ML20069G565

Centerior Energy Annual Rept 1993

ML20069G565
Person / Time
Site:	Beaver Valley
Issue date:	12/31/1993
From:	Farling R CENTERIOR ENERGY
To:
Shared Package
ML20069G506	List: ML20069G504 ML20069G516 ML20069G565 ML20069G588 ML20069G599
References
NUDOCS 9406100074
Download: ML20069G565 (39)

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DE A R S H A RE OWNER: THE REGW.AW IMATIVE AND economic forces impacting Centerior Energy and the electric utility industry brought your Company to a crucial position in 1993. As a result, we took tough and decisise actions to begin to shift our corporate culture and become a powerful, competitise company in the future.

The focus of this shift is a strategic action plan identifying priorities and actions that will guide Centerior Energy over the next eight years. Paramount to the success of this action plan were two decisions that reflect the seriousness of our position. The Board of Directors soled to reduce the quarterly common -

1 .

stock dividend to $0.20 per share and .

)

write off $1.023 billion, after taxes, of e. .,

assets. We notified you in January of r Y '

these decisions and their meaning within .

the structure of our plan, w hich delines  !

our commitment to financial well-being - .

>p }'

and competitive leadership.

Many of the past decisions which contrib- \ p -

uted to Centerior Energy's present status -

were based on pmjections of economic . .

grow th in our area that did not occur. 3 The economic sluggishness, coupled with increased competitive pressures, continues to exert dow nward pressure on earnings. I' 'h I"' %'

Meanwhile, federal policies continue to mose our industry further toward deregulation and unpixedented competition for customers in the once-protected markets of imestor-owned utilities.

l At Centerior Energy, we are no strangers to competition. As a condition of the licenses granted to operate our nuclear generating plants, we opened our power lines in 1977 to the transmission, or wheeling, of electric power from outside wholesalers to municipal electric systems in our area. Ilowever, the next phase of deregulation may well lead to retail wheeling in which any customer with high electricity consumption would have the option of shopping nationally for the lowest-cost electricity.

This situation occurs at a sery sensitive time for Centerior Energy. Our electric rates are above the regional and national aserages. They reflect the cost of major construction completed in the late 1980s to ensme continued service reliability to our more than one million customers. While these high rates put us at a disadvantage in a competitise environment, our future profits depend on our ability to compete successfully. This was a major factor underlying the strategic review and analysis that led to the development of our eight-year plan. The process had the direct involvement and concurrence of the Board of Directors. We are confident that the resulting plan will be the catalyst that moves Centerior Energy from a traditional regulated utility to a successful, more market-drisen business.

Setting the stage for the success of this plan required those very hard decitions that affected the short-term and lorm-term imerests of our share owners.

We recognite that the dividend reduction is a setback to share ow ners in the short run. Ilowever, our earnings projections did not support continuation of the disidend at its former rate, and the Board concluded that it would not be prudent to delay this reduction. Our estimates for future m

45F

e revenues, costs and capital spending iequirements indicate that we not only can sustain the dividend at the new rate barring unforeseen circumstances, but we also will have the opportunity to grow the dividend as we achieve our strategic objectives.

These decisions were made now because of the pressures imposed by a number of interrelated factors. l cgislatise and regulatory decisions have prompted increasing competition while imposing higher operating costs on investor-owned electrie utilities. The recent action by sescral security rating agencies to downgrade the ratings on securities of our operating companies, Cleseland Electric and Toledo Edison, accented our financial difficulties.

We also decided that, once the deferral of expenses and acceleration of benefits under our Rate Stabilization Program are completed in 1995. we should no longer plan to use regulatory accounting practices to the extent we have in the past. As a result, future earnings will be largely cash earnings. This will further move us toward being a more competitive, market-driven company. It also will provide a clearer picture of our progress and strengthen the Company's financial integrity.

Now that these decisions are behind us, we are better positioned to meet today's economic and competitive challenges through implementation of our sweeping strategic action plan. At the heart of the plan are these priorities:

• Maximize share owner return f rom corporate assets and resources.

• Achiese profitable revenue growth.

• Rank among the nation's top utilities in customer favorability.

• Motivate employees to achieve corporate objectives.

• Attain increasingly competitive power supply costs.

As a major step toward increased competitiveness, we reduced our workforce by 199 in 1993.

largely through early retirement. We respect the decision made by the employees who elected early retirement, and we will miss them. Our streamlined management team includes new members who have added a wealth of energy and ideas. Throughout the Company, we have noted the emergence of skilled and experienced employees who are showing the ability to take responsibility and contribute to our progress.

The following pages provide additional highlights from 1993, an overview of our strategic action plan and specific objectives through the year 2001. The plan is a bold and far-reaching blueprint for progress. Your Board and management are determined to make the plan succeed so that we can meet the single greatest challenge in our history - making the transition from a traditional utility to a more competitive, inarket-driven business whose profitability rewards all share owners.

Sincerely, Q &,

led y Rotwt J. Farling Chairman. President and Chief Executise Officer March 9,1994 m

w

P E R S P E C TI V E SETTING Tile STAGE FOR OUR

- strategic action plan required a period of financial transition involving costly but essential actions that had a major impact on 1993 earnings.

The asset write-offs were among those actions. One write-off involved

$598 million, after taxes, of previously deferred charges related to a 1989 rate agreement. The deferred charges were scheduled to be amortized and recovered in the 1994-1998 period. Ilowever, current projections show that revenues over that period would not provide for such recovery as scheduled due to economic and competitive pressures. Accordingly, we concluded it was necessary to write off the deferred balance. This action moves us closer to reporting earnings on a cash basis with less reliance on regulatory accounting measures. In addition because we recognized the charges in 1993, they will not have to be recognized in the 1994-1998 period.

The other write-off was a S425 million, after-tax charge for Unit 2 of i the Perry Nuclear Power Plant. Based on our current assessment of power l requirements in our region, the partially built unit will not be completed or I sold. As a result, the investment must be written off. l Another essential action was the 19% reduction in our workforce. While this will result in substantial savings annually beginning in 1994, the early retirement program that enabled the reduction resulted in a one-time charge against 1993 earnings of $87 million, after taxes.

The write-offs, the workforce reduction cost and $39 million, after taxes, of other year-end charges contributed to a loss of $6.51 per share for 1993.

Ilowever, our basic business remains stable. Without all of these charges, earnings would have been SI.44 per share, compared with $1.50 per share in 1992.

With these actions behind us, we now can focus on carrying out our strategic action plan. The plan is designed to strengthen us financially and competitively. It includes ambitious objectives and specific goals by which we will monitor and measure our progress. The first priority of the plan is to maximize total return to our share owners, who are deserving beneficiaries of the plan's success.

=

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p% m;, q A KEY FOCUS OF OUR STRATEGIC ACTION PLAN o r- ,

T U "" is the rebuilding of the Company's financial strength.

F I:N' A'N O!E we win measure our success by the improvements we y achieve in total annual return to share owners, in terms of j

%,5 ^ _.a < -a both disidends and stock price appreciation, relative to the Standard & Poor's Index of 500 stocks.

The reduction in the conunon stock dividend will reduce our cash outflow approximately $120 million annually, w hich we intend to use to pay off debt more quickly. As a result, we will improve both our capital structure and interest coverage ratios, thus creating opportunities for improved credit ratings on our securities which were lowered by rating agencies in 1993. Improved credit ratings and less outstanding debt will keep down our interest costs. Better credit ratings also will enhance the value of our stock by lowering its risk.

[YOP[dCS// dip Our strategic action plan calls for further reduction in our annual operation and maintenance expenses. This will be OWilerS G 1010/ challenging because we already reduced those costs by UHHlld[ /E/llrH nearly $80 million, or 9%, over the two years prior to 1993. Last ye r, we experienced some modest increase in CXCCed/Hg //le

, those costs, excluding the previously mentioned, one.

StaHdard & IbOrs time charges.1.or 1994, we ant. .icipate our operation and 500Index. maintenance expenses win be around $us minion. a ,

$65 million reduction from the adjusted 1993 level. For ,

the rest of the eight-year term of our strategic action plan. we expect to limit any increases in annual operation and maintenance expenses to modest levels below the rate of inflation.

As we work to control costs, capital expenditures will be limited to high priority projects.

We have mothballed the last few units operating at our Acme and Lake Shore Plants. This allows us to sase some $80 million in capital expenditures while still keeping our reserve margin of generaung capac:ty at an acceptable levd. We have no plans to begin construction of new generating facilities until well beyond 2001. At the beginning of 1993, our 10-year capital budget forceast averaged $350 million annually, including spending requirements to comply with federal clean-air legislation. Today, the 10-year budget averages $230 million annually.

1IVENEAR COMPARISON OF CUMULATIVE TOTAL. RETURN l s:w 5:00 M m -

5LW  ;

inn

"" EI E m E E m  !

w n m m vt w w Centerior Common Stock  ! S&P 50n Index Five-year total return of $W)im ested in Centerior Energy Comimm Stock at year-end 1988 compared to total return of Standant & Poor's SW)Indexfor the same period, anuming all dividends were reinvested.

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(her the time span of our action plan, we espect that I"'

} w u,. ,

earnings growth will lead to stock ,,

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price appreciation. thus f ulfilling """ ~

f b'

fn o, our objectise of improsed total 4# a D": * >

return to share owners. That '; ' d,a s

L, ,  % o,

"i n,

earnings growth will come ,g a f ._ , ,g 7 through continued cost control. ,

insn , n , a reductions in our interest charges "">'

and, most significantly, f rom ' """' ' ' "#

hm Iw . a , a-revenue increases, particularly f .,, og , , nj hom the aggressise new measures acm ," w .J we base deseloped to increase l ""J c, "n, a n ut electricity sales.

TO ACilll!Vli RfWiiNUl! GROWTil. Wi! Wil.l.

work sigorously to meet more customer needs, compete proactisely with other energy prosiders and encourage REVENUES economic development in our senice area. We also will see\ to increase resenues by restructuring our rates to our sariolls Clistomets lo sult these changing inarket conditions.

During the 1970s and 1980s. we cut back on our traditional promotion of kilowall hour sales.

We did so in response to poseinmental and societal pressures encouraging energy consenation as a way to deler the ad led costs and emironmental impact of new power plants beyond those already under construction. At the time, work was well under way on Unit 1 of the Perry Nuclear Power Plant and Unit 2 of the lleaver Valley Power Station. Those units are now in senice. Tlicy pise b. hC('lf Vf.'

us suf ficient generating capacity to accommodate sales /f7 ppg (jSp(jf7/7[fgf/

"mowth beyond the year 2001 without the need for additional units. reVeilllCS l11 (111 CVer-lllCreclSillX We base resumed promoting electricity sales, but we p()fffjypf[/[pg /JJgf r/(g/,

are doing so in ways consistent uith national energy objectises. We are promoting the use of electricity to sene our customeri comfort and consenience, benelit the environinent and iiiipiove the productisity of businewes u hile reducing their total energy costs.

Despite the slow-growth economy of our area today, there is considerable potential for increased electricity sales. Unlike other forms of energy, electricity can be applied to many industrial and commercial procewes with a flexibility and precision that enhances manufacturing elliciency w hile decreasing total energy requirements. New electrotechnologies also can reduce emiwions from the manufacturing procew, thus lowering our customers' costs of complying with pollution control requinnents.

To increase our sales and. consequently, our resenues. we are implementing a broad range of new marketing programs which include special communications, direct contact and customer e

6

incentises. We especially are targeting specific markets w hich represent the potential for annual revenue increases in the tens of millions of dollars. For example:

• lilectric process heating for use in the automotive, fabricated metals and nonmetals industries.

Specific applications include infrared process heating, induction heating and resistance heating.

• lilectrical equipment for food service applications.

• Electric baseboard heating, add-on heat pumps, new appliances and portable space heaters in the residential market.

• Use of geothermal heat pumps in new home construction.

Through a new program called i n ,or trn e

1. "" " ' U

.t/,a r a i / /, /,o ldIgCICd 200 kndnklria!Cnstomer\,

I. ir, no. r t h e Ms h i ro u 'o < o .v, a r -en - 10 large commercial concerns and a I m m"

• p residential developers that represent Ja,- tic Ilan scu rvan, -~

a substantial share of our revenues.

no- ro e, nt .

n, s. ",a r ucc,4 r  ; We base assigned each of our top as can ton 3 4 management people to serve as a n r en su, n: personal liaison with a corporate ima,n a officer of specific companies. Our um norran m , .

objective is to build a rapport with these customers. Then we can better help them in their efforts to remain productive and profitable while, at the same time, discovering new opportunities for kilowatt-hour sales. Customer Focus 2(HK) was pioneered in the Toledo Edison area in 1993, with good results. We gained greater understanding of the needs of nearly l(H) major customers, and 209i of our contacts resulted in sales leads.

In addition to sales promotions, we employ creatise new uses for existing assets and resources to add to annual earnings. As one .xample, we are pursuing partnerships with customers and independent power producers to put underutilized or mothballed generating units to work. As another source of new resenues, we will be marketing our services to local municipalities, water authorities and private entities In nehange for a fee, we could carry out their meter readings, billing, telephone services, order processing and credit work.

We also are combining revenue-growth strategies with increased promotion of economic deselopment. As one incentise, we return to industrial customeis a portion of their electricity payments to be apphed to capital investments or other expansion in our service area. In 1993, this plan helped encomage $325 million of capital imestments. creating or retaining nearly 3,tXX) l l

101.\l. RINI.Nl M pa s .' i un ,.

)  !!

~

su v3 ei ot .i yn Hillion s h

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jobs and more than 57 million in annual retenues for us. For example, the Chrysler Corporation receised this incentive for starting up production of Dodge Dakota trucks in its Toledo Assembly Plant.

As we work to increase electricity sales, we also are working to retain our customer base.

We base negotiated sole-supplier contracts coseting 759 of Toledo Edison's industrial sales and 50G of Cleveland filectric's industrial sales. We have achieved major successes in stabilizing municipali/ation actisity. In 1993, we negotiated a new franchise agreement with the City of Toledo and reached an accord with the Cleseland suburb of Brook Park to help prevent creation of municipal electric systems in those connuunities. Officials in two other cities we serve decided not to proceed at this time with municipali/ation activities after they examined the risks.

Cleseland Public Power continues its expansion into areas of Cleveland we now serve CPP's first phase of expansion has converted about 8JXX) customers to date. At risk are an estimated 35JHN) additional customers oser the 1994-1996 period. The number is significant, but these customers represent only about 39 of our total and less than 1.59 of our revenues. The municipal system plans a second phase of expansion to pursue more of our customers starting in 1997.

Plans are incomplete and the potential impact on us is not yet known.

To retain our industrial and conuncreial customers in Cleseland, we are marketing a package of incentises u hich includes energy-efliciency improvements and reductions in demand charges for increased electricity use. These incentises are offered in return for sole-supplier agreements with us, generally ranging from three to live years. Thus far, approximately 75% of the customers w ho base made their decisions have elected to stay with us.

AS A lilGil COST liNiiRGY SUPPLlliR IN A newiy compeiiiise inaustry. we recognize the need to become know n for correspondingly hich quality

'C U S T O M:E R S AT I S F A C T I O N

~ -

service. As part of our strategic action plan, we w:ill continuously measure, analy/e and work to increase customer satisfaction with our service.

Good sersice has many interpretations to our customers. It may be the line mechanic atop a utility pole restoring service after a thunderstorm. It might be the friendly voice answering a customer's telephone call. It may even be the heroic meter reader who crawls into a burning house and carries two children to safety, as occurred in the Cleveland area this past autumn.

We are only as good as our customers think ue are.

Each year we retain a pubb.e opmioa research h.rm to Objective: ,

I conduct in-depth surveys of a representative sample of NOfSe OUT CHS[OMef )

our customers. We measure results against past surveys jpppgh/((f y r[jf[77gi and against 70 other utilities nationwide. Our overall l tavorability rat.mg m 1993 was 664. This represents 10 the' 100 c'llarler I

I 1

considerable improsement from the low of 459 recorded Of,OllT //l([llSifY, I in 1989. Ilowever, we still are three percentage points (

under the 69% aserage of all 70 utilities. This puts us in the bottom half. We intend to be in the top quarter before the end of 2001.

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To further measure our success in meeting customer expectations, we send follow-up questionnaires to a small sample of customers each month to measure their satisfaction with j specine services rendered, such as new electrical installations. Another valuable source of feedback is provided by our three Consumer Advisory Panels who assist us in developing customer communications and new service options. We are developing other means to guide our etiorts to enhance customer satisfaction. l Our action plan includes specific goals to improve basic services affecting customer satisfaction.

We intend to reduce customer call-waiting time and the frequency of power interruptions. We also will accelerate service restoration, the replacement of burned-out street lamps and new I residential and commercial installations. In many of these categories, our response time already l is above average for the electric utility industry. Our goal is to achieve significant improvement in 1994 and to rank in the top 107c of the industry in all categories by 2001.

Our customer responsiveness was severely tested in 1993. A devastating thunderstorm on July 28 disrupted electric service to some 360,000 Cleveland Electric customers, about half of that company's total number of customers. Our service crews, operations personnel and telephone representatives reacted superbly. Service was restored to 97% of the affected customers within four days. Ilowever, our greatest disappointment in this emergency was our inability to provide customers with accurate estimates as to w hen their power might be restored. We are implementing procedural improvements to deal with this.

Among other service improvements in 1993, we activated our new Horizon Substation to improve reliability in downtown Cleveland and to serve the new Gateway sports complex.

We also set up a new communications system allowing customers with touch-tone phones to automatically access their account information and to report power outages. In addition. we established a national computer link so that most new service applications can be processed by phone rather than requiring an in-person visit by the customer. In 1994, we will test automated )

meter reading on a pilot basis for possible system-wide phase-in over a five-year period. This I would enhance our billing accuracy while reducing our meter-reading costs.

We continue to provide the energy-efficiency programs that give customers more control over their energy usage and costs. These programs include energy-efficiency rate incentives, conservation initiatives, load controls, energy information and other measures to benefit customers. In some instances, these programs might mean a modest reduction in our revenues.

Nevertheless, they are essential to good customer service and enhanced customer satisfaction.

Equally important, they help our commercial and industrial customers reduce costs and retain their competitiveness ir national and global markets. Ultimately, this improves our own sales and revenue prospects for the long-term benefit of share owners.

CUSTOMER FAVORAllllJIY RATING 80 bo 40

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n o su so '91 92 '91 Pctrent h

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livliN IN Tills liR A OF lilGil TliCilNOI.OGY.

employees remain our single most important resource in serving customers and maximi,ing iniai return in EMPL0YEES share ow ners. We recognize that the primary criteria for success is not the number of employees but rather j their skills, personal desclopment and commitment. Management's task is to proside the i training. leadership and cultural emironment to support employee efforts.

l As a result of the workforce reduction in 1993 and earlier downsi/ings, we base cut our total  ;

number of employees f rom 9.062 at year-end 1989 to 6,748 at year-end 1993. In that time, upper I u.anagement was reduced f rom 85 to 50. Responsibilities base been broadened and some I esecutises are being challenged with entirely new . .

responsibilities. Our reduced numbers are consistent with /UCllUCI other utilities w hich also hase been downsizing their M////)(([\' C////)[()\'CC staffs to control costs. .

jgj g gjg Meanwhile we are stressing accountability. As we have lll CIIf/NlNIIO streamlined management. so hase we reduced direct ()[)/CC((PCS, supen ision. We are empowering employees to handle greater responsibilities and make more decisions. We also are developing training programs and incentives to encourage escry employee to be part of our sales team.

To prepare them for their expanded roles, we are establishing cross-functional teams of employees to identify and address key corporate issues. No one know s the workings of our business better than our employees; they are in the best position to propose solutions to problems and new way s to increase etliciency and reduce costs. Management gives their siew s full attention.

Consistent with our expectations of employees, we are developing a total compensation strategy that prosides cost-elfective and appropriate rewards. The key to this strategy is incentise pay to rewaid employ ees based on the achiesement of corporate objectises.

Today's workforce is more diserse than any we have had in the past. Our employees are much more challenged than their predecessors. The past few years base been characteri/ed by rapid change. uncertainty and increasing demands. Nevertheless, our employees have maintained their dedication to the job. concern for customers and loyalty to the Company and its mission. With their continuing commitment, we are confident we can successfully achieve the objectises of our strategic action plan.

EMPLt WIJ 5 ( Year 1-inJ H

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~" VARI ABl.l? POWiiR SUPPIN COSTS INCI.UDli fuel expenses and operation and maintenance expenses P. O W E R S U P P L Y ror our generating units, as opposed to the nxed costs resulting from construction. Our strategic action plan calls upon us to reduce our variable power supply costs on a three-year rolling average from the 1993 level of 2.5 cents per kilowatt-hour to 2.2 cents by the end of 1998. We then will limit subsequent increases so that they do not exceed 2.3 cents per kilowatt-hour at year-end 2001, Ily reducing our production costs per kilowatt-hour, we become more coropetitive in our ow n service area and in the wholesale energy market. This will become increasi.igly important as deregulation provides new opportuni ies for independent Of)/fCll PC.' power producers and encourages more wholesale Re(litce v(iii(t/>le wheeling of power and, possibly, retail wheeling beyond j){)) Vel' SIll)))lY ,

C()S/S [() (/ //l()/'C We will achieve our cost-reduction goal by improving plant irrfonnance and reducing outage times. These will C()/11l)C///lFC /CPF/. be achieved through efliciency-enhancement projects and improved maintenance and scheduling. We also will use technological upgrades and experimentation when appropriate:

• In 1993, for example, we completely computerited the control room of a 132 megawatt unit at our Eastlake Plant, which greatly improved the unit's operations.

• This year, we are experimenting with a process called oxygenated boiler-water treatment to protect against boiler tube corrosion, thus reducing maintenance needs.

The cost reduction goal will also be achieved by lowering fuel costs, which are a little more than half of our variable power supply costs. We expect the unit cost of our nuclear fuel to decline 33% by the end of 2001. We have used most of our inventory of higher-priced uranium fuel and can now take advantage of the lower-cost fuel purchased more recently. Our coal costs per ton are expected to come down 15% by the end of 1995 because of the lower cost purchases we are able to make on the spot market.

'lypically, about 40% of our generating output comes from our three nuclear units. The longest-running of the three is the Davis Besse Nuclear Power Station, which continued its fine level of performance in 1993. Davis-llesse received its highest marks ever from the Nuclear Regulatory Commission in its most recent Systematic Assessment of Licensee Perfonnance. Also continuing IHOI)lrlloN COSIS 4

i I

n 29 m at n? vt Cents l*cr Kilowatt-flour I Threchar Rolling Average)

_ _=_______ _ _ _ . _.._ _ _ _ ___ _ _ _ _...__.._._ __ _ . _ . .

abose-average operations is Beaver Valley Unit 2 in which we share ownership. At year-end 1993, the three-year availability aserage of each unit was 87(i. Those marks are well abose the industry aserace of 784 for prewurized water reactors. -

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s llol stra:m..n The 1993 performance of our third - N I*d +

nuclear generating facility, Perry nm,I lhas % l tan.

Unit I, fell below espectations, g f. .s_, g t ,.

bringing down Perry's three-y ear is F/ l'rmA u L lou asailability aserace to 674. 'Ihis falls short of the 724 industry aserage for boiling water icactors. g K Perry experienced a series 01 x .

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maintenance problems last year, l

sharply increasing its downtime. , . . I a ,

1 l

We are working to turn the plant around. The Perry manacement team is now headed by some of the key people who saw Davis-Bewe through a $200 million improsement program in the mid-1980s with outstanding results. We base embarked on a two- l year,in-depth course of action at Perry w hich includes more aggressive maintenance, improved )

quality awewment and heightened management involvement at all lesels. Our cost is estimated l to tu $33 million. The Nuclear Regulatory Commission has concuned that successful implementation of this course of action will achiese our objectises for Perry.

Our emironmental engineering efforts over the years have placed us ahead of many other utilities in reducing sultur dioxide emiwions from fowil-fueled units as required by the Clean Air Act. More than two-thirds of our generation is already in compliance with existing law or is not affected by the legislation. We will bring the remaining third into compliance by the time required primarily by switching to lower-sulfur fuels. The necessary expenditures will hase no ,

I material effect on our electric rates.

Many other coal-reliant utilities in our region face much higher emironmental protection costs. i I

,\s a result, their electric rates oser the next sescral years will increase by a greater margin than ours. This uill bring us closer to rate parity, making us more competitise in our region.

We are about to begin a two-year, $30 million upgrade of our System Operations Center located near Cleveland. The Center coordinates the generation and transmission of bulk power throughout our system. This upgrade will ensure the availability of power for our ow n customers u hile making it easier for us to inarket oar electricity in other regions.

Power production is the heart of our business. As w e continue improving our operating efficiencies and reducing costs. we will be that much further along in making the succewful transition to being a more market-drisen business and in improving total return to share owners.

O

M A N AG EM ENT'S our Board of Directors i5 re5Ponsible for determinins whether management and the independent public ac-STATEM ENT OF countants are carrying out their responsibilities. The R E S P O N S 113 i L lT Y FO R noard is also responsible for making changes in manage-FIN ANC1 A L STATEM ENTS ment or independent public accountants if needed.

l The Board has appointed an Audit Committee, comprised l The management of Centerior Energy Lorporation is entirely of outside directors, which met two times in l responsible for the consolidated financial statements in 1993. The Committee recommends annually to the this Annual Report. The statements were prepared in lloard the firm of independent public accountants to be accordance with generally accepted accounting principles.

retained for the ensuing year and reviews the audit ap.

Under these principles, some of the recorded amounts proach used by the accountants plus the results of their are based on estimates which are,in turn, based on an audits. it also oversees the adequacy and clTectiveness analysis of the best information available, of our internal accounting controls and ensures that our We maintain a system of internal accounting controls accounting system produces financial statements which designed to assure that the financial records are substan, present fairly our financial position.

tially complete and accurate. The controls also are de- C k.

signed to help protect the assets and their related records. /

We structure our control procedures such that their costs '

do not exceed their benefits. GARY R. LEIDICil Our internal audit program monitors the internal account. Vice President and ing controls. This program gives us the opportunity to Chief financial Oficer assess the adequacy and elTectiveness of existing controls and to identify and institute changes where needed. In addition, an examination of our financial statements is

[

conducted by Arthur Andersen & Co., independent public PAUL G. BUSILY accountants, whose report appears below.

C"""N#f ""d Chief Accounting Oficer 11 E P O ItT O F disciosures in the financial statements. An audit also INDEPENDENT i""d" """. sing the munting principles used and sigmficant estimates made by management, as well as P U 13 L I C A C C O U N T A N T S evaluating the overali financial statemeni presentation.

We believe that our audits provide a reasonable basis for To the Share Owners and ARTHUR "' P'"i "'

Board of Directors or ANDERSEN In our opinion, the financial statements referred to above Centerior Energy Corporat. ion: .

present fairly, .in all material respects, the f.inancial pos.i.

We have audited the accompanying consolidated balance tion of Centerior Energy Corporation and subsidiaries as sheet and consolidated statement of preferred stock of of December 31,1993 and 1992, and the results of their Centerior Energy Corporation (an Ohio corporation) and operations and their cash 110ws for each of the three subsidiaries as of December 31,1993 and 1992, and the years in the period ended December 31 1993, in con-related consolidated statements of income, retained earn- formity with generally accepted accounting principles.

l I ings and casn flows for each of the three years in the As discussed further in Notes I and 9, changes were made period ended December 31,1993. These financial state-in the methods of accounting for nuclear plant deprecia-ments are the responsibility of the Company's manage-tion in 1991 and for postretirement benefits other than i ment. Our responsibility is to express an opinion on these pensions in 1993, i

financial statements based on our audits.

1 We conducted our audits in accordance with generally accepted auditing standards. Those standards require that g we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, Cleveland, Ohio on a test basis, evidence supporting the amounts and February 14,1994 l Gt -

1

M AN AG E M ENT'S ment and postemployment benefits. Dererred operating expenses decreased because of the write-off of the phase-FIN A.NCI AL AN ALYSIS in deferred operating expenses in 1993 as discussed in

. Note 7. Federal income taxes decreased as a result of '

Results of Operations lower pretax operating income.

l 1993 vs.1992 As discussed in Note 4(b), $583 million of our Perry Factors contributing to the 1.5% increase in 1993 operat- Nuclear Power Plant Unit 2 (Perry Unit 2) investment ing revenues are as follows: was written oft in 1993. Credits for carrying charges Minions recorded in nonoperating income decreased because of increase t Decrease) in oneratine Revenues or Dollan the write-off of the phase-in deferred carrying charges in Sales Volume and Mix $ 65 1993 as discussed in Note 7. The federal income tax

"" " 5 "j'g""d, ,

cre t for nonoperating income in 1993 resulted from the Total Q

The net revenue increase resulted primarily from the 1992 is. 1991 different weather conditions and the changes in the com-Factors contributing to the 4.8% decrease in 1992 operat-position of the sales mix among customer categories.

ing revenues are as follows:

Weather accounted for approximately $53 million of the higher 1993 revenues. Hot summer weather in 1993 Decrease in Operatine Revenues of Dollars boosted residential, commercial and wholesale kilowatt- Sales Volume and Mn $ 79 j hour sales. In contrast, the 1992 summer was the coolest flase Rates and Miscellaneous 32 I in 56 years in Northern Ohio. Residential and commer. ruel Cost Recovery Revenues _ 11 cial sales also increased as a result of colder late-winter Total M temperatures in 1993 which increased electric heating-related demand. As a result, total sales increased 3.1% in The revenue decreases resulted primarily from the difTer- l 1993. Residential and commercial sales increased 4.6% ent weather conditions and the changes in the composi-and 3.1%, respectively. Industrial sales increased 1.2% tion of the sales mix among customer categories.

Increased sales to large automotive manufacturers, petro- Weather accounted for approximately $77 million of the leum refiners and the broad-based, smaller industrial lower 1992 revenues. Winter and spring in 1992 were group were partially ofTset by lower sales to large steel milder than in 1991. In addition, the cooler summer in industry customers. Other sales increased 5.9% because of 1992 contrasted with the summer of 1991 which was increased sales to wholesale customers. Base rates and much hotter than normal. As a result, total kilowatt-hour miscellaneous revenues decreased in 1993 primarily from sales decreased 1.1% in 1992. Residential and commer-lower revenues under contracts having reduced rates cial sales decreased 4.5% and 1.3%, respectively, as with certain large customers and a declining rate structure moderate temperatures in 1992 reduced electric heating tied to usage. The contracts have been negotiated to and cooling demands. Industrial sales were virtually the meet competition and encourage economic growth. The same as in 1991 as sales increases to steel producers and net decrease in 1993 fuel cost recovery revenues resulted auto manufacturers of 10.9% and 2.7%, respectively, from changes in the fuel cost factors. The weighted offset a decline in sales to other industrial customers, average of these factors increased slightly for The Toledo Other sales increased 2.3% because of increased sales to Edison Company (Toledo Edison) but decreased 5% for wholesale customers. Operating revenues in 1991 in-The Cleveland Electric illuminating Company (Cleve- cluded the recognition by Toledo Edison of $24 million land Electric). of deferred revenues over the period of a refund to

. . . customers under a provision of its January 1989 rate Operatmg expenses increased 13.7% .in 1993. The increase order. No such revenues were reflected in 1992 as the m total operation and mamtenance expenses resulted refund period ended in December 1991. The decrease in from the $218 milhon of net benefit expenses related t 1992 fuel cost recovery revenues resulted from the good an early retirement program, called the Voluntary Tran-performance of our generating units, which in turn sition Program (VTP), other charges totaling $54 milhon decreased our fuel cost factors. The weighted averages and an increase in other operation and maintenance of these factors decreased approximately 3% for Cleve-expenses. Other charges recorded at year-end 1993 re-land Electric and Toledo Edison (Operating Companies).

lated to a performance improvement plan for Perry Nuclear Power Plant Unit 1 (Perry Unit 1), postemploy- Operating expenses decreased 4% in 1992. Lower fuel and ment benefits and other expense accruals. The increase purchased power expense resulted from less amortization in other operation and maintenance expenses resulted of previously deferred fuel costs than the amount amor- l from higher emironmental expenses, power restoration tized in 1991 and lower generation requirements stem- l and repair expenses following a July 1993 storm in the ming from less electric sales. A reduction of $17 million l Cleveland area, and an increase in other postretirement in other operation and maintenance expenses resulted benefit expenses. See Note 9 for information on retire- primarily from cost-cutting measures. Federal income D

taxes decreased because of the amortization of certain tax achieve these objectives, we will continue controlling our benefits under the Rate Stabilization Program discussed operation and maintenance expenses and capital expendi-in Note 7 and the effects of adopting the new accounting tures, reduce our outstanding debt, increase revenues by standard for income taxes (SFAS 109) in 1992. These finding new uses for existing assets and resources, im-decrease., were partially offset by higher depreciation plement a broad range of new marketing programs,in-and amortization, caused primarily by the adoption of crease revenues by restructuring rates for various SFAS 109, and by higher taxes, other than federalincome customers where appropriate, improve the operating per-taxes, caused by increased Ohio property and gross formance of our plants and take other appropriate receipts taxes. Deferred operating expenses increased as a actions.

result of the deferrals under the Rate Stabilization Program. Common Stock Dividends ,

The federalincome tax provision for nonoperating income The indicated quarterly common stock dividend is $.20 decreased because of lower carrying charge credits and a per share. We believe that the new level is sustainable greater tax allocation ofinterest charges to nonoperating barring unforeseen circumstances and that the new strate-activities. Credits for carrying charges recorded in non- gic plan will provide the opportunity to grow the divi-operating income decreased primarily because oflower dend as the objectives are achieved. Nevertheless, future phase-in carrying charge credits. Interest charges de- dividend action by our Board of Directors will continue creased as a result of debt refinancings at lower interest to be decided on a quarter-to-quarter basis after the rates and lower short-term borrowing requirements. evaluation of financial results, potential earning capacity and cash flow.

Outlook The lower dividend reduces our cash outflow by about Recent Actions $120 million annually, which we intend to use to repay debt more quickly than would otherwise be the case. This In January 1994, we announced a comprehensive strate- w 11 help improve our capitalization structure and interest gic action plan to strengthen our financial and competi- coverage ratios, both of which are key measures consid-tive position. The plan established specific objectives cred by securities rating agencies in determining credit and was designed to guide us through the year 2001. ratings. Improved credit ratings and less outstanding While the plan has a long-term focus,it also required us debt, in turn, will lower our interest costs.

to take some very difficult, but necessary, financial ac-tions at that time. We reduced the quarterly common stock dividend from S.40 per share to $.20 per share Ceih effective with the dividend payable February 15,1994 Our electric rates are among the highest in our region This action was taken because projected financial results because we are recovering the substantial investment in did not support continuation of the dividend at its former our nuclear construction program. Accordingly, some of rate.- We also wrote off our investment in Perry Unit 2 our customers continue to seek less costly alternatives, and certain deferred charges related to a January 1989 including switching to or working to create a municipal rate agreement (phase-in deferrals). The aggregate af- electric system. There are a number of rural and munici-ter-tax effect of these write-offs was $1.023 billion . pal systems in our service area. In addition, we face which resulted in a net loss in 1993 and a retained threats of other municipalities in our service area estab-earnings deficit. The write-offs are discussed in Notes lishing new systems and the expansion of an existing 4(b) and 7. We also recognized other one-time charges system. We have entered into agreements with some of totaling $39 million after taxes related to a performance the communities which considered establishing systems.

improvement plan for Perry Unit 1, postemployment Accordingly, they will not proceed #h such develop-benefits and other expense accruals. ment at this time in return for rate concessions and/or ec n m e development funds. Others have determined Also contributing to the net loss in 1993 was a charge of that developing a system was not feasible. Cleveland

$87 million after taxes representing a portion of the VTP Public Power continues to expand its operations mto areas costs. We will realize approximately $50 million of

• • ve served exclusively. We have been successful m

! savings in annual payroll and benefit costs beginning in 1994 as a result of the VTP.

re tau.'".ung most d th large indusMal and comm customers m those areas by providing economic incentive packages in exchange for sole-supplier contracts. We Strategic Plan also have similar contracts with customers in other areas.

The objectives of our strategic plan are to maximize share Most of these contracts have remaining terms of one to owner return from corporate assets and resources, five years. We will continue to address municipal system achieve profitable revenue growth, become an industry threats through aggressive marketing programs and em-leader in customer satisfaction, build a winning team and phasizing to cur customers the value of our service and j attain increasingly competitive power supply costs. To the risks of a municipal system.

I l j

l 1

The Energy Policy Act of 1992 (Energy Act) will provide We externally fund the estimated costs for the future I additional competition in the electric utility industry by decommissioning of our nuclear units. In 1993, we in- l requiring utilities to wheel to municipal systems in their creased our decommissioning expense accruals for revi- i service areas electricity from other utilities. This provi- sions in our cost estimates. We expect the increases sion of the Energy Act should not significantly increase associated with the new estimates will be recoverable in the competitive threat to us since the operating licenses future rates. See Note 1(c).

for our nuclear units have required us to wheel to munici-pal systems in our service area since 1977. The Energy llazardous Waste Disposal Sites Act also created a class of exempt w holesale generators which may increase competition in the wholesale power The Comprehensive Environmental Response, Compen-market. A further risk is the possibility that the govern. sation and Liability Act of 1980 as amended ment could mandate that utilities deliver power from (Superfund) established programs addressing the cleanup another utility or generation source to their retail of hazardous waste disposal sites, emergency prepared-customers. ness and other issues. The Operating Companies have been named as "potentially responsible parties" (PRPs) f r three sites listed on the Superfund National Priorities Rate Matters List (Superfund List) and are aware of their potential  ;

Our Rate Stabilization Program remains in effect. Under involvement in the cleanup of several other sites not on  !

this program, we agreed to freeze base rates until 1996 such list. The allegations that tb.- Operating Companies I and limit rate increases through 1998. In exchange, we disposed of hazardous waste at t:iese sites and the l are permitted to defer through 1995 and subsequently amounts involved are often unsubstantiated and subject to 1 recover certain costs not currently recovered in rates and dispute. Superfund provides that all PRPs to a particular to accelerate the amortization of certain benefits. The site can be held liable on a joint and several basis.

amortization and recovery of the deferrals will begin with Consequently, if the Operating Companies were held future rate recognition and will continue over the aver- liable for 100% of the cleanup costs of all of the sites age life of the related assets, or approximately 30 years. referred to above, the cost could be as high as $400 The continued use of these regulatory accounting mea- million. Ilowever, we believe that the actual cleanup costs sures will be depenJent upon our continuing assessment will be substantially lower than $400 million, that the and conclusion that there will be probable recovery of Operating Companies' share of any cleanup costs will be such deferrals in future rates. substantially less than 100% and that most of the other PRPs are financially able to contribute their share. The Our analys.is leading to the year-end 1993 financ.ia l ac- Operating Companies have accrued a liability totaling $19 tions and strategic plan also included an evaluation of our million at December 31,1993 based on estimates of the regulatory accountmg measures. We decided that, once costs of cleanup and their proportionate responsibility the deferral of expenses and acceleration of benefits for such costs. We believe that the ultimate outcome of under our Rate Stabilization Program are completed .in these matters will not have a material adverse elTect on 1995, we should no longer plan to use regulatory account- our financial condition or results of operations.

ing measures to the extent we have m the past.

1993 Tr.x Act Nuclear Operat. ions

. The Revenue Reconciliation Act of 1993 (1993 Tax Our three nuclear units may be . impacted by activities or Act), which was enacted in August 1993, provided for a events beyond our control. Operating nuclear generating 35% income tax rate in 1993. The 1993 Tax Act did not units have experienced unplanned outages or extensions materially impact the results of operations for 1993, but of scheduled outages because of equipment problems or did affect certain Balance Sheet accounts as discussed in new regulatory requirements. A major accident at a Note 8. The 1993 Tax Act is not expected to materially nuclear facility anywhere m the world could cause the impact future results of operations or cash flow.

Nuclear Regulatory Commission (NRC) to limit or pro-hibit the operation or licensing of any nuclear unit. If one InHadon of our nuclear units is taken out of service for an extended period of time for any reason, including an Although the rate of inflation has cased in recent years, accident at such unit or any other nuclear facility, we we are still affected by even modest inflation which causes cannot predict whether regulatory authorities would im- increases in the unit cost oflabor, materials and services.

pose unfavorable rate treatment. Such treatment could include taking our affected unit out of rate base or . .

disallowing certain construction or maintenance costs. An Cap. ital Resources and Liquidity extendeu outage of one of our nuclear units coupled with 1991-1993 Cash Requirements unfavorable rate treatment could have a material ad-verse elTect on our tirancial condition and results of We need cash for normal corporate operations, the operations. mandatory retirement of securities and an ongoing pro-O

a- _ u,s -

gram of constructing new facilities and modifyi ng existing As discussed in Note 11(e), certain unsecured debt facilities. The construction program is needed to meet agreements contain covenants relating to capitalization, anticipated demand for electric service, comply with fixed charge coverage ratios and secured financings. The governmental regulations and protect the environment. write-offs recorded at December 31, 1993 caused Over the three-year period of 1991-1993, these construc- Centerior Energy Corporation (Centerior Energy) and tion and mandatory retirement needs totaled approxi- the Operating Companies to violate certain of those mately $1.4 billion. In addition, we exercised various covenants. The afTected creditors have waived those viola-options to redeem and purchase approximately $900 mil- tions in exchange for our commitment to provide them lion of our securities. with a second mortgage security interest on our property nd other considerations. We expect to complete this We raised $2.2 billion through security issues and term pr cess m the second quarter of 1994. We will provide the bank loans during the 1991-1993 period as shown in the s me secunty mterest to certain other creditors because Cash Flows statement. During the three-year period, I '. agreements require equal treatment. We expect to the Operating Companies also utilized their short-term pr vide second mortgage collateral for $219 milhon of borrowing arrangements to help meet their cash needs.

unsecured debt, $228 milhon of bank letters of credit and Although the write-offs of Perry Unit 2 and the phase-in a $205 million revolving credit facility. For the next five deferrals in 1993 negatively affected our earnings, they years, the Operating Companies do not expect to raise did not adversely afTect our current cash flow. funds through the sale of debt junior to first mortgage bonds. However, if necessary or desirable, the Operating Companies believe that they could raise funds through 1994 and Beyond Cash Requirements the sale of unsecured debt or debt secured by the second Estimated cash requirements for 1994-1998 for Cleveland mortgage referred to above. The Opera:ing Companies Electric and Toledo Edison, respectively, are $791 mil- also are able to raise funds through the sale of preference lion and $249 million for their construction programs and stock and,in the case of Cleveland Electric, preferred

$715 million and $324 million for the mandatory re- stock. Toledo Edison will be unable to issue preferred demption of debt and preferred stock. Cleveland Electric stock untilit can meet the interest and preferred dividend and Toledo Edison expect to finance internally all of their coverage test in its articles of incorporation. Centerior 1994 cash requirements of approximately $239 million Energy will continue to raise funds through the sale of and $109 million, respectively. About 15-20% of the common stock.

Operating Companies' 1995-1998 requirements are ex-The Operating Companies currently cannot sell commer-pected to be financed externally. If economical, additional cial paper because of their low commercial paper ratings securities may be redeemed under optional redemption by Standard & Poor's Corporation (S&P) and Moody's provisions.

Investors Service, Inc. (Moody's) of "B" and "Not Our capital requirements are dependent upon our imple- Prime", respectively. We have a $205 million revolving mentation strategy to achieve compliance with the Clean credit facility which will run through mid-1996. However, Air Act Amendments of 1990 (Clean Air Act). Cash we currently cannot draw on this facility because the expenditures for our plan are estimated to be approxi- write-ofTs taken at year-end 1993 caused us to fail to mately $128 million over the 1994-1998 period. See Note meet certain capitalization and fixed charge coverage 4(a). covenants. We expect to have this facility available to us again after it is amended in the second quarter of 1994 to provide the participating creditors with a second mort-1;,qu,dity i

gage security interest.

Additional first mortgage bonds may be issued by the These financing resources are expected to be suflicient for l Operating Companies under their respective mortgages the Operating Companies' needs over the next several j on the basis of property additions, cash or refundable first years. The availability and cost of capital to meet our mortgage bonds. Under their respective mortgages, each external fmancing needs, however, also depend upon such Operating Company may issue first mortgage bonds on factors as financial market conditions and our credit the basis of property additions and, under certain circum- ratings. Current credit ratings for both Operating Com-stances, refundable bonds only if the applicable interest panies are as follows:

coverage test is met. At December 31,1993, Cleveland Electric and Toledo Edison would have been permitted to MP M #$

First mortgage bonds BB Ba2 issue approximately $78 million and $323 million of additional first mortgage bonds, respectively. After the *[ d fourth quarter of 1994, Cleveland Electric's ability to issue first mortgage bonds is expected to increase substan- These ratings reflect a downgrade in December 1993. In tially when its interest coverage ratio will no longer be addition, S&P has issued a negative outlook for the affected by the write-offs recorded at December 31,1993. Operating Companies.

l O

INCOME STATEMENT caneccior tnerzr corporazion ans sussisiaries For the years ended December 31.

1993 1992 1991 (millions of dollars, except per share amounts)

Operating Revenues 12.474 $2.438 $2.560 Operating Expenses l Fuel and purchased power 474 473 500 j Other operation and maintenance 811 784 801 i Early retirement program expenses and other __2_71 - -

Total operation and maintenance 1,557 1,257 1,301 Depreciation and amortization 258 256 243 Taxes, other than federal income taxes 312 318 305 Deferred operating expenses, net 23 (52) (6)

Federal income taxes 11 122 138

_2dhi 1.901 1.981 Operating income 313 537 579 Nonoperating income (Loss)

Allowance for equity funds used during construction 5 2 9 Other income and deductions, net (6) 9 6 Write-oft of Perry Unit 2 (583) - -

Deferred carrying charges, net (649) 100 110 Federal income taxes - credit (expense) 398 (7) (3.0)

(835) 104 95 income (Loss) Before Interest Charges and Preferred Dividends (522) 64l 674 Interest Charges and Preferred Dividends Debt interest 359 365 381 Allowance for borrowed funds used during construction (5) (1) (5)

Preferred dividend requirements of subsidiaries 67 65 61 421 429 437 Net Income (Loss) $ (943) $ 212 $ 237 Average Number of Common Shares outstanding (millions) 144.9 141.7 3

_L3_91 Earnings (Loss) Per Common Share $(6.5 l) $ 1.50 $ 1.71 Dividends Declared Per Common Share $160 $_MQ $ 1.60 RETAINED EARNINGS For the years ended December 31.

1993 1992 1991 (millions of dollars) i Reteined Earnings at Beginning of l' ear $ 652 $ 669 $ 655 j Additions Net income (loss) (943) 212 237 Deductions Common stock dividends (231) (226) (222)

Other, primarily preferred stock redemption expenses of subsidiaries (1) (3) (1)

Net increase (Decrease) (1,175) (17) 14 Retained Earnings (Depcit) at End of l' ear $ (523) $ 652 $ 669 The accompanying notes are an integral part of these statements.

O

B AL ANCE SHEET December 31.

1993 1992 (millions of dollars)

ASSETS Property, Plant and Equipment $ 9,571 $ 9,449 Utility plant in service 2.677 2.488 Less: accumulated depreciation and amortization 6,894 6,961 181 167 Construction work in progress - 614 Perry Unit 2 7,075 7,742 344 385 Nuclear fuel, net of amortization Other property, less accumulated depreciation 41 22 7.469 8.166 Current Assets 93 225 Cash and temporary cash investments 222 221 Amounts due from customers and others, net 124 114 Unbilled revenues 136 129 Materials and supplies, at average cost 65 32 Fossil fuel inventory, at average cost 250 247 Taxes applicable to succeeding years 7 5

Other 993 877 Deferred Charge s and Other Assets 975 968 Amounts due from customers for future federal income taxes 105 110 Unamortized loss from Beaver Valley Unit 2 sale 92 101 Unamortized loss on reacquired debt 862 1,533 Carrying charges and operating expenses 42 56 Nuclear plant decommissioning trusts 2(y7 174 Other 2.257 3.028 Total Assets iL0lLO $12.07)

The accompanying notes are an integral part of this statement.

M_ .

Centerior Energy Corporation and Subsidiaries December 31.

1993 1992 (millions of dollars)

CAPITAllZATION AND LIADlLITIES Capitali:ation Common shares, without par value (stated value of $345 million and $274 million for 1993 and 1992, respectively): 180 million authorized; 147 million (excluding 2.7 million shares in Treasury) and 142.9 million (excluding 2.7 million shares in Treasury) outstanding in 1993 and 1992, respectively $ 2,308 $ 2,237 Retained earnings (deficit) (523) 652 Common stock equity 1,785 2,889 Preferred stock With mandatory redemption provisions 313 364 Without mandatory redemption provisions 451 354 Long-term debt 4.019 3.694 6.568 7.30)

Other Noncurrent Liabilities Nuclear fuel lease obligations 254 303 Other 195 119 449 422 Current Liabilities Current portion of long-term debt and preferred stock 127 368 Current portion of nuclear fuel lease obligations 111 118 Notes payable to banks and others -

50 Accounts payable 188 143 Accrued taxes 378 368 Accrued interest 87 84 Other 75 19 966 1.190 Deferred Credits Unamortized investment tax credits 329 353 Accumulated deferred federal income taxes 1,579 2,035 Unamortized gain from Bruce Mansfield Plant sale 551 578 Accumulated deferred rents for Bruce Mansfield Plant and Beaver Valley Unit 2 128 116 Other 140 76 2.727 _ 3.118 Total Capitalization and Liabilities $R7_LO $12.071 O

r CASH FLOWS centerior em ?av corevrarion ans sussisiarias For the years ended December 31.

1993 2

._199_2_ 1991 (millions of dollars)

Cash Flowsfrom Operating Activities (1)

Net income (Loss) $ (943) $ 212 S 237 Adjustments to Reconcile Net income (Loss) to Cash from Operating Activities:

Depreciation and amortization 258 256 243 Deferred federal income taxes (452) 95 85 investment tax credits, net -

(14) 43 Deferred and unbilled revenues (10) (6) (51)

Deferred fuel 5 1 18 Deferred carrying charges, net 649 (100) (110)

Leased nuclear fuel amortization 86 126 123 Deferred operating expenses, net 23 (52) (6)

Allowance for equity funds used during construction (5) (2) (9)

Noncash early retirement program expenses, net 208 - -

Write-olT of Perry Unit 2 583 - -

Changes in amounts due from customers and others, net i 7 14 Changes in inventories 26 (10) (22)

Changes in accounts payable 45 (5) (49)

Changes in working capital affecting operations 25 8 19 Other noncash items 18 3 1 Total Adjustments 1.460 307 299 Net Cash from Operating Activities 517 519 536 Cash Flowsfrom Financing Activities (2)

Bank loans, commercial paper and other short-term debt (50) 50 (110)

Debt issues:

First mortgage bonds 300 600 -

Secured medium-term notes 128 138 285 Term bank loans and other long-term debt 40 135 108 Preferred stock issues 100 74 125 Common stock issues 71 53 32 Reacquired common stock I (3) -

Maturities, redemptions and sinking funds (434) (1,013) (312)

Nuclear fuel lease obligations (106) (117) (116)

Common stock dividends paid (231) (226) (222)

Premiums, discounts and expenses (13) (14) (7)

Net Cash from Financing Activities (194) (323) (217)

Cash Flowsfrom investing Activities (2)

Cash applied to construction (209) (200) (189)

Interest capitalized as allowance for borrowed funds used during construction (5) (1) (5)

Sale and leaseback restructuring fees -

(43) -

l Other cash received (applied) 23 (36) (1)

Net Cash from investing Activities (191) (280) (195)

Net Change in Cash and Temporary Cash Investments 132 (84) 124 Cash and Temporary Cash investments at Beginning of 1' ear 93 177 53 Cash and Temporary Cash investments at End of 1' ear $ 22$ $ 93 $_ 177 (1) Interest paid (net of amounts capitalized) was $295 million, $299 million and $339 million in 1993,1992 and 1991, respectively. Income taxes paid were $50 million, $32 million and $57 million in 1993,1992 and 1991, respectively.

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

The accompanying notes are an integral part of this statement.

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STATEMENT OF PREFERRED STOCK censerior enerar corvorazion ans sussisiaries l Current <

I l 1993 Shares Call Price December 31.

Outstandina Per Share _1191 .L9.92.

CLEl'ELIND ELECTRIC (millions or dollars)

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

! Subject to mandatory redemption:

$ 7.35 Series C 150,000 $ 101.00 $ 15 $ 16  ;

88.00 Series E 21,000 1,022.96 21 24

. Adjustable Series M 200,000 100.00 20 30 l l 9.125 Series N 600,000 103.04 59 74 l l 91.50 Series Q 75,000 -

75 75 i

! 88.00 Series R 50,000 -

50 50 I l 90.00 Series S 75,000 -

74 74 l 314 343 i j Less: Current maturities _ 29 29 l l

285 314 Not subject to mandatory redemption:

$ 7.40 Series A 500,000 101.00 50 50 7.56 Series B 450,000 102.26 45 45 Adjustable Series L 500,000 103.00 49 49 Remarketed Series P - -

9 42.40 Series T 200,000 -

97 -

241 153 Less: Current maturities _.

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1 41 144 TOLEDO EDISON

$100 par value, 3,000,000 preferred shares authorized and $25 par value, 12,000,000 preferred shares authorized Subject to mandatory redemption:  !

$100 par $9.375 100,150 102.47- 10 12 25 par 2.81 1,200,000 25.94 30 50 40 62 Less: Current maturities 12 _{2 28 _ l0 Not subject to mandatory redemption:

$100 par $ 4.25 160,000 104.625 16 16 4.56 50,000 101.00 5 5 4.25 100,000 102.00 10 10 8.32 100,000 102.46 10 10 l 7.76 150,000 102.437 15 15 7.80 150,000 101.65 15 15 10.00 190,000 101.00 19 19 25 par 2.21 1,000,000 25.25 25 25 2.365 1,400,000 27.75 35 35 Series A Adjustable __ 1,200,000 25.75 30 30 Series B Adjustable _ 1,200,000 25.75 30 30 210 210 CENTERIOR ENERGl' Without par value, 5,000,000 preferred shaies authorized, none outstanding - -

Total Preferred Stock, with Afandatory Redemption Provisions $3L3 $%4 Total Preferred Stock, without Afandatory Redemption Provisions $45_I

. $114 The accompanying notes are an integral part of this statement.

O

NOTES TO THE A fuel factor is added to the base rates for electric service.

ms f et r is designed to recova fmm customers the FIN ANCI AL STATEMENTS costs of fuel and most purchased power. It is reviewed nd adjusted semiannually in a PUCO proceeding.

(1) Summary of Significant Accounting Policies (c) Fuei Expense (a) nual The cost of fossil fuel is charged to fuel expense based on Centerior Energy is a holding company with two electric inventory usage. The cost of nuclear fuel, including an utility subsidiaries, Cleveland Electric and Toledo interest component, is charged to fuel expense based on Edison. The consolidated fmancial statements also in- the rate of consumption. Estimated future nuclear fuel clude the accounts of Centerior Energy's other wholly disposal costs are being recovered through the base rates.

l owned subsidiary, Centerior Service Company (Service The Operating Companies defer the difTerences between Company), and Cleveland Electric's wholly owned sub-actual fuel costs and estimated fuel costs currently being sidiaries. The Service Company provides management, recovered from customers through the fuel factor. This financial, administrative, engineering, legal and other ser-vices at cost to Centerior Energy and the Operating matches fuel expenses with fuel related revenues.

I Companies. The Operating Companies operate as sepa- Owners of nuclear generating plants are assessed by the rate companies, each serving the customers in its service federal government for the cost of decontamination and area. The preferred stock, first mortgage bonds and other decommissioning of nuclear enrichment facilities oper-debt obligations of the Operating Companies are out- ated by the United States Department of Energy. The standing securities of the issuing utility. All significant assessments are b'ased upon the amount of enrichment intercompany items have been eliminated in services used in prior years and cannot be imposed for consolidation. more than 15 years. The Operating Companies have Centerior Energy and the Operating Companies follow accrued the liability for their share of the total assess-the Uniform System of Accounts prescribed by the Fed- ments. These costs have been recorded in a deferred eral Energy Regulatory Commission and adopted by The charge account since the PUCO is allowing the Operating Public Utilities Commission of Ohio (PUCO). As rate. Companies to recover the assessments through their fuel regulated utilities, the Operating Companies are subject cost factors.

to Statement of Financial Accounting Standards (SFAS)

(d) Deferred Carrying Charges 71 which governs accounting for the efTects of certain and operating Expenses types of rate regulation. The Service Company follows the Uniform System of Accounts for Mutual Service The PUCO authorized the Operating Companies to defer Companies prescribed by the Securities and Exchange operating expenses and carrying charges for Perry Unit 1 Commission under the Public Utility Holding Company and Beaver Valley Power Station Unit 2 (Beaver Valley Act of 1935. Unit 2) from their respective in-service dates in 1987 The Operating Companies are members of the Central through December 1988. The annual amortization and Area Power Coordination Group (CAPCO). Other recovery of these deferrals, called pre-phase-in deferrals, members are Duquesne Light Company, Ohio Edison are $17 million which began in January 1989 and will Company and its wholly owned subsidiary, Pennsylvania continue over the lives of the related property.

Power Company. The members have constructed and Beginning in January 1989, the Operating Companies operate generation and transmission facilities for their deferred certain operating expenses and both interest and use. equity carrying charges pursuant to PUCO-approved rate phase-in plans for their investments in Perry Unit I and (b) Revenues

. Beaver Valley Unit 2. These deferrals, called phase-in Customers are billed on a monthly cycle bas.is for their deferrals, were wn.t ten oft at December 31,1993. See energy consumption based on rate schedules or contracts Note 7*

authorized by the PUCO or on ordinances of individual municipalities. An accrual is made at the end of each The Operating Companies also defer certain costs not month to record the estimated amount of unbilled reve- currently recovered in rates under a Rate Stabilization  ;

nues for kilowatt-hours sold in the current month but not Program approved by the PUCO in October 1992. See billed by the end of that month. Notes 7 and 14.

D.Jr

(e) Depreciation and Amortization external Nuclear Plant Decommissioning Trusts because the reserve began prior to the external trust funding.

The cost of property, plant and equipment is depreciated over their estimated useful lives on a straight-line basis. (f) Property, Plant and Equipment The annual straight-line depreciation provision for non-nuclear property expressed as a percent of average depre-Pr perty, plant and equipment are stated at original cost 1 ciable utility plant in service was 3.5% in 1993 and 3.4%

less amounts ordered by the PUCO to be written oft.

in both 1992 and 1991. EITective January 1,1991, the Construction costs include related payroll taxes, pen-si ns, fringe benefits, management and general overheads Operating Companies, after obtaining PUCO approval, nd allowance for funds used during construction changed their method of accounting for nuclear plant

( AFUDC). AFUDC represents the estimated composite depreciation from the units-of-production method to the debt and equity cost of funds used to finance construction.

straight-line method at about a 3% rate. This change decreased 1991 depreciation expense $36 million and This noncash aHowance is credited to income. The AFUDC rates averaged 9.9% in 1993,10.8% in 1992 and increased 1991 net income $28 million (net of $8 million ,

of income taxes) and earnings per share $.20 from what 10J% in 1991. l they otherwise would have been. The PUCO subse- Maintenance and repairs are charged to expense as in- j quently approved in 1991 a change to lower the 3% rate to curred. The cost of replacing plant and equipment is j 2.5% retroactive to January 1,1991. charged to the utility plant accounts. The cost of property l Pursuant to a PUCO order, the Operating Companies retired plus removal costs, after deducting any salvage j currently use external funding for the future decommis. value, is charged to the accumulated piovision for  ;

sioning of their nuclear units at the end of their licensed depreciation, operating lives. The estimated costs are based on the NRC's DECON method of decommissioning (prompt (g) Deferred Gain and Loss from Sales of Utility Plant decontamination). Cash contributions are made to the trust funds on a straight-line basis over the remaining The sale and leaseback transactions discusted in Note 2 licensing period for each unit. The current level of annual resulted in a net gain for the sale of the Bruce Mansfield expense being recovered from customers based on prior Generating Plant (Mansfield Plant) and a net loss for the estimates is approximately $8 million. However, actual sale of Beaver Valley Unit 2. The net gain and net loss decommissioning costs are expected to significantly were deferred and are being amortized over the terms of exceed those estimates. Current site-specific estimates for leases. These amortizations and the lease expense the Operating Companies' share of the future decom- amounts are recorded as other operation and maintenance missioning costs are $92 million in 1992 dollars for expenses.

Beaver Valley Unit 2 and $223 million and $300 million in 1993 dollars for Perry Unit I and the Davis-Besse (h) Interest Charges Nuclear Power Station (Davis-Besse), respectively. The Debt Interest reported in the Income Statement does not estimates for Perry Unit I and Davis-Besse are prelimi- include interest on obligations for nuclear fuel under nary and are expected to be finalized by the end of the construction. That interest is capitalized. See Note 6.

second quarter of 1994. The Operating Companies used these estimates to increase their decommissioning ex- Losses and gains realized upon the reacquisition or re-pense accruab in 1993. It is expected that the increases demption of long-term debt are deferred, consistent with associated with the revised cost estimates will be recover- the regulatory rate treatment. Such losses and gains are able in future rates. In the Balance Sheet at December either amortized over the remainder of the original life l 31, 1993, Accumulated Depreciation and Amortization of the debt issue retired or amortized over the life of the included $74 million of decommissioning costs previ- new debt issue when the proceeds of a new issue are ously expensed and the earnings on the external funding. used for the debt redemption. The amortizations are This amount exceeds the Balance Sheet amount of the included in debt interest expense. l i

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(i) Federal Income Taxes improvements to the units. The Operating Companies The Financial Accounting Standards Board (FASB) is. have options to buy the interests back at the end of the sued SFAS 109, a new standard for accounting for leases for the fair market value at that time or to renew income taxes, in February 1992. We adopted the new the leases. Additional lease provisions provide other standard in 1992. The standard amended certain provi. purchase options along with conditions for mandatory sions of SFAS 96 which we had previously adopted. termination of the leases (and possible repurchase of the Adoption of SFAS 109 in 1992 did not materially afTect leasehold interests) for events of default. These events our results of operations, but did affect certain Balance include noncompliance with several financial covenants Sheet accounts. See Note 8. discussed in Note i1(e).

The financial statements reflect the liability method of in April 1992, nearly all of the outstanding Secured Lease accounting for income taxes. This method requires that Obligation Bonds (SLOBS) issued by a special purpose deferred taxes be recorded for all temporary difTerences corporation in connection with financing the sale and between the book and tax bases of assets and liabilities. leaseback of Beaver Valley Unit 2 were refinanced The majority of these temporary difTerences are attributa- through a tender olTer and the sale of new bonds having a ble to property-related basis difTerences. Included in lower interest rate. As part of the refmancing transaction, these basis difTerences is the equity component of Toledo Edison paid $43 million as supplemental rent to AFUDC, which will increase future tax expense when it fund transaction expenses and part of the tender pre-is recovered thmugh rates. Since this componem is not mium. This amount has been deferred and is being recognized for tax purposes, we must record a liability for amortized over the remaining lease term. The refinancing our tax obligation. The PUCO permits recovery of such transaction reduced the annual rental expense for the taxes from customers when they become payable. There- Beaver Valley Unit 2 lease by $9 million.

fore, the net amount due from customers through rates has been recorded as a deferred charge and will be Future minimum lease payments under the operating recovered over the lives of the related assets. leases at December 31,1993 are summarized as follows:

Year Amount Investment tax credits are deferred and amortized over (millions or the lives of the applicable property as a reduction of dollars) depreciation expense. See Note 7 for a discussion of the 1994 s 166 1995 165 amortization of certain unrestricted excess deferred taxes im 188 and unrestricted investment tax credits under the Rate Stabilization Program.

3 Later Years 3 412 (2) Utility Plant Sale and mai roture umimum tease rayments su6i Leaseback Transactions Rental expense .is accrued on a straight-line basis over the The Operating Companies are co-lessees of 18.26% (150 terms of the leases. The amount recorded in 1993,1992 megawatts) of Beaver Valley Unit 2 and 6.5% (51 and 1991 as annual rental expense for the Mansfield megawatts), 45.9% (358 megawatts) and 44.38 % (355 Plant leases was $115 million. The amounts recorded in megawatts) of Units 1,2 and 3 of the Mansfield Plant, 1993,1992 and 1991 as annual rental expense for the respectively, all for terms of about 29h years. These Beaver Valley Unit 2 lease were $63 million, $66 million leases are the result of sale and leaseback transactions and $72 million, respectively. Amounts charged to ex-completed in 1987. pense in excess of the lease payments are classified as Accumulated Deferred Rents in the Balance Sheet.

Under these leases, the Operating Companies are respon-sible for paying all taxes, insurance premiums, operation Toledo Edison is selling 150 megawatts of its Beaver and maintenance expenses and all other similar costs for Valley Unit 2 leased capacity entitlement to Cleveland their interests in the units sold and leased back. They Electric. We anticipate that this sale will continue may incur additional costs in connection with capital indefinitely.

diffh mar

(3) Property Owned with Other Utilities and Investors The Operating Companies own, as tenants in common with other utilities and those investors who are owner-participants in various sale and leaseback transactions (Lessors), certain generating units as listed below. Each owner owns an undivided share in the entire unit. Each owner has the right to a percentage of the generating capability of each unit equal to its ownership share. Each utility owner is obligated to pay for only its respective share of the construction costs and operating expenses. Each Lessor has leased its capacity rights to a utility which is obligated to pay for such Lessor's share of the construction costs and operating expenses. The Operating Companies' share of the operating expenses of these  ;

generating units is included in the Income Statement. The Balance Sheet classirication of Property, Plant and Equipment  :

I at December 31,1993 includes the following facilities owned by the Operating Companies as tenants in common with I

other utilities and Lessors:

tn- Plant Construction Service Ownership Ow nership Power in Work in Accumulated Generuiina Unit Date Share Megawatts Source Service Proeress Deoreciation (millions of dollars)

Seneca Pumped Storage 1970 80.00% 351 ilydro $ 67 $- $ 22 Eastlake Unit 5 1972 68.80 411 Coal 156 2 -

Perry Unit t 1987 51.02 609 Nuclear 2.832 11 473 j Beaver Valley Unit 2 and l Common Facilities (Note 2) 1987 26.12 214 Nuclear 1.4% _1 _2M l Total $4m iH $H 1210 l 1

Depreciation for Eastlake Unit 5 has been accumulated with all other nonnuclear depreciable property rather than by I specific units of depreciable property.

strategy. If a difrerent plan is required by the U.S. EPA, (4) Construction and significantly higher capital apenditures could be re- '

COnlingenCieS quired during the 19%-2003 period. We believe Ohio (a) Construction Program law permits the recovery of compliance costs from cus-tomers in rates.

The estimated cost of our construction program for the 1994-1998 period is $1.088 billion, including AFUDC of (b) Perry Unit 2

$48 million and excluding nuclear fuel.

Perry Unit 2, including its share of the facilities common The Clean Air Act will require, among other things, with Perry Unit 1, was approximately 50% complete significant reductions in the emission of sulfur dioxide in when construction was suspended in 1985 pending con-two phases over a ten-year period and nitrogen oxides by sideration of various options. These options included fossil-fueled generating units. resumption of full construction with a revised estimated Our compliance strategy provides for compliance with cost, conversion to a nonnuclear design, sale of all or part both phases through at least 2005 primarily through of our owneiship share, or cancellation.

greater use of low-sulfur coal at some of our units and the We wrote oft our investment in Perry Unit 2 at December banking of emission allowances. The plan will require 31, 1993 after we determined that it would not be capital expenditures over the 1994-2003 period of ap- completed or sold. The write-off totaled $%3 million proximately $222 million for nitrogen oxide control ($425 million after taxes) for our 64.76% ownership share equipment, emission monitoring equipment and plant of the unit. See Note 14.

modifications. In addition, higher fuel and other operation and maintenance expenses will be incurred. The antici- (c) Hazardous Waste Disposal Sites pated rate increase associated with the capital expendi- The Operating Companies are aware of their potential tures and higher expenses would be about 1-2% in the involvement in the cleanup of three sites listed on the late 1990s. Cleveland Electric may need to install sulfur Superfund Iist and several other waste sites not on such emission control technology at one of its generating list. The Operating Companies have accrued a liability plants after 2005 which could require additional expendi- totaling $19 million at December 31,1993 based on tures at that time. The PUCO has approved this plan. estimates of the costs of cleanup and their proportionate We also are seeking United States Environmental Protec- responsibility for such costs. We believe that the ulti-tion Agency (U.S. EPA) approval of the first phase of mate outcome of these matters will not have a material I

"'P""- adverse elTect on our financial condition or results of We are continuing to monitor developments in new tech- operations. See Management's Financial Analysis -

nologies that may be incorporated into our compliance Outlook-Hazardous Waste Disposal Sites.

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(5) Nuclear Operations and total amount of financing currentiy available under these

. . lease arrangements is $382 million ($232 million from ContinSencies .

mtermediate-term notes and $150 milh.on from bank (a) Operating Nuclear Units credit arrangements). Financing in an amount up to $750 Our three nuclear units may be impacted by activities or million is permitted. The intermediate-term notes ma-events beyond our control. An extended outage of one of ture in the period 1994-1997, with $75 million maturing our nuclear units for any reason, coupled with any in September 1994. At December 31,1993, $370 million unfavorable rate treatment, could have a material ad. of nuclear fuel was financed. The Operating Companies verse effect on our fmancial condition and results of severally lease their respective portions of the nuclear operations. See discussion of these risks in Management's fuel and are obligated to pay for the fuel as it is consumed Financial Analysis - Outlook-Nuclear Operations. in a reactor. The lease rates are based on various intermediate-term note rates, bank rates and commercial (b) Nuclear Insurance paper rates.

The Price-Anderson Act limits the liability of the owners The amounts financed include nuclear fuel in the Davis-of a nuclear power plant to the amount provided by Besse, Perry Unit I and Beaver Valley Unit 2 reactors private insurance and an industry assessment plan. In the with remaining lease payments of $110 million, $78 event of a nuclear incident at any unit in the United million and $46 million, respectively, at December 31, States resulting in losses in excess of the level of private 1993. The nuclear fuel amounts fmanced and capitalized insurance (currently $200 million), our maximum poten- also included interest charges incurred by the lessors tial assessment under that plan would be $155 million amounting to $14 million in 1993,$15 million in 1992 (plus any inflation adjustment) per incident. The assess-and $21 million in 1991. The estimated future lease ment is limited to $20 million per year for each nuclear amortization payments based on projected consumption meident. These assessment limits assume the other are $111 million in 1994, $97 million in 1995, $87 million CAPCO companies contribute their proportionate share in 1996, $77 million in 1997 and $69 million in 1998.

of any assessment.

The CAPCO companies have insurance coverage for (7) Regulatory Matters damage to property at the Davis-Besse, Perry and Beaver Valley sites (including leased fuel rad clean-up costs). Phase-in deferrals were recorded beginning in 1989 pur-Coverage amounted to $2.75 billion for each site as of suant to the phase-in plans approved by the PUCO in January 1,1994. Damage to property could exceed the January 1989 rate orders for the Operating Companies.

insurance coverage by a substantial amount. If it does, The phase-in plans were designed so that the projected our share of such excess amount could have a material revenues resulting from the authorized rate increases and adverse effect on our financial condition and results of anticipated sales growth provided for the phase in of operations. Under these policies, we can be assessed a certain nuclear costs over a ten-year period. The plans maximum of $25 million during a policy year if the required the deferral of a portion of the operating ex-reserves available to the insurer are inadequate to pay penses and both interest and equity carrying charges on claims arising out of an accident at any nuclear facility the Operating Companies' deferred rate-based invest-covered by the insurer. ments in Perry Unit I and Beaver Valley Unit 2 during the early years of the plans. The amortization and We also have extra expense insurance coverage. It in-recovery of such deferrals were scheduled to be completed I cludes the incremental cost of any replacement power by 1998, purchased (over the costs which would have been in-curred had the units been operating) and other incidental As we developed our strategic plan, we evaluated the expenses after the occurrence of certain types of acci. future recovery of our deferred charges and continued dents at our nuclear units. The amounts of the coverage application of the regulatory accounting measures we are 100% of the estimated extra expense per w eek during follow pursuant to PUCO orders. We concluded that l the 52-week period starting 21 weeks after an accident projected revenues would not provide for the recovery of and 67% of such estimate per w'eek for the next 104 the phase-in deferrals as scheduled because of economic weeks. The amount and duration of extra expense could and competitive pressures. Accordingly, we wrote olithe substantially exceed the insurance coverage. cumulative balance of the phase-in deferrals. The total phase-in deferred operating expenses and carrying charges written oft at December 31,1993 were $172 (6) Nuclear Fuel million and $705 million, respectively (totaling $598 Nuclear fuel is financed for the Operating Companies million after taxes). See Note 14. While recovery of our through leases with a special-purpose corporation. The other regulatory deferrals remains probable, our current l

assessment of business conditions has prompted us to recovery of this deferral will commence prior to 1998 and change our future plans. We decided that, once the is expected to be completed by no later than 2012. See deferral of expenses and acceleration of benefits under our Note 9(b).

Rate Stabilization Program are completed in 1995, we should no longer plan to use regulatory accounting mea- (8) Federal Ineome Tax sures to the extent we have in the past. I In October 1992, the PUCO approved a Rate Stabiliza- before taxes and preferred dividend requirements of sub-tion Program that was designed to encourage economic sidiaries by the statutory rate (35% in 1993 and 34% in growth in our service area by freezing base rates until both 1992 and 1991), is reconciled to the amount of 1996 and limiting subsequent rate increases to specified federal income tax recorded on the books as follows:

annual amounts not to exceed $216 million for Cleveland l993 397 393 Electric and $89 million for Toledo Edison over the (millions of dollars) 1996-1998 period. Bwk income (Loss) Before Federal income Tax $(i 263) g g As part of the Rate Stabilization Program, the Operating Tax (Credit) on Book Income (Loss) at Statutory Rate $ (442) $138 $158 Companies are allowed to defer and subsequently recover

. Increase (Decrease) in Tax:

certain costs not currently recovered m. rates and to Write-off of Perry Unit 2 46 - -

accelerate amortization of certain benefits. Such regula- write-ott of phase-in dererrals _ 28 - -

tory accounting measures provide for rate stabilization by Depreciation (6) (9) I rescheduling the timing of rate recovery of certain costs Rate Stabilization Program (30) (7) -

Other items 17 __1 J and the amortization of certain benefits during the 1992 Total Federal Income Tax Expense (Credit) _ 1 0 87) 1129 II6_8 1995 period. The continued use of these regulatory accounting measures will be dependent upon our continu- Federal income tax expense is recorded in the Income ing assessment and conclusion that there will be probable Statement as follows:

recovery of such deferrals in future rates. 1993 1992 199i (millions of dollars)

The regulatory accounting measures we are eligible to Operating Expenses:

Current Tax Provision $ 99 $ 71 $ 88 record through December 31,1995 include the deferral of

. . . . Changes in Accumulated Deferred Federal post-in-service interest carrying charges, depreciation ex- Income Tax:

pense and property taxes on assets placed in service after Write off of deferred operating expenses, (39) - -

February 29,1988 and the deferral of Toledo Edison Accelerated depreciation and operating expenses equivalent to an accumulated excess Al e]a nimum tax credit ( ) (3 ) ( )

rent reserve for Beaver Valley Unit 2 (which resulted Retirement and postemployment from the April 1992 refmancing of SLOBS as discussed benefits (43) - -

Sale and leaseback transactions and in Note 2). The cost deferrals recorded in 1993 and 1992 amortization 9 8 4 pursuant to these provisions were $95 m.ll.i ion and $84 Taxes, other than federal income taxes ~ 19 (25) -

million, respectively. Amortization and recovery of these Rate Stabilization Program (9) 4 -

deferrals will occur over the average life of the related Reacquired debt costs (3) 10 22 assets and the remaining lease period, or approximately Deferred fuel costs (2) (1) (9)

Other items (14) 3 23 30 years, and will commence with future rate recognition.

esanent Tax Credas - -

9 The regulatory accounting measures also provide for the accelerated amortization of certain unrestricted excess arged to Opera &g Expenset M _W 08 a bcon :

deferred tax and unrestricted investment tax credit bal- " c" rt"lnt p,9 on (34) (38) (46) ances and interim spent fuel storage accrual balances for Changes in Accumulated Deferred Federal Davis-llesse. The total amount of such regulatory bene- Income Tax:

Write-otr of deferred carrying charges __ (240) - -

fits recognized in 1993 and 1992 pursuant to these f 2 provisions was $46 million and $12 million, respectively. ,

8j Rate Stabilization Program Il 11 -

j The Rate Stabilization Program also authorized the Op-AFUDC and carrying charges 12 24 41 f crating Compam.es to defer and subsequently recover the Net operating loss carr> forward 35 (7) -

incremental expenses associated with the adoption of Other items _..(1) (4) -

the accounting standard for postretirement benefits other Total Expense (Credit) to than pensions (SFAS 106). In 1993, we deferred $96 Nonoperating Income 098) 7 JO million pursuant to this provision. Amortization and Total Federal Ir.come Tax Expense (Credit) . _11_38J) 1J2_9 s 168 l

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In August 1993, the 1993 Tax Act was enacted. Retroac- In 1993, we olTered the VTP, an early retirement pro-tive to January 1,1993, the top marginal corporate gram. Operating expenses for 1993 included $205 million income tax rate increased to 35% The change in tax rate of pension plan accruals to cover enhanced VTP benefits increased Accumulated Deferred Federal Income Taxes and an additional $10 million of pension costs for VTP for the future tax obligation by approximately $90 million. benefits paid to retirees from corporate funds. The $10 Since the PUCO has historically permitted recovery of million is not included in the pension data reported below, such taxes from customers when they become payable, A credit of $81 million resulting from a settlement of the deferred charge, Amounts Due from Customers for pension obligations through lump sum payments to al-Future Federal Income Taxes, also was increased by most all the VTP retirees partially offset the VTP

$90 million. The 1993 Tax Act is no'. expected to expenses.

materially impact future results of operations or cash flow. Net pension and VTP costs (credits) for 1991 through Under SFAS 109, temporary ditTerences and carryfor- 1993 were comprised of the following components:

wards resulted in deferred tax assets of $619 million and E E 3993 (millions of dollars) deferred tax liabilities of $2.198 billion at December 31, Pension costs (Credits):

1993 and deferred tax assets of $563 million and de. service cost for benefits earned during the period $ 15 $ 15 $ 14 ferred tax liabilities of $2.598 billion at December 31. Interest cost on projected benent 1992. These are summari. red as follows: obligation 37 38 36 Actual return on plan assets (65) (24) (129)

Net amortization and deferral J W) 65 Net pension costs (credits) (9) (16) (14)

(millions of dollars) VTP cost 205 - -

Propeity, plant and equipment $1.845 $2.125 Settlement gain R) , , , - - -

Deferred carrying charFes and operating expenses _ 206 365 Net costs (credits) 1g $g) $R)

Net operating loss carr> forwards (108) (137)

Investment tax credits (183) (190) The following table presents a reconciliation of the funded Other (!81) _(.Uj) status of the plan (s) at December 31,1993 and 1992.

Net deferred tax hability 11 S 9 }2.0E g g (millions of For tax purposes, net operating loss (NOL) carryforwards Actuarial present value or benefit obligations:

of approximately $309 million are available to reduce vested benefits $333 $310 future taxable income and will expire in 2003 through Nonvested benefits _R _4.0 Accumulated benefit obligation 370 350 2005. The 35% tax effect of the NOLs is $108 million. mect or future compensanon levels _u R Total projected benefit obligation 423 471 The Tax Reform Act of 1986 provides for an alternative Plan assets at fair market value 18h _.73 minimum tax (AMT) credit to be used to reduce the Funded status (37) 283 regular tax to the AMT level should the regular tax Unrecognized nei loss (i,ain) from variance exceed the AMT. AMT credits of $171 million are *" **" *""" # " "" * # *"'* " #

Unrecogmzed prior senice cost 10 12 available to olTset future regular tax. The credits may be Transition asset at January 1,1987 being amortized carried forward indefinitely. over 19 years _(42) _(29)

Net prepaid pension cost (accrued pension liability) included in other deferred charges (credusHn the Balance Sheet @) 1;g (9) Retirement and Postemployment Benefits At December 31,1993, the settlement (discount) rate and long-term rate of return on plan assets assumptions (a) Retirement Income Plan were 7.25% and 8.75%, respectively. The long-term rate of We sponsor a noncontributing pension plan which covers annual compensation increase assumption was 4.25%

all employee groups. Two existing plans were merged At December 31,1992, the settlement rate and long-term into a single plan on December 31,1993. The amount of rate of return on plan assets assumptions were 8.5% and retirement benefits generally depends upon the length of the long-term rate of annual compensation increase as-service. Under certain circumstances, benefits can begin sumption was 5%

as early as age 55. Our funding policy is to comply with Plan assets consist primarily of investments in common the Employee Retirement income Security Act of 1974 stock, bonds, guaranteed investment contracts, cash guidelines. equivalent securities and real estate.

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(b) Other Postretirement Ilenefits were 7.25% and 4.25%, respectively. The assumed annual We sponsor a postretirement benefit plan which provides health care cost trend rates (applicable to gross eligible all employee groups certain health care, death and other charges) are 9.5% for medical and 8% for dentalin 1994.

postretirement benefits other than pensions. The plan is Both rates reduce gradually to a fixed rate of 4.75% in contributory, with retiree contributions adjusted annu. 1996 and later years. Elements of the obligation affected ally. The plan is not funded. A policy limiting the em. by contribution caps are significantly less sensitive to ployer's contribution for retiree medical coverage for the health care cost trend rate than other elements. If the employees retiring after March 31,1993 was imple- assumed health care cost trend rates were increased by mented in February 1993. 1% in each future year, the accumulated postretirement benefit obligation as of December 31,1993 would in.

We adopted SFAS 106, the account.ing standard for .

. crease by $11 milh.on and the aggregate of the service and postretirement benefits other than pensions, elTective Jan- .

mterest cost components of the annual postretirement uary 1,1993. The standard requires the accrual of the benefit cost would increase by $1 m.lh.i on.

expected costs of such benefits during the employees' years of service. Previously, the costs of these benefits (c) Postemployment Benefits were expensed as paid, which is consistent with ratemak-In 1993, we adopted SFAS 112, the new accounting ing practices. Such costs totaled $9 million in 1992 and standard which requires the accrual of postemployment

$10 million in 1991, w hich included medical benefits of benefit costs. Postemployment benefits are the benefits

$8 million in 1992 and $9 million in 1991. The total provided to former or inactive employees after employ-amount accrued for SFAS 106 costs for 1993 was $111 ment but before retirement, such as worker's compensa-million, of which $5 million was capitalized and $106 tion, disability bene!c and severance pay. The adoption mtllion was expensed as other operation and maintenance of this accounting methoo did cot materially alTect our expenses. In 1993, we deferred incremental SFAS 106 1993 results of operations or financial position.

expenses totaling $96 million pursuant to a provision of the Rate Stabilization Program. See Note 7.

The components of the total postretirement benefit costs (10) Guarantees for 1993 were as follows: Cleveland Electric has guaranteed certain loan and lease jM, obligations of two mining companies under two long-Service cost for benefits earned $ 3 term coal purchase arrangements. Toledo Edison is also a Interest cost on accumulated postretirement benefit party to one of these guarantee arrangements. This obligation 16 arrangement requires payments to the mining company

$N7 il$on oIer 2ear 8 f r any actual expenses (as advance payrnents for coal)

VTP curtailment cost (includes $16 million transition when the mines are idle for reasons beyond the control of obligation adjustment) _ 84 the mining company. At December 31,1993, the princi-Total uts M pal amount of the mining companies' loan and lease The accumulated postretirement benefit obligation and obligations guaranteed by the Operating Companies was accrued postretirement benefit cost at December 31,1993 $80 million.

are summarized as follows: . .

w hans (l1) Capitah.zation of IMlars Accumulated postretirement benefit obhgation (a) Capital Stock Transactions attributable to: Shares sold, retired and purchased for treasury during the Retired participants $(229) three years ended December 31,1993 are listed in the Fully eligible active plan participants (1)

Other active plan participants (28) following tables.

Accumulated postretirement benefit obligation (258) t itiIousands of shares)

Unrecognized net loss from variance between assumptions Centerior Energy Common Stock:

and expenence 14 Dividend Reinvestment and Stock Unamortized transition obligation 143 Purchase Plan 3.542 2.570 1,422 Accrued postretirement benefit cost included in other Employee Savings Plan 544 322 348 noncurrent liabilities in the Halance Sheet $LIO_ l ) Employee Purchase Plan 52 Total Common Stock Sales 4.138 2.892 1,770 At December 31,1993, the settlement rate and the long- Treasury Shares 26 _fL72) _.Li t )

term rate of annual compensation increase assumptions Net increase 4.JM Q @

l C

M I"2 I"'

(c) Equity Distribution Restrictions (thousands of shares)

Preferred Stuck of Subudiaries Subject to The Operating Companies make cash available for the Mandatory Redemption:

Cleveland Electric Sales funding of Centerior Energy's common stock dividends by

$ 91.50 Series Q - -

75 paying dividends on their respective common stock,

• $NeN#'$ es Z 5 $ which are held solely by Centerior Energy. Federal law Cleveland Elestric Retirements prohibits the Operating Companies from paying divi-I' 8k ! h $) $ $l dends out of capital accounts, llowever, the Operating Companies may pay preferred and common stock divi.

75 00 Series I - -

(2)

!c 2 2 dends out of appropriated retained earnings and current k 0}

Adjustable Series M (100) t100) (100) earnings. At December 31,1993, Cleveland Electric and 9.125 Series N (150) - -

Toledo Edison had $125 million and $42 million, re-1oledo Edison Retirements

$100 par $11.00 -

(25) (10) spectively, of appropriated retained earnings for the pay-9.375 (17) (17) (17) ment of dividends. However, Toledo Edison is prohibited

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Preferred $t k of S sidiaries Not from paying a common stock dividend by a provision in its Subject to Mandatory Redemption: mortgage.

Cleveland Electric Sales 5 42.40 Series T 200 - -

Cleveland Electric Retbements (d) Preferred and Preference Stock te case) h) _L4 )

Amounts to be paid for preferred stock which must be redeemed during the next five years are $40 million in Shares of common stock required for our stock plans in 1994,$51 million in 1995,$41 million in 1996,$31 1993 were either acquired in the open market, issued as million in 1997 and $16 million in 1998.

new shares or issued from treasury stock. The annual mandatory redemption provisions are as The Board of Directors has authorized the purchase in the follows:

open market of up to 1,500,000 shares of our common Sha es To P ce stock until June 30,1994. As of L)ecember 31,1993, Redeemed in Share 225,500 shares had been purchased at a total cost of $4 Cleveland Electric Preferred:

million. Such shares are being held as treasury stock. $ 7.35 Series C 10,000 1984 $ 100 88.00 Series E 3,000 198l 1,000 (b) Common Shares Resened for Issue Adjustable Series M 100.000 1991 100 Common shares reserved for issue under the Employee 9.125 Series N 150.000 1993 100 Savings Plan and the Employee Purchase Plan were 91.50 Series Q 10,714 1995 1,000 88.00 Series R 50.000 2001' I,000 1,962,174 and 469,457 shares, respectively, at December 90.00 Series S 18,750 1999 1,000 31,1993.

Toledo Edison Preferred:

Stock options to purchase unissued shares of common $100 par $9.375 16,650 1985 100 stock under the 1978 Key Employee Stock Option Plan 25 par 2.81 400,000 1993 25 were granted at an exercise price of 100% of the fair

• All outstanding shares to be redeemed on December 1,2001.

market value at the date of the grant. No additional options may be granted. The exercise prices of option in June 1993, Cleveland Electric issued $100 million shares pun.iwxd uming the ilm pars ended December principal amount of Serial Preferred Stock, $42.40 Series 31,1993 ranged from $14.09 to $17.41 per share. Shares T. The Series T stock was deposited with an agent which and price ranges of outstanding options held by employ- issued Depositary Receipts, each representing of a ecs were as follows: share of the Series T stock.

1993 1992 1991 Options Outstanding at The annualized preferred dividend requirement for the December 31: Operating Companies at December 31,1993 was i Shares 37,627 93.312 129,798 $68 million.

Option Prices $14.09 to $14.09 to $14.09 to

$20.73 $20.73 $20.73 The preferred dividend rates on Cleveland Electric's Se-ries L and M and Toledo Edison's Series A and B l fluctuate based on prevailing interest rates and market l conditions. The dividend rates for these issues averaged l 7%,7%,7.41% and 8.22%, respectively, in 1993. Cleve-land Electric's Series P had a 6.5% dividend rate in 1993 until it was redeemed in August 1993.

e W

-. .amA -_as_.__ _ . -L +- #_. _ _4-2 , _ , _ , , .-.

Preference stock authorized for the Operating Companies The mortgages of the Operating Companies constitute are 3,000,000 shares without par value for Cleveland direct first liens on substantially all property owned and Electric and 5,000,000 shares with a $25 par value for franchises held by them. Excluded from the liens, among Toledo Edison. No preference shares are currently out- other things, are cash, securities, accounts receivable, standing for either company. fuel, supplies and, in the case of Toledo Edison, automo-With respect to dividend and liquidation rights, each tive equipment.

Operating Company's preferred stock is prior to its prefer- Certain unsecured loan agreements of the Operating ence stock and common stock, and each Operating Companies contain covenants relating to capitalization Company's preference stock is prior to its common stock. ratios, fixed charge coverage ratios and limitations on (e) Long-Term Debt and Other secured financing other than through first mortgage bonds Borrowing Arrangements or certain other transactions. Two reimbursement agree-

. ments relating to separate letters of credit issued in Long-term debt,less current matunties for the Operating connection with the sale and leaseback of Beaver Valley Companies was as follows:

Unit 2 contain several financial covenants afTecting or'Average Actual Centerior Energy and the Operating Companies. Among Ig al,' these are covenants relating to fixed charge coverage December 31. December 31. ratios and capitalization ratios. The write-ofTs recorded at Year or Matuna 1993 1 1992 December 31,1993 caused Centerior Energy and the dollars) Operating Companies to violate certain covenants con-First mortgage bonds: tained in a Cleveland Electric loan agreement and the two

• 5

]3 2] reimbursement agreements. The afTected creditors have w ived those violations in exchange for our commitment 199s 13.75 4 4 1993 7.00 i i to provide them with a second mortgage security inter-1996 13.75 4 4 est on our property and other considerations. We expect 1996 7.00 1 1 to complete this process in the second quarter of 1994.

1997 10.68 6 6 We will provide the same security interest to certain 1997 13.75 4 4 1997 100 ther creditors because their agreements require equal t I 1997 6.l25 31 3t treatment. We expect to provide second mortgage collat-1998 10.88 6 6 eral for $219 million of unsecured debt, $228 million of 1998 13.75 4 4 bank letters of credit and a $205 million revolving credit 1998 7.00 1 i facility.

1998 10 00 1 1 1999-2003 7.89 568 468 2004-20u8 8.14 260 264 2009 2013 7.68 436 436 (12) Short-Term Borrowing '

2014-2018 2019-2023 8.07 7.89 513 733 513 583 Arrangements 2374 2.357 in May 1993, Centerior Energy arranged for a $205 Secured medium term notes due .

1995-2021 8.77 963 860 million, three-year revolving credit facility. The facility Term bank loans due 1995-1996 _ _ 7.41 154 121 may be renewed twice for one-year periods at the option Notes due 1995-1997 9 63 43 60 of the participating banks. Centerior Energy and the Debentures dae 2002 8.70 135 135 Service Company may borrow under the facility, with all

"""""'""d" '* borrowings jointly and severally guaranteed by the Oper-of3 10.1i l58 158 Other - net -

(8) 3 ating Companies. Centerior Energy plans to transfer any Total t ong-Term Debt 1.Lo_Lo $ 3.694 of its borrowed funds to the Operating Companies, while the Service Company may borrow up to $25 milli n f r its own use. The banks' fee is 0.5% per annum Long-term debt matures during the next five years as follows: 587 million in 1994,$317 million in 1995,$242 payable quarterly in addition to interest on any borrow-million in 1996, $94 million in 1997 and $117 million in ings. That fee is expected to increase to 0.625% when

993, the facility agreement is amended as discussed below.

There were no borrowings under the facility at December The Operating Companies issued $550 million aggregate 31,1993. The facility agreement contains cosenants principal amount of secured medium-term notes during relating to capitalization and fixed charge coverage ratios.

the 1991-1993 period. The notes are secured by first The write-ofTs recorded at December 31,1993 caused mortgage bonds the ratios to fall below those covenant requirements. The N I

revolving credit facility is expected to be available for (14) Quarterly Results of Operations borrowings after the facility agreement is amended in the second quarter of 1994 to provide the participatmg (Unaudited) creditors with a second mortgage security interest. The following is a tabulation of the unaudited quarterly Short-term borrowing capacity authorized by the PUCO results of operations for the two years ended December annually is $300 million for Cleveland Electric and $150 31, 1993.

Ouarters Ended million for Toledo Edison. The Operating Companies March 31. June 30. Setst. 30. Dec. 31' are author.ized by the PUCO to borrow from each other (millions or dollars, on a short-term basis, except per share amounts) 1993 At December 31,1993, the Operating Com unies had no Operating Revenues $598 $589 $709 $ 578 commercial paper outstanding. The Operating Compa- Operating income (Loss) _ $122 $126 $106 $ (42) nies are unable to rely on the sale of commercial paper to Net Income (Loss) $ 35 5 34 $ 17 $(1,029) provide short-term funds because of their below invest- Aserage Common Shares (millions) 143.4 144 4 145.3 146.4 ment grade commercial paper credit ratings.

Earnings (Loss) Per Common Share $ .25 $ .23 $ .12 $ (7.02)

Dividends Paid Per (13) Financial Instruinents' Common Share $.40 $.40 $.40 $ .40 Fair Value i992 Operating Revenues $592 $581 $665 $ 600 The estimated fair values at December 31,1993 and 1992 Operating income $122 $115 $191 $ 109 of financial instruments that do not approximate their Net income $ 23 $ 20 $122 $ 47 carrying amounts are as follows: Average Common Shares December 31. (millions) 140.6 141.6 142.0 142.5 1993 1992 Earnings Per Common Carrying Fair Carrying Fair Share $ .16 $ .14 $ .86 $ .33 A mount Value Amount Value Disidends Paid Per (millions of dollars)

Nuclear Plant Decommissioning Trusts $ 56 5 59 $ 42 $ 4.'

Earnings for the quarter ended September 30,1993 were Preferred Stock, with Mandator)

Redemption Provisions decreased by $81 m.llion, i or $.56 per share, as a result of (includ ng current portion) 354 349 405 40s the recording of $125 million of VTP pension-related i ong. Term Det t (including benefits.

eurrent portion) 4.113 4,260 4.017 4,107 Earnings for the quarter ended December 31,1993 were The fair value of the nuclear plant decommissioning trusts decreased as a result of year-end adjustments for the is estimated based on the quoted market prices for the $583 million write-otT of Perry Unit 2 (see Note 4(b)),

investment securities. The fair value of the Operating the $877 million write-ofr of the phase-in deferrals (see Companies' preferred stock with mandatory redemption Note 7) and $58 million of other charges. These adjust-provisions and long-term debt is estimated based on the ments decreased quarterly earnings by $1.06 billion, or quoted market prices for the respective or similar issues or $7.24 per share.

on the basis of the discounted value of future cash flows- Earnings for the quarter ended September 30,1992 were The discounted value used current dividend or interest increased by $41 million, or 5.29 per share, as a result of rates (or other appropriate rates) for similar issues and the recording of deferred operating expenses and carry-loans with the same remaining maturities- ing charges for the first nine months of 1992 totaling $61 The estimated fair values of all other financial instru. million under the Rate Stabilization Program approved r ments approximate their carrying amounts in the Balance by the PUCO in October 1992. See Note 7.

Sheet at December 11,1993 and 1992 because of their short-term nature.

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EX ECUTIVES OF CENTERIOR ENERG Y CO R PO R ATIO N Chairman. President and Chicf Executive Officer Robert J. Farling (57) Vice President li ntnce G. Lirmert (47)

Executive Vice President Alurray R. Edelman (54) Controllcr nud G. Bushy (45)

Senior Vice President Fred J. Ismge, Jr: (44) Treasurer Gary AI. Hawkinson (45)

Vice President Gary R. Leidich (43) Secretary E. Lyle Pepin (52)

EX EC UTIV ES O F CENTERIOR SERVICE COMPANY Chairman, President and Vice President-

- Chief Executise Officer Customer Support Jacquita K. Hausennan (5/)

(and Chairman V.ice Pres.i dent-Finance

& CEO of .

& Admim.stration Gary R. Leidich (43)

Cleveland Electric and Toledo Edison) Robert J. Farling (57) Vice President-Legal &

Executive Vice President-Governmental Afi. .mrs Operations & Engineerine ~

and General Counsel Terrence G. Linnert (47)

(and Vice Chairman of Toledo Edison Vice President-and President of Transmission & Distribution Cleveland Electric) Slurray R. Edehnan (54) Operations David L Alonseau (53)

Senior Vice President- Vice President-Fossil & Transmission and Nuclear-Perry Robert A. Stratman (45)

Distribution Operations Vice President-(and President Marketing Al R. 7i mple * (48) of Toledo Edison) Fred J. Lange, Jr (44) Controller Paul G. Husby (45)

Treasurer Gary AI. Hawkinson (45)

S.enior Vice Pres.i dent-Secretary '

E. Lyle Pepin (52)

Nucicar Donald C. Shelton (60)

Number in paremhesis mdicates age. ( *) 1:lected clkrtive l'chruary 2M 1994.

FIN ANCI AL AND STATISTIC AL REVIEW Operating Revenues (millions of dollars)

Steam Total Total Total iteating Operating Year Residential Commercial Industrial Other Retail Wholesale Elecinc & Gas Revenues 1993 $768 716 754 143 2 381 93 2 474 -

$2 474 1992 732 706 766 143 2 347 91 2 438 -

2 438 1991 777 723 783 188 2 471 89 2 560 -

2 560 1990 719 669 779 190 2 357 70 2 427 -

2 427 1989 686 617 747 204 2 254 107 2 361 -

2 361 1983 546 440 600 83 1 669 29 1 698 25 1 723 Operating Expenses (millions of dollars)

Other Deferred l uel a Operation Depreciation Tases. Operatmg federal Total Purchased & & Other Than Expenses. Income Operatmg Year Pow er Maintenance Amortization  !!T Net Taxes Expenses 1993 $474 1083(a) 258 312 23(b) 11 $2161 1992 473 784 256 318 (52) 122 1 901 1991 500 801 243(c) 305 (6) 138 1 981 1990 472 863 242 283 (34) 96 I922 1989 473 860 273 260 (59) 122 1929 1983 464 384 145 172 -

184 1 349 income (Loss) (millions of dollars)

F ederal Income Other Deferred income (Loss) income & Carrying Tax- Before Operating AI'U DC- Deductions, Charges. Credit Interest Debt Year Income Equity Net Net (Expense) Charges Interest 1993 $313 5 (589)(d) (649)(b) 398 ($22) 359 1992 537 2 9 100 (7) 641 365 1991 579 9 6 110 (30) 674 381 1990 505 8 (1) 205 (l3) 704 384 1989 432 17 14 299 (73) 689 369 1983 374 153 5 -- 47 579 258 income (Loss) (millions of dollars) Common Stock (dollars per share & %)

Return on Preferred & Average Average Preference Net Shares Common AIU DC- Stoc k Income Outstanding Earnings Stock Dividends Book Year Debt Dhidends (l ess) (millions) (Loss) Equity Iseclared Value 1993 $ (5) 67 $(943) 144.9 $(6.51) (40.3)% $1.60 $12.14 1992 (I) 65 212 141.7 1.50 7.4 1.60 20.22 1991 (5) 61 237 139.1 1.71 8.4 1.60 20.37 1990 (6) 62 264 138.9 1.90 9.4 1.60 20.30 -

1989 (13) 66 267 140.5 1.90 9.6 1.60 19.99 1983 (54) 69 306 98.2(c) 3.ll(c) 15.7 2.19(e) 20.24(c)

NOTE: 1983 data is the result of combining and restating data for the Operating Companies.

(a) Includes early retirement program expenses and other charges of $272 million in 1993.

j (b) Includes write-olT of phase-in deferrals of $877 million in 1993, consisting of $172 million of deferred operating opeases and $705 million of deferred carrying charges.. l (c) in 1991, the Operating Companies adopted a change in accounting for nuclear plant depreciation. changing from the units-of-production method to the straight.line method at a 2.5% rate.

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BO AR D OF DIR ECTORS Richard P. Anderson (64) President and Chief Executive George H. Kaull(62) Retired Chainnan of Premix, Inc.,

Officer of The Andersons N1anagement Corporation, a a developer, manufacturer and fabricator of thennoset grain, fann supply and retailing finn.1986 reinforced composite materials.1987 Albert C. BersticAcr (59) President and Chief Executise Richard A. Afiller (67) Retired Chairman and Chief Officer of Ferro Corporation, a pioducer of specialty Executive Of6cer of the Company and Centerior Service chemical materials for manufactured products.1990 Company.1986 Leigh Carter (68) Retired President and Chief Operating Frank E. 3fosier (63) Retired Vice Chairman of the Officer of The BFGoodrich Company, a producer of Advisory Board of BP America Inc., a producer and chemicals, plastics and aerospace products. Retired refiner of petroleum products.1986 Chairman of Tremco. Incorporated, a manufacturer of Sister 3fary 5farthe Reinhard, SND (64) Director of specially chemical products and a w holly owned Development for the Sisters of Notre Dame of Cleveland, subsidiary of The BFGoodrich Company.1986 Ohin Fonner President of Notre Dame College of Ohio.1986 Thomas A. Conunes (51) President and Chief Operating Robert C. Sarage (56) President and Chief Executive Officer of The Sherwin-Williams Company, a Of6cer of Savage & Associates, Inc. an insurance, manufacturer of paints and painting supplies.1987 OnanM @nig ud m @nnW Gm 1990 Wayne R. Embry (56) Executive Vice President and Paul 31. Smart * (65) Attorney and retired Vice Chairman General N1anager of the Cleveland Cavaliers, a professional of the Company and The Toledo Edison Company.1986 basketball team. Chairman of N1ichael Alan Lewis Company, a fabricator of hardboard, Oberglass and ilIlliam J. Ililliams (65) Retired Chairman of Huntington .

carpeting materials for the automotive industry.1991 National Bank.1986 Robert J. Farling (57) Chairman, President and Chief Executive Of6cer of the Company and Centerior Service Robert 31. Ginn Chainnan Emeritus Company.1988 John R HWliammn Chairman Emeritus Number in parenthesis indicates age.

Date indicatesfirst year in u hich elected to floani. f *) Retired fmm the floani em .kmuary 31.1994.

COh1hlITTEES OF TH E BO ARD Enrimnmental Capital and Conununity becutire thanan Audit Dpenditures Responsibility and Nominating finance Rewurces Nuclear T.A. Commes, G.H. Kaull, Sr. 51.51. Reinhard, R.J. Farling. R.A. Niiller. EE. hiosier, R.P. Anderson, Chairman Chairman Chairman Chairman Chairman Chairman Chainnan R.P. Anderson A.C. Bersticker W.R. Embry L. Carter L. Carter W.R. Embry A.C. Bersticker L. Carter R.A. Niiller R.A. Stiller T.A. Commes T. A. Commes G.il Kaull R.J. Farling W.R. Embry EE. $1 osier EE. h1 osier R.A. Stiller R.J. Farling R.C. Savage Sr. N1.N1. Reinhard Sr. St.ht. Reinhard P.51. Smart

• P.ht. Smart

• W.J. Williams EE. 51 osier W.J. Williams W.J. Williams R.C. Savage l P.ht. Smart *

( *} Retiredjnnn the Itoani on .imuary 31. Iwd.

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Centerwr Energy Corporation and &bsidiartes Electric Sales (millions of KWil)  !!!ectric Customers (year end) Residential Usage I Average l AveraFe Average Pnce Hevenue ,

industrial h %ll Per Per Per l Year knidectial Commercial Industnal W holesale Other l otal Revdenual Commercial & Other T ot al ( ustomer k% ll Customer l l

1993 _ _ 6 974 7 306 11 687 3 027 1 022 30 016 924 227 96 491 12 219 1 032 937 7 546 Il.0le $830.99 l l

\

j 1992 _._ 6 666 7 086 II 551 2 814 1 011 29 128 925 099 96 813 12 741 1 034 653 7 227 10.98 793.68 l 1991 _ . 6 981 7 176 11559 2 690 1 048 29 454 921 995 96 449 12 843 1 031 287 7 410 11.16 827.10 1990 _ _ 6 666 6 848 12 168 2 487 959 29 128 918 965 94 522 12 906 1 026 393 7 079 10.82 765.93 l

1989 _ _ 6 806 6 830 12 520 3 235 996 30 387 914 020 93 833 12 763 1 020 616 7 295 10.08 737.58 ,

1983.__ 6 327 5 606 10 641 703 854 24 131 886 024 85 769 II 557 983 350 6 9n7 8.64 603.22 l 1.oad (MW & %) linergy (millions of KWil) Fuel Operable

( apauty l lhcienes-C<ompany Generated f uel Cost 141U Per at hme Peak Capaaty load Purchased Year oI Peak I .oad M arym l utter lowd N uclear T otal Power l'otal Per A% ll A% Il 1993 5 998 5 397 10.0% 61.6 % 21 105 10 435 31 540 273 31 813 1.39c 10 276 l

1992, 6 430 5 091 20.8 63.4 17 371 13 814 31 185 (122) 31 063 1.45 10 395 j 1991 6 453 5 361 16.9 62.9 18 041 13 454 31 495 40 31 535 1.48 10 442 {

1990 6 437 5 261 18.3 63.6 21 114 9 481 30 595 413 31 008 1.52 10 354 i 1989 6 430 5 389 16.2 63.3 20 174 12 122 32 296 21 32 317 1.47 10 435 1983 6 218 4 717 24.1 63.1 19 487 4 895 24 382 1650 26 032 1.72 10 419 investment (millions of dollars) rk l T otal L bbly Accumulated Progrew N udear Propert). L 'hht)

Plant in ()cpreciauon & Nct & Perry Iueland Plant and Plant l otal Year $crvice A morwauon Plant Umi 2 Other i quepment Addinons A wets 1993 $9 571 2 677 6 894 181 385 $7 460 $218 $10 710 1992 9 449 2 488 6 961 781 424 8 166 200 12 071 1991 8 888 2 274 6 614 853 503 7 970 204 II 829 1990 8636 2 039 6 597 921 568 8 086 251 11 681 1989 8 398 I 824 6 574 945 592 8 III 217 II 454 1983 4 180 1047 3 133 2 710 392(f) 6 235 785 6 922 Capitali7ation (millions of dollars & %)

Preferred & Preference Preferred Stm.k. without Stock, mth Mandatory Mandatory Redemption J Year Common 5tmk i ymty Redemption Provisions Promons I onplerm Debi Total j 1993 $1785 27% 313 5% 451 7% 4 019 61% $6 568 l 1992 2 889 39 364 5 354 5 3 694 51 7 301 1991 2 855 38 332 4 427 6 3 841 52 7 455 1990 2 810 39 237 3 427 6 3 729 52 7 203 1989 2 795 40 281 4 427 6 3 534 50 7 037 1983 2 065 39 412 8 344 6 2 504 47 5 325 (d) includes write off of Perry Unit 2 of $583 million in 1993.

(c) Average shares outstanding and related per share computations reflect the Cleveland Electric 1.Il-for one exchange ratio and the Toledo Edison one-for-one eschange ratio for Centenor Energy shares at the date of athliation. April 29.1986.

(f) Restated for effects of capitalisation of nuclear fuel lease and financing arrangements pursuant to Statement of l'inancial Accounting Standards 71.

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Dividend Reinvestment and Stock Registrar Purchase Plan and Individual Retirement Society National Bank Corporate Trust Division Account (CX lRA) p,0 goxn477 The Company has a Dividend Reinvestment and Stock Cleveland, OH 44101 Purchase Plan which provides share owners of record and customers of the Company's subsidiaries a convenient Executive Offices means of purchasing shares of Company common stock by Centerior Energy Corporation investing all or a part of their quarterly dividends as well 6200 Oak Tree Boulevard as making cash investments. In addition, individuals may Independence OH establish an individual retirement account ORA) which Telephone:(216) 447-3100 invests in Company common stock through the Plan. FAX: (216) 447-3240 l Information relating to the Plan and the CX lRA may be obtained from Share Owner Services at the Company.

(

Mail Address l CX lRA Custodian Centerior Energy Corporation ,

P.O. Box 94661 '

All communications about an existing CX*lRA should Cleveland, OH 44101-4661 he directed to the Custodian at the address or telephone numbers listed below: Independent Accountants Society National Bank Arthur Andersen & Co.

Custodian, CX lRA 1717 East Ninth Street P.O. Box 6477 Cleveland, OH 44114 Cleveland, OH 44101 in Cleveland area 737-5745 Colunion Stock Listed on the New York, Midwest and Pacific Stock Elsewhere in Ohio I-800-362-0697, Extension 5745 Exchanges. Options are traded on The Pa.ific Stock Outside Ohio 1-800-321-1355, Extension 5745 Exchange New York Stock Exchange symbol-CX.

Newspaper abbreviation-CentEn or CentrEngy.

Share Owner Services Communications regarding stock transfer requirements, Annual MeetinoD lost certificates, dividends and changes of address shouki The 1994 annual meeting of the share owners of the be directed to Share Owner Services at the Company. To Company will be held on April 26,1994. Owners of reach Share Owner Services by phone, call: common stock as of February 25,1994, the record date for the meeting, will be eligible to vote on matters in Cleveland area 642-6900 or 447-2400 brought up for share owners' consideration.

Outside Cleveland area 1-800-433-7794 -

E,nvironmental Report Please have your account number ready when calling. The Company will furnish to share owners, without Investor Relations 'h"8 ' " *PY f "'P " " h* *"'i *""*"' l #""" "'"'

Requests should be directed to Share Owner Services.

Inquiries from security analysts and institutional investors should be directed to Terrence R. Moran, Form 10-K Manager-Investor Relations, at the Company's mail The Company will furnish to share owners, without charge, I address or by telephone at (216) 447-2882.

a copy of its most recent annual report to the Securities and Exchange Commission. Requests should be directed l,fallsfer Agent to Share Owner Services.

Centerior Energy Corporation Share Owner Services Audio Cassettes P.O. Box 94661 Share owners with impaired vision may obtain audio Cleveland,01144101-4661 cassettes of the Company's Quarterly Reports and Annual Stock transfers may be presented at Report. To obtain a cassette, simply write or call Share Society Trust Company of New York Owner Services. There is no charge for this service.

5 Hanover Square,10th Floor New York, NY 10004 O

Centerior Energy Corporation P.O. Box 94661 Cleveland, Oli 44101-4661 I

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