ML20112D641
| ML20112D641 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 12/31/1995 |
| From: | TOLEDO EDISON CO. |
| To: | |
| Shared Package | |
| ML20112D597 | List: |
| References | |
| NUDOCS 9606040439 | |
| Download: ML20112D641 (30) | |
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! The Toledo Edison Company l l A subsidiary of Centerior Energy l
l ANNUAL REPORT.
1995 9606040439 960524 PDR ADOCK 05000334 I PDR
T Contents About Tcledo Edison 2 Directors and Officers The Company, a wholly owned subsidiary of Centerior Energy Corporation, !
provides electric service to a 2,500-square mile area of northwestern Ohio.
3 Management,s Financial The Company also provides electric energy at wholesale to 13 municipally Analysis, Financial owned distribution systems and one rural electric cooperative distribution Statements and Notes system in its service area. Although the principal city in its service area is 25 Report ofIndependent Toledo, the Company derives about 54% of its total electric retail revenues from customers outside of the city. The Company's 1,809 employees serve Public Accountants about 290,000 customers.
26 Financial and Statistical Review 28 InvestorInformation Executive Offices The Toledo Edison Company 300 Madison Avenue Toledo, OH 43652-0001 (419)249-5000 General information about the Company and Centerior Energy Corporation is available on the Internet at http: // www.centerior.com O ~~ -~ -,
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Directors 1
Robert J. Fe; ting, Chairman and Chief Executive afficer of the Company l mi Tia: Cleveland Electric illuminating Company and Chairman, President i and Cnief E/ecutive Officer of Centerior Energy Corporation and Centerior l Senice Company.
Muncy R. Edelman. Vice Chairman of the Company, President of The '
Cleveland Electric illuminating Company and Executive Vice President of Centerior Energy Corporation and Centerior Service Company.
Fred J. lenge, Jr., President of the Company, Vice President of The I Cleveland Electric illuminating Company and Senior Vice President of Centerior Energy Corporation and Centerior Service Company.
Officers Chairman and Chief Executive Officer.. . ... .. Robert J. Farling
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Vice Chairman .. .. . . . .. . . . . ..Murray R. Edelman President.. . ... . . .. . . . Fred J. Lange, Jr:
Vice President & Chief Financial Officer.. ... Terrence G. Linnert Vice President.. . . . . . . . . . Gary R. Leidich Regional Vice President-West... . . . .. John E. Pagame l Treasurer. . . .... . .. . .. . .. David M. Blank )
Controller.. .. . .. .. . .. .. .E. Lyle Pepin . !
Secretary .. .. ... . . . . . .. . . ...Janis T Percio l
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l M:nng:m:nt's FinInsirl Analysis preferred stock. In our view, a successful conclusion Outlook would include approval of the full price increase requested with a regulatory commitment to maintain the established Strategic Plan . . .
price levels over an appropriate trans.i tion penod. This We continued to make progress during the second year of should be coupled with a means to accelerate recognition our eight-year strategic plan, but we remain keenly aware of regulatory assets (described in Note 7(a)) and nuclear of the magnitude of the problems that face us. The generating assets concurrent with our cost control and strategic plan was created by Centerior Energy Corpora- revenue enhancement efTorts in order to earn a fair return tion (Centerior Energy), along with The Toledo Edison f r Centerior Energy common stock share owners over Company (Company) and The Cleveland Electric illu- time.
minating Company (Cleveland Electric), to achieve two Another key part of our strategy is offering long term major goals: strengthening their financial conditions and contracts to those large customers who could have incen-improving their competitive positions. The Company and tives to change power suppliers. In 1995, 74% of our Cleveland Electric are the two wholly owned electric industrial kilowatt-hour sales and 13% of our commercial utility subsidiaries of Centerior Energy. The plan's objec- kilowatt-hour sales were under long-term contracts. We tives relate to the combined operations of all three com- are renegotiating contracts before they expire and in most panies. The objectives are to achieve profitable revenue cases are retaining customers under new long-term growth, become a leader in customer satisfaction, build a contracts.
winning employee team, attain increasingly competitive power supply costs and maximize share owner return on We are e ntinuing efforts to reduce fixed financing costs Centerior Energy common stock. We are not yet posi- in order to strengthen our fmancial condition. During tioned to compete in a less regulated electric utility 1995, utilizing strong cash flow and refinancing at I industry, but every major action being taken - strategic f v rable terms, the Cornpany reduced interest expense planning, revenue enhancement, cost reduction, improve- and preferred dividends by $7 million and outstanding ment of work practices and application for increased debt,and preferred stock by $113 million.
prices - is part of a comprehensive efTort to succeed in Our overall costs are high relative to many of our neigh-an increasingly competitive environment. boring utilities as a result of our substantial nuclear investment. The strategic plan calls for making us more A primary objective of the strategic plan is continued and competitive by continuing to reduce operating expenses sigmficant revenue growth even as our markets become and capital expenditures. In 1995, to improve the focus on more competitive. The Company's retail revenues cost reduction and other strategic plan objectives, Center-adjusted for weather and fuel costs have grown about 1%
ior Energy and its subsidiaries restructured into six busi-annually since 1990, During 1995, we took aggressive ness groups. The new organization includes groups to steps to increase revenues through enhanced marketmg manage the generation, distribution and transmission strategies. Also, our economic development etTorts proved businesses; provide services and administrative functions; successful in attracting major new customers and support-and invest in nonregulated enterprises. This arrangement ing the expansion of existing ones. Although we are not will also enhance each group's ability to identify cost satisfied with our growth rate, we expect that our market-reductions by focusing on margins and improving work ing activity will improve revenue growth.
practices and customer service. We will also continue to The rate case which the Company and Cleveland Electric aggressively pursue initiatives to reduce the heavy tax
.' filed with The Public Utilities Commission of Ohio burden imposed upon us by the state and local tax
- (PUCO) in April 1995 is a critical factor to the success of structure in Ohio.
the strategic plan. We do not see this rate case as a
. Rate Case and Regulatory Accounting continuat. ion of business as usual but as an important turning point which should, if we are successful in accom- In April 1995, the Company and Cleveland Electric filed plishing the objectives discussed below, bring an end to requests with the PUCO for price increases aggregating price increases for the foreseeable future. A successful $119 million annually to be efTective in 1996. The price conclusion of the case would speed our transition to a increases are necessary to recover cost increases and more competitive company by providing additional cash amortization of certain costs deferred since 1992 pursuant
- to lower costs by accelerating the pay-down of debt and to the Rate Stabilization Program discussed below and in three
i Note 7. If their requests are approved, the Company and pleted in November 1995 and aggregated $56 million for j Cleveland Electric intend to freeze prices until at least the Company in 1995. Recovery is expected to begin with
- 2002 with the expectation that increased sales and cost the etTective date of the PUCO's order in the pending rate control measures will obviate the need for further price case. Annual amortization of the deferred costs for the increases, if circumstances make it impossible to earn a Company is $10 million which began in December 1995.
fair return for Centerior Energy common stock share Consequently, earnings in 1996 will be sharply lower than owners over time, the Company and Cleveland Electric in 1995. Also contributing to lower earnings are the would ask for a further increase- but only after taking expectations that the requested price increase will not be all appropriate actions to make such a request efTective until the second quarter of 1996 and results from unnecessary, increased marketing and cost reduction efforts will take in December 1995, the PUCO ordered an investigation into the financial conditions, rates and practices of the Competition Company and Cleveland Electric.
Major structural changes are taking place in the electric In its report on the rate request, the PUCO Staff recom- .
utility mdustry which are expected to place downward mended approval of the $119 m.llion i requested ($35 .
pressure on prices and to increase competition for cus-milh.on for the Company and $84 m.lh.on i for Cleveland tomers' business. The changes are coming from both Electric), subject to a commitment by the Company and .
federal and state authorities. Many of the changes began Cleveland Electric to significantly revalue their assets. In when the Energy Poh.ey Act of 1992 permitted compet.t-late January 1996, the StafT proposed that the Company . . .
- t. ion m the electnc utility mdustry through broader access and Cleveland Electric significantly revalue the.ir nuclear . .
to a utility's transmission system. In March 1995, the plant and regulatory assets with.m a five-year period. The .
. . . Federal Energy Regulatory Comm. .ission (FERC) issued Stafi's asset revaluat. ion proposal is 'nconsistent with the .
. proposed rules relatmg to open access transmission ser-Ohio statutes that defme the rate-mak.ing process. The . .
vices by pubh.c utilities, recovery of stranded investment PUCO is not bound by the Stafi's recommendations. A
. and other related matters. The open access transmission decision by the PUCO is anticipated in the second quarter .
rules require utilities to deliver power from other utilities of 1996' or generation sources to their wholesale customers. In The outcome of the rate case could affect the Company's May 1995, the Company and Cleveland Electric filed l ability to meet the criteria of Statement of Financial open access transmission tariffs with the FERC which l Accounting Standards (SFAS) 71 for all or part of its used the proposed rules as a guideline. These tariffs are operations which could result in the write-off of all or a currently pending. I part of the regulatory assets shown in Note 7(a). In our Several groups m. Ohio are study.mg the possible applica-changing industry, other events m. dependent of the out- .
. . tion of retail whech.ng. Retail wheeling occurs when a come of the rate case could also result m wnte-ofTs or
. customer obta.ms power from a utility company other than wnte-downs of assets. .
its local utility. The PUCO is sponsoring informal discus-See Note 7 for a full discussion and analysis of the rate sions among a group of business, utility and consumer case, SFAS 71 and othu financial accounting require- interests to explore ways of promoting competitive options ments and the potential implications of these accounting without unduly harming the interests of utility company requirements for the Company's results of operations and share owners or customers. Legislative proposals are financial position. being drafted for submission to the Ohio House of Repre- ,
sentatives and several utilities in the state have offered Rate Stabilization Program their own proposed transition plans for introduction of ;
retail w heeling. The current retail wheeling efTorts in Ohio Under a Rate Stabilization Program approved by the i are exploratory and we cannot predict when and to what ,
PUCO in 1992, we agreed to freeze base rates until 1996 cxtent retail wheeling will be implemented in Ohio.
and limit rate increases through 1998. In exchange, we were permitted to defer through 1995 and subsequently The term " stranded investment" generally refers to fixed recover certain costs not currently recovered in rates and costs approved for recovery under traditional regulatory to accelerate amortization of certain benefits. Deferral of methods that would become unrecoverable, or those costs and amortization of those benefits were com- " stranded", as a result of wider competition. Although four
competitive pressures are increasing, the traditional regu- ity factor for Davis-Besse was 1001 The plant continues latory framework remains in place and is expected to to have its best run ever operating at or near full capacity continue for the foreseeable future. We cannot predict for 463 straight days through February 21,1996.
when and to what extent competition will be allowed. We believe that pure competition (unrestricted retail wheel- In 1995, Perry Unit 1 improved its average three-year unit ing for all customer classifications) is at least several availability factor to 62% with a 1995 availability factor of years away and that any transition to pure competition 935 Perry Unit 1 operated at or near capacity for 506 of will be in phases. The FERC and the PUCO have 531 days since the end of its last refueling and mainte-acknowledged the need to provide at least partial recovery nance outage in August 1994. Work on the comprehen-of stranded investment as greater competition is permit- sive course of action plan developed in 1993 for Cleveland ted and, therefore, we believe that there will be a mecha- Electric to improve the operating performance of Perry nism developed for the recovery of stranded investment. Unit I will be completed during the current refueling Ilowever, due to the uncertainty involved, there is a risk outage which began January 27,1996, that some of our assets may not be fully recovered.
A significant part of the strategic plan involves ongoing In 1995, we cont,nued i to experience significant compet,- i efforts to increase the availability and lower the cost of tion from municipal electric systems. Also, in Toledo, the production of our nuclear units. In 1995, we made great City Council responded to a petition drive by appropriat-progress regarding unit availability while continuing to ing funds to complete a consultant's study on whether t to costo h N ol' a mim ipve create a municipal electric utility. This study is expected ment program is for Cleveland Electric to replicate Davis-to be completed by mid-1996. ,
g,33, s operational excellence and cost reduction gains at In October 1995, Chase Brass & Copper Co. Inc., which Perry Unit I while improving performance ratings.
has provided annual net income of $2 million, terminated its service from the Company and began to receive its We externally fund the estimated costs for the future electric service from a consortium of other providers. We decommissioning of our nuclear units. In 1993 and 1994, have filed lawsuits contending that this arrangement vio. we increased our decommissioning expense accruals l
lates the legal limits of sales and delivery of power by because of revisions in our cost estimates. See Note 1(e). )
municipal electric systems outside their boundaries. We )
will continue to pursue all legal and regulatory remedies Our nuclear units may be impacted by activities or events j to this situation. beyond our control. Operating nuclear units have exper- l ienced unplanned outages or extensions of sch duled In 1995, our economic development efforts proved suc- outages because of equipment problems or new regulatory cessful m attracting major new customers, such as North requirements. A major accident at a nuclear facility Star BHP Steel, Worthington Steel and Aluminum Com- anywhere in the world could cause the Nuclear Regula- I pany of America, while support i ng the expansion of tory Commission (NRC) to limit or prohibit the opera-existing ones. We expect that our continued emphasis on tion or licensing of any domestic nuclear unit. If one of economic development along with a newly developed our nuclear units is taken out of service for an extended raarket segment focus will be major ingredients in provid- period for any reason, including an accident at such unit ing improved revenue growth. or any other nuclear facility, we cannot predict whether regulatory authorities would impose unfavorable rate Nuclear Operations treatment. Such treatment could . include taking our The Company has interests in three nuclear generating afTected unit out of rate base, thereby not permitting us to units - Davis-Besse Nuclear Power Station (Davis- recover our investment in and earn a return on it, or Besse), Perry Nuclear Power Plant Unit 1 (Perry Unit 1) disallowing certain construction or maintenance costs. An and Beaver Valley Power Station Unit 2 (Beaver Valley extended outage coupled with unfavorable rate treatment Unit 2) - and operates the first one. Cleveland Electric could have a material adverse effect on our financial operates Perry Unit 1. Davis-Besse and Beaver Valley condition and results of operations. Premature plant clos-Unit 2 both operated extremely wc!! in 1995. Their ings could also have a material adverse efTect on our average three-year unit availability factors at year-end financial condition and results of operations because the 1995 of 90% and 87%, respectively, exceeded the industry estimated cost to decommission the plant exceeds the average of 81% for similar reactors. in 1995, the availabil- current funding in the decommissioning trust.
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Hacrdous W:st3 Dispostl Sit:s C5pitil Resourcn cnd Liquidity The Company is aware of its potential involvement in the 19931995 Cash Requirements cleanup of several sites. Although these sites are not on . . .
A key part of the strategic plan is to s.igmficantly reduce the Superfund National Pn.onties List, they are generally bem. g the Company's level of debt and preferred stock. In 1995, adm.mts. tered by various governmental entities m
.. we were able to continue the reduct. ion pattern begun m.
the same manner as they would be administered if they 1994. The Company's obligations were reduced by $66 were on such h.st. Allegations that the Company d.isposed , . .
milh.on m 1994 and by $113 milh.on in 1995. We intend to of hazardous waste at these s.tes, i and the amount involved, are often unsubstantiated and subject to dispute.
Federal law provides that all "potentially responsible We need cash for normal corporate operations, retirement parties" (PRPs) for a particular site be held liable on a
. of maturing securities, and an ongoing program of con-joint and several basis, if the Company were held liable structing and improving facilities to meet demand for for 100% of the cicanup costs of all of the sites referred to electric service and to comply with government regula-above, the cost could be as high as $150 million. How- tions. Our cash construction expenditures totaled $42 ever, we believe that the actual cleanup costs will be million in 1993, $41 million in 1994 and $53 million in substantially lower than $150 million, that the Company's 1995. Our debt and preferred stock maturities and sinking share of any cleanup costs will be substantially less than fund requirements totaled $58 million in both 1993 and 100% and that most of the other PRPs are financially able 1994 and $83 million in 1995. In addition, we optionally to contribute their share. The Company has accrued a redeemed approximately $200 million in the period 1993-liability totaling $5 million at December 31,1995, based 1995. This amount includes $94 million of tax-exempt on estimates of the costs of cleanup and its proportionate issues refunded in 1995 resulting in approximately $4 responsibility for such costs. We believe that the ultimate million of interest savings. The embedded cost of the outcome of these matters will not have a material adverse Company's debt at the end of 1995 was 9.23% versus c!Tect on our financial condition or results of operations-9.48% in 1994 and 9.59% in 1993. In 1995, the Company and Cleveland Electric renewed for a four-year term approximately $225 million in bank letters of credit sup-Common Stock Dividends . ..
porting the equity owner participants .m the Beaver Valley in recent years, the Company has retained all of its Unit 2 lease. See Note ll(d),
earnings available for common stock. The Company has not paid a common stock dividend to Centerior Energy The Company also utilized short-term borrowings to help since February 1991. The Company is currently prohib- meet its cash needs. The Company had $21 million of ited from paying a common stock dividend by a provision n tes payable to affiliates at December 31,1995. See in its mortgage. See Note 11(b). The Company does not Note 12.
expect to pay any common stock dividends prior to its merger into Cleveland Electric, as discussed below. 1996 and Beyond Cash Requirements The Company's 1996 cash requirements for construction Merger of the Company into Cleveland Electric are $74 million and for debt and preferred stock maturi-ties and sinking fund requirements are $58 million. We We continue to seek the necessary regulatory approvals t expect to meet these requirements with internal cash complete the merger of the Company into Cleveland generation, cash reserves and about $40 million from the Electric which was announced in 1994. The FERC has sale of a AAA-rated security backed by our accounts deferred action on the merger application until the merits receivable.
of the open access transmissic,n taritTs proposed by the Company and Cleveland Electric are addressed in hear- We expect to meet all of our 1997-2000 cash require-ings. See Note 15. ments with internal cash generation. Estimated cash requirements for the Company's construction program during this period total $262 million. Debt and preferred stock maturities and sinking fund requirements total $233 million for the same period. If economical, additional securities may be redeemed under optional redemption l six l
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provisions, with funding expected to be provided through R:sults cf Oper;tions internal cash generation. 1995 vs.1994 Factors contributing to the 1% increase in 1995 operating Liquidity revenues are as follows:
Additional first mortgage bonds may be issued by the increase (Decrease) in Operating Revenues o I rs Company under its mortgage on the basis of property Kwli sales volume and Mix $ 29 additions, cash or refundable first mortgage bonds. If the Wholesale Revenues (9)
Reco e enues applicable interest coverage test is met, the Company
{uc may issue first mortgage bonds on the basis of property Toud s9
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additions and, under certain circumstances, refundable bonds. At December 31,1995, the Company would have For the second year in a row, total kilowatt-hour sales been permitted to issue approximately $288 million of increased. Total sales increased 2.2% in 1995 primarily additional first mortgage bonds. because of the hot summer weather. Residential and commercial sales increased 5.2% and 2.2%, respectively, The Company also is able to raise funds through the sale which included about 1% nonweather-related growth in of debt and preferred and preference stock. Under its residential sales. Industrial sales increased 1.8% on the articles of incorporation, the Company cannot issue pre-strength of increased sales to large glass manufacturers ferred stock unless certain earnings coverage require-and the broad-based, smaller industrial customer group.
ments are met. At December 31, 1995 the Company Other sales increased 0.5%. Weather accounted for would have been permitted to issue approximately $158 approximately $13 milh.on of the $21 m.llion i increase in million of additional preferred stock at an assumed divi-1995 base rate (nonfuel) revenues. Wholesale revenues dend rate of 10.5%. There are no restrictions on the decreased because of the lower revenues associated with Company's ability to issue preference stock.
the Beaver Valley Unit 2 capacity sale to Cleveland i The Company and Cleveland Electric have $307 million Electric. See Note 2. Lower 1995 fuel costs recovery l in financing vehicles available to support their nuclear revenues resulted from favorable changes in the fuel cost I fuel leases, portions of which mature this year. See Note factors. The weighted average of these fuel cost factors
- 6. The Company is a party to a $125 million revolving decreased approximately 6%.
credit facility which is expected to be renewed when it For 1995, operating revenues were 27% residential,21%
matures in May 1996. See Note 12. At the end of 1995, commercial,29% industrial and 23% other and kilowatt-the Company had $94 million in cash and temporary hour sales were 19% residential,16% commercial, 37%
investments.
industrial and 28% other. The average prices per kilowatt-The foregoing financing resources are expected to be hour for residential, commercial and industrial customers sufficient for the Company's needs over the next several were $.11, $.11 and $.06, respectively, years.110 wever, the availability and cost of capital t Operating expenses increased 0.1% in 1995. Federal meet the Company's external financing needs also depend income taxes increased as a result of higher pretax operat-upon such factors as financial market conditions and its ing income. Fuel and purchased power expenses credit ratings. Current credit ratings for the Company are decreased because of lower purchased power require-as follows: ments resulting from the increased availability of the standard Moody's
'" " nuclear generating units in 1995.
CIrNahon se Ee* I c.
First mortgage bond.$ BB Ba2 Interest charges and preferred dividends decreased in subordinated debt B+ BI 1995 because of the redemption of securities and refi-Preferred stock B b2 nancing at favorable terms.
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(- 1994 vs.1993'. were $.11, $.11 and $.06, respectively. The changes from 1993 were not significant.
~ Factors contributm.g to the 0.7% decrease in 1994 operat-
. ing revenues are as follows:
Operating expenses were 12% lower in 1994. Operation - ,
Millions and maintenance expenses for 1993 included $88 million Increase iDecrease) in Oncratina Revenues of Dollars ,
of net benefit expenses related to an early retirement KWH Sales Volume and Mix $8 ..
Wholesale Revenues (5) Program, called the Voluntary Transition Program Fuel Cost Recovery Revenues _ _E) (VTP), and other charges totaling $19 million. The VTP . j Total E1) ' benefit expenses in 1993 consisted of $75 million of costs The Company experienced good retail kilowatt-hour sales f r the Company plus $13 million for the Company's pro
. growth in the industrial and commercial categories in rata share of the costs for its affiliate, Centerior Service
--1994; the sales growth for the residential category was Company (Service Company). A smaller work force and lessened by weather. conditions, particularly during the ng ing c st reduction measures also lowered operation ,
summer. The revenue decrease resulted from milder and maintenance expenses. Lower purchased power costs -
l weather conditions in 1994 and both lower wholesale and helped reduce fuel and purchased power expenses in 1994 i fuel cost recovery revenues. Weather reduced base rate despite an increase in the amount of power purchased.
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revenues approximately $7 million from the 1993 amount. More nuclear generation and less coal-fired generation-l Total sales increased 7.8% Industrial sales increased 8.6% also accounted for a part of the lower fuel and purchased on the stregth of increased sales to large automotive p wer expenses. Depreciation and amortization expenses :)
- manufacturers and the broad-based, smaller industrial increased primarily because of higher nuclear plant customer group. This growth substantiated an economic decommissioning expenses as discussed in Note 1(e).
resurgence in Northwestern Ohio. Residential and com- Deferred operating expenses were greater primarily.
- mercial sales increased 0.8% and 2.3%, respectively, because of the write-off of $55 million ' of phase-in L
Other sales increased 16%' because of increased sales to . deferred operating expenses in 1993 as discussed in j wholesale customers, although the softer wholesale mar. Note 7(e). The 1993 deferrals also included $32 million ket conditions in 1994 resulted in lower wholesale reve- f p stretirement benefit' curtailment cost - deferrals 1 nues. Lower 1994 fuel cost recovery revenues resulted related to the VTP. See Note 9(b). Federal income taxes from favorable changes in the' fuel cost factors. The increased as a result of higher pretax operating income, weighted average of these fuel cost factors dropped by 6%.
As discussed in Note 4(b), $232 million of our Perry l For 1994, operating revenues were 26% residential,21% Unit .2 investment was written off in 1993. Also, as
. commercial,29% industrial and 24% other and kilowatt- discussed in Note 7(e), phase-in deferred carrying .;
hour sales were 19% residential,16% commercial,37%' charges of $186 million were written off in'1993. The
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industrial and 28% other. The average prices per kilowatt- change in the federal income tax ' credit amounts for _
hour for residential, commercial and industrial customers nonoperating income was attributable to these write-offs. '
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Inmm3 St:t:m:nt ne roteso esison compaar For the years ended December 31.
l 1991 1994 1993 l (millions of dollars)
Operating Retenues (1) $374 1861 $ 871 Operating Expenses l Fuel and purchased power 157 167 173 Other operation and maintenance 225 229 245 Ger.cration facilities rental expense, net IN 104 104 Early retirement program expenses and other - -
107 Total operation and maintenance 486 500 629 Depreciation and amortization 84 83 76 Taxes, other than federal income taxes 91 90 91 Deferred operating expenses, net (17) (21) (4) i Federal income taxes (credit) __42 _ 31 __il0)
E E 782 l Operating Income _183 _,13Q 89 Ninoperating Income (Loss)
Allowance for equity funds used during construction 1 1 1 Other income and deductions, net 6 3 i Write-off of Perry Unit 2 - -
(232) l Deferred carrying charges, net 14 15 (161)
Federal income taxes - credit (expense) _{2) __(2) 129 19 17 (263)
Income (1 oss) Before Interest Charges _.2Q7 197 (174) literest Charges Debt interest 111 116 116 Allowance for borrowed funds used during construction _Ll) (1) (1)
_11Q _111 115 Net Income (Loss) 97 82 (289)
Preferred Dividend Requirements _ 13 _2Q 23 Eernings (less)'Atallable for Common Stock M M E)
(1) Includes revenuesfrom all bulk power sales to Cleveland Electric of $102 million, $11I million and $120 million in i995,1994 and 1993, respectively, Retained Earnings For the vears ended December 31.
1995 1994 1993 (millions of dollars)
Retained Earnings (Deficit) at Beginning of Year $(113) $(175) $ 137 Additions Net income (loss) 97 82 (289)
Deductions Preferred stock dividends declared and other (19) __120) (23)
Net increase (Decrease) 78 62 (312)
Ritained Earnings (Deficit) at End of Year $ (35) $(113) $(175)
The accompanying notes are an integral part of these statements.
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. ASSETS
' Property, Plant and Equipment ,
Utility plant in service $2,896 $2,899 j Less: accumulated depreciation and amortization 942 892 :
1,954 2,007 1 Construction work in ' progress 28 30 1,982 2,037 Nuclear fuel, net of amortization 78 119 j
' Other property, less accumulated depreciation JQ 6 2.080 2.162 i
Current Assets l- Cash and temporary cash investments 94 ' 88 l Amounts due frcm customers and others, net 68 62
' ' Amounts due from afliliates 19 19 Unbilled revenues 22 22
, Materials and supplies, at average cost 40 45 Fossil fuel inventory, at average cost .9 12
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. Taxes applicable to succeeding years 71 72 ;
Other 4 2.
322 322 l
Regulatory and Other Assets Amounts due frcm customers for future federal income taxes, net 416 405 Unamortized loss from Beaver Valley Unit 2 sale 96 101 Unamortized loss on reacquired debt 28 28 Carrying charges and operating expenses 410 379 I Nuclear plant decommissioning trusts 52 38 Other 65 67 1.%7 1.018 ,
Total Assets M M The accompanying notes are an integral part of this statement.
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The Toledo Edison Company
. December 31.
1995 1994 (millions of dollars)
CAPITALIZATION AND LIABILITIES Ccpitalization Common shares, $5 par value: 60 million authorized; 39.1 million outstanding in 1995 and 1994 $ 196 $ 196 Premium on capital stock 481 481 Other paid-in capital 121 121 Retained earnings (deficit) (35) . (113)
Common stock equity 763 685 l
. Preferred stock l With mandatory redemption provisions 5 7 l Without mandatory redemption provisions 210 210' l Long-term debt 1.068 1.154 2.046 2.056 Current Liabilities Current portion oflong-term debt and preferred stock 58 83 Current portion of nuclear fuellease obligations 40 36 Accounts payable 56 48 Accounts and notes payable to affiliates 53 31 Accrued taxes 78 75 l Accrued interest 24 27 Other 20 16 i 329 316 l l
- l. Deferred Credits and Other Liabilities
! Unamortized investment tax credits 79 87 1 Accumulated deferred federal income taxes $73 541' I Unamortized gain from Bruce Mansfield Plant sale 188 198 Accumulated deferred rents for 8 uce Mansfield Plant and Beaver Valley Unit 2 54 54 Nuclear fuel lease obligations 52 87
- Retirement benefits 103 103 l
Other 50 60 1.099 1.130 ,
Total Capitalization and Liabilities 12d2l1 M I
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C:sh Fli.ws rse roicsa esuon company For the years ended December 31.
1995 1994 1993 (millions of dollars)
Cash Flows from Operating Activities (1)
Net Income (Loss) $ 97 $ 82 $(289)
Adjustments to Reconcile Net income (Loss) to Cash from Operating Activities:
Depreciation and amortization S4 83 76 Deferred federal income taxes 16 46 (160)
Unbilled revenues -
3 (4)
Deferred fuel (3) 3 -
Deferred carrying charges, net (14) (15) 161 Leased nuclear fuel amortization 54 44 38 Deferred operating expenses, net (17) (21) (4)
Allowance for equity funds used during construction (1) (1) (1)
Noncash early retirement program expenses, net - --
83 Write-off of Perry Unit 2 - -
232 Changes in amounts due from customers and others, net (6) 1 (3)
Changes in inventories 8' (2) 10 Changes in accounts payable 8 (15) 16 Changes in working capital affecting operations 4 (16) 21 Other noncash items 9 10 14 Total Adjustments 142 120 479 Net Cash from Operating Activities . 239 202 190 Cash Flows from Financing Activities (2)
Bank loans, commercial paper and other short-term debt - -
(40)
Notes payable to alliliates 21 - -
First mortgage bond issues 99 31 20 Secured medium-term note issues - -
93 Maturities, redemptions and sinking funds (215) (98) (89)
Nuclear fuel lease obligations (44) (49) (47)
Dividends paid (18) (20) (23)
Premiums, discounts and expenses (6) -
(1)
Net Cash from Financing Activities (163) (136) (87)
Cash Flows from Investing Activities (2)
Cash applied to construction (53) (41) (42)
Interest capitalized as allowance for borrowed funds used during construction (1) (1) (1)
Contributions to nuclear plant de:ommissioning trusts (11) (12) (4)
Other cash received (applied) (5) (6) 10 Net Cash from investing Activities (70) (60) (37)
Net Change in Cash and Temporary Cash Imestments 6 6 66 Cash and Temporary Cash Investments at Beginning of Year 88 82 16 Cash and Temporary Cash Investments at End of Year $ 94 $ 88 $ 82 (1) Interest paid (net of amounts capitali:ed) $ 93 $ 94 $ 92 Income taxes paid $ 23 $ $ $ 7 (2) Increases in Nuclear Fuel and Nuclear Fuel Lease Obligations in the Balance Sheet resulting from the noncash capitalizations under nuclearfuel agreements are excludedfrom this statement.
The accompanying notes are an integralpart of this statement.
rwelve
~ ~ . . . - - - . . .. .-
Stat:m:nt cf Pr:f rred Stock ne ra,ao uison co,,,y y Current 1995 Shares Call Price ' December 31.
Outstandine Per Share 1995 1994 (millions of dollars)
$100 par value, 3,000,000 preferred shares authorized;
$25 par value, 12,000,000 preferred shares authorized Subject to mandatory redemption:
$100 par $9.375 66,850 $101.48 $ 7 $8 25 par 2.81 - - -
_lQ 7 18 Less: Current maturities _.2 _ 11 Total Preferred Stock, with Mandatory Redemption Proilslons W W 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 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 25.00 30 30 Series B Adjustable 1,200,000 25.75 _JQ _1Q Total Preferred Stock, without Mandatory Redemption Provisions gj00 gj,,0 The accompanying notes are an integral part of this statement.
thirteen
N5t:s t3 ths Fin nci;l St:ttm'intS month to record the estimated amount of unbilled reve- I (1) Summ ry cf Significrnt Accounting nues for kilowatt-hours sold in the current month but not Policies billed by the end of that month.
(a) General A fuel factor is added to the base rates for electric service. l De Company is an electric utility and a wholly owned This factor is designed to recover from customers the subsidiary of Centerior Energy. The Company follows the e sts of fuel and most purchased power. It is reviewed and Uniform System of Accounts prescribed by the FERC adjusted semiannually in a PUCO proceeding.
and adopted by the PUCO, Rate-regulated utilities are (d) Fuel Expense subject to SFAS 71 which governs accounting for the effects of certain types of rate regulation. Pursuant to The cost of fossil fuel is charged to fuel expense based on SFAS 71, certain incurred costs are deferred for recovery inventory usage. The cost of nuclear fuel, including an in future rates. See Note 7. interest component, is charged to fuel expense based on l e ra mnsum n. s mated futum nuclear fuel The preparation of financial statements in conformity Posal es am bebg mmemd Grough base raus.
with generally accepted accounting principles requires l
management to make estimates and assumptions that The Company defers the differences between actual fuel afTect the reported amounts of assets, liabilities, revenues costs and estimated fuel costs currently being recovered and expenses, and the disclosure of contingent assets and from customers through the fuel factor. This matches fuel liabilities. The estimates are based on an analysis of the - expenses with fuel-related revenues.
best information available. Actual results could differ Owners of nuclear generating plants are assessed by the from those estimates.
federal government for the cost of decontamination and The Company is a member of the Central Area Power decommissioning of nuclear enrichment facilities oper-Coordination Group (CAPCO). Other members are ated by the United States Department of Energy. The l Cleveland Electric, Duquesne Light Company, Ohio assessments are based upon the amount of enrichment Edison Company and its wholly owned subsidiary, Penn- services used in prior years and cannot be imposed for sylvania Power Company. The members have constructed more than 15 years (to 2007). The Company has accrued and operate generation and transmission facilities for their a liability for its share of the total assessments. These I joint use. costs have been recorded in a deferred charge account since the PUCO is allowing the Company to recover the (b) Related Party Transactions assessments through its fuel cost factors.
Operating revenues, operating expenses and interest charges include those amounts for transactions with aflili- (e) Depreciation and Decommissioning ated companies in the ordinary course of business The cost of property, plant and equipment is depreciated operations. over their estimated useful lives on a straight-line basis.
The Company's transactions with Cleveland Electric are The annual straight-line depreciation provision for non-primarily for firm power, interchange power, transmission nuclear property expressed as a percent of average depre-line rentals and jointly owned power plant operations and ciable utility plant in service was 3.8% in 1995,3.5% in construction. See Notes 2 and 3. 1994 and 3.6% in 1993. The annual straight-line deprecia-tion rate for nuclear property is 2.5%. In conjunction with The Service Company provides management, financial, administrative, engineering, legal and other services at "S P n 8r Cax, mPany ha? aued & N cost to the Company and other afliliated companies. The """"" *"" E" " ' " * *EE" mately 3%'
Service Company bdled the Company $67 million, $59 million and $71 million in 1995,1994 and 1993, respec- The Company accrues the estimated costs of decommis-tively, for such services. sioning its three nuclear generating units. The accrets are required to be funded in an external trust. The PL CO (c) Revenues requires that the expense and payments to the extenal Customers are billed on a monthly cycle basis for their trusts be determined on a levelized basis by dividing the energy consumption based on rate schedules or contracts unrecovered decommissioning costs in current dollars by authorized by the PUCO or on ordinances of individual the remaining years in the licensing period of each unit.
municipalities. An accrual is made at the end of each This methodology requires that the net earnings on the fourteen
trusts be reinvested thcrein with the intent of having net tices are changed, the annual provision for decommission-earnings ofTset inflation. The PUCO requires that the 5; could increase; the estimated cost for decommis-estimated costs of decommissioning and the funding level sioning could be recorded as a liability rather than as be reviewed at least every five years. accumulated depreciation; and trust fund income from In 1994, the Company m.ereased its annual decomm.is- the external decommissioning trusts could be reported as sioning expense accruals to $11 m.lh.on i from the $5 mvestment income rather than as a reduct. ion to decom-million level in 1993. The accruals are reflected in current " " * " 8 W #""*' *"* " " * " "
. on the subject on February 7,1996.
rates. The m.ereased accruals in 1994 were den.ved from
- updated, site-specific studies for each of the units. The (f) Property, Plant and Equipment revised estimates reflect the DECON method of decom- ..
. . . . . Property, plant and equipment are stated at ongmal cost missiomng (prompt decontammation), and the locations .
. less amounts disallowed by the PUCO. Construction costs and cost characten. t.s ics specific to the units, and m. elude .
costs associated with decontamm.ation, dismantlement melude related payroll taxes, retirement benefits, fringe and site restorat, ion. benefits, management and general overheads and allow-ance for funds used dun.ng construct. ion (AFUDC).
The' revised estimates for the units in 1993 and 1992 AFUDC represents the estimated composite debt and dollars and in dollars at the time of license expiration, equity cost of funds used to finance construction. This aesuming a 4% annual inflation rate, are as follows: noncash allowance is credited to income. The AFUDC E atNn Future rak was M b N, RM in W ad WM k Generatina Unit car Amount Amount 1993.
(millions of dollars) Maintenance and repairs for plant and equipment are e UntI charged to expense as incurred. The cost of replacing Beaver Valley Unit 2 2027 __11(2) _L90 plant and equipment is charged to the utility plant Total E E accounts. The cost of property retired plus removal costs, (1) Dollar amounts in 1993 dollars, after deducting any. salvage value, is charged to the (2) Dollar amount in 1992 dollars. accumulated provision for depreciation.
The updated estimates reflect substantial increases from the (g) Deferred Gain and Loss from Sales of Utility prior PUCO-n: cognized aggregate estimates of $115 million Plant .
in 1987 and 1986 dollars. 1 The sale and leaseback transact. ions discussed .m Note 2 The classification, Accumulated Depreciation and Amor- resulted in a net gain for the sale of the Bruce Mansfield tization, in the Balance Sheet at December 31, 1995 Generating Plant (Mansfield Plant) and a net loss for the includes $59 million of decommissioning costs previously sale of Beaver Valley Unit 2. The net gain and net loss expensed and the earnings on the external trust funding. were deferred and are being amortized over the terms of This amount exceeds the Balance Sheet amount of the the leases. See Note 7(a). These amortizations and the external Nuclear Plant Decommissioning Trusts because lease expense amounts are reported in the income State-the reserve began prior to the external trust funding. The ment as Generation Facilities Rental Expense, Net, trust earnings are recorded as an increase to the trust assets and the related component of the decommissioning (h) Interest Charges reserve (included in Accumulated Depreciation and Debt Interest reported in the income Statement does not Amortization), include interest on obligations for nuclear fuel under construction. That interest is capitalized. See Note 6.
The stafTof the Securities and Exchange Commission has questioned certain of the current accounting practices of Losses and gains realized upon the reacquisition or the electric utility industry, including those of the Com- redemption of long-term debt are deferred, consistent pany, regarding the recognition, measurement and classi- with the regulatory rate treatment. See Note 7(a). Such fication of decommissioning costs for nuclear generating losses and gains are either amortized over the remainder stations in the financial statements. In response to these of the original life of the debt issue retired or amortized questions, the Financial Accounting Standards Board over the life of the new debt issue when the proceeds of a (FASB) is reviewing the accounting for removal costs, new issue are used for the debt redemption. The amorti-including decommissioning. If current accounting prac- zations are included in debt interest expense.
Jifteen
(l) Feder;l Income Tax:s gated to make such payments. No such payments have The Company i.ses the liability method of accounting for income taxes in accordance with SFAS 109. See Note 8. Future minimum lease payments under the operating This method requirca that deferred taxes be recorded for leases at December 31,1995 are summarized as follows:
all temporary differences between the book and tax bases For For the Cleveland of assets and liabilities. The majority of these temporary g Company Electric differences are attributable to property-related basis dif- (mulions or dollars) ferences. Included in these basis differences is the equity ,y 19 s1
]
s 63
,3 component of AFUDC, which will increase future tax 1998 102 63 expense when it is recovered through rates. Since this 1999 108 70
. 2000 11I 76 component is not recognized for tax purposes, the Com- Laier years t.807 1.245 pany must record a liability for its tax obligation. The Total Future Minimum Lease PUCO permits recovery of such taxes from customers Payments $D55 $l9n when they become payable. Therefore, the net amount due from customers through rates has been recorded as a Rental expense is accrued on a straight-line basis over the deferred charge and will be recovered over the lives of the terms of the leases. The amount recorded in 1995,1994 related assets. See Note 7(a). and 1993 as annual rental expense for the Mansfield Plant leases was $45 million. The amounts recorded in 1995, Investment tax credits are deferred and amortized over 1994 and 1993 as annual rental expense for the Beaver the lives of the applicable property as a redaction of Valley Unit 2 lease were $63 million, $64 million and $63 depreciation expense. See Note 7(d) for a discussion of million, respectively. Amounts charged to expense in the amortization of certain unrestricted excess deferred excess of the lease payments are classified as Accumu-taxes and unrestricted investment tax credits under the lated Deferred Rents in the Balance Sheet.
Rate Stabilization Program.
The Company is selling 150 megawatts of its Beaver (2) Utility Plant Sale and Leaseback Valley Unit 2 leased capacity entitlement to Cleveland Tran8aCflonS Electric. Revenues recorded for this transaction were $98 million, $108 million and $103 million in 1995,1994 and The Company and Cleveland Electn.e are co-lessees of .
1993, respectively. We ant. .icipate that th.is sale will con-18.26 % (150 megawatts) of Beaver Valley Unit 2 and .
tmue m. definitely. The future minimum lease payments 6.5% (51 megawatts), 45.9 % (358 megawatts) and i through 2017 associated with Beaver Valley Unit 2 aggre- '
44.38% (355 megawatts) of Units I, 2 and 3 of the gate $1.35 bilh.on.
Mansfield Plant, respectively. These leases extend through 2017 and are the result of sale and leaseback (3) Property Owned with Other Utillfles l transactions completed m 1987.
and Investors Under these leases, the Company and Cleveland Electric Company owns, as a tenant in common vith other are responsible for paying all taxes, insurance premiums, .
utilities and those mvestors who are owner-participants m operation and maintenance expenses and all other similar var us s 1 and leaseback transactions (Lessors), certain costs for their interests in the units sold and leased back.
gener ting uns as Hsted below. Ead owner owm an They may incur additional costs in connection with capi-und vided share in the entire unit. Each owner has the tal improvements to the units. The Company and Cleve-right to a percentage of the generating capability of each land Electric have options to buy the interests back at the un t equal to its ownership share. Each utility owner is end of the leases for the fair market value at that time or bligated to pay for only its respective share of the renew the leases. The leases include conditions for castructim costs and operating expenses. Each Lessor mandatory termination (and possible repurchase of the has leased its capacity rights to a utility which is obligated leasehold interest) for events of default.
to pay for such Lessor's share of the construction costs As co-lessee with Cleveland Electric, the Company is also and operating expenses. The Company's share of the obligated for Cleveland Electric's lease payments. If operating expenses of these generating units is included in Cleveland Electric is unable to make its payments under the Income Statement. The Balance Sheet classification the Manslield Plant leases, the Company would be obli- of Property, Plant and Equipment at December 31,1995 shteen
includes the following facilities owned by the Company as See Management's Financial Analysis-Outlook Haz-a tenant in common with other utilities and Lessors: ardous Waste Disposal Sites.
Property, Ownership t (5 Nuclear Operations and Megawatts (Exclusive of Accumulated Con (fngenCles Generatine Unit (% Share) Nuclear Fuel) Decreciation (millions of dollars) (a) Operating Nuclear Units Davis-Besse 429 (48.62%) $ 649 $202 Perry Unit i 238 (19.91) 1,050 221 The Company's three nuclear units may be impacted by ,
B a 2 and e
activities or events beyond our control. An extended I (Note 2) 13 (1.65) 207 J outage of one of our nuclear units for any reason, coupled Total 12 if21 with any unfavorable rate treatment, could have a mate-rial adverse effect on our financial condition and results of i (4) Construction and Contingencies ,
operatm.ns. See the discussion of these and other n.sks .m l
(a) Construction Program Management's Financial Analysis-Outlook-Nuclear l The estimated cost of the Company's construction pro- Operations. I gram for the 1996-2000 period is $345 million, including AFUDC of $10 million and excluding nuclear fuel.
(b) Nuclear Insurance The Price-Anderson Act limits the public liability of the The Clean Air Act Amendments of 1990 (Clean Air i owners of a nuclear power plant to the amount provided 1 Act) requires, among other things, significant reductions by private insurance and an industry assessment plan. In in the emission of sulfur dioxide and nitrogen oxides by the event of a nuclear incident at any unit in the United I fossil-fueled generating units. Our strategy provides for States resulting in losses in excess of the level of private compliance primarily through greater use of low-sulfur insurance (currently $200 million), the Company's maxi-coal at some of our umts and the use of emission mum potential assessment under that plan would be allowances. Total capital expenditures from 1991 through
$70 million per incident. The assessment is limited to 1995 in connection with Clean Air Act complianc
$9 million per year for each nuclear incident. These amounted to $4 million. The plan will require additional assessment limits assume the other CAPCO companies
' capital expenditures over the 1996-2005 period of approx-contribute their proportionate share of any assessment.
imately $41 million for nitrogen oxide control equipment and other plant process modifications. In addition, higher The utility owners and lessees of Davis-Besse, Perry and fuel and other operation and maintenance expenses may Beaver Valley also have insurance coverage for damage to be incurred. property at these sites (including leased fuel and cleanup l costs). Coverage amounted to $2.75 billion for each site (b) Perry Unit 2 as of January 1,1996. Damage to property could exceed Perry Unit 2, including its share of the facilities common the insurance coverage by a substantial amount. If it does, with Perry Unit 1, was approximately 50% complete when the Company's share of such excess amount could have a construction was suspended in 1985 pending considera- material adverse etTect on its financial condition and tion of various options. We wrote off our investment in results of operations. In addition, the Company can be I Perry Unit 2 at December 31,1993 after we determined ssessed a maximum of $19 million under these policies that it would not be completed or sold. The write-off during a policy year if the reserves available to the insurer l are inadequate to pay claims arising out of an accident at totaled $232 million ($167 million after taxes) for the Company's 19.91% ownership share of the unit. any nuclear facility covered by the insurer.
l The Company also has extra expense insurance coverage.
(c) Hazardous Waste Disposal Sites .
It includes the incremental cost of any replacement power l The Company is aware of its potential involvement in the purchased (over the costs which would have been cleanup of several sites. The Company has accrued a incurred had the units been operating) and other inciden-liability totaling $5 million at December 31,1995 based tal expenses after the occurrence of certain types of on estimates of the costs of cleanup and its proportionate accidents at our nuclear units. The amounts of the cover-responsibility for such costs. We believe that the ultimate age are 100% of the estimated extra expense per week outcome of these matters will not have a material adverse during the 52-week period stuting 21 weeks after an etTect on our financial condition or results of operations. accident and 80% of such c.,timate per week for the next St*VenlECn
. _ . ___ _ ~ _ __
104 weeks. The amount and duration of extra expense tory assets and (2) a significant change in the manner in could substantially exceed the insurance coverage. which rates are set by the PUCO from cost-based regula.
tion to some other form of reg'ilation. Regulatory assets (6) Nuclear Fuel represent probable future revenues to the Company asso-Nuclear fuel is financed for the Company and Cleveland ciated with certain incurred costs, which it will recover Electric through leases with a special-purpose corpora- from customers through the rate-making process.
tion. The total amount of financing currently available Effective January 1, 1996, the Company adopted under these lease arrangements is $307 million ($157 SFAS 121 which imposes stricter criteria for carrying million from intermediate-term notes and $150 million regulatory assets than SFAS 71 by requiring that such from bank credit arrangements). The intermediate-term assets be probable of recovery at each balance sheet date.
notes mature in 1996 and 1997 ($84 million in September The criteria under SFAS 121 for plant assets require such 1996 and $73 million in September 1997). 'The bank assets to be written down only if the book value exceeds credit arrangements terminate in October 1996. The spe- the projected net future cash flows.
cial-purpose corporation plans to obtain alternate financ-Regulatory assets in the Balance Sheet are as follows:
ing in 1996 to replace the $234 million of financing December 31.
expiring in 1996. At December 31,1995,$93 million of g g nuclear fuel was financed for the Company. The Com- qigof pany and Cleveland Electric severally lease their respec- Amounts due from customers for future rederal tive portions of the nuclear fuel and are obligated to pay g),,r iz d s r om Beaver valley Unit 2 sale._ 6 for the fuel as it is consumed in a reactor. The lease rates Unamortized loss on reacquired debt 28 28 are based on various intermediate-term note rates, bank Pre-phase-in deferrals' 222 229 Rate Stabilization Program deferrals lM _,J.jg rates and commercial paper rates. htal 3 g The amounts financed include nuclear fuel in the Davis-
- Represent deferrals of operating expenses and carrying charges for Perry Unit I and Beaver Valley Unit 2 in 1987 and 1988 which are Besse, Perry Unit I and Beaver Valley Unit 2 reactors being amortized over the lives of the related property.
with remaining lease payments for the Company of As of December 31, 1995, customer rates provide for
$37 milh.on, $21 m.lh.on i and $15 m.lh.i on, respectively, at recovery of all the above regulatory assets, except those December 31,1995. The nuclear fuel amounts financed related to the Rate Stabilization Program discussed ,
and capitalized also m. eluded interest charges m. curred by -
. . below. The remaining recovery periods for all of the the lessors amountm.g to $2 m..h.u on m 1995, $4 milh.on m !
. . regulatory assets listed above range from 16 to 33 years. i 1994 and $6 m.lh.i on m 1993. The estimated future lease amortization payments for the Company based on pro. (b) Rate Case jected consumption are $41 million in 1996,$34 million In April 1995, the Company and Cleveland Electric filed in 1997, $29 million in 1998, $28 million in 1999 and requests with the PUCO for price increases aggregating
$27 million in 2000. $119 million annually to be effective in 1996. The price increases are necessary to recover cost increases and (7) Regulatory Matters amortization of certain costs deferred since 1992 pursuant (a) Regulatory Accounting Requirements and to the Rate Stabilization Program. If their requests are Regulatory Assets approved, the Company and Cleveland Electric intend to The Company is subject to the provisions of SFAS 71 and freeze prices until at least 2002 with the expectation that has complied with its provisions. SFAS 71 provides, increased sales and cost control measures will preclude among other things, for the deferral of certain incurred the need for further price increases. If circumstances costs that are probable of future recovery in rates. We make it impossible to earn a fair return for Centerior monitor changes in market and regulatory conditions and Energy common stock share owners over time, the Com-consider the efTects of such changes in assessing tne p ny and Cleveland Electric would ask for a further continuing applicability of SFAS 71. Criteria that could increase, but only after taking all appropriate actions to give rise to discontinuation of the application of SFAS 71 make such a request unnecessary.
include: (1) increasing competition which significantly In November 1995, the PUCO Staff issued its report l restricts the Company's ability to charge prices which addressing the rate case. The Staff recommended that the i allow it to recover operating costs, earn a fair return on PUCO grant the full $119 million price increase invested capital and recover the amortization of regula- requested ($35 million for the Company and $84 million eighteen l
for Cleveland Electric). However, the Staff also recom- also result in a write-down of the Company's property, mended that the price increase be conditioned upon the plant and equipment pursuant to SFAS 121.
commitment by the Company and Cleveland Electric "t We believe application of SFAS 121 in that event will not a significant revaluation of their asset bases over some result in a write-oft of regulatory assets unless the PUCO fmite period of time" denies recovery of such assets or if we conclude, as a in December 1995, the PUCO ordered an investigation result of the outcome of the Company's pending rate case into the financial conditions, rates and practices of the or some other event, that recovery is not probable for Company and Cleveland Electric to identify outcomes some or all of the regulatory assets. Furthermore, a write-and remedies other than those routinely applied during down under SFAS 121 of the Company's property, plant the rate case process. and equipment is not expected.
In late January 1996, the Staff proposed an incremental (d) Rate Stabilization Program l reduction (currently, an aggregate of $1.25 billion for the The Rate Stabilization Program that the PUCO approved l Company and Cleveland Electric) beyond the normal in October 1992 allowed the Company to defer and level in nuclear plant and regulatory assets within five subsequently amortize and recover certain costs not cur-years. The Stati proposed that the Company and Cleve- rently recovered in rates and to accelerate amortization of land Electric have flexibility to determine how to achieve certain benefits during the 1992-1995 period. Recovery of ,
this incremental asset revaluation, but no additional price the deferrals will begin with the effective date of the increases to recover the accelerated asset revaluation were PUCO's order in the pending rate case. The regulatory j, proposed. Any incremental revaluation of assets would be assets recorded included the deferral of post-in-service for regulatory purposes and would cause prices and reve- interest carrying charges, depreciation expense and prop-nues after the five-year period to be lower than they erty taxes on assets placed in service after February 29, otherwise would be in conjunction with any rate case 1988, the deferral of incremental expenses resulting from following such revaluation. The Staffs asset revaluation the adoption of SFAS 106 (see Note 9(b)), and the proposal represents a substantial change in the form of deferral of the operating expenses equivalent to an accu.
l rate-making traditionally followed by the PUCO and is mulated excess rent reserve for Beaver Valley Unit 2
! inconsistent with the Ohio statutes that define the rate- (which resulted from the April 1992 refinancing of
! making process. The PUCO is not bound by the recom- Secured Lease Obligation Bonds issued by a special-mendations of the StalT. A decision by the PUCO is purpose corporation). The cost deferrals recorded in 1995, j anticipated in the second quarter of 1996. 1994 and 1993 pursuant to these provisions were $38 (c) Assessment of Potential Outcomes million, $43 million and $76 million, respectively. The regulatory accounting measures also provided for the We continually assess the effects of competition and the accelerated amortization of certain unrestricted excess '
changing industry and regulatory environment on opera-deferred tax and unrestricted investment tax credit bal-tions, the Company's ability to recover regulatory assets ances and an excess interim spent fuel storage accrual l and the Company's ability to continue application of balance for Davis-Besse. The total annual amount of such SFAS 71. If, as a result of the pending rate case or other l accelerated benefits was $18 million in 1995,1994 and events, we determine that the Company no longer meets g 993, the criteria for SFAS 71, the Company would be required to record a before-tax charge to write off the regulatory (e) Phase in Deferrals j asstts shown above and evaluate whether the Company's in 1993, upon completing a comprehensive study which j property, plant and equipment should be written down. In led to our strategic plan, we concluded that projected j
- the more likely event that only a portion of operations revenues would not provide for recovery of deferrals l
I (such as nuclear operations) no longer meets the criteria recorded pursuant to a phase-in plan approved by the !
of SFAS 71, a write-off would be limited to regulatory PUCO in 1989 and, consequently, that the deferrals l assets, if any, that are not reflected in the Company's would have to be written off. Such deferrals were sched- j cost-based prices established for the remaining regulated uled to be recovered in 1994 through 1998. The total operations. In addition, we would be required to evaluate phase-in deferred operating expenses and carrying charges
- whether the changes in the competitive and regulatory written oft at December 31,1993 by the Company were i
environment which led to discontinuing the application of $55 million and $186 million, respectively (totaling $165 J
SFAS 71 to a portion of the Company's operations would million after taxes). )
i H5NftffH ;
i l
- (8) Federciincome Tcx with a corresponding $43 million reduction in federal l income tax liability. Because of the alternative minimum !
The components of federal income tax expense (credit) tax ( AMT), $25 milh.on of the $43 million was realized .in l recorded in the Income Statement were as follows: . l g i994 3993 1994.The remaining $18 milh.on will not be realized until '
(millions of dollars) 1999. l Operating Expenses: I current $ 40 $ 18 $ 36 - Under SFAS 109, temporary differences and carryfor- i Deferred J ,_11 (46) wards resulted in deferred tax assets of $179 million and f Total Expense (Credit) to Operating deferred tax liabilities of $752 million at December 31, Nonoperating income: 1995 and deferred tax assets of $178 million and deferred Current (12) (29) (15) tax liabilities of $719 million at December 31, 1994.
Deferred _.l.4 _].1 [114, )
These are summarized as follows: l Total Expense (Credit) to Nonoperating December 31.
Income J J (.J]9) j,99.2 1994 Total Federal Income Tax Expense (Credit) ., M M g) (n o of Pr petty, plant and equiprr.ent $627 $606 The deferred federal income tax expense results from the Deferred carrying charges and operating expenses __ 85 83 temporary differences that arise from the different years ,
Net operating loss carr> forwards (44) (54) I certain expenses are recognized for tax purposes as investment tax credits (46) (51) opposed to financial reporting purposes. Such temporary Sale and leaseback transactions (4) (3) differences affecting operating expenses relate principally Other _{41) L40) to depreciation and deferred operating expenses whereas Net deferred tax liability g g i those affecting nonoperating income principally relate to )
For tax purposes, net operat.ing loss (NOL) carryforwards .
deferred carrying charges and the 1993 wr.ite-ofTs. . .
of approximately $125 milh.on are available to reduce Federal income tax, computed by multiplying income future taxable income and will expire in 2005 before taxes by the 35% statutory rate, is reconciled to the through 2009. The 35% tax effect of the NOLs is $44 mil-amount of federal income tax recorded on the books as lion. Additionally, AMT credits of $80 million that may follows: be carried forward indefinitely are available to reduce 1995 1994 1993 (millions of dollars) future tax. l Book Income (Loss) Before Federal l nacome iax u m g) (9) Retirement Benefits Tax (Credit) on Book income (Loss) at Statutory Rate $ 49 $ 41 $(150) (a) Retirement income Plan Increase (Decrease) in Tax: . .
Write-oft'of Perry Unit 2 - -
16 Centerior Energy sponsors jointly w.th i its subsid.ianes a i Write-off'of phase-in deferrals - -
8 noncontributing pension plan (Centerior Pension Plan)
"'i St zation Pogrm which covers all employee groups. The amount of retire-Sale and leaseback transactions and ment benefits generally depends upon the length of ser-amortization 5 5 5 vice. Under certain circumstances, benefits can begin as Other items - _,_.1, 4 ea@ as age E h hndng pok.y a b mmph w.n&
Total Federal income Tax Expense (Credit), Q Q g)
Employee Retirement income Security Act of 1974 The Company joins in the filing of a consolidated federal guidelines.
income tax return with its afliliated companies. The h W9 6 d & VTP,u method of tax allocation reflects the benefits and burdens early retirement program. Operating expenses for Center-realized by each company's participation m. the consoh.-
ior Energy and its subsidiaries in 1993 included $205 dated tax return, approximating a separate return result .
milh.on of pension plan accruals to cover enhanced VTP
- ' "
- E *"Y' benefits offset by a credit of $81 million resulting from a For tax reporting purposes, the Perry Unit 2 abandonment settlement of pension obligations through lump sum pay-l was recognized in 1994 and resulted in a $122 million loss ments to almost all the VTP retirees.
l twenty
Pension and VTP costs (credits) for Centerior Energy 10%, respectively. The long-term rate of annual compen-and its subsidiaries for 1993 through 1995 were comprised sation increase assumption was 3.5% for 1995 and 1996 of the following components: and 4% thereafter. At December 31,1995 and 1994, the L9_91 L994 L922 Company's net accrued pensiop liability included in "I
Pension Costs (Credits):
Retirement Benefits in the Balance Sheet was $64 million Service cost for benefits carned during the and $66 million, respectively, period $ 10 $ 13 $ 15 Interest cost on projected benefit obligation. 26 26 37 Plan assets consist primarily of investments in common U k, bonds, guaranteed investment contracts, cash Net m tion an d al ,
Net pension costs (credits) equivalent securities and real estate.
(8) 3 (9)
VTP cost - -
205 settlement gain _= _= E) (b) Other Postretirement Benefits Net costs (credits) M) Wg Centerior Energy sponsors jointly with its subsidiaries a Pension and VTP costs (credits) for the Company and its postretirement benefit plan which provides all employee pro rata share of the Service Company's costs were $(3) groups certain health care, death and other postretirement million, $1 million and $53 million for 1995,1994 and benefits other than pensions. The plan is contributory, 1993, respectively. with retiree contributions adju.ted annually. The plan is The following table presents a reconciliation of the funded n t funded. The Company adopted SFAS 106, the status of the Centerior Pension Plan. The Company's accounting standard for postretirement benefits other than share of the Centerior Pension Plan's total projected Pensions, effective January 1,1993. The standard requires benefit obligation approximates 30%. the accrual of the expected costs of such benefits during December 31.
the employees' years of service. Prior to 1993, the costs of L992 1921 these benefits were expensed as paid, which was consis-I
("$",5) tent with rate-making practices.
Actua al resent value of benefit obligations: g
.g g Nonvested benefits J J for 1993 through 1995 were as follows:
Accumulated benefit obligation 306 280 1991 M9,,1 1992 Effect of future compensation levels _ 14 _]7 (millions of dollars)
Total projected benefit obligation 360 317 Service cost for benefits carned during the Plan assets at fair market value _),91 _]s2 Period $1 $1 $1 Funded status 34 45 Interest cost on accumulated postretirement Unrecognized net gain from variance benefit obligation 7 7 6 between assumptions and experience (68) (79) Amortization of transition obligation at Unrecognized prior service cost 15 10 January 1,1993 f $63 million ver 0 yean 2 3 3 Transition asset at January 1,1987 being amortized over 19 years _(Jf) g) VTP curtailment cost (inJudes $6 million Net accrued pension liability g) g) transition obligation adjustment) ,,= -
J Total costs g g g A September 30 measurement date was used for 1995 and .
These amounts included costs for the Company and its 1994 reporting. At December 31, 1995, the settlement pro rata share of the Service Company's costs.
(discount) rate and long-term rate of return on plan assets assumptions were 8% and i1%, respectively. The in 1995,1994 and 1993, the Company deferred incremen-long-term rate of annual compensation increase tal SFAS 106 expenses (in excess of the amounts paid) of assumption was 3.5% in 1996 and 1997 and 4% thereafter. $1 million, $2 million and $37 million, respectively, pur-At December 31,1994, the settlement rate and long-term suant to a provision of the Rate Stabilization Program.
rate of return on plan assets assumptions were 8.5% and See Note 7(d).
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The accumulated pastretirement benefit obligation and contract is terminated early for any reason, the Company accrued postretirement benefit cost for the Company and would attempt to reduce the termination charges and its share of the ' Service Company's obligation are as would ask the PUCO to allow recovery of such charges follows: from customers thmugh the fuel factor.
December 31.
m m (11) Capitalization (millions of dollars) (a) Capital Stock Transactions Accumulated postretirement benclit obligation attributable to: Preferred stock shares retired dun.ng the three years Retired participants $(76) $(79) ended December 31,1995 are listed in the following table.
Fully eligible active plan participants (t) -
E M E Other active plan participants _(_9 ) .,_(1) (thousands of shares) i Accumulated postretirement benefit obligation ~~ (86) Subject to Mandatory Redemption:
(86)
$100 par $9.375 (17) (17)- (17)
Unrecognized net gain from variance between assumptions and experience E' (9) (7)
Unamortiecd transition obligation ._49 _H Accrued postretirement benefit cost M) g)
(b; Faulty Distribution Restrictions The Balance Sheet classification of Retirement Benefits Federal law prohibits the Company from paying dividends at December 31,1995 and 1994 includes only the Com- out of capital accounts. Ilowever, the Company may pay )
pany's accrued postretirement benefit cost of $39 million dividends out of appropriated retained earnings and cur-and $37 million, respectively, and excludes the Service rent earnings. At December 31,1995, the Company had Company's portion since the Service Company's total 3183 million of appropriated retained earnings for the .
accrued cost is carried on its books. payment of preferred stock dividends. The Company is prohibited from paying a common stock dividend by a A September 30 measurement date was used for 1995 and ., . .
E** *' " * '" * #8 8* " " D '*9" ** ""
1994 reporting. At December 31,1995 and 1994, the l dividends to be paid out of the total balance of retained settlement rate and the long-term rate of annual compen- l earnings, which currently is a deficit.
sation increase assumptions were the same as those d.is-cussed for . pension reporting in Note 9(a). At (c) Preferred and Preference Stock l December 31,1995, the assumed annual health care cost Amounts to be pa.d i for preferred stock which must be trend rates (applicable to gross eligible charges) were 8% .
redeemed during the next five years are $1.665 m.lh.on i m for medical and 7.5% for dental in 1996. Both rates reduce each year 1996 through 1999 only.
gradually to a fixed rate of 4.75% by 2003. Elements of the obligation affected by contribution caps are signifi- The annual preferred stock mandatory redemption provi-cantly less sensitive to the health care cost trend rate than sions are as follows:
other elements. if the assumed health care cost trend Shares To P ce rates were increased by one percentage point in each Redeemed in Share future year, the accumulated postretirement benefit obli. $100 par $9.375 16.650 1985 $100 gation as of December 31,1995 would increase by $3 mil- The annualized preferred dividend requirement at lion and the aggregate of the service and interest cost December 31,1995 was $17 million.
components of the annual postretirement benefit cost The preferred dividend rates on the Company's Series A would increase by $0.3 million, and B fluctuate based on prevailing interest rates and (10) Guarantees market conditions. The dividend rates for these issues The Company has guaranteed certain loan and lease obligations of a coal supplier under a long-term coal Preference stock authorized for the Company is 5,000,000 supply contract. At December 31, 1995, the principal shares with a $25 par value. No preference shares are amount of the loan and lease obligations guaranteed by currently outstanding.
the Company was $14 million. The prices under the With respect to dividend and liquidation rights, the Com-contract which includes certain minimum payments are pany's preferred stock is prior to its preference stock and l
l sufficient to satisfy the loan and lease obligations and common stock, and its preference stock is prior to its mine closing costs over the life of the contract. If the common stock.
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l (d) Long-T:rm Debt Cnd Other Borrowing (12) Short Tirm Bort: wing Arr ngements >
Arr:ngements .
Centenor Energy has a $125 m.lh.on i revolving credit Long term debt, less current maturities, was as follows: f cility through May 1996. Centerior Energy and the Actual Service Company may borrow under the facility, with all
'g,Q8' borrowings jointly and severally guaranteed by the Com-
- Pany and Cleveland Electric. Centerior Energy plans to Dec n ber 31, December 31.
Year of Maturity 1995 1995 1994 transfer any of its borrowed funds to the Company and f
(m$,",8 i )
Cleveland Electric. The credit agreement is secured with First mortgage bonds: first mortgage bonds of the Company and Cleveland 1997 6.125 % $ 31 s 31 EOctric in the proportion of 60% and 40%, respectively.
i f8 The banks' fee is 0.625% per annum payable quarterly in 2001-2005 7.85 207 207 addition to interest on any borrowings. There were no 0 7.
borrowings under the facility at December 31,1995. Also, I
2021-2023 7.74 148 148 the Company and Cleveland Electric may borrow from 684 585 each other on a short-term basis. At December 31,1995, Secured medium-term notes the Company had total short-term borrowings of $21 duc 1997-2021' ,, 8.41 238 250 Term bank loans million from its affiliates with a weighted average interest 62 Notes duc 1997" _ , 8.75 8 25
" ~
rou7 ion in con e due (13) FinancialInstruments tw7-2010 6.59 5 w Other - net The estimated fair values at December 31,1995 and 1994 (2) (2) f fm ncial instruments that do not approximate their Total Long-Term Debt _ . M M carrying amounts in the Balance Sheet are as follows:
- Secured by first mortgage bonds. December 31.
" Secured by subordinated mortgage collateral. 1995 1994 Carrying Fair Carrying Fair Amount Value Amount Value Long-term debt matures during the next five years as (millions of dollars) follows: $56 million in 1996, $40 million in 1997, $39 mil- Capitalization and Liabilities:
lion in 1998, $119 million in 1999 and $31 million in Preferred Stock, with Mandatory Redemption Provisions 2000.
(including current portion) _ $ 7 s 6 s 18 $ 19 Long-Term Debt (including The Company's mortgage constitutes a direct first lien on current portion) 1,126 1,137 1,227 1,116 substantially all property owned and franchises held by Noncash investments in the Nuclear Plant Decommis-the Company. Excluded from the lien, among other sioning Trusts are summarized in the following table.
things, are cash, securities, accounts receivable, fuel, g
supplies and automotive equipment. i995 1994 (millions of Certain credit agreements of the Company contain cove- d "'")
. . Type of Secun . ties:
nants relatmg to fixed charge coverage ratios and limita-Federal Government $21 521 tions on secured financing other than through first Municipal _11 _L4 mortgage bonds or certain other transactions. In June Total g 3
1995, the Company and Cleveland Electric replaced let- Maturities:
ters of credit in connection with the sale and leaseback of Due within one year $1 $9 Beaver Valley Unit 2 that were due to expire with new Due in one to five years 9 7 letters of credit expiring in June 1999. The letters of D"* I" *i* ' ' UY " " 7 Due after 10 years _[1 _12 credit are in an aggregate amount of approximately
$225 million and are secured by first mortgage bonds of Total 3 g the Company and Cleveland Electric in the proportion of The fair value of these trusts is estimated based on the 60% and 40%, respectively. At December 31,1995, the quoted market prices for the investment securities. As a Company had outstanding $52 million of bank loans and result of adopting the new accounting standard for certain notes secured by subordinated mortgage collateral. investments in debt and equity securities, SFAS 115, in twenty-three
1994, the carrying amount of these trusts approximates (15) Pending M;rger cf the C:mpany ints fair value. The fair value of the Company's preferred Cl;V;l;nd Electr/C stock, with mandatory redemption provisions, and long-term debt is estimated based on the quoted market prices In March 1994, Centerior Energy announced a plan to for the respective or similar issues or on the basis of the merge the Company into Cleveland Electric. Since the discounted value of future cash flows. The discounted Company and Cleveland Electric alliliated in 1986, efforts have been made to consolidate operations and administra-value used current dividend or interest rates (or other appropriate rates) for similar issues and loans with the tion as much as possible to achieve maximum cost same remaining maturities. savings.
The estimated fair values of all other financial instru- Various aspects of the merger are subject to the appiovat ments approximate their carrying amounts in the Balancc of the FERC and other regulatory authorities. The FERC Sheet at December 31,1995 and 1994 because of their has deferred action on the merger application until the short-term nature. merits of the open access transmission taritTs proposed by the C mPany and Cleveland Electric are addressed in (14) Quarterly Results of Operations hearings. The PUCO and the Pennsylvania Public Utility (Unaudited)
Commission have approved the merger. NRC action on The following is a tabulation of the unaudited quarterly the request by the Company and Cleveland Electric for )
results of operations for the two years ended Decem- authorization to transfer certaN NRC licenses to the ber 31,1995. l merged entity is not expected until approval has been Ouarters Ended Marqh ,11, June 3o. Sept. 30. Dec. 31.
obtained from the FERC.
(millions of dollars) l 1995 in June 1995, share owners of the Company's preferred !
Operating Revenues $206 $215 $246 $206 stock approved the merger and share owners of Cleveland Operating Income 43 45 59 41 Electric's preferred stock approved the authorization of Net income 20 22 33 22 additional shares of preferred stock. When the merger Earnings Available for Common Stock 15 17 2) 18 becomes efTective, share owners of the Company's pre-
,994 ferred stock will exchange the,ir shares for preferred stock Operating Revenues $217 $216 $227 $204 shares of Cleveland Electric having substantially the same Operating Income 43 43 53 40 terms. Debt holders of the merging companies will Net income 19 20 29 15 become debt holders of Cleveland Electric.
Earnings Available for Common Stock 13 14 24 11 For the merging companies, the combined pro forma operating revenues were $2.516 billion, $2.422 billion and
$2.475 billion and the combined pro forma net income (loss) was $281 million, $268 million and $(876) million for the years 1995,1994 and 1993, respectively. The pro forma data is based on accounting for the merger on a method similar to a pooling of interests. The pro forma data is not necessarily indicati"e of the results of opera-tions which would have been reported had the merger been in effect during those years or which may be reported in the future. The pro forma data should be read in conjunction with the audited financial statements of both the Company and Cleveland Electric.
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R: port cf Ind:p:nd:nt disclosures in the financial statements. An audit also Public Accountants includes assessing the accounting principles used and significant estimates made by management, as well as To the Share Owners and evaluating the overall financial statement presentation.
Board of Directors of We believe that our audits provide a reasonable basis for The Toledo Edison Company:
our opinion.
We have audited the accompanying balance sheet and in our opinion, the financial statements referred to above statement of preferred stock of The Toledo Edison Com-present fairly, in all material respects, the financial posi-pany (a wholly owned subsidiary of Centerior Energy tion of The Toledo Edison Company as of December 31, Corporation) as of December 31,1995 and 1994, and the 1995 and 1994, and the results of its operations and its related statements of income, retained earnings and cash cash flows for each of the three years in the period ended flows for each of the three years in the period ended December 31, 1995, in conformity with generally December 31, 1995. These financial statements are the accepted accounting principles.
L responsibility . of the Company's management. Our respansibility is to express an opinion on these financial As discussed further in Note 9, a change was made in the statements based on our audits. method of accounting for postretirement benefits other than pensions in 1993.
We conducted our audits m. accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free g4 g gf of material misstatement. An audit includes examining, Cleveland, Ohio on a test basis, evidence supporting the amounts and February 21,1996 i
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Fin;nci;l cnd St;tisticci Rcvi w Operating Revenues (millions of dollars)
Steam Total Total Total lleating Operating Year Residential Commercial Industrial Other Retail Wholesale Electric & Gas Revenues -
1995 $238 184 254 65 741 133 874 -
$874 1994 227 181 251 64 723 142 865 -
865 1993 229 180 244 71 724 147 871 -
871 1992 215 175 236 61 687 158 845 -
845 1991 230 184 236 90 740 147 887 - 887 1985 185 129 214 26 554 22 576 6 582 Operating Expenses (millions of dollars)
Other Generation Deferred Federal Fuel & Operation Facilities Depreciation Taxes. Operating income Total Pun;hased & Rental A Other Than Expenses, Taxes Operating Year Power Maintenance Expense, Net Amortization FIT Net (Credit) Eupenses 1995 $157 225 104 84 91 (17) 42 $686 1994 167 229 104 83 90 (21) 33 685 1993 173 352(a) 104 76 91 (4)(b) (10) 782 1992 169 236 106 77 91 (17) 33 695 1991 178 243 113 72(c) 89 1 32 728 1985 166 141 - 44 48 - 53 452 Income (Loss) (millions of dollars)
Federal Income Other Deferred income (Loss)
Income & Carrying Taxes- Before Operating AlUDC- . Deductions, Charges, Credit interest Year Income Equity Net Net (Expense) Charges 1995 $188 1 6 14 (2) $ 207 1994 I80 1 3 15 (2) 197 1993 89 1 (232)(d) (161)(b) 129 (174) ,
1992 150 1 1 4l (1) 192 1991 159 1 5 22 (6) 181 1985 130 105 11 --
38 284 Income (Loss) (millions of dollars)
Net (N$'
Available for Preferred Debt AFUDC- Income Stock Common Year Interest Debt (Loss) Dividends Stock 1995 $111 (1) 97 18 $ 79 l l
1994 116 (1) 82 20 62 i 1993 116 (1) (289) 23 (312) 1992 122 (1) 71 24 47 1991 132 (1) 50 25 25 1985 155 (45) 174 42 132 i (a) includes early retirement program expenses and other charges of $107 million.
(b) includes write-ofofphase-in deferrals of $24! million. consisting of $$$ million ofdeferred operating expenses and $l86 million ofdeferred carrying charges.
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The Toledo Edison Gwspany Electric Sales (millions of KWH) Electric Customers Residential Usage (thousands at year end)
Average Average Average Price Revenue industria! KWil Per Per Per Year Residential Commercial Industr d Wholesale Other Total Residential Cor imercial & Other Total Customer KWii Customer 1995 _ 2 164 1 748 4 174 2 563 500 11 149 260 27 4 291 8 384 10.99c $921.23 1994 _ 2 056 1 711 4 099 2 548 499 10 913 257 26 4 287 8 044 11.04 888.30 l 1993.,_ 2 039 I 672 3 776 2 146 490 10 123 255 26 4 285 7 997 11.23 897.65 1993 I 941 1619 3 563 2 753 478 10 354 255 26 5 286 7 632 11.08 845.99 1991 _ 2 041 1683 3 543 2 587 482 10 336 255 26 4 285 7 990 11.26 897.41 1985_ _ i901 1436 3 429 611 451 7 828 246 24 4 274 7 770 9.72 755.00 Imad (MW & %) Energy (millions of KWH) Fuel Net Emciency-Seasonal Peak Capacity Load C mp ny Generated Purchased Fuel Cost BTU Per Year Capabihty Load Marvin Factor Fossil Nuclear Total Power Total Per KWil KWil 1995 1 651 1738 (5.3)% 62.4 % 4 576 6 761 1I337 299 Ii 636 1.32c 10 341 199J l 726 1620 6.1 64.7 5 160 5 419 10 579 773 11352 1.35 10 298 1993 1726 1568 9.2 64.3 5 548 4 791 10 339 196 10 535 1.42 10 146 1993_ I759 1514 13.9 63.2 4 656 6 293 10 949 (82) 10 867 1.41 10 284 1991 1757 1 510 14.1 64.5 4 848 6 003 10 851 95 10 946 1.44 10 327 1985 1338 1 374 (2.7) 66.8 5 744 952 6 696 1683 8 379 1.90 10 124 Imestment (millions o." dollars)
Construction Work in Total Utihty Accumulated Progress Nuclear Property, Utility i Plant in Depreciation & Net & Perry Fuel and Plant and Plant Total Year Service Anmrtizatmn Plant linit 2 Other Equipment Additions Assets 1995 $2 896 942 1 954 28 98 $2 080 $ 56 $3 474 1994 2 899 892 2 M)7 30 125 2 162 41 3 502 1993 2 837 788 2 049 40 142 2 231 43 3 510 1993 2 847 760 2 087 280 164 2 531 44 3 939 1991 2 692 709 I983 308 198 2 489 54 3 926 1985 1 392 390 1002 1 755 228 2 985 389 3 373 Capitalization (millions of dollars & %)
Preferred Stock. Preferred Stock, with Mandatory without Mandatory Yeer Common Stock Equity Redemption Provisions Rederption Provisions Long-Term Debt Total 1995 $763 38 % 5 -% 210 10% 1 068 52% $2 046 1994 685 34 7 --
210 10 1 154 56 2 056 1993 623 30 28 1 210 10 1 225 59 2 086 1992 935 39 50 2 210 9 1 178 50 2 373 1991 888 38 64 3 210 9 1158 50 2 320 1985 950 36 154 6 230 8 1 339 50 2 673 (c) A change in accountingfor nuclear plant depreciation was adopted. changingfrom the unit.vof-production method to the straight-line method at a 2.5% rate.
(d) includes write-of of Perry Unit 2 of $232 million.
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l INVESTOR INFORMATION Share Owner Information Dividend Reinvestment and Stock Purchase Plan and Individual Retirement Account Share Owner Services (CX* IRA)
Communications regarding stock transfer requirements, Centerior Energy Corporation has a I'ividend Reinvestment lost certificates, dividends and changes of address should and Stock Purchase Plan which pmvides Toledo Edison be directed to Share Owner Services at Centerior Energy share owners of record and other investors a convenient i Corporation. Correspondence should be sent to the means of purchasing shares of Centerior common stock by address indicated below for the Stock Transfer Agent. investing all or a part of their quarterly dividends as well as To reach Share Owner Services by phone, call: making cash investments. In addition, individuals may establish an Individual Retirement Account (IRA) which In Cleveland area 447-2400 invests in Centerior common stock through the Plan.
Outside Cleveland area (800) 433-7794 Information relating to the Plan and the CX*1RA may be obtained from Share Owner Services.
Please have your account number ready when calling.
Independent Public Accountants Stock Transfer Agent Arthur Andersen LLP Centerior Energy Corporation 1717 East Ninth Street Share Owner Services Cleveland, OH 44114 P.O. Box 94661 cleveland, OH 44l01-4661 Environmental Report Stock transfers may be presented at The Company will furnish to share owners, without Society Trust Company of New York charge, a copy of a report on its environmental performance.
5 Hanover Square,10th Floor Requests should be directed to Share Owner Services.
New York, NY 10004 Form 10-K Stock Registrar The Company will furnish to share owners, without charge, Society National Bank a copy of its most recent annual report to the Securities Corporate Trust Division and Exchange Commission. Requests should be directed P.O. Box 6477 to Share Owner Services.
Cleveland, OH 44101 Investor Relations Bond and Debenture Information Inquines from security analysts and institutional investors should be directed to Ronald E. Seeholzer, . .
Manager-Investor Relations, at Centerior Energy First Afortgage Bond Trustee and Paying Agent Corporation, PO. Box 94661, Cleveland, OH 44101-4661 The Chase Manhattan Bank, N.A.
or by telephone at (216) 447-3339. Corporate Trust Customer Service Dept.
Box 3015 Exchange Listings 4 Chase Metrotech Center,3rd Floor Brooklyn, NY l1245 i Preferred Stock ($25 par value): 8.84% series,
$2.365 series, Adjustable Series A and Adjustable (800) 355 2663 l
Series B are listed on the New York Stock Exchange. .
Debenture Trustee and Paying Agent Preferred Stock ($100 par value): 4%%,8.32%,7.76% and F fth Third Bank 10% series are listed on the American Stock Exchange.
Corporate Trust Administration 38 Fountain Square Plaza Cincinnati, OH 45263 (513) 579-5132 l
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The Toledo Edison Company BULK RATE 300 Madison Avenue U.S. POSTAGE Toledo, Oli 43652-0001 PAID CLEVELAND, OHIO PERMIT NO. 409
. . . .