ML20070M552
| ML20070M552 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse, Perry  |
| Issue date: | 12/31/1993 |
| From: | Farlingr J CENTERIOR ENERGY |
| To: | |
| Shared Package | |
| ML20070M550 | List: |
| References | |
| NUDOCS 9404290215 | |
| Download: ML20070M552 (200) | |
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9404290215 940422 ' ' # 1.' 1 ' n - 'G MN.i J.U.Jl2.',f W ' Geni M M .'? * -iti w.1:D. ~ . M. PDR ADDCK 05000346 ! PDR y lJ: -
' ~ ' ' ':sf. l 'O ?.C -cf. M.) 1 e.? >:; , . 1.a
FIN ANCI A L S U M M A RY 1993 1992 % Change Quarterly Range Of Earnings (Loss) Per Share of Common Stock._ $ (6.51) $ I.50 - Write-Offs and Other Charges Common Stock Prices Per Share of Common Stock $ 7.95 - - 1993 liigh Low Earnings Per Share of Common Stock Excluding Write-Offs and Other Charges _ $ 1.44 $ 1.50 (4) ist Quarter $20 $18% Dividends Declared Per Share of 2nd Quarter 19 % 17 % Common Stock $ 1.60 $ 1.60 0 3rd Quaner 18 % 17 % Book Value Per Share of Common Stock 4th Quarter 17 % 12 at Year End $ 12.14 $ 20.22 (40) Closing Common Stock Price at Year End $ 13 % $ 19 % (33) Common Stock Share Owners at Year End __ 163,602 171,255 (4) 1992 High Low Common Stock Shares Outstanding at Year End (millions) 147 143 3 Ist Quarter $20 $17% 2nd Quarter 18 % 16 % 3rd Quarter 17 % 15 % eth Quarter 20 17 % Operating Revenues (millions) $ 2,474 $ 2,438 1 Operating Expenses (millions) $ 2,161 $1,901 14 Net Income (Loss) (millions) $ (943) $ 212 - Return on Average Common Stock Equity (40.3)% 7.4% - Return on Average Common Stock Equity Excluding Write-Offs and Other Charges _ 7.1 % 7.4% - Kilowatt-hour Sales (Millions of Kilowatt-hours) Residential 6,974 6,666 5 Commercial 7,306 7,086 3 Industrial 11,687 11,551 1 Wholesale 3,027 2,814 8 Other 1,022 1,011 1 Total _ 30,016 29,128 3 @ ennied on recnico paper Employees at Year End 6,748 8,376 (19)
CONTENTS
\
O Letter to Share Owners O Perspective O Finance ' O Revenues - O Customer Satisfaction O Employees O. Power Supply O Management's Statement of Responsibility for Financial Statements
@ Report ofIndependent Public Accountants O. Management's Financial Analysis, Financial Statements and Notes O Executives of Centerior Energy Corporation and Centerior Service Company O Financialand Statistical Review O Board of Directors O Share OwnerInformation
,.-...-.-.-~..n--- -~- - ~ ~ ~ ~ ~ ~ " ~ ~ ~ ~ ~ ~ ~ ~ ~
; ! l ; , l f ; I i1 HIGHLIGHTS A long-term strategic action plan t was developed to guide us through i
the year 2001.
- We wrote off
- our investment in Peny Unit 2 and certain deferred charges for a l total of $1.023 billion, after taxes.
1
- Our common stock dividend
( i was reduced to an indicated annual rate of $0.80 per share in January
\
1994.
- Over 1,500 employees q
accepted voluntary early retirement i in 1993, resulting in a 19% reduction in employees from year-end 1992. 2
- = Davis-Besse continued to operate as one of the nation's best j performing nuclear power plants and
- received its highest marks ever in the i
Nuclear Regulatory Commission's i Systematic Assessment of Licensee Performance. = A two-year course i of action plan was developed and implemented to improve substantially {; a the performance of Perry Unit 1. 4 1 = Cleveland Electric reached an 1 agreement that favorably resolved a municipalization threat in the City j 1 of Brook Park.
- Voters in the City of Toledo ratified a new franchise a
agreement for Toledo Edison which runs through the year 2000. (ToledoIktA i (ClevelandElectric} { t [F ii l t . i a OHIO i l a l' i Centenor 1.ne'rv Carporutsmo u as tornocJ in April Ivv> upon ihr affiitatuon of ihr Clen ciarul r 'r. to rt lilumimaure Company and ihe loluto lJnon Cornpans Wah anen of about 5II a billson. Centert,a 1 nr r er is vor ut Ihr laree st i t !t t lill Galltl\ % \ \f! r*f1 in llht risalt hil thC Centen<a vpe r,-nene e omparae s wn e .' h 4 insthon propic in a a unshmcd se n en c area at k $NS Qdfilt'C 10ll (\ dri hf Ulkle'en th alth ( t'U$f t'Itar 1.nr tp n an t qual opponumn emp!m rr a t
._ _ _ .._ __ _ _ _ - . _ _ _ _ _ _ . . . . _ _ _ _ . _ . . _ _ _ . _ - - _ _ _ _ _ . _ _ _ __J
f DE AR SH ARE OWNER: TiiE REGULATORY, LEGISLATIVE AND economic forces impacting Centerior Energy j i and the electric utility industry brought your l Company to a crucial position in 1993. As a result, we took tough and decisive actions to begin I to shift our corporate culture and become a powerful, competitive company in the future. l l
- 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 r
l of our position. The Board of Directors voted to reduce the quarterly common ,, ,. , jl
- stock dividend to $0.20 per share and 1 write off $1.023 billion, after taxes, of ,
]
~
ssets. We notified you in January of - { i these decisions and their meaning within .- I the structure of our plan, which defines
=-
our commitment to financial well-being j, j and competitive leadership. Many of the past decisions which contrib-i l l uted to Centerior Energy's present status , ! were based on projections of economic _. growth in our area that did not occur. The economic sluggishness, coupled with
- increased competitive pressures, continues to exert downward pressure on earnings. MNN Meanwhile federal policies continue to move our industry further toward deregulation and j unprecedented competition for customers in the once-protected markets of investor-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, 2 or wheeling, of electric power from outside wholesalers to municipal electric systems in our
- area. However, 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 j lowest-cost electricity.
I i This situation occurs at a very sensitive time for Centerior Energy. Our electric rates are above ! 'he regional and national averages. They reflect the cost of major construction completed in the late 1980s to ensure continued service reliability to our more than one million customers. While these high rates put us at a disadvantage in a competitive 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 j successful, more market-driven business. l, l Setting the stage for the success of this plan required those very haru decisions that affected the short-term and long-term interests of our share owners. 1 3 We recognize that the dividend reduction is a setback to share owners in the short run. Ilowever. j our earnings projections did not support continuation of the dividend at its former rate, and the ) Board concluded that it would not be prudent to delay this reduction. Our estimates for future h
j revenues, costs and capital spending requirements 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 d cisions were made now because of the pressures imposed by a number of interrelated factors, i egislative and regulatory decisions have prompted increasing competition while I imposing higher operating costs on investor-owned electric utilities. The recent action by several security rating agencies to downgrade the ratings on securities of our operating companies, i Cleveland Electric and Toledo Edison, accented our financial difHeulties. 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 mose 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 from corporate assets and resources.
- Achieve 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 19% 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, market-driven business whose profitability rewards all share owners. Sincerely, Roben J. Farling Chairman, President and Chief Executive Officer March 9,1994 e w
l l P E R S P E C 7'I V E SETTING THE STAGE FOR OUR strategic action plan required a period of l financial transition involving costly but l essential actions that had a major impact on 1993 earnings. l 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. However, current projections l show that revenues over that period would not provide for such recovery l
as scheduled due to economic and competitive pressures. Accordingly, we l concluded it was necessary to write off the deferred balance. This action I moves us closer to reporting earnings on a cash basis with less reliance
- on regulatory accounting measures. In addition, because we recognized l l the charges in 1993, they will not have to be recognized in the i 1994-1998 period.
The other write-off was a $425 million, after-tax charge for Unit 2 of the Perry Nuclear Power Plant. Based on our current assessment of power requirements in our region, the partially built unit will not be completed or j sold. As a result, the investment must be written off. Another essential action was the 19% reduction in our workforce. While l this will result in substantial savings annually beginning in 1994, the early l 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. However, our basic business remains stable. Without all of these charges, earnings would have been $1.44 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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a gyr % g@;1 rpq A KEY FOCUS OF OUR STRATEGIC ACTION PLAN if bD is the rebuilding of the Company's financial strength, p F I;N A NGjE we win measure our success by the improvements we achieve in total annual return to share owners, in terms of q p g- j vM _ _A. M both dividends and stock price nppreciation, relative to the Standard & Poor's Index of 5(X) stocks. The reduction in the common stock dividend will reduce our cash outflow approximately $120 million annually, which we intend to use to pay on uebt 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. Provide share our stratesic action pian caiis for further reduction in our annual operation and maintenance expenses. This will be owners a totaI challenging because we already reduced those costs by allnlla[ re/llr/l nearly $80 million, or 9%, over the two years prior to
' 993 L** Y'* ** ** P"i'""d """' '""d'* I"**'* I" CXCeeding Ihe those costs, excluding the previously mentioned, one-Stanc/ arc / & har,s . . .
time charges. I.or 1994, we anticipate our operation and 500 hidex. mainienance expenses win be around su5 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 innation.
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 save some $80 million in capital expenditures while still keeping our reserve margin of geccating capacity at an acceptable level. 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 forecast averaged $350 million annually, including spending requirements to comply with federal clean-air legislation. 'lklay, the 10-year budget averages $230 million annually. IlVE-YEAR CONtPARISON OF CUh1ULATIVE TOTAL RETURN
$250 DM) mm - _
$150 Sim l l
= El B I E E E w n w w st s2 vs Centerior Common Stock l S&P 500 Index Five-year total return of $HD im'ested in Centerior Energy Common Stod at year-end lYM compared to total return of Standard & n>or's 500 Indexfor the same period, assuming all dividends were reinvested.
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l l i Over the time span of our action plan, we expect that l ' "' 1 earnings grow th w.ll i lead to stock n."n c woum. , 1 I g f.,, g.,, price appreciation, thus fulfilling ""*" i 7 f *?. TT.[ 3E m fronminion our objective of improved total n. . - # F1e 4- 3 Doi" leon return to share owners. That "I'"'"'"'" 2 # '"# ] ' l.<mer. Semor Yie e j earnings growth will come p,nfge,,,_ f%g 3 through continued cost control, In m wnu mn med l reductions in our interest charges D"'"l'"""" i and, most significantly, from "'["'{,),'[ "h 7 i revenue increases, particularly 3 rreudent-to.d i from the aggressive new measures a Goicrnmemal we have developed to increase ^ #"" ' ""d Genend coma, t. i electricity sales. l ' TO ACillEVE REVENUE GROWTil, WE WILL 7' o # work vigorously to meet more customer needs, compete l proactively with other energy providers and encourage R E:V E NU E S) economic development in our service area. We also will ,
^
seek to increase revenues by restructuring our rates to " ~# our various customers to suit these changing market conditions. During the 1970s and 1980s, we cut back on our traditional promotion of kilowatt-hour sales. We did so in response to governmental and societal pressures encouraging energy conservation as a way to defer the added costs and environmental 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 Beaver Valley Obf6 Clip 62 ~ Power Station. Those units are now m service. They give us sufficient generating capacity to accommodate sales fj7cygggg gfy777g[ prowth beyond the year 2001 without the need for additmnal units. TCVCHilCSiH aH ever-increasing We have resumed promoting electricity sales, but we g g j y jy g f jff p g y 7 g r /( g [, are doing so in ways consistent with national energy , j objectives. We are promoting the use of(lectricity to serve our customers' comfort and l convenience, benefit the environment and improve the productivity of businesses while reducing l 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 processes with a flexibility and precision that enhances manufacturing i
efficiency while decreasing total energy requirements. New electrotechnologies also can reduce emissions from the manufacturing process, thus lowering our customers' costs of complying with pollution control requirements. To increase our sales and, consequently, our revenues, we are implementing a broad range of new marketing programs w hich include special communications, direct contact and customer h Nummp'
incentives. We especially are targeting specific markets which represent the pctential for annual revenue increases in the tens of millions of dollars. For example:
- Electric process heating for use in the automotive, fabricated metals and nonmetals industries.
Specific applications include infrared process heating, induction heating and esistance hearing.
- Electrical equipment for food senice applications.
1
- lilectric baseboard heating, add-on heat pumps, new appliances and portable space heaters in !
the residential market. I
- Use of geothermal heat pumps in new home construction.
i es ar \ Through a new program called . I'"m!# J . Customer Focus 2000, we have
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Em utne 174 e targeted 200 m. dustrial customers, k' , i en uscia . o verario,n . large commercial concerns and
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jaaw nauserman. g residential developers that represent
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We have assigned each of our top i " ans c; art i<is,ch. ts . management people to serve as a Ma emisc,u. personal liaison wnh a corporate t u,am e a ; c . . asmmninumn. ofh.eer of. specific companies. Our l 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 timc, discosering new opportunities for kilowatt-hour sales. Customer Focus 2(XX) was pioneered in the Toledo Edison area in 1993, with good results. We gained greater understanding of the needs of nearly 100 major customers, and 209 of our contacts resulted in sales leads.
In addition to sales promotions, we employ creative new uses for existing assets and resources to add to annual earnings. As one example, we are pursuing partnerships with customers and independent power producers to put underutili/cd or mothballed generating units to work. As another source of new revenues, we will be marketing our services to local municipalities, water authorities and private entities. In exchange 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 development. As one incentise, we return to industrial customers a portion of their electricity payments to be applied to capital investments or other expansion in our service area. In 1993, this plan helped encourage $325 million of capital investments, creating or retaining nearly 3.(XX)
'I OTAt. LEVI;NUIS sw C3 bj u
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$10 Sa $
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jobs and more than $7 million in annual revenues for us For example the Chrysler . , Corporation received 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 wo-king to retain our customer base. We have negotiated sole-supplier contracts covering 75% of Toledo Edison's industrial sales and 50% of Cleveland Electric's industrial sales. We have achieved major successes in stabilizing municipalization activity. In 1993, we negotiated a new franchise agreement with the City of Toledo and reached an accord with the Cleveland suburb of Brook Park to help prevent creation of municipal electric systems in those communities. OfGeials in two other cities we serve decided not to proceed at this time with municipalization activities after they examined the risks. l Cleveland Public Power continues its expansion into areas of Cleveland we now serve. CPP's first phase of expansion has converted about 8.000 customers to date. At risk are an estimated 35,000 additional customers over the 1994 1996 period. The number is significant, but these customers represent only about 3% of our total and less than 1.5% of our revenues. The municipal i system plans a second phase of expansion to pursue more of our customers starting in 1997. l Plans are incomplete and the potential impact on us is not yet known< To retain our industrial and commercial customers in Cleveland, we are marketing a package ' of incentives which includes energy-efficiency improvements and reductions in demand charges for increased electricity use. These incentives are offered in return for sole-supplier agreements with us, generally ranging from three to live years. Thus far, approximately 75% of the customers who have made their decisions have elected to stay with us. AS A lilGH-COST ENERGY SUPPLIER IN A , m m% - - ypum@e 04 uZ % sd 1 C U S-T OME O RJ ;3 newly competitive mdustry, we recognize the need to become known for correspondingly high quality 6 - service. As part of our strategic action plan, we will S $T I S,F A;CM*I OqN _
- continuously measure, analyze and work to increase - hk 4 ' AA. ,w#hu customer satisfaction with our service.
Good service 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 we are. Each year we retain a pubh.c opmion research firm to
. . Obiective: J conduct in-depth surveys of a representative sample of Raise Our cus/Onzer our customers. We measure results against past surveys fgpggghj((fy pgf[gg.
and against 70 other utilities nationwide. Our overall favorability rating in 1993 was 661 This represents 0 / IlNO OI considerable improvement from the low of 45% recorded Of,OUT Uldlls/Ty. in 1989.110 wever, we still are three percentage points under the 69% average of all 70 utilities. This puts us in the bottom half. We intend to be in the top quarter before the end of 2001. T' yvc--w- + - - * - --+'T-"* * '44- me-3' M e,yy e p y-m m- M m - ru ,e ene=4 *ge+rrast -e i m--' rS---*sstrih**d'W*re Meti t g 9 q93+--ya sqisiq- 6eseg'r gir ei'w1h**#F--_t w
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 specific services rendered, such as new electricalinstallations. 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 i efforts to enhance customer satisfaction. j
\
Our action plan includes specific goals to improve basic services affecting customer satisfaction. i l We intend to reduce customer call-waiting time and the frequency of power interruptions. We l also will accelerate service restoration, the replacement of burned-out street lamps and new 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 10% of the industry in all categories by 2001. Our customer responsiveness was severely tested in 1993. A devastating thunderstorm on July 28 j 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 j four days. However, our greatest disappointment in this emergency was our inability to pmvide l
customers with accurate estimates as to when their power might be restored. We are implementing ! procedural improvements to deal with this.. Among other service improvements in 1993, we activated our new florizon 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 would enhance our billing accuracy while reducing our meter-reading costs. We continue to provide the energy-efficiency progra'ms 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 in national and global markets. Ultimately, this improves our own sales and revenue prospects for the long-term benefit of share owners. CUSTONIER FAVORAlllLITY RATING m j w e 20 o m w 91 92 M Percent h w
EVEN IN Tills ERA OF 111G11 TECilNOLOGY, Tm;'FC 'S employees remain our single most important resource dm r4 N. t uo 1 "M-in serving customers and maximizing total return to @ P L[1*.O;Y E E S' ! share owners. We recognize that the primary criteria y g, for success is not the number of employees but rather "'- '- h'j - their skills, personal development and commitment. Management's task is to provide the training, leadership and cultural environment to support employee efforts. As a result of the workforce reduction in 1993 and earlier downsizings, we have cut our total number of employees from 9,062 at year-end 1989 to 6,748 at year-end 1993. In that time, upper l management was reduced from 85 to 50. Responsibilities have been broadened and some executives are being challenged with entirely new . l responsibilities. Our reduced numbers are consistent with 0b.lOCIYOI j other utilities which also have been downsizing their A//if)[l[y CfJif)[OyCC l staffs to control costs. (g,,yyyyjfyyyg,yl l Meanwhile, we are stressing accountability. As we have O COIOOI~O O ; streamlined management, so have we reduced direct ()hjCC/[PCS, supervision. We are empowering employees to handle greater responsibilities and make more decisions. We also are devebping training programs and iacentives to encourage every employee to be part of our sales teant. To prepare them for their expended roles, we are establishing cro'.s-functional teams of employees to identify and address key corporate issues. No one knows the wo-kings of our business better than our employees; they are in the best position to propose sc lutions to problems and new ways to increase efficiency and reduce costs. Management gives their views full attention. Consistent with our expectations of employees, we are developing a total compensation strategy that provides cost-effective and appropriate rewards. The key to this strategy is incentive pay to reward employees based on the achievement of corporate objectives. Today's workforce is more diverse than any we have had in the past. Our employees are much more challenged than their predecessors. The past few years have been characterized by rapid change, uncertainty and increasing demands. Nevertheless, our employees have maintained their j 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 objectives of our strategic action plan. l l l EMPl.OYEES (Year End) 10 8 6 4 {} 'XY 5M 4) Y1 Y.t l Thoustmds i l ! h
7."** f - VARIABLE POWER SUPPIX COSTS INCLUDE r - f fuel expenses and operation and maintenance expenses
.P O W' ~ E R OS..U.lP PforLY.
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our generating units, as opposed to the Oxed 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 l kilowatt-hour at year-end 2001. I By reducing our production costs per kilowatt-hour, we become more competitive in our own ! l service area and in the wholesale energy market. This will become increasingly important as
, deregulation provides new opportunities for independent Obj.ectlvez po w er p m ducer and encourayes m ore w hoiesaie
/fC(/IICC Wir/d/1/6 S' heeling of power and, possibly, retail wheeling beyond traditional service area boundaries. ]
fyg}pgyggfjyfyf), COSTS 10 a 1110re We wiiiachieve ee,ce,,.,cdectien geai byimg,eving plant performance and reducing outage times. These will CD/1?f>C////PC [6PC/. be achieved through efficiency-enhancement projects and improved maintenance and scheduling. We also will use technological upgrades and experimentation when appropriate:
- In 1993, for example, we completely computerized 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. Typically, 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 l performance in 1993. Davis-Besse received its highest marks ever from the Nuclear Regulatory Commission in its most recent Systematic Assessment of Licensee Performance. Also continuing PRODUCTION COSTS 4 f t l O ?N W '91 92 '93 Cents l'er Kilowatt-ilcmr (Three-Year Rolling Average)
, above-average operations is lleaver Valley Unit 2 in which we share ownership. At year-end e i 1993, the three-year availability average of each unit was 87G. Those marks are well abose the industry average of 784 for . l pressurized water reactors. .
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The 1993 perfonnance of our third na l'rnaru l .
) nuclear generating facility, Perry ,
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- Unit I, fell below expectations. .
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! bringing down Perry's three-year .I' ? n i l h kin- h !rar
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j availability aserace to 679. This -
'- I i falls short of the 72'Iindustry ' )l f average for boiling water reactors. $$
i Perry experienced a series of -
%- m; j mamtenance problems last year, '4 -
l; sharply increasing its dow ntime.
- 7. .
1 We are working to tum the plant j around. The Perry m magement j team is now headed by some of the key people who saw Davis-llesse through a $200 million l improvement program in the mid-1980s with outstanding results. We have embarked on a two- { year, in-depth course of action at Perry which includes more aggressive maintenance, improved j quality assessment and heightened management involvement at all levels. Our cost is estimated j to be $33 million. The Nuclear Regulatory Commission has concurred that successful { implementation of this course of action will achieve our objectives for Perry. i j Our environmental engineering efforts mer the years have placed us ahead of many other
- utilities in reducing sulfur dioxide emissions from fossil-fueled units as required by the Clean l Air Act. 51 ore than two-thirds of our generation is already in compliance with existing law or is j not affected by the legislation. We will bring the remaining third into compliance by the time l required primarily by switching to lower-sulfur fuels. The necessary expenditures will hase no j material effect on our electric rates.
f i l h1any other coal-reliant utilities in our region face much higher emironmental protection costs. ! As a result, their electric rates over the next several years will increase by a greater margin than j ours. This will bring us closer to rate parity, making us more competitive in our region. f We are about to begin a two-year,530 million upgrade of our System Operations Center located near Cleseland. The Center coordinates the generation and transmission of bulk power l j throughout our system. This upgrade will ensure the availability of power for our own customers l w hile making it easier for us to market our electricity in other regions. i i i Power production is the heart of our business. As we continue improving our operating
] efficiencies and redu ing costs, we will be that much further along in making the successful j transition to being a more market-driven business and in improving total return to share owners.
1 i 4 i j
. . . . , . ~ - , _ . , , . .. ,- -,. .-
I l M AN AG EM ENT'S Our Board of Directors is responsible for determining "hether management and the independent public ac-l STATEMENT OF countants are carrying out their responsibilities. The I i RESPONSIBILITY FOR Board is also responsible for making changes in manage-F1N ANC1 AL STATEM ENTS ment or independent public accountants if needed. The Board has appointed an Audit Committee, comprised The management of Centerior Energy Corporation is entirely of outside directors, which met two times in responsible for the consolidated financial statements in 1993. The Committee recommends annually to the this Annual Report. The statements were prepared in Board the firm of independent public accountants to be accordance with generally accepted accounting principles. retained for Se ensuing year and reviews the audit ap-Under these principles, some of the recorded amounts proach used i j 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 efTectiveness 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 fmancial position. tially complete and accurate. The controls also are de- ) signed to help protect the assets and their related records. f
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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 efTectiveness of existing controls l and to identify and institute changes where needed. In addition, an examination of our financial statements is [ l conducted by Arthur Andersen & Co., independent public PAUL G. BUSBY l l accountants, whose report appears below. Contr ller and Chief Accounting O@cer REPORT OF disclosures in the financial statements. An audit also indudes assessing the amounting prindples used and INDEPENDENT sigmficant estimates made by management, as well as PUBLIC ACCOUNTANTS evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for To the Share Owners and ARTHUR ""' "'"' "' Board of Directors of ANDERSEN In our opinion, the financial statements referred to above Centenor Energy Corporatwn: present fairly, .m all material respects, the financial posi- 1 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 carporation) and operations and their cash flows 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. I ings and cash 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 Cornpany's manage-tion in 1991 and for postretirement benefits other than ment. Our responsibility is to express an opinion on thes pensions in 1993. financial statements based on our audits. We conducted our audits in accordance with generally I accepted auditing standards. Those standards require that g we plan and perform the audit to obtam reasonable assurance about whether the financial statements are free l of material misstatement. An audit includes examining, Cleveland, Ohio on a test basis, evidence supporting the amounts and February 14,1994 l l 1
M AN AG E M ENT'S ment and postemployment benerits. Dererred operating expenses decreased because of the write-otT of the phase-FIN ANCI 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.
1993 vs.1992 As discussed in Note 4(b), $583 million of our Perry i 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 oliin 1993. Credits for carrying charges I Minions recorded in nonoperating income decreased because of ! Increase iDecrease) in Operatine Revenues of Dollars the write-off of the phase-in deferred carrying charges in ; 1 Sales Volume and Mix $ 65 1993 as discussed in Note 7. The federal income tax i cre t for nonoperating income in 1993 resulted from the Ba{ Ras R s Total Q l The net revenue increase resulted primarily from the 1992 vs.1991 l different weather conditions and the changes in the com-Factors contributing to the 4.8% decrease m. 1992 operat-position of the sales mix among customer categories. ing menues are as foHows Weather accounted for approximately $53 million of the , j higher 1993 revenues. Hot summer weather in 1993 Decrease in Operatina Revenues o lars boosted residential, commercial and wholesale kilowatt- Sales Volume and Mix $ 79 ! hour sales. In contrast, the 1992 summer was the coolest ' Base Rates and Miscellaneous 32 in 56 years in Northern Ohio. Residential and commer. Fuel Cost Recovery Revenues _jj. cial sales also increased as a result of colder late-winter h*l .4_22_ 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 differ-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 offset 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 custorners. Base rates and much hatter 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 ofTset a decline in sales to other industrial customers. average of these factors increased slightly for The Toledo Other sales increased 2.3% bect.use 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 l Operating expenses increased 13.7% m. 1993. The m.erease order. No such revenues were reflected in 1992 as the m total operation and maintenance 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 (71 P), other charges totahng $54 milh,on 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-from higher environmental expenses, power restoration tized in 1991 and lower generation requirements stem-and repair expenses following a July 1993 storm in the ming from less electric sales. A reduction of $17 million 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 O
1 taxes decreased because of the amortization of certain tax achieve these objectives, we will continue controlling our benefits under the Rate Stabilitation 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-decreases were partially oliset by higher depreciation piement 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 federal income 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 Dhidends The federal income tax provision for nonoperating incorne 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 of interest 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 rehnancings at lower interest to be decided on a quarter-to-quarter basis after the l rates and lower short term borrowing requirements. evaluation of financial results, potential earning capacity
)
and cash flow. Outlook 73,30 ,,,givia,na ,,auces ou,cas3 ooifiow 3y a30ot l Recent Actions $120 million annually, which we intend to use to repay j debt more quickly than would otherwise be the case. This j In January 1994, we announced a comprehensive strate- will help improve our capitalization structure and interest i gic action plan to strengthen our financial and competi- coverage ratios, both of which are key measures consid- l 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 i While the plan has a long-term focus, it also required us debt, in turn, will lower our interest costs. to take some very dillicult, but necessary, financial ac-tions at that time. We reduced the quarterly common
,
- E" ""
stock dividend from $.40 per share to $.20 per share ellective with the dividend payable February 15, 1994. Our electric rates are among the highest in our region
'T his 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, son af rate. We also wrote off our investment in Perry Unit ; 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-ofTs are discussed in Notes lishing new systems and the expansion of an existing 4(b) and 1 We also recognized other one-time charges system. We have entered into agreements with some of totaling $39 million after taxes rehted to a performance the communities which considered establishing systems.
improvement plan for Ferry Unit 1, postemployment Accordingly, they will not proceed with such develop-benefits and other expense accruals. ment at this time in return for rate concessions and/or ec n mic development funds. Others have determined Also contributing to the net loss in 1993 was a charge of that developing a system was not feas,ble. i Cleveland
$87 million after taxes representing a portion of the \,TP .
" # "" "N""'.s to expand hs opuan. ons mto areas costs. We will realize approximately $50 million of savings in annual payroll and benefit costs beginning in "" .' .ve served exclusively W e have been successful m, retauung most of the large mdustrial and commercial 1994 as a result of the VTP.
customers m those areas by providing economic incent,ive packages in exchange for sole-supplier contracts. We Strateg,ic Plan also have similar contracts with customers in other areas. j The objectives of our strategic plan are to maximize share Most of these contracts have remaining terms of one # 1 owner return from corporate assets and resources, five years. We will continue to address municipal systen-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 our customers the value of our service and , attain increasingly competitive power supply costs. To the risks of a municipal system. 1 O
}
The Energy Policy Act of 1992 (Energy Act) will provide We externally fund the estimated costs for the future additional competition in the electric utility industry by decommissioning of our nuclear units. In 1993, we in-requiring utilities to wheel to municipal systems in their creased our decommissioning expense accruals for revi-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 wholesale 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 j Our Rate Stabilization Program remains in elTect. Under involvement in the cleanup of several other sites not on i this program, we agreed to freeze base rates until 1996 such list. The allegations that the Operating Companies l and limit rate increases through 1998. In exchange, we disposed of hazardous waste at these sites and the ] are permitted to defer through 1995 and subsequently amounts involved are often unsubstantiated and subject to 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 l 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.1lowever, we believe that the actual cleanup costs sures will be dependent 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 financial ac. Operating Companies have accrued a liability totaling $19 - tions and strategic plan also meluded 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 I the deferral of expenses and acceleration of benefits for such costs. We believe that the ultimate outcome of i under our Rate Stabilization Program are completed m. these matters will not have a material adverse elTect on 1995, we shnuld no longer plan to use regulatory account- our financial condition or results of operations. mg measures to the extent we have m the past. Tax Act Nuclear Operations Our three nuclear units may be impacted by activities or Thy Revenue Reconciliation Act of 1993 (1993 Tax ActL which was enacted in Augu 1993, provided for a events beyond our control. Operating nuclear generating
. 35% income tax rate m 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 alTect 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 row.
Nuclear Regulatory Commission (NRC) to limit or pro-hibit the operation or licensing of any nuclear unit. If one Inflation 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 eased 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 oilabor, 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.tali Resources and Liquidity extended outage of one of our nuclear units coupled with 19911993 Cash Requirements unfavorable rate treatment could have a material ad-verse elTect on our fmancial condition and results of We need cash for normal corporate operations, the operations. mandatory retirement of securities and an ongoing pro. O
l gram of constructing new facilities and modifying existing As discussed in Note ll(c), 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 construe. Centerior Energy Corporation (Centerior Energy) and tion and mandatory retirement needs totaled approxi- the Operating Companies to violate certain of those j mately $1,4 billion. In addition, we exercised various covenants. The affected creditors have waived those viola- l options to redeem and purchase approximately $900 mil- tions in exchange for our commitment to provide them i lion of our securities. with a second mortgage security interest on our property an ther considerations. We expect to complete this We raised $2.2 billion through security issues and term bank loans during the 1991 1993 period as shown in the Pmss m p sed quam of N We d proe &, s me secunty interest to certam other creditors because Cash Flows statement. During the three-year period, their agreements require equal treatment. We expect to the Operating Companies also utilized their short-terni 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-ofTs 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. Ilowever, 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 Operating 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 'neir 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 until it 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, addit onal securities may be redeemed under optional redemptlon cial paper because of their low commercial paper ratings i 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, flowever, 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 thE -icility available to us again after it is amended in the second quarter of 1994 to provide the participating creditors with a second mort-Liqu,dity i gage security interest. Additional first mortgage bonds may be issued by the These financing resources are expected to be sullicient for Operating Companies under their respective mortgages the Operating Companies' needs over the next several 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 financing 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 S&f M *W' issue approximately $78 million and $323 million of First mortgage bonds BH Ba2
" +
additional first mortgage bonds, respectively. After the fourth quarter of 1994, Cleveland Electric's ability to
"[d u B j
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 alTected by the write-offs recorded at December 31,1993. Operating Companies. O
INCOME STATEMENT canserio, enerar corporarion ans sussisiarias For the years ended December 31. 1993 1992 1991 (millions of dollars, except per share amounts) Operating Revenues $2.474 $2.438 $2.560 Operating Expenses Fuel and purchased power 474 473 500 Other operation and maintenance 811 784 801 Early retirement program expenses and other __222 - - 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 2.161 1.901 1.981 Operating lacome 313 537 579 Nonoperating income (Loss) l ! Allowance for equity funds used during construction 5 2 9 ! Other income and deductions, net (6) 9 6 l Write-olT of Perry Unit 2 (583) - - Deferred carrying charges, net (649) 100 110 l Federal income taxes - credit (expense) 398 (7) (30) (835) 104 95 income (Loss) Before Interest Charges and Preferred Dividends (522) 641 674 Inte:est Charges and Preferr. . 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) $_L943) $__212 $_231 Average Number of Common Shares outstanding (millions) 144.9 141.7 139.1 \ Earnings (Loss) Per Common Share $M 51) $ l.50 $_L11 r Dividends Declared Per Common Share $_L61 $ 1.60 $ 1.60 l I RETAINED E ARNINGS For the years ended December 31. l i 1993 1992 1991 (millions of dollars) Retained Earnings at Beginning of Year $ 652 $ 669 $ 655 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 (Deficit) at End of Year $ (521) $ 652 $ 669 The accompanying notes are an integral part of these statements. O
- . , . , v- . r- , m. . , _ , _ _ - _ . - ,.,3._ rr. .r., .ew_ . _ , _ . m ,--e., .-#. .. .
BALANCE SHEET l December 31. 1993 1992 (millions of dollars) ASSETS I Property, Plant and Equipment Utility plant in service $ 9,571 $ 9,449 Less: accumulated depreciation and amortization . 2.677 __2 483 , 6,894 6,961 Construction work in progress 181 167 Perry Unit 2 - 614 7,075 7,742 Nuclear fuel, net of amortization 344 385 Other property, less accumulated depreciation 41 39 7.460 8.166 Current Assets Cash and temporary cash investments 225 93 Amounts due from customers and others, net 221 222 Unbilled revenues 124 114 Materials and supplies, at average cost 136 129 Fossil fuel inventory, at average cost 32 65 Taxes applicable to succeeding years 250 247 Other 5 7 993 877 Deferred Charges and Other Assets Amounts due from customers for future federal income taxes 968 975 Unamortized loss from Beaver Valley Unit 2 sale 105 110 Unamortized loss on reacquired debt 92 101 Carrying charges and operating expenses 862 1,533 Nuclear plant decommissioning trr !s 56 42 Other 174 267 2.257 3.028 Total Assets $10J10 112All The accompanying notes are an integral part of this statement. O
I Centerior Energy Corporation and Subsidiaries December 31. 1993 1992. , (millions of dollars) l CAPITAllZATION AND LIABILITIES Capitali:ation Common shares, without par value (stated value of $345 million and $274 million for 1993 i 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 j With mandatory redemption provisions 313 364 l , Without mandatory redemption provisions 451 354 ; Long-term debt 4.019 3.694 l l 6,M8 7.301 I l Other Noncurrent Liabilities , Nuclear fuel lease obligations 254 303 i Other 195 119 l 449 422 Current Liabilities l Current portion of long-term debt and preferred stock 127 368 i Current portion of nuclear fuellease obligations 111 118 j Notes payable to banks and others - 50 Accounts payable 188 143 Accrued taxes 378 368 l Accrued interest 87 84 , Other 75 59 ' 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 3.158 Total Capitalization and Liabilities $10.710 $12.071 O
CASH FLOWS cenacria, enerar corporazion ans sussisiaries For the years ended December 31. _L931 _L9.1 1991 (millions of dollars) l Cash Flowsfrom Operating Activities (1) Net Income (Loss) $ (943) $ 212 $ 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 quity funds used during construction (5) (2) (9) Noncash early retirement program expenses, net 208 - - Write-off 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 afTecting operations 25 8 19 Other noncash items 18 3 1 Total Adjustments 1.460 307 299 Net Cash from Operating Activities $17 519 536 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 1 (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) (1) Net Cnh from Financing Activities _(124) (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 - (13) - 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 __$1 Cash and Temporary Cash investments at End of 1' ear $_22$ $ 91 5 177 (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. O
STATEMENT OF PREFERRED STOCK c cenuaior enere o,mraaon ans sussisiaries Current 1993 Shares Call Price December 31. Outstanding, Per Sharg_ 1991 .1999 1 CLEVELAND 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 9.125 Series N 600,000 103.04 59 74 91.50 Series Q 75,000 - 75 75 88.00 Series R 50,000 - 50 50 90.00 Series S 75,000 - 74 74 314 343 Less: Current maturities __29 _ 29
< 285 _1M i Not subject to mandatory redemption: 500,000 50 50
$ 7.40 Series A 101.00 7.56 Series B 450,000 102.26 45 45 a Adjustable Series L 500,000 103.00 49 49 Remarketed Serics P - - -
9 42.40 Series T 200,000 - 97 - 241 153 l Less: Current maturities - 9 _241 144 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 l Less: Current maturities __12 12 28 50 Not subject to mandatory redemption:
$100 par $ 4.25 160,000 104.625 16 16 4.56 50,000 101.00 5 5 4.25 100,000 102.00 10 10 ! 8.32 100,000 102.46 10 10 7.76 150,000 102.437 15 15 7.80 150,000 101.65 15 15 10.00 190,000 101.00 19 19 25 par 2.21 1,000,000 25.25 25 25 l 2.365 1,400,000 27.75 35 35 l Series A Adjustable __ 1,200,000 25.75 30 30 i Series B Adjustable __ 1,200,000 25.75 __.10 30
_210 210 i CENTERIOR ENERGY
- Without par value, 5,000,000 preferred shares authorized, none outstanding - -
Total Preferred Stock, with Mandatory Redemption Provisions $10 $164 Total Preferred Stock, without Mandatory Redemption Provisions $4.11 $3L4 The accompanying notes are an integral part of this statement. O i 1 l
NOTES TO THE ^ ruel factor is added to the base rates for electric service.
*' I" ' i' d"i 8
"*d ' '** "* ""* '"*"* 9 t h e l FINANCI AL STATEMENTS costs of fuel and most purchased power. It is reviewed nd djusted semi nnually in PUCO proceeding.
(1) Surnmaiy of Significant Accounting Policies (c) Fuei Expense (a) General The cost of fossil fuel is charged to fuel expense based on Centerior Energy is a holding company with two electric nventory 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 financial 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. cwned subsidiary, Centerior Service Company (Service Company), and Cleveland Electric's wholly owned sub. The Operating Companies defer the differences between sidiaries. The Service Company provides management, actual fuel costs and estimated fuel costs currently being financial, administrative, engineering, legal and other ser. recovered from customers through the fuel factor. This vices at cost to Centerior Energy and the Operating matches fuel expenses with fuel-related revenues. Companies. The Operating Companies operat: as sepa- Owners of nuclear generating plants are assessed by the I rate companies, each serving the customers in its service federal government for the cost of decontamination and l area. The preferred stock, first mortgage bonds and other decommSsioning of nuclear enrichment facilitiu 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 l consolidation. more than 15 years. The Operating Comnanies 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 Operatmg i 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) 71 which governs accounting for the effects of certain (d) Deferred Carrying Charges 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, j members arc Duquesne Light Company, Ohio Edison are $17 million which began in January 1989 and will l 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 (h) Resenues phase-in plans for their investments in Perry Unit I and Beaver Valley Unit 2. These deferrals, called phase-in Customers are billed on a monthly cycle basis for their deferrals, were written off 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 Con.panies 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 l billed by the end of that month. Notes 7 and 14. O
(c) 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- Property, plant and equipment are stated at original cost ciable utility plant in service was 3.5% in 1993 and 3.4% less amounts ordered by the PUCO to be written off. in both 1992 and 1991. Effective January 1,1991, the Construction costs include related payroll taxes, pen-Operating Companies, after obtaining PUCO approval, si ns, fringe benefits, management and general ov:rheads changed their method of accounting for nuclear plant and allowance for funds used during construction depreciation from the units-of-production method to the (AFUDC). AFUDC represents the estimated composite straight-line method at about a 3% rate. This change debt and equity cost of funds used to finance construction. decreased 1991 depreciation expense $36 million and This noncash allowance is credited to income. The AFUDC rates averaged 9.9% in 1993,10.8% in 1992 and increased 1991 n.t income $28 million (net of $8 million of income taxes) and earnings per share $.20 from what 10.7% in 1991. they otherwise would have been. The PUCO subse- Maintenance and repairs are charged to expense as in-quently approved in 1991 a change to lower the 3% rate to curred. The cost of replacing plant and equipment is 2.5% retroactive to January 1,1991- charged to the utility plant accounts. The cost of property Pursuant to a PUCO order, the Operating Companies retired plus removal costs, after deducting any salvage currently use external funding for the future decommis, value, is charged to the accumulated provision 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 discussed 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. Ilowever, actual sale of Beaver Valley Unit 2. The net gam 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 accruals in 1993. It is expected that the increases demption of long-term debt are deferred, consistent with associated with the revi.;ed 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 an.ortized over the remainder of the originallife 31, 1993, Accumulated Depreciation and Amortization of the debt issue retired or amortized over the life of the included S74 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. O l - -
(1) Feder:1 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 l standard in 1992. The standard amended certain provi. purchase options along with conditions for mandatory l l sions of SFAS 96 which we had previously adopted. termination of the leases (and possible r: purchase of the Adoption of SFAS 109 in 1992 did not materially affect leasehold interests) for events of default. Then events our results of operations, but did affect certain Balance include noncompliance with several financial covenants ! Sheet accounts. See Note 8. discussed in Note ll(e). l The financial statements reflect the liability method of in April 1992, nearly all of the outstanding Secured Lease l accounting for income taxes. This method requires that Obligation Bonds (SLOBS) issued by a special purpose deferred taxes be recorded for all temporary differences 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 differences are attributa- through a tender offer and the sale of new bonds having a ble to property-related basis differences. Included in lower interest rate. As part of the refmancing transaction, these basis differences 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 through rates. Since this component 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 l our tax obligation. The PUCO permits recovery of such transaction reduced the annual rental expense for the l j taxes from customers when they become payable. There- Beaver Valley Unit 2 lease by $9 million. l 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 summarir i as follows: Year
--- -Amount Investment tax credits are deferred and amortized over (nmns of the lives of the applicable property as a reduction of dollars) depreciation expense. See Note 7 for a discussion of the 1994 s 166 1W5 165 amortization of certain unrestricted excess deferred taxes tw6 188 l and unrestricted investment tax credits under the Rate 6
Stabilization Program. Later Years 3.412 (2) Utility Plant Sale and mai ruiure maimum tease earmena 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 29% 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, l Under these leases, the Operating Companies are respon- i l 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. O '
(3) Property Owned with Other Utilities and Investors The Operating Companies own, as tenants in common witi 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 tLe 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 OperatNg Companies'sh 3re of the operating expenses of these generating units is included in the Income Statement. The Balance Sheet classification of Property, Plant and Equipment at December 31,1993 incluces the following facilities owned by the Operating Companies as tenants in common with other utilities and Lessors: In- Plant Construction Service Ownership Ownership Power in Work in Accumulated Generatina Unit Date Share Megawatts Source Service Proeress Denreciation (millions of dollars) Seneca Pumped Storage 1970 80.00% 351 Ilydro $ 67 $- $ 22 Eastlake Unit 5 1972 68.80 411 Coal I56 2 - Perry Unit i 1987 51.02 609 Nuclear 2,832 11 473 Beaver Valley Unit 2 and Common Facilities (Note 2) 1987 26.12 214 Nuclear 1.480 _1 ,,.2_51 Total $4.535 Q q Depreciation for Eastlake Unit 5 has been accumulated with all other nonnuclear depreciable property rather than by specific units of depreciable p'operty. strategy. If a dilTerent plan is required by the U.S. EPA, (4) Construction and significantly higher capital expenditures could be re-Contingencies quired during the 1994-2003 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 w hen construction was suspended in 1985 pending con-two phases over a teng ear 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 ownership share, or cancellation. greater use oflow-sulfur coal at some of our units and the We wrote otT 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-oft totaled $583 million proximately $222 million for nitrogen oxide control ($425 million after taxes) for our 64.76% ownership share equipment, emission monitormg 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) llazardous 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 List 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 ur P lan. a6 verse effect 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. O
(5) Nuclear Operations and total amount of financing currently available under these lease arrangements is $382 million ($232 million from ContinOencies . 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 I unfavorable rate treatment, could have a material ad, of nuclear fuel was financed. The Operating Companies verse efTect on our financial condition and results of severally lease their respective portions of the nuclear fuel and are obligated to pay for the fuel as it is consumed operations. See di:cussion of these risks in Management's 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. i
)
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 fina,ced 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 incident. 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 and 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 cludes the incremental cost of any replacement power by 1998. pun.hased (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 week during follow pursuant to PUCO orders. We concluded that 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 week 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 oft the substantially exceed the insurance coverage. cumulative balance of the phase in deferrals. The total phase-in deferred operating expenses and carrying l (6) Nuclear Fuel charges written off at December 31,1993 were $172 i 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 6 w
In August 1993, the 1993 Tax Act was enacted. Retroac- In 1993, we offered 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 not 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 differences and carryfor- 1993 were comprised of the following components: wards resulted in deferred tax assets of $619 million and l991 E 1991 (millions of dollars) deferred tax liabilities of $2.198 billion at December 31, Pension costs (crediis): 1993 and deferred tax assets of $563 million and de. Service cost for benefits earned during the ferred tax liabilities of $2.598 billion at December 31, int 7rNsYcost on projected benefit 1992. These are summarized as follows: obligation 37 38 36 Decm W 31 Actual return on plan assets (65) (24) (129) y993 Net amortization and deferral _3 _{45) 65 999f (millions of Net pension costs (credits) (9) (16) (14) dollars) VTP cost 205 - - Property. plant and equipment $1,845 $2.125 Settlement gain L81) _- - DcIerred carrying charges and operating expenses _._ 206 368 Net costs (credits) M g) $_114) Net operating loss carr> forwards (108) (137) Investment tax credits (183) (190) The following table presents a reconciliation of the funded Other _.LI.81 ) (131) status of the plan (s) at December 31,1993 and 1992. Net deferred tax liability $M29 12 nM g g (millions of For tax purposes, net operating loss (NOL) carr> forwards Actuarial present value of 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 _J1 _4_0
. Accumulated benefit obligation 370 350 2005. The 35% tax effect of the NOLs is $108 million. ErTect or future compensation levels _D _n1 Total projected benefit obligation 423 471 The Tax Reform Act of 1486 provides for an alternative Plan assets at fair market value JJ8fr _n4 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 (gain) from variance
*****" """*P" ""d **P*"*"** " U# I exceed the AMT. AMT credits of $171 million are Unrecognized prior service cost 10 12 available to offset future regular tax. The credits may be Transition asset at January 1,1987 being amortized carried forward indefinitely. over 19 years _tal) 129)
Net prepaid pension cost (accrued pension liability) included in other deferred charges (*'*d) '" 'h* ""'""ce sheet it5_9) 1. 16 (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 r te f 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 w s 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. O
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 nica- (8) Federal Income Tax ) sures to the extent we have in the past. I Federal income tax, computed by multiplying the income ! 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% m growth in our service area by freezing base rates until both 1992 and 1991),is reconciled to the amount of j 1996 and limiting subsequent rate increases to specified federal income tax recorded on the books as follows: I annual amounts not to exceed $216 million for Cleveland 1993 L992 L991 Electric and $89 million for Toledo Edison over the (millions or dollars) 8 k Incane a ss) Before rederal Income 1996-1998 Eeriod' Tax $Lt 26J) $M $466 l i As part of the Rate Stabilization Program, the Operating Tax (Credit) on Book Income (Loss) at j Statutory Rate $ (442) $138 $158 Companies are allowed to defer and subsequently recover increase (Decrease) in Tax: l certain costs not currently recovered in rates and to write-otr or Perry Unit 2 46 - - accelerate amortization of certain benefits. Such regula- write-orr or 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) - and the amortization of certain benefits during the 1992- Other items 17 _1 __9 Total Federal lncome Tax Expense (Credit) ., $ (387) $L2_9 $168 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: 4 recovery of such deferrals in future rates. 1993 1992 1991 j (millions or dollars) The regulatory accounting measures we are eligible to Operating Expenses: i C""'"' I** "' "i'i " 8 9' I 7I 5 88 record through December 31,1995 include the deferral of
. . . . Changes in Accumulated Deterred Federal post-m-service mterest carrying charges, depreciat. ion ex- Income Tax:
pense and property taxes on assets placed in service after Write-off or deferred operating expenses. (39) - - February 29,1988 and the deferral of Toledo Edison Accelerated depreciation and operating expenses equivalent to an accumulated excess 3,[,,,t n]nimum tax credit ( 7) (3 ) ( 6) rent reserve for Beaver Valley Unit 2 (which resulted Retirement and postemployment from the April 1992 refinancing of SLOBS as discussed bener ts (43) - - Sale and leaseback transactions and in Note 2). The cost deferrals recorded in 1993 and 1992 amortization 9 8 4 pursuant to these provis. ions were $95 million and $84 Taxes, other inan rederal 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 Deterred fuel costs (2) (1) (9) 30 years, and will commence with future rate recognition. Other items (14) 3 23 The regulatory accounting measures also provide for the
' " * * " * * " ' *
- Cd - -
Total Charged to Operating Expenses 11 122 138 accelerated amortizat. ion of certain unrestricted excess Nonoperating Income: deferred tax and unrestricted .mvestment tax credit bal- Current Tax Provision (34) (38) (46) ances and interim spent fuel storage accrual balances for Changes in Accumulated Dererred Federal Davis-Besse. The total amount of such regulatory bene. Income Tax: fits recognized in 1993 and 1992 pursuant to these write- fr or deferred carrying charges _ (240) - - provisions was $46 million and $12 million, respectively.
"" ' ~
j d r co O s - Rate StaMzation Pmgrarn H H - The Rate Stabilization Program also authorized the Op-Al UDC and carrying charges 12 24 41 erating Compades to defer and subsequently recover the Nei operating loss carryrorward (7) - 35 incremental expenses associated with the adoption of Other items (2) (4) - the accounting standard for postretirement benefits other Total Expense (Credit) to than pensions (SFAS 106). In 1993, we deferred $96 Nonoperating Income _.(M) 7 30 million pursuant to this provision. Amortization and Total rederal Income Tax Expense (Credit) ., $1)!2) $_L29 $ 168 O
l l (b) Other Postretirement Benefits were 7.25% and 4.25%, respectively. The assumed annual l l We sponsor a postretirement benefit plan which provides health care cost trend rates (applicable to gross cligible all employee groups certain health care, death and other charges) are 9.5% for medical and 8% for dental in 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 a!Tected 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 heahh care cost trend rate than other elements. If the l employees retiring after March 31, 1993 was imple, assumed health care cost trend rates were increased by l 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 accounting standard for
- crease by $11 m.lh.oni and the aggregate of the service and postretirement benefits other than pensions, efTect.ive 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. l expected costs of such benefits during the employees' l 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, which included medical benefits of benefit costs. Postemployment benefits are the benefits $3 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 benefits and severance pay. The adoption l million was expensed as other operation and mamtenance of this accounting method did not materially alrect our I expenses. In 1993, we deferred incremental SFAS 106 l 1993 results of operations or financial position.
expenses totaling $96 million pursuant to a provision of ) the Rate Stabilization Program. See Note 7. J The components of the total postretirement benefit costs (10) Guarantees 1 for 1993 were as follows: Cleveland Electric has guaranteed certain loan and lease Service cost for benenis earned [$ s3 obligations of two mining companies under two long-term coal purchase arrangements. Toledo Edison is also a ! Interest cost on accumulated postretirement benef t party to one of these guarantee arrangements. This bHgation 16 arrangement requires payments to the mining company
' 8 '" for ny actual expenses (as advance payments for coal) ^N"n'it$on o cr" a 8 VTP curtailment cost (includes $16 million transition when the mines are idle for reasons beyond the control of obligation adjustment) _M the mining company. At December 31,1993, the princi-Total costs MI 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: Millions (ll) Cap. ital.lZal.lOn gf Dollars Accumulated postretirement benefit obligation (a) Capital Stock Transactions attributable to: Shares sold, retired and purchased for treasury during the l u ly eligIblac e plan participants *
- Y* * * * ' "'"
Other active plan participants (28) following tables. Accumulated postretirement benefit obligation (258) l (thousands 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 l noncurrent liabilities in the llalance Sheet $LI.01) 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 _.2fi 3 22) _02) term rate of annual compensation increase assumptions Net Increase LIM 2m 71n L75.L9 l l i
1993 j]91 1991 (c) Equit) Distribution Restrictions (thousands of shares) Preferred Stock of Subsidiaries Subject t 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,
~
*M!eN*e S 2 5 which are held solely by Centerior Energy. Federal law Cleveland Electric Retirements prohibits the Operating Companies from paying divi-8 ! sb ) ($) l dends out of capital accounts. Ilowever, the Operating 75.00 Series F - -
(2) Companies may pay preferred and common stock divi-1 !e sK 2 2 oj dends out of appropriated retained earnings and current Adjustable Series M (100) (100) (100) earnings. At December 31,1993, Cleveland Electric and i 9.125 Series N (150) Toledo Edison had $125 million and $42 million, re- I Toledo Edison Retirements 5100 par $11.00 - (25) (10) spectively, of appropriated retained earnings for the pay-9375 (17) (17) (17) ment of dividends, llowever Toledo Edison is prohibited i
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Preferred St k of Su sidiaries Not from paying a common stock dividend by a provision in its Subject to Mandatory Redemption: mortgage. Cleveland Electric Sales Cl veland e e Retirements e e an e crence hck Amounts to be paid for prefared stock which must be Ne e rease) 18 )' _ ) redeemed during the nen five years are $40 million in Shares of common stock required for our stock plans in 1994,$51 million in 1995, $41 millicn 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 es The Board of Directors has authorized the purchase in the follows: open market of up to 1,500,000 shares of our common Sha s To P ce stock until June 30,1994. As of December 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. 5 735 Series C 10,000 1984 s 100 88.00 Series E 3,000 1981 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 1,962,174 and 469,457 shares, respectively, at December 88.00 Series R - 50.000 2uol? 1,000 31,1993. m Se&s S m,no N W Toledo Edison Preferred: Stock options to purchase unissued shares of common $ioo pa, $9.375 16,650 1985 100 stock under the 1978 Key Einployee 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 purchased during the three years 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 ces 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 Shares 37,627 93.312 129,798 $68 million. Option Prices $14.09 to $14.09 to $14.09 to
$20.73 $20.73 520.73 The preferred dividend rates on Cleveland Electric's Se-ries L and M and Toledo Edison's Series A and B fluctuate based on prevailing interest rates and market conditions. The dividend rates for these issues averaged 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 1
Preference stock authorized for the Operating Companies The mortgages of the Operating Companies constitute l are 3.000,000 shares without par value for Cleveland direct first liens on substantially all property owned and i 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, l 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 l (e) Long-Term Debt and Other secured financing other than through first mortgage bonds ]
Borrowing Arrangements r certain other transactions. Two reimbursement agree- j ments relating to separate letters of credit issued in 1 Long-term debt,less current maturities, for the Operating connection with the sale and leaseback of Beaver Valley l Companies was as follows: Unit 2 contain several financial covenants alTecting Actual or Average Centerior Energy and the Operating Companies. Among iniresi g ,, these are covenants relating to fixed charge coverage December 31, December 31- ratios and capitalization ratios. The write-offs recorded at l Year of Maturity 1993 1993 199 December 31,1993 caused Centerior Energy and the
- dollars) Operating Companies to violate certain covenants con-rirst mortgage bonds
- tained in a Cleveland Electric loan agreement and the two 75% $ 5 25 reimbursement agreements. The affected creditors have 3
1995 13.75 4 4 waived those violations in exchange for our commitment 1995 7.00 1 1 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. 1%7 la88 6 6 We will provide the same security interest to certain 1997 13.75 4 4
,997 7gg , , other creditors because their agreements require equal 1997 6.125 31 31 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 2004-2008 8.14 260 264 2009-2013 7.68 436 436 ( 2) Shart-Term Borrowing 2014-2018 8.07 2019-2023 7.89 513 733 513 583 Arrangements 2.574 2.357 in May 1993, Centerior Energy arranged for a $205 Secured medium term notes due . 1995-2021 8.77 963 860 milh.on, 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 due 2002 8.70 135 135 Service Company may borrow under the facility, with all Po lution control notes due 1995-Wowings jointly and severally guaranteed by the Oper-Other - net - (8) 3 ating Companies. Centerior Energy plans to transfer any Total Long-Term Debt $4.019 $3&94 of its borrowed funds to the Operating Companies, while the Service Company may borrow up to $25 Long-term debt matures during the next five years as milli n f r its own use. The banks' fee is 0.5% per annum follows: $87 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 j 99g, 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 covenants 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 O
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 participalmg (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. million for Toledo Edison. The Operating Companies 0 3 , "8"5
, 3g ["d*d, are authorized by the PUCO to borrow from each other (minions or dollars, on a short-term basis, cucpt per share amounts) 1993 At December 31,1993, the Operating Companies had no Operating Revenues $598 $589 $709 $ 578 l 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 $ 34 $ 17 $(1,029) provide short-term funds because of their below invest- Average Common Shares I ment grade commercial paper credit ratings. (minions) 143.4 144.4 145.3 146.4 Earnings (Loss) Per Common Share $.25 $.23 $ .12 $ (7.02)
Dividends Paid Per (l3) Financial Instruments' Common Share $.40 $d $.40 $ .40 Fair Value i992 ( Operating Revenues $592 1581 $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 3L (milbons) 140.6 141.6 142.0 142.5 1993 1992 Earnings Per Common Carrying Fair Carrying Fair Share $ .16 $ .14 $ .86 $ .33 Amount ,y_al.u_y_ Amou.nl Mu.g. (millions of dollars) Nuclear Plant Decommissioning Trusts $ 56 $ 59 $ 42 $ 45 Earnings for the quarter ended September 30,1993 were Preferred Stock, with Mandatory Redemption Provisions decreased by $81 milh.on, or $.56 per share, as a result of (including current portion) 354 349 405 408 the recording of $125 million of VTP pension-related Long Term Debt (including benefits. current 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-off of Perry Unit 2 (see Note 4(b)), investment securities. The fair value of the Operating the $877 million write-off 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 $.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 ments approximate their carrying amounts in the Balance by the PUCO in October 1992. See Note 7. Sheet at December 31,1993 and 1992 because of their short-term nature. l - - -
EXECUTIVES OF CENTERIOR ENERGY COR PO R ATION Chairman, President and Chief Executive Officer Robert J. Farling (57) Vice President Tenence G. Linnert (47) Executive Vice President Afurray R. Edebnan (54) Controller Paul G. Busby (45) Senior Vice President Fred J. Lange, Jr (44) Treasurer Gary Af. Hasckinson (45) Vice President Gary R. Leidich (43) Secretary E. Lyle Pepin (52) l l l l EX EC UTIVES OF CENTERIOR SERVICE l COMPANY I Chairman, President and Vice President-Chief Executive Officer Customer Support Jacquita K. Hansennan (51) (and Chairman
& CEO of
^"" " "" "7 ' ' '#^
l Cleveland Electric i and Toledo Edison) Robert J. Farling (57) Vice President-
"E"'
Executive Vice President-omnmental AUaks ! Operations & Engineerino' and General Counsel 7errence G. Linnert (47; (and Vice Chairman of Toledo Edison Vice President - . and President of Transmission & Distribution Cleveland Electric) Afurray R. Edehnan (54) Operations David L Afonseau (53) Senior Vice President- Vice President-Fossil & Transmission and Nuclear-Perry Robert A. Stratman (45) ; l l Distribution Operations Vice President- j (and President Marketing Al R. Temple * (48) of Toledo Edison) Fred J. Lange, Jt: (44) Controller Paul G. Busby (45) Treasurer Garv Af. Haidinson (45) Senior Vice President- ' CMa7 E. Lyle Pepin (52) Nuclear Donald C. Shelton (60) l l l Number in parcruhesis indicates age. v) Elecant ellective iebnwry 28,19YJ. l l i
FI N A N C I A L. A N D STATISTICAL REVIEW Operating Revenues (millions of dollars) Steam Total Total Total lleating Operating f Year Residential Commercial Industrial Other Retail Wholesale Electric & 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 1723 Operating Expenses (millions of dollars) Other Deferred ' Fuel & Operation Depreciation Taxes, Operating Federal Total Purchased & & Other Than Expenses, Income Operating Year Power klaintenance Amortization FIT 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 1 922 1989 473 860 273 260 (59) 122 1929 1983 464 384 145 172 -- 184 1 349 Income (Loss) (millions of dollars) Federal Income Other Deferred . Income (Loss) Income & Carrying Tax- Before Operating AFUDC- Deductions, Charges. Credit Interest Debt Year income Equity Net Net ( Expense) - Charges Interest 1993 $313 5 (589)(d) (649)(b) 398 (522) 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 AFUDC- Stock Income Outstanding Earnings Stock Dividends Book Year Debt Dividends ( Loss) (millions) (Loss) Equity Declared Value 1993 $ (5) 67 $(943) 144.9 $(6.51) (40.3)% $ 1.60 $12.14 i 1992 (1) 65 212 141.7 1.50 7.4 1,60 20.22 l 237 1,71 1991 (5) 61 139.1 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 3% 98.2(e) 3.ll(c) 15.7 2.19(e) 20.24(e) 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. (b) Includes write-off of phase-in deferrals of $877 million in 1993, consisting of $172 million of deferred operating expenses and $705 million of deferred carrying charges. (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. O w _1
Centerior Energy Corporation and Subsidiaries Electric Sales (millions of KWH) Electric Customers (year end) Residential Usage Average Average Average Price Revenue Industrial K%il Per Per Per Year Residential Commercial Industrial Wholesale Other Total Residential Commercial & Other Total Customer KWil Customer 1993 _ _ 6 974 7 306 11687 3 027 1 022 30 016 924 227 96 491 12 219 1 032 937 7 546 11.01c $830.99 1992__ 6 666 7 086 11 551 2 814 1 011 29 128 925 099 96 813 12 741 1 034 653 7 227 10.98 793.68 1991 __ 6 981 7 176 11 559 2 690 1 048 29 454 921 995 96 449 12 843 1 031 287 7 410 11.16 827.10 l 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 1939 _ 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 11 557 983 350 6 967 8.64 603.22 l Load (MW & %) Energy (millions of KWH) Fuel Operable Company Generated Purchased fuel Cost th[ t e Peak Capacity Load Year of Peak Load Margin Factor Fossil Nuclear Total Power Total Per KWil KWit 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 l 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
- 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)
Construction Work in Total Utihn Accumulated Progress Nuclear Property. Utihty Plant In Depreciation & Net & Pery iveland Plant and Plant Total Year Service Amortisatmn Plani Umt . Other Equipment Additions Awets 1993 $9 571 2 677 6 894 181 385 $7 460 $218 $10 710 l992 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 11 829 1990 8 636 2 039 6 597 921 568 8 086 251 11681 1939 8 398 I 824 6 574 945 592 8 111 217 11454 1983 4 180 1 047 3 133 2 710 392(f) 6 235 785 6 922 Capitalization (millions of dollars & %) ; I Preferred & Preference Preferred Stock. without Stock, with Mandatory Mandatory Redemption Year Common Stock Equity Redemption Provisions Provisions Long-Term Debi Total 1993 $1785 27% 313 5% 451 7% 4 019 61% $6 568 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 3 477 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-otT of Perry Unit 2 of $583 rnillion in 1993. te) Average shares outstanding and related per share computations reflect the Cleveland Electric 1.ll-for-one exchange ratio and the Toledo Edison one-for-one exchange ratio for Centerior Energy shares at the date of affiliation, April 29,1986. (f) Restated for effects of capitalization of nuclear fuel lease and financing arrangements pursuant to Staternent of I'inancial Accounting Standards 71. l C
BO A RD OF DIR ECTORS RichardIt Anderson (64) President and Chief Executive George H. Kaull(62) Retired Chairman of Premix, Inc., Officer of The Andersons Management Corporation, a a developer, manufacturer and febricator of thennoset grain, farm supply and retailing firm.1986 reinforced composite materials.1987 Albert C. Rcrsticker (59) President and Chief Executive Richard A. 3 filler (67) Retired Chainnan and Chief Officer of Ferro Corporation, a producer of specialty Executive Officer 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 j chemicals, plastics and aerospace products. Retired refiner of petroleum products.1986 l Chairman of Tremco, incorporated, a manufacturer of Sister Afary Afarthe Reinhard, SND (64) Director of specialty chemical products and a wholly owned Development for the Sisters of Notre Dame of Cleveland, subsidiary of The BFGoodrich Company.1986 Ohio. Fonner President of Notre Dame College of Ohio.1986 Thomas A. Commes (51) President and Chief Operating Robert C. Sarage (56) President and Chief Executive Officer of The Sherwin-Williams Company, a ' Officer of Savage & Associates, Inc., an insurance, manufacturer of paints and painting supplies.1987 financial planning and estate planning firm.1990 Wayne R. Embry (56) Executive Vice President and j,aul 31. Smart * (65) Attorney and retired Vice Chairman General Manager of the Cleveland Cavaliers, a professional of the Company and The Toledo Edison Company.1986 basketball team. Chairman of Michael Alan Lewis Company, a fabricator of hardboard, fiberglass and Hilliam J. H7/liams (65) Retired Chairman of fluntington carpeting materials for the automotive industry.1991 National Bank.1986 Robert J. Farling (57) Chairman, President and Chief Executive Oflicer of the Company and Centerior Service Robert 31. Ginn Chairman Emeritus Company.1988 John It H7#iamson Chairman Emeritus Nwnher in parenthesis indicates age. Date indicates first year in which elected to Board. ( *) Retiredfrom the floard on Amuarv 31.1Y94. COMMITTEES O F T il E B O A R D Environmental Capital and Community Executive lhonan Audit Expenditures Responsibility and Nominating Finance Resomres Nuclear l T. A. Commes, G.H. Kaull, Sr. M.M. Reinhard, R.J. Farling, R.A. Miller, EE. Mosier, R.P. Anderson, l Chairman Chairman Chairman Chairman Chairman Chairman Chairman l R.P. Anderson A.C. Bersticker W.R. Embry L. Carter L. Carter W.R. Embry A.C. Bersticker L. Carter R.A. Miller R. A. Miller T.A. Commes T.A. Commes G.H. Kaull R.J. Earling W.R. Embry EE. Mosier EE. Mosier R.A. Miller R.J. Farling R.C. Savage Sr. M.M. Reinhard Sr. M.M. Reinhard P.M. Smart
- P.M. Smart
- W.J. Williams EE. Mosier W.J. Williams W.J. Williams R.C. Savage P.M. Smart *
(*) Retiredfnnn the Board on Amuary 31,1994. l l 6 w L. . .. . ..
. _ _ _ _ _ _ _ _ _ a
1 SH ARE OWNER IN FO R M ATION Dividend Reinvestment and Stock Registrar Purchase Plan and Individual Retirement Society National Bank Cmporate Tmu ohision Account (CX IRA) P.O. Box 6477 l The Company has a Dividend Reinvestment and Stock Cleveland, OH 44101 i Purchase Plan which provides share owners of record and customers of the Company's subsidiaries a convenient Executive OfTices l 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 (IR A) which Telephone:(216) 447-3100 invests in Company common stock through the Plan. FAX: (216) 447-3240 Information relating to the Plan and the CX+ IRA may be obtained from Share Owner Services at the Company. Mail Address Centerior Energy Corporation CX IRA Custodian P.O. Box 94661 All communications about an existing CX+1RA should Cleveland, OH 44101-4661 l be directed to the Custodian at the address or telephone numbers listed below: Independent Accountants Society National Bank Arthur Andersen & Co. Custodian, CX+ IRA 1717 East Ninth Street P.O. Box 6477 Cleveland, OH 44114 Cleveland, OH 44101 In Cleveland area 737-5745 Listed on the New York., Midwest and Pacific Stock Elsewhere in Ohio 1-800-362-0697, Extension 5745 Exchanges. Options are traded on The Pacific Stock Outside Ohio 1-800-321-1355, Extension 5745 Exchange. New York Stock Exchange symbol-CX. Newspaper abbreviation-CentEn or CentrEngy. Share Owner Services C,ommunications regarding stock transfer requ.irements, Annual Meeting lost certificates, dividends and changes of address should The 1994 annual meeting of the share owners of the be directed to Share Owner Services at the Company. To Con pany will be held on April 26,1994. Owners of reach Share Owner Services by phone call: common stock as of Febn..'ry 25,1994, the record date for the meeting, will be eligitWe to vote on matters in Cleveland area 642-6900 or 447-2400 brought up for share owners' consideration. l Outside Cleveland area 1-800-433-7794 ! E,nv.ironmental Report Please have your account number ready when calling. The Company will furnish to share owners, without charge, a copy of a report on its environmental performance. l Investor Relations Requests should be directed to Share Owner Services. l 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, address or by telephone at (216) 447-2882. a copy of its most recent annual report to the Securities and Euhange Comminion. RequeMWmuld be diruted Transfer Agent , to Share Owner Services. l l Centerior Energy Corporation l Share Owner Services Audio Cassettes RO Box 94661 l Cles\ eland, OH 44101-4661 Share owners with impaired vision may obtain audio i 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. l 5 Hanover Square,10th Floor New York, NY 10004 O
Centerior Energy Corporation P.O. Box 94661 Cleveland, Oli 44101-4661 l 1
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASillNGTON, D.C. 20549 Form 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF TIIE SECURITIES EXCIIANGE ACT OF 1934 (FEE REQUIRED) For the fiscal year ended December 31,1993 OR [] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF Tile SECURITIES EXCilANGE ACT OF 1934 (NO FEE REQUIRED) For the transition period from to Commission Registrant: State of Incorporation; 1.R.S. Employer File Number Address; and Telephone Number Idchdrication No. 1-9130 CENTERIOR ENERGY CORPORATION 34-1479083 (An Ohio Corporation) 6200 Oak Tree Boulevard Independence, Ohio 44131 Telephone (216) 447-3100 1-2323 THE CLEVELAND ELECTRIC ILLUMINATING 34-0150020 COMPANY (An Ohio Corporation) 55 Public Square Cleveland, Ohio 44113 Telephone (216) 622-9800 1-3583 THE TOLEDO EDISON COMPANY 34-4375005 (An Ohio Corporation) 300 Madison Avenue Toledo, Ohio 43652 Telephone (419) 249-5000 Indicate by check mark whether each of the registrants (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No _. Indicate by check mark if disclosure of delinquent filers pursuant to item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part 111 of this Form 10-K or any amendment to this Form 10-K. [X] The aggregate market value of Centerior Energy Corporation Common Stock, without par value, held by non-affiliates was $1,754,200,163 on February 28,1994 based on the closing sale price of $11.875 as quoted for that date on a composite transactions basis in The WallStreet Journaland on the 147,722,119 shares of Common Stock outstanding on that date. Centerior Energy Corporation is the sole holder of the 79,590,689 shares and 39,133,887 shares of the outstanding common stock of The Cleveland Electric Illuminating Company and The Toledo Edison Company, respectively.
Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange Registrant Title of Each Class on Which Registered Centerior Energy Common Stock, Corporation without par value New York Stock Exchange Chicago Stock Exchange Pacific Stock Exchange The Cleveland Electric Cumulative Serial Preferred Illuminating Company Stock, without par value:
$7.40 Series A New York Stock Exchange
$7.56 Series B New York Stock Exchange Adjustable Rate, Series L New York Stock Exchange Depository Shares:
1993 Series A, each share l representing 1/20 of a share of Serial Preferred Stock, $42.40 Series T (without par value) New York Stock Exchange First Mortgage Bondc 4-3/8% Series due 1994 New York Stock Exchange 8-3/4% Series due 2005 New York Stock Exchange 9-1/4% Series due 2009 New York Stock Exchange 8-3/8% Series due 2011 New York Stock Exchange ; 8-3/8% Series due 2012 New York Stock Exchange 4 The Toledo Edison Cumulative Preferred Stock, Company par value $100 per share i 4-1/4% Series American Stock Exchange 8.32% Series American Stock Exchange 7.76% Series American Stock Exchange 10% Series
- American Stock Exchange j
- l Cumulative Preferred Stock, l l par value $25 per share ,
l 8.84% Series New York Stock Exchange !
$2.365 Series New York Stock Exchange Adjustable Rate, Series A New York Stock Exchange i Adjustable Rate, Series B New York Stock Exchange l
$2.81 Series New York Stock Exchange ;
i First Mo cgage Bonds: 7-1/2% 'eries due 2002 New York Stock Exchange 8% Seri i due 2003 New York Stock Exchange i i
Securities registered pursuant to Section 12(g) of the Act: Registrant Title of Each Class Centerior Energy None Corporation The Cleveland Electric None Illuminating Company 1 l l The Toledo Edison Cumulative Preferred Stock, Company par value $100 per share: I 4.56% Series and 4.25% Series )
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DOCUMENTS INCORPORATED BY REFERENCE Part of Form 10-K Into Which Document Description Is Incorporated l Portions of Proxy Statement of Centerior Energy Corporation, dated March 23, 1994 Part III l I ( l
TABLE OF CONTENTS Page Number Glossary of Terms iv PART I Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . 1 The Centerior System . . . . . . . . . . . . . . . . . . . . . . 1 3 CAPCO Group . . . . . . . . . . . . . . . . . . . . . . . . . . 2 ft Construction and Financing Programs . . . . . . . . . . . . . . 3 Construction Program . . . . . . . . . . . . . . . . . . . . . 3 Financing Program . . . . . . . . . . . . . . . . . . . . . . 5 General Regulation . . . . . . . . . . . . . . . . . . . . . . . 5 Holding Company Regulation . . . . . . . . . . . . . . . . . . 5 State Utility Commissions . . . . . . . . . . . . . . . . . . 6 Ohio Power Siting Board . . . . . . . . . . . . . . . . . . . 7 Federal Energy Regulatory Commission . . . . . . . . . . . . . 7 Nuclear Regulatory Commission . . . . . . . . . . . . . . . . 7 Other Regulation . . . . . . . . . . . . . . . . . . . . . . . 7 Environmental Regulation . . . . . . . . . . . . . . . . . . . . 8 General . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Air Quality Control . . . . . . . . . . . . . . . . . . . . . 8 Water Quality Control . . . . . . . . . . . . . . . . . . . . 9 Waste Disposal . . . . . . . . . . . . . . . . . . . . . . . . 10 t Electric Rates . . . . . . . . . . . . . . . . . . . . . . . . . 10 Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Sales of Electricity . . . . . . . . . . . . . . . . . . . . . 11 Operating Statistics . . . . . . . . . . . . . . . . . . . . . 12 Nuclear Units . . . . . . . . . . . . . . . . . . . . . . . . 12 Competitive Conditions . . . . . . . . . . . . . . . . . . . . 14 General . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Cleveland Electric . . . . . . . . . . . . . . . . . . . . . 15 Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . 16
1 E 4^ a 1 1 Page ' Number 17 Fuel Supply . . . . . . . . . . . . . . . . . . . . . . . . . 7 17 Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . 18 Nuclear . . . . . . 19
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4 Executive Officers of the Registrants and the Service Company . 20
. . . . . . . . . . . . . . . . 26 l Item 2. Properties . . . . . .
26 General . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . 26 The Centerior System .
27 Cleveland Electric . . . . . . . . . . . . . . . . . . . . . 27 ' Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . . 28 Title to Property . . . . . . . . . . . . . . . . . . . . . . . 30 Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . Submission of Matters to a Vote of Security Holders . . . 30 Item 4. PART II Item 5. Market for Registrants' Common Equity and Related 30 Stockholder Matters . . . . . . . . . . . . . . . . . . 31 Market Information . . . . . . . . . . . . . . . . . . . . . . 31 Share Owners . . . . . . . . . . . . . . . . . . . . . . . . 31 Dividends . . . . . . . . . . . . . . . . . . . . . . . . . . 31 Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . Centerior Energy . . . . . . . . . . . . . . . . . . . . . . . . 31 32 Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . 32 Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . . . Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . 32 Centerior Energy . . . . . . . . . . . . . . . . . . . . . . 32 32 Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . . 32 Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . . . This combined Form 10-K is separately filed by Centerior Energy Corporation, The Cleveland Electric illuminating Company and The Toledo Edison Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant, except that information relating to either or both of the operating Companies is also attributed to Centerior Energy. l l GLOSSARY OF TERMS . l I The following terms and abbreviations used in the text of this report are defined as indicated: Term Definition AFUDC Allowance for Funds Used During Construction. AMP-Ohio American Municipal Power-Ohio. Inc., an Ohio j not-for-profit corporation, the members of l which are certain Ohio municipal electric systems. Beaver Valley Unit 2 Unit 2 of the Beaver Valley Power Station, in which the Operating Companies have ownership and leasehold interests. CAPCO Group Central Area Power Coordination Group. Centerior Energy or Centerior Centerior Energy Corporation. Centerior System Centerior Energy, the Operating Companies and the Service Company. Clean Air Act Federal Clean Air Act of 1970 as amended. Clean Air Act Amendments November 1990 Amendments to the Clean Air Act. Clean Water Act Federal Water Pollution Control Act as amended. Cleveland Electric The Cleveland Electric Illuminating Company, an electric utility subsidiary of Centerior Energy and a member of the CAPCO Group. Consol Consolidation Coal Company. CPP Cleveland Public Power, a municipal electric system operated by the City of Cleveland. ; I I CWIP Construction Work in Progress. Davis-Besse Davis-Besse Nuclear Power Station.
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Page Number Item 8. Financial Statements and Supplementary Data . . . . . . . 32 l Centerior Energy . . . . . . . . . . . . . . . . . . . . . . 32 I Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . . 32 Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . . 32 Item 9. Changes in and Disagreemencs With Accountants on Accounting and Financial Disclosure . . . . . . . . . . . 32 , PART III t i Item 10. Directors and Executive Officers of the Registrants . . 33 l Centerior Energy . . . . . . . . . . . . . . . . . . . . . . . . 33 Cleveland Electric . . . . . . . . . . . . . . . . . . . . 33 Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . . . 33 Item 11. Executive Compensation . . . . . . . . . . . . . . . . . 34 Centerior Energy, Cleveland Electric'and Toledo Edison . . . . . 34 Item 12. Security ownership of Certain Beneficial Owners and Management . . . . . . . . . . . . . . . . . . . . . . 34 Centerior Energy . . . . . . . . . . . . . . . . . . . . . . . . 34 Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . . 36 Toledo Edison . . .. . . . . . . . . . . . . . . . . . . . . 36 Item 13. Certain Relationships and Related Transactions . . . . . 37 l Centerior Energy. Cleveland Electric and Toledo Edison . . . . . 37 i i PART IV l Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . . . . . . . , . . . . , , . . , , 37 Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 I Index to Selected Financial Data Management's Discussion and Analysis of Financial Condition and Results of Operations: and Financial Statements . . . . . . . . . . . . . . . . . . . . . F-1 Index to Schedules . . . . . . . . . . . . . . . . . . . . . . . . S-1 The Cleveland Electric Illuminating Company and Subsidiaries and The Toledo Edison Company Combined Pro Forma Condensed Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . P-1 Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . . . E-1
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Term Definition Detroit Edison Detroit Edison Company, an electric utility. District of Columbia United States Court of Appeals for the Dis-Circuit Appeals Court trict of Columbia Circuit. DOE United States Department of Energy. Duquesne Duquesne Light Company, an electric utility subsidiary of DQE, Inc. and a member of the CAPCO Group. ECAR East Central Area Reliability Coordination Group. Energy Act Energy Policy Act of 1992. Federal Power Act Federal Power Act, as amended, codified in Chapter 12 of Title 16 of the United States Code. FERC Federal Energy Regulatory Commission. General Electric General Electric Company. Holding Company Act Public Utility Holding Company Act of 1935. Mansfield Plant Bruce Mansfield Generating Plant, a coal-fired power plant, in which the Operating Companies have leasehold interests as joint and several lessees. Note or Notes Note or Notes to the Financial Statements in the Centerior Energy, Cleveland Electric and Toledo Edison Annual Reports for 1993 (Note or Notes, where used, refers to all three companies unless otherwise specified). NPDES National Pollutant Discharge Elimination - System. NRC United States Nuclear Regulatory Commission. Ohio Edison Ohio Edison Company, an electric utility and a member of the CAPCO Group. Ohio EPA Ohio Environmental Protection Agency. Ohio Power Ohio Power Company, an electric utility sub-sidiary of American Electric Power Company, Inc.
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Term Definition Ohio Valley The Ohio Valley Coal Company, the successor l corporation to The Nacco Mining Company and a f subsidiary of Ohio Valley Resources, Inc.
- Operating Companies Cleveland Electric and Toledo Edison.
l (individually, Operating Company) ] OPSB Ohio Power Siting Board. PaPUC Pennsylvania Public Utility Commission. Penelec Pennsylvania Electric Company, an electric utility subsidiary of GPU. Pennsylvania Power Pennsylvania Power Company, an electric ) utility subsidiary of Ohio Edison and a ! member of the CAPC0 Group. Perry Plant Perry Nuclear Power Plant. Perry Unit 1 and Perry Unit 2 Unit 1 and Unit 2 of the Perry Plant, in which the Operating Companies have ownership interests. PUC0 The Public Utilities Commission of Ohio. j Quarto Quarto Mining Company, a subsidiary of Consol. SALP Systematic Assessment of Licensee Performance - the NRC's performance evaluation of a nuclear unit. SEC United States Securities and Exchange Commission. Seneca Plant Seneca Power Plant, a pumped-storage, hydro-electric generating station jointly owned by Cleveland Electric and Penelet. Service Company Centerior Service Company, a service sub-sidiary of Centerior Energy. Superfund Comprehensive Environmental Response, Com-pensation and Liability Act of 1980 and the Superfund Amendments and Reauthorization Act of 1986.
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Definition Toledo Edison The Toledo Edison Company, an electric utility subsidiary of Centerior Energy and a member of the CAPCO Group. U.S. EPA United States Environmental Protection Agency. Westinghouse Westinghouse Electric Corporation.
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l l PART I Item 1. Business THE CENTERIOR SYSTEM Centerior Energy is a public utility holding company and-the parent company of the Operating Companies and the Service Company. Centerior was incorporated under the laws of the State of Ohio in 1985 for the purpose of enabling l Cleveland Electric and Toledo Edison to affiliate by becoming wholly owned subsidiaries of Centerior. The affiliation of the Operating Companies became effective in April 1986. Nearly all of the consolidated operating revenues of the Centerior System are derived from the sale of electric energy by Cleveland ! Electric and Toledo Edison. l The Operating Companies' combined service areas encompass approximately 4,200 square miles in northeastern and northwestern Ohio with an estimated popula-tion of about 2,600,000. At December 31, 1993, the Centerior System had 6,748 employees. Centerior Energy has no employees. Cleveland Electric, which was incorporated under the laws of the State of Ohio in 1892, is a public utility engaged in the generation, purchase, transmis-sion, distribution and sale of electric energy in an area of approximately 1,700 square miles in northeastern Ohio, including the City of Cleveland. Cleveland Electric also provides electric energy at wholesale to other elec-tric utility companias and to two municipal electric systems (directly and through AMP-Ohio) in its service area. Cleveland Electric serves approxi-mately 748,000 customers and derives approximately 75% of its total electric revenue from customers outside the City of Cleveland. Principal industries served by Cleveland Electric include those producing steel and other primary metals automotive and other transportation equipment; chemicals; electrical and nonelectrical machinery; fabricated metal products; and rubber and plastic products. Nearly all of Cleveland Electric's operating revenues are derived from the sale of electric energy. At December 31, 1993, Cleveland Electric had 3,606 employees of which about 51% were represented by one union having a collective bargaining agreement with Cleveland Electric. Toledo Edison, which was incorporated under the laws of the State of Ohio in 1901, is a public utility engaged in the generation, purchase, transmission, distribution and sale of electric energy in an area of approximately 2,500 square miles in northwestern Ohio, including the City of Toledo. Toledo Edison also provides electric energy at wholesale to other electric utility companies and to 13 municipally owned distribution systems (through AMP-Ohio) and one rural electric cooperative distribution system in its service area. Toledo Edison serves approximately 285,000 customers and derives approximately 55% of its total electric revenue from customers outside the City of Toledo. Among the principal industries served by Toledo Fd. son are metal casting, 4 forming and fabricating; petroleum refining; automotive equipment and assembly; food processing; and glass. Nearly all of Toledo Edison's operating At December 31, 1993. revenues are derived from the sale of electric energy. Toledo Edison had 1,909 employees of which about 55% were represented by three unions having collective bargaining agceements with Toledo Edison.
l , The Service Company, which was incorporated in 1986 under the laws of the I State of Ohio, is also a wholly owned subsidiary of Centerior Energy. It pro-vides management, financial, administrative, engineering, legal, governmental and public relations and other services to Centerior Energy and the operating Companies. At December 31, 1993, the Service Company had 1,233 employees. On March 25, 1994, Centerior Energy announced plans to merge Toledo Edison into Cleveland Electric. Since Cleveland Electric and Toledo Edison affiliated in 1986, efforts have been made to consolidate operations and administration as much as possible to achieve maximum cost savings. The j merger of the two companies into a single entity is the completion of this i consolidation process. Various aspects of the merger are subject to the approval of the FERC, the PUCO, the PaPUC and other regulatory authorities. The merger must be approved by Toledo Edison preferred stock share owners. Preferred stock share owners of Cleveland Electric must approve the authori-zation of additic hares of preferred stock. Upon the merger becoming effective, the o. ing shares of Toledo Edison preferred stock will be exchanged for share. e Cleveland Electric preferred stock having sub-stantially the same terms. Cleveland Electric and Toledo Edison plan to seek preferred share owner approval in the summer of 1994. The merger is expected to be effective late in 1994. See Note 15 to the Operating r ,anies' Financial Statements for further discussion of this matter and Combined Pro Forma Condensed Financial Statements (Unaudited)" conta ander Item 14. of this Report for selected historical and combined pro forma financial information of Cleveland Electric and Toledo Edison. l CAPCO GROUP Cleveland Electric and Toledo Edison are members of the CAPCO Group, a power pool created in 1967 with Duquesne, Ohio Edison and Pennsylvania Power. This pool affords greater reliability and lower cost of providing electric service through coordinated generat ' nit operations and maintenance and generating rererve back-up among the fi companies. In addition, the CAPCO Group has completed programs to construct larger, more efficient electric generating units and to strengthen interconnections within the pool. l The CAPCO Group companies have placed in service nine major generating units, of which the Operating Companies have ownership or leasehold interests in seven (three nuclear and four coal-fired). Each CAPCO Group company owns, as a tenant-in-common, or leases a portion of certain of these generating units. Each company has the right to the net capability and associated energy of its respective ownership and leasehold portions of the units and is, severally and not jointly, obligated for the capital and operating costs equivalent to its respective ownership and leasehold portions of the units and the required fuel, except that the obligations of Pennsylvania Power are the joint and several cSligations of that company and Ohio Edison and except that the leasehold obligations of Cleveland Electric and Toledo Edison are joint and several. (See " Operations--Fuel Supply".) For all plants but one, the company in whose service area a generating unit is located is responsible for the operation of that unit for all the owners, except for the procurement of nuclear fuel for a nuclear generating unit. The Mansfield Plant, which is located in Duquesne's service area, is operated by Pennsylvania Iower. Each company owns the necessary interconnecting transmission facilities within its service area, and the other CAPCO Group companies contribute toward fixed charges and operating costs of those transmission facilities.
All of the CAPCO Group companies are members of ECAR, which is comprised of 28 electric companies located in nine contiguous states. ECAR's purpose is to improve reliability of bulk power supply through coordination of planni g and operation of member companies' generation and transmission facilities, CONSTRUCTION AND FINANCING PROGRAMS Construction Program The Centerior System carries on a continuous program of constructing trans-mission, distribution and general facilities and modifying existing generating facilities to meet anticipated demand for electric service, to comply with governmental regulations and to protect the environment. The Operating Companies' 1993 long-term (20-year) forecast, as filed with the PUC0 (see
" General Regulation--State Utility Commissions"), projects long-term annual growth rates in peak demand and kilowatt-hour sales for the Operating Companies of 1.12 and 1.42, respectively, after demand-side management con-siderations. The Centerior System's integrated resource plan for the 1990s (which is included in the long-term forecast) combines demand-side management programs with maximum utilization of existing generating capacity to postpone the need for new generating units until the next decade. Demand-side manage-ment programs, such as energy-efficient lighting and motors, curta11able load and energy management, are expected to assist customers in achieving greater energy efficiency. Centerior plans to invest up to $35,000,000 in demand-side programs in 1994 and 1995.
Operable capacity margins over the next ten years are expected to be adequate without adding generating capacity. According to the current long-term l integrated resource plan, the next increment of generating capacity that the Centerior System plans to put into service will be two 136,000-kilowatt units in 2003, with additional small, short-lead-time capacity in subsequent years. l The following tables show, categorized by major components, the construction expenditures by Cleveland Electric and Toledo Edison and, by aggregating them, for the Centerior System during 1991, 1992 and 1993 and the estimated cost of their construction programs for 1994 through 1998, in each case including AFUDC and excluding nuclear fuel: Actual Estimated 1991 1992 1993 1994 1995 1996 1997 1998 Cleveland Electric (Millions of Dollars) Perry Unit 2* $ 0 $ 3 $ 0 $ - $ - $ - $ - $ - Transmission, Distribution and General Facilities 77 73 85 76 82 86 96 97 Renovation and Modification of Generating Units Nuclear 25 23 16 18 14 15 14 11 l Nonnuclear 48 56 65 55 70 36 29 41 ( Clean Air Act Amendments Compliance 0 1 9 27 22 3 4 33 i Total $g SQ $Q $3 $g,g $3 $L4,), $$ l 1 Note: The footnote to the tables is on the following page. l
Actual Estimated 1991 1992 1993 1994 1995 1996 1997 1998 Toledo Edison (Millions of Dollars) Perry Unit 2* $ 0 $ 0 $ 0 $ - $ - $ - $ - $ - Transmission, Distribution and General Facilities 30 25 22 23 27 26 25 20 Renovation and Modification of Generating Units Nuclear 17 12 15 15 10 12 10 8 Nonnuclear 7 7 6 11 9 6 6 8 Clean Air Act Amendments Compliance 0 0 0 6 4 11 11 11 Total $2 $3 $4 $2 $2 $2 $2 $$ Actual Estimated 1991 1992 1993 1994 1995 1996 1997 1998 Centerior System (Millions of Dollars) Perry Unit 2* $ 0 $ 3 $ 0 $ - $ - $ - $ - $ - Transmission, Distribution and General Facilities 107 98 107 99 109 112 121 117 Renovation and Modification of Generating Units Nuclear 42 35 31 33 24 27 24 19 Nonnuclear 55 63 71 66 79 42 35 49 Clean Air Act Amendments Compliance 0 1 9 33 26 14 15 44 , 1 Total $M $go,0q $g13, $4}} $1}}, $g $g $Zj,g l
- Construction of Perry Unit 2 was suspended in 1985. In 1992, Cleveland I Electric purchased Duquesne's ownership share of Perry Unit 2 for
$3,324,000. At December 31, 1993, Centerior Energy, Cleveland Electric and Toledo Edison wrote off their investment in Perry Unit 2 (see Note 4(b)).
Each company in the CAPCO Group is responsible for financing the portion of the capital costs of nuclear fuel equivalent to its ownership and leased interest in the unit in which the fuel will be utilized. See " Operations-- Fuel Supply--Nuclear" for information regarding nuclear fuel supplies and Note , 6 regarding leasing arrangements to finance nuclear fuel capital costs. ' l Nuclear fuel capital costs incurred by Cleveland Electric. Toledo Edison and the Centerior System during 1991, 1992 and 1993 and their estimated nuclear fuel capital costs for 1994 through 1998 are as follows: l l Actual Estimated 1991 1992 1993 1994 1995 1996 1997 1998 (Millions of Dollars) Cleveland Electric $ 32 $ 30 $ 26 $ 28 $ 18 $ 29 $ 33 $ 37 Toledo Edison $ 27 $ 22 $ 20 $ 23 $ 12 $ 30 $ 27 $ 28 Centerior System $ 59 $ 52 $ 46 $ 51 $ 30 $ 59 $ 60 $ 65 Financing Program . Reference is made to Centerior Energy's, Cleveland Electric's and Toledo , Edison's Management's Financial Analysis contained under Item 7 of this Report I and to Notes 11 and 12 for discussions of the Centerior System's financing activity in 1993; debt and preferred stock redemption requirements during the 1994-1998 period; expected external financing needs during such period; re- ; strictions on the issuance of additional debt securities and preferred stock; I short-term and long-term financing capability; and securities ratings for the j Operating Companies. In the second quarter of 1994, Cleveland Electric and Toledo Edison expect to issue $46,100,000 and $30,500,000, respectively, of first mortgage bonds as collateral security for the sale by a public authority of equal principal amounts of tax-exempt bonds. The proceeds from the sales of the public authority's bonds will be used to refund $46,100,000 and $30,500,000, respec-tively, of tax-exempt bonds that were issued in 1988 and have been continu-ously remarketed on a floating rate basis. The new series of bonds will each be issued at a fixed rate of interest for the remaining term to July 1, 2023. l Centerior expects to raise about $35,000,000 in 1994 from the sale of ( authorized but unissued common stock under certain of its employee and share l owner stock purchase plans. I GENERAL REGULATION Holding Company Regulation Centerior Energy is currently exempt from regulation under the Holding Company Act. The Energy Act contains, among other provisions, amendments to the Holding Company Act and the Federal Power Act. The Energy Act also adopted nuclear i power licensing and related regulations, energy efficiency standards and incentives for the use of alternative transportation fuels. Amendments to the Holding Company Act create a new class of independent power producers known as
" Exempt Wholesale Generators", which are exempt from the Holding Company Act corporate structure regulations rnd operate without SEC approval or regulation. Exempt Wholesale Generators may be owned by holding companies, electric utility companies or any other person.
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i l State Utility Commissions The Operating Companies are subject to the jurisdiction of the PUC0 with re-spect to rates, service, accounting, issuance of securities and other matters. Under Ohio law, municipalities may regulate rates, subject to appeal to the PUC0 if not acceptable to the utility. See " Electric Rates" for a description of certain aspects of Ohio rate-making law. The Operating Companies are also s ^ ject to the jurisdiction of the PaPUC in certain respects relating to their ownership interests in generating facilities located in Pennsylvania. l The PUC0 is composed of five commissioners appointed by the Governor of Ohio from nominees recommended by a Public Utility Commission Nominating Council. Nominees must have at least three years' experience in one of several disci-p11nes. Not more than three commissioners may belong to the same political party. Under Ohio law, a public utility must file annually with the PUC0 a long-term forecast of customer loads, facilities needed to serve those loads and prospective sites for those facilities. This forecast must include the following: (1) Demand Forecast--the utility's 20-year forecast of sales and peak demand, before and after the effects of demand-side management programs. (2) Integrated Resource Plan (required biennially)--the utility's projected mix of resource options to meet the projected demand. (3) Short-Term Implementation Plan and Status Report (required biennially)-- the utility's discussion of how it plans to implement its integrated resource plan over the next four years. Estimates of annual expenditures i and security issuances associated with the integrated resource plan over the four-year period must also be provided. The PUC0 must hold a public hearing on the long-term forecast at least once every five years to determine the reasonableness of such forecast. The PUC0 and the OPSB are required to consider the record of such hearings in proceed-ings for approving facility sites, changing rates, approving security issues and initiating energy conservation programs. Ohio law also permits electric utilities under PUC0 jurisdiction to submit environmental compliance plans for PUC0 review and approval. Ohio law requires that the PUC0 make certain statutory findings prior to approving the environmental compliance plan, which includes that the plan is a reasonable least cost strategy for compliance with air quality requirements. In 1992, the PUC0 held hearings on the Operating Companies' 1092 long-term forecast and environmental compliance plan. Centerior and the parties intervening in the proceeding reached agreement on the forecast and environmental compliance plan, and the agreement was sub-sequently approved by the PUC0 in February 1993. The PUC0 has jurisdiction over certain transactions by companies in an elec-tric utility holding company system if it includes at least one Ohio electric utility and is exempt from regulation under Section 3(a)(1) or (2) of the Holding Company Act. An Ohio electric utility in such a holding company l l
system, such as Centerior, must obtain PUC0 approval to invest in, lend funds to, guarantee the obligations of or otherwise finance or transfer assets to ] any nonutility company in that holding company system, unless the transaction ? is in the ordinary course of business operations in which one company acts for or with respect to another company. Also, the holding company in such a hold-ing company system must obtain PUC0 approval to make any investment in any nonutility subsidiaries, affiliates or associates of the holding company if such investment would cause all such capital investments to exceed 15% of the consolidated capitalization of the holding company unless such funds were , provided by nonutility subsidiaries, affiliates or associates. The PUC0 has a reserve capacity policy for electric utilities in Ohio stating that (1) 20% of service area peak load excluding interruptible load is an appropriate generic benchmark for an electric utility's reserve margin; (11) a reserve margin exceeding 20% gives rise to a presumption of excess capacity, but may be appropriate if it confers a positive net present benefit to cus-tomers or is justified by unique system characteristics; and (iii) appropriate i remedies for excess capacity (possibly including disallowance of costs in rates) will be determined by the PUC0 on a case-by-case basis. Ohio Power Siting Board The OPSB has state-wide jurisdiction, except to the extent pre-empted by Federal law, over the location, need for and certain environmental aspects of electric generating units with a capacity of 50,000 kilowatts or more and transmission lines with a rating of at least 125 kV. Federal Energy Regulatory Commission The Operating Companies are each subject to the jurisdiction of the FERC with respect to the transmission and sale of power at wholesale in interstate com-merce, interconnections with other utilities, accounting and certain other matters. Cleveland Electric is also subject to FERC jurisdiction with respect to its ownership and operation of the Seneca Plant. Nuclear Regulatory Commission l The nuclear generating units in which the Operating Companies have an interest are subject to regulation by the NRC. The NRC's jurisdiction encompasses broad supervisory and regulatory powers over the construction and operation of nuclear reactors, including matters of health and safety, antitrust considera-tions and environmental impacts. Owners of nuclear units are required to purchase the full amount of nuclear liability insurance available. See Note 5(b) for a description of nuclear in-surance coverages. Other Regulation The operating Companies are subject to regulation by Federal, state and local authorities with regard to the location, construction and operation of certain facilities. The Operating Companies are also subject to regulation by local authorities with respect to certain zoning and planning matters. j l 7-
l ENVIRONMENTAL REGULATION I General The Operating Companies are subject to regulation with respect to air quality, 1 I water quality and waste disposal matters. Federal environmental legislation affecting the operations and properties of the Operating Companies includes the Clean Air Act, the Clean Air Act Amendments, the Clean Water Act, Superfund, and the Resource Conservation and Recovery Act. The requirements of these statutes and related state and local laws are continually changing due to the promulgation of new or revised laws and regulations and the results of judicial and agency proceedings, Compliance with such laws and regulations may require the Operating Companies to modify, supplement, abandon or replace
- facilities and may delay or impede construction and operation of facilities, l all at costs which could be substantial. The Operating Companies expect that the impact of such costs would eventually be reflected in their respective rate schedules. Cleveland Electric and Toledo Edison plan to spend, during the period 1994-1996, $70,000,000 and $20,000,000, respectively, for pollution control facilities, including Clean Air Act Amendments compliance costs.
The Operating Companies believe that they are currently in compliance in all i material respects with all applicable environmental laws and regulations, or to the extent that one or both of the Operating Companies may dispute the applicability or interpretation of a particular environmental law or regula-tion, the affected company has filed an appeal or has applied for permits, - revisions in requirements, variances or extensions of deadlines. l Concerns have been raised regarding the possible health effects associated with electric and magnetic fields. Although scientific research as to such effects has yielded inconclusive results, additional studies are being con-ducted. If electric and magnetic fields are ultimately found to pose a health risk, the operating Companies may be required to modify transmission and distribution lines or other facilities. Air Quality Control Under the Clean Air Act, the Ohio EPA has adopted Ohio emission limitations for particulate matter and sulfur dioxide for each of the Operating Companies' plants. The Clean Air Act provides for civil penalties of up to $25,000 per day for each violation of an emission limitation. The U.S. EPA has approved the Ohio EPA's emission limitations and the related implementation plans ex- l cept for some particulate matter emissions and certain sulfur dioxide emis-sions. The U.S. EPA has adopted separate sulfur dioxide emission limitations for each of the Operating Companies' plants. l In November 1990, the Clean Air Act Amendments were signed into law imposing restrictions on nitrogen oxides emissions and making sulfur dioxide emission limitations significantly more severe beginning in 1995. See Note 4(a) for a description of the operating Companies' compliance strategy, which was in-l cluded in the agreement approved by the PUC0 in February 1993 in connection I with the Operating Companies' 1992 long-term forecast. The Clean Air Act l l l
_ ___ _ . - ~ _ ._ _ . - _ . .. _ _ . .. . _ _ -__ _ _ i 4 Amendments also require studies to be conducted on the emission of certain potentially hazardous air pollutants which could lead to additional I restrictions. In 1985, the U.S. EPA issued revised regulations specifying the extent to which power plant stack height may be incorporated into the establishment of an emission limitation. Pursuant to the revised regulations, the Operating Companies submitted to the Ohio EPA information intended to support continua-tion of the stack height credit received under the previous-regulations for ! stacks at Cleveland Electric's Avon Lake and Eastlake Plants and Toledo Edison's Bay Shore Station. The Ohio EPA has accepted the submissions and forwarded them to the U.S. EPA for approval. In January 1988, the District of Columbia Circuit Appeals Court remanded portions of the 1985 regulations to the U.S. EPA for further consideration; however, the U.S. EPA has not taken action specifically on this issue. Congress is considering legislation to reduce emissions of gases such as those resulting from the burning of coal that are thought to cause global warming. If such legislation is adopted, the cost of operating coal-fired plants could increase significantly and coal-fired generating capacity could decrease significantly. Water Quality Control The Clean Water Act requires that power plants obtain permits that contain certain effluent limitations (that is, limits on discharges of pollutants into bodies of water). It also requires the states to establish water quality standards (which could result in more stringent effluent limitations than those required under the Clean Water Act) and a permit system to be approved-by the U.S. EPA. Violators of effluent limitations and water quality standards are subject to a civil penalty of up to $25,000 per day for each such violation. The Clean Water Act permits thermal effluent limitations to be established for a f acility which are less stringent than those which otherwise would apply if the owner can demonstrate that such less stringent limitations are sufficient to assure the protection and propagation of aquatic and other wildlife in the affected body of water. By 1978, the Operating Companies had submitted to the Ohio EPA such demonstrations for review with respect to their Ashtabula, Avon Lake, Lake Shore, Eastlake, Acme and Bay Shore plants. The Ohio EPA has taken no action on the submittals. The Operating Companies have received NPDES permit renewals from the Ohio EPA or have applied for such renewals for all of their power plants. In those situations where a permit application is pending, the affected plant may con-tinue to operate under the expired permit while such application is pending. Any violation of an NPDES permit is considered to be a violation of the Clean Water Act subject to the penalty discussed above.
In 1990, the Ohio EPA issued revised water quality standards applicable to Lake Erie and waters of the State of Ohio. Based upon these revised water quality standards, the Ohio EPA placed additional effluent limitations in their most recent NPDES permits. The revised standards also may serve as the basis for more stringent effluent limitations in future NPDES permits. Such limitations could result in the installation of additional pollution control equipment and increased operating expenses. The operating Companies are monitoring discharges at their plants to support their position that addi-tional effluent limitations are not justified. On April 16, 1993, the U.S. EPA issued proposed rules for water quality standards applicable to all states abutting the Great Lakes, including Ohio. These states would be required to adopt state water quality standards and procedures consistent with the rules within two years of final publication. Preliminary reviews indicate that the cost of complying with these rules could be significant. However, Centerior cannot determine what impact these rules will have on its operations until such rules are issued in final form and are incorporated into Ohio regulations. Waste Disposal See " Hazardous Waste Disposal Sites" in Management's Financial Analysis contained under Item 7 of this Report and Note 4(c) for a discussion of the operating Companies' potential involvement in certain hazardous waste disposal sites, including those subject to Superfund. See " Nuclear Units" and " Fuel l Supply--Nuclear" under " Operations", below, for discussions concerning the l disposal of nuclear waste. l The Resource Conservation and Recovery Act exempts certain fossil fuel com-l bustion vaste products, such as fly ash, from hazardous waste disposal re-l quirements. The Operating Companies are unable to predict whether Congress l will choose to amend this exemption in the future or, if so, the costs relat-ing to any required changes in the operations of the Operating Companies. ELECTRIC RATES Under Ohio law, rate base is the original cost less depreciation of a utility's total plant adjusted for certain items. The law permits the PUCO, in its discretion, to include CWIP in rate base when a construction project is at least 752 complete, but limits the amount included to 10% of rate base ex-cluding CWIP or, in the case of a project to construct pollution control fa-cilities which would remove sulfur and nitrous oxides from flue gas emissions, 20% of rate base excluding CWIP. When a project is completed, the portion of its cost which had been included in rate base as CWIP is excluded from rate base until the revenue received due to the CWIP inclusion is offset by the revenue lost due to its exclusion. During this period of time, an AFUDC-type credit is allowed on the portion of the project cost excluded from rate base. I Also, the law permits inclusion of CWIP for a particular project for a period not longer than 48 consecutive months, plus any time needed to comply with
- - .- - .. . _, - _ = . . _
changed governmental regulations, standards or approvals. The PUC0 is em-powered to permit inclusion for up to another 12 months for good cause shown. If a project is canceled or not completed within the allowable period of time after inclusion of its CWIP has started, then CWIP is excluded from rate base and any revenues which resulted from such prior inclusion are offset against future revenues over the same period of time as the CWIP was included. Current Ohio law further provides that requested rates can be collected by a public utility, subject to refund, if the PUC0 does not make a decision within 275 days after the rate request application is filed. If the PUC0 does not make its final decision within 545 days, revenues collected thereafter are not subject to refund. A notice of intent to file an application for a rate in-crease cannot be filed before the issuance of a final order in any prior pend-l ing application for a rate increase or until 275 days after the filing of the ! prior application, whichever is earlier. The minimum period by which the notice of intent to file must precede the actual filing is 30 days. The test year for determining rates may not end more than nine months after the date the application for a rate increase is filed. Under Ohio law, electric rates are adjusted every six months to reflect changes in fuel costs. The PUC0 reviews such adjustments annually. Any difference between actual fuel costs during a six-month period and the fuel revenues recovered in that period is deferred and is taken into account in setting the fuel recovery factor for a subsequent six-month period. j l The PUC0 has authorized the Operating Companies to adjust their rates on a seasonal basis such that electric rates are higher in the summer. Also, under Ohio law, municipalities may regulate rates charged by a utility, subject to appeal to the PUC0 if not acceptable to the utility. If municipally fixed rates are accepted by the utility, such rates are binding on both parties for the specified term and cannot be changed by the PUCO. See Note 7 and Management's Financial Analysis contained under Item 7 of this Report for information relating to the PUCO's January 1989 rate orders and the Rate Stabilization Program that was approved by the PUC0 for the Operating Companies in October 1992. OPERATIONS Sales of Electricity Kilowatt-hour sales by the Operating Companies follow a seasonal pattern marked by increased customer usage in the summer for air conditioning and in the winter for heating. Historically, Cleveland Electric has experienced its heaviest demand for electric service during the summer months because of a significant air conditioning load on its system and a relatively low amount of electric heating load in the winter. Toledo Edison, although having a significant electric heating load, has experienced in recent years its heaviest demand for electric service during the summer months because of heavy air conditioning usage.
The Centerior System's largest customer is a steel manufacturer which has two major steel producing facilities served by Cleveland Electric. Sales to these j facilities accounted for 2.5% and 3.5% of the 1993 total electric operating 1 revenues of Centerior Energy and Cleveland Electric, respectively. The loss l of these facilities (and the resultant loss of another large customer whose primary product is purchased by the two steel producing facilities) would reduce Centerior Energy's and Cleveland Electric's net income by about $34,000,000 based on 1993 sales levels. The largest customer served by Toledo Edison is a major automobile manufac-turer. Sales to this customer accounted for 1.4% and 3.9% of the 1993 total electric operating revenues of Centerior Energy and Toledo Edison, re-apectively. The loss of this customer would reduce Centerior Energy's and Toledo Edison's net income by about $10,000,000 based on 1993 sales levels. l Operating Statistics For data on operating revenues by service category, electric sales by service category, customers by service category and electric energy generation for 1983 and 1989 through 1993, see the attached Pages F-23 and F-24 for Centerior Energy, F-46 and F-47 for Cleveland Electric and F-68 and F-69 for Toledo Edison. Nuclear Units The Operating Companies' generating facilities include, among others, three nuclear units owned or leased by the CAPCO Group--Perry Unit 1, Beaver Valley Unit 2 and Davis-Besse. T: ese three units are in commercial operation. Cleveland Electric has responsibility for operating Perry Unit 1 Duquesne has responsibility for operating Beaver Valley Unit 2 and Toledo Edison has re-sponsibility for operating Davis-Besse. Cleveland Electric and Toledo Edison own, respectively, 31.11 and 19.91% of Perry Unit 1, 24.47% and 1.65% of Beaver Valley Unit 2 and 51.382 and 48.622 of Davis-Besse. Cleveland Electric and Toledo Edison also lease, as joint lessees, another 18.262 of Beaver , Valley Unit 2 as a result of a September 1987 sale and leaseback transaction I (see Note 2). ] Davis-Besse was placed in commercial operation in 1977, and its operating license expires in 2017. Perry Unit 1 and Beaver Valley Unit 2 were placed in commercial operation in 1987, and their operating licenses expire in 2026 and 2027, respectively. , As part of its January 1989 rate orders, the PUC0 approved nuclear plant performance standards for the operating Companies based on rolling three-year industry averages of operating availability for pressurized water reactors and for boiling water reactors over the 1988-1998 period. Operating availability is the ratio of the number of hours a unit is available to generate elec-tricity (whether or not the unit is operated) to the number of hours in the period, expressed as a percentage. The three-year operating availability averages of the Operating Companies' nuclear units are compared against the industry averages for the same three-year period with a resultant penalty or banked benefit. If the industry performance standards are not met, a penalty
would be incurred which would require the Operating Companies to refund in-cremental replacement power costs to customers through the semiannual fuel cost rate adjustment. However, if the performance of the Operating Companies' nuclear units exceeds the industry standards, a banked benefit results which can be used to offset disallowances of incremental replacement power costs should future performance be below industry standards. The relevant industry standards for the 1991-1993 period are 78.0% for pressurized water reactors such as Davis-Besse and Beaver Valley Unit 2 and 72.8% for boiling water reactors such as Perry Unit 1. The 1991-1993 availability average for Davis-Besse and Beaver Valley Unit 2 was 87.12 and for Perry Unit 1 was 69.2%. At December 31, 1993, the total banked benefit for the Operating Companies is estimated to be between $18,000,000 and $20,000,000. All three nuclear units have received generally favorable evaluations from the NRC in their most recent SALP reviews. Each of the functional areas evaluated is rated according to three performance categories, with category 1 Indicating performance substantially exceeding regulatory requirements and that reduced NRC attention may be appropriate; category 2 indicating performance above that needed to meet regulatory requirements and that NRC attention may be main-tained at normal levels; and category 3 indicating performance does not significantly exceed that needed to meet minimal regulatory requirements and that NRC attention should be increased above normal levels. The most recent review periods and SALP review scores for Perry Unit 1 and Davis-Besse are: Perry Unit 1 Davis-Besse SALP Review Period 11/1/91-1/31/93 12/1/91-6/30/93 Plant Operations 2 2 Radiological Controls 2 2 Maintenance / Surveillance 2 1 Emergency Preparedness 1 1 Security and Safeguards 1 1 Engineering / Technical Support 2 1 Safety Assessment / Quality Verif. 3 1 The NRC increased its attention to Perry Unit 1 in 1993 and placed the unit on a newly created list for units identified as showing " safety performance trending downward". Centerior made specific organizational changes and developed a comprehensive course of action to improve the operating performance of Perry Unit 1. In response to this course of action, on January 27, 1994, the NRC removed Perry Unit 1 from the performance trending downward list. ! In 1993, the NRC revised the functional areas which comprise the SALP grading I process. Plant Support is.a new category which covers the areas previously covered by Security, Emergency Preparedness and Radiological Controls. The Safety Assessment / Quality Verification category is now an integral part of l each category and is no longer being singled out. Beaver Valley Unit 2 is the only Centerior System unit to have been graded under the new system. Perry Unit 1 and Davis-Besse will be graded under the new system when their next 1 l SALP scores are issued. The most recent review period and SALP review scores for Beaver Valley Unit 2 are: SALP Review Period 6/14/92-11/27/93 Operations 1 Engineering 2 Maintenance 2 Plant Support 1 The Operating Companies ship low-level radioactive waste produced at their nuclear plants to an offsite disposal facility which may not accept such shipments after mid-1994. The Operating Companies' ability to continue offsite disposal depends on whether the State of Ohio develops a low-level ; radioactive waste disposal facility within the next several years. If offsite disposal becomes unavailable, the Operating Companies have facilities to temporarily store such waste on site at each of the nuclear plants. However, the operating Companies do not intend to store such waste on site until all available off-site options have been exhausted. See Note 4(b) for a discussion of the write-off of Perry Unit 2, and see Note 5(a) and " Outlook--Nuclear Operations" in Management's Financial Analysis contained under Item 7 of this Report for a discussion of potential risks facing Centerior and the Operating Companies as owners of nuclear generating units. Competitive Conditions General. The Operating Companies compete in their respective service areas with suppliers of natural gas to satisfy customers' energy needs with regard to heating and appliance usage. The Operating Companies also are engaged in I competition to a lesser extent with suppliers of oil and liquefied natural gas for heating purposes and with suppliers of cogeneration equipment. One competitor provides steam for heating purposes and provides chilled water for cooling purposes in certain areas of downtown Cleveland. The Operating Companies also compete with municipally owned electric systems within their respective service areas. As discussed below, two of the munici-palities served by the operating Companies, the City of Toledo and the City of Garfield Heights, are investigating the economic feasibility of establishing and operating municipally owned electric systems. A few other communities have evaluated municipalization of electric service and decided to continue service from Cleveland Electric and Toledo Edison. Officials in still other communities have indicated an interest in evaluating the municipalization issue. The operating Companies face continuing competition from locations outside their service areas which are promoted by governmental and private agencies in attempts to influence potential and existing commercial and industrial cus-tomers to locate in their respective areas. l Cleveland Electric and Toledo Edison also periodically compete with other j producers of electricity for sales to electric utilities which are in the market for bulk power purchases. The Operating Companies have inter-connections with other electric utilities (see " Item 2. Properties--General") and have a transmission system capable of transmitting (" wheeling") power between the Midwest and the East. l Cleveland Electric. Located within Cleveland Electric's service area are two municipally owned electric systems. Cleveland Electric supplies a small portion of those systems' power needs at wholesale rates. l One of those systems, CPP, is operated by the City of Cleveland in competition with Cleveland Electric. CPP is primarily an electric distribution system which currently supplies electric power in approximately 70% of the City's geographical area (expected to increase to 100% by the end of 1997) and to l approximately 28% (about 59,000) of the electric consumers in the City--equal ; to about 8% of all customers served by Cleveland Electric. CPP's kilowatt- I hour sales and revenues are equal to about 5% of Cleveland Electric's j kilowatt-hour sales and revenues. Much of the area served by CPP overlaps that of Cleveland Electric. For all classes of customers, Cleveland Electric's rates are higher than CPP's rates due largely to CPP's exemption from taxation, its reliance on short- and medium-term power supply contracts and the spot market which are lower in cost and the lower-cost financing available to CPP. Cleveland Electric makes power available to CPP on a wholesale basis, subject to FERC regulation. In 1993, Cleveland Electric directly and through AMP-Ohio provided about 15% of CPP's energy requirements. The balance of CPP's power is purchased from other sources and wheeled over Cleveland Electric's transmission system. In cases currently pending, the FERC has been asked to determine whether Cleveland Electric is obligated to provide an additional interconnection with CPP and to rule on Cleveland Electric's request for an increase in rates for power and services provided to CPP. Cleveland Electric believes that it is entitled to a higher level of compensation for the power and the services it provides because the rates currently paid by CPP do not adequately cover the cost of providing such power and services. CPP is constructing new transmission and distribution facilities extending into eastern portions of Cleveland and plans to expand to western portions of Cleveland, both of which now are served exclusively by Cleveland Electric. During the 1991-1993 period, Cleveland Electric had a net loss of about 7,000 i customers, including several hundred commercial and industrial customers, to the CPP system which resulted in a reduction in Cleveland Electric's 1993 annual income of about $14,000,000. CPP's Phase I expansion, as now planned, could take away about 18,000 more of Cleveland Electric's customers, while its Phase II expansion could take away about 29,000 customers over the next several years. This could eventually reduce Cleveland Electric's net income by about $27,000,000. Cleveland Electric has retained many medium and large commercial and industrial customers in Cleveland despite CPP's expansion efforts. Long-term contracts with many of these customers provide them with economic incentives to remain with Cleveland Electric. Most of those contracts have remaining terms of one to five years. i i
\
l In 1991, the City of Brook Park, located within the Cleveland Electric service territory, commissioned a feasibility study regarding the establishment of a l I municipal electric system. Ford Motor Company operates a large engine manu-facturing plant in Brook Park. In April 1993, Cleveland Electric entered into an agreement with Brook Park running through the year 2000 whereby Cleveland Electric would make available a total of $1,250,000 for demand-side manage-ment programs to help reduce the energy bills of Brook Park customers over the next five years and $400,000 to study the feasibility of a resource recovery plant in the City to process municipal waste. At the same time, Cleveland Electric entered into a five-year agreement with Ford Motor Company in Brook , Park which provides pricing incentives to help Ford improve its competitive- l ness and encourage economic growth in Cleveland Electric's service area. The l agreement can be renewed, at Ford's option, through the year 2000.. j i In March 1994, the City Council of Garfield Heights, a suburb of Cleveland, ) passed an ordinance calling for a 302 reduction in rates for Cleveland i Electric's customers in that city. Cleveland Electric will appeal that ) ordinance to the PUC0 which will allow the existing rates to stay in effect. The potential impact of the rate reduction on Cleveland Electric's annual revenues is $5,500,000. Currently, one commercial customer and one industrial customer of Cleveland Electric have cogeneration installations. A number of customers have inquired about cogeneration applications, but there were no new installations in 1991, 1992 or 1993. Toledo Edison. Located wholly or partly within Toledo Edison's service area are six rural electric cooperatives, five of which are supplied with power, transmitted in some cases over Toledo Edison's facilities, by Buckeye Power. I Inc. (an affiliate of a number of Ohio rural electric cooperatives) and the l sixth is supplied by Toledo Edison. l l Also located within Toledo Edison's service area are 16 municipally owned l electric distribution systems, three of which are supplied by other electric systems. Toledo Edison provides a portion of the power purchased by the other 13 municipalities at wholesale rates through a contract with AMP-Ohio that expires in 2009. Rates under this agreement are permitted to increase annually to compensate for increased costs of operation. Less than 22 of
- Toledo Edison's total electric operating revenues in 1993 were derived from sales under the AMP-Ohio contract.
l In October 1989, the City of Toledo adopted an ordinance establishing an l Electric Franchise Review Committee for the purpose of studying Toledo Edison's franchise agreement with the City to determine whether alternate energy sources may be utilized. The Committee investigated the feasibility of establishing a municipal electric system within the City of Toledo and the feasibility of utilizing other alternative electric power sources. In May 1992, the Committee recommended that the City negotiate with Toledo Edison with regard to rates and other customer initiatives rather than create its own [ municipal electric system. The Committee recommended that if negotiations with Toledo Edison were unsuccessful, the City should create a small municipal utility to serve approximately 20% of the City's electricity load, primarily ? l l
City facilities, such as the waste water treatment plant, and businesses with large electricity consumption. In March 1993, the city and Toledo Edison reached agreement on a non-exclusive franchise which runs through 2000. The l franchise, which was approved by voters in November 1993, will terminate two l ! years earlier if Toledo Edison files for a rate increase with the PUC0 prior to 1999. The City also retains its right to establish a municipal electric l system. In addition, Toledo Edison will provide $6,000,000 for demand-side 1 management programs energy efficiency programs for senior citizens, low income customers and small businesses; and economic development programs over a five-year period beginning in 1994. These expenditures will be in addition to the demand-side management expenditures currently planned by the Centerior System. The agreement does not call for a reduction in base electric rates. Meanwhile, the Electric Franchise Review Committee continues to explore the formation of a municipal system to serve 202 of the load in the City. The last commercial customer of Toledo Edison having a cogeneration unit ceased operation of its unit during the first quarter of 1992. i l I Fuel Supply i Generation by type of fuel for 1993 was 732 coal-fired and 272 nuclear for Cleveland Electric; 54Z coal-fired and 46Z nuclear for Toledo Edison and 672 coal-fired and 33% nuclear for the Centerior System. Coal. In 1993, Cleveland Electric and Toledo Edison burned 6,238,000 tons and 2,138,000 tons of coal, respectively, for electric generation. Each utility normally maintains a reserve supply of coal sufficient for about 40 days of normal operations. On March 1, 1994, this reserve was about 24 days for plants operated by Cleveland Electric, 34 days for plants operated by Toledo Edison and 40 days for the Mansfield Plant, which is operated by Pennsylvania l Power. In 1993, about 59% of Cleveland Electric's coal requirements were purchased under long-term contracts, with the longest remaining term being almost 10 years. In most cases, these contracts provide for adjusting the price of the coal on the basis of changes in coal quality and mining costs. The sulfur content of the coal purchased under these contracts ranges from less than 1% to about 4%. The balance of Cleveland Electric's coal was purchased on the spot market with sulfur content ranging from less than 1% to 3.5%. In 1993, about 66% of Toledo Edison's coal requirements were purchased under long-term contracts, with the longest remaining term being almost seven years. In most cases, these contracts provide for adjusting the price of the coal on the basis of changes in coal quality and mining costs. The sulfur content of the coal purchased under these contracts ranges from less than 12 to 42. One of Cleveland Electric's long-term coal supply contracts is with Ohio l Valley. Cleveland Electric has agreed to pay Ohio Valley certain amounts to cover Ohio Valley's costs regardless of the amount of coal actually delivered. Included in those costs are amounts sufficient to service certain long-term debt and lease obligations incurred by Ohio Valley. If the coal sales agree-ment is terminated for any reason, including the inability to use the coal, 1 I l I l 1 7 41
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-City facilities, such as the waste water treatment plant', and businesses with r M}}y large electricity consumption. In March 1993, the City and Toledo Edison reached agreement on a non-exclusive franchise which runs through 2000. The franchise,'which was approved by voters in November 1993, will terminate two years earlier if Toledo Edison files for a rate increase withlthe PUC0 prior. .
j to 1999. The City also' retains 'its right to establish a municipal electric j' Ja system. In addition,-Toledo Edison will provide $6,000,000 for demand-side. j management programs: energy efficiency programs for senior citizens, low
- y. Income-customers and small businesses; and economic development programs over j a five-year period beginning in 1994. These expenditures will be in addition
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to the demand-side management expenditures currently planned by the Centerior ]% System.- The agreement does not call for a reduction in base electric rates. {g; jj Meanwhile, the Electric. Franchise ~ Review Committee continues to explore the= d formation of a municipal system to serve 20% of.the load in the City. d w. The last commercial customer of. Toledo Edison having a cogeneration unit Q] ceased. operation of its unit during the firstiquarter of 1992. h Fuel Supply-
- y. . ,
Generation by type of fuel for 1993 was 73% coal-fired'and-27% nuclear for ?! Cleveland Electric;-542 coal-fired and 462 nuclear for Toledo Edisons and 67% %' coal-fired and 33% nuclear for the Centerior System. %} Coal. In 1993, Cleveland Electric and Toledo Edison burned 6,238,000 tons and J. 2,138,000 tons of coal, respectively,.for electric generation. Each utility j* normally maintains a' reserve supply of coal sufficient for about 40 days of t normal operations. con March 1,~1994, this reserve was about 24 days-for [ j plants operated by Cleveland Electric, 34 days for plants operated:by Toledo E i Edison and 40 days'for the Mansfield Plant, which is operated by Pennsylvania hj t Power. !,j A 'i d In 1993, about 59% of Cleveland Electric's coal ~ requirements were purchased 1 1 under long-term contracts, with the longest. remaining term being almost 10 j-.! O] years. In most cases, these contracts provide for: adjusting'the price of the [l q coal on the basis-'of changes in coal quality and mining costs. The sulfur- t;
]g content of the coal purchase'd under these contracts ranges from less than 1%- !g to about 42. The' balance of Cleveland Electric's coal'was purchased on the ;
} spot market with sulfur content ranging from less than 1% to 3.5%. io 9 In 1993, about 66% of Toledo Edison's coal requirements were purchased under-M long-term contracts, with the longest-remaining term being almost seven years. q gj In most cases, these contracts provide for adjusting the price of'the coal on ; i the basis'of changes"in coal quality and mining: costs. The' sulfur content of ' 3 the coal purchased under these contracts ranges from less'than 12 to 4%. d iy, One of Cleveland Electric's long-term coal supply contracts is with Ohio fi
'l .
@ Valley'. Cleveland Electric has agreed to pay Ohio Valley certain- a:.nounts to ( cover Ohio Valley's costs regardless of the amount'of coal =actually delivered. ,j ji Included-'in those costs are amounts sufficient to service certain long-term L: Lj- debt and lease obligations incurred by Ohio Valley. If'the coal sales agree- ), i-j a ment is terminated for'any reason,' including the inability to use the coal, 1 ik -J H a H gi k . ' Ik j u y >
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l. Cleveland Electric must assume certain of Ohio Valley's debt and lease obli-gations and may incur other expenses including mine closing costs, if necessary. The principal amount of debt and termination va'ues of leased property covered by Cleveland Electric's agreement was $27,116,000 at l December 31, 1993. Cleveland Electric is considering terminating the Ohio l Valley agreement as part of its least cost plan to comply with the I requirements of the Clean Air Act Amendments. If the agreement is so terminated. Cleveland Electric would ask the PUC0 to allow recovery of the termination charges from its customers through the fuel component. If the agreement is not terminated early, Cleveland Electric expects that Ohio Valley , revenues from sales of coal will continue to be sufficient for Ohio Valley to ! l meet its debt and lease obligations. The contract with Ohio Valley expires in ! September 1997. l ( The CAPCO Group companies, including the Operating Companies, have a long-term l contract with Quarto and Consol for the supply of about 752-85% of the annual l coal needs of the Mansfield Plant. The contract runs through at least the end i ! of 1999, and the price of coal is adjustable to reflect changes in labor, l materials, transportation and other costs. The CAPC0 Group companies have guaranteed, severally and not jointly, the debt and lease obligations incurred by Quarto to develop, equip and operate two of the mines which supply the , Mansfield Plant. At December 31, 1993, the total dollar amount of Quarto's j debt and lease obligations guaranteed by Cleveland Electric was $33,380,000 and by Toledo Edison was $19,522,000. Centerior, Cleveland Electric and Toledo Edison expect that Quarto revenues from sales of coal to the CAPCO Group companies will continue to be sufficient for Quarto to meet its debt and lease obligations. The Operating Companies' least cost plan for complying with the Clean Air Act I Amendments, which was included in the agreement approved by the PUC0 in February 1993 in connection with the Operating Companies' 1992 long-term forecast, calls for greater use of low-sulfur coal and less use of high-sulfur coal. Some of the low-sulfur coal required to comply with Phase 1 of the
- Clean Air Act Amendments was contracted for in 1992. Additional supplies of low-sulfur coal will be contracted for in 1994. The only long-term coal contract affected by the Clean Air Act Amendments is Cleveland Electric's contract with Ohio Valley.
Nuclear. The acquisition and utilization of nucleer fuel involves six dis-tinct steps: (1) supply of uranium oxide raw material, (ii) conversion to uranium hexafluoride, (iii) enrichment. (iv) fabrication into fuel assemblies, (v) utilization as fuel in a nuclear reactor and (vi) storing or disposing of spent fuel. The Operating Companies have inventories of raw material i sufficient to provide nuclear fuel through 1996 for the operation of their nuclear generating units and have contracts for fabrication services for all of that fuel. The CAPCO Group companies have a 30-year contract with the DOE which will supply all of the needed enrichment services for their nuclear j units' fuel supply through 1995. Beyond 1995, the amount of enrichment j services under the DOE contract varies by CAPCO Group company, with Cleveland ! Electric's and Toledo Edison's enrichment services reduced to 702 in 1996-1999 l and reduced to 02 in 2000-2002. The additional required enrichment services are available. Substantial additional fuel will have to be obtained in the
t l future over the remaining useful lives of the units. There is a plentiful supply of uranium oxide raw material to meet the industry's nuclear fuel needs. Off-site disposal of spent nuclear fuel is unavailable, but the CAPCO Group companies have contracts with the DOE which provide for the future acceptance j of spent fuel for disposal by the Federal government. Pursuant to the Nuclear l Waste Policy Act of 1982, the Federal government has indicated it will begin
- accepting spent fuel from utilities by the year 2010. On-site storage capacity at Davis-Besse, Perry Unit 1 and Beaver Valley Unit 2 should be sufficient through 1996, 2009 and 2008, respectively. Any additional storage i capacity needed for the period until the government accepts the fuel can be j provided for either on-site or off-site by the time it is needed. ,
011. The Operating Companies each have adequate supplies of oil and. fuel for their oil-fired electric generating units which are used primarily as reserve and peaking capacity. l l l l ! i 1 i l l l 1 l l I i l I i f 1 l b
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I i I EXECUTIVE OFFICERS OF THE REGISTRANTS AND THE SERVICE COMPANY Set forth below are the names, ages as of March 15, 1994, and business experience during the past five years (effective dates of positions in parentheses) of the executive officers of Centerior Energy, the Service Company, Cleveland Electric and Toledo Edison. Positions currently held are designated with an asterisk (*). Business Experience Name (Age) Centerior Energy Service Company Cleveland Electric Toledo Edison Robert J. Farling
- Chairman of the
- Chairman of the
- Chairman of the
- Chairman of the ,
(57) Board and Chief Board and Chief Eoard and Chief Board and Chief Executive Officer Executive Executive Officer Executive Officer (March 1992) Officer (March (February 1989 to (October 1988 to
- President 1992) April 1990; July April 1990; July '
(October 1988)
- President (July 1993) 1993) j 1988)
Murray R. Edeiran
- Executive Vice
- Executive Vice
- President *Vice Chairman (54) President President- (November 1993) (November 1993)
(July 1988) Operations & President (July 1988) e Engineering n (July 1993) , Executive Vice President-Power Generation
.(April 1990) i I
Business Experience Centerior Energy Service Company Cleveland Electric Toledo Edison Name (Age) Fred J. Lange, Jr.
- Senior Vice
- Senior Vice *Vice President
- President (November (44) President President- (April 1990) 1993)
(July 1993) Fossil & Vice President (April Senior Vice Transmission 1990) President-Legal, and Distribution Hmman & Corporate Operations Affairs (March (July 1993) 1992) Senior Vice Vice President- President-Legal, Legal & Corporate Human & Affairs (April Corporate Affairs 1990) (March 1992) Vice President-Legal & Corporate Affairs (April 1990) General Attorney and i Senior Director of n Governmental Affairs " (July 1989) Assistant General Counsel and Principal Corporate Counsel (November 1986) Donald C. Shelton
- Senior Vice Vice President-(60) President-Nuclear Nuclear (August (July 1993) 1986)
Vice President-Nuclear-Davis-Besse (April 1990)
Business Experience Name (Age) Centerior Energy Service Company Cleveland Electric Toledo Edison Jacquita K. Hauserman *Vice President- *Vice President (51) Customer Support (November 1993) j (July 1993) Vice President-Vice President- Administration Customer Service (October 1988)
& Community Affairs (April 1990)
Gary R. Leidich *Vice President *Vice President- *Vice President & *Vice President & (43) (July 1993) Finance & Chief Financial Chief Financial ' Administration Officer (July Officer (July , (July 1993) 1993) 1993) Director-Human Resources Dept. (August 1991) ! Director-System
- Planning N
Engineering Dept. (December 1987)
- .1
Business Experience Name (Age) Centerior Energy Service Company Cleveland Electric Toledo Edison Terrence G. Linnert *Vice President *Vice President- *Vice President *Vice President (47) (July 1993) Legal & (July 1993) (July 1993) ' Gove rnmental Affairs and General Counsel (July 1993) Vice President-Legal and General Counsel (March 1992) General Counsel and Director- t Legal Services Dept. (May 1990) General Counsel (July 1989) Principal Counsel (June 1987) David L. Monseau *Vice President- Vice President-(53) Transmission & Customer Distribution Operations Operations (September 1987) (April 1990) i
Business Experience Name (Age) Centerior Energy Service Company Cleveland Electric Toledo Edison Robert A. Stratman *Vice President- General Manager-(45) Nuclear-Perry Perry Plant (December 1992) Operations Dept. (April 1990) Director-Perry Plant Nuclear Engineering Dept. (January , 1989)
^' o Temple *Vice President-(4o, Marketing (February 1994)
WMX Technologies, Inc.: Alliance Executive (July 1992) Vice President / i General Manager, i w Midwest Region (April 1991) . Director of Marketing, . Chemical Waste i Management (June 1989) Borg Warner Chemicals: General Mgr., Multi- , National Accts. (November 1988) { f t
I l Business Experience Name (Age) Centerior Energy Service Company Cleveland Electric Toledo Edison Paul G. Busby
- Controller (April
- Controller (June
- Controller (April
- Controller (April (45) 1988) 1986) 1990) 1990)
Gary M. Hawkinson
- Treasurer
- Treasurer (April
- Treasurer (April
- Treasurer (April 1990)
(45) (February 1986) 1986) 1990) Assistant Treasurer Assistant Treasurer (August 1987) (September 1986) E. Lyle Pepin
- Secretary
- Secretary (April
- Secretary (October
- Secretary (October (52) (February 1986) 1986) 1988) 1988)
I t,M B
l l All of the executive officers of Centerior Energy, the Service Company, Cleveland Electric and Toledo Edison are elected annually for a one-year term by the Board of Directors of Centerior, the Service Company, Cleveland Electric or Toledo Edison, as the case may be. ( tio family relationship exists among any of the executive officers and direc-l tors of any of the Centerior System companies. ( Item 2. Properties GENERAL 1 The Centerior System 1 The wholly owned, jointly owned and leased electric generating f acilities of I l the Operating Companies in commercial operation as of February 28, 1994 pro-vide the Centerior System with a net demonstrated capability of 5,980,000 1 kilowatts during the winter. These facilities include 20 generating units (3,634,000 kilowatts) at seven fossil-fired steam electric generation sta-tions; three nuclear generating units (1,856,000 kilowatts); a 351,000 kilo-watt share of the Seneca Plant; seven combustion turbine generating units (135,000 kilowatts) and one diesel generator (4,000 kilowatts). Operations at two fossil-fired generating units (320,000 kilowatts) ceased in 1993 and the units are being preserved for future use. All of the Centerior System's generating facilities are located in Ohio and Pennsylvania. The Centerior System's net 60-minute peak load of its service area for 1993 l was 5,397,000 kilowatts and occurred on August 27. At the time of the 1993 l peak load, the operable capacity available to serve the load was 5,998.000 l kilowatts. The Centerior System's 1994 service area peak load is forecasted to be 5,250,000 kilowatts, after demand-side management considerations. The operable capacity expected to be available to serve the Centerior System's 1994 peak is 5,670,000 kilowatts. Over the 1994-1996 period, Centerior Energy forecasts its operable capacity margins at the time of the projected Centerior System peak loads to range from 72 to 9.5%. l Each Operating Company owns the electric transmission and distribution facili-ties located in its respective service area. Cleveland Electric and Toledo ! Edison are interconnected by 345 kV transmission facilities, some portions of which are owned and used by Ohio Edison. The Operating Companies have a long-l term contract with the CAPCO Group companies, including Ohio Edison, relating l to the use of these facilities. These interconnection facilities provide for the interchange of power between the two operating Companies. The Centerior system is interconnected with Ohio Edison, Ohio Power, Penelec and Detroit Edison.
Cleveland Electric , The wholly owned, jointly owned and leased electric generating facilities of Cleveland Electric in commercial operation as of February 28, 1994 provide a net demonstrated capability of 4,148,000 kilowatts during the winter. These facilities include 16 generating units (2,709,000 kilowatts) at five fossil-fired steam electric generation stations: its share of three nuclear generat-ing units (1,026,000 kilowatts): a 351,000 kilowatt share of the Seneca Plant: two cembustion tutbine generatin ts (58,000 kilowatts) and one diesel gen-erator (4,000 kilowatts). Operations at one fossil-fired generating unit (245,000 kilowatts) ceased in October 1993 and the unit is being preserved for future use. All of Cleveland Electric's generating facilities are located in Ohio and Pennsylvania. The net 60-minute peak load of Cleveland Electric's service area for 1993 was , 3,862,000 kilowatts and occurred on July 28. The operable capacity at the time of the 1993 peak was 4,122,000 kilowatts. Cleveland Electric's 1994 service area peak load is forecasted to be 3,790,000 kilowatts, after demand-side management considerations. The operable capacity, which includes firm purchases, expected to be available to serve Cleveland Electric's 1994 peak is 4,018,000 kilowatts. Over the 1994-1996 period, Cleveland Electric forecasts its operable capacity margins at the time of its projected peak loads to range from 61 to 9%. Cleveland Electric owns the facilities located in the area it serves for transmitting and distributing power to all its customers. Cleveland Electric has interconnections with Ohio Edison, Ohio Power and Penelec. The intercon- i nections with Ohio Edison provide for the interchange of electric power with the other CAPCO Group companies and for transmission of power from the tenant-in-co-non owned or leased CAPCO Group generating units as well as for.the , interchange of power with Toledo Edison. The interconnection with Penelec provides for transmission of power from Cleveland Electric's share of the ' Seneca Plant. In addition, these interconnections provide the means for the interchange of electric power with other utilities. 1 Cleveland Electric has interconnections with each of the municipal systems operating within its service area. l Toledo Edison The wholly owned, jointly owned and leased electric generating f acilities of Toledo Edison in commercial operation as of February 28, 1994 provide a net demonstrated capability of 1,832,000 kilowatts during the winter. These facilities include six generating units (925,000 kilowatts) at three fossil-fired steam electric generation stations; its share of three nuclear generating units (830,000 kilowatts) and five combustion turbine generating units (77,000 kilowatts). Operations at one fossil-fired generating unit (75,000 kilowatts) teased in July 1993 and the unit is being preserved for future use. All of Toledo Edison's generating facilities are located in Ohio 1 and Pennsylvania. 1 l l f The net 60-minute peak load of Toledo Edison's service area for 1993 was 1,568,000 kilowatts and occurred on August 27. The operable capacity at the time of the 1993 peak was 1,874,000 kilowatts. Toledo Edison's 1994 service area peak load is forecasted to be 1,490,000 kilowatts, after demand-side management considerations. The operable capacity, which includes the effect of firm sales, expected to be available to serve Toledo Edison's 1994 peak is 1,652,000 kilowatts. Over the 1994-1996 period, Toledo Edison forecasts its operable capacity margins at the time of its projected peak loads to range from 0% to 10%. Toledo Edison owns the facilities located in the area it serves for trans-mitting and distributing power to all its customers. Toledo Edison has interconnections with Ohio Edison, Ohio Power and Detroit Edison. The in-terconnection with Ohio Edison provides for the interchange of electric power with the other CAPCO Group companies and for transmission of power from the tenant-in-common owned or leased CAPCO Group generating units as well as for the interchange of power with Cleveland Electric. In addition, these inter-connections provide the means for the interchange of electric power with other utilities. Toledo Edison has interconnections with each of the municipal systems operating within its service area. TITLE TO PROPERTY The generating plants and other principal facilities of the operating Companies are located on land owned in fee by them, except as follows: (1) Cleveland Electric and Toledo Edison lease from others for a term of about 29-1/2 years starting on October 1, 1987 undivided 6.5%, 45.9% and 44.38% tenant-in-common interests in Units 1, 2 and 3, respectively, of the Mansfield Plant located in Shippingport, Pennsylvania. Cleveland Electric and Toledo Edison lease from others for a term of about 29-1/2 years starting on October 1, 1987 an 18.26% undivided tenant-in-common interest in Beaver Valley Unit 2 located in Shippingport, Pennsylvania. Cleveland Electric and Toledo Edison own another 24.47% interest and 1.65% interest, respectively, in Beaver Valley Unit 2 as a tenant-in-common. Cleveland Electric and Toledo Edison continue to own as a tenant-in-common the land upon which the Mansfield Plant and Beaver Valley Unit 2 are located, but have leased to others certain portions of that land relating to the above-mentioned generating unit leases. (2) Most of the facilities of Cleveland Electric's Lake Shore Plant are situated on artificially filled land, extending beyond the natural shore-line of Lake Erie as it existed in 1910. As of December 31, 1993, the cost of Cleveland Electric *s facilities, other than water intake and discharge facilities, located on such artificially filled land aggregated approximately $112,026,000. Title to land under the water of Lake Erie within the territorial limits of Ohio (including artificially filled land) is in the State of Ohio in trust for the people of the State for the public uses to which it may be adapted, subject to the powers of the United States, the public rights of navigation, water commerce and fishery and the rights of upland owners to wharf out or fill to make use of the water. The State is required by statute, after appropriate pro-ceedings, to grant a lease to an upland owner, such as Cleveland Elec-tric, which erected and maintained facilities on such filled land prior to October 13, 1955. Cleveland Electric does not have such a lease from the State with respect to the artificially filled land on which its Lake shore Plant facilities are located, but Cleveland Electric's position, on advice of counsel for Cleveland Electric, is that its facilities and occupancy may not be disturbed because they do not interfere with the free flow of commerce in navigable channels and constitute (at least in part) and are on land filled pursuant to the exercise by it of its to the property rights as owner of the land above the shoreline adjacent filled land. Cleveland Electric holds permits, under Federal statutes relating to navigation, to occupy such artificially filled land. (3) The facilities of Cleveland Electric's Seneca Plant in Warren County, Pennsylvania, are located on land owned by the United States and occupied by Cleveland Electric and Penelec pursuant to a license issued by the FERC for a 50-year period starting December 1, 1965 for the construction, operation and maintenance of a pumped-storage hydroelectric plant. (4) The water intake and discharge facilities at the electric generating plants of Cleveland Electric and Toledo Edison located along Lake Erie, the Maumee River and the Ohio River are extended into the lake and rivers under their property rights as owners of the land above the water line and pursuant to permits under Federal statutes relating to navigation. (5) The transmission systems of the Operating Companies are located on land, easements or rights-of-way owned by them. Their distribution systems also are located, in part, on interests in land owned by them, but, for the most part, their distribution systems are located on lands owned by others and on streets and highways. In most cases, permission has been obtained from the apparent owner of the property or, if the distribution system is located on streets and highways, from the apparent owner of the abutting property. Their electric underground transmission and distri-bution systems are located, for the most part, in public streets. The Pennsylvania portions of the main transmission lines from the Seneca Plant, the Mansfield Plant and Beaver Valley Unit 2 are not owned by Cleveland Electric or Toledo Edison. All Cleveland Electric and Toledo Edison properties, with certain exceptions, are subject to the lien of their respective mortgages. The fee titles which Cleveland Electric and Toledo Edison acquire as tenant-in-common owners, and the leasehold interests they have as joint lessees, of certain generating units do not include the right to require a partition or sale for division of proceeds of the units without the concurrence of all the other owners and their respective mortgage trustees and the trustees under Cleveland Electric's and Toledo Edison's mortgages. Item 3. Legal Proceedings Regulatory Proceedings and Suits Contesting Sulfur Dioxide Emission Limitations and Related Regulations Applicable to the Operating Companies. See " Item 1. Business--Environmental Regulation--Air Quality Control" Westinghouse Lawsuit. In April 1991, the CAPCO Group companies filed a lawsuit against Westinghouse in the United States District Court for the Western District of Pennsylvania. The suit alleges that six steam generators supplied by Westinghouse for Beaver Valley Power Station Units 1 and 2 contain serious defects, particularly defects causing tube corrosion and cracking. Steam generator maintenance costs have increased due to these defects and will likely continue to increase. The condition of the steam generators is being monitored closely. If the corrosion and cracking continue, replacement of the uteam generators could be required earlier than their 40-year design life. The suit seeks monetary and corrective relief. General Electric Lawsuit. On February 2, 1994, the CAPCO Group companies announced that a settlement had been reached with General Electric regarding the lawsuit filed by the CAPCO Group companies against General Electric in August 1991. In that suit which was filed in the United States District Court in Cleveland, the CAPC0 Group companies as joint owners of the Perry Plant alleged that General Electric had provided defective design informatica relating to the containment vessels for Perry Units 1 and 2. The CAPCO Group companies also alleged that the required corrective actions caused extensive delays and cost increases in the construction of the Perry Plant. i Under the settlement agreement, General Electric will provide the CAPCO Group companies with discounts on future purchases and cash payments. The value of the settlement depends on the volume of future purchases. Because the payments will be made over a period of years and the discounts will be offered over the life of the plant, they will not have a material impact on the financial results of Centerior, Cleveland Electric and Toledo Edison in any particular year or on their financial conditions. The terms of the settlement agreement are the subject of a confidentiality agreement. Item 4. Submission of Matters to a Vote of Security Holders CENTERIOR ENERGY, CLEVELAND ELECTRIC AND TOLEDO EDISON None. PART II l 1 Item 5. Market for Registrants' Common Equity and Related Stockholder Matters The information regarding common stock prices and i.7mber of share owners required by this Item is not applicable to Cleveland Elect-ic or Toledo Edison because all of their common stock is held solely by Centerior Energy. Market Information Centerior Energy's common stock is traded on the New York Chicago and Pacific Stock Exchanges. The quarterly high and low prices of Centerior common stock (as reported on the composite tape) in 1992 and 1993 were as follows: 1992 1993 High Low High Low 1st Quarter $20 $17-7/8 $20 $18-5/8 2nd Quarter 18-5/8 16-3/8 19-7/8 17-3/8 3rd Quarter 17-3/4 15-3/4 18-7/8 17-3/8 4th Quarter 20 17-1/8 17-7/8 12 Share Owners As of March 15, 1994, Centerior Energy had 159,506 common stock share owners of record. Dividends See Note 14 to Centerior's Financial Statements for quarterly dividend pay-ments in the last two years. See " Outlook--Common Stock Dividends" in Management's Financial Analysis contained under Item 7 of this Report for a discussion of the payment of future dividends by Centerior and the Operating Companies. At December 31, 1993 Centerior Energy had a retained earnings deficit of $523 million and capital surplus of $2 billion, resulting in an overall surplus of $1.477 billion that was available to pay dividends under Ohio law. Any current period earnings in 1994 will increase surplus under Ohio law. See Note 11(c) to Centerior's Financial Statements and Note 11(b) to the Operating Companies' Financial Statements for discussions of dividend restrictions affecting Cleveland Electric and Toledo Edison. Dividends paid in 1993 on each of the Operating Companies' outstanding series of preferred stock were fully taxable. The operating Companies believe that all or a portion of their preferred stock dividends paid in 1994 will be a return of capital because they intend to take a deduction for the abandonment of Perry Unit 2. Item 6. Selected Financial Data CENTERIOR ENERGY l The information required by this Item is contained on Pages F-23 and F-24 attached hereto.
CLEVELAND ELECTRIC The information required by this Item is contained on Pages F-46 and F-47 attached hereto. TOLEDO EDISON The information required by this Item is contained on Pages F-68 and F-69 attached hereto. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations CENTERIOR ENERGY The information required by this Item is contained on Pages F-3 through F-6 attached hereto. CLEVELAND ELECTRIC The information required by this Item is contained on Pages F-26 through F-29 attached hereto. TOLEDO EDISON The information required by this Item is contained on Pages F-49 through F-52 attached hereto. 1 Item 8. Financial Statements and Supplementary Data CENTERIOR ENERGY The information required by this Item is contained on Pages F-2 and F-7 through F-22 attached hereto. CLEVELAND ELECTRIC The information required by this Item is contained on Pages F-25 and F-30 through F-45 attached hereto. l TOLEDO EDISON I The information required by this Item is contained on Pages F-48 and F-53 through F-67 attached hereto. Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure CENTERIOR ENERGY, CLEVELAND ELECTRIC AND TOLEDO EDISON None. PART III Item 10. Directors and Executive Officers of the Registrants CENTERIOR ENERGY l The information required by this Item for Centerior regarding directors is incorporated herein by reference to Pages 4 through 8 of Centerior's definitive proxy statement dated March 23, 1994. Reference is also made to " Executive Officers of the Registrants and the Service Company" in Part I of this Report for information regarding the executive officers of Centerior Energy. CLEVELAND ELECTRIC Set forth below are the name and other directorships held, if any, of each director of Cleveland Electric. The year in which the director was first elected to Cleveland Electric's Board of Directors is set forth in paren-thesis. Reference is made to " Executive Officers of the Registrants and the Service Company" in Part I of this Report for information regarding the directors and executive officers of Cleveland Electric. The directors received no remuneration in their capacity as directors. Robert J. Farling* Mr. Farling is a director of National City Bank. (1986) Murray R. Edelman Mr. Edelman is a director of Society Bank & Trust. (1993) Fred J. Lange, Jr. (1993)
- Also a director of Centerior Energy and the Service Company.
I TOLEDO EDISON Set forth below are the name and other directorships held, if any, of each director of Toledo Edison. The year in which the director was first elected to Toledo Edison's Board of Directors is set forth in parenthesis. Reference is made to " Executive Officers of the Registrants and the Service Company" in Part I of thic Report for information regarding the directors and the executive officers of Toledo Edison. The directors received no remuneration in their capacity as directors. I l i I Robert J. Farling* Mr. Farling is a director of Naticaal City Bank. (1988) Murray R. Edelman Mr. Edelman is a director of Society Bank & Trust. (1993) Fred J. Lange. Jr. (1993)
*Also a director of Centerior Energy and the Service Company.
Item 11. Executive Compensation i CENTERIOR ENERGY, CLEVELAND ELECTRIC _AND TOLEDO EDISON The information required by this Item for Centerior is incorporated herein by reference to the information concerning compensation of directors on Page 9 and the information concerning compensation of executive officers, stock option transactions, long-term incentive awards and pension benefits on Pages 17 through 25 of Centerior's definitive proxy statement dated March 23, 1994. The named executive officers for Centerior are included for Cleveland Electric and Toledo Edison regardless of whether they were officers of Cleveland Electric or Toledo Edison because they were key policymakers for the Centerior System in 1993. Item 12. Security Ownership of Certain Beneficial Owners and Management J CENTERIOR ENERGY The following table sets forth the beneficial ownership of Centerior common stock by individual directors of Centerior, the named executive officers and all directors and executive officers of Centerior Energy and the Service Company as a group as of February 28, 1994:
Name of. Beneficial Number of Common owner Shares Owned (1) Richard P. Anderson 1,444 Albert C. Bersticker 1,000 Leigh Carter 2,257 Thomas A. Commes 5,000 Wayne R. Embry 1,000 Robert J. Farling 23,970 (2) George H. Kaull 4,842 Richard A. Miller 12,027 Frank E. Mosier 1,591 Sister Mary Marthe Reinhard, SND 500 (3) Robert C. Savage 1,000 William J. Williams 1,649 Murray R. Edelman 7,488 (2) Donald C. Shelton 1,665 Fred J. Lange, Jr. 1,270-David L. Monseau 4.164 (2) Lyman C. Phillips (4) 706 All' directors and executive officers as a group 89,726 (2) (1) Beneficially owned shares include any shares with respect to which voting or investment power is attributed to a director or executive officer because of joint or fiduciary ownership of the shares or relationship to the record owner, such as a spouse, even though the director or executive officer does not consider himself or herself the beneficial owner. On February 28, 1994, all directors and executive officers of Centerior Energy and the Service Company as a group were considered to own bene-ficially 0.1% of Centerior's common stock and none of the preferred stock of Cleveland Electric and Toledo Edison. Certain-individuals disclaim-beneficial ownership of some of those s ha r e s '. (2) Includes the following numbers of shares which are not owned but could have been purchased within 60 days after February 28, 1994 upon exercise of options to purchase shares of Centerior common stock: Mr. Farling - 6,832; Mr. Edelman - 5,550; Mr. Monseau - 1,665; and all directors and executive officers as a group - 15,612. None of those options have been exercised as of March 28, 1994. (3) Owned by the Sisters of Notre Dame. (4) Mr. Phillips is included in the table because he would have been one of the five most highly compensated executive officers had he not retired on November 1, 1993. CLEVELAND ELECTRIC Individual directors of Cleveland Electric, the named executive officers and all directors and executive officers of Cleveland Electric as a group as of March 15, 1994 beneficially owned the following number of shares of Centerior common stock on February 28, 1994: Name of Beneficial Number of Common Owner Shares Owned (1) Robert J. Farling 23,970 (2) Murray R. Edelman 7,488 (2) Donald C. Shelton 1,665 Fred J. Lange, Jr. 1,270 David L. Monseau 4,164 (2) Lyman C. Phillips (3) 706 All directors and executive officers as a group 51,602 (2) (1) Beneficially owned shares include any shares with respect to which voting or investment power is attributed to a director or executive officer because of joint or fiduciary ownership of the shares or relationship to the record owner, such as a spouse, even though the director or executive officer does not consider himself or herself the beneficial owner. On February 28, 1994, all directors and executive officers of Cleveland Electric as a group were considered to own beneficially 0.03Z of l Centerior's ccmmon stock and none of Cleveland Electric's serial preferred l stock. Certal, individuals disclaim beneficial ownership of some of those ' shares. (2) Includes the following numbers of shares which are not owned but could have been purchased within 60 days after February 28, 1994 upon exercise of options to purchase shares of Centerior common stock: Mr. Farling - 6,832; Mr. Edelman - 5,550; Mr. Monseau - 1,665; and all directors and executive officers as a group - 15,612. None of those options have been exercised as of March 28, 1994. (3) Mr. Phillips is included in the table because he would have been one of the five most highly compensated executive officers had he not retired on November 1, 1993. TOLEDO EDISON Individual directors of Toledo Edison, the named executive officers and all directors and executive officers of Toledo Edison as a group as of March 15, 1994 beneficially owned the following number of shares of Centerior common stock on February 28, 1994: 1 l l l l Name of Beneficial Number of Common l Owner Shares Owned (1) l i Robert J. Farling 23,970 (2) i ! I Murray R. Edelman 7,488 (2) Donald C. Shelton 1,665 Fred J. Lange, Jr. 1,270 David L. Monseau 4,164 (2) Lyman C. Phillips (3) 706 All directors and executive officers as a group 44,249 (2) (1) Beneficially owned shares include any shares with respect to which voting or investment power is attributed to a director or executive officer because of joint or fiduciary ownership of the shares or relationship to the record owner, such as a spouse, even though the director or executive officer does not consider himself or herself the beneficial owner. On February 28, 1994, all directors and executive officers of Toledo Edison as a group were considered to own beneficially 0.03% of Centerior's common stock. Certain individuals disclaim beneficial ownership of some of those shares. t l (2) Includes the following numbers of shares which are not owned but could j have been purchased within 60 days after February 28, 1994 upon exercise of options to purchase shares of Centerior common stock: Mr. Farling - 6,832; Mr. Edelman - 5,550; Mr. Monseau - 1,665; and all other executive officers as a group - 15,612. None of those options have been exercised as of March 28, 1994 f (3) Mr. Phillips is included in the table because he would have been one of I the five most highly compensated executive officers had he not retired on November 1, 1993. Item 13. Certain Relationships and Related Transactions CENTERIOR ENERGY, CLEVELAND ELECTRIC AND TOLEDO EDISON l None. PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) Documents Filed as a Part of the Report
- 1. Financial Statements:
Financial Statements for Centerior Energy, Cleveland Electric and Toledo Edison are listed in the Index to Selected Financial Data; Management's Discussion and Analysis of Financial Condition and Re-sults of Operations; and Financial Statements. See Page F-1.
- 2. Financial Statement Schedules:
Financial Statement Schedules for Centerior Energy, Cleveland Electric and Toledo Edison are listed in the Index to Schedules. See Page S-1.
- 3. Combined Pro Forma Condensed Financial Statements (Unaudited):
Combined Pro Forma Condensed Financial Statements (unaudited) for Cleveland Electric and Toledo Edison related to their pending merger. See Pages P-1 to P-4.
- 4. Exhibits:
Exhibits for Centerior Energy, Cleveland Electric and Toledo Edison are listed in the Exhibit Index. See Page E-1. (b) Reports on Form 8-K During the quarter ended December 31, 1993 Centerior Energy, Cleveland Electric and Toledo Edison did not file any Current Reports on Form 8-K. l l t U SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. j CENTERIOR ENERGY CORPORATION Registrant March 30, 1994 By
- ROBERT J FARLING, Chairman of the ;
Board, President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this re-port has been signed below by the following persons on behalf of the regi-strant and in the capacities and on the date indicated: Signature Title Date Principal Executive Officer )
- ROBERT J. FARLING Chairman of the Board, )
President and Chief ) l Executive Officer ) Principal Financial Officer: )
- GARY R. LEIDICH Vice President and ) 1 Chief Financial ) l Officer ) l Principal Accounting Officers
- PAUL G. BUSBY Controller )
Directors: )
- RICHARD P. ANDERSON Director )
- ALBERT C. BERSTICKER Director )
*LEIGH CARTER Director )
- THOMAS A. COMMES Director ) March 30, 1994
- WAYNE R. EMBRY Director ) I 1
l
- ROBERT J. FARLING Director )
- GEORGE H. KAULL Director )
- RICHARD A. MILLER Director ) J
- FRANK E. MOSIER Director )
*SR. MARY MARTHE REINHARD, SND Director )
- ROBERT C. SAVAGE Director )
{
- WILLIAM J. WILLIAMS Director )
*By J. T. PERCIO J. T. Percio, Attorney-in-Fact SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY Registrant l March 30, 1994 By
- ROBERT J. FARLING, Chairman of the l
I Board and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this re-port has been signed below by the following persons on behalf of the regi- l l strant and in the capacities and on the date indicated l Signature Title Date Principal Executive Officers )
- ROBERT J. FARLING Chairman of the Board ) ,
and Chief Executive ) ! Officer ) Principal Financial Officer: )
- GARY R. LEIDICH Vice President and )
Chief Financial ) March 30, 1994 Officer ) Principal Accounting Officer: )
- PAUL G. BUSBY Controller )
Directors: )
- ROBERT J. FARLING Director )
*MURRAY R. EDELMAN Director )
- FRED J. LANGE, JR. Director )
*By J. T. PERCIO J. T. Percio. Attorney-in-Fact l
l SIGNATURES , Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. THE TOLEDO EDISON COMPANY Registrant March 30, 1994 By
- ROBERT J. FARLING, Chairman of the l Board and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this re-f port has been signed below by the following persons on behalf of the regi-l l strant and in the capacities and on the date indicated:
1 I Signature Title Date Principal Executive Officer: )
- ROBERT J. FARLING Chairman of the Board )
and Chief Executive ) Officer ) Principal Financial Officer )
- GARY R. LE1CICH Vice President and )
Chief Financial ) l Officer ) Principal Accounting Officer: ) March 30, 1994
- PAUL G. BUSBY Controller )
Directors: )
- ROBERT J. FARLING Director )
*MURRAY R. EDELMAN Director )
l l
- FRED J. LANGE, JR. Director )
*By J. T. PERCIO J. T. Percio, Attorney-in-Fact INDEX TO SELECTED FINANCIAL DATA: MANAGEMENT'S DISCUSSION !
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF i OPERATIONS; AND FINANCIAL STATEMENTS 1 I Page Centerior Energy Corporation and Subsidiaries: Report of Independent Public Accountants . . . . . . . . . . . . . F-2 Management's Financial Analysis . . . . . . . . . . . . . . . . . F-3 Income Statement for the Years Ended December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . F-7 l Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . F-7 Balance Sheet as of December 31, 1993 and 1992 . . . . . . . . . F-8 I Cash Flows for the Years Ended December 31, 1993, 1992 and 1991 . F-10 j Statement of Preferred Stock at December 31, 1993 and 1992 . . . . F-11 Notes to the Financial Statements . . . . . . . . . . . . . . . . F-12 Financial and Statistical Review . . . . . . . . . . . . . . . F-23 The Cleveland Electric Illuminating Company and Subsidiaries: 1 Report of Independent Public Accountants . . . . . . . . . . . . . F-25 Management's Financial Analysis . . . . . . . . . . . . . . . F-26 Income Statement for the Years Ended December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . F-30 Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . . . . F-30 Cash Flows for the Years Ended December 31, 1993, 1992 and 1991 F-31 Balance Sheet as of December 31, 1993 and 1992 . . . . . . . . . . F-32 Statement of Preferred Stock at December 31, 1993 and 1992 . . F-34 Notes to the Financial Statements . . . . . . . . . . F-35 Financ!al and Statistical Review . . . . . . . . . . . . F-46 The Taledo Edison Company: Rerort of Independent Public Accountants . . . . . . . . . . F-48 M2nagement's Financial Analysis . . . . . . . . . . . . . . . F-49 Income Statement for the Years Ended December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . . . . . F-53 Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . . . . . F-53 Cash Flows for the Years Ended December 31, 1993, 1992 and 1991 . F-54 Balance Sheet as of December 31, 1993 and 1992 . . . . . . . . . F-55 Statement of Preferred Stock at December 31, 1993 and 1992 . . . . F-57 Notes to the Financial Statements . . . . . . . . . . . . F-58 Financial and Statistical Review . . . . . . . . . . . . . F-68 F-1 l
.. .. . . _~
REPORT OF In our opinion, the fmancial statements referred to above ' Present fairly, in all material respects, the financial posi-INDEPENDENT tion of Centenor Energy Corporation and subsidianes as PUBLIC ACCOUNTANTS of December 31,1993 and 1992, and the results of their operations and their cash flows for each of the three f To the Share Owners and ARTHUR Board of Directors of MNDERSEN years in the period ended December 31,1993, in con-
)
i g form.ty i w.th i generally accepted accountmg pnnciples. Centen.or Energy Corporation: l i As discussed further in Notes 1 and 9, changes were made We have audited the accompanying consolidated balance sheet and consolidated statement of preferred stock of in the methods of accounting for nuclear plant deprecia. Centerior Energy Corporation (an Ohio corporation) and tion in 1991 and for postretirement benefits other than subsidiaries as of December 31,1993 and 1992, and the pensions in 1993. related consolidated statements ofincome, retained earn- Our audits were made for the purpose of forming an ings and cash flows for each of the three years in the opinion on the basic financial statements taken as a period ended December 31,1993. These financial state- whole. The schedules of Centerior Energy Corporation ments and the schedules referred to below are the and subsidiaries listed in the Index to Schedules are responsibility of the Company's management. Our re-presented for purposes of complying with the Securities sponsibility is to express an opinion on these financial and Exchange Commission's rules and are not part of the statements and schedules based on our audits. basic financial statements. These schedules have been We conducted our audits in accordance with generally subjected to the auditing procedures applied in the audits accepted auditing standards. Those standards require that of the basic financial statements and, in our opinion, we plan and perform the audit to obtain reasonable fairly state in all material respects the financial data assurance about whether the financial statements are free required to be set forth therein in relation to the basic of material misstatement. An audit includes examining, financial statements taken as a whole. on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and ARTilUR ANDERSEN & CO. significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for Cleveland, Ohio our opinion. February 14,1994 i (Centerior Energy) F-2 (Centerior Energy)
M AN AG E M E NT'S me"'""d P 5 temp I Yme"t be"efi'S Deferred Per ti"3 expenses decreased because of the write-off of the phase-FIN ANCI AL ANALYSIS in deferred operating expenses in 1993 as discussed in 1 l Note 7. Federal income taxes decreased as a result of Results of Operations lower pretax operating income. , 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 l ing revenues are as follows: was written offin 1993. Credits for carrying charges Million, recorded in nonoperating income decreased because of increase (Decrease) in Operaune Revenues o.Lpollars the write-oft of the phase-in deferred carrying charges in Sales Volume and Mix $ 65 Base Rates and htiscellaneous 1993 as discussed in Note 7. The federal income tax (18) Fuel Cost Recosery Revenues . credit for nonoperating income in 1993 resulted from the _Lil) Total l_3p i The net revenue increase resulted primarily from the 1992 is. 1991 difTerent weather conditions and the changes in the com-position of the sales mix among customer categories. Factors contributing to the 4.8% decrease in 1992 operat-Weather accounted for approximately $53 million of the ing revenues are as follows: i higher 1993 revenues. Hot summer weather in 1993 Decrease in Oxratine Revenues of Dollars boosted residential, commercial and wholesale kilowatt- saics volume and Mix s 79 . hour sales, in contrast, the 1992 summer was the coolest Base Rates anct Misecilaneous 32 in 56 years in Northern Ohio. Residential and commer. ruel Cost Recovery Revenues _l.1 cial sales also increased as a result of colder late-winter Total 1122 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 differ-1993. Residential and commercial sales increased 4.6% ent weather conditions and the changes in the composi- j and 3.1%, respectively. Industrial sales increased 1.25 tion of the sales mix among customer categories. Increased sales to large automotive manufacturers, petro- Weather accounted for approximately $77 million of the i leum refiners and the broad-based, smaller industrial lower 1992 revenues. Winter and spring in 1992 were group were partially offset by lower sales to large steel milder than in 1991. In addition, the cooler summer in industry customers. Other sales increased 5.9% becaus: 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 lliuminating Company (Cleve- cluded the recognition by Toledo Edison of $24 million land Electric). of deferred revenues over the period of a refund to Operating expenses increased 13.7% m. 1993. The m.erease customers under a provision of its January 1989 rate m total operation and maintenance expenses resulted order. No such revenues were reflected in 1992 as the from the $218 million of net benefit expenses related t refund period ended in December 1991. The decrease in an early retirement program, called the Voluntary Tran- 1992 M m mg mvenues resulted from the good i sition Program (VTP), other charges totahng $54 million performance of our generating units, which in turn and an increase in other operation and maintenance decreased our fuel cost factors. The weighted averages expenses. Other charges recorded at year-end 1993 re- of these factors decreased approximately 3% for Cleve-lated to a performar.cc improvement plan for Perry land Electric and Toledo Edison (Operating Companies). 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-from higher environmental expenses, power restoration tized in 1991 and lower generation requirements stem-and repair expenses following a July 1993 storm in the ming from less electric sales. A reduction of $17 million Cleveland area, and an increase in other postrctirement in other operation and maintenance expenses resulted benefit expenses. See Note 9 for information on retire- primarily from cost-cutting measures. Federal income (Centerior Energy) F-3 (Centerior Energy)
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 elTects 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-decreases 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 Diiidends The federal income 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 of interest charges to nonoperating barring unforeseen circumstances and that the new strate-activities. Credits for carrying charges recorded in non- gic plaa will provide the opportunity to grow the divi-operating income decreased primarily because of lower 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 mterest 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. Outbok 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- will 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
% hile the plan has a long-term focus, ,ti also required us to take some very diflicult, but necessary, financial ac-
*## "I * #8 # '
l I tions at that time. We reduced the quarterly common ! stock dividend from 5.40 per share to $.20 per share Competition etTective 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 ur nuclear construction program. Accordingly, some of rate. We also wrote off our investment in Perry Unit 2 ur customers continue to seek less costly alternatives, and certain deferred charges related to a January 1989 rate agreement (phase-in deferrals). The aggregate af- including switching to or working to create a municipa1 , electric system. There are a number of rural and mun,ci- i ter-tax etTect of these write-ofTs was $1.023 billion p 1 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 sysicms. improvement plan for Perry Unit I, postemployment Accordingly, they will not proceed with such develop-benefits and other expense accruals. ment at this time in return for rate concessions and/or Also contributing to the net loss in 1993 was a charge of economic development funds. Others have determined
$87 million after taxes representing a portion of the VTP that developing a system was not feasible. Cleveland costs. We will realize approximately $50 million of Public Power continues to expand its operations into areas savings in annual payroll and benefit costs beginning in we have served exclusively. We have been successfulin 1994 as a result of the VTP. retaining most of the large industrial and commercial customers in 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 our customers the value of our service and attain increasingly competitive power supply costs. To the risks of a municipal system. (Centerior Energy) F-4 (Centerior Energy)
The Energy Policy Act of 1992 (Energy Act) will provide We externally fund the estimated costs for the future additional competition in the electric utility industry by decommissioning of our nuclear units. In 1993, we in-requiring utilities to wheel to municipal systems in their creased our decommissioning expense accruals for revi-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(e). 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 wholesale 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) Rate Matters f r three sites listed on the Superfund National Priorities List (Superfund List) and are aware of their potential i Our Rate Stabilization Program remains in effect. Under involvement in the cleanup of reveral other sites not on this program, we agreed to freeze base rates until 1996 such list. The allegations that the Operating Companies and limit rate increases through 1998. In exchange, we disposed of hazardous waste at these sites and the are permitted to defer through 1995 and subsequently amounts involved are often unsubstantiated and subject to 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. However, we believe that the actual cleanup costs sures will be dependent 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 I such deferrals in future rates. substantially less than 100% and that most of the other
{ Our analys.is leading to the year-end 1993 financial ac- PRPs are fmancially able to contribute their share. The i tions and strategic plan also included an evaluation of our Operating Companies have accrued a liability totaling $19 regulatory accountmg measures. We decided that, once million at December 31,1993 based on estimates of the the deferral of expenses and acceleration of benefits costs of cleanup and their proportionate responsibility under our Rate Stabilization Program are completed in for such costs. We believe that the ultimate outcome of 1995, we should no longer plan to use regulatory account- these matters will not have a matenal adverse efTect on ing measures to the extent we have m the past. our financial condition or results of operations. Nuclear Operations The Revenue Reconciliation Act of 1993 (1993 Tax Our three nuclear units may be impacted by actis.ities or events beyond our control. Operating nuclear generating Act), which was enacted in August 1993, provided for a umts have experienced unplanned outages or extensions 35% income tax rate in 1993. The 1993 Tax Act did not of scheduled outages because of equipment problems or rnaterially impact the results of operations for 1993, but t new regulatory requirements. A major accident at a did alTect certain Balance Sheet accounts as discussed in nuclear facility anywhere m the world could cause the Note 8. The 1993 Tax Act is not expected to materially Nucleai Regulatory Commission (NRC) to h,mit or pro- impact future results of operations or cash flow. hibit the operation or licensing of any nuclear unit. If one of our nuclear units is taken out of service for an Inflation extended period of time for any reason, including an Although the rate of inflation has eased in recent years, accident at such unit or any other nuclear facility, we w e are still affected by even modest inflation which causes cannot predict whether regulatory authorities would im-increases in the unit cost of labor, materials and services. pose unfavorable rate treatment. Such treatment could include taking our afTected unit out of rate base or Cap.ital Resources and Liquidity disallowing certain construction or maintenance costs. An extended outage of one of our nuciear units coupled with 1991-1993 Cash Requirements unfavorable rate treatment could have a material ad-verse efTect on our financial condition and results of We need cash for normal corporate operations, the operations. mandatory retirement of securities and an ongoing pro-(Centerior Energy) F5 (Centerior Energy)
gram of constructing new facilities and modifying 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 affected 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 and other considerations. We expect to complete this We raised $2.2 billion through security issues and term process in the second quarter of 1994. We will provide the bank loans during the 1991-1993 period as shown in the same security interest to certain other creditors because Cash Flows statement. During the three-year period, their agreements require equal treatment. We expect to the Operating Companies also utilized their short-term provide second mortgage collateral for $219 million of borrowing arrangements to help meet their cash needs. unsecured debt, $228 million of bank letters of credit and a $205 million revolving credit facility.. For the next five Although the write-offs of Perry Unit 2 and the phase-in years, the Operatmg Companies do not expect to raise deferrals in 1993 negatively affected our earnings, they funds through the sale of debt j,um,or to first mortgage did not adversely affect our current cash flow. bonds. However, if necessary or desirable, the Operatmg Companies believe that they could raise funds through the sale of unsecured debt or debt secured by the second 1994 and lleyond Cash Requirements mortgage referred to above. The Operating Companies Estimated cash requirements for 1994-1998 for Cleveland also are able to raise funds through the sale of preference , Electric and Toledo Edison, respectively, are $791 mil- stock and, in the case of Cleveland Electric, preferred lion and $249 million for their construction programs and stock. Toledo Edison will be unable to issue preferred $715 million and $324 million for the mandatory re- stock untilit can meet the interest and preferred dividend demption of debt and preferred stock. Cleveland Electric coverage test in its articles of incorporation. Centerior and Toledo Edison expect to finance internally all of their Energy will continue to raise funds through the sale of 1994 cash requirements of approximately $239 million common stock. and $109 million, respectively. About 15-20% of the 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 Prime", respectively. We have a $205 million revolving Our capital requirements are dependent upon our imple* credit facility which will run through mid-1996. However, mentation strategy to achieve compliance with the Clean we currently cannot draw on this facility because the Air Act Amendments of 1990 (Clean Air Act). Cash write-offs taken at year-end 1993 caused us to fail to expenditures for our plan are estimated to be approxi- meet certain capitalization and fixed charge coverage mately $128 million over the 1994-1998 period. See Note covenants. We expect to have this facility available to us 4(a). again after it is amended in the second quarter of 1994 to provide the participating creditors with a second mort-gage security interest. Liquidity These financing resources are expected to be suflicient for Additional first mortgage bonds may be issued by the Operating Companies under their respective mortgages the Operating Companies' needs over the next several on the basis of property additions, cash or refundable first years. The availability and cost of capital to meet our external financing needs, however, also depend upon such mortgage bonds. Under their respective mortgages, each 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 sn Moodes Electric and Toledo Edison would have been permitted to nrst mortgage bonds BB Ba2 issue appmximately $78 million and $323 million of Unsecured notes B+ Ba3 Preferred stock B bl additional first moiigage bonds, respectively. After the fourth quarter of 199? Cleveland Electric's ability to issue first mortgap M is expected to increase substan- These ratings reflect a downgrade in December 1993. In tially when its inteet o : rage ratio will no longer be addition, S&P has issued a negative outlook for the affected by the write-ofis .ecorded at December 31,1993. Operating Companies. (Centerior Energy) F-6 (Centerior Energy)
INCOME STATEMENT cenrector enecer coreo,arion ans sussisiaries For the years ended Decembel_3L_ l 1993 1992_ 1991 (millions of dollars, except per share amounts) l Ope.ating Revenues $2.474 $2,560 ' 122 4.J8_ Operating Expenses Fuel and purchased power 474 473 500 Other operation and maintenance 811 784 801 Early retirement program expenses and other 272 - - 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 2.161 1.901 1.981 Operating income 3l3 537 579 Nonoperating income (Loss) Allowance for equity funds used during construction 5 2 9 Other income and deductions, net (6) 9 6 Write-off of Perry Unit 2 (583) - - Deferred carrying charges, net (649) 100 110 Federal income taxes - credit (expense) 395 (7) (3.0) (835) 104 95 income (Loss) Before Interest Charges and Preferred Dividends (522) 641 674 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) l44.9 141.7 11.92 Earnings (Loss) Per Common Share
$L62) $ 1.50 $ 1.71 Dividends Declared Per Common Share $lhQ $ 1,60 $_ l&Q RETAINED EARNINGS For the years ended December 31.
1993 1992 1991 (millions of dollars) Retained Earnings at Beginning of Year $ 652 $ 669 $ 655 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) l Net increase (Decrease) (1.175) (17) 14 Retained Earnings (Defcit) at End of Year $ _(ji21) $ 652 $ 669 The accompanying notes are an integral part of these statements. l l l (Centerior Energy) F-7 (Centerior Energy)
CASH FLOWS centeno, encru co, vocation ans sussisiaries For the years ended December 31. 1993 1992 1991 l (millions of dollars) Cash Flowsfrom Operating Activities (1) Net Income (Loss) _ $_(94_l) $ 212 $ 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-off of Perry Unit 2 583 - - Changes in amounts due from customers and others, net 1 7 14 Changes in inventories 26 (10) (22) Changes in accounts payable 45 (5) (49) Changes in working capital afTecting 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) Prem' ims, discounts and expenses (13) __(H) (7) Net Cash from Financing Activities (194) (32_J) (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) - Other cash received (applied) 23 (36) (1) Net Cash from Investing Activities (191) _(280) (195) Net Change in Cash and Temporary Cash Investments In (84) 124 Cash and Temporary Cash investments at Beginning of Year 93 177 53 Cash and Temporary Cash investments at End of Year $__2_25 $_ 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. (Centerior Energy) F-8 (Centerior Energy)
l BAL ANCE SHEET December 31. l 1993 1992 (millions of dollars) ASSETS Property, Plant and Equipment Utility plant in service $ 9,571 $ 9,449 Less: accumulated depreciation and amortization 2.677 _2 m.48 8 6,894 6,961 Construction work in progress 181 167 Perry Unit 2 - 614 7,075 7,742 Nuclear fuel, net of amortization 344 385 Other property, less accumulated depreciation 41 39 7.460 8.I66 Current Assets l Cash and temporary cash investments 225 93 Amounts due from customers and others, net 221 222 Unbilled revenues 124 114 Materials and supplies, at average cost 136 129 Fossil fuel inventory, at average cost 32 65 Taxes applicable to succeeding years 250 247 Other 5 7 993 877 Deferred Charges and Other Assets Amounts due from customers for future federal income taxes 968 975 Unamortized loss from Beaver Valley Unit 2 sale 105 110 Unamortized loss on reacquired debt 92 101 Carrying charges and operating expenses 862 1,533 Nuclear plant decommissioning trusts 56 42 l Other 174 267 l 2 257 3 028 Total Assets $12,0B
$10.2LO The accompanying notes are an integral part of this statement.
i l l (Centerior Energy) F-9 (Centerior Energy)
- . _ . . - . . - =_ - - - - -- Centerior Energy Corporation and Subsidiaries December 31. 1993 1992 (millions of dollars) CAPITALIZATION AND LIABILITIES 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) ($23) __j12 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 1 694 6J68 7.301 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 fuellease obligations 111 118 Notes payable to banks and others - 50 Accounts payable 188 143 Accrued taxes 378 368 Accrued interest 87 84 Other 75 59 966 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 _2122 1158 Total Capitalization and Liabilities $J0.710 112.071 l l l (Centerior Energy) F-10 (Centerior Energy)
! STATEMENT OF l PREFERRED STOCK ceniccior tnero cori,orazion ons sussisiaries Current 1993 Shares Call Price _ lkE m bit.ll m Outstandine Per Share 1993 1992 CLEI' ELAND ELECTRIC (millions or dollars) Without par value, 4,000.000 preferred shares authorized i 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 < 9.125 Series N 600,000 103.04 59 74 91.50 Series Q 75,000 - 75 75 88.00 Series R 50,000 - 50 50 90.00 Series S 75,000 - 74 74 l 314 343 ) Less: Current maturities 29 29 285 _.).14 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 - 9 2_41 _14d 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 12 _ 28 50 Not subject to mandatory redemption:
$100 par $ 4.25 160,000 104.625 16 16 1
1 4.56 50,000 101.00 5 5 4.25 100,000 102.00 10 10 8.32 100,000 102.46 10 10 7.76 150,000 102.437 15 15 7.80 150,000 101.65 15 15 10.00 190,000 101.00 19 19 25 par 2.21 1,000,000 25.25 25 25 2.365 1,400,000 27.75 35 35 Series A Adjustable ___ 1,200,000 25.75 30 30 Series B Adjustable __. 1,200,000 25.75 30 30 210 210 CENTERIOR ENERGl' Without par value, 5,000,000 preferred shares authorized, none outstanding - - Total Preferred Stock, with Afandatory Redemption Provisions
$313. $hf Total Preferred Stock, without Afandatory Redemption P.orisions $451 $314 The accompanying notes are an integral part of this <atement.
(Centerior Energy) F-11 (Centerior Energy)
NOTES TO THE ^ fuel factor is added to the base rates for electric service-Ms f et r b designed t rec m fmm cust niers the FINANCI AL STATEMENTS costs of fuel and most purchased power. It is reviewed (1) Summary of Significant and djusted semiannu tiy in PuCO proceeding. Accounting Policies (c) roei Expense { (a) General The cost of fossil fuel is charged to fuel expense based on Centerior Energy is a holding company with two electric utility subsidiaries, Cleveland Electric and Toledo inventory usage. The cost of nuclear fuel, including an interest component, is charged to fuel expense based on Edison. The consolidated financial 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. owned subsidiary, Centerior Senice Company (Service Company), and Cleveland Electric's wholly owned sub- The Operating Companies defer the differences between sidia.ies. The Service Company provides management, actual fuel costs and estimated fuel costs currently being financial, administrative, engineering, legal and other ser- recovered from customers through the fuel factor. This vices at cost to Centerior Energy and the Operating matches fuel expenses with fuel-related revenues. Companies. The Operating Companies operate as sepa-rate companies, each serving the customers in its servi'e Owners of nuclear generating plants are assessed by the federal government for the cost of decontamination and area. The preferred stock, first mortgage bonds and otLer debt obligations of the Operating Companies are out- decommissioning of nuclear enrichment facilities oper-ated by the United States Department of Energy. The standing securities of the issuing utility. All significant intercompany items have been eliminated in assessments are based upon the amount of enrichment consolidation. services used in prior years and cannot be imposed for 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) 71 which governs accounting for the etrects of certain (d) Deferred Carrying Charges types of rate regulation. The Service Company follows and Operating Expenses 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 llolding Company Act of 1935. and Beaver Valley Power Station Unit 2 (Beaver Valley 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 hase constructed and operate generation and transmission facilities for their Beginning in January 1989, the Operating Companies use. deferred certain operating expenses and both interest and equity carrymg charges pursuant to PUCO-approved rate (b) Resenues phase-in plans for their investments in Perry Unit I and Customers are billed on a monthly cycle basis for their Beaver Valley Unit 2. These deferrals, called phase-in energy consumption based on rate schedules or contracts deferrals, were written oft at December 31,1993. See authorized by the PUCO or on ordinances ofindividual Nm 7' 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. (Centerior Energy) F-12 (Centerior Energy)
(e) Depreciation and Amortization external Nuclear Plant Decommissioning Trusts because The cost of property, plant and equipmt nt is depreciated the reserve began prior to the external trust funding. 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- Nputy, plant and equipment are stated at original cost ciable utility plant in service was 3.5% in 1993 and 3.4% less amounts ordered by the PUCO to be written off. in both 1992 and 1991. Effective January 1,1991, the Construction costs include related payroll taxes, pen-Operating Companies, after obtaining PUCO approval, si ns, fringe benefits, managt ment and general overheads changed their method of accounting for nuclear plant and allowance for funds used during construction depreciation from the units-of-production method to the (AFUDC). AFUDC represents the estimated composite straight-line method at about a 3% rate. This change debt and equity cost of funds used to finance construction. decreased 1991 depreciation expense $36 million and This noncash allowance 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 l ofincome taxes) and earnings per share $.20 from what 10.7% in 1991. they otherwise would have been. The PUCO subse-Maintenance and repairs are charged to expense as in-quently approved in 1991 a change to lower the 3% rate to curred. The cost of replacing plant and equipment is 2.5% retroactive to January 1,1991. charged to the utility plant accounts. The cost of property Pursuant to a PUCO order, the Operating Companies retired plus removal costs, after deducting any salvage currently use external funding for the future decommis- value, is charged to the accumulated provision 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) Deferied Gain and Loss from decontamination). Cash contributions are made to the Sales of Utility Plant trust funds on a straight-line basis over the remaining The sale and leaseback transactions discussed 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 customert based on prior Generating Plant (Mansfield Plant) and a net loss for the estimates is approximately $8 milbon.*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. Thi Debt Interest reported in the Income Statement does not estimates for Perry Unit I and Davis-Besse are prehmi-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 Compames used these estimates to increase their decommissioning ex- Losses and gains realized upon the reacquisition or re-pense accruals 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 amorized over the remainder of the original life 31, 1993, Accumulated Depreciation and imortization 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. (Centerior Energy) F-13 (Centerior Energy)
l l (e) Depreciation and Amortizatior. external Nuclear Plant Decommissioning Trusts because The cost of property, plant and equipment is depreciated the reserve began prior to the external trust funding. l 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. Pl ant and equipment are stated at original cost ciable utility plant in service was 3.5% in 1993 and 3.4% less amounts ordered by the PUCO to be written off. in both 1992 and 1991. EfTective January 1,1991, the Construction costs include related payroll taxes, pen-Operating Companies, after obtaining PUCO approval, si ns, fringe benefits, management and general overheads changed their method of accounting for nuclear plant nd allowance for funds used during construction depreciation from the units-of-production method to the ( AFUDC). AFUDC represents the estimated composite ; straight-line method at about a 3% rate. This change debt and equity cost of funds used to finance construction. I decreased 1991 depreciation expense $36 million and This noncash allowance is credited to income. The { increased 1991 net income $28 million (net of $8 million AFUDC rates averaged 9.9% in 1993,10.8% in 1992 and l of income taxes) and earnings per share $.20 from what 10.7% in 1991. they otherwise would have been. The PUCO subse-Maintenance and repairs are charged to expense as in- I quently approved in 1991 a change to lower the 3% rate to curred. The cost of replacing plant and equipment is 2.5% retroactive to January 1,1991. charged to the utility plant accounts. The cost of property Pursuant to a PUCO order, the Operating Companies retired plus removal costs, after deducting any salvage currently use external funding for the future decommis- value, is charged to the accumulated provision 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 decontamination). Cash contributions are made to the Sales of Utility Plant trust funds on a straight-line basis over the remaining The sale and leaseback transactions discussed in Note 2 j licensing period for each unit. The current level of annual resulted in a net gain for the sale of the Bruce Mansfield i expense being recovered from customers based on prior Generating Plant (Mansfield Plant) and a net loss for the l estimates is approximately $8 million. However, actual sale of Beaver Valley Unit 2. The net gain and net loss I 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 j 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. I second quarter of 1994. The Operating Compames used these estimates to increase their decommissioning ex- Losses and gains realized upon the reacquisition or re-pense accruals 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 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. (Centerior Energy) F-13 (Centerior Energy) 1
(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 i 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 i 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 i Adoption of SFAS 109 in 1992 did not materially affect leasehold interests) for events of default. These events our results of operations, but did afTect certain Balance include noncompliance with several finandal covenants Sheet accounts. See Note 8. discussed in Note ll(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 differences 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 refmanced The majority of these temporary difTerences are attributa- through a tender offer and the sale of new bonds having a , ble to property-related basis difTerences. Included in lower interest rate. As part of the refinancing 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 through rates. Since this component 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 leases at December 31,1993 are summarized as follows: recovered over the lives of the related assets. Year A mount 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 amortization of certain unrestricted excess deferred taxes m5 165 and unrestricted investment tax credits under the Rate m6 m Stabilization Program. Later Years 24:2 (2) Utility Plant Sale and Toiai rutore Minimum tease rayments 14,23 3. Leaseback Transactions Rental expense .is accrued on a stra.ight-I.me bas.is 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 epnse for the Mansfield Plant leases was $115 millior,. The amounts recorded in megawatts),45.9% (358 megawatts) and 44.38% (355 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 29% 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 , Valley Unit 2 leased capacity entitlement to Cleveland and maintenance expenses and all other similar costs for 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. (Centerior Energy) F-14 (Centerior Energy)
(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 obligatect 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 classification of Property, Plant and Equipment l at December 31,1993 includes the following facilities owned by the Operating Companies as tenants in common with other utilities and Lessors: In- Plant Construction Senice Ownership Ownership Power in Work in Accumulated Generatine Unit Date Share Megawatts Source service Progress Depreciation (millions of dollars) Seneca Pumped Storage 1970 80.00% 351 Ilydro 5 67 $- $ 22 Eastlake Unit 5 1972 68.80 411 Coal 156 ' Perry Unit 1 1987 51.02 609 Nuclear 2.832 11 473 Beaver Valley Unit 2 and Common Facilities (Note 2) _.__ 1987 26.12 214 Nuclear 1.480 5 255 Total
$4.535 1 !.11 $710 Depreciation for Eastlake Unit 5 has been accumulated with all other nonnuclear depreciable property rather than by specific units of depreciable property.
(4) Construction and strategy. If a different plan is required by the U.S. EPA, significantly higher capital expenditures could be re-Contingencies quired during the 1994-2003 period. We believe Ohio (a) Construction Program law permits the recovery of compliance costs from cus-The estimated cost of our construction program for the tomers in rates. 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 ownership share, or cancellation. greater use of low-sulfur coal at some of our units and the We wrote olT 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 $583 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) llazardous Waste Disposal Sites pated rate increase associated with the capital expendi-tures and higher expenses would be about 1-2% in the The Operating Companies are aware of their potential nvolvement in the cleanup of three sites listed on the late 1990s. Cleveland Electric may need to install sulfur Superfund List 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. We also are seeking United States Environmental Protec- estimates of the costs of cleanup and their proportionate 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
"' PI "'
adverse effect 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. (Centerior Energy) F-15 (Centerior Energy)
N (5) Nuclear Operations and total amount of financing currently available under these lease arrangements is $382 million ($232 million from Contingencies intermediate-term notes and $150 million 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 l unfavorable rate treatment, could have a material ad- of nuclear fuel was financed. The Operating Companies verse efTect on our financial condition and resuhs of severally lease their respective portions of the nuclear i operations. See discussion of these risks in Management's fuel and are obligated to pay for the fuel as it is consumed j Financial Analysis - Outlook-Nuclear Operations. in a reactor. The lease rates are based on various intermediate-term note rates, bank rates and commercial i (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 financed 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 incident. 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 and 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 nnd 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 cludes the meremental 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 week during follow pursuant to PUCO orders. We concluded that 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 week for the next 104 the phase-in deferrals as scheduled because of economic l weeks. The amount and duration of extra expense could and competitive pressures. Accordingly, we wrote ofTthe substantially exceed the insurance coverage. cumulative balance of the phase-in deferrals. The total phase-in deferred operating expenses and carrying charges written off 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 (Centerior Energy) F-16 (Centerior Energy)
-- -- - - . .- - - ~ - - - - - . . - - . - - - - --
- l i
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 e spected 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 Income Tax sures to the extent we have in the past. Federal income tax, computed by multiplying the income 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 j 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 i993 jo92 j99). l Electric and $89 million for Toledo Edison over the (minims or dollars) 1996-1998 period ~ n k lac me (L u) Ber m redaal Income Tax illlM) $M 14M As part of the Rate Stabilization Program, the Operating Tax (Credit) on Book income (Loss) at Companies are allowed to defer and subsequently recover certain costs not currently recovered in rates and t [a Rate ggg s (442) s138 $158 write-orr of Perry Unit 2 46 - - I accelerate amortization of certain benefits. Such regula- Wriie-off or phase-in dererrals 28 - - tory accounting measures provide for rate stabilization by Depreciation (6) (9) 1 l rescheduling the timing of rate recovery of certain costs Rate stabilization Program (30) (7) - l and the amortization of certain benefits during the 1992- Other items t7 7 9 1995 period. The continued use of these regulatory Total federal Income Tax Expense (Credit) _ $ (387) $j29 1!68 accounting measures will be dependent upon our continu- 1 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 1991 (millions or dollars) The regulatory accounting measures we are eligible to Operating Expenses: record through December 31,1995 include the deferral of C""*"' $ % $ 71 5 88 c . Iax Pronsim
. Changes m Accumulated Deferred Federal post-in-service interest carrying charges, deprec. ia tion ex- Income Tax:
pense and property taxes on assets placed in service after write-off or deferred operating expenses. (39) - - February 29,1988 and the deferral of Toledo Edison Accelerated depreciation and operating expenses equivalent to an accumulated excess amortization 95 39 17 l rent reserve for Beaver Valley Unit 2 (which resulted Aliernative mmimum tax credit (57) (31) (46) Retirement and postemployment from the April 1992 refinancing of SLOBS as discussed benerits (43) - - in Note 2). The cost deferrals recorded in 1993 and 1992 sale and leaseback transactions and amortization 9 8 4 pursuant to these provis. ions were $95 mi!! ion and $84 Taxes, other than federalincome taxes (25) 19 - 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 Deterred ruel costs (2) (1) 19) 30 years, and will commence with future rate recognition. Other items (14) 3 23 The regulatory account.mg measures also provide for the Investment Tax Credits - - 39 Total Charged to Operating Expenses' 11 122 138 accelerated amortizat. ion of certa.m unrestricted excess Nonoperating Income: deferred tax and unrestricted investment tax credit bal-ances and interim spent fuel storage accrual balances for Current Tax Provision (34) (38) (46) Changes in Accumulated Dererred federal Davis-Besse. The total amount of such regulatory bene. Income Tax: fits recognized in 1993 and 1992 pursuant to these Write- fr or deferred carrying charges _ (240) - - Write-off or Perry Unit 2 (158) - - provisions was $46 m.ll.i ion and $12 million, respectively. Disallowed nuclear costs 20 14 - Ra t " The Rate Stabilization Program also authorized the Op- ~ erating Companies to defer and subsequently recover the C i 8( n Net operating loss carryruruard (7) - 35 incremental expenses associated with the adoption of Other items __Q) (4) - the accounting standard for postretirement benefits other Total Expense (Credit) to than pensions (SFAS 106). In 1993, we deferred $96 Nonoperating Income (398) 7 30 million pursuant to this provision. Amortization and Total rederal Income Tax Expense (Credit), $1382) $__l g $_118 (Centerior Energy) F-17 (Centerior Energy) T
In August 1993, the 1993 Tax Act was enacted. Retroac- In 1993, we offered 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 ofTset the VTP
$90 million. The 1993 Tax Act is not expected to expenses.
materially impact future results of operations or cash flow. Net pension and VTP costs (credits) for 1991 through 1993 were comprised of the following components: Under SFAS 109, temporary differences and carryfor-wards resulted in deferred tax assets of $619 million and E E 1993 (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 ferred tax liabilities of $2.598 billion at December 31, in[r)sfcost on projected benefit 1992. These are summarized as follows: obligation 37 38 36 December 31 Actual nturn n plan assets (65) (24) (129)
;993 ,99p Net amortization and deferral _4 _L4.1) 65 Net pension costs (credits) (9) (16) (14)
(millions of dollars) VTP cost 205 - - Property, plant and equipment $1.845 52.125 Settlement gain _.L81) _- - Deferred carrying charges and operating expenses _ 206 368 Net costs (credits) g g) $_Llj!) Net operating loss carryforwards (108) (137) Investment tax credits (1R3) (190) Tiie following table presents a reconciliation of the funded Other (181) (131) status of the plan (s) at December 31,1993 and 1992. Net deferred tax liability 1LM $2.035 g g (millions of For tax purposes, net operating loss (NOL) carryforwards Actuarial present value of benefit obligations: of approximately $309 million are available to reduce vested benefits $333 5310 future taxable income and will expire in 2003 through Nonvested benefits _)) _40
. Accumulated benefit obligation 370 350 2005. The 35% tax efTect of the NOLs is $108 milh.on. Efrect of future compensation levels _H _l.21 Total projected benefit obligation 423 471 The Tax Reform Act of 1986 provides for an alternative Plan assets at fair market value _.1% _13 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 net loss (gain) from variance ,
***'i assumpdm and eWena 11 0 40) exceed the AMT. AMT credits of $171 million are Unrecogm. zed prior service cost 10 12 available to offset future regular tax. The credits may be Transition asset at January 1,1987 being amortized carried forward indefinitely, over 19 years f.42) _ (j99)
Net prepaid pension cost (accrued pension liability) included in other deferred charges
@ndits) in the Balance Sheet id) $_56 (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 pensiot, 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. (Centerior Energy) F-18 (Centerior Energy)
her Postretirement Benefits were 7.25% and 4.25%, respectively. The assumed annual ponsor a postretirement benefit plan which provides health care cost trend rates (applicable to gross eligible mployee groups certain health care, death and other charges) are 9.5% for medical and 8% for dental in 1994. tretirement benefits other than pensions. The plan is Both rates reduce gradually to a fixed rate of 4.75% in ntributory, with retiree contributions adjusted annu. 1996 and later years. Elements of the obligation alTected ly. The plan is not funded. A policy limiting the em, by contribution caps are significantly less sensitive to loyer's contribution for retiree medical coverage for the health care cost trend rate than other elements. If the ployees retiring after March 31, 1993 was imple. assumed health care cost trend rates were increased by ented in February 1993. 1% in each future year, the accumulated postretirement benefit obligation as of December 31,1993 would in-e adopted SFAS 106, the accounting standard for
>stretirement beneh.ts other than pensions, efTective Jan- crease by $11 m.llion i and the aggregate of the service and ry 1,1993. The standard requires the accrual of th interest cost components of the annual postretirement benefit cost would increase by $1 million.
pected costs of such benefits during the employees' pars of service. Previously, the costs of these benefits (c) Postemployment Benefits
!ere expensed as paid, which is consistent with ratemak-pg practices. Such costs totaled $9 million in 1992 and In 1993, we adopted SFAS 112, the new accounting ;10 million in 1991, which included medical benefits of standard which requires the accrual of postemployment 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-mount accrued for SFAS 106 costs for 1993 was $111 ment but before retirement, such as worker's compensa-qllion, of which $5 million was capitalized and $106 nihon was expensed as other operation and matntenance tion, disability benefits and severance pay. The adoption (penses. In 1993, we deferred incremental SFAS 106 of this accounting method did not materially affect our 1993 results of operations or financial position.
(penses totaling $96 million pursuant to a provision of te Rate Stabilization Program. See Note 7. he components of the total postretirement benefit costs (10) Guarantees ir 1993 were as follows: Cleveland Electric has guaranteed certain loan and lease oNQ obligations of two mining companies under two long-
- rvice cost for benefits earned $3 term coal purchase arrangements. Toledo Edison is also a terest cost on accumulated postretirement benefit party to one of these guarantee arrangements. This obligation 16 arrangement requires payments to the mining company N6 n1il$o oIer 2 ear 8 f r any actual expenses (as advance payments for coal)
TP curtailment cost (includes $16 million transition when the mines are idle for reasons beyond the control of obligation adjustment) _B the mining company. At December 31,1993, the princi-T '^I " 1111 pal amount of the mining companies' loan and lease he accumulated postretirement benefit obligation and obligations guaranteed by the Operating Companies was
- crued postretirement benefit cost at December 31,1993 $80 million.
e summarized as follows: , , minions of Dollars (l1) Capitah,zation ecumulated postretirement benefit obligation (a) Capital Stock Transactions attributable to: Shares sold, retired and purchased for treasury during the ull elig b c e plan participants ye n r M M are W in b
- Other active plan par 1icipants ,_R8 ) following tables.
Accumulated postretirement benefit obligation (258) recognized net loss from variance between assumptions (thousands of shares) nd experience Centerior Energy Common Stock: 14 amortized transition obligation Dividend Reinvestment and Stock 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 Balance Sheet 1J_10,1) Employee Purchase Plan 52 - Total Common Stock Sales 4,138 2,892 1,770 .t December 31,1993, the settlement rate and the long. Treasury Shares 26 _u72) _Lil) rm rate of annual compensation increase assumptions Net increase Lit! 2J20 M5J Centerior Energy) F-19 (Centerior Energy)
1993 IM I" (c) Equity Distribution Restrictions (thousands of shares)
# i i S*i"
i at edeIpI[ n The Operating Companies make cash available for the cleveland nectric sales
$ 91.50 Series Q -
funding of Centerior Energy's common stock dividends by l 75 88 00 Senes R - - 60 paying dividends on their respective common stock, 90.00 senes s - 75 L which are held solely by Centerior Energy. Federal law Cleveland Electric Reorements prohibits the Operating Companies from paying divi-IE 7s 00 series IE ($') ($f dends out of capital accounts. However, the Operating (2' Companies may pay preferred and common stock divi-
! Iris K 2 2 '
3 dends out of appropriated retained earnings and current Adjustable Series M (100) (100) (100) earnings. At December 31,1993, Cleveland Electric and 9.125 Series N (150) - - Toledo Edison Retirements Toledo Edison had $125 million and $42 million, re-
$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 Preferred 5 of sidiaries Not from paying a common stock dividend by a provision in its Subject to Mandatory Redemption:
mortgage. Cleveland Electric Sales Cl clanI![cNr'ic Retirements (d) Preferred and Preference Stock Net e ca c) 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 follow s: open market of up to 1,500,000 shares of our common shares To en e stock until June 30,1994. As of December 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 (b) Common Shares Reserted for Issue 3.000 1981 1.000 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 1,962,174 and 469,457 shares, respectively, at December 88.00 Series R 50.000 200l* I,000 31,1993. 90 00 series s 18,750 1999 1,000 Stock options to purchase unissued shares of common Toledo Edison Preferred:
$100 par $9.375 16,650 stock under the 1978 Key Employee Stock Option Plan 1985 100 25 par 2 8t . 400.000 1993 were granted at an exercise price of 100% of the fair 25 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 purchased during the three years 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-ees were as follows: issued Depositary Receipts, each representing b of a 1993 share of the Series T stock. 1992 1991 Options Outstanding at The annualized preferred dividend requirement for the December 31: Shares Operating Companies at December 31,1993 was 37.627 93.312 Option Prices 129.798 $68 million.
$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 fluctuate based on prevailing interest rates and market conditions. The dividend rates for these issues averaged 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.
(Centerior Energy) F-20 (Centerior Energy)
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 $25 par value for franchises held by them. Excluded from the liens, among Toledo Edison. No preference shares are currently out- other things, are cash, securities, accounts receivable, standing for either company. fuel, supplies and, in the case of Toledo Edison, automo-With respect to dividend and liquidation rights, each * #4" *""' Operating Company's preferred stock is prior to its prefer- Certain unsecured loan agreements of the Operating ence stock and common stock, and each Operating Companies contain covenants relating to capitalization Company's preference stock is prior to its common stock. ratios, fixed charge coverage ratios and limitations on (e) Long-Term Debt and Other secured financing other than through first mortgage bonds Borroumg Arrangements or certain other transactions. Two reimbursement agree-ments relating to separate letters of credit issued in Long-term debt, less current maturities, for the Operating connection with the sale and leaseback of 13eaver Valley Companies was as follows: Unit 2 contain several financial covenants alTecting Actual Centerior Energy and the Operating Companies. Among
" Int
^$eli these are covenants relating to fixed charge coverage Dee$"n'*,e"r' 31, December 31. ratios and capitalization ratios. The write-offs recorded at Year of Maturin 1993 1993 1993 December 31,1993 caused Centerior Energy and the f Operating Companies to violate certain covenants con.
(m,[,y,",5 ) nrst mortgage bonds: tained in a Cleveland Electric loan agreement and the two 1994 4.375% $ - $ 25 reimbursement agreements. The alTected creditors have 1994 13.75 4 waived those violations in exchange for our commitment tw5 1335 4 4 1995 7.00 to provide them with a second mortgage security inter-1 1
,993 g 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 88 6 6 We will provide the same security interest to certain 1997 13.75 4 4 other creditors because their agreements require equal 1997 N I I tw7 treatment. We expect to provide second mortgage collat-6a 25 31 31 1998 1018 eral for $219 million of unsecured debt, $228 million of 6 6 1998 13.75 4 4 bank letters of credit and a $205 million revolving credit 1998 7.00 l i U3CElIIY-1995 10.00 1 1 1999-2003 7.89 $68 468 20 +200s 834 260 264 2009 2013 7.68 436 436 (l2) Short-Term Borrowing 20!4-2018 8.07 513 511 Arrangements 2019-2023 7.89 733 _.__m 2.574 2,357 In May 1993, Centerior Energy arranged for a $205 Secured medmm tenn notes due 1995-2021 8 77 million, three-year revolving credit facility. The facility 963 860 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 o ep ..pahg banks. OnMor Enugy ad k Debentures due 2002 8.70 135 135 Service Company may borrow under the facility, with all Motion control notes due 1995- borrowings jointly and severally guaranteed by the Oper-2015 10.11 158 158 Other - net ating Companies. Centerior Energy plans to transfer any
@ 3 Total l ong-Term Debt of its borrowed funds to the Operating Companies,
$4 019 $M94 while the Service Company may borrow up to $25 Long-term debt matures during the next five years as million for its own use. The banks' fee is 0.5% per annum follows: $87 milhon in 1994,$317 milhon m 1995,$242 payable quarterly in addition to interest on any borrow-mdh.on in 1996, $94 milh.on m 1997 and $117 milh.on in ings. That fee is expected to increase to 0.625% when 1 998' 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 covenants 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 (Centerior Energy) F-21 (Centerior Energy)
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 participat.ing (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 $150 31,1993. 4 million for Toledo Edison. The Operating Companies ouarters Endgd
"" " 3" l are authorized by the PUCO to borrow from each other (Niions or t$ar ,'
on a short-term basis, except per share amounts) 1993 At December 31,1993, the Operating Companies 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 locome (Loss) $ 35 $ 34 $ 17 $(1,029) provide short-term funds because of their below invest- Average 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 5 (7.02) Dividends Paid Per (l3) Financial Instruments' 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 Dividends Paid Per (mi l ) Common Share $ A0 $.40 $.40 $ .40 Nuclear Plant Decommissioning Prefe d Stock, with Mandatory Redemption Provisions decreased by $81 milh.on, or $.56 per share, as a result of (including current portion) 354 349 405 408 the recording of $125 million of VTP pension-related Long-Term Debt (including benefits. current 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-off of Perry Unit 2 (see Note 4(b)), investment secunties. The fair value of the Operating the $877 million write-off 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 $.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 i The estimated fair values of all other financial instru. million under the Rate Stabilization Program approved I ments approximate their carrying amounts in the Balance by the PUCO in October 1992. See Note 7. Sheet at December 31,1993 and 1992 because of their short-term nature. l I I (Centerior Energy) F-22 (Centerior Energy)
l FINANCI AL AND l STATISTICAL REVIEW Operating Revenues (millions of dollars) ! ) 1 ' Steam Total Total Total lleatmg Operating Year Residential Commercial Industrial Other Retail Wholesale Electric & Gas Revenues a 1993 $768 716 m 1 13 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 1 1990 719 669 779 190 2 357 70 2 427 - 2 427 4 1989 686 617 747 204 2 254 107 2 361 - 2 361 1983 546 440 600 83 1 669 29 I 698 25 1723 Operating Expenses (millions of dollars) Other Deferred Fuel & Operation Depreciation Taxes. Operating Federal Total Purchased & & Other Than Expenses, Income Operating Year Power Maintenance Amortization FIT Net Taxes Expenses j 1993 $474 1083(a) 258 312 23(b) 11 $2161 1992 473 784 256 318 (52) 122 1901 , 1991 500 801 243(c) 305 1981 (6) 138 ! 1990 472 863 242 283 (34) 96 1922 1989 473 860 273 260 122 1929 (59) l 1983 464 384 145 172 - 184 1349 t Income (Loss) (millions of dollars) Federal Income Other Deferred Income (Loss) Income & Carrying Tax- Before , Operating AFUDC- Deductions. Charges. Credit Interest Debt Year income Equity Net Net ( Expense) Charges Interest 1993 $313 5 (589)(d) (649)(b) 398 (522) 359 4 1992 537 2 9 100 (7) 641 365 1991 579 9 6 110 674 (30) 381
; I990 505 8 (1) 205 (l3) 704 384 1989 432 17 14 299 689 (73) 369 1983 374 153 5 --
47 579 258 J Income (Loss) (millions of dollars) Common Stock (dollars per share & %) 4
' Return on Preferred & Average Average Preference Net Shares Common AFUDC- Stock Income Outstanding Earnings Stock Dividends Book Year Debt Dividends t Loss) (millions) ( Loss) Equity Declared Value 1993 $ (5) 67 $(943) 144.9 $(6.51) (40.3)% $1.60 $12.14 1992 (1) 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 1933 (54) 69 306 98.2(e) 3.11(c) 15.7 2.19(e) 20.24(e)
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. (b) Includes write-off of phase-in defer als of $877 million in 1993. consisting of $172 million of deferred operating expenses and $705 million of deferred carrying charges. (c) In 1991, the Operating Companies adopted a change in accounting for nuclear plant depreciation, changing from the units-cf production method to the straight-line method at a 2.5% rate. (Centerior Energy) F-23 (Centerior Energy)
Centerior Energy Corporation and Subsidiaries Electric Sales (millions of KWH) Electric Customers (year end) Residential Usage Average Average Average Pnce Revenue Industrial KWH Per Per Per Year Residential Commercial Industrial Wholesulc Other Total Residential Commercial & Other Total Customer KWII Customer 1993_ _ 6 974 7 306 11687 3 027 1 022 30 016 924 227 96 491 12 219 1 032 937 7 546 11.01c $830.99 1992_ _ 6 666 7 086 11 551 2 814 1 011 29 128 925 099 96 813 12 741 1 034 653 7 227 10.98 793.68 1991 _ 6 981 7 176 11 559 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 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 11 557 983 350 6 967 8.64 603.22 Load (MW & %) Energy (millions of KWil) Fuel Operable Capacity Elliciency-at Time Company Generated Tuci Cost BTU Per Peak Capacity Load Purchased Year of Peak Load Margin Factor Fossil Nuclear Total Power Total Per KWil KWil 1993 5 998 5 397 10.0% 61.6 % 21 105 10 435 31 540 273 31 813 1.39c 10 276 1992 6 430 5 091 20.8 63.4 17 371 13 814 31 185 (122) 31 % 3 1.45 10 395 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 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 1 650 26 032 1.72 10 419 Investment (millions of dollars) Construction Work In Total Utility Accumulated Progress Nuclear Property, Utility Plant in Depreciation & Net & Perry Tueland Plant and Plant Total Year Service Amortization Plant Unit 2 Other Equipment Additions Assets 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 11 829 1990 8 636 2 039 6 597 921 568 8 086 251 11 681 > 1989 8 398 1 824 6 574 945 592 8 111 217 11 454 1983 4 180 1 047 3 133 2 710 392(f) 6 235 785 6 922 Capitalization (millions of dollars & %) Preferred & Preference Preferred Stock. without Stock. with Mandatory Mandatory Redemption Year Common Stock Equity Redemption Provisions Provisions Long-Term Debt Total 1993 $1785 27% 313 5% 451 7% 4 019 61 % $6 568 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 l i 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. (e) Average shares outstanding and related per share computations reflect the Cleveland Electric 1.ll-for-one exchange ratio and the Toledo Edison one-for-one
. exchange ratio for Centerior Energy shares at the date of affiliation, April 29,1986.
(f) Restated for cliccts of capitalization of nuclear fuellease and financing arrangements pursuant to Statement of Financial Accounting Standards 71. I l i l l (Centerior Energy) F-24 (Centerior Energy)
. REPORT OF In our opinion, the fmancial statements referred to above 1 i INDEPENDENT Present fairly, in all material respects, the financial posi-tion of The Cleveland Electric illuminating Company PUBL1C ACCOUNTANTS and subsidiaries as or December 31,1993 and 1992, and 1 To the Share Owners of the results of their operations and their cash flows for e ch of the three years in the period ended December 31, The Cleveland Electric AN ERhN
- Illuminating Company; D I993, in conf rmity with generally accepted accounting pnneiples.
We have audited the accompanying consolidated balance ,
^8 8'" " * ' * *"" ""E * **'*
- sheet and consolidated statement of preferred stock of '
in the methods of accounting for nuclear plant deprecia-The Cleveland Electric illuminating Company (a wholly owned subsidiary of Centerior Energy Corporation) and tion in 1991 and for postretirement benefits other than
! subsidiaries as of December 31,1993 and 1992, and the pensi ns m 1993.
related consolidated statements of income, retained earn. Our audits were made for the purpose of forming an ings and cash flows for each of the three years in the opinion on the basic financial statements taken as a period ended December 31,1993. These financial state- whole. The schedules of The Cleveland Electric illumi-ments and the schedule: referred to below are the nating Company and subsidiaries listed in the Index to ! responsibility of the r%mpany's management. Our re. Schedules are presented for purposes of complying with sponsibility is to express an opinion on these financial the Securities and Exchange Commission's rules and are statements and schedules based on our audits. not part of the basic financial statements. These sched-We conducted our audits in accordance with generally ules have been subjected to the auditing procedures accepted auditing standards. Those standards require that applied in the audits of the basic financial statements and, we plan and perform the audit to obtain reasonable in our opinion, fairly state in all material respects the assurance about whether the financial statements are free financial data required to be set forth therein in relation of material misstatement. An audit includes examining, to the basic financial statements taken as a whole. on a test basis, evidence supporting the amounts and 4 disclosures in the financial statements. An audit also ARTilUR ANDERSEN & CO. includes assessing the accounting principles used and ~ significant estimates made by management, as well as Cleveland, Ohio evaluating the overall financial statement presentation. February 14,1994 We believe that our audits provide a reasonable basis for (except with respect to the matter discussed in Note our opinion. 15, as to which the date is March 25,1994) t 1 (Cleveland Electric) F-25 (Cleveland Electric) J
ment 1 expems, power restoration and repair expenses M AN AG EM ENT'S following a July 1993 storm, and an increase in other FIN ANCI AL AN ALYSIS postretirement benerit expenses. See Note 9 for informa-
. tion on retirement and postemployment benefits. De-Results of Operations ferred operating expenses decreased because of the 1993 vs.1992 write-oft of the phase-in deferred operating expenses in
. 1993 as discussed in Note 7. Federal income taxes de-Factors contributing to the 0.5% increase in 1993 operat-creased as a result of lower pretax operating income.
ing revenues for The Cleveland Electnc illummatmg Company (Company) are as follows: As discussed in Note 4(b), $351 million of our Perry Millions Nuclear Power Plant Unit 2 (Perry Unit 2) investment Increase (Decrease) in Onerating Revenues of Dollars was written oft in 1993. Credits for carrying charges 1
' I ree rded in nonoperating income decreased because of uelc st$ecIery evenues () the wnte-oft of the phase-in deferred carrying charges m, i Base Rates and Miscellaneous (10)
Wholesale Sales _.J1 1993 as discussed in Note 7. The federal income tax Total s._j credit for nonoperating income in 1993 resulted from the wnte-ofTs. The net revenue increase resulted primarily from the difTerent weather conditions and the changes in the com- 1992 ts.1991 position of the sales mix among customer categories. Factors contributing to the 4.5% decrease m. 1992 operat- 1 Weather accounted for approximately $36 million of the Ing revenues are as follows: higher 1993 revenues. Hot summer weather in 1993 boosted residential, commercial and wholesale kilowatt- Decrease in Oxrating Revenues o I rs hour sales. In contrast, the 1992 summer was the coolest sales volume and Mix 550 in 56 years in Northeastern Ohio. Residential and com- Base Rates and Miscellaneous 23 1 mercial sales also increased as a result of colder late- Fuel Con Recovery Revenues ].g winter temperatures in 1993 which increased electric M heating-related demand. As a result, total sales increased i 2.9% in 1993. Residential and commercial sales in- The revenue decreases resulted primarily from the difTer-creased 4.4% and 3.1%, respectively. Industrial sales ent weather conditions and the changes in the composi-decreased 1%. Lower sales to large steel industry custom- tion of the sales mix among customer categories. ers were partially otTset by increased sales to large Weather accounted for approximately $55 million of the automotive manufacturers and the broad-based, smaller lower 1992 revenues. Winter and spring in 1992 were industrial customer group. Other sales increased 11.9% milder than in 1991. In addition, the cooler summer in because of increased sales to wholesale customers. The 1992 contrasted with the summer of 1991 which was net decrease in 1993 fuel cost recovery revenues resulted much hotter than normal. As a result, total kilowatt-hour from changes in the fuel cost factors. The weighted sales decreased 3.5% in 1992. Residential and commer-average of these factors decreased approximately 5%. cial sales decreased 4.4% and 0.5%, respectively, as , Base rates and miscellaneous revenues decreased in 1993 moderate temperatures in 1992 reduced electric heating l primarily from lower revenues under contracts having and cooling demands. Industrial sales declined 0.4% as an reduced rates with certain large customers and a declin- 8.1% decrease in sales to the broad-based, smaller indus- I ing rate structure tied to usage. The contracts have been trial customer group completely ofTset an 8.8% increase negotiated to meet competition and encourage economic in sales to the larger industrial customer group. Sales to growth. steel producers and auto manufacturers within the large industrial customer group rose 10.9% and 7%, respec-Operating expenses increased 12.4% m. 1993. The m.erease ively. Other sales decreased 16.1% because of decreased m total operation and maintenance expenses resulted sales to wholesale customers and public authorities. The i from the $130 milhon of net benefit expenses related t decrease in 1992 fuel cost recovery revenues resulted i an early retirement program, called the Voluntary ' Iran-
, primarily because of the good performance of our gener-sition Program (VTP), other charges totaling $35 milhon ating units, which in turn decreased our fuel cost factors. I and an increase in other operation and mamtenance The weighted averages of these factors decreased ap- ,
expenses. The VTP benefit expenses consisted of $102 i cly 3%* I million of costs for the Company plus $28 million for the Company's pro rata share of the costs for its afIlliate, Operating expenses decreased 3.6% in 1992. Lower fuel Centerior Service Company (Service Company). Other and purchased power expense resulted from lower genera- I charges recorded at year-end 1993 related to a perform- tion requirements stemming from less electric sales and I ance improvement plan for Perry Nuclear Power Plant less amortization of previously deferred fuel costs than Unit I (Perry Unit 1), postemployment benefits and the amount amortized in 1991. Federal income taxes other expense accruals. The increase in other operation decreased because of the amortization of certain tax and maintenance expenses resulted from higher environ- benefits under the Rate Stabilization Program discussed 1 (Cleveland Electric) F-26 (Cleveland Electiic) \ _ -
in Note 7 and the efTects of adopting the new accounting growth, become an industry leader in customer satisfac-standard for income taxes (SFAS 109) in 1992. These tion, build a winning team and attain increasingly com-decreases were partially ofTset by higher depreciation and petitive power supply costs. To achieve these objectives, amortization, caused primarily by the adoption of SFAS the Company will continue controlling its operation and 109, and by higher taxes, other than federal income taxes, maintenance expenses and capital expenditures, reduce caused by increased Ohio property and gross receipts its outstanding debt, increase revenues by finding new taxes. Deferred operating expenses increased as a result uses for existing assets and resources, implement a broad of the deferrals under the Rate Stabilization Program. range of new marketing programs, increase revenues by i restructuring rates for various customers where appropri-The federal income tax provision for nonoperating income ate, improve the operating performance ofits plants and decreased because oflower carrying charge credits and a take other appropriate actions, greater tax allocation ofinterest charges to nonoperating activities. Credits for carrying charges recorded in non-operating income decreased pnmanly because oflower Common Stock Dividends phase-in-carrying charge credits. Interest charges de- Centerior Energy's common stock dividend has been creased as a result of debt refinancings at lower interest funded in recent years primarily by common stock divi-rates and lower short-term borrowing requirements. dends paid by the Company. We expect this practice to continue for the foreseeable future. Centerior Energy's lower common stock dividend reduces its cash outflow by about $120 million annually which,in turn, reduces Outlook the common stock dividend demands placed on the Com-Recent Actions Pany. The Company intends to use the increased retained , cash to repay debt more quickly than would otherwise be l In Janaary 1994, Centerior Energy Corporation (Center- the case. This will help improve the Company's capital-ior Energy), along with the Company and The Toledo ization structure and interest coverage ratios. l 1 Edison Company (Toledo Edison), announced a com-prehensive strategic action plan to strengthen their finan-cial and competitive positions. The Company and Toledo Competition ) Edison are the two wholly owned electric utility subsidi- Our electric rates are among the highest in our region aries of Centerior Energy. The plan established specific because we are recovering the substantial investment in objectives and was designed to guide Centerior Energy our nuclear construction program. Accordingly, some of and its subsidiaries through the year 2001. Several actions our customers continue to seek less costly alternatives, were taken at that time. Centerior Energy reduced its including switching to or working to create a municipal quarterly common stock dividend from $.40 per share to electric systemiThere are two municipal systems in our $.20 per share effective with the dividend payable Febru- service area. In addition, we face threats of other munici-ay 15,1994. This action was taken because projected palities in our service area establishing new systems and financial results did not support continuation of the divi- the expansion of an existing system. We have entered into dend at its former rate. The Company and Toledo Edison agreements with some of the communities which consid-also wrote off their investments in Perg Unit 2 and ered establishing systems. Accordingly, they will not certain deferred charges related to a January 1989 rate proceed with such development at this time in return for agreement (phase-in deferrals). The aggregate after-tax rate concessions and/or economic development funds. efTect of these write-offs for the Company was $691 Others have determined that developing a system was not million which resulted in a net loss in 1993 and a retained feasible. Cleveland Public Power continues to expand its earnings deficit. The write-offs are discussed in Notes operations into areas we have served exclusively. We have 4(b) and 7. The Company also recognized other one ' been successful in retaining most of the large industrial time charges totaling $25 million after taxes related to a and commercial customers in those areas by providing performance improvement plan for Perry Unit 1, post- economic incentive packages in exchange for sole-sup-employment benefits and other expense accruals, plier contracts. We also have similar contracts with cus-tomers in other areas. Most of these contracts have Also contributing to the net loss in 1993 was a charge of remaining terms of one to five years. We will continue to $51 million after taxes representing a portion of the VTP address municipal system threats through aggressive mar-costs. The Company will realize approximately $30 keting programs and emphasizing to our customers the million of savings in annual payroll and benefit costs value of our service and the risks of a municipal system. beginning in 1994 as a result of the VTP. The Energy Policy Act of 1992 (Energy Act) will provide additional competition in the electric utility industry by b""I'U" "" requiring utilities to wheel to municipal systems in their The objectives of the strategic plan are to maximize share sersice areas electricity from other utilities. This provi-owner return on Centerior Energy common stock from sien of the Energy Act should not significantly increase corporate assets and resources, achieve profitable revenue the competitive threat to us since the operating licenses (Cleveland Electric) F-27 (Cleveland Electric)
for our nuclear units have required us to wheel to munici- verse effect on our financial condition and results of pal systems in our service area since 1977. The Energy operations. Act also created a class of exempt wholesale generators which may increase competition in the wholesale power We externally fund the estimated costs for the future market. A further risk is the possibility that the govern'
, decommissioning of our nuclear units. In 1993, we in-ment could mandate that utilities deliver power from creased our decommissioning expense accruals for revi-another utility or generation source to their retail custom-sions in our cost estimates. We expect the increases ers. As mentioned above, we have contracts with many of associated with the new estimates will be recoverable in our large industrial and commercial customers. We w,ll i attempt to renew those contracts as they expire which will future rates. See Note 1(f).
help us compete if retail wheeling is permitted in the
- future, llazardous Waste Disposal Sites !
The Comprehensive Environmental Response, Compen-Rate Matters sation and Liability Act of 1980 as amended Our Rate Stabilization Program remains in effect. Under (Superfund) established programs addressing the cleanup this program, we agreed to freeze base rates until 1996 of hazardous waste disposal sites, emergency prepared-and limit rate increases through 1998. In exchange, we ness and other issues. The Company has been named as a are permitted to defer through 1995 and subsequently "Potentially responsible party" (PRP) for three sacs recover certain costs not currently recovered in rates and listed on the Superfund National Priorities List to accelerate the amortization of certain benefits. The (Superfund List) and is aware of its potential involve. amortization and recovery of the deferrals will begin with ment in the cleanup of several other sites not on such list. future rate recognition and will continue over the aver. The allegations that the Company disposed of hazardous age life of the related assets, or approximately 30 years. waste at these sites and the amounts involved are often The continued use of these regulatory accounting mea. unsubstantiated and subject to dispute. Superfund pro-sures will be dependent upon our continuing assessment vides that all PRPs to a particular site can be held liable and conclusion that there will be probable recovery of on a joint and several basis. Consequently,if the Com- , I such deferrals in future rates. pany were held liable for 100% of the cleanup costs of all of the sites referred to above, the cost could be as high as The analysis leading to the year-end 1993 financial ac- $250 million. However, we believe that the actual tions and strategic plan also included an evaluation of our cleanup costs will be substantially lower than $250 mil-regulatory accounting measures. We decided that, once lion, that the Company's share of any cleanup costs will l the deferral of expenses and acceleration of benefits be substantially less than 100% and that most of the under our Rate Stabilization Program are completed in other PRPs are financially able to contribute their share. 1995, we should no longer plan to use regulatory account- The Company has accrued a liability totaling $13 million ing measures to the extent we have in the past. at December 31,1993 based on estimates of the costs of cleanup and its proportionate responsibility for such costs. We believe that the ultimate outcome of these matters Nuclear Operations will not have a material adverse efTect on our financial The Company's three nuclear units may be impacted by activities or events beyond our control. Operating nuclear generating units have experienced unplanned outages or 1993 Tax Act extensions of scheduled outages because of equipment problems or new regulatory requirements. A major acci- The Revenue Reconciliation Act of 1993 (1993 Tax Act), which was enacted in August 1993, provided for a dent at a nuclear facility anywhere in the world could cause the Nuclear Regulatory Commission (NRC) to 35% income tax rate in 1993. The 1993 Tax Act did not limit or prohibit the operation or licensing of any nuclear m terially impact the results of operations for 1993, but did affect certain Balance Sheet accounts as discussed in unit. If one of our nuclear units is taken out of service for N te 8. The 1993 Tax Act is not expected to materially an extended period of time for any reason, including an accident at such unit or any other nuclear facility, we impact future results of operations or cash flow. cannot predict whether regulatory authorities would im-pose unfavorable rate treatment. Such treatment could Inflation include taking our affected unit out of rate base or disallowing certain construction or maintenance costs. An Although the rate of inflation has eased in recent years, extended outage of one of our nuclear units coupled with we are still affected by even modest inflation which causes unfavorable rate treatment could have a material ad- increases in the unit cost of labor, materials and services. (Cleveland Electric) F-28 (Cleveland Electric)
Capital Resources and Liquidity As discussed in Note ll(d), certain unsecured debt l agreements contam covenants relatmg to capitalization, i 1991-1993 Cash Requiremente fixed charge coverage ratios and secured financings. The We need cash for normal corporate operations, the w e srx ed at Deensu M, y caused mg mandatory retirement of securities and an ongoing pro- Company, Toledo Edison and Centenor Energy to vio-
'"*"""* a ated Mton gram of constructing new facilities and modifying existing " " 7 " ".
- facilities. The construction program is needed to meet
* * " * * . "' "S* "*"
j anticipated demand for electric service, comply with ynts m pm& hm w?e"' a'"s*e* cod mongage sl governmental regulations and protect the environment, interest on property of the Company and Toledo Edison Over the three-year period of 1991-1993, these construc- and other coin"4 rations. W e expect to complete this tion and mandatory retirement needs totaled approxi- pr cess in the second quarter of 1994. % e will provide the
- mately $970 million. In addition, we exercised various s me wcurh intuest to adam du neGon because options to redeem and purchase approximately $430 mil- ir agreemenu rquire equal heatmm M gut to h.on of our securities.
provide second mortgage collateral for $47 million of ' unsecured debt, $228 million of bank letters of credit and We raised $1.2 billion through security issues and term a $205 million revolving credit facility. The bank letters bank loans during the 1991-1993 period as shown in the of credit and revolving credit facility are joint and Cash Flows statement. During the three-year period, several obligations of the Company and Toledo Edison. l the Company also utilized its short-term borrowing ar- For the next five years, the Company does not expect to l rangements to help meet its cash needs. raise funds through the sale of debt junior to first APSough the write-ofTs of Perry Unit 2 and the phase-in * "E E * #' " " ** 'I ' " ' *
- deferrals in 1993 negatively afTected our earnings, they believe that the Company could raise funds through the did not adversely alTect our current cash flow, sale of unsecured debt or debt secured by the second mortgage referred to above. The Company also is able to raise funds through the sale of preference and preferred 1994 and Beyond Cash Requirements stock, i Estimated cash requirements for 1994-1998 for the Com-pany are $791 milhon for its construction program and The Company currently cannot sell commercial paper
$715 milhon for the mandatory redemption of debt and because of its low commercial paper ratings by Standard a
preferred stock. The Company expects to finance mter- Poor's Corporation (S&P) and Moody's Investors nally all of its 1994 cash requirements of approximately Service, Inc. (Moody's) of "I " and "Not Prime", re-j $239 milhon. About 20% of the Company s 1995-1998 spectively. The Company is a party to a $205 million requirements are expected to be financed externally. If rev Iving credit facility which will run through m.d-1996. i economical, additional securities may be redeemed U ***' ** currently cannot draw on this facility be-under optional redemption provisions. cause the wn.te-offs taken at year-end 1993 caused the Company, Toledo Edison and Centenor Energy to fail to Our capital requirements are dependent upon our imple- meet certain capitalization and fixed charge coverage mentation strategy to achieve compliance with the Clean covenants. We expect to have this facility available to us Air Act Amendments of 1990 (Clean Air Act). Cash again after it is amended in the second quarter of 1994 to expenditures for our plan are estimated to be approxi- provide the participating creditors with a second mort-mately $87 million over the 1994-1998 period. See Note gage security interest. 4(a). These financing resources are expected to be suflicient for
" I the Company's needs over the next several years. The availability and cost of capital to meet the Company's Additional first mortgage bonds may be issued by the external financing needs, however, also depend upon such Company under its mortgage on the basis of property factors as financial market conditions and its credit I , additions, cash or refundable first mortgage bonds. Under ratings. Current credit ratings for the Company are as l its mortgage, the Company may issue first mortgage follows:
bonds on the basis of property additions and, under
; certain circumstances, refundable bonds only if the appli- gp yq cable interest coverage test is met. At December 31, First mongage bonds BB Ba2 1993, the Company would have been permitted to issue approximately $78 million of additional first mortgage **d" 8+ "'3 bonds. After the fourth quarter of 1994, the Company's Preferred stock B bl ability to issue first mortgage bonds is expected to increase substantially when its interest coverage ratio will These ratings reflect a downgrade in December 1993. In no longer be affected by the write-ofTs recorded at De- addition, S&P has issued a negative outlook for the cember 31,1993. Company.
(Cleveland Electric) F-29 (Cleveland Electric) l
lNCOME STATEMENT na ciavaians sicciric rituminatine company ans sussisiarias
.J_or the years ended D_gcember 31. ,
l 1993 1992 1991 (millions of dollars) Operating Revenues $1.751 $L741 SLE2h , Operating Expenses l Fuel and purchased power (1) 423 434 455 l Other operation and maintenance 489 465 470 Early retirement program expenses and other 165 - - Total operation and maintenance 1,077 899 925 Depreciation and amortization 182 179 171 Taxes, other than federal income taxes 221 226 216 Deferred operating expenses, net 27 (35) (7) Federal income taxes __22 89 106 1,529 1,M8 1.411 Operating income 222 385 415 Nonoperating income (Loss) Allowance for equity funds used during construction 4 I 8 Other income and deductions, net (5) 8 6 Write-off of Perry Unit 2 (351) - - Deferred carrying charges, net (487) 59 88 Federal income taxes - credit (expense) 270 (5) _ l24) (569) 63 78 Income (Loss) Before Interest Charges (347) 448 493 Interest Charges Debt interest 244 243 251 Allowance for borrowed funds used during construction (4) - (4) 240 243 247 Net income (Loss) (587) 205 246 Preferred Dividend Requirements 45 41 36 Earnings (Loss) Availablefor Common Stock $_lD2) $ lh4 $ 21D (1) includes purchased power expense of $120 million, $130 million and $128 million in 1993,1992 and 1991, respectively, for all purchases from Toledo Edison. RETAINED EARNINGS For the years ended December 31. 1993 1992 1991 (millions of dollars) Retained Earnings at Beginning of Year $ 545 $ 578 $ 564 Additions Net income (loss) (587) 205 246 Deductions Dividends declared: Common stock (189) (195) (194) Preferred stock (48) (41) (36) Other, primarily preferred stock redemption expenses (1) (2) (2) (825) (33) 14 Net Increase (Decrease) Retained Earnings (Deficit) at End of Year $128Q) S 545 $_17_8 The accompanying notes are an integral part of these statements. (Cleveland Electric) F-30 (Cleveland Electric)
CASH FLOWS nc cw:an.1 neanc wummaane c omen, aa sumann l For the years ended December 31. 1993 1992 1991 (millions of dollars) Cash Flowsfrom Operating Activities (1) Net income (Loss) $(587) $ 205 $ 246 Adjustments to Reconcile Net income (Loss) to Cash from Operating Activities: l Depreciation and amortization 182 179 171 l Deferred federal income taxes (292) 66 51
- Investment tax credits, net -
(8) 13 . l Deferred and unbilled revenues (6) (7) (25) I l Deferred fuel 4 6 13 1 Deferred carrying charges, net 487 (59) (88) Leased nuclear fuel amoitization 47 70 69 Deferred operating expenses, net 27 (35) (7) Allowance for equity funds used during construction (4) (1) (8) Noncash early retirement program expenses, net 125 - - Write-off of Perry Unit 2 351 - - Changes in amounts due from customers and others, net 5 6 12 Changes in inventories 17 (2) (15) Changes in accounts payable 18 7 (24) Changes in working capital affecting operations 29 (4) 37 Other noncash items 5 (11) (13) Total Adjustments 995 207 186 Net Cash from Operating Activities 408 412 432 Cash Flowsfrom Financing Activities (2) Bank loans, commercial paper and other short-term debt (10) 10 (87) l Notes payable to afliliates (11) (13) 7 Debt issues: First mortgage bonds 280 324 - Secured medium-term netes 35 90 150 Term bank loan 40 - - Preferred stock issues 100 74 125 Maturities, redemptions and sinking funds (345) (481) (133) Nuclear fuel lease obligations (59) (65) (64) Dividends paid (232) (235) (230) Premiums, discounts and expenses (11) (7) (5) Net Cash from Financing Activities (213) (303) (237) Cash Flowsfrom investing Activities (2) Cash applied to construction (167) (152) (138) Interest capitalized as allowance for borrowed funds used during construction (4) - (4) Loans to alliliates - - 11
- Other cash received (applied) 19 (20) 2 Net Cash from investing Activities (152) (172) (129)
Net Change in Cash and Temporary Cash investments 43 (63) 66 Cash and Temporary Cash investments at Beginning of l' ear 34 97 31 Cash and Temporary Cash investments at End of l' ear $ 77 $ 34 $ 97 l (1) Interest paid (net of amounts capitalized) was $204 million, $205 million and $221 million in 1993,1992 and 1991, respectively. Income taxes paid were $28 million in both 1993 and 1992 and $50 million in 1991. (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. (Cleveland Electric) F-31 (Cleveland Electric)
B ALANCE SHEET December 31. 1993 1992 (milhons of dollars) ASSETS Property, Plant and Equipment Utility plant in service $6,734 $6,602 Less: accumulated depreciation and amortization 1.889 _1728 4,845 4,874 Construction work in progress l'erry Unit 2 141 130 371 (1 4,986 5,375 Nuclear fuel, net of amortization 202 224 Other property, less accumulated depreciation 41 37 _.L229 5.636 Current Assets Cash and temporary cash investments 77 34 Amounts due from customers and others, net 156 161 Amounts due from afliliates 5 10 Unbilled revenues 99 93 Materials and supplies, at average cost 93 90 Fossil fuel inventory, at average cost 20 40 Taxes applicable to succeeding years 179 176 Other 3 3 632 607 Deferred Charges and Other Assets Amounts due from customers for future federal income taxes 586 583 Unamortized loss on reacquired debt 60 64 Canying charges and operating expenses 519 1,033 Nuclear plant decommissioning trusts 30 23 Other _ 103 177 1.298 1.880 Total Assets $7.159 18m L23 The accompanying notes are an integral part of this statement. i l (Cleveland Electric) F-32 (Cleveland Electric)
The Cleveland Electric illuminating Company and Subsidiaries l Deeg_mber 31. , 1993 1992 l (millions of dollars) CAPITALIZATION AND LIABILITIES I Capitalization Common shares, without par value: 105 million authorized; 79.6 million outstanding in 1993 and 1992 $1,241 $ 1,241 Other paid-in-capital 79 79 Retained earnings (deficit) (280) 545 Common stock equity 1,040 1,865 Preferred stock With mandatory redemption provisions 285 314 l Without mandatory redemption provisions 241 144 Long-term debt 2,793 2.515 4,359 4.838 ) Other Noncurrent Liabilities Nuclear fuel lease obligations 151 177 Other 96 57 247 __23_4 Current Liabilities Current portion of long-term debt and preferred stock 70 310 Current portion of nuclear fuel lease obligations 63 67
- Notes payable to banks and others -
10 - Accounts payable 122 104 Accounts and notes paynble to affiliates 61 50 Accrued taxes 305 291 Accrued interest 60 55 Other 52 37 733 924 Deferred Credits Unamortized investment tax credits 235 250 Accumulated deferred federal income taxes 1,105 1,392 Unamortized gain from Bruce Mansfield Plant sale 343 359 Accumulated deferred rents for Bruce Mansfield Plant 77 70 Other 60 56 1.820 . 2.127 Total Capitalization and Liabilities iL15_9 18.123 l t (Cleveland Electric) F-33 (Cleveland Electric) l
STATEMENT OF PREFERRED STOCK na cravarans zicci,1c rituminarinacompan, ans sus.;isia,1c, Current 1993 Shares Call Price Dutmber 31. QuLst;inding Per Share 1993 .]S_91 (millions of dollars) Without par value,4,000,000 preferred shares authorized Subject to mandatory redemption: j
$ 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 9.125 Series N 600,000 103.04 59 74 1 91.50 Series Q 75,000 -
75 75 88.00 Series R 50,000 - 50 50 90.00 Series S 75,000 - 74 74 314 343 ! Less: Current maturities 29 ._29 Total Preferred Stock, with Mandatory Redemption Provisions $185 $3.14 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 - 9 Total Preferred Stock, without Mandatory Redemption Provisions $14L _ $_14_4 The accompanying notes are an integral part of this statement. l l I l l (Cleveland Electric) F-34 (Cleveland Electric)
I l NOTES TO THE A fuel factor is added to the base rates for electric service. ms faa r is designed to recova fmni customus the l FINANCI AL STATEMENTS costs of fuel and most purchased power. It is reviewed and adjusted semiannually in a PUCO proceeding. (1) Sunin1ary Of Significant Accounting Policies (d) Fuel Expense i i The cost of fossil fuel is charged to fuel expense based on ggg l inventory usage. The cost of nuclear fuel, including an The Company is an electric utility and a wholly owned interest component, is charged to fuel expense based on subsidiary of Centerior Energy. Centerior Energy has two the rate of consumption. Estimated future nuclear fuel l l other wholly owned subsidiaries Toledo Edison and the disposal costs are being recovered through the base rates. l i Service Company. The Company follows the Uniform I The Company defers the difTerences between actual fuel System of Accounts prescribed by the Federal Energy e sts and estimated fuel costs currently being recovered Regulatory Commission (FERC) and adopted by The fr m customers through the fuel factor. This matches Public Utilities Commission of Ohio (PUCO). As a rate-regulated utility, the Company is subject to Statement of "" **E#"*#8 * '" # **""* j , Financial Accounting Standards (SFAS) 71 which gov- Owners of nuclear generating plants are assessed by the ! erns accounting for the elTects of certain types of rate federal government for the cost of decontamination and l regulation. The financial statements include the accounts decommissioning of nuclear enrichment facilities oper-i of the Company's wholly owned subsidiaries, which in ated by the United States Department of Energy. The the aggregate are not material. assessments are based upon the amount of enrichment l I services used in prior years and cannot be imposed for l The Company is a member of the Central Area Power more than 15 years. The Company has accrued a liability Coordination Group (CAPCO). Other members are To- for its share of the total assessments. These costs have ledo Edison, Duquesne Light Company, Ohio Edison been recorded in a deferred charge account since the Company and its wholly owned subsidiary, Pennsylvania i PUCO is allowing the Company to recover the assess- ! Power Company. The members have constructed and ments through its fuel cost factors. operate generation and transmission facilities for their use. (c) Deferred Carrying Charges and Operating Expenses (b) Related Party Transactions The PUCO authorized the Company to defer operating Operating revenues, operating expenses and interest expenses and carrying charges for Perry Unit I and charges include those amounts for transactions with aHili. Beaver Valley Power Station Unit 2 (Beaver Valley Unit ated companies in the ordinary course of business 2) from their respective in senice dates in 1987 through operations. December 1988. The annual amortization and recovery of these deferrals, called pre-phase-in deferrals, are $10 The Company's transactions with Toledo Edison are pri- million which began in January 1989 and will continue marily for firm power, interchange power, transmission over the lives of the related property, line rentals and jointly owned power plant operations and construction. See Notes 2 and 3. Beginning in January 1989, the Company deferred certain operating expenses and both interest and equity carrying The Service Company provides management, financial, charges pursuant to a PUCO-approved rate phase-in administrative, engineering, legal and other senices at plan for its investments in Perry Unit I and Beaver Valley cost to the Company and other aniliated companies. The Unit 2. These deferrals, called phase-in deferrals, were Service Company billed the Company $180 million, $150 written oft at December 31,1993. See Note 7. million and $138 million in 1993,1992 and 1991, respec-The Company also defers certain costs not currently [ tively, for such services. recovered in rates under a Rate Stabilization Program approved by the PUCO in October 1992. See Notes 7 and (c) Regenues j4 Customers are billed on a monthly cycle basis for their (f) Depreciation and Amortization energy consumption based on rate schedules or contracts authorized by the PUCO. An accrualis made at the end The cost of property, plant and equipment is depreciated of each month to record the estimated amount of over their estimated useful lives on a straight-line basis. unbilled revenues for kilowatt-hours sold in the current The annual straight-line depreciation provision for non-month but not billed by the end of that month. nuclear property expressed as a percent of average depre-(Cleveland Electric) F-35 (Cleveland Electric)
ciable utility plant in service was 3.4% in 1993,1992 Maintenance and repairs are charged to expense as in-and 1991. EITective January 1,1991, the Company, after curred. The cost of replacing plant and equipment is obtaining PUCO approval, changed its method of ac- charged to the utility plant accounts. The cost of property counting for nuclear plant depreciation from the units-of- retired plus removal costs, after deducting any salvage production method to the straight-line method at about a value, is charged to the accumulated provision for 3% rate. This change decreased 1991 depreciation ex- depreciation. pense $22 million and increased 1991 net income $17 (h) Deferred Gain from million (net of $5 m.lh.on i of income taxes) from what they otherwise would have been. The PUCO subse-Sale of Utility Plant quently approved in 1991 a change to lower the 3% rate to The sale and leaseback transaction discussed in Note 2 2.5% retroactive to January 1,1991. resulted in a net gain for the sale of the Bruce Mansfield Generating Plant (Mansfield Plant). The net gain was c Pursuant to a PUCO order, the Company currently uses deferred and is being amortized over the term of leases, external funding for the future decommissiomng of its The amortization and the lease expense amounts are nuclear units at the end of their heensed operating lives, I recorded as other operation and maintenance expenses. The estimated costs are based on the NRC's DECON method of decommissioning (prompt decontamination). (i) Interest Charges Cash contributions are made to the trust funds on a Debt Interest reported in the Income Statement does not straight-line basis over the remaining licensing period for include interest on obligations for nuclear fuel under each unit. The current level of annual expense being construction. That interest is capitalized. See Note 6. recovered from customers based on prior estimates is approximately $4 million. However, actual decommis- L sses and gains realized upon the reacquisition or re-sioning costs are expected to significantly exceed those demption of long-term debt are deferred, consistent with estimates. Current site-specific estimates for the Com- the regulatory rate treatment. Such losses and gains are pany's share of the future decommissioning costs are $51 cither amortized over the remainder of the originallife million in 1992 dollars for Beaver Valley Unit 2 and $136 f the debt issue retired or amortized over the life of the million and $154 million in 1993 dollars for Perry Unit i new debt issue when the proceeds of a new issue are and the Davis-Besse Nuclear Power Station (Davis- used for the debt redemption. The amortizations are Besse), respectively. The estimates for Perry Unit I and included in debt interest expense. Davis-Besse are preliminary and are expected to be (j) Federal Income Taxes finalized by the end of the second quarter of 1994. The . . . Company used these estimates to increase its decomm.is- The Financial Accountm.g Standards Board (FASB) is-sioning expense accruals .m 1993. It is expected that the sued SFAS 109, a new standard for account.ing for inc me taxes, in February 1992. We adopted the new increases associated with the revised cost estimates will standard in 1992. The standard amended certain provi-be recoverable in future rates. In the Balance Sheet at si ns SFAS 96 which we had previously adopted.- December 31,1993, Accumulated Depreciation and Amortizat.ion meluded $41 m.llion i of decommissioning Adoption of SFAS 109 m 1992 did not materially affect costs previously expensed and the earnings on the external m resu p r d ns, ut & a&ct attain Balana funding. This amount exceeds the Balance Sheet amount **"""""' # of the external Nuclear Plant Decommissioning Trusts The fmancial statements reflect the liability method of because the reserve began prior to the external trust accounting for income taxes. This method requires that funding. deferred taxes be recorded for all temporary differences between the book and tax bases of assets and liabilities. (g) Property, Plant and Equipment The majority of these temporary differences are attributa-Property, plant and equipment are stated at original cost ble to property-related basis differences. Included in less amounts ordered by the PUCO to be written oft. these basis difTerences is the equity component of Construction costs include related payroll taxes, pen- AFUDC, which will increase future tax expense when it sions, fringe benefits, management and general overheads j is recovered through rates. Since this component is not and allowance for funds used during construction recognized for tax purposes, we must record a liability for (AFUDC). AFUDC represents the estimated composite our tax obligation. The PUCO permits recovery of such debt and equity cost of funds used to finance construction. taxes from customers when they become payable. There-This noncash allowance is credited to income. The fore, the net amount due from customers through rates AFUDC rate was 9.63% in 1993,10.56% in 1992 and has been recorded as a deferred charge and will be 10.-17% in 1991, recovered over the lives of the related assets. (Cleveland Electric) F-36 (Cleveland Electric)
. = - _ . - . _ .
Investment tax credits are deferred and amortized over Edison is unable to make its payments under the Beaver the lives of the applicable property as a reduction of Valley Unit 2 and Mansfield Plant leases, the Company depreciation expense. See Note 7 for a discussion of the would be obligated to make such payments. No payments amortization of certain unrestricted excess deferred taxes have been made on behalf of Toledo Edison to date. and unrestricted investment tax credits under the Rate FutureIminimum lease payments under the operating Stabilization Program. leases at December 31,1993 are summarized as follows: (2) Utility Plant Sale and ror the ror Toledo Leaseback Transactions year comnany edison tmilhons of dollars) The Company and Toledo Edison are co-lessees of 1994 s 63 $ 103 18.26% (150 megawatts) of Beaver Valley Unit 2 and 1995 0 102 6.5% (51 megawatts), 45.9% (358 megawatts) and 1996 63 125 44.38 % (355 megawatts) of Units 1, 2 and 3 of the 1997 e 102 Mansfield Plant, respectively, all for terms of about 29% 1998 63 102 years. These leases are the result of sale and leaseback 1.mer Years L391 2.021 transactions completed in 1987. Total future Minimum 1. case Under these leases, the Company and Toledo Edison are Payments 51,706 $2.555 responsible for paying all taxes, insurance premiums, operation and maintenance expenses and all other similar Rental expense is accrued on a straight-line basis over the costs for their interests in the units sold and leased back. terms of the leases. The amount recorded in 1993,1992 They may incur additional costs in connection with capi- and 1991 as annual rental expense for the Mansfield tal improvements to the units. The Company and Toledo Plant leases was $70 million. Amounts charged to ex-Edison have options to buy the interests back at the end pense in excess of the lease payments are classified as of the leases for the fair market value at that time or to Accumulated Deferred Rents in the Balance Sheet. renew the leases. Additionallease provisions provide other The Company is buying 150 megawatts of Toledo purchase options along with conditions for mandatory Edison's Beaver Valley Unit 2 leased capacity entitle-termination of the leases (and possible repurchase of the ment. We anticipate that this purchase will continue leasehold interests) for events of default. These events ndefinitely. Purchased power expense for this transaction include noncompliance with several financial covenants was $103 million, $108 million and $107 million in 1993, discussed in Note 11(d). 1992 and 1991, respectively. The future minimum lease As co-lessee with Toledo Edison, the Company is also payments through the year 2017 associated with Beaver obligated for Toledo Edison's lease payments. If Toledo Valley Unit 2 aggregate $1.47 billion. (3) Property Owned with Other Utilities and Investors The Company owns, as a tenant in common with other utilities and those investors who are owner-participants in various sale and leaseback transactions (Lessors), certain generating units as listed below. Each owner owns an undivided share in the entire unit. Each owner has the right to a percentage of the generating capability of each unit equal to its ownership share. Each utility owner is obligated to pay for only its respective share of the construction 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 Company's share of the operating expenses of these generating units is included in the income Statement. The Balance Sheet classification of Property, Plant and Equipment at December 31,1993 includes the following facilities owned by the Operating Company as a tenant in common with other utilities and Lessors: i In- Plant Construction l Service Ownership Ownership Power in Work in Accumulated l Generatine Unit Date Share Megawatts Source Serviqq Proeress Deoreciation l (millions of dollars) Seneca Pumped Storage 1970 80.00% 351 flydro s 67 s- s 22 Eastlake Unit 5 1972 68.80 411 Coal I$6 2 - Davis-Besse 1977 51.38 454 Nuclear 700 5 179 Perry Unit i 1987 31.11 371 Nuclear 1.781 8 287 Beaver Valley Unit 2 and Common racilities (Note 2) 1987 24.47 201 Nuclear _1221 J 219 j Total $19M J
$ g Depreciation for Eastlake Unit 5 has been accumulated with all other nonnuclear depreciable property rather than by specific units of depreciable property.
(Cleveland Electric) F-37 (Cleveland Electric)
(c) "aZ8tdouS W8Ste Disposal Sites (4) Construction and Contingencies The Company is aware ofits potential involvement in the cleanup of three sites listed on the Superfund List and (a) Construction Program several other waste sites not on such list. The Company has accrued a liability totaling $13 million at December The est.imated cost of the Company's construction pro-
. 31,1993 based on estimates of the costs of cleanup and its gram for the 1994-1998 period is $829 milh.on, includ.ing .
E*E "" "*
- AFUDC of $38 million and excluding nuclear fuel.
that theimate ult."outcome 'Y I ' '"' # ***' D
'**E of these matters will not have The Clean Air Act will require, among other things, a material adverse effect on our financial condition or ,
significant reductions in the emission of sulfur dioxide in results of operations. See Management's Financial Analy- - two phases over a ten-year period and nitrogen oxides by sis - Outlook-Ilazardous Waste Disposal Sites. fossil-fueled generating units. (5) Nuclear Operations and Our compliance strategy provides for compliance with Contingencies t both phases through at least 2005 primarily through (a) Operating Nuclear Units greater use of low-sulfur coal at some of our units and the banking of emission allowances. The plan will require The Company's three nuclear units may be impacted by activities or events beyond our control. An extended capital expenditures over the 1994-2003 period of ap-proximately $165 million for nitrogen oxide control utage of one of our nuclear units for any reason, coupled with any unfavorable rate treatment, could equipment, emission monitoring equipment and plant modifications. In addition, higher fuel and other operation have a material adverse efTect on our financial condition and maintenance expenses will be incurred. The antici- and results of operations. See discussion of these risks in pated rate increase associated with the capital expendi- ManagemenO Financial Analysis-Outlook-Nuclear tures and higher expenses would be about 12% in the Operations, late 1990s. The Company may need to install sulfur (b) Nuclear Insurance emission control technology at one ofits generating plants The Price-At:derson Act limits the liability of the owners after 2005 which could require additional expenditures at f a nuclear power plant to the amount provided by that time. The PUCO has approved this plan. We also Private insurance and an industry assessment plan, in the are seeking United States Environmental Protection event of a nuclear incident at any unit in the United Agency (U.S. EPA) approval of the first phase of our States resulting in losses in excess of the level of private plan. insurance (currently $200 million), the Company's maxi-We are continuing to monitor developments in new tech- mum potential assessment under that plan would be $85 nologies that may be incorporated into our compliance million (plus any inflation adjustment) per incident. The strategy. If a difTerent plan is required by the U.S. EPA, assessment is limited to $11 million per year for each significantly higher capital expenditures could be re- nuclear incident. These assessment limits assume the quired during the 1994-2003 period. We believe Ohio other CAPCO companies contribute their proportionate law permits the recovery of compliance costs from cus- share of any assessment. tomers in rates. The CAPCO companies have insurance coverage for damage to property at the Davis-Besse, Perry and Beaver (b) Perry Unit 2 Valley sites (including leased fuel and clean-up costs). Coverage amounted to $2.75 billion for each site as of Perry Unit 2, including its share of the facilities common January 1,1994. Damage to property could exceed the with Perry Unit 1, was approximately 50% complete insurance coverage by a substantial amount. If it does, when construction was suspended m 1985 pending con-the Company's share of such excess amount could have sideration of various options. These options included a material adverse efTect on its financial condition and resumption of full construction with a revised estimated results of operations. Under these policies, the Company cost, conversion to a nonnuclear design, sale of all or part can be assessed a maximum of $14 million during a policy of our ownership share, or cancellation. year if the reserves available to the insurer are inadequate We wrote otT our investment in Perry Unit 2 at Decem- to pay claims arising out of an accident at any nuclear ber 31,1993 after we determined that it would not be facility covered by the insurer. completed or sold. The write-off totaled $351 million The Ccmpany also has extra expense insurance coverage. 1 ($258 million after taxes) for the Company's 44.85% It includes the increraental cost of any replacement ownership share of the unit. See Note 14. power purchased (over the costs which would have been 1 l (Cleveland Electric) F-38 (Cleveland Electric)
incurred had the units been operating) and other inci- application of the regulatory accounting measures we l dental expenses after the occurrence of certain types of follow pursuant to PUCO orders. We concluded that 1 accidents at our nuclear units. The amounts of the cover- projected revenues would not provide for the recovery of I age are 100% of the estimated extra expense per week the phase-in deferrals as scheduled because of economic i during the 52-week period starting 21 weeks after an and competitive pressures. Accordingly, we wrote olithe l accident and 67% of such estimate per week. for the next cumulative balance of the phase-in deferrals. The total 104 weeks. The amount and duration of extra expense phase-in deferred operating expenses and carrying could substantially exceed the insurance coverage. charges written off at December 31,1993 by the Com-l pany were $117 million and $519 million, respectively (6) Nuclear Fuel (totaling $433 million arter taxes). See Note 14. While recovery of our other regulatory deferrals remains proba-Nuclear fuel is financed for the Company and Toledo ble, our current assessment of business conditions has , Edison through leases with a special-purpose corporation. ! pr mpted us to change our future plans. We decided that, The total amount of financing currently available under nce the deferral of expenses and acceleration of benefits I these lease arrangements is $382 million ($232 million under our Rate Stabilization Program are completed in from intermediate-term notes and $150 million from 1995, we should no longer plan to use regulatory ac-bank credit arrangements). Financing in an amount up to e untirg measures to the extent we have m the past. l $750 million is permitted. The intermediate-term notes n ature in the period 1994-1997, with $7.5 million matur- In October 1992, the PUCO approved a Rate Stabiliza-ing in September 1994. At December 31,1993,$216 tion Program that was designed to encourage economic million of nuclear fuel was financed for the Company. growth in the Company's service area by freezing the The Company and Toledo Edison severally lease their Company's base rates until 1996 and limiting subsequent l respective portions of the nuclear fuel and are obligated to rate increases to specified annual amounts not to exceed pay for the fuel as it is consumed in a reactor. The lease $216 million over the 1996-1998 period. rates are based on various intermediate-term note rates, As part of the Rate Stabilization Prsgram, the Company bank rates and commercial paper rates. is allowed to defer and subsequently recover certain costs The amounts financed include nuclear fuel in the Davis- net currently recovered in rates and to accelerate amor-Besse, Perry Unit I and Beaver Valley Unit 2 reactors tization of certain benefits. Such regulatory accounting with remaining lease payments for the Company of $57 measures provide for rate stabilization by rescheduling million, $48 million and $26 million, respectively, at the timing of rate recovery of certain costs and the December 31,1993. The nuclear fuel amounts financed amortization of certain benefits during the 1992-1995 and capitalized also included interest charges incurred period. The continued use of these regulatory accounting by the lessors amounting to $9 million in both 1993 and measures will be dependent upon our continuing assess-1992 and $12 million in 1991. The estimated future lease ment and conclusion that there will be probable recovery amortization payments based on projected consumption of such deferrals in future rates. are $63 million in 1994,$56 million in 1995,$50 million The regulatory accounting measures we are eligible to in 1996, $44 million in 1997 and $39 million in 1998. record through December 31,1995 include the deferral of post-in-service interest carrying charges, depreciation ex-(7) Regulatory Matters pense and property taxes on assets placed in service after Phase-in deferrals were recorded beginning in 1989 pur- February 29,1988. The cost deferrals recorded in 1993 suant to the phase-ii. plan approved by the PUCO in a and 1992 pursuant to these provisions were $56 million January 1989 rate order for the Company. The phase-in and $52 million, respectively. Amortization and recovery plan was designed so that the projected revenues resulting of these deferrals will occur over the average life of the frorr. the authorized rate increases and anticipated sales related assets, approximately 30 years, and will com-g owth provided for the phase-in of certain nuclear costs mence with future rate recognition. The regulatory ac-over a ten-year period. The plan required the deferral of a counting measures also provide for the accelerated pcrtion of the operating expenses and both interest and amortization of certain unrestricted excess deferred tax equity carrying charges on the Company's deferred rate- and unrestricted investment tax credit balances and in-based investments in Perry Unit I and Beaver Valley terim spent fuel storage accrual balances for Davis-Besse. Unit 2 during the early years of the plan. The amortiza- The total amount of such regulatory benefits recognized tion and recovery of such deferrals were scheduled to be in 1993 and 1992 pursuant to these provisions was $28 completed by 1998. million and $7 million, respectively. As we developed our strategic plan, we evaluated the The Rate Stabilization Program also authorized the Com-future recovery of our deferred charges and continued pany to defer and subsequently recover the incremental (Cleveland Electric) F-39 (Cleveland Electric)
expenses associated with the adoption of the accounting The Company joins in the filing of a consolidated federal standard for postretirement benefits other than pensions income tax return with its affiliated companies. The (SFAS 106). In 1993, we deferred $60 million pursuant method of tax allocation reflects the benefits and burdens to this provision. Amortization and recovety of this realized by each company's participation in the consoli-deferral will commence prior to 1998 and is expected to dated tax return, approximating a separate return result be completed by no later than 2012. See Note 9(b). for each company. In August 1993, the 1993 Tax Act was enacted. Retroac-(8) Federal Income Tax tive to 3anuary 1,1993, the top marginal corporate Federal income tax, computed by multiplying income income tax rate increased to 35%. The change in tax rate before taxes by the statutory rate (35% in 1993 and 34% increased Accumulated Deferred FederalIncome Taxes in both 1992 and 1991), is reconciled to the amount of for the future tax obligation by approximately $61 million. ( federal income tax recorded on the books as follows: Since the PUCO has historically permitted recovery of 1993 g g such taxes from customers when they become payable, (millions of dollars) the deferred charge, Amounts Due from Customers for i Bmk Income (Loss) Before Federal Income Future Federal income Taxes, also was increased by Tax 13.]}) $299 $1.7.6
$61 m.lh.i on. The 1993 Tax Act is not expected to T cdat) n Book Income (Loss) at g g g increase tDecrease) in Tax: Under SFAS 109, temporary differences and carryfor-wards resulted in deferred tax assets of $426 million and pha e n e errals Depreciation 6 deferred tax liabilities of $1.531 billion at December 31, (3) (2)
Rate Stabilization Program (20) (5) - 1993 and deferred tax assets of $415 million and de-Other items 8 - 4 ferred tax liabilities of $1.807 billion at December 31, Total Federal income Tax Expense (Credit) _ 1G48) 1 94 11 10 1992. These are summarized as follows: December 31. Federal income tax expense is recorded in the Income 1993 1992 Statement as follows: (minions of 1993 1992 1991 dollars) I Property, plant and equipment $1,311 $1.468 (millions of dollars) Operating Expenses: Deferred carrying charges and operating expenses __ 127 249 Current Tax Provision $ 64 $ 47 $ 75 Sale and leaseback transactions (126) (123) Changes in Accumulated Deferred Federal Net operating loss carryforwards (69) (79) Income Tax: Investment tax credits (128) (132) Write-off of deferred operating expenses. (26) - - Other (10) 9 Accelerated depreciation and Net deferred tax liability $1J05 1LJ91 amortization 60 32 9 Alternative minimum tax credit (19) (18) (3) For tax purposes, net operating loss (NOL) carryforwards Re ren ent and postemployment g ; Sale and leaseback traruactions and future taxable income and will expire in 2003 through amortization 4 4 (9) 2005. The 35% tax effect of the NOLs is $69 million. Taxes, other than federal income taxes __ (18) 14 - Rate Stabilization Program (8) 2 -- The Tax Reform Act of 1986 provides for an alternative Reacquired debt costs (2) 6 16 minimum tax (AMT) credit to be used to reduce the Deferred fuel costs (2) (2) (5) regular tax to the AMT level should the regular tax Other items (7) 4 12 exceed the AMT. AMT credits of $94 million are availa- 1 Investment Tax Credits -
- _jl !
Total Charged to Operating Expenses _ __22 #7 l _196 carried forward indefinitely. Nonoperating income: Current Tax Provision (20) (19) (8) t Changes in Accumulated Deferred Federal (9) Retirement and k"'n$*orr oIdcrerred carr>4ng (iv7) charges __ _ _ Postemployment Benefits I Write-off of Perry Unit 2 (93) - - (a) Retirement Income Plan l D;sallowed nuclear costs 6 7 - Rate Stabilization Program 7 6 - e er M, %, M Gmpay and Ses AFUDC and carrying charges 7 14 32 Company jointly sponsored a noncontributing pension Other items - _Q) _- plan which covered all employee groups. The plan was Total Expense (Credit) to merged with another plan which covered the employees of Nonoperating income _[_2Jg) 1 24 Toledo Edison into a single plan on December 31,1993. Total Federal Income Tax Expense (Credit), $(248) gy 12 The amount of retirement benefits generally depends (Cleveland Electric) F-40 (Cleveland Electric)
% W
l 1 incurred had the units been operating) and other inci- application of the regulatory accounting measures we l dental expenses after the occurrence of certain types of follow pursuant to PUCO orders. We concluded that accidents at our nuclear units. The amounts of the cover- projected revenues would not provide for the recovery of age are 100% of the estimated extra expense per week the phase-in deferrals as scheduled because of economic during the 52-week period starting 21 weeks after an and competitive pressures. Accordingly, we wrote off the accident and 67% of such estimate per week for tF : next cumulative balance of the phase-in deferrals. The total 104 weeks. The amount and duration of extra expense phase-in deferred operating expenses and carrying could substantially exceed the insurance coverage. charges written off at December 31,1993 by the Com-pany were $117 million and $519 million, respectively (6) Nuclear Fuel (totaling $433 million after taxes). see Note 14. While rec very f ur ther regulatory deferrals remains proba-Nuclear fuel is financed for the Company and Toledo ' ble, our current assessment of business conditions has Edison through leases with a special-purpose corporation. Prompted us to change our future plans. We decided that, The total amount of financing currently available under nce the deferral of expenses and acceleration of benefits 3 these lease arrangements is $382 million ($232 millica under our Rate Stabilization Program are completed in from intermediate-term notes and $150 million from 1995, we should no longer plan to use regulatory ac-bank credit arrangements). Financing in an amount up to e unting measures to the extent we have m the past.
$750 million is permitted. The intermediate-term notes mature in the period 1994-1997, with $75 million matur- In October 1992, the PUCO approved a Rate Stabiliza-ing in September 1994. At December 31,1993,$216 tion Program that was designed to encourage economic million of nuclear fuel was financed for the Company. growth in the Company's service area by freezing the The Company and Toledo Edison severally lease their Company's base rates until 1996 and limiting subsequent respective portions of the nuclear fuel and are obligated to rate increases to specified annual amounts not to exceed pay for the fuel as it is consumed in a reactor. The lease $216 million over the 1996-1998 period.
rates are based on various intermediate-term note rates, As part of the Rate Stabilization Program, the Company bank rates and commercial paper rates. { is allowed to defer and subsequently recover certain costs The amounts financed include nuclear fuel in the Davis- not currently recovered in rates and to accelerate amor- l Besse, Perry Unit I and Beaver Valley Unit 2 reactors tization of certain benefits, Such regulatory accounting l with remaining lease payments for the Company of $57 measures provide for rate stabilization by rescheduling million, $48 million and $26 million, respectively, at the timing of rate recovery of certain costs and the December 31,1993. The nuclear fuel amounts financed amortization of certain benefits during the 1992-1995 and capitalized also included interest charges incurred period. The continued use of these regulatory accounting l by the lessors amounting to $9 million in both 1993 and measures will be dependent upon our continuing assess- l 1992 and $12 million in 1991. The estimated future lease ment and conclusion that there will be probable recovery amortization payments based on projected consumption of such deferrals in future rates. are $63 million in 1994, $56 million in 1995,$50 million The regulatory accounting measures we are eligible to in 1996, $44 million in 1997 and $39 million in 1998. record through December 31,1995 include the deferral of post-in-sersice interest carrying charges, depreciation ex-(7) Regulatory Matters pense and property taxes on assets placed in service after Phase-in deferrals were recorded beginning in 1989 pur- February 29,1988. The cost deferrals recorded in 1993 suant to the phase-in plan approved by the PUCO in a and 1992 pursuant to these provisions were $56 million January 1989 rate order for the Company. The phase-in and $52 million, respectively. Amortization and recovery plan was designed so that the projected revenues resulting of these deferrals will occur over the average life of the i from the authorized rate increases and anticipated sales related assets, approximately 30 years, and will com-growth provided for the phase-in of certain nuclear costs mence with future rate recognition. The regulatory ac-over a ten-year period. The plan required the deferral of a counting measures also provide for the accelerated portion of the operating expenses and both interest and amortization of certain unrestricted excess deferred tax equity carrying charges on the Company's deferred rate- and unrestricted investment tax credit balances and in-based investments in Perry Unit I and Beaver Valley terim spent fuel storage accrual balances for Davis-Besse. Unit 2 during the early years of the plan. The amortiza- The total amount of such regulatory benefits recognized tion and recovery of such deferrals were scheduled to be in 1993 and 1992 pursuant to these provisions was $28 completed by 1998. milhon and $7 million, respectively. As .: developed our strategic plan, we evaluated the The Rate Stabilization Program also authorized the Com-future recovery of our deferred charges and continued pany to defer and subsequently recover the incremental (Cleveland Electric) F-39 (Cleveland Electric) _ t " %{
upon the length of service. Under certain circumstances, were 7.25% and 8.75%, respectively. The long-term rate benefits can begin as early as age 55. The funding policy of anr.ual compensation increase assumption was 4.25%. At is to comply with the Employee Retirement Income December 31,1992, the settlement rate and long-term Security Act of 1974 guidelines. rate of return on plan assets assumptions were 8.5% and In 1993, the Company and Service Company offered the the long-term rate of annual compensation increase VTP, an early retirement program. Operating expenses assumption was 5%. for both companies for 1993 included $146 million of Plan assets consist primarily of investments in common pension plan accruals to cover enhanced VTP benefits stock, bonds, guaranteed investment contracts, cash and an additional $7 million of pension costs for VTP equivalent securities and real estate. benefits paid to retirees from corporate funds. The $7 million is not included in the pension data reported below. (b) Other Postretirement Benefits A credit of $66 million resulting from a settlement of Centerior Energy sponsors jointly with its subsidiaries a pension obligations through lump sum payments to al-postretirement benefit plan which provides all employee most all the VTP retirees partially offset the VTP groups certain health care, death and other postretirement expenses. benefits other than pensions. The plan is contributory, 1 Net pension and VTP costs (credits) for 1991 through with retiree contributions adjusted annually. The plan is 1993 were comprised of the following components: not funded. A policy limiting the employer's contribu-1993 1992 1991 tion for retiree medical coverage for employees retiring a a , a p n may N Pension Costs (Credits): Service cost for benefits carned during the 5 0 $ lo 5 9 The Company adopted SFAS 106, the accounting stan-Interest cost on projected benefit obligation _ 26 27 25 dard for postretirement benefits other than pensions, ef- ; Ict a ort $z$tUon d $cr al ]j fective January 1,1993. The standard requires the accrual Net pension costs (credits) (12) (17) (15) of the expected costs of such benefits during the employ-VTP cost 146 - - ees' years of service. Previously, the costs of these settlement gain E) - - benefits were expensed as paid, which is consistent with Net costs (credits) 1E in7) $111) ratemaking practices. Such costs for the Company totaled
. $5 million in 1992 and $6 million in 1991, which in-The following table presents a reconciliation of the funded cluded medical benefits of $4 million in 1992 and $5 status of the former plan of the Company and Serpce million in 1991. The total amount accrued by the Com-Company at December 31,1992 with comparable mfor-pany for SFAS 106 costs for 1993 was $69 million, of mation for a portion of the merged plan at December 31, which $4 million was capitalized and $65 million was 1993. The December 31,1993 benefit obligation esti-
. expensed as other operat.ion and ma.intenance expenses.
mates were derived from m. formation for the former plans. In 1993, the Company deferred incremental SFAS 106 Plan assets of the merged plan were allocated based on a expenses totaling $60 million pursuant to a provision of pro rata share of the projected benefit obligation. the Rate Stabilization Program. See Note 7. l 1992 1992 i tmillions of The components of the total postretirement benefit costs dollars) Actuarial present value of benefit obligations: for 1993 were as follows: Vested benefits $231 $215 Millions Nonvested hencrits J J of Dollars Accumulated benefit obligation 257 243 Service cost for benef ts earned $2 Effect of future compensation levels 37 ft6 Interest cost on accumulated postretirement benefit Total projected benefit obligation 294 329 obligation 10 Plan assets at fair market value _263 ,,f,.31 Amortization of transition obligation at January 1,1993 of Funded status (26) 256 5104 mi!Iion over 20 years 5 Unrecognized net loss (gain) from variance VTP curtailment cost (includes $10 million transition between assumptions and experience 61 (107) obligation adjustment) ,12 Unrecognized prior service cost 6 7 Total costs ig Transition asset at January 1,1987 being amortized over 19 years J) J J) These amounts included costs for the Company and a pro Net prepaid pension cost $=j j=M rata share of the Service Company's costs. At December 31,1993, the settlement (discount) rate The accumulated postretirement benefit obligation and and long-term rate of return on plan assets assumptions accrued postretirement benefit cost at December 31,1993 i e (Cleveland Electric) F-41 (Cleveland Electric)
for the Company and its share of the Service Company's of the mining companies' loan and lease obligations guar-obligation are summarized as follows: anteed by the Company was $60 million. l of Dollars . . . Accumulated postretirement benefit obligation (ll) C Pitalization j attributable to: (a) Capital Stock Transactions J Retired participants $(141) Fully eligible active plan panicipants (1) Preferred stock shares sold and retired during the three Other active plan participants (19) years ended December 31,1993 are listed in the following Accumulated postretirement benefit obligation (161) lable. Unrecognized net loss from variance between assumptions 19933 1992 1991 and experience 9 (thousands of shares) Unamortized transition obligation 89 Subject to Mandatory Redemption: 1 LLQ) Accrued postretirement benefit cost Sales
$ 91.50 Series Q - -
75 i The Balance Sheet classification of Other Noncurrent Liabilities at December 31,1993 includes only the Com-Q[R Retirements 50 pany's accrued postretirement benefit cost of $52 million c (I s g Se and excludes the Service Company's portion since the 75.00 Series F - - (2) Service Company's total accrued cost is carried on its 145.00 Series I - - (14) 113.50 Series K - - (10) books. Adjustable Series M (100) (100) (100) At December 31,1993, the settlement rate and the long-Not Sub c to h a d tory Redemption: term rate of annual compensation merease assumptions Sales were 7.25% and 4.25%, respectively. The assumed annual s 42.40 Series T 200 - - Retirements health care cost trend rates (applicable to gross eligible Remarketed Series P - (1) - charges) are 9.5% for medical and 8% for dentalin 1994. Net (Decrease) _LM) (39) _LL4) Both rates reduce gradually to a fixed rate of 4.75% in 1996 and later years. Elements of the obligation affected (b) Equity Distribution Restrictions by contribution caps are significantly less sensitive t Federal law prohibits the Company from paying dividends the health care cost trend rate than other elements. If the out of capital accounts. However, the Company may pay assumed health care cost trend rates were increased by preferred and common stock dividends out of appropri-1% in each future year, the accumulated postretirement ated retained earnings and current earnings. At Decem-benefit obligation as of December 31,1993 would in- ber 31,1993, the Company had $125 million of crease by $7 million and the aggregate of the service and appropriated retained earnings for the payment of pre-mterest cost components of the annual postretirement ferred and common stock dividends. benefit cost would increase by $0.5 million. (c) Postemployment Benefits Amounts to be paid for preferred stock which must be in 1993, the Company adopted SFAS 112, the new redeemed during the next five years are $29 million in accounting standard which requires the accrual of post- 1994,$40 million in 1995,$30 million in both 1996 and employment benefit costs. Postemployment benefits are 1997 and $15 million in 1998. the benefits provided to former or inactive employees after employment but before retirement, such as The annual preferred stock mandatory redemption provi-worker's compensation, disability benefits and severance sions are as follows: pay. The adoption of this accounting method did not "[*' Beginning Ir , materially affect the Company's 1993 results of operations Redeemed in Share
)
or financial position. 5 7.35 Series C 10.000 1984 $ 100 88.00 Series E 3,000 1981 1,000 Adjustable Series M 100.000 1991 100 (10) Gtialantees 9.i25 Series N 150,000 1993 100 I
. 91.50 Series Q 10,714 1995 1,000 The Company has guaranteed certain loan and lease 88.00 Series R 50.000 200l* t/100 obligations of two mining companies under two long-term 90.00 Series S 18,750 1999 th00 coal purchase arrangements. One of these arrangements
- All outstanding shares to be redeemed on December I,2001.
requires payments to the mining company for any actual expenses (as advance payments for coal) when the mines in June 1993, the Company issued $100 million princl pal are idle for reasons beyond the control of the mining amount of Serial Preferred Stock, $42.40 Series T. The company. At December 31,1993, the principal amount Series T stock was deposited with an agent which issued (Cleveland Electric) F-42 (Cleveland Electric)
Depositary Receipts, each representing % of a share of The Company issued $275 million aggregate principal the Series T stock. amount of secured medium-term notes during the 1991-The annualized preferred dividend requirement at De- 1993 peri d. The notes are secured by first mortgage cember 31,1993 was $47 million, bonds. The Company's mortgage constitutes a direct first lien on The preferred dividend rates on the Company's Series L substantially all property owned and franchises held by and M fluctuate based on prevailing interest rates and the Company. Excluded from the lien, among other market conditions. The dividend rates for both issues things, are cash, securities, accounts receivable, fuel and averaged 7% in 1993. The Company's Series P had a SUPphes. 6.5% dividend rate in 1993 untilit was redeemed in August 1993. An unsecured loan agreement of the Company contains
. covenants relating to capitalization ratios, fixed charge Preference acck author.ized for the Company is 3,000,000 .
coverage rat.ios and limitations on secured h.nancing other shares w.thout i pai value. No preference shares are cur-than through first mortgage bonds or certain other trans. I rently outstanding. . 1 actions. Two re.imbursement agreements relating to sep-With respect to dividend and liquidation rights, the Com- arate letters of credit issued in connection with the sale l pany's preferred stock is prior to its preference stock and and leaseback of Beaver Valley Unit 2 contain several common stock, and its preference stock is prior to its financial covenants affecting the Company, Toledo common stock. Edison and Centerior Energy. Among these are covenants relating to fixed charge coverage ratios and capitalization (d) Long-Term Debt and Other , r tios. The write-offs recorded at December 31,1993 J Horrowing Arrangements caused the Company, Toledo Edison and Centerior En- ) Long-term debt, less current maturities, was as follows: ergy to violate certain covenants contained in the loan
,, ^f',"*jg , agreement and the two reimbursement agreements. The Interest affected creditors have waived those violations in ex-Rate at December 31, December 31. change for commitments to provide them with a second Year of Matunty 1993 1 1992 mortgage security interest on property of the Company dollars) and Toledo Edison and other considerations. We expect First mortgage bonds: to complete this process in the second quarter of 1994.
1994 4.375% $ - s 25 We will provide the same security interest to certain
- 4 other creditors because their agreements require equal 1995 100 1 1 treatment. We expect to provide secoad mortgage collat-1996 13.75 4 4 eral for $47 million of unsecured debt, $228 million of 1996 7.00 1 I bank letters of credit and a $205 million revolving credit 1997 10.88 6 6 facility. The bank letters of credit and revolving credit 1997 13.75 4 4 facility are joint and several obligations of the Company I
, f and Toledo Edison.
l 1998 13.75 4 4 I 1998 7.00 1 1 1999-2003 8.06 406 306 (12) Short-Term Borrowing 20 % 2008 8.48 H5 H9 2009 2013 8.08 405 405 Arranaements D 2014-2018 8.07 513 513 2019 2023 8.23 _, 1)) ,_,jfl n May M. Centerior Energy anangd for a W 1,989 1,772 million, three-year revolving credit facility. The facility Secured medium term notes due may be renewed twice for one-year periods at the option 1995-2021 8.88 713 678 of the participating banks. Centerior Energy and the Term bank loans duc 1995-1996 _ , 4.07 45 8 l Service Company may borrow under the facility, with all Pollution control notes duc 1995-bonowings jointly and severally guaranteed by the Com-Other - net - (7) 4 pany and Toledo Edison. Centerior Energy plans to trans-Total t.ong-Term Debt $2.793 $2.515 fer any ofits borrowed funds to the Company and Toledo Edison, while the Service Company may borrow up to Long-term debt matures during the next five years as $25 million for its own use. The banks' fee is 0.5% per follows: $42 million in 1994,$246 million in 1995, $151 annum payable quarterly in addition to interest on any million in 1996,$55 million in 1997 and $78 million in borrowings. That fee is expected to increase to 0.625% 1998. when the facility agreement is amended as discussed (Cleveland Electric) F-43 (Cleveland Electric)
below. There were no borrowings under the facility at (14) Quarterly Results of Operations December 31,1993. The facility agreement contains cov-enants relating to capitalization and fixed charge cover-(Unaudited)
,The following is a tabulat. ion of the unaudited quarterly los for k Company, Toledo Edison and resu s pera ns r two years ce hmber Centerior Energy. The write-offs recorded at December 31' 1993' 1 31,1993 caused the ratios to fall below those covenant Ouarters Ended requirements. The revolving credit facility is expected to March 31, June 30. Sept. 30. Dec. 31. I be available for borrowings after the facility agreement (millions of dollars) is amended in the second quarter of 1994 to provide the perating Revenues $421 $417 $507 $ 406 participating creditors with a second mortgage security operating Income (Loss) _ 82 85 89 (32) l Net income (Loss) 33 30 39 (689) interest. l Earnings (Loss) Available !
Short-term borrowing capacity authorized by the PUCO ror common stock 23 19 27 (701) i annually is $300 million for the Company. The Ccmpany 1992 operating Revenues $422 $415 $479 $ 427 and Toledo Edison are authorized by the PUCO to Operating income 83 85 139 77 borrow from each other on a short-term bas.is. Net Income 27 33 102 43 Earnings Available for At December 31,1993, the Company had no commercial Common Stock 17 23 92 32 paper outstanding. The Company is unable to rely on the sale of commercial paper to provide short-term funds Earnings for the quarter ended September 30,1993 were because of its below investment grade commercial paper decreased by $46 million as a result of the recording of credit ratings. $71 million of VTP pension-related benefits. Earnings for the quarter ended December 31,1993 were decreased as a result of year-end adjustments for the (l3) Financial Instruments' . $351 million write-oft of Perry Unit 2 (see Note 4(b)), Fair Value the $636 million write-oft of the phase-in deferrals (see i I Note 7) and $38 million of other charges. These adjust-The estimated fair values at December 31,1993 and 1992 ments decreased quarterly earnings by $716 million. of financial instruments that do not approximate their Earnings for the quarter ended September 30,1992 were carrying arnounts are as follows: increased by $26 million as a result of the recording of December 31. deferred operating expenses and carrying charges for the i carrying Fair Carrying Fair Amount Value Amoun_t Value Rate Stabilization Program approved by the PUCO in tmillions of dollars) October 1992. See Note 7. Nuclear Plant Decommissioning Trusts $ 30 $ 32 $ 23 $ 24 Preferred Stock, with Mandatory (l5) Pending Merger of the Company Redemption Provisions (including current portion) 314 307 343 342 with Toledo Edison Long-Term Debt (including On March 25,1994, Centerior Energy announced that its current portion) 2.84 2.946 2.793 2.886 operating utility subsidiaries, the Company and Toledo The fair value of the nuclear plant decommissioning trusts
"' " ' *#IE# " *E E# "E ""
the Company and Toledo Edison afliliated m 1986, is est.imated based on the quoted market prices for the
. efforts have been made to consolidate operations and mvestment securities. The fa.ir value of the Company's admm. .istration as much as possible to achieve maximum preferred stock with mandatory redemption provisions and long-term debt is estimated based on the quoted '. st savings. The merger of the two companies into a
. . smgle entity is the completion of this consolidation pro-market prices for the respect.ive or similar issues or on the cess. a us aspects ome merger are suNect to th basis of the discounted value of future cash flows. The
. approval of the FERC, the PUCO and other regulatory discounted value used current dividend or interest rates .
. authorities. The merger must be approved by share (or other appropriate rates) for s.imilar issues and loans owners of Toledo Edison's preferred stock. Share owners with the same remaining maturities.
of the Company's preferred stock must appmve the au-The estimated fair values of all other financial instru- thorization of additional shares of preferred stock. Share ments approximate their carrying amounts in the Balance owners of Toledo Edison's preferred stock will exchange ; Sheet at December 31,1993 and 1992 because of their their shares for preferred stock shares of the successor l short-term nature. corporation having substantially the same terms, while the l (Cleveland Electric) F-44 (Cleveland Electric) l l
Company's preferred stock will automatically become income (loss) was $(876) million, $276 million and $296 thares of the successor corporation. Debt holders of the million for the years ended December 31,1993,1992 and merging companies will become debt holders of the 1991, respectively. The pro forma data is based on successor corporation. The merging companies plan to accounting for the merger on a method similar to a seek preferred stock share owner approvalin the summer pooling of interests. The pro forma data is not necessarily of 1994. The merger is expected to be effective in late indicative of the results of operations which would have 1994. been reported had the merger been in effect during those years or which may be reported in the future. The For the merging companies, the combined pro forma pro forma data should be read in conjunction with the operating revenues were $2.475 billion, $2.439 billion audited financial statements of both the Company and and $2.561 billion and the combined pro forma net Toledo Edison. l 4 1 1 9 a 1 (Cleveland Electric) F-45 (Cleveland Electric)
FIN ANCI AL AND STATISTICAL REVIEW Operating Revenues (rnillions of dollars) Total Total Total Steam Operating Year Residential Commercial Industrial Other Retail Wholesale Electric ifcaung Revenues 1993 $539 536 510 98 , 1 683 68 1 751 -
$1751 1992 517 531 530 101 1 679 64 1 743 -
1 743 1991 547 540 547 117 1 751 75 1 826 -- I 826 1990 495 494 544 123 1 656 35 1691 -- 1 691 1989 470 453 520 117 1 560 74 1 634 -- 1 634 1983 385 335 430 43 1 193 9 1 202 16 1218 Operating Expenses (millions of dollars) Other Deferred I uct & Operatinn Depreciation T axes. Operating Federal Total Purchased & & Other Than Expenses, income Operating Year Power Maintenance Amortization FIT Net Taxes Expenas 1993 $423 654(a) 182 221 27(b) 22 51 529 1992 434 465 179 226 (35) 89 1 358 1991 455 470 171(c) 216 (7) 106 1 411 1990 412 514 170 197 (24) 75 1 344 1989 427 508 188 183 (42) 85 1 349 1983 341 270 94 127 - 127 959 Income (l.oss) (millions of dollars) Federal Income Other Deferred income (Loss) Income & Carrying Taxes- Before Operating Afl1DC- Deductions, Charges, Credit Interest Year income Equiry Net Net (Expense) Charges, 1993 $222 4 (356)(d) (487)(b) 270 $(347) 1992 385 1 8 59 (5) 448 1991 415 8 6 88 (24) 493 1990 347 5 1 162 (20) 495 1989 285 8 9 235 (56) 481 1983 259 87 4 -- 23 373 Income (Loss) (millions of dollars) Earnings Preferred & (Loss) Net Preference Available for Debt Al'UDC- Income F sk Common Year Interest Dot (Loss) Di . 'ds Stock 1993 $244 (4) (587) -;5 $(632) 1992 243 -- 205 41 164 1991 251 (4) 246 36 210 1990 255 (3) 243 37 206 1989 238 (7) 250 40 210 1983 154 (27) 246 38 208 (a) Includes early retirement program expenses and other charges of $165 million in 1993. (b) Includes w rite-off of phase-in deferrals of 5636 million in 1993, consisting of $117 million of deferred operating expenses and $519 million of deferred carrying charges. (c) In 1991, a change in accounting for nuclear plant depreciation was adopted, changing from the units-of-production method to the straight-line l method at a 2.5% rate. i (Cleveland Electric) F-46 (Cleveland Electric)
l REPORT OF In our opinion, the financial statements referred to above present f ir y, in 11 m teri resp cts, the financial posi-INDEPENDENT tion of The Toledo Edison Company as of December 31,
- PUBLIC ACCOUNTANTS 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period To the Share Owners of ended December 31,1993, in conformity with generally l The Toledo A E N cepted accounting principles.
Edison Company:
&gg, As discussed further in Notes 1 and 9, changes were made We have audited the accompanying balance sheet and in the methods of accounting for nuclear plant deprecia-statement of preferred stock of The Toledo Edison Com- . .
tion m 1991 and for postretirement benefits other than I ! pany (a wholly owned subsidiary of Centerior Energy pensions in 1993. l I Corporation) as of December 31,1993 and 1992, and the Our audits were made for the purpose of forming an ! related statements ofincome, retained earnings and cash flows for each of the three years in the period ended opini n on the basic financial statements taken as a I December 31,1993. These financial statements and the whole. The schedules of The Toledo Edison Company schedules referred to below are the responsibility of the listed in the Index to Schedules are presented for pur-Company's management. Our responsibility is to express poses of complying with the Securities and Exchange an opinion on these financial statements and schedules Commission's rules and are not part of the basic financial
- based on our audits. statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic We conducted our audits in accordance with generally f nancial statements and, in our opinion, fairly state in all accepted auditing standards. Those standards require that m terial respects the financial data required to be set we plan and perform the audit to obtain reasonable f rth therein in relation to the basic financial statements assurance about whether the financial statements are free of material misstatement. An audit includes examining, taken as a whole.
on a test basis, evidence supporting the amounts and ARmUR ant)ERSEN & CO. disclosures in the financial statements. An audit also includes assessing the accounting principles used and Cleveland, Ohio sigmfico est.imates made by management, as well as February 14,1994 evaluating the overall financial statement presentation. (except with respect to the matter discussed in Note We believe that our audits provide a reasonable basis for 15, as to which the date is March 25,1994) our opinion. l l 1 l l l l i i I l l 1 (Toledo Edison) F-48 (Toledo Edison) t
The Cleveland Electric illuminating Company and Subsidiaries Electric Sales (millions of KWH) Electric Customers (year end) Residential Usage Average Average Industrial K% 11 er Per Pc Year Residential Commercial Industrial Wholessile Other Total Residential Commercial & Other Total Customer KWH Customer 1993 _ 4 934 5 634 7 911 2 290 532 21 301 669 118 70 442 8 149 747 709 7 373 10.93c $805.68 l 1992 _ 4 725 5 467 7 988 1 989 533 20 702 669 800 70 943 8 375 749 118 7 071 10.94 773.77 ' 1991 _ 4 940 5493 8 017 2 442 565 21 457 667 495 70 405 8 398 746 298 7 170 11.08 797.25 1990 __, 4 716 5 234 8 551 1 607 463 20 571 665 000 68 700 8 351 742 051 6 867 10.53 723.15 1989 _ 4 789 5208 8 780 2 132 501 21 410 660 786 68 030 8 329 737 145 7 025 9.81 691.83 l 1983._,_ 4 412 4 265 7 514 263 426 16 880 643 065 62 075 7 693 712 833 6 608 8.77 579.49 ! Load (MW & %) Energy (millions of KWH) Fuel Operable t ri e Peak Capacity Load Company Generated Purchased fuel Cost Year of Peak Load M arpn Factor Fossd Nuclear Total Power Total Per KWH KWH 1993 4 122 3 862 6.3% 59.9 % 15 557 5 644 21 201 1 454 22 655 1.37c 10 339 1992 4 703 3 605 23.3 63.0 12 715 7 521 20 236 1 649 21 885 1.47 10 456 1991 4 695 3 886 17.2 61.8 13 193 7 451 20 644 2 144 22 788 1.49 10 503 1990 4 685 3 778 19.4 63.3 15 579 5 262 20 841 964 21 805 1.52 10 417 1989 4 536 3 866 14.8 65.2 ' 14 968 6 570 21 538 1 268 22 806 1.49 10 506 1983 4 441 3 404 23.4 61.9 14 804 2 512 17 316 937 18 253 1.77 10 452 Investment (millions of dollars) Utihty NorYi Total Accumulated Progress Nuclear Property, Utility Plant in Depreciauon & Net & Perry Fueland Plant and Plant Total Year Service Amortization Plant Unit 2 Other Equipment Additions Assets 1993 $6 734 1 889 4 845 141 243 $5 229 $175 $7159 1992 6 602 1 728 4 874 501 261 5 636 156 8 123 1991 6 196 1 565 4 631 545 305 5 481 150 7 942 1990 6 032 1398 4 634 572 344 5 550 165 7 821 1989 5 869 1259 4 610 603 354 5 567 144 7 546 1983 2 838 722 2 116 1 617 228(e) 3 961 491 4 425 Capitalization (millions of dollars & %) Preferred & Preference Preferred Stock, without Stock, with Mandatory Mandatory Redemption Year Common Stock Equity Redemption Provisions Provisions Long-Term Debt Total 1993 $1040 24 % 285 7% 241 5% 2 793 64 % $4 359 1992 1 865 39 314 6 144 3 2 515 52 4 838 1991 1898 38 268 5 217 4 2 683 53 5 066 1990 1 884 38 171 3 217 4 2 632 55 4 904 1989 1828 40 212 4 217 5 2 336 51 4 593 1983 1 355 41 318 9 144 4 1 519 46 3 336 (d) Includes write-off of Perry Unit 2 of $351 million in 1993. (c) Restated for effects of capitalization of nuclear fuel lease and financing arrangements pursuant to Statement of Financial Accounting Standards 71. (Cleveland Electric) 1-47 (Cleveland Electric)
l M AN AG E M ENT'S other expense accruals. See Note 9 for information on retirement and postemployment benefits. Deferred oper-FIN ANCI AL AN ALYSIS ating expenses decreased because of the write-oft of the 1 l phase-in deferred operating expenses in 1993 as discussed Restilts of Operations in Note 7. Federalincome taxes decreased as a result or i l 1993 Ss. 1992 lower pretax operating income. l Factors contributing to the 3.1% increase in 1993 operat- As discussed in Note 4(b), $232 million of our Perry ing revenues for The Toledo Edison Company (Com- Nuclear Pc ar Plant Un:t 2 (Perry Unit 2) investment pany) are as follows: was written offin 1993. Credits for carrying charges Lncrease (Decrease) in oneratine Revenues oNs re rded in nonoperating income decreased because of a@gcW u,m Sales Volume and Mix $ 38 wholesale Sales (11) 1993 as discussed in Note 7. The federal income tax Base Rates and Misecllaneous (3) credit for nonoperating income in 1993 resulted from the Fuct Cost Recovery Revenues _2 write-offs. l Total Q The net revenue increase resulted primarily from the
- I difTerent 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 $17 million of the Minions higher 1993 revenues. Ilot summer weather in 1993 Increase (Decrease) in Oneratine Revenues of Dolbrs boosted residential and commercial kilowatt-hour sales. Sales Volume and Mix $(29) In contrast, the 1992 summer was the coolest in 56 years
$egRat gs and MisceHaneous in Northwestern Ohio. Residential and commercial sales g also increased as a result of colder late-winter tempera-
-g tures in 1993 which increased electric heating-related demand. Residential and commercial sales increased 5.1% The revenue decreases resulted primarily from the differ-and 3.2%, respectively, in 1993. Industrial sales increased ent weather conditions and the changes in the composi-6% as a result of increased sales to large automotive tion of the sales mix among customer categories.
manufacturers, petroleum refiners and the broad-based, Weather accounted for approximately $22 million of the l smaller industrial customer group. Other sales decreased lower 1992 revenues. Winter and spring in 1992 were 18.4% because of fewer sales to wholesale customers. milder than in 1991. In addition, the cooler summer in Generating plant outages and retail customer demand 1992 contrasted with the summer of 1991 which was limited power availability for bulk power transactions. As much hotter than normal. Total kilowatt-hour sales in-a result, total sales decreased 2.2% in 1993. Base rates creased 0.2% in 1992. Residential and commercial sales and miscellaneous revenues decreased in 1993 primarily decreased 4.9% and 3.8%, respectively, as moderate tem-from lower revenues under contracts having reduced rates Peratures in 1992 reduced electric heating and cooling with certain large customers and a declining rate strue. demands. Industrial sales increased 0.6% as increased ture tied to usage. The contracts have been negotiated to sales to glass and metal manufacturers and to the broad-meet competition and encourage economic growth. The based, smaller industrial customer group offset lower net increase in 1993 fuel cost recovery revenues resulted sales to petroleum refining and auto manufacturing cus-from changes in the fuel cost factors. The weighted tomers. Other sales increased 5.2% because ofincreased average of these factors increased about 2%. sales to wholesale customers. Operating revenues in 1991 included the recognition of $24 million of deferred reve-Operating expenses increased 12.6% in 1993. The increase nues over the period of a refund to customers under a m total operation and maintenance expenses resulted provision of a hnuary 1989 rate order. No such revenues from the $88 million of net benefit expenses related to an were reflected in 1992 as the refund period ended in early retirement program, called the Voluntary Transi-December 1991. tion Program (VTP), other charges totaling $19 million and a slight increase in other operation and maintenance Operating expenses decreased 4.4% in 1992. A reduction expenses. The VTP benefit expenses consisted of $75 of $14 million in other operation and maintenance ex-million of costs for the Company plus $13 million for the penses resulted primarily from cost-cutting measures. Company's pro rata share of the costs for its affiliate, Lower fuel and purchased power expense resulted from Centerior Service Company (Service Company). Other less amortization of previously deferred fuel costs than the charges recorded at year-end 1993 related to a perform- amount amortized in 1991. These decreases were par-ance improvement plan for Pctry Nuclear Power Plant tially offset by higher depreciation and amortization, Unit 1 (Perry Unit 1), postemploymert benefits and caused primarily by the adoption of the new accounting (Toledo Edison) F-49 (Toledo Edison)
standard for income taxes (SFAS 109) in 1992, and by tion, build a winning team and attain increasingly com-higher taxes, other than federal income taxes, caused by petitive power supply costs. To achieve these objectives, increased Ohio property taxes. Deferred operating ex- the Company will continue controlling its operation and penses increased as a result of the deferrals under the maintenance expenses and capital expenditures, reduce Rate Stabilization Program discussed in Note 7. its outstanding debt, increase revenues by finding new uses f r xisting assets and resources, implement a broad The federal income tax provision for nonoperating income r nge f new m rketing programs, increase revenues by decreased because of a greater tax allocation of interest restructuring rates for various customers where appropri-charges to nonoperating activities. Credits for carrying te, impmve the operating performance ofits plants and charges recorded in nonoperating income increased pri- take other appropriate actions. ; marily because of Rate Stabilization Program carrying charge credits. Interest charges decreased as a result of Comm n St ek Disidends debt refinancings at lower interest rates and lower short, ' term borrowing requirements. In recent years, the Company hi s retained all of its earnings available for common stock. The Company has Otitlook not paid a common stock dividend to Centerior Energy since February 1991. Because the Company is currently Recent Actions prohibited from paying a common stock dividend by a provision in its mortgage (see Note 11(b)), the Company In January 1994, Centerior Energ~y Corporation does not expect to pay any common stock dividends in (Centerior Energy), along with the Company and The Cleveland Electric illuminating Company (Cleveland the foreseeable future. Electric), announced a comprehensive strategic action plan to strengthen their fmancial r.nd competitive posi. Competition tions. The Company and Cleveland Electric are the tw Our electric rates are among the highest in our region wholly owned electne utility subsidianes of Centerior . . ecause we am rec vc 8 h suWandal innument in Energy. The plan established specific objectives and was ur n ear c utmedon pmgram. Acodngh, some d designed to guide Centerior Energy and its subsidiaries through the year 2001. Several actions were taken at that gur gtonwrs connue to seg ku cosdy ahemade, mcu ng swid,ng to or woWng m neak a mumcipa1 time. Centerior Energy reduced its quarterly common e ectnc system. Dem am a nunk d mral ad mum,m, stock dividend from $.40 per share to $.20'per share pal systems in our service area. In addition, we face elTective with the dividend payable February 15,1994. ts of een munic@ amies b our sene area estab This action was taken because projected financial results lishing new systems. We have entered into agreements did not support continuation of the dividend at its former with some of the communities which considered estab-rate. The Company and Cleveland Electric also wrote Ung systems Acordbgh, Mey wiH not pmceed 4 off their investments in Perry Unit 2 and certain deferred m e pmen at Ms dme in mmm b rak conus-charges related to a January 1989 mte agreement s m and/or economic development funds. Others have (phase-in deferrals). The aggregate after-tax e' rect of determmed that developing a system was not feasible. We these write-offs for the Company was $332 million which resulted in a net loss in 1993 and a retained earnings will e ntinue to address municipal system threats , mug 88mnh mahmg pmgrams ad em@as,izing deficit. The write-olTs are discussed in Notes 4(b) and 7. t ur customers the value of our service and the n,sks of The Company also recognized other one-time charges a nmn c p system. totaling $15 million after taxes related to a performance improvement plan for Perry Unit I, postemployment The Energy Policy Act of 1992 (Energy Act) will provide benefits and other expense accruals. additional competition in the electric utility industry by requiring utilities to wheel to municipal systems in their Also contributing to the net loss in 1993 was a charge of service areas electricity from other utilities. This provi-
$36 million after taxes representing a portion of the VTP si n f the Energy Act should not significantly increase costs. The Company will realize approximately $20 the competitive threat to us since the operating licenses million of savings in annual payroll and benefit costs f r ur nuclear units have required us to wheel to mumci-beginning in 1994 as a result of the VTP.
pal systems in our service area since 1977. The Energy Act also created a class of exempt wholesale generators Strategic Plan which may increase competition m the wholesale power The objectives of the strategic plan are to maximize share market. A further risk is the possibility that the govern-owner return on Centerior Energy common stock from ment could mandate that utilities deliver power from corporate assets and resources, achieve profitable revenue another utility or generation source to their retail custom-growth, become an industry leader in customer satisfac- ers. We have entered into contracts with many of our (Toledo Edison) F-50 (Toledo Edison)
large industrial and commercial customers which have Hazardous Waste Disposal Sites remaining terms of one to five years. We will attempt to renew those contracts as they expire which will help us The Comprehensive Environmental Response, Compen-compete if retail wheeling is permitted in the future. sation and Liability Act of 1980 as amended (Superfund) established programs addressing the cleanup Rate Matters of hazardous waste disposal sites, emergency prepared-Our Rate Stabilization Program remains in effect. Under ness and other issues. The Company is aware of its this program, we agreed to freeze base rates until 1996 potential involvement in the cleanup of several sites. Although these sites are not on the Superfund National I and limit rate increases through 1998. In exchange, we ' Priorities List, they are generally being administered by are permitted to defer through 1995 and subsequently vdous governmental entities in the same manner as l recover certain costs not currently recovered in rates and they would be administered if they were on such list.The l to accelerate the amortization of certain benefits. The
. allegations that the Company disposed of hazardous j amortization and recovery of the deferrals wdl beg,m with
! future rate recognition and will continue over the aver- waste at these sites and the amounts involved are often unsubstantiated and subject to dispute. Superfund pro-l age life of the related assets, or approximately 30 years. vides that all "potentially responsible parties" (PRPs) to The contmued use of these regulatory accounting mea-a particular site can be held liable on a joint and several sures will be dependent upon our continuing assessment basis. Consequently,if the Company were held liable for and conclusion that there will be probable recovery of 100% of the cleanup costs of all of the sites referred to such deferrals m future rates. above, the cost could be as high as $150 million. The analysis leading to the year-end 1993 financial ac- However, we believe that the actual cleanup costs will be tions and strategic plan also included an evaluation of our substantially lower than $150 million, that the Company's regulatory accounting measures. We decided that, once share of any cleanup costs will be substantially less than the deferral of expenses and acceleration of benefits 100% and that most of the other PRPs are financially under our Rate Stabilization Program are completed in able to contribute their share. The Company has accrued 1995, we should no longer plan to use regulatory account- a liability totaling $6 million at December 31,1993 ing measures to the extent we have in the past, based on estimates of the costs of cleanup and its proportionate responsibility for such costs. We believe Nuclear Operations that the ultimate outcome of these matters will not have a material adverse elTect on our financial condition or The Company's three nuclear units may be impacted by results of operations. activities or events beyond our control. Operating nuclear generating units have experienced unplanned outages or extensions of scheduled outages because of equipment 1993 Tax Act problems or new regulatory requirements. A major acci-dent at a nuclear facility anywhere in the world could The Revenue Reconciliation Act of 1993 (1993 Tax cause the Nuclear Regulatory Commission (NRC) to Act), which was enacted in August 1993, provided for a limit or prohibit the operation or licensing of any nuclear 35% income tax rate in 1993. The 1993 Tax Act did not unit. If one of our nuclear units is taken out of service for materially impact the results of operations for 1993, but an extended period of time for any reason, including an did afTect certain Balance Sheet accounts as discussed in accident at such unit or any other nuclear facility, we Note 8. The 1993 Tax Act is not expected to materially cannot predict whether regulatory authorities would im. impact future results of operations or cash flow. pose unfavorable rate treatment. Such treatment could include taking our affected unit out of rate base or Inflation disallowing certain construction or maintenance costs. An extended outage of one of our nuclear units coupled with Although the rate of inflation has eased in recent years, unfavorable rate treatment could have a material ad- we are still affected by even modest inflation which causes verse effect on our financial condition and results of increases in the unit cost of labor, materials and services. operations. We externally fund the estimated costs for the futur decommissionmg of our nuclear um,ts. In 1993, we in- Capital Resources and Liquidity creased our decommissioning expense accruals for revi- 1991-1993 Cash Requirements sions in our cost estimates. We expect the increases associated with the new estimates will be recoverable in We need cash for normal corporate operations, the future rates. See Note 1(f). mandatory retirement of securities and an ongoing pro-(Toledo Edison) F-51 (Toledo Edison)
y gram of constructing new facilities and modifying existing write-offs recorded at December 31,1993 caused the I facilities. The construction program is needed to meet Company, Cleveland Electric and Centerior Energy to anticipated demand for electric service, comply with violate certain of those covenants. The affected creditors governmental regulations and protect the environment, have waived those violations in exchange for commit-Over the three-year period of 1991-1993, these construc- ments to provide them with a second mortgage security lion and mandatory retirement needs totaled approxi- interest on property of the Company and Cleveland mately $440 million. In addition, we exercised various Electric and other considerations. We expect to complete options to redeem approximately $490 million of our this process in the second quarter of 1994. We will securities. provide the same security interest to certain other credi-tors because their agreements require equal treatment. We raised $815 million through security issues and term We expect to provide second mortgage collateral for $172 bank.ioans during the 1991-1993 period as shown m. the million of unsecured debt, $228 million of bank letters of- l Cash Flows :tatement. During the three-year period, th credit and a $205 million revolving credit facility. The I Company also utilized its short-term borrowmg arrange- bank letters of credit and revolving credit facility are joint ments to help meet its cash needs. and several obligations of the Company and Cleveland Although the write-ofTs of Perry Unit 2 and the phase-in Electric. For the next five years, the Company does not deferrals in 1993 negatively afTected our earnings, they expect to raise funds through the sale of debt junior to did not adversely affect our current cash flow. first mortgage bonds. However, if necessary or desirable, we believe that the Company could raise funds through the sale of unsecured debt or debt secured by the second 1994 and lleyond Cash Requirements mortgage referred to above. The Company also is able to Estimated cash requirements for 1994-1998 for the Com- raise funds through the sale of preference stock. The pany are $249 million for its construction program and Company will be unable to issue preferred stock until it
$324 million for the mandatory redemption of debt and can meet the interest and preferred dividend coverage preferred stock. The Company expects to finance inter- test in its articles of incorporation.
nally all of its 1994 cash requirements of approximately The Company currently cannot sell commercial paper .
$109 million. About 15% of the Company's 1995-1998 because of its low commercial paper ratings by Standard requirements are expected to be financed externally. If
& Poor's Corporatmn (S&P) and Moody's Investors economical, additional securities may be redeemed under Service, Inc. (Moody's) of "B" and "Not Prime", re-optional redemption provisions, which will help improve ,
spectively. The Company is a party to a $205 milhon the Company's capitalization structure and interest cov-rev Iving credit facility which will run through mid-1996. erage ratios. However, we currently cannot draw on this facility be-Our capital requirements are dependent upon our imple- cause the write-offs taken at year-end 1*? caused the mentation strategy to achieve compliance with the Clean Company, Cleveland Electric and Ce Nr Energy to Air Act Amendments of 1990 (Clean Air Act). Cash fail to meet certain capitalization ara! ti ed charge cover-expenditures for our plan are estimated to be approxi- age covenants. We expect to have this facility available mately $41 million over the 1994-1998 period. See Note to us again after it is amended in the second quarter of 4(a). 1994 to provide the participating creditors with a second mortgage security interest. Liquidity These financing resources are expected to be suflicient for the Company's needs over the next several years. The Additional first mortgage bonds may be issued by the availability and cost of capital to meet the Company's Company under its mortgage on the basis of property external financing needs, however, also depend upon such additions, cash or refundable first mortgage bonds. Under f ctors as financial market conditions and its credit its mortgage, the Company may issue first mortgage ratings. Current credit ratings for the Company are as bonds on the basis of property additions and, under f H ws: certain circumstances, refundable bonds only if the appli-cable interest coverage test is met. At December 31, SAP Moody's 1993, the Company would have been permitted to issue First mortgage bonds BB Ba2 approximately $323 million of additional first mortgage Unsecured notes B+ Ba3 , Preferred stock B bl bonds. As discussed in Note ll(d), certain unsecured debt These ratings reflect a downgrade in December 1993. In agreements contain covenants relating to capitalization, addition, S&P has issued a negative outlook for the fixed charge coverage ratios and secured financings. The Company. (Toledo Edison) F 52 (Toledo Edison)
INCOME STATEMENT ne roicso esison compan, _for thtyears ended December 31. 1993 1992 1991 (millions of dollars) Operating Revenues (1) % 871 $845 8
$8_81 l Operating Expenses Fuel and purchased power .
173 169 178 Other operation and maintenance __ 349 342 356 Early retirement program expenses and other _ 107 - - Total operation and maintenance 629 511 534 Depreciation and amortization 76 77 72 Taxes, other than federal income taxes 9 91 89 Deferred operating expenses, net (4) (17) 1 Federal income taxes (credit) (10) 33 32 782 695 _728 i Operating income 89 I50 159 Nonoperating income (Loss) Allowance for equity funds used during construction i 1 1 Other income and deductions, net - 1 5 Write-off of Perry Unit 2 (232) - - Deferred carrying charges, net (161) 41 22 Federal income taxes - credit (expense) _lL9 (1) (6) _(261)6 42 22 income (Loss) Before Interest Charges (l74) _l92 181 Interest Charges \ Debt interest i16 122 132 Allowance for borrowed funds used during construction (1) (1) (1) _ 111 _l21 E Net income (Loss) (289) 71 50 Preferred Dividend Requirements 23 24 _2_5 Earnings (Loss) Availablefor Common Stock $L112) $ 47 $ 25 (1) Includes revenues from all bulk power sales to Cleveland Electric of $120 million, $130 million and $128 million in 1993,1992 and 1991, respectively. RETAINED E ARNINGS For the years ended December 31. 1993 1992 L991 (millions of dollars) Retained Earnings at Beginning of l' ear % 131 $ 90 $ 83 Additions Net income (loss) (289) 71 50 Deductions Dividends declared: Common stock - - (18) Preferred stock (23) (24) _(21) Net increase (Decrease) .(312) 47 7 Retained Earnings (Deficit) at End of l' ear $-(17._5) $131 $_90 The accompanying notes are an integral part of these statements. (Toledo Edison) F-53 (Toledo Edison)
CASH FLOWS na roteso ssison compan, For the years ended December 31. 1993 1992 1991 (millions of dollars) Cash Flowsfrom Operating Activities (1) Net Income (Loss) $(289) $ 71 $ 50 Adjustments to Reconcile Net Income (Loss) to Cash from Operating Activities: Depreciation and amortization 76 77 72 Deferred federal income taxes (160) 28 32 Investment tax credits, net - (5) 30 Deferred and unbilled revenues (4) 1 (26) Deferred fuel (4) 4 Deferred carrying charges, net 161 (41) (22) Leased nuclear fuel amortization 38 56 54 Deferred operating expenses, net (4) (17) 1 Allowance for equity funds used during construction (1) (1) (1) Noncash early retirement program expenses, net 83 - - Write-ofl' of Perry Unit 2 232 - - Changes in amounts due from customers and others, net (3) - 3 Changes in inventories 10 (9) (7) Changes in accounts payable 16 (8) (13) Changes in working capital affecting operations 21 7 (26) Other noncash items 14 13 14 Total Adjustments 479 97 115 Net Cash from Operating Activities 190 168 165 Cash Flowsfrom Financing Activities (2) Bank loans, commercial paper and other short-term debt (40) 40 (23) Notes payable to afIlliates - (30) 14 i
- Debt issues
i First mortgage bonds 20 276 - l Secured medium-term notes 93 48 135 Term bank loans and other long-term debt - 135 108 Maturities, redemptions and sinking funds (89) (531) (179) Nuclear fuel lease obligations (47) (52) (52) Dividends paid (23) (24) (43) Premiums, discounts and expenses (1) (8) (1) Net Cash from Financing Activities (87) (146) (41) Cash Flowsfrom investing Activities (2) Cash applied to construction (42) (48) (51) Interest capitalized as allowance for borrowed funds used during construction (1) (1) (1) Loans to afliliates - 12 (12) Sale and leaseback restructuring fees - (43) - Other cash received (applied) 6 (5) (3) Net Cash from investing Activities (37) (85) (67) Net Change in Cash and Temporary Cash investments 66 (63) 57 Cash and Temporary Cash investments at Beginning of Year 16 79 22 Cash and Temporary Cash investments at End of Year S 82 $ 16 $ 19 (1) Interest paid (net of amounts capitalized) was $92 million, $95 million and $120 million in 1993,1992 and 1991, ) respectively. Income taxes paid were $7 million, $3 million and $9 million in 1993,1992 and 1991, respectively. j (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. (Toledo Edison) F-54 (Toledo Edison)
CASH FLOWS na rateso rsison compan, For the years ended December 31. 1993 1992 1991 (millions of dollars) Cash Flowsfrom Operating Activities (1) Net income (Loss) 11L89) $ 71 $ 50 Adjustments to Reconcile Net income (Loss) to Cash from Operating Activities: Depreciation and amortization 76 77 72 Deferred federal income taxes (160) 28 32 Investment tax credits, net - (5) 30 Deferred and unbilled revenues (4) 1 (26) Deferred fuel - (4) 4 Deferred carrying charges, net 161 (41) (22) Leased nuclear fuel amortization 38 56 54 Deferred operating expenses, net (4) (17) 1 Allowance for equity funds used during construction (1) (1) (1) Noncash early retirement program expenses, net 83 - - Write-off of Perry Unit 2 232 - - Changes in amounts due from customers and others, net (3) - 3 Changes in inventories 10 (9) (7) Changes in accounts payable 16 (8) (13) Changes in working capital afTecting operations 21 7 (26) Other noncash items 14 13 14 Total Adjustments 479 97 115 Net Cash from Operating Activities 190 168 165 Cash Flowsfrom Financing Activities (2) Bank loans, commercial paper and other short-term debt (40) 40 (23) Notes payable to afIlliates - (.30) 14 Debt issues: First mortgage bonds 20 276 - Secured medium-term notes 93 48 135 Term bank loans and other long-term debt - 135 108 Maturities, redemptions and sinking funds (89) (531) (179) Nuclear fuel lease obligations (47) (52) (52) Dividends paid (23) (24) (43) Premiums, discounts and expenses (1) (8) (1) Net Cash from Financing Activities (87) (146) (41) Cash Flowsfrom investing Activities (2) Cash applied to construction (42) (48) (51) Interest capitalized as allowance for borrowed funds used during construction (1) (1) (1) Loans to afliliates - 12 (12) Sale and leaseback restructuring fees - (43) - l Other cash received (applied) 6 (5) (3) l Net Cash from investing Activities (37) (85) (67) i Net Change in Cash and Temporary Cash investments 66 (63) 57 j Cash and Temporary Cash Investments at Beginning of l' ear 16 79 22 Cash and Temporary Cash investments at End of l' ear S 82 $ 16 $ 79 (1) Interest paid (net of amounts capitalized) was $92 million, $95 million and $120 million in 1993,1992 and 1991, respectively. Income taxes paid were $7 million, $3 million and $9 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 i i capitalizations under nuclear fuel agreements are excluded from this statement. The accompanying notes are an integral part of this statement. (Toledo Edison) F-54 (Toledo Edison)
l [THis PAGE INTENTIONALLY LEFr BLANK) 1 i I l l
BALANCE SHEET _ December 31. 1993 1992 (millions of dollars) ASSETS Property, Plant and Equipment Utility plant in service $2,837 $2,847 Less: accumulated depreciation and amortization 788 760 2,049 2,087 Construction work in progress 40 37 Perry Unit 2 - 243 2,089 2,367 I Nuclear fuel, net of amortization 142 161 Other property, less accumulated depreciation - 3 2,231 2.531 Current Assets Cash and temporary cash investments 82 16 Amounts due from customers and others, net 63 60 Amounts due from alliliates 16 23 Unbilled revenues 25 21 Materials and supplies, at average cost 43 40 Fossil fuel inventory, at average cost 12 25 Taxes applicable to succeeding years 71 71 Other 2 2 314 258 Deferred Charges and Other Assets Amounts due from customers for future federalincome taxes 382 391 Unamortized loss from Beaver Valley Unit 2 sale 105 110 Unamortized loss on reacquired debt 32 37 Carrying charges and operating expenses 343 500 Nuclear plant decommissioning trusts 26 20 Other 77 92 ; 965 1.150 Total Assets $3.510 $3 939 The accompanying notes are an integral part of this statement. 1 1 f l l (Toledo Edison) F-55 (Toledo Edison)
The Toledo Edison Company _Dscember 31_ 1993 1992 (millions of dollars) CAPITAllZATION AND LIABILITIES Capitali:ation Common shares, $5 par value: 60 million authorized; 39.1 million outstanding in 1993 and 1992 $ 196 $ 196 , Premium on capital stock ,_ _ 481 481 l Other paid-in capital 121 121 l Retained earnings tdeficit) . (175) 137 Common stock equity 623 935 Preferred stock With mandatory redemption provisions 28 50 Without mandatory redemption provisions 210 210 Long-term debt L225 1.17.1 ; _.2.QM 2.373 Other Noncurrent Liabilities Nuclear fuel lease obligations 103 126 Other 83 62 186 188 Current Liabilities Current portion of long-term debt and preferred stock 57 58 , Current portion of nuclear fuel lease obligations 49 51 Notes payable to banks and others - 40 Accounts payable 63 47 Accounts payable to afIlliates 27 16 ; Accrued taxes 90 78 Accrued interest 27 28 Other 16 14 329 332 Deferred Credits Unamortized investment tax credits 94 103 Accumulated deferred federal income taxes 471 640 Unamortized gain from Bruce Mansfield Plant sale 208 218 Accumulated deferred rents for Bruce Mansfield Plant and Beaver Valley Unit 2 50 46 Other 86 39 I 909 1.046 Total Capitalization and Liabilities $3.5LQ $3.939 (Toledo Edison) F-56 (Toledo Edison)
STATEMENT OF PREFERRED STOCK na roicso tsison compan, Current Call Price 1993 Shares Per December 31. Outstanding Share 1993 1992 (millions of dollars) $100 par value, 3.000,000 preferred shares authorized and
$25 par value, 12,000,000 preferred shares authorized Subject to mandatory redemption:
$100 par $9.375 100,150 $102.47 $ 10 $ 12 25 par 2.81 1,200,000 25.94 _l0 50 40 62 Less: Current maturities 12 12 Total Preferred Stock, with Afandatory Redemption Provisions $ 28 $ 50 Not subject to mandatory redemption:
$100 par S 4.25 160,000 104.625 $ 16 $ 16 4.56 50,000 101.00 5 5 4.25 100,000 102.00 10 10 8.32 100,000 102.46 10 10 7.76 150,000 102.437 15 15 7.80 150,000 101.65 15 15 10.00 190,000 101.00 19 19 25 par 2.21 1,000,000 25.25 25 25 2.365 1,400,000 27.75 35 35 Series A Adjustable _._ 1,200,000 25.75 30 30 Series B Adjustable __ 1,200,000 25.75 30 30 Total Preferred Stock, without Afandatory Redemption Provisions $2Lo $210 The accompanying notes are an integral part of this statement.
I (Toledo Edison) F-57 (Toledo Edison)
y NOTES TO THE (d) Fuel Expense FINANCI AL STATEMENTS h c st f f ssil fuel is charged to fuel expense based on mventory usage. The cost of nuclear fuel, meluding an l (1) Summary of Significant interest component, is charged to fuel expense based on { the rate of consumption. Estimated future nuclear fuel Accounting Policies disposal costs are being recovered through the base rates. (a) General The Company defers the difTerences between actual fuel The Company is an electric utility and a wholly owned costs and estimated fuel costs currently being recovered subsidiary of Centerior Energy. Centerior Energy has two from customers through the fuel factor. This matches other wholly owned subsidiaries, Cleveland Electric and fuel expenses with fuel-related revenues. , the Service Company. The Company follows the Uni-Owners of nuclear generating plants are assessed by the l form System of Accounts prescribed by the Federal ' federal government for the cost of decontamination and Energy Regulatory Commission (FERC) and adopted by decommissioning of nuclear enrichment facilities oper. The Public Utilities Commission of Ohio (PUCO). As a ated by the United States Department of Energy. The rate-regulated utility, the Company is subject to State-assessments are based upon the amount of enrichment ment of Financial Accounting Standards (SFAS) 71 ) services used in prior years and cannot be imposed for which governs accounting for the effects of certain types more than 15 years. The Company has accrued a liability of rate regulation. for its share of the total assessments. These costs have The Company is a member of the Central Area Power been recorded in a deferred charge account since the Coordination Group (CAPCO). Other members are PUCO is allowing the Company to recover the assess-Cleveland Electric, Duquesne Light Company, Ohio ments through its fuel cost factors. Edison Company and its wholly owned subsidiary, Penn-(e) Deferred Carrying Charges sylvania Power Company. The members have con- and Operating Expenses structed and operate generation and transmission The PUCO authorized the Company to defer operating facilities for their use. expenses and carrying charges for Perry Unit I and (b) Related Party Transactions Beaver Valley Power Station Unit 2 (Beaver Valley Unit Operating revenues, operating expenses and interest 2) from their respective in-service dates in 1987 through charges include those amounts for transactions with allili. December 1988. The annual amortization and recovery ated companies in the ordinary course of business of these deferrals, called pre-phase-in deferrals, are operations. $7 million which began in January 1989 and will continue The Company's transactions with Cleveland Electnc are
. over the lives of the related property.
primarily for firm power, interchange power, transmis- Beginning in January 1989, the Company deferred certain sion line rentals and jointly owned power plant operations perating expenses and both interest and equity carrying and construction. See Notes 2 and 3. charges pursuant to a PUCO-approved rate phase-in plan for its investments in Perry Unit I and Beaver Valley The Service Company provides management, financial, Unit 2. These deferrals, called phase-in deferrals, were administrative, engineering, legal and other services at written off at December 31,1993. See Note 7. cost to the Company and other afliliated companies. The Service Company billed the Company $76 milh.on,$60 The Company also defers certain costs not currently recovered .in rates under a Rate Stabilizat. ion Program milh.on and $61 milh.on m 1993,1992 and 1991, respec-tively, for such senices. approved by the PUCO in October 1992. See Notes 7 and (c) Resenues . (f) Depreciation and Amortizat. ion Customers are billed on a monthly cycle basis for their The cost of property, plant and equipment is depreciated energy consumption based on rate schedules or contracts over their estimated useful lives on a straight-line basis, authorized by the PUCO or on ordinances of individual The annual straight-line depreciation provision for non-municipalities. An accrualis made at the end of each nuclear property expressed as a percent of average depre-month to record the estimated amount of unbilled reve-ciable utility plant in service was 3.6% in both 1993 and nues for kilowatt-hours sold in the current month but not 1992 and 3.4% in 1991. Effective January 1,1991, the billed by the end of that month. _ Company, after obtaining PUCO approval, changed its A fuel factor is added to the base rates for electric service. method of accounting for nuclear plant depreciation from This factor is designed to recover from customers the the units-of-production method to the straight-line costs of fuel and most purchased power. It is reviewed method at about a 3% rate. This change decreased 1991 . and adjusted semiannually in a PUCO proceeding. depreciation expense $14 million and increased 1991 net (Toledo Edison) F-58 (Toledo Edison)
income $11 million (net of $3 million of income taes) (h) Deferred Gain and Loss from from what they otherwise would have been. The PlICO Sales of Utility Plant subsequently approved in 1991 a change to lower the 3% The sale and leaseback transactions discussed in Note 2 rate to 2.5% retroactive to January 1,1991. resulted in a net gain for the sale of the Bruce Mansfield Generating Plant (Mansfield Plant) and a net loss for the Pursuant to a PUCO order, the Company currently uses ule of Beaver Valley Unit 2. The net gain and net loss external funding for the future decommissioning of its were deferred and are being amortized over the terms of nuclear units at the end of their licensed operating lives
- leases. These amortizations and the lease expense The estimated costs are based on the NRC's DECON amounts are recorded as other operation and maintenance method of decommissioning (prompt decontamination), expenses.
Cash contributions are made to the trust funds on a straight-line basis over the remaining licensing period for (i) Interest Charges each unit. The current level of annual expense being Debt Interest reported in the income Statement does not recovered from customers based on prior estimates is include interest on obligations for nuclear fuel under approximately $4 million. However, actual decommis- construction. That interest is capitalized. See Note 6. sioning costs are expected to significantly exceed those Losses and gains realized upon the reacquisition or re-l estimates. Current site-specific estimates for the Com-demption of long-term debt are deferred, consistent with pany's share of the future decommissioning costs are $41 the regulatory rate treatment. Such losses and gains are million in 1992 dollars for Beaver Valley Unit 2 and $87 either amortized over the remainder of the original life million and $146 million in 1993 dollars for Perry Unit I of the debt issue retired or amortized over the life of the and the Davis-Besse Nuclear Power Station (Davis- new debt issue when the proceeds of a new issue are Besse), respectively. The estimates for Perry Unit I and used for the debt redemption. The amortizations r.re Davis-Besse are preliminary and are expected to be included in debt interest expense. finalized by the end of the second quarter of 1994. The Company used these estimates to increase its decommis. (j) Federal Income Taxes sioning expense accruals in 1993. It is expected that the The Financial Accounting Standards Board (FASB) is-increases associated with the revised cost estimates will sued SFAS 109, a new standard for accounting for be recoverable in future rates. In the Balance Sheet at income taxes, in February 1992. We adopted the new December 31,1993, Accumulated Depreciation and standard in 1992. The standard amended certain provi-Amortization included $34 million of decommissioning sions of SFAS 96 which we had previously adopted. costs previously expensed and the earnings on the external Adoption of SFAS 109 in 1992 did not materially afTect funding.This amount exceeds the Balance Sheet amount our results of operations, but did afTect certain Balance of the external Nuclear Plant Decommissioning Trusts Sheet accounts. See Note 8. because the reserve began prior to the external trust The financial statements reflect the liability method of funding
- accounting for income taxes. This method requires that deferred taxes be recorded for all temporary differences (g) Property, Plant and Equipment between the book and tax bases of assets and liabilities.
Property, plant and equipment are stated at original cost The majority of these temporary dilTerences are attributa-less amounts ordered by the PUCO to be written off. ble to property-related basis difTerences, included in Construction costs include related payroll taxes, pen- these basis differences is the equity component of sions, fringe benefits, management and general overheads AFUDC, which will increase future tax expense when it and allowance for funds used during construction is recovered through rates. Since this component is not (AFUDC). AFUDC represents the estimated composite recognized for tax purposes, we must record a liability for l debt and equity cost of funds used to finance construction. ur tax obligation. The PUCO permits recovery of such This noncash allowance is credited to income. The taxes from customers when they become payable. There-AFUDC rate was 10.22% in 1993 and 10.96% in both f re, the net amount due from customers through rates 1992 and 1991. has been recorded as a deferred charge and will be recovered over the lives of the related assets. Maintenance and repairs are charged to expense as in- Investment tax credits are deferred and amortized over curred. The cost of replacing plant and equipment is the lives of the applicable property as a reduction of charged to the utility plant accounts. The cost of property depreciation expense. See Note 7 for a discussion of the retired plus removal costs, after deducting any salvage amortization of certain unrestricted excess deferred taxes value, is charged to the accumulated provision for and unrestricted investment tax credits under the Rate depreciation. Stabilization Program. (Toledo Edison) F-59 (Toledo Edison)
(2) Utility Plant Sale and the Company paid $43 million as supplemental rent to fund transaction expenses and part of the tender pre-Leaseback Transact. ions mium. This amount has been dererred and is being The Company and Cleveland Electric are co-lessees of amortized over the remaining lease term. The refinancing 18.26% (150 megawatts) of Beaver Valley Unit 2 and transaction reduced the annual rental expense for the 6.5% (51 megawatts), 45.9% (358 megawatts) and Beaver Valley Unit 2 lease by $9 million. 44.38 % (355 megawatts) of Units I,2 and 3 of the Mansfield Plant, respectively, all for terms of about 29% Future minimum lease payments under the operating years. These leases are the result of sale and leaseback te ses at December 31,1993 are summarized as follows: transactions completed in 1987. For For Under these leases, the Company and Cleveland Electric Year co$pany e are responsible for paying all taxes, insurance premiums, (millions or dollars) operation and maintenance expenses and all other simi. 1994 . s 103 s 63 1995 102 63 lar costs for their interests in the units sold and leased 1996 125 63 back. They may incur additional costs in connection with 1997. 102 63 I capital improvements to the units. The Company and '
$8 dears . 2 1.3 Cleveland Electric have options to buy the interests back Total Future Minimum Lease at the end of the leases for the fair market value at that Payments . $2,555 $1.706 time or to renew the leases. Additional lease provisions provide other purchase options along with conditions for Rental expense is accrued on a straight-line basis over the mandatory termination of the leases (and possible repur- terms of the leases. The amount recorded in 1993,1992 chase of the leasehold interests) for events of default. and 1991 as annual rental expense for the Mansfield These events include noncompliance with several finan-Plant leases was $45 million. The amounts recorded in cial covenants discussed in Note ll(d). 1993,1992 and 1991 as annual rental expense for the As co-lessee with Cleveland Electric, the Company is also Beaver Valley Unit 2 lease were $63 million, $66 million obligated for Cleveland Electric's lease payments. If and $72 million, respectively. Amounts charged to ex-Cleveland Electric is unable to make its payments under Pense in excess of the lease payments are classified as the Mansfield Plant leases, the Company would be Accumulated Deferred Rents in the Balance Sheet.
obligated to make such payments. No payments have The Company is selling 150 megawatts of its Beaver been made on behalf of Cleveland Electric to date. Valley Unit 2 leased capacity entitlement to Cleveland in April 1992, nearly all of the outstanding Secured Lease Electric. We anticipate that this sale will continue indefi-Obligation Bonds (SLOBS) issued by a special purpose nitely. Revenues recorded for this transaction were $103 corporation in connection with financing the sale and million, $108 million and $107 million in 1993,1992 and l leaseback of Beaver Valley Unit 2 were refinanced 1991, respectively. The future minimum lease payments through a tender offer and the sale of new bonds having a through the year 2017 associated with Beaver Valley lower interest rate. As part of the refinancing transaction, Unit 2 aggregate $1.47 billion. (3) Property Owned with Other Utilities and Investors The Company owns, as a tenant in common with other utilities and those investor: 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 Company's share of the operating expenses of these generating units is included in the Income Statement. The Balance Sheet classification of Property, Plant and Equipment at December 31,1993 includes the following facilities owned by the Company as a tenant in common with other utilities and Lessors: In. Plant Construction Service Ownership Ownership Power in Work in Accumulated Generatine Unit Date Share Megawatts Source Service Progress Denreciation (millions of dollars) Davis-Besse 1977 48.62% 429 Nuclear $ 679 510 $163 Perry Unit i 1987 19.91 238 Nuclear 1.051 3 186 Beaver Valley Unit 2 and Common Facilities (Note 2) 1987 1.65 13 Nuclear 203 .,,_2 _Jf! Total $L9.JJ Q 3 (Toledo Edison) F-60 (Toledo Edison)
will not have a material adverse elTect on our financial (4) Construction and. . condition or results of operations. See Management's Contingencies yi,,,ci,, 3 ,,,,,,, _ o ,,,,,x_,,,,,,o,,, ,,,,, oi,p,. (a)' Construct.mn Program sal Sites. The estimated cost of the Company's construction pro- . gram for the 1994-1998 period is $259 million, including (5) Nuclear Operations and AFUDC of $10 million and excluding nuclear fuel. Contingencies The Clean Air Act will require, among other things, (a) Operating Nuclear Units l significant reductions in the emission of sulfur dioxide in The Company's three nuclear units may be impacted by two phases over a ten-year period and nitrogen oxides by activities or events beyond our control. An extended fossil-fueled generating units. outage of one of our nuclear units for any reason, Our compliance strategy provides for compliance with coupled with any unfavorable rate treatment, could have a both phases through at least 2005 primarily through material adverse effect on our financial condition and greater use of low-sulfur coal at some of our units and the results of operations. See discussion of these risks in banking of emission allowances. The plan will require hianagement's Financial Analysis - Outlook-Nuclear capital expenditures over the 1994-2003 period of ap- Operations, proximately $57 million for nitrogen oxide control equip-(b) Nuclear Insurance ment, emission monitoring equipment and plant The Price-Anderson Act limits the liability of the owners modifications. In addition, higher fuel and other opera-f a nuclear power plant to the amount provided by tion and maintenance expenses may be incurred. The private insurance and an industry assessment plan. In the anticipated rate increase associated with the capital ex-penditures and higher expenses would be less than 2% event f a nuclear incident at any unit in the United States resultir.g in losses in excess of the level of private over the ten-year period. The PUCO has approved this plan. We also are seeking United States Environmental insur nce (currently $200 million), the Company's maxi-mum p tential assessment under that plan would be $70 Protection Agency (U.S. EPA) approval of the first phase of our plan. milli n (plus any inflation adjustment) per incident. The assessment is limited to $9 million per year for each We are continuing to monitor developments in new tech- nuclear incident. These assessment limits assume the nologies that may be incorporated into our compliance other CAPCO companies contribute their proportionate strategy. If a different plan is required by the U.S. EPA, share of any assessment, significantly higher capital expenditures could be re-quired during the 1994-2003 period. We believe Ohio The CAPCO companies have insurance coverage for law permits the recovery of compliance costs from cus- damage to property at the Davis-Besse, Perry and Beaver tomers in rates. Valley sites (including leased fuel and clean-up costs). Coverage amounted to $2.75 billion for each site as of
'I "" January 1,1994. Damage to property could exceed the Perry Unit 2, including its share of the facilities common insurance coverage by a substantial amount. If it does, with Perry Unit 1, was approximately 50% complete the Company's share of such excess amount could have when construction was suspended in 1985 pending con-a material adverse effect on its financial condition and sideration of various options. These options included results of operations. Under these policies, the Company resumption of full construction with a revised estimated can be assessed a maximum of $11 million during a policy cost, conversion to a nonnuclear design, sale of all or part year if the reserves available to the insurer are inadequate of our ownership share, or cancellation.
to pay claims mising out of an accident at any nuclear We wrote off our investment in Perry Unit 2 at December facility covered by the insurer. 31, 1993 after we determined that it would not be The Company also has extra expense insurance coverage. completed or sold. The write-off totaled $232 million it includes the incremental cost of any replacement ($167 million after taxes) for the Company's 19.91% power purchased (over the costs which would have been ownership share of the unit. See Note 14. incurred had the units been operating) and other inci-(c) llazardous Waste Disposal Sites dental expenses after the occurrence of certain types of , The Company is aware of its potential involvement in the accidents at our nuclear units. The amounts of the cover-cleanup of several hazardous waste disposal sites. The age are 100% of the estimated extra expense per week Company has accrued a liability totaling $6 million at during the 52-week period starting 21 weeks after an December 31,1993 based on estimates of the costs of accident and 67% of such estimate per week for the next cleanup and its proportionate responsibility for such costs. 104 weeks. The amount and duration of extra expense We believe that the ultimate outcome of these matters could substantially exceed the insurance coverage. l (Toledo Edison) F-61 (Toledo Edison) l l l _
(6) Nuclear Fuel pany were $55 million and $i86 million, respectively (totaling $165 million after taxes), See Note 14. While Nuclear fuel is financed for the Company and Cleveland recovery of our other regulatory deferrals remains proba-Electric through leases with a special-purpose corpora- ble, our current assessment of business conditions has tion. The total amount of fmancing currently available prompted us to change our future plans. We decided that, under these lease arrangements is $382 million ($232 once the deferral of expenses and acceleration of benefits million from intermediate-term notes and $150 million under our Rate Stabilization Program are completed in from bank credit arrangements). Financing in an 1995, we should no longer plan to use regulatory ac-amount up to $750 million is permitted. The intermedi-counting measures to the extent we have in the past. ate-term notes mature in the period 1994-1997, with $75 million maturing in September 1994. At December 31, in October 1992, the P'UCO approved a Rate Stabiliza-1993,$154 million of nuclear fuel was financed for the tion Program that was designed to encourage economic Company. The Company and Cleveland Electric severally gmwth in the Company's sersice area by freezing the lease their respective portions of the nuclear fuel and are Company's base rates until 1996 and limiting subsequent ' obligated to pay for the fuel as it is consumed in a r te increases to specified annual amounts not to exceed reactor. The lease rates are based on various intermedi- $89 million over the 1996-1998 period. I ate-term note rates, bank rates and commercial paper As part of the Rate Stabilization Program, the Company rates. is allowed to defer and subsequently recover certain costs The amounts financed include nuclear fuel in the Davis- n t currently recovered in rates and to accelerate amor. Besse, Perry Unit I and Beaver Valley Unit 2 reactors tization of certain benefits. Such regulatory accounting with remaining lease payments for the Company of $52 measures pmvide for rate stabilization by rescheduling million, $29 million and $20 million, respectively, at the timing of rate recovery of certain costs and the December 31,1993. The nuclear fuel amounts financed amortization of certain benefits during the 1992-1995 l and capitalized also included interest charges incurred period. The continued use of these regulatory accounting by the lessors amounting to $6 million in both 1993 and measures will be dependent upon our continuing assess-1992 and $9 million in 1991. The estimated future lease ment and conclusion that there will be probable recovery amortization payments based on projected consumption f such deferrals in future rates. are $49 million in 1994,$42 million in 1995, $37 million The regulatory accounting measures we are eligible to in 1996, $33 million in 1997 and $30 million in 1998. record through December 31,1995 include the deferral of post-in-service interest carrying charges, depreciation ex-(7) Regulatory Matters pense and property taxes on assets placed in service after Phase-in deferrals were recorded beginning in 1989 pur- February 29,1988 and the deferral of operating ex-suant to the phase-in plan approved by the PUCO in a penses equivalent to an accumulated excess rent reserve January 1989 rate order for the Company. The phase-in for Beaver Valley Unit 2 (which resulted from the April plan was designed so that the projected resenues resulting 1992 refinancing of SLOBS as discussed in Note 2). The from the authorized rate increases and anticipated sales cost deferrals recorded in 1993 and 1992 pursuant to growth provided for the phase-in of certain nuclear costs these provisions were $39 million and $32 million, respec-over a ten-year period. The plan required the deferral of a tively. Amortization and recovery of these deferrals will portion of the operating expenses and both interest and occur over the average life of the related assets and the equity carrying charges on the Company's deferred rate- remaining lease period, or approximately 30 years, and i based investments in Perry Unit I and Beaver Valley will commence with future rate recognition. The regu-Unit 2 during the early years of the plan. The amortiza- latory accounting measures also provide for the acceler-tion and recovery of such deferrals were scheduled to be ated amortization of certain unrestricted excess deferred completed by 1998. tax and unrestricted investment tax credit balances and As we developed our strategic plan, we evaluated the interim spent fuel storage accrual balances for Davis-future recovery of our deferred charges and continued Besse. The total amount of such regulatory benefits recog-application of the regulatory accounting measures we nized in 1993 and 1992 pursuant to these provisions was follow pursuant to PUCO orders. We concluded that $18 million and $5 million, respectively. projected revenues would not provide for the recovery of The Rate Stabilization Program also authorized the Cora-the phase-in deferrals as scheduled because of economic pany to defer and subsequently recover the incremental and competitive pressures. Accordingly, we wrote off the expenses associated with the adoption of the accounting cumulative balance of the phase-in deferrals. The total standard for postretirement benefits other than pensions phase-in deferred operating expenses and carrying (SFAS 106). In 1993, we deferred $37 million pursuant charges written off at December 31,1993 by the Com- to this provision. Amortization and recovery of this (Toledo Edison) F-62 (Toledo Edison)
I deferral will commence prior to 1998 and is expected to rc alized by each company's participation in the consoli- ; be completed by no later than 2012. See Note 9(b). dated tax return, approximating a separate return result i for each company. (8) Federal Income tax in August 1993, the 1993 Tax Act was enacted. Retroac- 1 Federal income tax, computed by multiplying income tive to January 1,1993, the top marginal corporate i before taxes by the statutory rate (35% in 1993 and 34% income tax rate increased to 35%. The change in tax rate j in both 1992 and 1991), is reconciled to the amount of increased Accumulated Deferred Federal Income Taxes ; federal income tax recorded on the books as follows: for the future tax obligation by approximately $29 million. I l993 [9g g Since the PUCO has historically permitted recovery of l (millions of dollars) such taxes from customers when they become payable, l B Income (Loss) Hefore Federal Income
)g g the deferred charge, Amounts Due from Customers for Future Federal Income Taxes, also was increased by Tax (Credit) on Book Income (Loss) at Statutory Rate $(150) $ 36 $30 $29 million. The 1993 Tax Act is not expected to j te o r of e U it2 16 - -
@ era h m M b DefrENijn P ^" f "*
Rate Stabilization Program d (10) 5) (2) - 3 Under SFAS 109, temporary di1Terences and carryfir-wards resulted in deferred tax assets of $178 million cnd Sale and le seback transactions and deferred tax liabilities of $649 million at December 31, 5 5 5 Other items ' 4 J _- 1993 and deferred tax assets of $154 million and deferred Total Federal Income Tax Expec (Credit) __ 5(139) 1_M @ tax liabilities of $794 million at December 31,1992. These are summarized as follows: Federal income tax expense is recorded in the income December 31-Statement as follows: 1993 1992 1991 d.M l_99 ( IIII*"5 (millions of dollars) dollar. "I Operating Expenses: Property, plant and equipment $534 $656 Current Tax Provision 5 36 $ 26 $ 14 79 119 Deferred carrying charges and operating expenses Changes in Accumulated Deferred Federal income Tax: Net operating loss carryforwards (39) (56) Write-off of deferred operating expenses _ (13) - _ investment tax credits (55) (58) Accelerated depreciation and amortization. 35 7 9 Other _[43) _QJ) Alternative minimum tax credit (37) (13) (44) Net deferred tas liability $_4E 16_40 Retirement and postemployment benefits _ (20) - - Sale and leaseback transactions and For tax purpose 3, net operating loss (NOL) carryforwards d appdmateh M11 mMon am avah m reduce Tax s o he than federalincome taxes () future taxable income and will expire in 2003 through Rate Stabilization Program (1) 2 - Reacquired debt costs (1) 4 7 2005. The 35% tax etTect of the NOLs is $39 million. I l Deferred fuel costs - 1 (4) The Tax Reform Act of 1986 provides for an alternative Other items (7) (3) 10 Investment Tax Credits -
- _ 22 minimum tax (Ah1T) credit to be used to reduce the Total Expense (Credit) to Operating regular tax to the Ah1T level should the regular tax Expenses f lo) _H _.R exceed the Ah1T. AhiT credits of $77 million are availa-Nonoperating income: ble to otTset future regular tax. The credits may be Current Tax Provision (15) (20) (38) carried forward indefinitely.
Changes in Accumulated Deferred Fede*al Income Tax: Write-off of deferred carrying charges __. write-off of Perry Unit 2 (63) - (65) - (9) Retiiement and Disallowed nuclear costs 14 7 - Postemployment Benefits l Rate Stabilization Program 4 5 - AFUDC and carrying charges 5 9 9 (a) Rednmem Income 11an Net operating loss carr> forward (7) - 35 Prior to December 31,1993, the Company sponsored a 1 0*h*' I'* *' -W=~ noncontributory pension plan which covered all employee Total Expense (Credit) to Nonoperating Income _ut9) J J groups. The plan was merged with another plan which Total Federal Income Tax Expense (Credit) _ $11)_9) L34~ ~ ~L33 ~~ covered employees of Cleveland Electric and the Service Company into a single plan on December 31,1993. The The Company joins in the filing of a consolidated federal amount of retirement benefits generally depends upon the income tax return with its afIlliated companies. The length of service. Under certain circumstances, benefits method of tax allocation reflects the benefits and burdens can begin as early as age 55. The funding policy is to (Toledo Edison) F-63 (Toledo Edison) l 1
)
comply with the Employee Retirement income Security annual compensation increase assumption was 4.25%. At Act of 1974 guidelines. December 31,1992, the settlement rate and long-term rate of return on plan assets assumptions were 8.5% and In 1993, the Company offered the VTP, an early ret.ire-ment program. Operating expenses for 1993 m. eluded the long-term rate of annual compensation increase
$M m.lh.on i of pension plan accruals to cover enhanced assumption was 5%
- VTP benefits and an additional $3 million of pension costs Plan assets consist primarily of investments in common ,
l for VTP benefits paid to retirees from corporate funds. stock, bonds, guaranteed investment contracts, cash ; l The $3 million is not included in the pension data equivalent securities and real estate. reported below. A credit of $15 million resulting from a settlement of pension obligations through lump sum pay. (b) Other Postretirement Benefits l ments to almost all the VTP retirees partially ofTset the Centerior Energy sponsors jointly with its subsidiaries a i VTP expenses, postretirement benefit plan which provides all employee Net pension and VTP costs for 1991 through 1993 were groups certain health care, death and other portretirement comprised of the following components: benefits other than pensions. The plan is centributory, t993 g g with retiree contributions adjusted annually. The plan is (millions of dollars) not funded. A policy limiting the employer's contribu- I c cost for benefits earned during the on b rdree mehal mage b emphes rehg l period $5 5 5 5 5 after March 31,1993 was implemented in February 1993. ) interest cost on projected benefit obligation _ 11 11 11 l Actual return on plan asseh (15) (5) (30) The Company adopted SFAS 106, the accounting stan. Net an t n and deferral E) ._.1
, dard for postretirement benefits other than pensions, ef-VTP cost 59 - - fective January 1,1993. The standard requires the accrual settlement gain _ m) - --
of the expected costs of such benefits during the employ-Net costs _ LM $J $J _ ees' years of service. Previously, the costs of these ; benefits were expensed as paid, which is consistent with j The following table presents a reconciliation of the funded ratemaking practices. Such costs for the Company totaled i status of the Company's former plan at December 31, $4 million in both 1992 and 1991, which included medi-1992 with comparable information for a portion of the cal benefits of $3 million in both years. The total merged plan at December 31,1993. The December 31, amount accrued by the Company for SFAS 106 costs for 1993 benefit obligation estimates were derived from infor-1993 was $42 million, of which $1 million was capital-mation for the former plans. Plan assets of the merged ized and $41 mil' ion was expensed as other operation and plan were allocated based on a pro rata share of the maintenance expenses. In 1993, the Company deferred projected benefit obligation. incremental SFAS 106 expenses totaling $37 million l L92 L992 pursuant to a provision of the Rate Stabilization Pro-l U"$"s') r gram. See Note 7, i Actuarial present value of benefit obligations: Vested benefits $102 5 95 T.he components of the total postretirement benefit costs Nonvested benefits _JJ _ 12 for 1993 were as follows:
- Accumulated benefit obligation 113 107 Millions j Effect of future compensation levels _1_Q J of Dollars Total projected benefit obligation 129 142 Service cost for benefits earned $1 Plan assets at fair market value R R Interest cost on accumulated postretirement benefit Funded status (l1) 27 obligation 6 Unrecognized net gain from variance between Amortization of transition obligation at January 1,1993 of assumptions and experience (50) (33) $63 million over 20 years 3 Unrecognized prior service cost 4 5 VTP curtailment cost (includes $6 million transition Transition asset at January 1,1987 being amortized obligation adjustment) 22 over 19 years J) E) Total costs Net accrued pension liability included in Deferred 1Q Credits - Other in the Balance Sheet gg) ig These amounts included costs for the Company and a pro
"" #
- E*"
At December 31,1993, the settlement (discount) rate and long-term rate of return on plan assets assumptions The accumulated postretirement benefit obligation and were 7.25% and 8.75%, respe:tively. The long-term rate of accrued postretirement benefit cost at December 31,1993 (Toledo Edison) F-64 (Toledo Edison)
for the Company and its share of the Senice Company's At December 31,1993, the principal amount of the obligation are summarized as follows: mining company's loan and lease obligations guaranteed jjig by the Company was $20 million. Accumulated postretirement benefit obligation auribuiable = (l1) Capitalization Retired participants $(88) Other active plan participants _L9) (a) Capital Stock Transactions Accumulated postretirement benefit obligation (97) p Unrecogmzed net loss from variance between assumptions and experience 5 ended December 31,1993 are listed in the following table. Unamortized transition obligation _jL4 Accrued postretirement benefit cost _,_
-$Ql)
M 1222 l.2I (thousands of shares) The Balance Sheet classification of Other Noncurrent subject to Mandatory Redemption: Liabilities at December 31,1993 includes only the Com- $1* P*' 5 Q* g pany's accrued postretirement benefit cost of $33 million 25 pr 2.81 I! Loo) - - and excludes the Senice Company's portion since the Total L817) L42) 122) Service Company's total accrued cost is carried on its books. (b) Equity Distribution llestrictions At December 31,1993, the settlement rate and the long- Federallaw prohibits the Company from paying dividends term rate of annuai compensation increase assumptions out of capital accounts. However, the Company may pay were 7.25% and 4.25%, respectively. The assumed annual dividends out of appropriated retained earnings and health care cost trend rates (applicable to gross eligible current earnings. At December 31,1993, the Company charges) are 9.5% for medical and 8% for dental in 1994. had $42 million of appropriated retained earnings for the Both rates reduce gradually to a fixed rate of 4.75% in payment of preferred stock dividends. The Company is 1996 and later years. Elements of the obligation alTected currently prohibited from paying a common stock divi-by contribution caps are significantly less sensitive to dend by a provision in its mortgage, the health care cost trend rate than other elements. If the assumed health care cost trend rates were increased by (c) Preferred and Preference Stock 1% in each future year, the accumulated postretirement Amounts to be paid for preferred stock which must be benefit obligation as of December 31,1993 would in- redeemed during the next five years are $12 million in crease by $4 million and the aggregate of the service and each year 1994 through 1996 and $2 million in both 1997 interest cost components of the annual postretirement and 1998. I benefit cost would increase by $0.3 million. The annual preferred stock mandatory redemption provi-(c) Postemployment Benefits sions are as follows: Shares To Price in 1993, the Company adopted SFAS 112, the new Redeemed in sha're accounting standard which requires the accrual of post- $100 par $9.375 16,650 1985 $100 employment benefit costs. Postemployment benefits are 25 par 2.81 400,000 1993 25 the benefits provided to former or inactive employees after employment but before retirement, such as The annualized preferred dividend requirement at De-cember 31,1993 was $21 million. worker's compensation, disability benefits and severance pay. The adoption of this accounting method did not The preferred dividend rates on the Company's Series A materially affect the Company's 1993 results of operations and B (luctuate based on prevailing interest rates and or financial position. market conditions. The dividend rates for these issues averaged 7.41% and 8.22%, respectively, in 1993. (10) Guarantees Preference stock authorized for the Company is 5,000,000 shares with a $25 par value. No preference shares are The Company has guaranteed certain loan and lease currently outstanding. obligalms of a mmmg company under a long-term coal purchase arrangement. This arrangement requires pay- With respect to dividend and liquidation rights, the Com-ments to the mining company for any actual expenses pany's preferred stock is prior to its preference stock and (as advance payments for coal) when the mines are idle common stock, and its preference stock is prior to its for reasons beyond the control of the mining company. common stock. (Toledo Edison) F-65 (Toledo Edison) i _ - . _ - _ - _ _ - _ _ _ - . .. .. . . A
(d) lAng-Term Debt and Other mitments to provide theni with a s. :ond mortgage Borrowing Arrangements security interest on property of the Company and Cleve-Long-term debt, less current maturities, was as follows: land Electric and other considerations. We expect to Actual complete this process in the second quarter of 1994. We
',,A[,*gge will provide the same security interest to certain other
' creditors because their agreements require equal treat-pec$'n ber 31, December 31.
Year of Maturity 1993 1993 1992 ment. We expect to provide second mortgage collateral (millions of for $172 million of unsecured debt, $228 million of bank dollars) lemrs d cre@ and a W mMon moMng cree First mortgage bonds: 1997 6.125 % $ 31 $ 31 facility. The bank letters of credit and revolving credit 1998 10.00 1 1 facility are joint and several obligations of the Company 1999-2003 7.46 162 162 and Cleveland Electric. 2004-2008 7.88 145 145 2009-2013 2.50 31 31 2019-2023 7.06 215 215 585 585 (12) Short-Term Borrowing , Secured medium term notes due 8.44 250 182 Arrangements 1995-2021 in May 1993, Centerior Energy arranged for a $205 o s due 19951997 3 Debentures due 2002 8.70 135 135 million, three-year revolving credit facility. The facility Pollution control notes duc 1995- may be renewed twice for one-year periods at the option 20i5 12.02 105 105 of the participating banks. Centerior Energy and the Other - net - (2) (2) Se ce Company may borrow under the facility, with all Total Long-Term Debt iL225 11J.73 borrowings jointly and severally guaranteed by the Com-p ny nd Cleveland Electric. Centerior Energy plans to Long-term debt matures during the next five years as transfer any of its borrowed funds to the Company and follows: $45 million in 1994,$71 million in 1995,$91 Cleveland Electric, while the Service Company may ; million in 1996 and $39 million in both 1997 and 1998. borrow up to $25 million for its own use. The banks' fee is i The Company issued $275 million aggregate principal 0.5% per annum payable quarterly in addition to interest amount of secured medium-term notes during the 1991- on any borrowings. That fee is expected to increase to 1993 period. The notes are secured by first mortgage 0.625% when the facility agreement is amended as dis-bonds. cussed below. There were no borrowings under the facility The Company's mortgage constitutes a direct first lien on at December 31,1993. The facility agreement contains substantially all property owned and franchises held by covenants relating to capitalization and fixed charge j the Company. Excluded from the lien, among other coverage ratios for the Company, Cleveland Electric and things, are cash, securities, accounts receivable, fuel, Centerior Energy. The write-offs recorded at December supplies and automotive equipment. 31,1993 caused the ratios to fall below those covenant Certain unsecured loan agreements of the Company con. requirements. The revolving credit facility is expected to be available for borrowings after the facility agreement tain covenants relating to capitalization ratios, fixed is amended in the second quarter of 1994 to provide the charge coverage ratios and limitations on secured financ-p rticipating creditors with a second mortgage security ing other than through first mortgage bonds or certain nterest. other transactions. Two reimbursement agreements relat-ing to separate letters of credit issued in connection with Short-term borrowing capacity authorized by the PUCO the sale and leaseback of Beaver Valley Unit 2 contain annually is $150 million for the Company. The Company several financial covenants affecting the Company, Cleve- and Cleveland Electric are authorized by the PUCO to land Electric and Centerior Energy. Among these are borrow from each other on a short-term basis. covenants relating to fixed charge coverage ratios and capitalization ratios. The write-offs recorded at December At December 31,1993, the Company had no commercial 31,1993 caused the Company, Cleveland Electric and paper outstanding. The Company is unable to rely on the Centerior Energy to violate certain covenants contained sale of commercial paper to provide short-term funds in the two reimbursement agreements. The affected cred- because of its below investment grade commercial paper itors have waived those violations in exchange for com- credit ratings. (Toledo Edison) F-66 (Toledo Edison)
Earnings for the quarter ended December 31,1993 were (13) Financial Instruments' . decreased as a result of year-end adjustments for the Fair Value $232 million write off of Perry unit 2 (see Note 4(b)), The estimated fair values at December 31,1993 and 1992 the $241 million write-off of the phase-in deferrals (see of financial instruments that do not approximate their Note 7) and $19 million of other charges. These adjust-carrying amounts are as follows: ments decreased quarterly earnings by $345 million. DemmJrr 31. _ Earnings for the quarter ended September 30,1992 were 1993 1992 Carrying Fair Carrying Fair nereased by $15 million as a result of the recording of Amount Value Amount Valug deferred operating expenses and carrying charges for the (millions of dollars) first nine months of 1992 totaling $22 million under the Nuclear Plant Decommissioning Trusts Rate Stabilization Program approved by the PUCO in 5 26 5 27 s 20 $ 21 Preferred Stock, with Mandatory October 1992. See Note 7. Redemption Provisions . (including eurtent portion) 40 42 62 66 (15) Pending Merger of the C,ompany Long-Term Debt (including current portion) 1.271 1,314 1,225 1,221 with Cleveland Electric The fair value of the nuclear plant decommissioning trusts On March 25,1994, Centerior Energy announced that its is estimated based on the quoted market prices for the per ting utility subsidiaries, the Company and Cleve-investment securities. The fair value of the Company's I nd Electric, plan to merge into a single operating entity, preferred stock with mandatory redemption provisions Since the Company and Cleveland Electric afliliated in and long-term debt is estimated based on the quoted 1986, cfrorts have been made to consolidate operations market prices for the respective or similar issues or on the and administration as much as possible to achieve maxi-l basis of the discounted value of future cash flows. The mum cost savings. The merger of the two companies discounted value used current dividend or interest rates into a single entity is the completion of this consolidation (or other appropriate rates) for similar issues and loans Process. Various aspects of the merger are subject to the with the same remaining maturities. approval of the FERC, the PUCO and other regulatory authorities. The merger must be approved by share own-The estimated fair values of all other financial instru-ers of the Company's preferred stock Share owners of ments approximate their carrying amounts m the Balance Cleveland Electric's preferred stock must approve the Sheet at December 31,1993 and 1992 because of their authorization of additional shares of preferred stock, short-term nature. Share owners of the Company's preferred stock will exchange their shares for preferred stock shares of the (14) Quarterly Results of O PerationS successor corporatton having substantially the same (Unaudited) terms, while Cleveland Electric's preferred stock will automatically become shares of the successor corporation. The following is a tabulation of the unaudited quarterly Debt holders of the merging companies will become debt results of operations for the two years ended December holders of the successor corporation. The merging com-31,1993. g panies plan to seek preferred stock share owner approval March 3I, June 30, Sept, 30, Dec 31, in the summer of 1994. The merger is expected to be (millions of donars) effective in late 1994 1993 Operating Revenues $215 5210 5239 5 207 For the merging companies, the combined pro forma Operating Income (Loss) ~ 39 42 operating reveriucs ouc $2.475 billion, $2.439 billion and 17 (10) Net Income (Loss) 18 20 (5) (323)
$2.561 billion and the combined pro forma net income Earnings (Loss) Available (loss) was $(876) million, $276 million and $296 million for Common Stock 12 14 (10) (328) for the years ended December 31,1993,1992 and 1991, 1992 respectively. The pro forma data is based on accounting Operating Revenues $207 $202 $225 $ 210 for the merger on a method similar to a pooling of Operating Income 38 29 52 31 interests. The pro forma data is not necessarily indicative Net Income 11 4 36 20 of the results of operations which would have been for C mon s 5 (3) 30 14 reported had the merger been in effect during those years or which may be reported in the future. The pro forma Earnings for the quarter ended September 30,1993 were data should be read in conjunction with the audited decreased by $35 million as a result of the recording of financial statements of both the Company and Cleveland $54 million cf VTP pension-related oenefits. Electric.
(Toledo Edison) F-67 (Toledo Edison)
FIN ANCI AL AND STATISTICAL REVIEW Operating Revenues (millions of dollars) Steam Total Total Total lleatmg Operatmg Year Residential Commercial Industrial Other Retail Wholesale Electric & Gas H evenues 1993 $229 180 244 71 724 147 871 -
$871 1992 215 175 236 61 687 tS8 845 -- 845 1991 230 184 236 90 740 147 887 --
887 1990 224 175 236 78 713 f50 863 - 863 1939 216 164 227 99 706 160 866 -- 866 1983 161 105 170 42 478 21 499 9 508 Operating Expenses (millions of dollars) Other Deferred I ederal Fuel & Operation Depreciation Taxes. Operating income Total Purchased & & Other Than E xpenses, Taxes Operatmg Year Power Maintenance Amoruzation FIT Net (Credit ) Expenses 1993 $173 456(a) 76 91 (4)(b) (10) $782 1992 169 342 77 91 (17) 33 695 1991 178 356 72(c) 89 1 32 728 1990 174 373 73 79 (10) 21 710 1989 172 373 85 72 (16) 37 723 1933 125 115 51 45 - 57 393 income (Loss) (rnillions of dollars) Federal Income Other Deferred Income (Loss) Income & Carrying Taxes - Defore Operating AFU DC- Deductions, Charges, Credit Interest Year income Equity Net Net (Expense) Charges 1993 $ 89 1 (232)(d) (161)(b) 129 $(174) 1992 150 1 I 41 (1) 192 1991 159 1 5 22 (6) 181 9 213 l 1990 153 3 5 43 1989 143 9 20 82 (22) 232 1983 115 66 1 - 24 206 1 Income (Loss) (millions of dollars) l Larnmgs (Loss) Net Preferred Available fu l Debt AFUDC- Income Stock Common Year Interest Debt ( Lost) Dividends Stock 1993 $116 (1) (289) 23 $(312) I 1992 122 (1) 71 24 47 1991 132 (1) 50 25 25 1990 135 (3) 81 25 56 1989 145 (5) 92 25 67 1983 104 (26) 128 30 98 (a) includes early retirement progran e penses and other charges of $107 million in 1993. (b) Includes write-off of phase-in deferrals of $241 million in 1993, consisting of $55 million of deferred operating expenses and $186 million of deferred carrying charges. (c) In 1991, a change in accounting for nuclear plant depreciation was adopted, changing from the units-of-production method to the straight-line method at a 2.5% rate. l l (Toledo Edison) F-68 (Toledo Edison)
- . - . . . _ ~ . _ . . - .
1 s l I The Toledo Edison Company l Electric Sales (millions of KWH) Electric Customers (year end) Residential Usage , I Average Average Average Pnce Revenue Industrial KWil Per Per Per Year Residential Commercial Industrial Wholesale Other Total Residential Commercial & Other Total Customer KWH Customer 1993_ _ 2 039 1672 3 776 2 146 490 10 123 255 109 26 049 4 076 285 234 7 997 11.23c $897.65 l 1992 _ 1941 1 619 3 563 2 753 478 10 354 255 299 25 870 4 372 285 541 7 632 11.08 845.99 i 1991 _ 2 041 1683 3 543 2 587 482 10 336 254 500 26 044 4 444 284 988 7 990 11.26 897.41 1990 _ _ 1 950 1 614 3 617 2 333 496 10 010 253 965 25 822 4 555 284 342 7 692 11.48 882.99 l 1989 _ 2 017 1622 3 740 3 138 495 11 012 253 234 25 803 4 434 283 471 7 989 10.71 855.29 1983.__ 1915 1 341 3 127 476 428 7 287 242 959 23 694 3 864 270 517 7 900 8.44 665.43 Load (MW & %) Energy (millions of KWH) Fuel Operable Capacity Efficiency-at Time Peak Capacity Lead C mpany Gencruted Pwchased I uel Cod BTU Per Year of Peak Load Margin l~nctor F.msl N uclear Total Power Total Per KWit KWil 1993 1 874 1568 16.3% 64.3 % 5 548 4 791 10 339 196 10 535 1.42c 10 146 l 1992 1727 1 514 12.3 63.2 4 656 6 293 10 949 (82) 10 867 1.41 10 284 1991 1 758 1 510 14.1 64.5 4 848 6 003 10 851 95 10 946 1.44 10 327 1990 1 752 1 516 13.5 63.0 5 535 4 219 9 754 902 10 656 1.50 10 220 1989 1 894 1 526 19.4 65.2 5 206 5 552 10 758 788 11 546 1.42 10 293 1983 1777 1 325 25.4 65.6 4 683 2 383 7 066 749 7 815 1.67 10 337 investment (millions of dollars) Construction Work in Total Utility Accumulated Progress Nuclear Property. Utihty Plant in Depreciation & Net & Perry Fuel and Plant and Plant Total Year Service Amortization Plant Unit 2 Other Equipment Additions Assets 1993 $2 837 788 2 049 40 142 $2 231 $ 43 $3 510 1992 2 847 760 2 087 280 164 2 531 44 3 939 1991 2 692 709 I983 308 198 2 489 54 3 926 1990 2 604 640 1964 349 224 2 537 87 3 913 1989 2 528 565 1 963 342 237 2 542 73 4 051 1983 1342 325 1 017 1 094 164(e) 2 275 294 2 501 Capitalization (millions of dollars & %) ) Preferred Stock, Preferred Stock. with Mandatory without Mandatory Year Common Stock Equiry Redemption Provisions Redemption Provisions Long-Term Debt Total 1993 $623 30% 28 1% 210 10% 1 225 59% $2 086 1992 935 39 50 2 210 9 1 178 50 2 373 1991 888 38 64 3 210 9 1158 50 2 320 1990 881 39 66 3 210 9 1 097 49 2 254 1989 898 38 69 3 210 9 1 197 50 2 374 1983 716 36 94 5 200 10 985 49 1995 (d) Includes write-otT of Perry Unit 2 of $232 rnillion in 1993. (c) Restated for effects of capitalization of nuclear fuel lease and financing arrangements pursuant to Ststement of Financial Accounting Standards 71. l (Toledo Edison) F-69 (Toledo Edison)
l l INDEX TO SCHEDULES Page Centerior Energy Corporation and Subsidiaries: Schedule V Property, Plant and Equipment for the Years S-2 Ended December 31, 1993, 1992 and 1991 Schedule VI Accumulated Depreciation and Amortization of S-5 l j Property, Plant and Equipment for the Years i I Ended December 31, 1993, 1992 and 1991 l S-8 Schedule VII Guarantees of Securities of Other Issuers for the Year Ended December 31, 1993 Schedule VIII Valuation and Qualifying Accounts for the S-9 i ! Years Ended December 31, 1993, 1992 and 1991 Schedule IX Short-Term Borrowings for the Years Ended S-10 l December 31, 1993, 1992 and 1991 ! Schedule X Supplementary Income Statement Information for S-11 the Years Ended December 31, 1993, 1992 and 1991 ( The Cleveland Electric Illuminating Company and Subsidiaries: l l Schedule V Property, Plant and Equipment for the Years S-12 Ended December 31, 1993, 1992 and 1991 Schedule VI Accumulated Depreciation and Amortization of S-15 l Property, Plant and Equipment for the Years Ended December 31, 1993, 1992 and 1991 l Schedule VII Guarantees of Securities of Other Issuers for S-18 the Year Ended December 31, 1993 Schedule VIII Valuation and Qualifying Accounts for the S-19 Years Ended December 31, 1993, 1992 and 1991 Schedule IX Short-Term Borrowings for the Years Ended S-20 December 31, 1993, 1992 and 1991 Schedule X Supplementary Income Statement Information for S-21 the Years Ended December 31, 1993, 1992 and 1991 The Toledo Edison Company: Schedule V Property, Plant and Equipment for the Years S-22 Ended December 31, 1993, 1992 and 1991 Schedule VI Accumulated Depreciation and Amortization of S-25 Property, Plant and Equipment for the Years Ended December 31, 1993, 1992 and 1991 Schedule VII Guarantees of Securities of Other Issuers for S-28 the Year Ended December 31, 1993 Schedule VIII Valuation and Qualifying Accounts for the S-29 Years Ended December 31, 1993, 1992 and 1991 Schedule IX Short-Term Borrowings for the Years Ended S-30 December 31, 1993, 1992 and 1991 l Schedule X Supplementary Income Statement Information for S-31 the Years Ended December 31, 1993, 1992 and 1991 Schedules other than those listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the financial statements or notes thereto. S-1 l l \
CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars) Balance at Retirements Balance at i Beginning of Additions or End of Classification Period at Cost Sales Other Period Utility Plant (Electric): Intangible $35,040 ($72) 50 50 534,968 Production: Steam 1,401,660 53,173 (5,251) (44,745)(a) 1,404,837 Nuc lear 5,648,748 35,382 (17,782) 0 5,666,348 Hydraulic 59,857 4,335 (1) 0 64,191 Other 14,750 33 (10) 0 14,773 Transmission 736,331 27,952 (1,625) 1,010 (a) 763,668 Distribution 1,330,851 73,245 (6,731) 0 1,397,365 General 221,763 4,062 (852) 1 224,974 Total Utility Plant 9,449,000 198,110 (32,252) (43,734) 9,571,124 Perry Unit 2 (b) 826,674 (31,436) 0 (795,238)(c) O Construction Work in Progress 167,139 26,082 (72) (12,218)(a) 180,931 Nuclear Fuel 1,038,327 45,823 0 0 1,084,150 Other Property 47,343 51 (18) 55,953 (a) 103,329
............ ............ ............ ............ ............ l l
Total Property, Plant and , i Equipment $11,528,483 5238,630 (532,342) ($795,237) 510,939,534
============ ~sessss====== =====s====== ============ ============
(a) Transfer of Acme Plant Unit 2 to future use and nonutility property and reclassification of future use property. (b) Includes Perry Unit 2 AFUDC. See Schedule Vill, (c) Write-off of Perry Unit 2 investment. S2
CENTER 10R ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE V - PROPERTY, PLAWT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1992 (Thousands of Dollars) Balance at Retirements Balance at Beginning of Additions or End of Period at Cost Sales Other Period Classification Utility Plant (Electric):
$34,774 $266 SO SO $35,040 Intangible Producti on:
1,413,761 45,619 (72,212) 14,492 (a) 1,401,660 Steam Nuclear 5,227,393 78,403 (12,128) 355,080 (a) 5,648,748 Hydraulic 55,427 5,024 (594) 0 59,857 14,750 0 0 0 14,750 Other Transmission 710,217 19,467 (1,051) 7,698 (a) 736,331 Distribution 1,233,176 99,503 (3,948) 2,120 (a) 1,330,851 General 198,721 24,809 (1,767) 0 221,763 Total Utility Plant 8,888,219 273,091 (91,700) 379,390 9,449,000 Perry Unit 2 (b) 850,573 (23,899) 0 0 826,674 Construction Work in Progress 215,855 (48,434) (282) 0 167,139 Nuclear Fuel 985,781 52,546 0 0 1,038,327 other Property 64,763 (671) (16,749) 0 47,343 Total Property, Plant and Equipment $11,005,191 $252,633 ($108,731) $379,390 $11,528,483
........e=== ............ ............ ............ ............
(a) Results from adoption of SFAS 109 in 1992, which requires the presentation of emounts on a pre-tax basis. Such amounts were previously stated on a net-of-tax basis. (b) Includes Perry Unit 2 AFU0C. See Schedule Vill. S-3
CENTER 10R ENERGY CORPORAfl0N AND SUBS! DIARIES SCHEDULE V PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1991 (Thousands of Dollars) Balance at Retirements Balance at Beginning of Additions or End of Classification Period at Cost Sales Other Period Utility Plant (Electric): Intangible $22,035 $12,739 $0 $0 $34,774 Production: Steam 1,338,332 80,909 (5,480) 0 1,413,761 Nuclear 5,123,492 105,296 (1,395) 0 5,227,393 Hydraulle 56,354 (557) (370) 0 55,427 Other 14,693 48 9 0 14,750 Transmission 694,181 16,667 (631) 0 710,217 Distribution 1,199,941 37,674 (4,439) 0 1,233,176 General 187,191 18,174 (6,644) 0 198,721 Total utility Plant 8,636,219 270,950 (18,950) 0 8,888,219 Perry Unit 2 (a) 865,149 (14,576) 0 0 850,573 Construction Work in Progress 268,386 (52,531) 0 0 215,855 Nuclear Fuel 927,268 58,513 0 0 985,781 Other Property 63,524 1,254 (15) 0 64,763 Total Property, Plant and Equipnent $10,760,546 5263,610 ($18,965) $0 $11,005,191 333333333333 E33323333333 33333#333333 333333333333 E33333333333 l l (a) Includes Perry Unit 2 AFUDC. See Schedule VIII.
)
l S4 l l l l l l
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CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE VI ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars) Additions Deduc t ions Balance at Charged to Removal Cost Balance at Beginning of Income Net of Salvage End of Description Period Statement Other Retirements Add /(Deduct) Period Utility Plant: Electric - Depreciation $2,466,961 $276,251 ($47,780)(a)(b) ($32,095) ($14,782) $2,648,555
- Amu. G 3. u on 21,476 7,337 0 0 0 28,813 Total Utility Plant 2,488,437 283,588 (c) (47,780) (32,095) (14,782) 2,677,368 Other Property - Depreciation 8,166 1,480 (d) 52,875 (b) 0 0 62,521 Total $2,496,603 $285,068 $5,095 ($32,095) ($14,782) $2,739,889 33=333333333 333333333333 333333333333 333333333333 333333233333 333333333333 Nuclear Fuct - Amortization $653,776 $85,732 (e) $0 $0 $0 $739,508 g
33333'43333=3 333333333333 333333333333 333333333333 3=3333333333 333333333333 (a) Includes nuclear plant decommissioning trust earnings charged to the trust accounts and depreciation charged to construction work in progress. (b) Transfer of acetsnulated depreciation for Acne Plant Unit 2 and reclassification of accumulated depreciation for future use property. (c) Depreciation and amortization, as reported in the income Statement, includes approximately $27 million of amortization of investnent tax credits. (d) Nonutility plant expense charged to other income and deductions, net. (e) Charged to fuel and purchased power expense. S-5 ( -.
CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORT!ZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1992 (Thousands of Dollars) Additions Deductions
............................ .s........... ................
Balance at Charged to Removal Cost Balance at Beginning of Income Net of Salvage End of Description Period Statement Other Retirements Add /(Deduct) Period w Utility Plant: Electric - Depreciation 52,260,186 $261,943 552,593 (a) ($91,982) ($15,779) $2,466,961
- Amortization 14,303 7,1 73 0 0 0 21,476 Total Utility Plant 2,274,489 269,116 (b) 52,593 (91,982) (15,779) 2,488,437 Other Property - Depreciation 20,250 2,049 (c) 0 (14,129) (4) 8,166 Total 52,294,739 $271,165 $52,593 ($106,111) ($15,783) 52,496,603 sassazzasssa sassassassas ssasssssssas asssssssssas sassassasssa sssssssssssa l
Nuclear Fuel - Amortization $527,367 5126,409 (d) 50 $0 $0 $653,776 assassassssa sasssssssssa ssssssssssas massassenssa sessassassas sassssssssas (a) Includes adjustment resulting from adoption of SFAS 109 in 1992 ($48.1 million), nuclear plant decommissioning trust earnings charged to the trust accounts, 7d depreciation charged to construction work in progress. (b) Depreciation and amortization, as reported in the Income Statement, includes approximately $13 million of amortization of investment tax credits. (c) Nonutility plant expense charged to other income and deductions, net. (d) Charged to fuel and purchased power expense. 1 1 i 1 i l I S-6
l
)
i CENTERIDR ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE VI ACCUMULATED DEPRECIATION AND AMORT!ZATION OF PROPERTY, PLANT AND EQUIPMENT . YEAR ENDED DECEMBER 31, 1992 4 (Thousands of Dollars) i Additions Deductions
............................ .............................. )
Balance at Charged to Removal Cost Balance at Beginning of Income Net of Salvage End of Description Period Statement Other Retirements Add /(Deduct) Period Utility Plant: Electric - Depreciation 52,260,186 $261,943 $52,593 (a) (S91,982) ($15,779) $2,466,961
- Amortization 14,303 7,173 0 0 0 21,476 Total Utility Plant 2,274,489 269,116 (b) 52,593 (91,982) (15,779) 2,488,437 Other Property - Depreciation 20,250 2,049 (c) 0 (14,129) (4) 8,166 Total 52,294,739 $271,165 $52,593 ($106,111) ($15,783) 52,496,603 EEEEEEEEEEEE EE333E333333 233333333333 E333333333E2 EEEEEEEEEEEE 333333333333 Nuclear Fuel - Amortization $527,367 5126,409 (d) 50 50 50 5653,776 EEEEEEEEEEEE E33333333333 E33333E32222 333333333333 EEEEEEEEEEEE BEEEEEEEEEEE (a) Includes adjustment resulting from adoption of SFAS 109 in 1992 ($48.1 million), nuclear plant decommissioning trust earnings charged to the trust accounts, and depreciation charged to construction work in progress.
(b) Depreciation and amortization, as reported in the income Statement, includes approximately $13 million of amortization of investment tax credits. (c) Nonutility plant expense charged to other incone and deductions, net. (d) Charged to fuel and purchased power expense. l S-6
..l CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1991 (Thousands of Dollars)
Additions Deductions Balance at Charged to Removal Cost Balance at Beginning of Income Net of Salvage End of Description Period Statement Other Retirements Add /(Deduct) Period Utility Plant: Electric - Depreciation 52,030,437 5248,231 $3,555 (a)(b) (518,950) ($3,087) 52,260,186
- Ame-ti??' inn 8,0 73 5,679 551 (b) 0 0 14,303 Total Utility Plant 2,038,510 253,910 (c) 4,106 (18,950) (3,087) 2,274,489 Other Property - Depreciation 18,072 2,178 (d) 0 0 0 20,250 l
i Total $2,056,582 5256,088 $4,106 ($18,950) ($3,087) $2,294,739 I ............ ............ ............ ............ .....=...... ............ l l Nuclear Fuel - Amortization 1404,596 $122,771 (e) 50 $0 - 50 $527,367 l ............ ............ ............ ............ ............ ............ 1 l l l (a) Includes nuclear plant decommissioning trust earnings charged to the trust accounts and depreciation charged to construction work in progress. l (b) Transfer from accumulated depreciation to accumulated amortization. (c) Depreciation and amortization, as reported in the Income Statement, includes approximately $11 million of amortization of investment tax credits. (d)5 Jtility plBnt expense Charged to other income and deductions, net. (e) Charged to fuel and purchased power expense. l 1 i S7 l
f CENTESIOR ENERGY C03PORATIDN AND SUBSIDIARIES SCHEDULE VII - GUARANTEES OF SECURITIES OF OTHER ISSUERS TEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars) Principal Amount Name of Issuer of Guaranteed and Securities Guaranteed Title of Issue (a) Outstanding (a) Nature of Guarantee Quarto Mining Company (b) Guaranteed Mortgage Bonds, I due 2000 Series A 8.25% $821 Principal and Interest Series B 9.70% 801 Principal and Interest Series C 9.40% 4,007 Principal and Interest Series EA 10.25% 954 Principal and Interest Series FA 10.50% 731 Principal and Interest Series G 9.05% 12,098 Principal and Interest series HA 7.75% 9,308 Principal and Interest Series HB 8.31% 5,395 Principal and Interest Guaranteed Refunding Bonds, Series I, 7.45%, due 1997 7,381 Principal and Interest Unsecured Note, interest at prime (6% effective 7/1/93 and applicable through 12/31/93) plus 2%, due 2000 2,849 Principal and Interest Equipment leases 8,557 Termination value per Agreements 52,902 The Ohio Valley Coal Company First Mortgage Notes, Series D, 8.00%, due 1994 to 1997 5,200 Principal and Interest Series E, 10.25%, due 1994 to 1997 2,310 Principal and Interest Equipnert leases 4,129 Stipulated Loss Value per Agreements Term Notes, 9.53%, due 1994 to 1996 1,525 Principal and Interest 10.85%, due 1994 to 1997 13,952 Principal and Interest 27,116 580,018 33333333 (a) None of the securities were owned by the Operating Companies; none were held in the treasury of the issuer; and none were in default. (b) The Operating Companies and the other CAPCO Group Companies have agreed to guarantee severally, and not jointly, their proportionate shares of Quarto Mining Company debt and lease obligations incurred while developing and equippin0 the mines. The amounts shown are , the Operating Companies' proportionate share of the total obligations. S-8
1 I I CENTER 10R ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE Vill - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (Thousands of Dollars) Additions Deductions Dalance at Charged to Deductions Balance at Beginning Income from End of l Description of Period Statement Other Reserves Other Period Reflected as Reductions to the Related Assets: Accumulated Provision ' for Uncollectible Accounts l (Deduction from Amounts Due from Customers and Others) 1993 $3,723 $14,139 (a) $3,516 (b) $17,675 (a)(c) 50 $3,703 l 1992 3,703 19,673 (a) 2,376 (b) 22,029 (a)(c) 0 3,723 1991 3,026 20,567 (a) 3,192 (b) 23,082 (a)(c) 0 3,703 1 I Reserve for Perry Unit 2 l Allowance for Funds used During Construction (Deduction from Perry Unit 2) l 1993 $212,693 SO SO $212,693 (d) $0 $0 l 1992 212,693 0 0 0 0 212,693 1991 212,693 0 0 0 0 212,693 (a) Includes a provision and corresponding write off of uncollectible accounts of $4,550,000, $5,968,000 and 56,020,000 in 1993, 1992 and 1991, respectively, relating to customers which qualify for the PUC0 mandated Percentage of income Payment Plan (PIPP). Such uncollectible accounts are recovered through a separate PUC0 approved surcharge tariff. (b) Includes amounts for collection of accounts previously written off and deferral of PIPP uncollectibles in excess of the amounts included in the last base rate cases. The amounts deferred for future recovery were
$971,000 and $37,000 in 1993 and 1992, respectively.
(c) Uncollectible accounts written off. (d) Write-off of Perry Unit 2 investment. S-9
CENTER 10R ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE IX - SHORT-TERM BORROWINGS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (Thousands of Dollars) Average Weighted Daily Average Average Maximum Weighted Daily Balance Interest Amount Amount Weighted at End Rate at Outstanding Outstanding Interest of End of During the During the Rate During Category Period Period Period Period the Period Commercial Paper 1993 50 0.0% $36,900 52,688 (a) 4.1% (b) 1992 0 0.0 101,800 16,823 (a) 4.5 (b) 1991 0 0.0 170,900 61,781 (a) 7.4 (b) Uncommitted Financing Facility 1993 $0 0.0% $80,001 $19,710 (a) 3.8% (b) 1992 49,502 4.4 80,003 38,952 (a) 4.1 (b) Not applicable for 1991. (a) Computed by dividing the total of the daily outstanding balances for the year by 365 days (366 for 1992). (b) Computed by dividing total interest expense for the year by the average daily balance outstanding. l S-10 m . _
CENTER 10R ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (Thousands of Dollars) Item 1993 1992 1991 Maintenance and Repairs Charged to Operating Expenses $174,332 $184,183 $174,121 333333323333 333333333333 333333333333 Taxes, Other Than Payroll and Inec.Tc Taxcs: Charged to Operating Expense;* Real and Personal Property Taxes $170,346 $171,603 $163,123 Ohio State Excise Taxes 109,865 111,316 106,672 Other 9,371 11,452 11,883 Total Charged to Operating Expenses 289,582 294,371 281,678 Total Charged to Nonoperating income 622 129 684 Total $290,204 $294,500 $282,362 333333333333 333333333333 343333333333 S-11 I
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDI ARIES SCHEDULE V PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars) l i Balance at Retirements Balance at J Beginning of Additions or End of Classification Peri od at Cost Sales Other Period I Utility Plant (Electric): Intangible $22,647 ($21) $0 $0 $22,626 Production: Steam 1,121,056 50,631 (4,177) 0 1,167,510 Nuclear 3,737,103 19,314 (11,474) 0 3,744,943 Hydraulic 59,857 4,335 (1) 0 64,191 Other 8,075 0 0 0 8,075 Transmission 584,813 23,935 (1,038) 0 607,710 Distribution 923,022 52,425 (5,797) 0 969,650 General 145,223 4,983 (781) 0 149,425 Total Utility Plant 6,601,796 155,602 (23,268) 0 6,734,130 Perry Unit 2 (a) 495,296 (20,361) 0 (474,935)(b) O Construction Work in Progress 130,327 21,783 (72) (10,616)(c) 141,422 Nuclear Fuel 582,380 26,053 0 0 608,433 Other Property 43,260 50 (18) 10,616 (c) 53,908 Total Property, Plant and Equipment $7,853,059 $183,127 ($23,358) ($474,935) $7,537,893 333E23333333 E33333333333 333333333333 EEEEEEEEEEEE E33333333333 (a) includes Perry Unit 2 AFUDC. See Schedule VI!!. (b) Write off of Perry Unit 2 investment. (c) Reclassification of future use property. S-12
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1992 (Thousands of Dollars) Balance at Retirements Balance at Beginning of Additions or End of Classification Period at Cost Sales Other Period Utility Plant (Electric): Intangible $22,462 5185 50 50 $22,647 Production: Stee: 1,104,815 38,830 (35,012) 12,423 (a) 1,121,056 Nuclear 3,461,108 51,556 (6,298) 230,737 (a) 3,737,103 Hydraulic 55,427 5,024 (594) 0 59,857 Other 8,0 75 0 0 0 8,075 Transmission 561,188 17,597 (1,028) 7,056 (a) 584,813 Distri bution 857,392 66,747 (3,038) 1,921 (a) 923,022 General 125,478 20,512 (767) 0 145,223 Total Utility Plant 6,195,945 200,451 (46,737) 252,137 6,601,796 Perry Unit 2 (b) 507,806 (12,510) 0 0 495,296 Construction Work in Progress 161,890 (31,281) (282) 0 130,327 Nuclear Fuel 551,934 30,446 0 0 582,380 Other Property 60,667 (688) (16,719) 0 43,260 Tctal Property, Plant and Equipment $7,478,242 5186,418 (563,738) 1252,137 $7,853,059 333E33333333 833333333333 E33333333333 E33333333333 EEEEEEEEEEEE (a) Results from adoption of SFAS 109 in 1992, which requires the presentation of amounts on a pre-tax basis. Such amounts were previously stated on a net-of-tax basis. (b) Includes Perry Unit 2 AFUDC. See Schedule Vill. S 13
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES , SCHEDULE V - PROPERTY, PLANT'AND EQUIPMENT YEAR ENDED DECEMBER 31, 1991 (Thousands of' Dollars) Balance at Retirements Balance at Beginning of Additions or End of Classification Period at Cost Sales Other Period Utility Plant (Electric): Intangible S18,499 53,963 SO $0 $22,462 Produet!cr.: Steam 1,046,921 63,374 (5,480) 0 1,104,815 Nuclear 3,405,230 56,601 (723) 0 3,461,108 Hydraulic 56,354 (557) (370) 0 55,427 other 7,967 99 9 0 8,075 Transmission 547,300 14,518 (630) 0 561,188 Distribution 833,153 27,823 (3,584) 0 857,392 General 116,912 11,184 (2,618) 0 125,478 Total Utility Plant 6,032,336 177,005 (13,396) 0 6,195,945 Perry Unit 2 (a) 521,464 (13,658) 0 0 507,806 Construction Work in Progress 175,232 (13,342) 0 0 161,890 Nuclear Fuel 520,762 31,172 0 0 551,934 Other Property 60,221 461 (15) 0 60,667 Total Property, Plant and , Equipnent $7,310,015 5181,638 ($13,411) $0 57,478,242 E33333333333 333333353133 5253323W3333 3333333353E3 3E853333E353 (a) Includes Perry Unit 2 AFUDC. See Schedule Vill. f S-14 i
i 1 1 1 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES ) SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars) Additions Deductions Balance at Charged to Removal Cost Balance at Beginning of Income Net of Salvage End of Description Period Statement Other Retirements Add /(Deduct) Period Utility Plant: ( Electric Depreciation $1,711,620 $193,085 ($1,762)(a)(b) ($23,111) ($11,456) $1,868,376
- Amurtization 16,496 4,712 0 0 0 21,208 i I
Total Utility Plant 1,728,116 197,797 (c) (1,762) (23,111) (11,456) 1,889,584 Other Property - Depreciation 6,694 1,409 (d) 4,764 (b) 0 0 12,867 Total $1,734,810 $199,206 $3,002 ($23,111) ($11,456) $1,902,451 I ssssssssssas massassassas asasssssssas assssssssmas assassssssas assas=== sass i Nuclear Fuel - Amortization $358,B61 $47,372 (e) $0 $0 $0 $406,233 l sussssazzssa assassanssas assassssazza sassassassas essassammass n=ss=sssssse (a) Includes nuclear plant decommissioning trust earnings charged to the trust accounts and depreciation charged to construction work in progress. (b) Reclassification of accumulated depreciation for future use property. (c) Depreciation and amortization, as reported in the Income Statement, includes approximately $17 million of j amortization of investment tax credits. (d) Nonutility plant expense charged to other income and deductions, net. (e) Charged to fuel and purchased power expense. I l 1 I S-15
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES SCHEDULE VI ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1992 (Thousands of Dollars) Additions Deductions Balance at Chstged to Removal Cost Balance at l Beginning of Income Net of Salvage End of Description Period Statement Other Retirements Add /(Deduct) Period Utility Plant: Electric - Depreciation $1,552,870 $182,706 $34,385 (a) ($47,019) ($11,322) $1,711,620
- Amortization 12,114 4,382 0 0 0 16,496 Total Utility Plant 1,564,984 187,088 (b) 34,385 (47,019) (11,322) 1,728,116 Other Property - Depreciation 18,833 1,960 (c) 0 (14,099) 0 6,694 Total $1,583,817 $189,048 $34,385 ($61,118) ($11,322) $1,734,810 ERESEEEEEEEE BEEEEEESEEEE 333333333333 EEEEEEEEEEEE BEEEEEEEEEEE ESSEEEEEEEEE Nuclear Fuel - Amortization $288,805 $70,056 (d) $0 $0 $0 $358,861 555533333333 EEEEEEEEEEEE E33333333553 333333333355 333333323335 333333333333 (a) Includes adjustment resulting f rom adoption of SFAS 109 in 1992 ($31.5 million), nuclear plant decommissioning trust earnings charged to the trust accounts, and depreciation charged to construction work in progress.
(b) Depreciation and amortization, as reported in the Income Statement, includes approximately $8 million of amortization of investment tax credits. (c) Nonutility plant expense charged to other incone and deductions, net. (d) Charged to fuel and purchased power expense. 1 S-16 1 l
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPFRTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1991 l l l (Thousands of DolLars) l l l t Additions Deductions I Balance at Charged to Removal Cost Balance at Beginning of Income Net of Salvage End of Description Period Statement Other Retirements Add /(Deduct) Peri od 1 i utility Plant: I i l Electric . Depreciation $1,391,080 $173,126 $1,794 (a)(b) ($13,396) $266 $1,552,870
- Amortization 7,1 78 4,385 551 (b) 0 0 12,114 Total Utility Plant 1,398,258 177,511 (c) 2,345 (13,396) 266 1,564,984 l
l Other Property - Depreciation 16,793 2,040 (d) 0 0 0 18,833 ! Total $1,415,051 $179,551 $2,345 ($13,396) $266 $1,583,817 j ==ss===ssses as====s== sus zusanassness ss=======. . ..........z. .. 33 ...... Nuclear Fuel - Amortization $219,938 $68,867 (e) $0 $0 SO $288,805 R33333333335 333513333333 533323333333 533353238833 E33332532323 R33333333322 I (a) Includes nuclear plant decommissioning trust earnings charged to the trust accounts and depreciation charged to construction work in progress.
]
(b) Transfer from accumulated depreciation to accumulated amortization. l (c) Depreciation and amortization, as reported ,n the income Statement, includes approximately $7 million of amortization of investment tax credits. (d) Nonutility plant expense charged to other income and deductions, net. (e) Charged to fuel and purchased power expense. S 17 L s
i THE CLEVELAND ELECTRIC ILLUMINATING CCIPANY AND SUBSIDIARIES SCHEDULE VII - GUARANTEES OF SECURITIES OF OTHER ISSUERS YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars) Principal Amount Name of Issuer of Guaranteed and Securities Guaranteed Title of Issue (a) Outstanding (a) Nature of Guarantee Quarto Mining Company (b) Guaranteed Mortgage Bonds, due 2000 Series A 8.25% S550 Principal and Interest Series B 9.70% 537 Principal and Interest Series C 9.40% 2,684 Principal and Interest Series EA 10.25% 596 Principal and Interest Series FA 10.50% 457 Principal and Interest Series G 9.05% 7,448 Principal and Interest Series HA 7.75% 5,730 Principal and Interest Series HB 8.31% 3,321 Principal and Interest Guaranteed Refunding Bonds, series I, 7.45%, due 1997 4,544 Principal and Interest Unsecured Note, interest at prime (6% effective 7/1/93 and applicable through 12/31/93) plus 2%, due 2000 1,781 Principal and Interest Equipment leases 5,732 Termination value per Agreements 33,380 The Ohio Valley Coal Company First Mortgage Notes, Series D, 8.00%, due 1994 to 1997 5,200 Principal and Interest Series E, 10.25%, due 1994 to 1997 2,310 Principal and Interest Equipment Leases 4,129 Stipulated Loss Value per Agreements Term Notes, 9.53%, due 1994 to 1996 1,525 Principal and Interest 10.85%, due 1994 to 1997 13,952 Principal and Interest 27,116
$60,496
========
(a) None of the securities were owned by Cleveland Electric; none were held in the treasury of the issuer; and none were in default. (b) Cleveland Electric and the other CAPCO Group Canpanies have agreed to guarantee severally, and not jointly, their proportionate shares of Quarto Mining Company debt and lease obligations incurred while developing and equipping the mines. The amounts shown are Cleveland Electric's proportionate share of the total obligations. S 18
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES SCHEDULE VIII . VALUAT]ON AND QUALIFY]NG ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (Thousands of Dollars) Additions Deductions l Balance at Charged to Deductions Balance at i Beginning Income from End of Description of Period Statement other Reserves Other Period Reflected as Reductions l to the Related Assets: Acc mulated Provision for Uncollectible Accounts (Deduction from Amounts Due from Customers and Others) l l 1993 $2,333 59,280 (a) $1,813 (b) 511,113 (a)(c) 50 $2,313 1 1992 2,313 16,359 (a) 1,309 (b) 17,648 (a)(c) 0 2,333 l . 1991 1,826 15,669 (a) 1,686 (b) 16,868 (a)(c) 0 2,313 i Reserve for Perry Unit 2 i Allowance for Funds Used During Construction (Deduction from Perry Unit ?) h 1993 $124,398 50 $0 $124,398 (d) 50 50 1992 124,398 0 0 0 0 124,398 1991 124,398 0 0 0 0 124,398 (a) Includes a provision and corresponding write-off of uncollectible accounts of $2,447,000, $5,269,000 and
$5,616,000 in 1993,1992 and 1991, respectively, relating to customers which qualify for the PUC0 mandated Percentage of Income Payment Plan (PIPP). Such uncollectible accounts are recovered through a separate PUC0 approved surcharge tariff.
(b) Includes amounts for collection of accounts previously written off and deferral of PIPP uncollectibles in ~ excess of the amount included in the last base rate case. The amount deferred for future recovery was
$507,000 in 1993.
(c) Uncollectible accounts written off. (d) Write off of Perry Unit 2 investment. S.19
I 1 THE CLEVELAND ELECTRIC ILLUMINATINO COMPANY AND SUBSIDIARIES l l SCHEDULE IX - SHDRT-TERM BORROWINGS l FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 i I 1 (Thousands of Dollars) j l Average Weighted Daily Average l Average Maximum Weighted Daily Balance Interest Amount Amount Weighted at End Rate at Outstanding Outstanding Interest of End of During the During the Rate During Category Period Period Period Period the Period Connercial Paper 1993 50 0.0% $36,900 52,688 (a) 4.1% (b) 1992 0 0.0 75,000 9,473 (a) 4.3 (b) 1991 0 0.0 133,100 45,825 (a) 7.5 (b) Uncommitted Financing Facility 1993 50 0.0% $40,001 58,303 (a) 3.6% (b) 1992 10,000 4.3 40,001 17,180 (a) 4.1 (b) Not applicable for 1991. (a) Computed by dividing the total of the daily outstanding balances for the year by 365 days (366 for 1992). (b) Computed by dividing total interest expense for the year by the average daily balance outstanding. S 20
1 i i THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES SCHEDULE IX - SHORT 1ERM BORROW!YGS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 l (Thousands of Dollars) Average Weighted Daily Average Average Maximum Weighted Daily Balance Interest Amount Amount Weighted at End Rate at Outstanding Outstanding Interest of End of During the During the Rate During Category Period Period Period Period the Period Commercial Paper 1993 $0 0.0% S36,900 $2,688 (a) 4.1% (b) 1992 0 0.0 75,000 9,473 (a) 4.3 (b) 1991 0 0.0 133,100 45,825 (a) 7.5 (b) Unconunitted Financing Facility 1993 50 0.0% $40,001 $8,303 (a) 3.6% (b) 1992 10,000 4.3 40,001 17,180 (a) 4.1 (b) Not applicable for 1991. (a) Computed by dividing the total of the daily outstanding balances for the year by 365 days (366 for 1992). (b) Computed by dividing total it.terest expense for the year by the average daily balance outstanding. l l l l l l l l ( i i i S 20
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATIDN FOR THE YEARS ENDED DECEMBER 31,1993,1992 AND 1991 (Thousands of Dotters) Item 1993 '1992 1991 Maintenance and Repairs -- Charged to Operating Expenses $114,915 $122,789 5115,816
============ ============ ============
Taxes, other Than Pavee!! and Income Taxes: Charged to Operating Expenses: Real and Personal Property Taxes $122,405 5125,200 $119,613 Ohio State Excise Taxes 77,647 78,518 73,644 Other 9,608 10,560 11,366 Total Charged to operating Expenses 209,660 214,278 204,623 Total Charged to Nonoperating Income 551 38 593 I Total $210,211 $214,316 $205,216
============ ============ ============
S 21
THE TOLEDO EDISON COMPANY SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1993 1 (Thousands of Dollars) l l l Balance at Retirements Balance at j Beginning of Additions or End of Classification Period at Cost Sales Other Period i
.............. ............ ............ ............ ............ ............ l Utility Plant (Electric):
Intangible $12,393 ($51) 50 50 $12,342 l Production: l l Steam 280,604 2,542 (1,0 74 ) (44,745)(a) 237,327 i Nuclear 1,911,645 16,068 (6,308) 0 1,921,405 l Other 6,675 33 (10) 0 6,698 Transmission 151,518 4,017 (587) 1,010 (a) 155,958 Olstribution 407,829 20,820 (934) 0 427,715 General 76,540 (921) (71) 0 75,548 Total Utility Plant 2,847,204 42,508 (8,984) (43,735) 2,836,993 Perry Unit 2 (b) 331,378 (11,075) 0 (320,303)(c) 0 Construction Work in Progress 36,812 4,299 0 (1,602)(a) 39,509 Nuclear Fuel 455,947 19,770 0 0 475,717 Other Property 4,083 1 0 45,337 (a) 49,421 Total Property, Plant and Equipment $3,675,424 $55,503 (58,984) ($320,303) $3,401,640 EBERESSSSSSE 233333335233 333338383335 855333825333 3E2353333333 (a) Transfer of Acme Plant Unit 2 to future use rend nonutility property and reclassification of future use property. (b) Includes Perry Unit 2 AFUDC. See Schedule VI!!. (c) Write-off of Perry Unit 2 investment. j S-22
THE TOLEDO EDISON COMPANY SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1992 (Thousands of Dollars) Balance at Reti rmnents Balance at Beginning of Additions or End of Classification Period at Cost Sales Other Period Utility Plant (Electric): Intangible $12,312 581 50 SO S12,393 Production: Steam 308,946 6,789 (37,200) 2,069 (a) 280,604 Nuclear 1,766,285 26,847 (5,830) 124,343 (a) 1,911,645 Other 6,675 0 0 0 6,675 Transmission 149,029 1,870 (23) 642 (a) 151,518 Distribution 375,784 32,756 (910) 199 (a) 407,829 General 73,243 4,297 (1,000) 0 76,540 l Total Utility Plant 2,692,274 72,640 (44,963) 127,253 2,847,204 Perry Unit 2 (b) 342,767 (11,389) 0 0 331,378 l l construction Work in Progress 53,965 (17,153) 0 0 36,812 Nuclear Fuel 433,847 22,100 0 0 455,947 Other Property 4,096 17 (30) 0 4,083 Total Property, Plant and i Equipment $3,526,949 S66,215 ($44,993) 5127,253 $3,675,424 l amassazzzzes assmazzass=s ass =s:ssanza azzz=====ms ======s::: = I I I (a) Results from adoption of SFAS 109 in 1992, which requires the presentation of amounts on a
]
pre-tax basis. Such amounts were previously stated on a net-of-tax basis. (b) Includes Perry Unit 2 AFUDC. See Schedule VI!!. S 23
THE TOLEDO EDISON COMPANY SCHEDULE V - PROPEL'TY, PLANT AND EQUIPMENT YEAR ENDED LECEMBER 31, 1991 (Thousands of Dollars) Balance at Retirements Balance at Beginning of Additions or End of Classification Period at Cost Sales Other Period Utility Plant (Electric): Intangible $3,536 58,776 SO $0 $12,312 Production: Steam 291,411 17,535 0 0 308,946 Nuclear 1,718,262 48,695 (672) 0 1,766,285 other 6,726 (51) 0 0 6,675 Transmission 146,881 2,149 (1) 0 149,029 Distribution 366,788 9,851 (855) 0 375,784 General 70,279 6,990 (4,026) 0 73,243 Total Utility Plant 2,603,883 93,945 (5,554) 0 2,692,274 j Perry Unit 2 (a) 343,685 (918) 0 0 342,767 Construction Work in Progress 93,154 (39,189) 0 0 53,965 Nuclear Fuel 406,506 27,341 0 0 433,847 Other Property 3,303 793 0 0 4,096 l Total Property, Plant and Equipment 53,450,531 581,972 ($5,554) $0 $3,526,949
============ ============ ============ ============ ============
l (a) includes Perry Unit 2 AFUDC. See Schedule Vill. S-24 i
1 i l l THE TOLEDO EDISON COMPANY i SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORilZATION OF PRDPERTY, PLANT AND EQUIPMENT , 1 YEAR ENDED DECEMBER 31, 1993 l (Thousands of Dollars) l i 4 Additions Deductions i Balance at Charged to Removal Cost Balai e at Beginning of Income Net of Salvage End of 1 Description Period Statement Other Reti renents Add /(Deduct) Period 1 t
........... ............ ............ ............ ............ .............. ............ i i ~ Utility Plant- '
I Electric - Depreciation $755,341 583,166 ($46,018)(a)(b) ($8,984) (53,326) $780,179 j
- Amortization 4,980 2,625 0 0 0 7,605 ,
1 .
]
Total Utility Plant 760,321 85,791 (c) (46,018) (8,984) (3,326) 787,784 l 1 i 1 Other Property - Depreciation 1,472 72 (d) 48,111 (b) 0 0 49,655 i Total $761,793 $85,863 $2,093 ($8,984) ($3,326)
$837,439 233E22EE3333 33333=23E332 333333332=33 E33333322333 E322333331ER EE32232 E E37
} i 4 Nuclear Fuel - Amortization $294,915 538,360 (e) 50 SO 50 5333,275 l ,! mz==s=szzars ======z===zz =========== azuzzzsezwzB sus =ezzzzzzz s:::::: :::= (a) Includes nuclear plant decommissioning trust earnings charged to the trust accounts and depreciation charged
]
to construction work in progress. ' (b) Transfer of accumulated depreciation for Acme Plant Unit 2. (c) Depreciation and amortization, as reported in the Income Statement, includes approximately $10 million of amortization of investment tax credits. (d) Nonutility plant expense charged to other income and deductions, net. (e) Charged to fuel and purchased power expense. i S-25
THE TOLEDO EDISON COMPANY SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1992 (Thousands of Dollars) Additions Deductions Balance at Charged to Removal Cost Balance at Beginning of Income Net of Salvage End of Description Period Statement Other Retirmnents Add /(Deduct) Period Utility Plant: Electric - Depreciation $707,316 $79,237 $18,208 (a) ($44,963) ($4,457) $755,341
- Amortization 2,189 2,791 0 0 0 4,980 Total Utility Plant 709,505 82,028 (b) 18,208 (44,963) (4,457) 760,321 1 Other Property
- Depreciation 1,417 89 (c) 0 (30) (4) 1,472 Total $710,922 $82,117 $18,208 ($44,993) ($4,461) $761,793 333333335555 EEEEEEEEEEEE BEEEEEEEEEEE BEEEEEEEEEEE EEEEEEEEEEEE EEEEEEEEEEEE Nuclear Fuel Amortization $238,562 $56,353 (d) $0 $0 $0 $294,915 E23322333333 EEEEEEEEE=EE BEEEEEEEEEEE E33212333333 EEEEFERE%EEE SEEEEEEEEEEE (a) Includes adjustnent resulting f rom adoption of SFAS 109 in 1992 ($16.6 million), nuclear plant decommissioning trust earnings charged to the trust accounts, and depreciation charged to construction work in progress.
(b) Depreciation and amortization, as reported in the income Statement, includes approximately $5 million of amortization of investment tax credits. (c) Nonutility plant expense charged to other income and deductions, net. (d) Charged to fuel and purchased power expense. S 26
THE TOLEDO EDISON COMPANY SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AO EQUIPMENT YEAR ENDED DECEMBER 31, 1991 (Thousands of Dollars) Additions Deduetions Balance at Charged to Removal Cost Balance at Beginning of Income Net of Salvage End of Dascription Period Statement Other Retirements Add /(Deduct) Period Utility Plant: Electric - Depreciation $639,357 $75,105 $1,/61 (a) ($5,554) ($3,353) $707,316
- Amortization 895 1,294 0 0 0 2,189 Total Utility Plant 640,252 76,399 (b) 1,761 (5,554) (3,353) 709,505 Other Property - Depreciation 1,279 138 (c) 0 0 0 1,417 Total $641,531 $76,537 $1,761 ($5,554) ($3,353) $710,922 3333333333E3 EEEEEEEEEEEE E33333333333 E33333333333 EEEEEEEEEEEE E33333333333 Nuclear Fuel - Amortization $184,658 $53,904 (d) $0 $0 $0 $238,562 33333E333333 333333333333 E3333333E333 333333333333 EEEEEEEEEEEE E33333333E35 l (a) Includes nuclear plant decommissioning trust earnings charged to the trust accounts and depreciation charged to construction work in progress. )
(b) Depreciation and amortization, as reported in the Income Statement, includes approximately $4 million of amortization of investment tax credits. (c) Nonutility plant expense charged to other income and deductions, net. , (d) Charged to fuel and purchased power expense. 4 i -f d i s S-27 4 1
THE TOLEDO EDISON COMPANY a SCHEDULE VII - GUARANTEES OF SECURITIES OF OTHER !$ SUERS YEAR EkDED DECEMBER 31, 1993 i (Thousands of Dollars) 1 Principal Amount i Nane of issuer of Guaranteed and Securities Guaranteed Title of Issue (a) Outstanding (a) Nature of Guarantee =
' Quarto Mining Company (b) Guaranteed Mortgage Bonds, due 2000 Series A 8.25% $271 Principal and Interest Series B 9.70% 264 Principal and Interest Series C 9.40% 1,323 Principal and Interest Series EA 10.25% 358 Principal and Interest Series FA 10.50% 274 Principal and Interest Series G 9.05% 4,650 Principal and Interest Series HA 7.75% 3,578 Principal and Interest Series HB 8.31% 2,074 Principal and Interest Guaranteed Refunding Bonds, Series I, 7.45%, due 1997 2,837 Principal and Interest unsecured Note, interest at prime (6% ef fective 7/1/93 and applicable through 12/31/93) plus 2%,
due 2000 1,068 Principal and Interest Equipment leases 2,825 Termination value per Agreements
$19,522 E3333335 (a) None of the securities were owned by Toledo Edison; none were held in the treasury of the issuer; and none were in default.
(b) Toledo Edison and the other CAPCO Group Companies have agreed to guarantee severally, and not jointly, their proportionate shares of Quarto Mining Company debt and lease obligations incurred while developing and equipping the mines. The amounts shown are Toledo Edison's proportionate share of the total obligations. S-28
THE TOLEDO EDISON COMPANY SCHEDULE Vill . VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31,1993,1992 AND 1991 (Thousands of Dollars) Additions Deductions Balance at Charged to Deductions Balance at Beginning Income from End of Dtscription of Period Statement Other Reserves Other Period R flected as Peductions to the Related Assets: Accumulated Provision for Uncollectible Accounts (Deduction f rom Amounts Due from Customers and Others) 1993 $1,390 $4,859 (a) $1,703 (b) 56,562 (a)(c) $0 $1,390 1992 1,390 3,314 (a) 1,067 (b) 4,381 (a)(c) 0 1,390 1991 1,200 4,898 (a) 1,506 (b) 6,214 (a)(c) 0 1,390 Reserve for Perry Unit 2 Allowance for Funds Used During Construction (Deduction from Perry Unit 2) 1993 588,295 $0 $0 588,295 (d) $0 50 1992 88,295 0 0 0 0 88,295 1991 88,295 0 0 0 0 88,295 1 (a) Includes a provision and corresponding write-off of uncollectible accounts of $2,103,000, $699,000 and ;
$404,000 in 1993,1992 and 1991, respectively, relating to customers which qualify for the PUC0 mandated Percentage of Income Payment Plan (PIPP). Such uncollectible accounts are recovered through a separate PUC0 approved surcharge tariff.
(b) Includes amounts for collection of accounts previously written eff and deferral of PIPP uncollectibles in excess of the amount included in the last base rate case. The amounts deferred for future recovery were 5464,000 and $37,000 in 1993 and 1992, respectively. (c) Uncollectible accounts written off. (d) Write-off of Perry Unit 2 investment. S-29 l
THE TOLEDO EDISON COMPANT SCHEDULE IX - SHORT TERM BORROWINGS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (Thousands of Dollars) Average I Weighted Daily Average l Average Maximum Weighted Daily l Balance Interest Amount Amount Weighted at End Rate at Outstanding Outstanding Interest of End of During the During the Rate During Category Period Period Period Period the Period Commercial Paper l 1993 50 0.0% $0 50 (a) 0.0%(b) 1992 0 0.0 31,000 7,350 (a) 4.7 (b) 1991 0 0.0 45,000 15,956 (a) 7.1 (b) Unconrnitted Financing Facility 1993 $0 0.0% $40,001 $11,407 (a) 3.9%(b) 1992 39,502 4.4 40,003 21,772 (a) 4.0 (b) Not applicable for 1991. I (a) Computed by dividing the total of the daily outstanding balances for the year by 365 days (366 for 1992). ' (b) Computed by dividing total interest expense for the year by the average daily balance outstanding. l S-30 l l
THE TOLEDO EDISON COMPANY SCHEDULE X - SUPPLEMENiARY INCOME STATEMENT INFORMATION FOR THE YEARS ENDEb DECEMBER 31, 1993, 1992 AND 1991 (Thousands of Dollars) Item 1993 1992 1991 Maintenance and Repairs -- Charged to Operating Expenses $59,417 $61,394 $58,305 sazzzsasssas assassanzass masssassassa Taxes, Other Than Payroll and Income Taxes: Charged to Operating Expenses: Real and Personal Property Taxes $47,941 $46,403 543,510 Ohio state Excise Taxes 32,218 32,798 33,028 other 3,568 5,014 4,217 Total Charged to Operating Expenses 83,727 84,215 80,755 ! l Total Charged to Nonoperating income 71 91 91 l Total 583,798 584,306 580,846 ausasssssssa massssassmus seassssssusa ) i i 1 1 I I l 1 i I S-31 8
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES AND THE TOLEDO EDISON COMPANY COMBINED PRO FORMA CONDENSED FINANCIAL STATEMENTS Tha following pro forma condensed balance sheets and income statements give effect to the agreement between Cleveland Electric and Toledo Edison to merge Toledo Edison into Cleveland Electric. These statements are unaudited and based on accounting for the merger on a method similar to a pooling of interests. These statements combine the two companies' historical balance sheets at December 31, 1993 and December 31, 1992 and their historical income statements for each of the three years ended December 31, 1993. The following pro forma data is not necessarily indicative of the results of operations or the financial condition which would have been reported had the merger been in effect during those periods or which may be reported in the future. The statements should be read in conjunction with the accompanying notes and with the audited financial statements of both Cleveland Electric and Toledo Edison. vvMBINED PRO FCRMA CONDENSED BALANCE SHEETS OF CLEVELAND ELECTRIC AND TOLEDO EDISON (Unaudited) (Millions of Dollars) At December 31, 1993 Historical ; Cleveland Toledo Adjust- Pro Forma Electric Edison ments Totals j Assets l Property, Plant and Equipment $7,538 $3,402 $ - $10,940 Less: Accumulated Depreciation and Amortization 2,309 1,171 - 3,480 Net Property, Plant and Equipment 5,229 2,231 - 7,460 Current Assets 632 314 (20)(A) 926 Deferred Charges and Other Assets 1,298 965 (9)(B) 2,254 Total Assets $7,159 $3,510 $10,640 ;
${29) i 1
R d P-1
1 At December 31, 1993 Historical Cleveland Toledo Adjust- Pro Forma Electric Edison ments Totals Capitalization and Liabilities Capitalization: Common Stock Equity $1,040 $ 623 $ (1)(R) $ 1,662 Preferred Stock: With Mandatory Redemption Provisions 285 28 - 313 ' Without Mandatory Redemption Provisions 241 210 - 451 Long-Term Debt 2,793 1,225 1(R) 4,019 Total Capitalization 4,359 2,086 - 6,445 Other Noncurrent Liabilities 247 186 - 433 Current Liabilities 733 329 (21)(A) 1,041 Deferred Credits 1,820 909 (8)(A,B) 2,721 Total Capitalization and Liabilities $7,159 $3,510 $129) $10,640 At December 31, 1992 Historical Cleveland Toledo Adjust- Pro Forma Electric Edison ments Totals Assets Property, Plant and Equipment $7,729 $3,587 $ - $11,316 Less: Accumulated Depreciation and Amortization 2,093 1,056 1(R) 3,150 Net Property, Plant and Equipment 5,636 2,531 (1) 8,166 Current Assets 607 258 ;33)(A,R) 832 Deferred Charges and Other Assets 1,880 1,150 (17)(A,B) -3,013 Total Assets $8,123 $3,939 $1511 $12,011 Capitalization and Liabilities Capitalization: Common Stock Equity $1,865 $ 935 $ (1)(R) $ 2,799 Preferred Stock: With Mandatory Redemption Provisions 314 50 - 364 i Vithout Mandatory Redemption Provisions 144 210 - 354 Long-Term Debt 2,515 1,178 1(R) 3,694 l Total Capitalization 4,838 2,373 - 7,211 Other Noncurrent Liabilities 234 188 - 422 Current Liabilities 924 332 (32)(A) 1,224 Deferred Credits 2,127 1,046 (19)(B) 3,154 Total Capitalization and Liabilities $8,123 $3,939 $151)
$12,011 P-2
COMBINED PRO FORMA CONDENSED INCOME STATEMENTS OF CLEVELAND ELECTRIC AND TOLEDO EDISON (Unaudited) (Millions of Dollars) l Year Ended December 31, 1993 Historical l Cleveland Toledo Adjust- Pro Forma Electric Edison ments Totals Operating Revenues $1,751 $ 871 $(147)(C) $2,475 Operating Expenses 1,529 782 (148)(C,D) 2,163 Operating Income 222 89 1 312 Nonoperating (Loss) (569) (263) (1)(D) (833) (Loss) Before Interest Charges. (347) (174) - (521) l Interest Charges 240 115 - 355 Net (Loss) (587) (289) - (876) Preferred Dividend Requirements 45 23 - 68 (Loss) Available for Common Stock $_1632) $1312) $ -
$ (944)
Year Ended December 31, 1992 l Historical Cleveland Toledo Adj us t- Pro Forma Electric Edison ments Totals Operating Revenues $1,743 $ 845 $(149)(C) $2,439 Operating Expenses 1,358 695 (150)(C,D) 1,903 Operating Income 385 150 1 536 Nonoperating Income 63 42 (1)(D) 104 Income Before Interest Charges 448 192 - 640 Interest Charges 243 121 - 364 Net Income 205 71 - 276 Preferred Dividend Requirements 41 24 - 65 l Earnings Available for Common l Stock $ 164 $ 47 $ -
$ 211 l t
l Year Ended December 31, 1991 Historical Cleveland Toledo Adjust- Pro Forma Electric Edison ments Totals Operating Revenues $1,826 $ 887 $(152)(C) $2,561 Operating Expenses 11411 728 (153)(C,D) 1,986 Operating Income 415 159 1 575 Nonoperating Incc.ne 78 22 (2)(D,E) 98 Income Before Interest Charges 493 181 (1) 673 Interest Charges 247 131 (1)(E) 377 Net Income 246 50 - 296 Preferred Dividend Requirements 36 25 - 61 Earnings Available for Common Stock $ 210 $ 25 $ -
$ 235 P-3
NOTES TO COMBINED PRO FORMA CONDENSED BALANCE SHEETS AND INCOME STATEMENTS (Unaudited) The Pro Forma Financial Statements include the following adjustments: (A) Elimination of intercompany accounts and notes receivable and accounts and notes payable. (B) Reclassification of prepaid pension costs or pension liabilities. (C) Elimination of intercompany operating revenues and operating expenses. ; (D) Elimination of intercompany working capital transactions. l (E) Elimination of intercompany interest income and interest expense. (R) Rounding adjustments. l P-4
N J 1 EXHIBIT INDEX 2 The exhibits designated with en asterisk (*) are filed herewith. The exhibits not so designated have previously been filed with the SEC in the file indi-cated in parenthesis following the description of such exhibits and are in- ' corporated herein by reference. An exhibit designated with a pound sign (#) is a management contract or compensatory plan or arrangement. COMMON EXHIBITS (The following documents are exhibits to the reports of Centerior Energy, Cleveland Electric and Toledo Edison.) Exhibit Number Document 10b(1)(a) CAPCO Administration Agreement dated November 1, 1971, as of September 14, 1967, among the CAPCO Group members re-garding the organization and procedures for implementing the objectives of the CAPCO Group (Exhibit 5(p), Amendment No. 1, File No. 2-42230, filed by Cleveland Electric). 10b(1)(b) Amendment No. 1, dated January 4, 1974, to CAPCO Adminis-tration Agreement among the CAPCO Group members (Exhibit 5(c)(3), File No. 2-68906, filed by Ohio Edison). 10b(2) CAPCO Transmission Facilities Agreement dated November 1, 1971, as of September 14, 1967, among the CAPCO Group members regarding the installation, operation and mainte3 nance of transmission facilities to carry out the objec-tives of the CAPCO Group (Exhibit 5(q), Amendment No. 1 File No. 2-42230, filed by Cleveland Electric). -j 10b(2)(1)
- Amendment No. 1 to CAPCO Transmission Facilities Agree- 1 i ment, dated December 23, 1993 and effective as of I January 1, 1993, among the CAPCO Group members regarding
]
requirements for payment of invoices at specified times, 1 for payment of interest on non-timely paid invoices, for I I restricting adjustment of invoices after a four-year period. and for revising the method for computing the Inve tment Responsibility charge for use of a member's ,1 trsnsmission facilities. 10b(3) *CAPCO Basic Operating Agreement As Amended January 1, 1993 anong the CAPCO Group members regarding coordinated operation of the members' systems. 10b(4)
- Agreement for the Termination or Construction of Certain Agreements By and Among the CAPCO Group members, dated Decenber 23, 1993 and effective as of September 1, 1980. i 10b(5) Constcuction Agreement, dated July 22, 1974, cmong the j CAPCO Jroup members and relating to the Perry Nuclear Plant (Exhibit 5(yy), File No. 2-52251, filed by Toledo Edison).
10b(6) Contract, dated as of December 5, 1975, among the CAPCO ) Group members for the construction of Beaver Valley Unit No. 2 (Exhibit 5(g), File No. 2-52996, filed by Cleveland Electric). E-1
l l Exhibit Number Document 10b(7) Amendment No. 1, dated May 1, 1977, to Contract, dated as of December 5, 1975, among the CAPCO Group members for the construction of Beaver Valley Unit No. 2 (Exhibit 5(d)(4), File No. 2-60109, filed by Ohio Edison). 10d(1)(a) Form of Collateral Trust Indenture among CTC Beaver Valley Funding Corporation, Cleveland Electric, Toledo Edison and Irving Trust Company, as Trustee (Exhibit 4(a), File No. l J 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(1)(b) Form of Supplemental Indenture to Collateral Trust In-denture constituting Exhibit 10d(1)(a) above, including form of Secured Lease obligation Bond (Exhibit 4(b), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(1)(c) Form of Collateral Trust Indenture among Beaver Valley II Funding Corporation, The Cleveland Electric Illuminating Company and The Toledo Edison Company and The Bank of New York, as Trustee (Exhibit (4)(a), File No. 33-46665, filed by Cleveland Electric and Toledo Edison). 10d(1)(d) Form of Supplemental Indenture to Collateral Trust Indenture constituting Exhibit 10d(1)(c) above, including form of Secured Lease Obligation Bond (Exhibit (4)(b), File No. 33-46665, filed by Cleveland Electric and Toledo Edison). 10d(2)(a) Form of Collateral Trust Indenture among CTC Mansfield Funding Corporation, Cleveland Electric. Toledo Edison and IBJ Schroder Bank & Trust Company, as Trustee (Exhibit 4(a), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(2)(b) Form of Supplemental Indenture to Collateral Trust In-denture constituting Exhibit 10d(2)(a) above, including forms of Secured Lease Obligation Bonds (Exhibit 4(b), File No. 33-20128 filed by Cleveland Electric and Toledo Edison). 10d(3)(a) Form of Facility Lease dated as of September 15, 1987 be-tween The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the limited partnership Owner Participant named therein, Lessor, and Cleveland Electric and Toledo Edison, Lessees (Exhibit 4(c), File No. 33-18755, filed by cleveland Electric and Toledo Edison). 10d(3)(b) Form of Amendment No. I to Facility Lease constituting Exhibit 10d(3)(a) above (Exhibit 4(e). File No. 33-18755, filed by Cleveland Electric and Toledo Edison), 10d(4)(a) Form of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the corporate owner Participant named therein, Lessor, and Cleveland Electric and Toledo Edison, Lessees ; (Exhibit 4(d), File No. 33-18755, filed by Cleveland ! Electric and Toledo Edison). 10d(4)(b) Form of Amendment No. 1 to Facility Lease constituting Exhibit 10d(4)(a) above (Exhibit 4(f), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). E-2
Exhibit Number Document 10d(5)(a) Form of Facility Lease dated as of September 30, 1987 be-tween Meridian Trust Company, as owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Lessor, and Cleveland Electric and Toledo Edison, Lessees (Exhibit 4(c), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). l 10d(5)(b) Form of Amendment No. 1 to the Facility Lease constituting Exhibit 10d(5)(a) above (Exhibit 4(f), File No. 33-20128. filed by Cleveland Electric and Toledo Edison). 10d(6)(a) Form of Participation Agreement dated as of September 15, 1987 among the limited partnership Owner Participant named therein, the original Loan Participants listed in Schedule 1 thereto, as Original Loan Participants. CTC Beaver Valley Funding Corporation, as Funding Corporation. The First National. Bank of Boston, as owner Trustee, Irving Trust Company, as Indenture Trustee, and Cleveland l Electric and Toledo Edison, as Lessees (Exhibit 28(a), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(6)(b) Form of Amendment No. 1 to Participation Agreement consti-tuting Exhibit 10d(6)(a) above (Exhibit 28(c), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(7)(a) Form of Participation Agreement dated as of September 15, 1987 among the corporate Owner Participant named therein, the original Loan Participants listed in Schedule 1 thereto, as Original Loan Participants CTC Beaver Valley Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Cleveland Electric and Toledo Edison, as Lessees (Exhibit 28(b), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(7)(b) Form of Amendment No. 1 to Participation Agreement consti-tuting Exhibit 10d(7)(a) above (Exhibit 28(d). File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(8)(a) Form of Participation Agreement dated as of September 30, 1987 among the Owner Participant named therein, the Origi- j nal Loan Participants listed in Schedule II thereto, as i Original Loan Participants. CTC Mansfield Funding Corpora-tion, Meridian Trust Company, as Owner Trustee. IBJ Schroder Bank & Trust Company, as Indenture Trustee, and Cleveland Electric and Toledo Edison, as Lessees (Exhibit 28(a), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(8)(b) Form of Amendment No. 1 to the Participation Agreement constituting Exhibit 10d(8)(a) above (Exhibit 28(b), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). i l E-3
Exhibit Number Document 10d(9) Form of Ground Lease dated as of September 15, 1987 be-tween Toledo Edison, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, Tenant (Exhibit 28(e), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(10) Form of Site Lease dated as of September 30, 1987 between Toledo Edison, Lessor, and Meridian Trust Company, as l Owner Trustee under a Trust Agreement dated as of j September 30, 1987 with the owner Participant named therein, Tenant (Exhibit 28(c), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). I 10d(11) Form of Site Lease dated as of September 30, 1987 between Cleveland Electric, Lessor, and Meridian Trust Company, as 1 Owner Trustee under a Trust Agreement dated as of I September 30, 1987 with the Owner Participant named I therein, Tenant (Exhibit 28(d), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(12) Form of Amendment No. 1 to the Site Leases constituting Exhibits 10d(10) and 10d(11) above (Exhibit 4(f), File No. 33-20128 filed by Cleveland Electric and Toledo Edison). 10d(13) Form of Assignment, Assumption and Further Agreement dated as of September 15, 1987 among The First National Bank of j Boston, as Owner Trustee under a Trust Agreement dated as ' of September 15, 1987 with the Owner Participant named therein, Cleveland Electric, Duquesne, Ohio Edison, Pennsylvania Power and Toledo Edison (Exhibit 28(f), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(14) Form of Additional Support Agreement dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, and Toledo Edison (Exhibit 28(g). File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(15) Form of Support Agreement dated as of September 30, 1987 between Meridian Trust Company, as owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named there. Toledo Edison, Cleveland Electric, Duquesne, Ohio Edison and Pennsylvania Power (Exhibit 28(e), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(16) Form of Indenture, Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between Toledo Edison, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the owner Participant named therein, Buyer (Exhibit 28(h), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). E-4
. - . . - _ - ~- .
Exhibit Number Document 10d(17) Form of Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between Toledo Edison, Seller, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the owner Participant named therein, Buyer (Exhibit 28(f), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(18) Form of Bill of Sale. Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between Cleveland Electric, Seller, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the owner Participant named therein, Buyer (Exhibit 28(g), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(19) Forms of Refinancing Agreement, including exhibits thereto, among the Owner Participant named therein, as Owner Participant, CTC Beaver Valley Funding Corporation, as Funding Corporation, Beaver Valley II Funding Corporation, as New Funding Corporation, The Bank of New York, as Indenture Trustee, The Bank of New York, as l Collateral Trust Trustee, The Bank of New York, as New l Collateral Trust Trustee, and The Cleveland Electric ' Illuminating Company and The Toledo Edison Company, as Lessees (Exhibit (28)(e)(1), File No. 33-46665, filed by Cleveland Electric and Toledo Edison). 10e(1) *# Employment agreement, dated May 25, 1993, between Centerior Service Company and Donald C. Shelton effective June 4, 1993 and extending until June 30, 1995. 10e(2) *lEmployment agreement, dated February 2, 1994 and accepted on February 8, 1994, between Centerior Energy and Al R. Temple effective through December 1996. 18a Letter regarding change in accounting principles (Exhibit 18, June 30, 1991 Form 10-Q, File Nos. 1-9130, 1-2323 and 1-3583). 99a Financial Statements of the Centerior Energy Corporation Employee Savings Plan for the fiscal year ended December 31, 1993 (to be filed by amendment), i E-5 l ! l ! )
CENTERIOR ENERGY EXHIBITS Exhibit Number Document e 3a Amended Articles of Incorporation of Centerior Energy ef-fective April 29, 1986 (Exhibit 4(a), File No. 33-4790). 3b Regulations of Centerior Energy effective April 28, 1987 (Exhibit 3b, 1987 Form 10-K, File No. 1-9130). 10a
- Indemnity Agreements between Centerior and certain of its current directors and officers.
10e # Employment and Consulting Agreement, dated November 30, 1989, with P. M. Smart regarding his employment with Toledo Edison through August 31, 1990 and his providing consulting services to Centerior and Toledo Edison for the period September 1, 1990 through January 31, 1994 (Exhibit 10e(2), 1989 Form 10-K, File No. 1-9130). 21 List of subsidiaries (Exhibit 22, 1986 Form 10-K, File No. 1-9130). 23a
- Consent of Independen Accountants.
23b
- Consent of Counsel for Centerior Energy.
24a Power of Attorney of Centerior Energy and certified resolution of Centerior Energy's Board of Directors authorizing the signing on behalf of Centerior pursuant to a power of attorney (Exhibit 25(a), March 31, 1993 Form 10-Q, File No. 1-9130). , 24"
- Powers of Attorney of Centerior Energy directors and officers required to sign the Report.
CLEVELAND ELECTRIC EXHIBITS Exhibit Number Document 3a
- Amended Articles of Incorporation of Cleveland Electric, as amended, effective May 28, 1993.
3b Regulations of Cleveland Electric, dated April 29, 1981, as amended effective October 1, 1988 and April 24, 1990 (Exhibit 3b, 1990 Form 10-K, File No. 1-2323). 4b(1) Mortgage and Deed of Trust between Cleveland Electric and Guaranty Trust Company of New York (now Morgan Guaranty Trust Company of New York), as Trustee, dated July 1, 1940 (Exhibit 7(a), File No. 2-4450). Supplemental Indentures between Cleveland Electric and the Trustee, supplemental to Exhibit 4b(1), dated as follows: E-6 I
Exhibit Number Document Ab(2) July 1, 1940 (Exhibit 7(b). File No. 2-4450). 4b(3) August 18, 1944 (Exhibit 4(c), File No. 2-9887). 4b(4) December 1, 1947 (Exhibit 7(d), File No. 2-7306). Ab(5) September 1, 1950 (Exhibit 7(c), File No. 2-8587). 4b(6) June 1, 1951 (Exhibit 7(f), File No.. 2-8994). 4b(7) May 1, 1954 (Exhibit 4(d), File No. 2-10830). 4b(8) March 1, 1958 (Exhibit 2(a)(4), File No. 2-13839). 4b(9) April 1, 1959 (Exhibit 2(a)(4), File No. 2-14753). 4b(10) December 20, 1967 (Exhibit 2(a)(4), File No. 2-30759). 4b(11) January 15, 1969 (Exhibit 2(a)(5), File No. 2-30759). 4b(12) November 1, 1969 (Exhibit 2(a)(4), File No. 2-35008). 4b(13) June 1, 1970 (Exhibit 2(a)(4). File No. 2-37235). 4b(14) November 15, 1970 (Exhibit 2(a)(4), File No. 2-38460). 4b(15) May 1, 1974 (Exhibit 2(a)(4), File No. 2-50537). Ab(16) April 15, 1975 (Exhibit 2(a)(4), File No. 2-52995). Ab(17) April 16, 1975 (Exhibit 2(a)(4), File No. 2-53309). 4b(18) May 28.-1975 (Exhibit 2(c), June 5, 1975 Form 8-A, File No. 1-2323). 4b(19) February 1, 1976 (Exhibit 3(d)(6), 1975 Form 10-K, File No. 1-2323). 4b(20) November 23, 1976 (Exhibit 2(c)(4), File No. 2-57375). 4b(21) July 26, 1977 (Exhibit 2(a)(4), File No. 2-59401), 4b(22) September 27, 1977 (Exhibit 2(a)(5), File No. 2-67221). 4b(23) May 1, 1978 (Exhibit 2(b), June 30, 1978 Form 10-Q, File No. 1-2323). 4b(24) September 1, 1979 (Exhibit 2(a), September 30, 1979 Form 10-Q, File No. 1-2323). l I 4b(25) April 1, 1980 (Exhibit 4(a)(2), September 30, 1980 Form 10-Q, File No. 1-2323). 4b(26) April 15, 1980 (Exhibit 4(b), September 30, 1980 Form 10-Q, File No. 1-2323). 4b(27) May 28, 1980 (Exhibit 2(a)(4), Amendment No. 1, File No. 2-67221). 4b(28) June 9, 1980 (Exhibit 4(d), September 30, 1980 Form 10-Q, File No. 1-2323). 4b(29) December 1, 1980 (Exhibit 4(b)(29), 1980 Form 10-K, File No. 1-2323). 4b(30) July 28, 1981 (Exhibit 4(a), September 30, 1981, Form 10-Q, File No. 1-2323), 4b(31) August 1, 1981 (Exhibit 4(b), September 30, 1981, Form 10-Q, File No. 1-2323). 4b(32) March 1, 1982 (Exhibit 4(b)(3), Amendment No. 1, File No. 2-76029). 4b(33) July 15, 1982 (Exhibit 4(a), September 30, 1982 Form 10-Q, File No. 1-2323). 4b(34) September 1, 1982 (Exhibit 4(a)(1), September 30, 1982 Form 10-Q, File No. 1-2323). 4b(35) November 1, 1982 (Exhibit 4(a)(2), September 30, 1982 Form 10-Q, File No. 1-2323). 4b(36) November 15, 1982 (Exhibit 4(b)(36), 1982 Form 10-K, File No. 1-2323). E-7 a
Exhibit Number Document 4b(37) May 24, 1983 (Exhibit 4(a), June 30, 1983 Form 10-Q, File No. 1-2323). 4b(38) May 1, 1984 (Exhibit 4, June 30, 1984 Form 10-Q File No. 1-2323). 4b(39) May 23, 1984 (Exhibit 4, May 22,_1984 Form 8-K, File No. 1-2323). 4b(40) June 27, 1984 (Exhibit 4, June 11, 1984 Form 8-K, File No. 1-2323). 4b(41) September 4, 1984 (Exhibit 4b(41), 1984 Form 10-K, File No. 1-2323). 4b(42) November 14, 1984 (Exhibit 4b(42), 1984 Form 10-K, File No. 1-2323). 4b(43) November 15, 1984 (Exhibit 4b(43), 1984 Form 10-K, File No. 1-2323). 4b(44) April 15, 1985 (Exhibit 4(a), May 8, 1985 Form 8-K, File No. 1-2323). 4b(45) May 28, 1985 (Exhibit 4(b), May 8, 1985 Form 8-K, File No. 1-2323). 4b(46) August 1, 1985 (Exhibit 4, September 30, 1985 Form 10-Q, File No. 1-2323). ! 4b(47) September 1, 1985 (Exhibit 4, September 30, 1985 Form 8-K, File No. 1-2323). 4b(48) November 1, 1985 (Exhibit 4, January 31, 1986 Form 8-K, File No. 1-2323). ! 4b(49) April 15, 1986 (Exhibit 4. March 31, 1986 Form 10-Q, File No. 1-2323). 4b(50) May 14, 1986 (Exhibit 4(a), June 30, 1986 Form 10-Q, File No. 1-2323). 4b(51) May 15, 1986 (Exhibit 4(b), June 30, 1986 Form 10-Q, File No. 1-2323). 4b(52) February 25, 1987 (Exhibit 4b(52), 1986 Form 10-K, File No. 1-2323). 4b(53) October 15, 1987 (Exhibit 4 September 30, 1987 Form 10-Q, l q File No. 1-2323). j 4b(54) February 24, 1988 (Exhjbit 4b(54), 1987 Form 10-K, File No. 1-2323). 4b(55) September 15, 1988 (Exhibit 4b(55), 1988 Form 10-K File No. 1-2323). 4b(56) May 15, 1989 (Exhibit 4(a)(2)(1), File No. 33-32724). 4b(57) June 13, 1989 (Exhibit 4(a)(2)(li), File No. 33-32724). 4b(58) October 15, 1989 (Exhibit 4(a)(2)(111), File No. 33-32724). l 4b(59) January 1, 1990 (Exhibit 4b(59), 1989 Form 10-K, File No. 1-2323). 4b(60) June 1, 1990 (Exhibit 4(a), September 30, 1990 Form 10-Q, File No. 1-2323). l 4b(61) August 1, 1990 (Exhibit 4(b), September 30, 1990 Form 10-Q, File No. 1-2323). l 4b(62) May 1, 1991 (Exhibit 4(a), June 30, 1991 Form 10-Q, File No. 1-2323). E-8 l
Exhibit Number Document 4b(63) May 1, 1992 (Exhibit 4(a)(3), File No. 33-48845). 4b(64) July 31, 1992 (Exhibit 4(a)(3), File No. 33-57292). 4b(65) January 1, 1993 (Exhibit 4b(65), 1992 Form 10-K, File No. 1-2323). 4b(66) February 1, 1993 (Exhibit 4b(66), 1992 Form 10-K, File No. 1-2323). 4b(67) May 20, 1993 (Exhibit 4(a), July 14, 1993 Form 8-K, File No. 1-2323). 4b(68) June 1, 1993 (Exhibit 4(b), July 14, 1993 Form 8-K, File No. 1-2323). 10a Indemnity Agreements between Cleveland Electric and cer-tain of its current directors (Exhibit 10a, 1988 Form 10-K, File No. 1-2323). 10a(1) #1978 Key Employee Stock Option Plan (Exhibit 1 File No. 2-61712). 21 List of subsidiaries (Exhibit 22, 1991 Form 10-K, File No. 1-2323). 24a Power of Attorney of Cleveland Electric and certified resolution of Cleveland Electric's Board of Directors authorizing the signing on behalf of Cleveland Electric pursuant to a power of attorney (Exhibit 25(b), March 31, 1993 Form 10-Q, File No. 1-2323). 24b
- Powers of Attorney of Cleveland Electric directors and (
officers required to sign the Report. j TOLEDO EDISON EXHIBITS , l Exhibit Number Document l l 3a Amended Articles of Incorporation of Toledo Edison, as l amended effective October 2, 1992 (Exhibit 3a, 1992 Form l 10-K, File No. 1-3583). l 3b Code of Regulations of Toledo Edison dated January 28, 1987, as amended effective July 1 and October 1, 1988 and April 24, 1990 (Exhibit 3b, 1990 Form 10-K, File No. 1-3583). 4b(1) Indenture, dated as of April 1, 1947, between the company I and The Chase National Bank of the City of New York (now The Chase Manhattan Bank (National Association)) (Exhibit 2(b), File No. 2-26908). Supplemental Indentures between Toledo Edison and the f Trustee, Supplemental to Exhibit 4b(1), dated as follows: E-9
Exhibit Number Document 4b(2) September 1, 1948 (Exhibit 2(d), File No. 2-26908). Ab(3) April 1, 1949 (Exhibit 2(e), File No. 2-26908). 4b(4) December 1, 1950 (Exhibit 2(f), File No. 2-26908). 4b(5) March 1, 1954 (Exhibit 2(g), File No. 2-26908). 4b(6) February 1, 1956 (Exhibit 2(h), File No. 2-26908). 4b(7) May 1, 1958 (Exhibit 5(g), File No. 2-59794). 4b(8) August 1, 1967 (Exhibit 2(c). File No. 2-26908). 4b(9) November 1, 1970 (Exhibit 2(c). File No. 2-38569). 4b(10) August 1, 1972 (Exhibit 2(c), File No. 2-44873). 4b(11) November 1, 1973 (Exhibit 2(c), File No. 2-49428). 4b(12) July 1, 1974 (Exhibit 2(c), File No. 2-51429). 4b(13) October 1, 1975 (Exhibit 2(c), File No. 2-54627). 4b(~6) June 1, 1976 (Exhibit 2(c), File No. 2-56396). Abu October 1, 1978 (Exhibit 2(c), File No. 2-62568). 4b(16) September 1, 1979 (Exhibit 2(c), File No. 2-65350). 4b(17) September 1, 1980 (Exhibit 4(s), File No. 2-69190). 4b(18) October 1, 1980 (Exhibit 4(c), File No. 2-69190). 4b(19) April 1, 1981 (Exhibit 4(c). File No. 2-71580). 4b(20) November 1, 1981 (Exhibit 4(c). File No. 2-74485). 4b(21) June 1, 1982 (Exhibit 4(c), File No. 2-77763). 4b(22) September 1, 1982 (Exhibit 4(x), File No. 2-87323). 4b(23) April 1, 1983 (Exhibit 4(c), March 31, 1983 Form 10-Q, File No. 1-3583). ? 4b(24) December 1, 1983 (Exhibit 4(x), 1983 Form 10-K, File No. 1-3583). 4b(25) April 1, 1984 (Exhibit 4(c), File No. 2-90059). 4b(26) October 15, 1984 (Exhibit 4(z), 1984 Form 10-K, File No. 1-3583). 4b(27) October 15, 1984 (Cxhibit 4(aa), 1984 Form 10-K, File No. 1-3583). 4b(28) August 1, 1985 (Exhibit 4(dd), File No. 33-1689). Ab(29) August 1, 1985 (Exhibit 4(ee). File No. 33-1689). 4b(30) December 1, 1985 (Exhibit 4(c), File No. 33-1689). 4b(31) March 1, 1986 (Exhibit 4b(31), 1986 Form 10-K, File No. 1-3583). 4b(32) October 15, 1987 (Exhibit 4, September 30, 1987 Form 10-Q, File No. 1-3583). Ab(33) September 15, 1988 (Exhibit 4b(33), 1988 Form 10-K, File No. 1-3583). Ab(34) June 15, 1989 (Exhibit 4b(34), 1989 Form 10-K, File No. 1-3583). 4b(35) October 15, 1989 (Exhibit 4b(35), 1989 Form 10-K, File No. 1-3583). Ab(36) May 15, 1990 (Exhibit 4 June 30, 1990 Form 10-Q, File No. 1-3583). 4b(37) March 1, 1991 (Exhibit 4(b), June 30, 1991 Form 10-Q, File No. 1-3583). 4b(38) May 1, 1992 (Exhibit 4(a)(3), File No. 33-48844). 4b(39) August 1, 1992 (Exhibit 4b(39), 1992 Form 10-K, File No. 1-3583). E-10
r--__,---- , Exhibit Number Document 4b(40) October 1, 1992 (Exhibit 4b(40), 1992 Form 10-K, File No. j 1-3583). i 4b(41) January 1, 1993 (Exhibit 4b(41), 1992 Form 10-K, File No. l 1-3583). 10a Indemnity Agreements between Toledo Edison and certain of its current directors (Exhibit 10a, 1988 Form 10-K, File No. 1-3583). 24a Powers of Attorney of Toledo Edison and certified resolution of Toledo Edison's Board of Directors authorizing the signing on behalf of Toledo Edison pursuant to a power of attorney (Exhibit 25(c), March 31, 1993 Form 10-Q, File No. 1-3583). 24b
- Powers of Attorney of Toledo Edison directors and officers required to sign the Report.
Pursuant to Paragraph (b)(4)(lii)(A) of Item 601 of Regulation S-K, the Regis- , trants have not filed as an exhibit to this Form 10-K any instrument with 1 respect to long-term debt if the total amount of securities authorized there-under does not exceed 10% of the total assets of the applicable Registrant and its subsidiaries on a consolidated basis, but each hereby agrees to furnish to the Securities and Exchange Commission on request any such instruments. Pursuant to Rule 14a-3(b)(10) under the Securities Exchange Act of 1934, copies of exhibits filed by the Registrants with this Form 10-K will be fur-nished by the Registrants to share owners upon written request and upon re-ceipt in advance of the aggregate fee for preparation of such exhibits at a rate of S.25 per page, plus any postage or shipping expenses which would be incurred by the Registrants. l E-11}}