service Company.

northwestern Ohio, mcluding the City of Toledo. The Company also provides electric energy at wholesale to Edgar H. Maugans. Vice President & Chief Fm.ancial 13 municipally owned distribution systems and one OWcer of the Company and The Cleveland Electric i

rural electric cooperative distribution system in its Illuminatmg Company and Executive Vice President of service area The Company's 2,400 employees serve Centerior Energy Corporation and Centerior Service about 286,000 customers.

Company.

Lyman C Phimps. Chairman and Chief Executive Officer of the Company, President and Chief Executive Officer of The Cleveland Electric Illummating Company and 1

ve Offices Executive Vice President of Centerior Energy I

Corporation and Centerior service 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 43652-0001 (419)249-5000 Chairman and Chief

}

i Executive Officer.

.Lyman C Philhrs President

. Donald H. Saunders

)'

Vice President & Chief Financial Officer.

. Edgar H. Maugans Vice President

. Fred), Lange,Jr.

j Controller.

. Paul G. Busby

.l l

Treasurer

. Gary M. Hawkmson l

Secretary.

. E. Lyle Pepin s

e t

i 4

l f

I f

I J

l t

F i

1 i

?

Report of Independent Public Accountants ARTHUR ANDERSEN To the Share Owners of The Toledo Edison Company:

o 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 of income, retained As discussed further.m the Summary of S.igmficant earnings and cash flows for each of the three years in the period ended December 31,1992. These financial Acc untmg Policies, a change was made m the s'.atements are the responsibility of the Company's method of accountmg for nuclear plant c epreciation i

m 1991, retroactive to January 1,1991.

management. Our responsibility is to express an opin-ion on these financial statements based on our audits.

As discussed further in Note 3(c), the future of Perry Unit 2 is undecided. Construction has been sus-We conducted our audits in accordance with generally accepted auditing standards. Those standards require Pended since July 1985. Various options are bemg that we plan and perform the audit to obtain reason-c nsidered, including resuming construction, con-able assurance about whether the financial statements verting the unit to a nonnuclear design, sale of all or are free of material misstatement. An audit includes part of the Company,s ownership share, or canceling examining, on a test basis, evidence supporting the the um,t. Management can give no assurance when, amounts and disclosures in the financial statements.

f ever, Perry Unit 2 will go in service or whether the An audit also includes assessing the accounting princi-Compan) s investment m, that umt 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 fmancial statements referred to

foove present fairly,in all material respects, the finan-cial position of The Toledo Edison Company as of Cleveland, Ohio December 31,1992 and 1991, and the results of its February 12,1993 2-

i Summary of Significant Accounting Po cies GENERAL nucle.:r fuel disposal costs are being recovered The Toledo Edison Company (Company) is an elec-through the base rates, o

tric utility and a wholly owned subsidiary of Center-The Company defers the differences between actual nor Energy Corporation (Centenor 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 presenbed 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 Nuclear Coordination Group (CAPCO). Other members in.

P wer Plant Unit 1 (Perry Unit 1) and Beaver Valley clude The Cleveland Electric Illuminating Company Power Station Unit 2 (Beaver Valley Unit 2). The lP an called for the Company to begin deferring in (Cleveland Electric), Duquesne Light Company (Du-quesne), Ohio Edisan Company (Ohio Edison') and Jamsary 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.

investment. These deferrals, called phase-in deferrals, l

s'.ructed 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 I and Beaver Valley Unit 2 from their respective in-service dates in 1987 through December RELATED PARTY TRANSACTIONS 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 indude those amounts for transactions with ary 1989 and will contmue over the lives of the affiliated companies in the ordinary course of bus.

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 primarily for firm power, interchange power, carrying charges related to plant placed in 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 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 provides management, financial, 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 Company billed the Company $60 million,561 mil-equivalent to an accumulated excess rent reserve for lion and 549 million in 1992,1991 and 1990, respec.

Beaver Valley Unit 2 over a 39 month period com-tively, for such services.

mencing October 1,1992. Amortization and recovery of this deferral will occur over the unit's remaining REVENUES lease term beginning in 1996. See Note 6.

Customers are billed on a monthly cyde basis for their energy consumption based on rate schedules or con.

DEPRECIATION AND AMORTIZATION tracts authorized by the PUCO or on ordinances of The cost of property, plant and equipment is depreci-mdividual municipalities. An accrualis made at the ated over their estimated useful lives on a streight-end of each month to record the estimated amount of I ne basis. The annual straight-line depreciation pro-unbilled revenues for kilowatt-hours sold in the cur rent month but not billed by the end of that month.'

vision for nonnudear property expressed as a per-cent of average depreciable utility plant in service 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 obtammg tomers the costs of fuel and most purchased power. It PUCO approval, changed its method of accountmg is reviewed and adjusted semiannually in a PUCO f r nudear plant depreciation from the units-of-pro-proceeding' duction method to the straight-line method at about a 3% rate. This change decreased 1991 depreciation E

TUEL EXPENSE

$11 million (net of $3 million of income taxes) from i

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, includ-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.

3 f

i

i i

The Company uses external funding of future decom-INTEREST CHARGES missioning costs for its operating nuclear units pursu-j 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 indude 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.

l customers over the remaining licensing periods of the l

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

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

decommissioning costs of $59 million in 1986 doPars with the regulatory rate treatment. Such losses and for the Davis-Besse Nudear Power Station (Davis-gains are either amortized over the remainder of the

~!

Besse) and $28 million in 1987 dollars each for Perry original life of the debt issue retired or amortized Unit 1 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.

l ment of these estimates in 1993 to update the decom-missioning cost amounts and to continue to satisfy the external funding requirements. It is expected that TEDERALINCOAff TAXES increases in the cost estimates will be recoverable in future rates. The present funding reqmrements 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 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-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.

ceeds the Balance Sheet amount of the external Nu-clear Plant Decommissioning 3 rusts 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 differences between the book and tax bases of assets PROPERTY, PIANT AND EQfIlPAfENT and liabilities. The majonty of these temporary dif-Property, plant and equipmeit are stated at original ferences are attributable to property-related basis dif-cost less any amounts ordered >v the PUCO to be ferences. Included in these basis differences is the written off. Construction costs incde related payroll equity component of AFUDC, which will increase taxes, pensions, fringe benefits, managment and future tax expense when it is recovered through rates, general overheads and allowance for funce used dur-Since this component is not recognized for tax pur-ing construction (AFUDC). AFUDC repres nts the poses, we must record a liability for our tax obliga-estimated composite debt and equity cost d funds tion. The PUCO permits recovery of such taxes from used to finance construction. This noncash a lowance customers when they become payable. Therefore, is credited to income, except for certain AFUDC for the net amount due from customers through rates has 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% i.: 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 charged to the utility plant accounts. The cost of as a reduction of depreciation expense. See Note 6 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 Rate Stabilization Program.

DETERRED GAIN AND LOSS TROAf SM OT MIMW RECLASSITICATIONS The sale and leaseback transactions discussed in Note 2 resulted in a net gain for the sale of the Bruce Certain reclassi6 cations were made to prior years Mansfield Generating Plant (Mansfield 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-and the lease expense amounts are recorded as other hed as an offset against the Perry Unit 2 asset balance.

operation and maintenance expenses. See Note 6.

See ' Note 3(c).

4

Management's Financial Analysis i

RESULTS OF OPERATIONS ongoing determination that recovery of the de-ferred costs in rates is probable.

o t

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 54 million in 1994, increasing to $101 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 inflation has j

designed to have a relatively neutral impact on eased in recent years, we are still affected by even earnings. Gains in revenues were to be initially modest inflation which causes increases in the offset by a reduction in the deferral of operating' unit cost of labor, materials and services.

l expenses and carrying charges and subsequently offset by the amortization of such deferrals. A key To combat the forces described above, we have assumption underlying the phase-m plan was that embarked on the following course. Reductions in revenues would increase as a result of projected other operation and maintenance expenses and sales growth. When sales decreased primarily be-capital expenditures were implemented in 1991 and cause of a u ish economy, earnings were ad-1992 and will be vigorously pursued in 1993 and beyond. We will further reduce staffing levels and look to improve efficency 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 seekm, g additional long-term recording of nuclear plant depreciation at levels in Power sales agreements with wholesale customers 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 Pobey Act of 1992 (Energy placed in service after February 1988 as current Act), which requires utilities to transmit electricity expenses even though such items were not being from wholesale suppliers to wholesale customers, a

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 imtiatives, we have continued i

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, beyond what one might expect from a apal system. Such programs include provid-industrial and commercial customers.

mu ing services to communities to help them retain We determined that the best solution to address and attract businesses, providing consulting ser-i these factors was to delay 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-Programs.

proval of regulatory accounting measures designed increases in sales are expected to be modest with to recognize the effects of a delay m rate recovery annual sales growth projected at about 1-2% for the of certam 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 and rate of accruing nuclear plant depreciation. In that costs can be reduced only so far and the limitations imposed by our sales forecasts and com-October 1992, the PUCO approved a Rate Stabih,-

petition in the wholesale power market, rate in-zation Program, which was supported by certain creases will be necessary eventually to recognize customer representative groups, as discussed in the cost of our new capital investment, 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-

.j recovered in rates and to accelerate amortization of nues give us the opportunity to improve our com-certain benefits. However, our ability to utilize petitive position and our earnings. Nevertheless, these regulatory accounting measures is dependent we operate in a changing industry and market. We upon our taking significant 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 5

t F

i

)

regulatory accounting provided by our various ing income increased primarily because of Rate i

agreements.

Stabilization Program carrying charge credits. In-

[

terest charges decreased as a result of debt refinanc-

[

ings at lower interest rates and lower short-term 3992 3,7997 borrowing requirements.

Factors contributing to the 4.8% decrease in 1992 j

operating revenues are as follows:

1991 vs.1990 l

Millions increase (Decrea<.r} in Operating Revenues of Dollars se R d isc llaneous',

operating revenues are as follows:

Wholesale Sales.

11 Millio"8 increase (Decrease) in Operating Revenues of Dollars

{

Base Rates and Miscellaneous -

520.

Sales Volume and Mix.

7 Wholesale Sales..

13)

The revenue decreases resulted primarily from the different weather conditions in both years and the

$_21 l

changes in the composition of the sales mix among customer categories. Weather accounted for

-1 approximately $22 million of the lower 1992 reve.

A significant factor accounting for the increase in i

nues. Winter and spring in 1992 were milder than operating revenues resulted from the January 1989 in 1991. In addition, the 1992 summer was the PUCO rate order for the Company as discussed in Note 6. Total kilowatt-hour sales increased 3.3%

coolest in 56 years in Northwestem Ohio as con-trasted with the summer of 1991 which was much in 1991. Residential and commercial sales increased hotter than normal. Total kilowatt-hour sales in-4.6% and 4.3%, respectively, as a result of higher 1

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

sales decreased 4.9% and 3.8%, respectively, as unusually warm late spring and summer 1991 tem-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 for the commercial sector. Industrial sales declined

'l creased 0.6% as increased sales to glass and metal 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 j

increased 8.5% because of increased sales to whole-troleum refining and auto manufacturing customers. Other sales increased 5.2% because of sale customers.

}

increased sales to wholesale customers. Operating revenues in 1991 included the recognition of $24 Operatmg expenses mcreased 2.3% in 1991. The f

million of deferred revenues over the period of a increase was mitigated by a reduction of $17 l

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' j

flected 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 j

Operating expenses decreased 4.4% in 1992. A re-federal income taxes, resulting frorn higher prop-j duction of $14 million in other operation and main-erty and gross receipt taxes and accruals for Penn-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 by higher depreciation and amortization, caused deferrals for Perry Unit 1 and Beaver Valley Unit 2 primarily by the adoption of SFAS 109 in 1992, and pursuant to the January 1989 rate order.

by higher taxes, other than federal income taxes, caused by increased Ohio property taxes. Deferred Credits fcr carrying charges recorded ini i

operating expenses increased as a result of the nonoperating income decreased in 1991 because a deferrals under the Rate Stabilization Program as greater share of our investments and leasehold mentioned in Note 6.

interests in Perry Unit 1 and Beaver Valley. Unit 2 i

were recovered in rates. The federal income tax The federal income tax provision for nonoperating provision for nonoperating income increased j

income decreased because of a greater tax alloca-mainly because the 1990 provision was reduced $19 tion of interest charges to nonoperating activities.

million for unamortized investment tax credits on -

t Credits for carrying charges recorded in nonoperat-the 1988 write-off of nuclear plant investment, 6

i i

f

" " "^*

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

Operating Revenues (1)

$845

$887

$863 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).

[

Federal income taxes.

33 32 21

+

695 728 710 Operating income 150 159 153 Nonoperating income Allowance for equity funds used during construction I

1 3

Other income and deductions, net...

1 5

5 Deferred carrying charges..

41 22 43 Federal income taxes - credit (expense)..

(1)

(6) 9 i

42 22 60 income Before Interest Charges.

192 181 213 interest Charges 122 132 135 l

Debt interest Allowance for borrowed funds used during construction (1)

(1)

(3) l 121 131 132 Net Income 71 50 81 Preferred Dividend Requirements.

24 25 25 Earnings Available for Common Stock

$ 47 5.25

$ 56 (1) Includes revenues from all bulk power sales to Cleveland Electric of $130 million, $128 million and $112 million in 1992,1991 and 1990, respectively.

Retained Eamings For the years ended December 31, 1992 1991 1990 (millions of dollars)

Balance at Beginning of Year.

$ 90

$ 83

$100 j

Additions l

Net income 71 50 81 Deductions Dividends declared:

Common stock (18)

(73)

Preferred stock (24)

(25)

(25)

J Net Increase (Decrease)..

47 7

(17)

Balance at End of Year.

$137

$ 90

$ 83 The accompanying notes and summary of significant accounting policies are an integral part of these statements.

7 i

1

L 4

Management's Financial Analysis CAPITAL RESOURCES AND LIQUIDITY ance with the Clean Air Act Amendments of 1990 (Clean Air Act). Expenditures for our optimal We need cash for normal corporate operations, the pian are estimated to be approximately $36 milh,on mandatory retirement of securities and an ongoing ver 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 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 penod of 1990-1992 these construction and effect on our liquidity. See Note 3(d).

mandatory retirenu nt needs totaled approximately

$530 million. In a<',dition, we exercised various We expect to be able to raise cash as needed. The options to rec 6rn and purchase approximately availability and cost of capital to meet our external

$520 millk,n of our secunties.

financing needs, however, depends upon such We raised $784 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 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 follows:

i Comparjy are $203 million for its construction program and $154 million for the mandatory re-Standard Moody's demption of debt and preferred stock. The Com-

& Poor's Investors pany expects to finance externally about 10% of its Corporation service total 1993 cash requirements of approximately First mortgage bonds.

BBB-Baa3

$118 million. About 40-50% of the Company's 1994 Unsecured notes.

BB+

Bal i

and 1995 requirements ar expected to be financed Preferred stock.

BB+

ba2 externally. If economical, additional securities may

[

be redeemed under optional redemption provi-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 timing of such a wnte-off, could stock and debt.

reduce retamed earnmgs sufficiently to impair its Our capital requirements after 1995 will depend on ability to declare dividends, but would not affect our implementation strategy to achieve compli-cash flow.

.l i

f f

8 j

i

THE TOLEDO EDISON COMPANY For the years ended December 31, 1992 1991 1990 n

(minions of dollars)

Cash flows from Op ' rating Activities (1)

Net Income.

$ 71 5 50

$ 81 Adjustments to Reconcile Net income to Cash from Operating Activities:

Depreciation and amortization.

77 72 73 Deferred federalincome taxes 28 32 31 Investment tax credits, net (5) 30 (17)

Deferred and unbilled revenues.

1 (26)

(23)

Deferred fuel (4) 4 Deferred carrying charges.

(41)

(22)

(43)

Irased 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 r.nd others, net.

3 (9)

Changes in inventories.

(9)

(7)

(7)

Changes in accounts payable.

(8)

(13) 7 Changes in working capital affecting operations 7

(26) 1 Other noncash items 13 14 15 Total Adjustments..

97 115 46 Net Cash from Operating Activities 168 165 127 Cash flows from Financing Activities (2)

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)

Loans to affiliates 12 (12) 114 Sale and leaseback restructuring fees.

(43)

Other cash applied.

(5)

(3)

(4) i Net Cash from Investing Activities.

(85)

(67) 26 Net Change in Cash and Temporary Cash Investments.

(63) 57 (52) l Cash and Temporary Cash Investments at Beginning of Year 79 22 y

i Cash and Temporary Cash investments at End of Year.

$ 16 5 79

$ 22 1

(1) Interest paid (net of amounts capitalized) was $95 million, $120 million and $114 million in 1992,1991 and 1990, respectively. Income taxes 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 accompar.ying notes and summary of significant accounting policies are an integral part of this statement.

)

9 1

i

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

ASSETS j

Property, Plant and Equipment Utility plant in service.

52,847

$2,692 Less: accumulated depreciation and amortization..

760 709 2,087 1,983 Construction work in progress.

37 54 Perry Unit 2.

243 254 2,367.

2,291 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 1

Amounts due from customers and others, net.

60 60 l

Accounts receivable from affiliates.

23 22 Notes receivable from affiliates..

12 Unbilled revenues 21 22 40 37 Materials and supplies, at average cost.

Fossil fuel inventory, at average cost.

25 19 Taxes applicable to succeeding years.

71 66 2

3 Other...

258 320 Deferred Charges and Other Assets Amounts due from customers for future federal income taxes..

391 472 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 20 15 Nuclear plant decommissioning trusts.....

92 53 Other.

1,150 1,117 i

53,939 53,926 i

Total Assets.....

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

10 1

L e

THE TOLEDO EDISON COMPANY December 31,

.l 1992 1991

{

(millions of dollan) i CAPITALIZATION AND LIABILITIES Capitalization Common shares, $5 par value: 60.0 million authorized; j

39.1 million outstanding in 1992 and 1991.........

$ 196

$ 196-jl Premium on capital stock........

481 481 Other paid-in capital...........

121 121 Retained earnings.

137 90

]

Common stock equity Preferred stock 935 888 50 l

With mandatory redemption provisions.

64 1

Without mandatory redemption provisions.......

210

.210 Long-term debt..

1,178 1,158 e

2.373 2.320 Other Noncurrent Liabilities 126 143 Nuclear fuel lease obligations.

Other....

62 50 188 193 i

r Current Liabilities Current portion of long-term debt and preferred stock...

58 123 Current portion of nuclear fuel lease obligations.

51 64 Notes payable to banks and others..

40 7

A ccounts payable........

47 55 Accounts and notes payable to affiliates....

16 40 Accrued taxes 78 68 Accrued interest...

28 31 Other........

14

-16 332 397 l

I Deferred Credits Unamortized investment tax credits..........

103 108 Accumulated deferred federal income taxes...............................

640 577 l

Unamortized gain from Bruce Mansfield Plant sale.......................

218 227-Accumulated deferred rents for Bruce Mansfield Plant and Beaver Valley Unit 2.........

46 67 Other...

39 37 1,046 1,016 Total Capitalization and Liabilities.

$3,939

$3,926 I

e 1

i j

l 11 i

l I

1

"" EDISON COMPANY j

Statement of Preferred Stock Current Call Price o

1992 Shares Per December 31, t

Outstanding Share 1992 M1, (millions of dollars) 1

$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

$3 9.375..

116,800 102.96 12 13 25 par 2.81 2,000,000 26.25 50 50 62 66 l

less: Current maturities 12 2

j Total Preferred Stock, with Afandatory Redemption Provisions S 50

$ 64 Not subject to mandatory redemption:

$100 par $ 4.25 160,000 104.625

$ 16

$ 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 l

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 j

$210

$210 Total Preferred Stock, without hiandatory Redemption Provisions.......

The accompanying notes and summary of signi6 cant accounting policies are an integral part of this statement.

l 1

{

i 1

i 1

t 12-

t 4

4 Notes to the Financial Statements (1) PROPERT)' OWNED WITH OTHER UTILITIES AND INVESTORS 3

o The Company owns, as a tenant in common with other utilities and those im estors who are owner-participants in

)

various sale and leaseback transactions (Lessors), certain generating units as listed below. Each owner owns an l

t undivided share in the entire unit. Each owner has the right to a percentage of tha generating capability of each unit equal to its ownership share. Each utility owner is obligated to p:y for only its respective share of the 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 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:

1 Construction Owner-Work in In-Owner-ship Plant Progress Service ship Mega-Pewer in and Accumulated Genecattne Unit Date Share watts Sount Sendre Suspended Derreciation (millions of dollars)

In Semce.

Davis 4 esse.

1977 48 62%

429 Nuclear 5 672 5 8 5151 Perry Unit 1 and Common Taalities.

1987 19.91 238 Nuclear 1,042 2

158 Braver Valley Unit 2 and Common Fachties s

(Note 2) 1987 1.65 13 Nuclear 203 3

30 Construaior Suspended.

Perry Unit 2 (Note 3(c)).

Uncertain 19.91 240 Nuclear

~

y i

51.917 5256 5339 4

1 f 2) UTILITY PLANT SALE AND LEASEBACK TRANSACTIONS The Company and Cleveland Electric are co-lessees 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-t 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 Plar t leases, the t

of the Mansfield Plant, respectively, all for terms of Company would be obligated to make such pay-about 29W years. These leases are the result of sale ments. No payments have been made on behalf of i

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-l ance premiums, operation and maintenance costs cial purpose corporation in connection with fi-3 and all other similar costs for their interests in the nancing the sale and leaseback of Beaver Valley l'

units sold and leased back. The Company and Unit 2 were refmanced through a tender offer for 1

Cleveland Electric may incur additional costs in the outstanding SLOBS and the sale by another connection with capitalimprovements to the units.

special purpose corporation of new bonds having a 1

The Company and Cleveland Electric have options lower interest rate. As part of the refinancing trans-i to buy the interests back at the end of the leases action, the Company paid $43 million as supple-i i

for the fair market value at that time or to renew mental rent to fund transaction expenses and j

the leases. Additional lease provisions provide part of the tender premium. This amount has been 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 refinancing transaction reduced repurchase of the leasehold interests) for events of the straight-line annual rental expense for the default. These events include noncompliance with Beaver Valley Unit 2 lease by $9 million.

several financial covenants discussed in Note l

10(d).

d k

13 l

~

'{

t

- Future minimum lease payments under the operat-greater use of low-sulfur coal at some of our units i

ing leases at December 31,1992 are summarized as and the banking of emission allowances. The plan follows:

would require capital expenditures for the Com- -

'[

pany over the 1993-2002 period of approximately J

3, ror the cleoctand

$36 million for nitrogen oxide control equipment, M

Comr,an ricctric emission monitoring equipment and plant modifi-

{

(millions of dollas) cations. In addition, higher fuel and other opera-1993.

5 103 5 63 tion and n.aintenance expenses would be i

1994.

103 63 incurred. The anticipated rate increase associated

.I 1995.

102 63 with the Company's capital expenditures and 1996.

125 63 higher expenses would be less than 2% over the i

er cars.

2.

1.4 Toul Future Mmimum trase Our compliance plan will depend upon future envi-nymena.

s2.6ss 51.768 ronmental regulations and input from the PUCO, other regulatory bodies and other concerned enti-Rental expense is accrued on a straight-line basis ties. In addition, we are continuing to monitor over the terms of the leases. The amount recorded developments m new technologies that may be j

inc rPorated into our compliance strategy.1f a plan i

in 1992,1991 and 1990 as annual rental expense for the Mansfield Plant leases was $45 million. The ther than the least cost plan is required, sigmfi-amounts recorded in 1992 and both 1991 and 1990 cantly higher capital expenditures could be re-qutred dunng the 1993-2002 period. We beb, eve j

as annual rental expense for the Beaver Valley Unit 2 lease were $66 million and $72 million, Ohio law perrrdts the recovery of compliance costs j

fr m customers an rates.

respectively. Amounts charged to expense in excess of the lease payments are classified as Accumu-lated Deferred Rents in the Balance Sheet.

(c) PERRY UNIT 2

.l The Company is selling 150 megawatts of its Bea-Perry Unit 2, including itt share of the common j

ver Valley Unit 2 leased capacity entitlement to facilities, is approximately 50% complete. Construc-i Cleveland Electric. We anticipate that this sale will tion of Perry Unit 2 was suspended in 1985 pend-l continue at least until 1998. Revenues recorded for ing future c nsideration of various options. These.

this transaction were $108 million, $107 million ptions include resumption of full construction j

with a revised estimated cost, conversion to a non-and $103 million in 1992,1991 and 1990, respec_

tively. The future minimum lease payments associ-nuclear design, sale of all or part of our ownership ated with Beaver Valley Unit 2 aggregate $1.533 share, or cancellation. No option may be imple-bution' mented without the unanimous approval of the owners. A request by Cleveland Electric, the com-Pany responsible for the construction of Perry l

(3) CONSTRUCTION AND CONTINGENCIES Unit 2, for an extension of the construction hcense (a) CONSTRUCTION PROGRAAf iS Pending with the Nuclear Regulatory Commis-sion (NRC).

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.

P ans to resume construction of Perry Unit 2. It l

including AFUDC of $10 million and excluding nuclear fuel.

was made to keep the various options open.

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

. (b) CLEAN AIR IEGISlAT10N ment would have to be written off. Such a write-i off (based on the Company's investment as of the The Clean Air Act will require, among other things, end of 1992) would be about $171 million. Notes significant reductions m the emission of sulfur 10(b) and (d) discuss more about the effects of a i

dioxide m two phases over a ten-year period and write-off nitrogen oxides by fossil-fueled generating units.

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

- Centerior Energy developed a compliance strategy nonnuclear design, we would expect to write off a

'I for the Company and Cleveland Electnc which portion of our investment for nuclear plant con-I was submitted to the PUCO in 1992 for review.

struction costs not transferable to the nonnuclear f

Centerior Energy subsequently reached agreement construction project.

with intervening parties and is awaiting formal j

- PUCO approval. Centerior Energy also is seeking Perry Unit 2 AFUDC was credited to a deferred 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 j

which results in the least cost and the greatest deferred AFUDC amount of $88 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 l

,i

I i

4 (d) SUPERFUND SITES share of such excess amount could have a material l

adverse effect on its financial condition and 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 j

dressing the cleanup of hazardous waste disposal coverage. It includes the incremental cost of any i

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 deanup of two hazardous waste sites. The been operating) and other incidental expenses after l

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 matters will not have a material adverse effect on during the 52-week period starting 21 weeks after 1

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

(4) NUCEEAR OPERATIONS AND CONTINCENCIES extra expense could substantially exceed the insur-(a) OPERATING NUCLEAR UNITS j

The Company's interests in nudear units may be (c) NUCLEAR DECONTAAflNATION AND -

l impacted by activities or events beyond our control.

DECOAfAflSSIONING ASSESSAfENT Operating nudear generating units have exper' The Energy Act permits special assessments on ienced unplanned outages or extensions of sched-investor-owned electric utilities which own nuclear i

uled outages because of equipment problems or generating plants for the decontamination and new regulatory requirements. A major accident at a decommissioning of nudear enrichment facilities nudear facility anywhere m the world could cause operated by the Department of Energy. The assess-the NRC to limit or prohibit the operation, con-ments to individual utilities are based upon the struction or licensing of any nuclear unit. If one of I

amount of enrichment services used in prior years our nudear units is taken out of service for an and cannot be imposed for more than 15 years. At l

extended period of time for any reason, mdudm.g December 31,1992, the Company accrued a liabil-t an accident at such unit or any other nudear facil~

ity of $15 million for its share of the total assess-sty, the Company cannot predict whether regula~

ments. These costs are recorded as deferred charges i

tory authorities would impose unfavorable rate I

since, based on the legislation, the Company be-treatment. Such treatment could mclude taking 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 I

construction or maintenance costs. An extended factors' i

outage of one of our nuclear units coupled with unfavorable rate treatment could have a material adverse effect on our financial condition and results (5) NUCLEAR FUEL of Operations' The Company has inventories for nudear fuel which should provide an adequate supply into the

}

fFI NUCLEAR INSURANCE mid-1990s. Substantial additional nuclear fuel i

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 mcident Nudear fuel is financed for the Company and i

Cleveland Electric throuSh leases with a special at any unit m the United States resulting m losses Purpose corporation. The total amount of financm.-

g in excess of the level of private insurance (cur-rently $200 million), the Company's maximum currently available under these lease arrangements i

potenthi assessment under that plan would be $59 is $509 million ($309 million from mtermediate-term n tes and $200 million from bank credit niillion (plus any inflation adjustment) per inci-dent. The assessment is limited to $9 million per arrangements). Financing in an amount up to $900 year for each nudear incident. These assessment nulhon is permitted. The m, termediate-term notes mature m, the period 1993-1997, with $77 milhon limits assume the other CAPCO companies con-tribute their proportionate share of any assessment.

maturing in September 1993. The bank credit j

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 (induding leased fuel and nuclear fuel was financed for the Company. The i

dean-up costs). Coverage amounted to $2.625 Company and Cleveland Electric severally lease j

billion for each site as of January 1,1993. Damage their respective portions of the nudear fuel and are j

to property could exceed the insurance coverage obligated to pay for the fuel as it is consumed in a j

. by a substantial amount. If it does, the Company's reactor. The lease rates are based on various inter.

15 I

l

~

-~

f i

mediate-term note rates, bank rates and commer-The Company deferred $33 million, $28 million f

cial paper rates.

and 560 million in 1992,1991 and 1990, respec-J I'

" E Y"'"' "

"E ' ##E"'

The amounts financed include nuclear fuel in the pursuant to the phase-m plan. The amount of Dav.is-Besse, Perry Unit 1 and Beaver Valley Unit 2 deferrals scheduled to be recorded in 1993 total $15 reactors with remaining lease payments for the million. Beginning in the sixth year (1994) and i

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

lion, respectively, as of December 31,1992. The levels authorized pursuant to the phase-in plan i

nuclear fuel amounts fmanced and capitalized als were designed to be sufficient to recover that pe-mcluded interest charges incurred by the lessors riod's operating expenses, a fair retum on the unre-amounting to $6 milhon m 1992, $9 milhon m 1991 covered investments, and the amortization of the l

and $14 milhon m, 1990. The estimated future lease deferred operating expenses and canying charges i

amortization payments based on projected con-recorded during the first five years of the plan. The sumption are $45 milhon m 1993, $47 million in phase-in deferrals relating to these two units will 1994, $43 milhon m 1995, $40 milhon m 1996 and total $241 million after 1993 which reflects an $11

[

$37 milhon,m 1997.

million reduction of deferrals for 1990 and 1991 j

pursuant to the plan. The deferrals are scheduled to j

(6) REGULATORY MATTERS be amortized and recovered as follows: $4 million j

in 1994, $25 million in 1995, $48 million in 1996, 4

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 i

the Company of approximately 9%,7% and 6%

$11 millior) reduction referred to in the preceding i

effective with bills rendered on and after February sentence. These amortizations can be accelerated at 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 ment audit were used to reduce the rate increase.

Stabilization Program as set forth in a joint recom-j The Company waived its 2.74% rate increase for mendation filed by the Company, Cleveland Elec-residential and small commercial customers and tric and certain customer representative groups

'i reduced its residential rate by 3% effective in March involved in the 1989 rate case settlement. Under 1991 and by an additional 1% effective in Septem-the Rate Stabilization Program, the Company-ber 1991 to improve its competitive position in its agreed to frceze base rates until 1996 and limit

-[

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 1

order were $44 million and $2 million, respec-in 1998. For purposes of any rate increase proceed-tively. The increase in 1991 reflects the net of $19 ing in the 1996-1998 period, the Company agreed

_i million of annualized revenues authorized for the to cap operation and maintenance expenses 2.74% increase less $17 million for the waiver and (other than fuel and purchased power) at $784 i

rate reductions.

million on a consolidated basis for Centerior En-1 ergy, subject to adjustment for inflation and other i

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 couphx! with then-projected sales growth, would additional regulatory accounting measures would

{

provide revenues over the ten years beginning be dependent upon our success in implementing

'I january 1,1989 sufficient to recover all operatmg cost-reduction and revenue-enhancement initia-expenses and provide a fair rate of retum on the tives. The Company agreed to seek authorization Company's allowed investments m Perry Unit 1 for acceleration of the post-1998 Mansfield Plant and Beaver Valley Unit 2. Revenues in the first unamortized gain in any rate increase proceeding five years of the plan were expected to be less than in the 1996-1998 period. See Summary of Signifi-I that required to recover operating expenses and cant Accounting Policies.

t provide a fair return on investment. Therefore, the amounts of operating expenses and return on As part of the Rate Stabilization Program, the Com-l 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 i

ferred federal income taxes that result from the use stabilization by rescheduling the timing of rate of accelerated tax depreciation. Therefore, the recovery of certain costs and the amortization of i

amount of revenues required to provide a fair certain benefits, thereby preventing what otherwise return also declines. This results in decreasing would be an crosion in earnings during the 1992-i 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 -

q tion and recovery in the later years of the plan.

dependent upon a continuing assessment and de-16

~

J I

~

7 J

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

= 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-l this period could be as much as $179 million on an tion of the customer benefit of these transactions.

j 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 i

revenue-enhancement initiatives, among other fac-events.

I tors. Such regulatory accounting measures which i

are eligible to be recorded through December 31, Deferred Operating Expenses, Net, and Deferred j

1995 on an after-tax basis are as follows:

Carrying Charges shown in the income Statement

. Deferral of up to $100 million of accrued post-in-c nsist of the following:

{

service interest carrying charges, depreciation 1992 1992 1990 expense and property taxes on assets placed in 7minionQdoh7 I

service after February 29,1988. The deferrals Deferred Operating Expenses, Net:

recorded in 1992 were retroactive to January 1, Phase-in. -

5 (6) $ (6) $(17) 1992. Deferrals are based on actual capital ex-Rate Stabiliation..

(18) penditures relating to assets placed in service Amortiution of Pre-Phase-in i

Defenals.

7 7

7 i

within the 1988-1995 period. Consequently, the deferrals will be lower than $100 million if the Total.

$317) y silo) l f

Company continues to reduce capital expendi' Deferred carrying charges.

tures. Amortization and recovery of these defer-phase.in:

rals will occur over the average life of the assets Debt.

$ 10

$7

$ 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.

G G

G l

penses equivalent to an accumulated excess rent

=

=

=

reserve for Beaver Valley Unit 2 which resulted from the April 1992 refinancing of SLOBS as (7) TEDERAL INCOME TAX l

discussed m Note 2. The deferral commenced 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-c me re taws h tk statutory rates,is ruon-beginning in 1996.

ciled to the amount of federal income tax recorded j

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

$32 million in unrestricted excess deferred taxes 1992 2991 1990 -

and $16 million in unrestricted investment tax credits available after 1998. The amortizations U"

"I I

commenced October 1,1992. The amortization of

$3"**' B*' " f*d""(I""*'

33 g,,

3 gg

, 93

. investment tax credits is reported as a reduction of depreciation expense.

Tax on Book income at Statutory Rate... __ -.

$ 36

$ 30

$ 32 t

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

(6)-

3 (1) spent fuel storage accrual balances for Davis-

","yg,y g

Besse. The amortization commenced October 1, amortiution....

5 5

7 1992.

Investment tax credits on disallowed nuclear plant.

(19)

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

(2) 7 quently recover the incremental expenses associ.

Taxes. other than federal income I

ated with adoption of the accounting standard for g,3,,$,,,

}

I J postretirement benefits other than pensions. See Total Federal Income Tax Expense..

$ 34 5 38

$ 12 l

Note 8(b).

=

-

i l

i I

j 17

J

.a 4

A.

A L

6' W-E.

--4 3e.+

-a s

Im.6 M

a'-~a*

A-a.:

,E_m I

l

- Federal income tax expense is recorded in the Millions of

.i Donars income Statement as follows:

1992 1991 1990 Property. plant and equipment..

. 5656 l

(millions of dollars)

Deferred carrying charges and operating expens.es.,

119:

Net operating loss carryforwards.

(56)-

Operatmg Expenses:

Investment tax cwdits.

(58)

Current Tax Provision.......... 5 26 5 14 5 17 Other.

3)

Changes in Acmmutated Deferred Federal inmme Tax:

. Net deferred tax liability.

5640

[

Accelerated depreciation and 7

9 2

amortization.

Alternative minimum tax credit.

(13)

(44)

(5)

For tax purposes, net operating loss (NOL) car-l Sale and leaseback transactions ryforwards of approximately $165 million are avail-and amortization.

4 13 5

able to reduce future taxable income and will Rate Stabihzation.

2 expire in 2003 through 2005. The 34% tax effect of Property tax expense.

5 (4) the NOLs is $56 million.

i Reacquired debt costs..

4 7

(1)

Deferred construction work in The Tax Reform Act of 1986 provides for an alter-native minimum tax (AMT) credit to be used to DeErr d fuS"s"s$ '

l

()

()

Other items...

(3) 2 1

reduce the regular tax to the AMTlevel should the Investment Tax Credits.

27 1

regular tax exceed the AMT. AMT credits of $40 Total Charged to Operating million are available to offset future regular tax.

j Expensn 33 32 21 The credits may be carried forward indefinitely.

f Nonoperating income:

Current Tax Provision...

(20)

(38)

(18)

(8) RETIREMENT AND POSTEMPLOYAfENT l

Changes in Acenmulated Deferred BENETITS Federal Income Tax:

jg{"y{",y,'*' "' ~

(a) RETIREMENT INCOME PLAN l

I'*)

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 income.

1 6

J) upon the length of service. Under certain circum-3 Total Federal income Tax Expense.

5 34 5 38 5 12 stances, benefits can begin as early as age 55. The f

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.

federal income tax return with its affiliated com-with the Employee Retirement income Secunty Act f 1974 guidelmes.

panies. The method of tax allocation reflects the benefits and burdens realized by each company's in 1990, the Company offered a Voluntary Early participation in the consolidated tax return, approx-Retirement Opportunity Program (VEROP). Oper-l imating a separate retum result for each company.

ating expenses for 1990 included $7 million of

-l Pension plan accruals to cover enhanced VEROP l

In 1990, adjustments for unamortized investment benefits and an additional 58 million of pension f

tax credits on the 1988 write-off of nuclear plant costs for VEROP benefits paid to retirees from investment decreased the federal income tax provi-c rporate funds. The 58 milhon is not mcluded m, sion for nonoperating income $19 million. Also in the pension data reported below..A credit of 55 j

1990, the resolution of a property tax deduction milli n resulting from a settlement of pension obh,-

issue resulted in a reduction in federal income tax gations through lump sum payments to a substan-expense of 54 million.

tial number of VEROP retirees partially offset the i

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

.l 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:

l

^an offsetting increase in Accumulated Deferred

. g, q

,,y Federal Income Taxes.

4 (millions of dollars)

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

service cost for benents earned ryforwards gave rise to deferred tax assets of $154 d

5 5 55 55 million and deferred tax liabilities of $794 million go, ","jaj, Q &,g at December 31,1992. These are summanzed as obligatica.

... 11 11 11 i

follows:

Actual return on plan assets...

(5)-

(30) 2 i

..,,,QO)

_15, y) '-

Net amortization and deferral.

Net pension costs.

I 1

3 3

VEROP cost..

7 i

(5)

{

Settlement gain

. 5 1 5 1 5 5 l

Net rosts.

i i

18 l

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.

. rend rate, work force demographics, plan provi-1997 1991 sions or interest rates. Like the retirement income (mimons of plan, these estimates reflect a discount rate assump-doners) tion of 8.5% per year. The annual health care cost Actuanal present value of benent obligations.

trend assumption is 12% in 1992, reducing gradu-Vested benefits..

5 95 5 92 ally to an ultimate annual rate of 6% in 1996 and Nonvested benehts.

. 12 10 Wer ym Accumulated tencht obligation 107 102 Effect of future compensation levels.

. 35 34 The PUCO authorized the Company to defer for Total projected beneht obliganon.

142 136 subsequent recovery postretirement benefit costs 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-zation Program discussed in Note 6. The amount Unr ized net gain from variance betmen we can defer will be determined by the extent to assumptions and expenence.

(33)

(40) unrecognized prior service cost...

5 5

which Centerior Energy is successful in reducing Transinon asset at lanuary L 1987 being the added obligation on a consolidated basis by $37 amortized over 19 years.

27)

E8) million or 25% of the incremental costs expected Net accrued pension liabihty included in when the Company got the order. The Company its - Other in the

{ferred and Centerior Energy have until December 31,1997 S

== ) _

to make the reductions.

g At December 31,1992 and 1991, the settlement (c) POSTEMPLOYMENT BENEFITS (discount) rate and long-term rate of return on 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 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 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 benefits The Company has guaranteed certain loan and during the employees years of service. The as-lease obligations of a mining company under a sumptions and calculations myolved m determin' long-term coal purchase arrangement. This ar-ing the accrual closely parallel pension accounting rangement requires payments to the mining com-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 benehts 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 million in 1990.

(10) CAPITALIZATION The Company will adopt the standard effective 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).

(amends of deren Had the standard been adopted in 1992, the addi.

Subject to Mandatory Redemption:

tional 1992 postretirement benefit cost would have

$100 par 511 A (25) 00) 00)

E E

E been in the range of $10 million to $13 million Total..

g). g) g)

(pretax). The Company believes the 1993 effect of 19

i (b) EQUITY DISTRIBUTION RESTRICTIONS (d) LONG-TERM DEBT AND OTHER I

BORROWING ARRANGEMENTS l

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

million. Substantially all of the retamed earnings foDows'-

were available for the declaration of dividends on i

ac,,f,,ay,7,ge the Company's preferred and common shares.

Iraern, Rare,r

~)

All of the Company's common shares are held by December 3L D"'" 6" 3 '

Y'"""*"

1992 7992 1993 Centerior Energy. A write-off of the Company's investment in Perry Unit 2, depending upon the (millim of magnitude and timing of such a write-off, could first mortgage bonds:

d U"5) j reduce retained earnings sufficiently to impair the 1996.

9.375 %

5 - 5 100 Company's ability to declare dividends.

$.E l

2003 2007.

7.90 181 66 i

Any financing by the Company of any of its non-2008 2012,

2.90 31 52 utility affiliates requires PUCO authorization un-2018-2022.

s.00 los ns 2023.

- 6.83 107 107

'l less the financing is made in connection with transactions in the ordinary course of the Com-Term bank loans due pany's pubhc utilities business operations in which 1994 3997.

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) PRETERRED AND PREFERENCE STOCK Debenture, due 2002.

s.70 135 l

Debentures due 1997...

125

. Amounts to be paid for preferred stock which must Pottution contral notes due be redeemed during the five years 1993-1997 are 1994-2015.

12.02 105 136 Other - net..

(2) ti) -

$12 million in each year.

Total Long-Term Debt.

51,178 51.158 i

The annual preferred stock mandatory redemption provisions are as follows:

Long-term debt matures during the next five years Sharn 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-l Redeemed in Share lion in 1997.

h 5100 par 59.375 16,650 1985 5100 25 par 2.61

. 400,000 1993 25 The Company issued $182 million aggregate princi-pal amount of secured medium-term notes during The annualized preferred dividend requirement as 1991 and 1992. The notes are secured by first i

of December 31,1992 was $24 million.

mortgage bonds. At December 31,1992, the Com-j pany had $93 million aggregate principal amount of The preferred 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 tively, m 1992' lien on substantially all property owned and i

Under its articles of incorporation, the Company franchises held by the Company. Excluded from cannot issue preferred stock unless certain earnings the lien, among other things, are cash, securities, coverage requirements are met. Based on earnings accounts receivable, fuel, supplies and automotive

+

for the 12 months ended December 31,1992, the.

egmpment.

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

[

the future will depend on earnings for any 12 bondable property additions, cash or substitution consecutive months of the 15 months preceding for refundable first mortgage bonds. The issuance I

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

i debt outstanding and the dividends on all preferred

- property additions is limited by two provisions of f

stock issues outstanding-

- our mortgage. One relates to the amount of

(

Preference stock authorized for the the Company is bondable property available and the other to cam-l 5,000,000 shares with a $25 par value. No prefer _

ings coverage of interest on the bonds. Under the j

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

restrictions on the Company's ability to issue earnings coverage test), the Company would have 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 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 December l

20 t

J l

1 31,1992. If Perry Unit 2 had been canceled and Canying rair 3

written off as of December 31,1992, the amount of V"'

bonds which could have been issued by the Com-("dh""5ofdoH'5) f pany would not have changed.

Nuclear Plant Decommissioning Trusts 5 20 5 21 Preferred Stock, with Mandatory l

Redemption Provisions (includmg I

Certain unsecured loan agreements of the Com-cunent Portion)......

62 66 i

pany ccmtain covenants relating to capitalization 1

Q ebt (including current D

ratios, earnings coverage ratms 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' 1

with the sale and leaseback of Beaver Valley Unit 2 of the Company's preferred stock with mandatory contains several fmancial covenants affecting the redemption previsions and long-term debt is es-

-l Company, Cleveland Electric and Centerior En-timated based on the quoted market prices for the j

ergy. Among these are covenants relating to earn-respective or similar issues or on the basis of the i

ings coverage ratios and capitalization ratios. The discounted value of future cash flows. The dis-

-l Company, Cleveland Electric and Centerior En-counted value used current dividend or interest i

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.

j 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 fmancial

.j barring unforseen circumstances.

mstrumems approximate their carrying amounts m, the Balance Sheet at December 31,1992 because of their short-term nature.

(11) SHORT-TERM BORROWING ARRANGESfENTS (13) QUARTERLY RESULTS OF OPERATIONS i

The Compar - id $70 million of bank lines of (UNAUDITED)

]

credit arrango. mts at December 31,1992. There l'

were no borrowings under these bank credit ar-

.l'he following is a tabulation of the unaudited rangements at December 31,1992.

qu rterly results of operations for the two years 4

ended December 31,1992.

Short-term borrowing capacity authrized by the PUCO annually is $150 million for the Company.

M"" 3 I""' 3" 5'' 3" U" 3 3' The Company and Cleveland Electric are autho-("Rh*"s of donan)

.j 37 rized by the PUCO to borrow from each other on a Operating Revenues.

5207 5202 5225 5210 short-term basis.

Operating Inmme.

38 29 52 31 Net income.....

11 4

36 20-o)

Most borrowing arrangements under the short-A i 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 1991 j

of credit. For those banks without fee require.

Operating Revenues.

5213 5228 5238 5208 ments, the average daily cash balance in the M',$8 '"' *i 3

n 2

f Company's bank accounts satisfied informal com-Earnings Available for pensating balances.

Common Stoct 6

8 8

2:

}

Earnings for the quarter ended September 30,1992 :

TI At December 31,1992, the Company had $40 mil-were increased by $15 million as a result of the 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 j,

- borrow up to $40 million until the agreement is totaling $22 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-

'i mercial paper outstanding. If commercial paper Earnings for the quarter ended December 31,1991 -

l were outstanding, it would be backed by at least were increased by $7 million as a result of a year-l an equal amount of unesed bank lines of credit.

end adjustment of $9 million to reduce deprecia -

-l tion expense for the year for the change in the l

nuclear plant straight-line depreciation rate to 2.5%

' (12) TINANCIAL INSTRUAfENTS FAIR VALUE (see Summary of Significant. Accounting Policies),.

l which was partially offset by another adjustment -

The estimated fair values at December 31,1992 of of $1 million to reduce phase-in carrying charges

.j financial instruments that do not ap, toximate '

for an adjustment to 1991 cost deferrals (see their carrying amounts are as follows:_

Note 6).

-l l

D l

l

Financial and Statistical Review l

?

Operating Revenues (millions of dollars) i, Steam Total Total Total Heatmg Operatmg Year Residential Commernal Industnal Other Retail Wholesale Electnc

& Gas Revenues i

1992...

5215 1 75 236 61 687 158 845 5845 i

1991.

230 184 236 40 740 147 887 887 1990.

224 7'S 236 78 713 150 863 863

1989, 216 1r-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 r

Fuel &

Operaten Depreciation Taxes.

Operatmg Federal Total Purchased Other Than Expenses.

Inmme Operstmg Year Power Maintenance Amortnaten ITT Net Tames Empenses 1992.

5169 342 77 91 (17) 33 5695 1991.

178 356 72(a) 89 1

32 728 1990.

174 3 73 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 incomc &

Deferred lases-Before Operatmg ATUDC-Deductions, Carrymg Credit interest i

iear inmme Equity Net Charges (Expense)

Charges l

1992.

5150 1

1 41 (1)

$192 l

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 1982.

109 49 1

19 178 income (loss) (millions of dollars) l Income (Loss)

Before Earrungs i

Cumulatwe Cumulative (Ims)

E'fect of an Effect of an Net Preferred Available l

Debt AIUDC-Accountmg Accountmg Income stock for Common.

Tear interest Debt Change Change (Ims)

Dividerids Stock i

1992.

5122 (1) 71 71 24 5 47 1991.

132 (1) 50 50 25 25 1990..

135 (3) 61 81 25 56 1989..

145 (5) 92 92 25 67 l

1988.

150 (2)

(121) 6(c)

(115) 27 (142)

.l 1982..

95 (22) 105 105 26 79 (a) In 1991, a change in accountin;; for nuclear plant depreciation was adopted, changing from the units-of-production method to the straight-line method et a 2h rate.

r (b) Includes write-off of nuclear w4 in the amount of 5277 million in 1988.

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

f I

l 1

22 i

i...

=.

I t

THE TOLEDO EDISON COMPANY -

l Electric Sales (millions of KWH)

Electric Customers (year end)

Residential Usage Average Average l

Average Pnce Revenue Industnal Kh% Per Per Per Year Residential Commernal Industnal Wholesale Other Total Residential Commernal & Other Total Custome.

K%H Customer 1992.

1 941 1 619 3 563 2 753 478 10 354 255 299 25 870 4 372 285 541 7 632 la 08c 5845.99 1991.

2 041 1 683 3 543 2 587 482 10 336 254 500 26 044 4 444 284 988 7 990

".26 897.41 1990.

I950 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 3 780 2 044 474 9 945 251 540 25 526 4 102 281 218 8 264 9.72 802.87 i

f 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 Operawe ab Peak Capanty load Company Generated

- Purchawd Fuel Cost TU7er tear of Peak Lead Marpn factor Faml 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 f

1991 1 758 1510 14.1 64.5 4 848 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 i

1989..

1894 1 526 19.4 65.2 5 206 5 552 10 758 788 11 546 1.42 10 293 l

1988..

1057(d) 1 614 (52.7) 62.8 5 820 3 325 9 145 1 491 10 636 1.59 10 174 i

1982,

1 790 1355 24.3 61.8 5 306 1 569 6 875 1 044 7 919 1.80 10 221 investment (millions of dollars)

Construction Work In Total i

Utility Accumulated Profess Nuclear Property.

Utility

?

Plant in Depreaation &

Net

& rerry Tueland Plant and Plant Total Year service Amort +t ation f%nt Unit 2 Other Equipment Additions Assets

)

i 1992.

52 847 760 2 087 280 164

$2 531 5 44

$3 939 l

t 1991..

2 692 709 1 983 308 198 2 489 54 3 926 H

1990..

2 604 640 1 964 349 224 2 537 87 3 913 1989.

2 528 565 1 963 342 237 2 542 73 4 051 1988.

2 439 488 1 951 3 71 263 2 585 132 4 046 i

t 1982.

1 294 285 1 009 856 119(e) 1 984 249_

2 181 I

Capitalization (millions of dollars & %)

i Preferred Stock, Preferred Stock, with Mandatory without Mandatory j

4 Year Common Stock Equity Redemption Provisions Redemption Provisions Long-Term Debt lotal 1992.

5935 39%

50 2%

210 9%

1 178 50%

$2 373.

I

. 1991...

888 38 64 3

210-9 1 158 50 2 320 l

1990....

881 39 66 3

210 9

1 097-49 2 254 i

1989..

898 38 69 3

210 9

1 197 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 umt outage for renovation and improvements.

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

i 23 m,.

I

i investor information SilARE OWNER INFORMATION SHARE OWNER SERvlCES DIYlDEND REINVESTMENT A ND STOCK PURCHASE Communicanons regard;ng stock transfer requirements, PLAN AND INDIVIDUAL RETIREMENT ACCOUNT lost certificates, dividends and changes of address (CXalRA) should be directed to share Owner Services at Centenor Centerior Energy Corporation has a Dividend Energy Corporation. Correspondence should be sent Remvestment and Stock Purchase Plan which provides to the address indicated below for the Stock Transfer Toledo Edison share owners of record and other Agent. To reach Share Owner Se rvices by phone, call:

investors 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

" 9"*"#' I

' " * * * * * * * *

• E '*

Outside Cleveland area 1-800-433-7704 investments. In addition, indis iduals may establish an Please have your account number ready when callmg.

Individual Retirement Account (IRA) which invests in Centerior common stock through the Plan. Information STOCK TRANSFER AGENT relating to the Plan and the CX*1RA may be obtained l

Centeriot Energy Corporation from Share Owner Services.

Shae Owner Services PO. Box 94661 INDEPENDENTACCOUNTANTS Cle eland OH 44101-4661 Arthur Andersen & Co.

1717 East Ninth Street Ste :k transfers may be presented at Cleveland OH 44114 PN : Trust Company of New York 40 Jroad Street, Fifth Floor EN\\TRONMENTAL REPORT l

l New York NY 10004 The Company will furnish to share owners, without STOCK REGISTRAR charge, a copy of a report on its environmental Society National Bank performance. Requests should be directed to Share Owner Services.

Corporate Trust Division PO. Box 6477 FORM 10-K Cleveland OH 44101 The Company will furnish to share owners, without INVESTOR RELATIONS charge. a copy of its most recent annual report to the Inquiries from security analysts and insututional Securities and Exchange Commission. Requests should investors should be directed to Terrence R. Moran, he directed to Sharc Owner Services.

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

EXCHANGE LISTINGS Prrferred-525 par value-8 84%,52.365 and $2.81 series, Adjustable Series A and Adjustable Series B-New York Stock Exchange Prrfenrd-$100 par value-4%%,8.32%,7.76% and 10% series-American Stock Exchange BOND AND DEBENTURE INFORMATION BOND TRUSTEE AND PAYING AGENT DEBENTURE TRUSTEE AND PAYING AGENT The Chase Manhattan Bank, N.A.

Fifth Third Bank Corporate Trust Administration Division CorporateTrust Administration 4 Chase Metrotech Center,3rd Floor 38 Fountain Square Plaza Brooklyn NY 11245 Cincinnati OH 45263 (718) 242-7290 (513)579-5132 24

i

~;

?

The Toledo Edison Company i

BUL.K RATE l

300 Madison Avenue US POSTAGE j

Toledo OH 43652-0001 PA1D ctn UAND.OWO PEEMrfNO.409

'i

..t

'i l

I P

b

i

-i 4

'i h

i I

i

'. f Y

/l i

.i

.I i

l i

t

=

.