Annual Report (Form 10-K), fiscal year 1993

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 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.
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 companies 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 Edison are metal casting, forming and fabricating; petroleum refining; automotive equipment and assembly; food processing; and glass. Nearly all of Toledo Edison's operating revenues are derived from the sale of electric energy. At December 31, 1993, Toledo Edison had 1,909 employees of which about 55% were represented by three unions having collective bargaining agreements with Toledo Edison.
The Service Company, which was incorporated in 1986 under the laws of the 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 merger of the two companies into a single entity is the completion of this 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 additional shares of preferred stock. Upon the merger becoming effective, the outstanding shares of Toledo Edison preferred stock will be exchanged for shares of 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 Companies' Financial Statements for further discussion of this matter and "3. Combined Pro Forma Condensed Financial Statements (Unaudited)" contained under Item 14. of this Report for selected historical and combined pro forma financial information of Cleveland Electric and Toledo Edison.
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 generating unit operations and maintenance and generating reserve back-up among the five companies. In addition, the CAPCO Group has completed programs to construct larger, more efficient electric generating units and to strengthen interconnections within the pool.
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 obligations 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 Power. 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 planning 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 PUCO (see "General Regulation--State Utility Commissions"), projects long-term annual growth rates in peak demand and kilowatt-hour sales for the Operating Companies of 1.1% and 1.4%, 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, curtailable 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 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.
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:
*Construction of Perry Unit 2 was suspended in 1985. In 1992, Cleveland 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. 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:
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 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; short-term and long-term financing capability; and securities ratings for the 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.
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 owner stock purchase plans.
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 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 and operate without SEC approval or regulation. Exempt Wholesale Generators may be owned by holding companies, electric utility companies or any other person.
State Utility Commissions - ------------------------- The Operating Companies are subject to the jurisdiction of the PUCO 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 PUCO 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 subject to the jurisdiction of the PaPUC in certain respects relating to their ownership interests in generating facilities located in Pennsylvania.
The PUCO 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- plines. Not more than three commissioners may belong to the same political party.
Under Ohio law, a public utility must file annually with the PUCO 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 and security issuances associated with the integrated resource plan over the four-year period must also be provided.
The PUCO must hold a public hearing on the long-term forecast at least once every five years to determine the reasonableness of such forecast. The PUCO 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 PUCO jurisdiction to submit environmental compliance plans for PUCO review and approval. Ohio law requires that the PUCO 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 PUCO held hearings on the Operating Companies' 1992 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 PUCO in February 1993.
The PUCO 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 system, such as Centerior, must obtain PUCO 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 PUCO 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 PUCO has a reserve capacity policy for electric utilities in Ohio stating that (i) 20% of service area peak load excluding interruptible load is an appropriate generic benchmark for an electric utility's reserve margin; (ii) 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 remedies for excess capacity (possibly including disallowance of costs in rates) will be determined by the PUCO 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
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. ENVIRONMENTAL REGULATION
General
The Operating Companies are subject to regulation with respect to air quality, 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, 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 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.
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- 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.
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- cluded in the agreement approved by the PUCO in February 1993 in connection with the Operating Companies' 1992 long-term forecast. The Clean Air Act Amendments also require studies to be conducted on the emission of certain potentially hazardous air pollutants which could lead to additional 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 facility 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 Supply--Nuclear" under "Operations", below, for discussions concerning the disposal of nuclear waste.
The Resource Conservation and Recovery Act exempts certain fossil fuel com- bustion waste products, such as fly ash, from hazardous waste disposal re- quirements. The Operating Companies are unable to predict whether Congress 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 75% 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. 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 PUCO 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 PUCO does not make a decision within 275 days after the rate request application is filed. If the PUCO 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- 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 PUCO 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.
The PUCO 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 PUCO 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 PUCO 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 facilities accounted for 2.5% and 3.5% of the 1993 total electric operating revenues of Centerior Energy and Cleveland Electric, respectively. The loss 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- spectively. 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.
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 and for Centerior Energy, and for Cleveland Electric and and 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. These 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 51.38% and 48.62% of Davis-Besse. Cleveland Electric and Toledo Edison also lease, as joint lessees, another 18.26% of Beaver Valley Unit 2 as a result of a September 1987 sale and leaseback transaction (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 PUCO 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 87.1% 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:
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 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 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 SALP scores are issued. The most recent review period and SALP review scores for Beaver Valley Unit 2 are:
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 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.
Cleveland Electric and Toledo Edison also periodically compete with other 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.



Item 2. Properties
GENERAL
The Centerior System
The wholly owned, jointly owned and leased electric generating facilities of 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 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 was 5,397,000 kilowatts and occurred on August 27. At the time of the 1993 peak load, the operable capacity available to serve the load was 5,998,000 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 7% to 9.5%.
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- term contract with the CAPCO Group companies, including Ohio Edison, relating 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 combustion turbine generating units (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 6% 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- 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-common 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.
Cleveland Electric has interconnections with each of the municipal systems operating within its service area.
Toledo Edison
The wholly owned, jointly owned and leased electric generating facilities 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) ceased in July 1993 and the unit is being preserved for future use. All of Toledo Edison's generating facilities are located in Ohio and Pennsylvania.
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 property rights as owner of the land above the shoreline adjacent to the 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.

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 steam 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 CAPCO Group companies as joint owners of the Perry Plant alleged that General Electric had provided defective design information 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.
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.

Item 4. Submission of Matters to a Vote of Security Holders
CENTERIOR ENERGY, CLEVELAND ELECTRIC AND TOLEDO EDISON
None.
PART II
Item 5.

Item 5. Market for Registrants' Common Equity and Related Stockholder Matters
The information regarding common stock prices and number of share owners required by this Item is not applicable to Cleveland Electric 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:
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.

Item 6. Selected Financial Data
CENTERIOR ENERGY
The information required by this Item is contained on Pages and attached hereto.
CLEVELAND ELECTRIC
The information required by this Item is contained on Pages and attached hereto.
TOLEDO EDISON
The information required by this Item is contained on Pages and attached hereto.
Item 7.

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 through attached hereto.
CLEVELAND ELECTRIC
The information required by this Item is contained on Pages through attached hereto.
TOLEDO EDISON
The information required by this Item is contained on Pages through attached hereto.
Item 8.


Item 8. Financial Statements and Supplementary Data
CENTERIOR ENERGY
The information required by this Item is contained on Pages and through attached hereto.
CLEVELAND ELECTRIC
The information required by this Item is contained on Pages and through attached hereto.
TOLEDO EDISON
The information required by this Item is contained on Pages and through attached hereto.
Item 9.

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.



Item 10. Directors and Executive Officers of the Registrants
CENTERIOR ENERGY
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.
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 this Report for information regarding the directors and the executive officers of Toledo Edison. The directors received no remuneration in their capacity as directors.
Robert J. Farling* Mr. Farling is a director of National 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.

Item 11. Executive Compensation
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.

Item 12. Security Ownership of Certain Beneficial Owners and Management
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:
(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 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) 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:
(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 0.03% of Centerior's common stock and none of Cleveland Electric's serial preferred stock. Certain 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) 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.
(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 other 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.
Item 13.

Item 13. Certain Relationships and Related Transactions
CENTERIOR ENERGY, CLEVELAND ELECTRIC AND TOLEDO EDISON
None.
PART IV
Item 14.

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.
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.
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.
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:
*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
March 30, 1994 By *ROBERT J. FARLING, Chairman of the 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- strant and in the capacities and on the date indicated:
*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 TOLEDO EDISON COMPANY Registrant
March 30, 1994 By *ROBERT J. FARLING, Chairman of the 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- strant and in the capacities and on the date indicated:
*By J. T. PERCIO J. T. Percio, Attorney-in-Fact
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS - --------------------------------------------------------------------------------
To the Share Owners and Board of Directors of [Logo] Centerior Energy Corporation:
We have audited the accompanying consolidated balance sheet and consolidated statement of preferred stock of Centerior Energy Corporation (an Ohio corporation) and subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1993. These financial statements and the schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Centerior Energy Corporation and subsidiaries as of December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
As discussed further in Notes 1 and 9, changes were made in the methods of accounting for nuclear plant depreciation in 1991 and for postretirement benefits other than pensions in 1993.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules of Centerior Energy Corporation and subsidiaries listed in the Index to Schedules are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Cleveland, Ohio February 14, 1994
(Centerior Energy) (Centerior Energy)
MANAGEMENT'S FINANCIAL ANALYSIS - -------------------------------------------------------------------------------- Results of Operations
1993 VS. 1992
Factors contributing to the 1.5% increase in 1993 operating revenues are as follows:
The net revenue increase resulted primarily from the different weather conditions and the changes in the composition of the sales mix among customer categories. Weather accounted for approximately $53 million of the higher 1993 revenues. Hot summer weather in 1993 boosted residential, commercial and wholesale kilowatt-hour sales. In contrast, the 1992 summer was the coolest in 56 years in Northern Ohio. Residential and commercial sales also increased as a result of colder late-winter temperatures in 1993 which increased electric heating-related demand. As a result, total sales increased 3.1% in 1993. Residential and commercial sales increased 4.6% and 3.1%, respectively. Industrial sales increased 1.2%. Increased sales to large automotive manufacturers, petroleum refiners and the broad-based, smaller industrial group were partially offset by lower sales to large steel industry customers. Other sales increased 5.9% because of increased sales to wholesale customers. Base rates and miscellaneous revenues decreased in 1993 primarily from lower revenues under contracts having reduced rates with certain large customers and a declining rate structure tied to usage. The contracts have been negotiated to meet competition and encourage economic growth. The net decrease in 1993 fuel cost recovery revenues resulted from changes in the fuel cost factors. The weighted average of these factors increased slightly for The Toledo Edison Company (Toledo Edison) but decreased 5% for The Cleveland Electric Illuminating Company (Cleveland Electric).
Operating expenses increased 13.7% in 1993. The increase in total operation and maintenance expenses resulted from the $218 million of net benefit expenses related to an early retirement program, called the Voluntary Transition Program (VTP), other charges totaling $54 million and an increase in other operation and maintenance expenses. Other charges recorded at year-end 1993 related to a performance improvement plan for Perry Nuclear Power Plant Unit 1 (Perry Unit 1), postemployment benefits and other expense accruals. The increase in other operation and maintenance expenses resulted from higher environmental expenses, power restoration and repair expenses following a July 1993 storm in the Cleveland area, and an increase in other postretirement benefit expenses. See Note 9 for information on retirement and postemployment benefits. Deferred operating expenses decreased because of the write-off of the phase-in deferred operating expenses in 1993 as discussed in Note 7. Federal income taxes decreased as a result of lower pretax operating income.
As discussed in Note 4(b), $583 million of our Perry Nuclear Power Plant Unit 2 (Perry Unit 2) investment was written off in 1993. Credits for carrying charges recorded in nonoperating income decreased because of the write-off of the phase-in deferred carrying charges in 1993 as discussed in Note 7. The federal income tax credit for nonoperating income in 1993 resulted from the write-offs.
1992 VS. 1991
Factors contributing to the 4.8% decrease in 1992 operating revenues are as follows:
The revenue decreases resulted primarily from the different weather conditions and the changes in the composition of the sales mix among customer categories. Weather accounted for approximately $77 million of the lower 1992 revenues. Winter and spring in 1992 were milder than in 1991. In addition, the cooler summer in 1992 contrasted with the summer of 1991 which was much hotter than normal. As a result, total kilowatt-hour sales decreased 1.1% in 1992. Residential and commercial sales decreased 4.5% and 1.3%, respectively, as moderate temperatures in 1992 reduced electric heating and cooling demands. Industrial sales were virtually the same as in 1991 as sales increases to steel producers and auto manufacturers of 10.9% and 2.7%, respectively, offset a decline in sales to other industrial customers. Other sales increased 2.3% because of increased sales to wholesale customers. Operating revenues in 1991 included the recognition by Toledo Edison of $24 million of deferred revenues over the period of a refund to customers under a provision of its January 1989 rate order. No such revenues were reflected in 1992 as the refund period ended in December 1991. The decrease in 1992 fuel cost recovery revenues resulted from the good performance of our generating units, which in turn decreased our fuel cost factors. The weighted averages of these factors decreased approximately 3% for Cleveland Electric and Toledo Edison (Operating Companies).
Operating expenses decreased 4% in 1992. Lower fuel and purchased power expense resulted from less amortization of previously deferred fuel costs than the amount amortized in 1991 and lower generation requirements stemming from less electric sales. A reduction of $17 million in other operation and maintenance expenses resulted primarily from cost-cutting measures. Federal income
(Centerior Energy) (Centerior Energy)
taxes decreased because of the amortization of certain tax benefits under the Rate Stabilization Program discussed in Note 7 and the effects of adopting the new accounting standard for income taxes (SFAS 109) in 1992. These decreases were partially offset by higher depreciation and amortization, caused primarily by the adoption of SFAS 109, and by higher taxes, other than federal income taxes, caused by increased Ohio property and gross receipts taxes. Deferred operating expenses increased as a result of the deferrals under the Rate Stabilization Program.
The federal income tax provision for nonoperating income decreased because of lower carrying charge credits and a greater tax allocation of interest charges to nonoperating activities. Credits for carrying charges recorded in nonoperating income decreased primarily because of lower phase-in carrying charge credits. Interest charges decreased as a result of debt refinancings at lower interest rates and lower short-term borrowing requirements.
Outlook
RECENT ACTIONS
In January 1994, we announced a comprehensive strategic action plan to strengthen our financial and competitive position. The plan established specific objectives and was designed to guide us through the year 2001. While the plan has a long-term focus, it also required us to take some very difficult, but necessary, financial actions at that time. We reduced the quarterly common stock dividend from $.40 per share to $.20 per share effective with the dividend payable February 15, 1994. This action was taken because projected financial results did not support continuation of the dividend at its former rate. We also wrote off our investment in Perry Unit 2 and certain deferred charges related to a January 1989 rate agreement (phase-in deferrals). The aggregate after-tax effect of these write-offs was $1.023 billion which resulted in a net loss in 1993 and a retained earnings deficit. The write-offs are discussed in Notes 4(b) and 7. We also recognized other one-time charges totaling $39 million after taxes related to a performance improvement plan for Perry Unit 1, postemployment benefits and other expense accruals.
Also contributing to the net loss in 1993 was a charge of $87 million after taxes representing a portion of the VTP costs. We will realize approximately $50 million of savings in annual payroll and benefit costs beginning in 1994 as a result of the VTP.
STRATEGIC PLAN
The objectives of our strategic plan are to maximize share owner return from corporate assets and resources, achieve profitable revenue growth, become an industry leader in customer satisfaction, build a winning team and attain increasingly competitive power supply costs. To achieve these objectives, we will continue controlling our operation and maintenance expenses and capital expenditures, reduce our outstanding debt, increase revenues by finding new uses for existing assets and resources, implement a broad range of new marketing programs, increase revenues by restructuring rates for various customers where appropriate, improve the operating performance of our plants and take other appropriate actions.
COMMON STOCK DIVIDENDS
The indicated quarterly common stock dividend is $.20 per share. We believe that the new level is sustainable barring unforeseen circumstances and that the new strategic plan will provide the opportunity to grow the dividend as the objectives are achieved. Nevertheless, future dividend action by our Board of Directors will continue to be decided on a quarter-to-quarter basis after the evaluation of financial results, potential earning capacity and cash flow.
The lower dividend reduces our cash outflow by about $120 million annually, which we intend to use to repay debt more quickly than would otherwise be the case. This will help improve our capitalization structure and interest coverage ratios, both of which are key measures considered by securities rating agencies in determining credit ratings. Improved credit ratings and less outstanding debt, in turn, will lower our interest costs.
COMPETITION
Our electric rates are among the highest in our region because we are recovering the substantial investment in our nuclear construction program. Accordingly, some of our customers continue to seek less costly alternatives, including switching to or working to create a municipal electric system. There are a number of rural and municipal systems in our service area. In addition, we face threats of other municipalities in our service area establishing new systems and the expansion of an existing system. We have entered into agreements with some of the communities which considered establishing systems. Accordingly, they will not proceed with such development at this time in return for rate concessions and/or economic development funds. Others have determined that developing a system was not feasible. Cleveland Public Power continues to expand its operations into areas we have served exclusively. We have been successful in retaining most of the large industrial and commercial customers in those areas by providing economic incentive packages in exchange for sole-supplier contracts. We also have similar contracts with customers in other areas. Most of these contracts have remaining terms of one to five years. We will continue to address municipal system threats through aggressive marketing programs and emphasizing to our customers the value of our service and the risks of a municipal system.
(Centerior Energy) (Centerior Energy)
The Energy Policy Act of 1992 (Energy Act) will provide additional competition in the electric utility industry by requiring utilities to wheel to municipal systems in their service areas electricity from other utilities. This provision of the Energy Act should not significantly increase the competitive threat to us since the operating licenses for our nuclear units have required us to wheel to municipal systems in our service area since 1977. The Energy Act also created a class of exempt wholesale generators which may increase competition in the wholesale power market. A further risk is the possibility that the government could mandate that utilities deliver power from another utility or generation source to their retail customers.
RATE MATTERS
Our Rate Stabilization Program remains in effect. Under this program, we agreed to freeze base rates until 1996 and limit rate increases through 1998. In exchange, we are permitted to defer through 1995 and subsequently recover certain costs not currently recovered in rates and to accelerate the amortization of certain benefits. The amortization and recovery of the deferrals will begin with future rate recognition and will continue over the average life of the related assets, or approximately 30 years. The continued use of these regulatory accounting measures will be dependent upon our continuing assessment and conclusion that there will be probable recovery of such deferrals in future rates.
Our analysis leading to the year-end 1993 financial actions and strategic plan also included an evaluation of our regulatory accounting measures. We 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 measures to the extent we have in the past.
NUCLEAR OPERATIONS
Our three nuclear units may be impacted by activities or events beyond our control. Operating nuclear generating units have experienced unplanned outages or extensions of scheduled outages because of equipment problems or new regulatory requirements. A major accident at a nuclear facility anywhere in the world could cause the Nuclear Regulatory Commission (NRC) to limit or prohibit the operation or licensing of any nuclear unit. If one of our nuclear units is taken out of service for an extended period of time for any reason, including an accident at such unit or any other nuclear facility, we cannot predict whether regulatory authorities would impose unfavorable rate treatment. Such treatment could include taking our affected unit out of rate base or disallowing certain construction or maintenance costs. An extended outage of one of our nuclear units coupled with unfavorable rate treatment could have a material adverse effect on our financial condition and results of operations.
We externally fund the estimated costs for the future decommissioning of our nuclear units. In 1993, we increased our decommissioning expense accruals for revisions in our cost estimates. We expect the increases associated with the new estimates will be recoverable in future rates. See Note 1(e).
HAZARDOUS WASTE DISPOSAL SITES
The Comprehensive Environmental Response, Compensation and Liability Act of 1980 as amended (Superfund) established programs addressing the cleanup of hazardous waste disposal sites, emergency preparedness and other issues. The Operating Companies have been named as "potentially responsible parties" (PRPs) for three sites listed on the Superfund National Priorities List (Superfund List) and are aware of their potential involvement in the cleanup of several other sites not on such list. The allegations that the Operating Companies disposed of hazardous waste at these sites and the amounts involved are often unsubstantiated and subject to dispute. Superfund provides that all PRPs to a particular site can be held liable on a joint and several basis. Consequently, if the Operating Companies were held liable for 100% of the cleanup costs of all of the sites referred to above, the cost could be as high as $400 million. However, we believe that the actual cleanup costs will be substantially lower than $400 million, that the Operating Companies' share of any cleanup costs will be substantially less than 100% and that most of the other PRPs are financially able to contribute their share. The Operating Companies have accrued a liability totaling $19 million at December 31, 1993 based on estimates of the costs of cleanup and their proportionate responsibility for such costs. We believe that the ultimate outcome of these matters will not have a material adverse effect on our financial condition or results of operations.
1993 TAX ACT
The Revenue Reconciliation Act of 1993 (1993 Tax Act), which was enacted in August 1993, provided for a 35% income tax rate in 1993. The 1993 Tax Act did not materially impact the results of operations for 1993, but did affect certain Balance Sheet accounts as discussed in Note 8. The 1993 Tax Act is not expected to materially impact future results of operations or cash flow.
INFLATION
Although the rate of inflation has eased in recent years, we are still affected by even modest inflation which causes increases in the unit cost of labor, materials and services.
Capital Resources and Liquidity
1991-1993 CASH REQUIREMENTS
We need cash for normal corporate operations, the mandatory retirement of securities and an ongoing pro-
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gram of constructing new facilities and modifying existing facilities. The construction program is needed to meet anticipated demand for electric service, comply with governmental regulations and protect the environment. Over the three-year period of 1991-1993, these construction and mandatory retirement needs totaled approximately $1.4 billion. In addition, we exercised various options to redeem and purchase approximately $900 million of our securities.
We raised $2.2 billion through security issues and term bank loans during the 1991-1993 period as shown in the Cash Flows statement. During the three-year period, the Operating Companies also utilized their short-term borrowing arrangements to help meet their cash needs.
Although the write-offs of Perry Unit 2 and the phase-in deferrals in 1993 negatively affected our earnings, they did not adversely affect our current cash flow.
1994 AND BEYOND CASH REQUIREMENTS
Estimated cash requirements for 1994-1998 for Cleveland Electric and Toledo Edison, respectively, are $791 million and $249 million for their construction programs and $715 million and $324 million for the mandatory redemption of debt and preferred stock. Cleveland Electric and Toledo Edison expect to finance internally all of their 1994 cash requirements of approximately $239 million and $109 million, respectively. About 15-20% of the Operating Companies' 1995-1998 requirements are expected to be financed externally. If economical, additional securities may be redeemed under optional redemption provisions.
Our capital requirements are dependent upon our implementation strategy to achieve compliance with the Clean Air Act Amendments of 1990 (Clean Air Act). Cash expenditures for our plan are estimated to be approximately $128 million over the 1994-1998 period. See Note 4(a).
LIQUIDITY
Additional first mortgage bonds may be issued by the Operating Companies under their respective mortgages on the basis of property additions, cash or refundable first mortgage bonds. Under their respective mortgages, each Operating Company may issue first mortgage bonds on the basis of property additions and, under certain circumstances, refundable bonds only if the applicable interest coverage test is met. At December 31, 1993, Cleveland Electric and Toledo Edison would have been permitted to issue approximately $78 million and $323 million of additional first mortgage bonds, respectively. After the fourth quarter of 1994, Cleveland Electric's ability to issue first mortgage bonds is expected to increase substantially when its interest coverage ratio will no longer be affected by the write-offs recorded at December 31, 1993.
As discussed in Note 11(e), certain unsecured debt agreements contain covenants relating to capitalization, fixed charge coverage ratios and secured financings. The write-offs recorded at December 31, 1993 caused Centerior Energy Corporation (Centerior Energy) and the Operating Companies to violate certain of those covenants. The affected creditors have waived those violations in exchange for our commitment to provide them with a second mortgage security interest on our property and other considerations. We expect to complete this process in the second quarter of 1994. We will provide the same security interest to certain other creditors because their agreements require equal treatment. We expect to provide second mortgage collateral for $219 million of unsecured debt, $228 million of bank letters of credit and a $205 million revolving credit facility. For the next five years, the Operating Companies do not expect to raise funds through the sale of debt junior to first mortgage bonds. However, if necessary or desirable, the Operating Companies believe that they could raise funds through the sale of unsecured debt or debt secured by the second mortgage referred to above. The Operating Companies also are able to raise funds through the sale of preference stock and, in the case of Cleveland Electric, preferred stock. Toledo Edison will be unable to issue preferred stock until it can meet the interest and preferred dividend coverage test in its articles of incorporation. Centerior Energy will continue to raise funds through the sale of common stock.
The Operating Companies currently cannot sell commercial paper because of their low commercial paper ratings by Standard & Poor's Corporation (S&P) and Moody's Investors Service, Inc. (Moody's) of "B" and "Not Prime", respectively. We have a $205 million revolving credit facility which will run through mid-1996. However, we currently cannot draw on this facility because the write-offs taken at year-end 1993 caused us to fail to meet certain capitalization and fixed charge coverage covenants. We expect to have this facility available to us again after it is amended in the second quarter of 1994 to provide the participating creditors with a second mortgage security interest.
These financing resources are expected to be sufficient for the Operating Companies' needs over the next several years. The availability and cost of capital to meet our external financing needs, however, also depend upon such factors as financial market conditions and our credit ratings. Current credit ratings for both Operating Companies are as follows:
These ratings reflect a downgrade in December 1993. In addition, S&P has issued a negative outlook for the Operating Companies.
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INCOME STATEMENT CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES - -------------------------------------------------------------------------------
RETAINED EARNINGS - ----------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
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CASH FLOWS CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES - ----------------------------------------------------------------------
(1) Interest paid (net of amounts capitalized) was $295 million, $299 million and $339 million in 1993, 1992 and 1991, respectively. Income taxes paid were $50 million, $32 million and $57 million in 1993, 1992 and 1991, respectively.
(2) Increases in Nuclear Fuel and Nuclear Fuel Lease Obligations in the Balance Sheet resulting from the noncash capitalizations under nuclear fuel agreements are excluded from this statement.
The accompanying notes are an integral part of this statement.
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BALANCE SHEET - ----------------------------------------------------------------------
The accompanying notes are an integral part of this statement.
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CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES
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STATEMENT OF PREFERRED STOCK CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES - ----------------------------------------------------------------------
The accompanying notes are an integral part of this statement.
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NOTES TO THE FINANCIAL STATEMENTS - -------------------------------------------------------------------------------- (1) Summary of Significant Accounting Policies
(A) GENERAL
Centerior Energy is a holding company with two electric utility subsidiaries, Cleveland Electric and Toledo Edison. The consolidated financial statements also include the accounts of Centerior Energy's other wholly owned subsidiary, Centerior Service Company (Service Company), and Cleveland Electric's wholly owned subsidiaries. The Service Company provides management, financial, administrative, engineering, legal and other services at cost to Centerior Energy and the Operating Companies. The Operating Companies operate as separate companies, each serving the customers in its service area. The preferred stock, first mortgage bonds and other debt obligations of the Operating Companies are outstanding securities of the issuing utility. All significant intercompany items have been eliminated in consolidation.
Centerior Energy and the Operating Companies follow the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission and adopted by The Public Utilities Commission of Ohio (PUCO). As rate-regulated utilities, the Operating Companies are subject to Statement of Financial Accounting Standards (SFAS) 71 which governs accounting for the effects of certain types of rate regulation. The Service Company follows the Uniform System of Accounts for Mutual Service Companies prescribed by the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935.
The Operating Companies are members of the Central Area Power Coordination Group (CAPCO). Other members are Duquesne Light Company, Ohio Edison Company and its wholly owned subsidiary, Pennsylvania Power Company. The members have constructed and operate generation and transmission facilities for their use.
(B) REVENUES
Customers are billed on a monthly cycle basis for their energy consumption based on rate schedules or contracts authorized by the PUCO or on ordinances of individual municipalities. An accrual is made at the end of each month to record the estimated amount of unbilled revenues for kilowatt-hours sold in the current month but not billed by the end of that month.
A fuel factor is added to the base rates for electric service. This factor is designed to recover from customers the costs of fuel and most purchased power. It is reviewed and adjusted semiannually in a PUCO proceeding.
(C) FUEL EXPENSE
The cost of fossil fuel is charged to fuel expense based on inventory usage. The cost of nuclear fuel, including an interest component, is charged to fuel expense based on the rate of consumption. Estimated future nuclear fuel disposal costs are being recovered through the base rates.
The Operating Companies defer the differences between actual fuel costs and estimated fuel costs currently being recovered from customers through the fuel factor. This matches fuel expenses with fuel-related revenues.
Owners of nuclear generating plants are assessed by the federal government for the cost of decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy. The assessments are based upon the amount of enrichment services used in prior years and cannot be imposed for more than 15 years. The Operating Companies have accrued the liability for their share of the total assessments. These costs have been recorded in a deferred charge account since the PUCO is allowing the Operating Companies to recover the assessments through their fuel cost factors.
(D) DEFERRED CARRYING CHARGES AND OPERATING EXPENSES
The PUCO authorized the Operating Companies to defer operating expenses and carrying charges for Perry Unit 1 and Beaver Valley Power Station Unit 2 (Beaver Valley Unit 2) from their respective in-service dates in 1987 through December 1988. The annual amortization and recovery of these deferrals, called pre-phase-in deferrals, are $17 million which began in January 1989 and will continue over the lives of the related property.
Beginning in January 1989, the Operating Companies deferred certain operating expenses and both interest and equity carrying charges pursuant to PUCO-approved rate phase-in plans for their investments in Perry Unit 1 and Beaver Valley Unit 2. These deferrals, called phase-in deferrals, were written off at December 31, 1993. See Note 7.
The Operating Companies also defer certain costs not currently recovered in rates under a Rate Stabilization Program approved by the PUCO in October 1992. See Notes 7 and 14.
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(E) DEPRECIATION AND AMORTIZATION
The cost of property, plant and equipment is depreciated over their estimated useful lives on a straight-line basis. The annual straight-line depreciation provision for nonnuclear property expressed as a percent of average depreciable utility plant in service was 3.5% in 1993 and 3.4% in both 1992 and 1991. Effective January 1, 1991, the Operating Companies, after obtaining PUCO approval, changed their method of accounting for nuclear plant depreciation from the units-of-production method to the straight-line method at about a 3% rate. This change decreased 1991 depreciation expense $36 million and increased 1991 net income $28 million (net of $8 million of income taxes) and earnings per share $.20 from what they otherwise would have been. The PUCO subsequently approved in 1991 a change to lower the 3% rate to 2.5% retroactive to January 1, 1991.
Pursuant to a PUCO order, the Operating Companies currently use external funding for the future decommissioning of their nuclear units at the end of their licensed operating lives. The estimated costs are based on the NRC's DECON method of decommissioning (prompt decontamination). Cash contributions are made to the trust funds on a straight-line basis over the remaining licensing period for each unit. The current level of annual expense being recovered from customers based on prior estimates is approximately $8 million. However, actual decommissioning costs are expected to significantly exceed those estimates. Current site-specific estimates for the Operating Companies' share of the future decommissioning costs are $92 million in 1992 dollars for Beaver Valley Unit 2 and $223 million and $300 million in 1993 dollars for Perry Unit 1 and the Davis-Besse Nuclear Power Station (Davis-Besse), respectively. The estimates for Perry Unit 1 and Davis-Besse are preliminary and are expected to be finalized by the end of the second quarter of 1994. The Operating Companies used these estimates to increase their decommissioning expense accruals in 1993. It is expected that the increases associated with the revised cost estimates will be recoverable in future rates. In the Balance Sheet at December 31, 1993, Accumulated Depreciation and Amortization included $74 million of decommissioning costs previously expensed and the earnings on the external funding. This amount exceeds the Balance Sheet amount of the external Nuclear Plant Decommissioning Trusts because the reserve began prior to the external trust funding.
(F) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment are stated at original cost less amounts ordered by the PUCO to be written off. Construction costs include related payroll taxes, pensions, fringe benefits, management and general overheads and allowance for funds used during construction (AFUDC). AFUDC represents the estimated composite debt and equity cost of funds used to finance construction. This noncash allowance is credited to income. The AFUDC rates averaged 9.9% in 1993, 10.8% in 1992 and 10.7% in 1991.
Maintenance and repairs are charged to expense as incurred. The cost of replacing plant and equipment is charged to the utility plant accounts. The cost of property retired plus removal costs, after deducting any salvage value, is charged to the accumulated provision for depreciation.
(G) DEFERRED GAIN AND LOSS FROM SALES OF UTILITY PLANT
The sale and leaseback transactions discussed in Note 2 resulted in a net gain for the sale of the Bruce Mansfield Generating Plant (Mansfield Plant) and a net loss for the sale of Beaver Valley Unit 2. The net gain and net loss were deferred and are being amortized over the terms of leases. These amortizations and the lease expense amounts are recorded as other operation and maintenance expenses.
(H) INTEREST CHARGES
Debt Interest reported in the Income Statement does not include interest on obligations for nuclear fuel under construction. That interest is capitalized. See Note 6.
Losses and gains realized upon the reacquisition or redemption of long-term debt are deferred, consistent with the regulatory rate treatment. Such losses and gains are either amortized over the remainder of the original life of the debt issue retired or amortized over the life of the new debt issue when the proceeds of a new issue are used for the debt redemption. The amortizations are included in debt interest expense.
(Centerior Energy) (Centerior Energy) (I) FEDERAL INCOME TAXES
The Financial Accounting Standards Board (FASB) issued SFAS 109, a new standard for accounting for income taxes, in February 1992. We adopted the new standard in 1992. The standard amended certain provisions of SFAS 96 which we had previously adopted. Adoption of SFAS 109 in 1992 did not materially affect our results of operations, but did affect certain Balance Sheet accounts. See Note 8.
The financial statements reflect the liability method of accounting for income taxes. This method requires that deferred taxes be recorded for all temporary differences between the book and tax bases of assets and liabilities. The majority of these temporary differences are attributable to property-related basis differences. Included in these basis differences is the equity component of AFUDC, which will increase future tax expense when it is recovered through rates. Since this component is not recognized for tax purposes, we must record a liability for our tax obligation. The PUCO permits recovery of such taxes from customers when they become payable. Therefore, the net amount due from customers through rates has been recorded as a deferred charge and will be recovered over the lives of the related assets.
Investment tax credits are deferred and amortized over the lives of the applicable property as a reduction of depreciation expense. See Note 7 for a discussion of the amortization of certain unrestricted excess deferred taxes and unrestricted investment tax credits under the Rate Stabilization Program.
(2) Utility Plant Sale and Leaseback Transactions
The Operating Companies are co-lessees of 18.26% (150 megawatts) of Beaver Valley Unit 2 and 6.5% (51 megawatts), 45.9% (358 megawatts) and 44.38% (355 megawatts) of Units 1, 2 and 3 of the Mansfield Plant, respectively, all for terms of about 29 1/2 years. These leases are the result of sale and leaseback transactions completed in 1987.
Under these leases, the Operating Companies are responsible for paying all taxes, insurance premiums, operation and maintenance expenses and all other similar costs for their interests in the units sold and leased back. They may incur additional costs in connection with capital improvements to the units. The Operating Companies have options to buy the interests back at the end of the leases for the fair market value at that time or to renew the leases. Additional lease provisions provide other purchase options along with conditions for mandatory termination of the leases (and possible repurchase of the leasehold interests) for events of default. These events include noncompliance with several financial covenants discussed in Note 11(e).
In April 1992, nearly all of the outstanding Secured Lease Obligation Bonds (SLOBs) issued by a special purpose corporation in connection with financing the sale and leaseback of Beaver Valley Unit 2 were refinanced through a tender offer and the sale of new bonds having a lower interest rate. As part of the refinancing transaction, Toledo Edison paid $43 million as supplemental rent to fund transaction expenses and part of the tender premium. This amount has been deferred and is being amortized over the remaining lease term. The refinancing transaction reduced the annual rental expense for the Beaver Valley Unit 2 lease by $9 million.
Future minimum lease payments under the operating leases at December 31, 1993 are summarized as follows:
Rental expense is accrued on a straight-line basis over the terms of the leases. The amount recorded in 1993, 1992 and 1991 as annual rental expense for the Mansfield Plant leases was $115 million. The amounts recorded in 1993, 1992 and 1991 as annual rental expense for the Beaver Valley Unit 2 lease were $63 million, $66 million and $72 million, respectively. Amounts charged to expense in excess of the lease payments are classified as Accumulated Deferred Rents in the Balance Sheet.
Toledo Edison is selling 150 megawatts of its Beaver Valley Unit 2 leased capacity entitlement to Cleveland Electric. We anticipate that this sale will continue indefinitely.
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(3) Property Owned with Other Utilities and Investors
The Operating Companies own, as tenants in common with other utilities and those investors who are owner-participants in various sale and leaseback transactions (Lessors), certain generating units as listed below. Each owner owns an undivided share in the entire unit. Each owner has the right to a percentage of the generating capability of each unit equal to its ownership share. Each utility owner is obligated to pay for only its respective share of the construction costs and operating expenses. Each Lessor has leased its capacity rights to a utility which is obligated to pay for such Lessor's share of the construction costs and operating expenses. The Operating Companies' share of the operating expenses of these generating units is included in the Income Statement. The Balance Sheet classification of Property, Plant and Equipment at December 31, 1993 includes the following facilities owned by the Operating Companies as tenants in common with other utilities and Lessors:
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 Contingencies
(A) CONSTRUCTION PROGRAM
The estimated cost of our construction program for the 1994-1998 period is $1.088 billion, including AFUDC of $48 million and excluding nuclear fuel.
The Clean Air Act will require, among other things, significant reductions in the emission of sulfur dioxide in two phases over a ten-year period and nitrogen oxides by fossil-fueled generating units.
Our compliance strategy provides for compliance with both phases through at least 2005 primarily through greater use of low-sulfur coal at some of our units and the banking of emission allowances. The plan will require capital expenditures over the 1994-2003 period of approximately $222 million for nitrogen oxide control equipment, emission monitoring equipment and plant modifications. In addition, higher fuel and other operation and maintenance expenses will be incurred. The anticipated rate increase associated with the capital expenditures and higher expenses would be about 1-2% in the late 1990s. Cleveland Electric may need to install sulfur emission control technology at one of its generating plants after 2005 which could require additional expenditures at that time. The PUCO has approved this plan. We also are seeking United States Environmental Protection Agency (U.S. EPA) approval of the first phase of our plan.
We are continuing to monitor developments in new technologies that may be incorporated into our compliance strategy. If a different plan is required by the U.S. EPA, significantly higher capital expenditures could be required during the 1994-2003 period. We believe Ohio law permits the recovery of compliance costs from customers in rates.
(B) PERRY UNIT 2
Perry Unit 2, including its share of the facilities common with Perry Unit 1, was approximately 50% complete when construction was suspended in 1985 pending consideration of various options. These options included resumption of full construction with a revised estimated cost, conversion to a nonnuclear design, sale of all or part of our ownership share, or cancellation.
We wrote off our investment in Perry Unit 2 at December 31, 1993 after we determined that it would not be completed or sold. The write-off totaled $583 million ($425 million after taxes) for our 64.76% ownership share of the unit. See Note 14.
(C) HAZARDOUS WASTE DISPOSAL SITES
The Operating Companies are aware of their potential involvement in the cleanup of three sites listed on the Superfund List and several other waste sites not on such list. The Operating Companies have accrued a liability totaling $19 million at December 31, 1993 based on estimates of the costs of cleanup and their proportionate responsibility for such costs. We believe that the ultimate outcome of these matters will not have a material adverse effect on our financial condition or results of operations. See Management's Financial Analysis -- Outlook-Hazardous Waste Disposal Sites.
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(5) Nuclear Operations and Contingencies
(A) OPERATING NUCLEAR UNITS
Our three nuclear units may be impacted by activities or events beyond our control. An extended outage of one of our nuclear units for any reason, coupled with any unfavorable rate treatment, could have a material adverse effect on our financial condition and results of operations. See discussion of these risks in Management's Financial Analysis -- Outlook-Nuclear Operations.
(B) NUCLEAR INSURANCE
The Price-Anderson Act limits the liability of the owners of a nuclear power plant to the amount provided by private insurance and an industry assessment plan. In the event of a nuclear incident at any unit in the United States resulting in losses in excess of the level of private insurance (currently $200 million), our maximum potential assessment under that plan would be $155 million (plus any inflation adjustment) per incident. The assessment is limited to $20 million per year for each nuclear incident. These assessment limits assume the other CAPCO companies contribute their proportionate share of any assessment.
The CAPCO companies have insurance coverage for damage to property at the Davis-Besse, Perry and Beaver Valley sites (including leased fuel and clean-up costs). Coverage amounted to $2.75 billion for each site as of January 1, 1994. Damage to property could exceed the insurance coverage by a substantial amount. If it does, our share of such excess amount could have a material adverse effect on our financial condition and results of operations. Under these policies, we can be assessed a maximum of $25 million during a policy year if the reserves available to the insurer are inadequate to pay claims arising out of an accident at any nuclear facility covered by the insurer.
We also have extra expense insurance coverage. It includes the incremental cost of any replacement power purchased (over the costs which would have been incurred had the units been operating) and other incidental expenses after the occurrence of certain types of accidents at our nuclear units. The amounts of the coverage are 100% of the estimated extra expense per week during the 52-week period starting 21 weeks after an accident and 67% of such estimate per week for the next 104 weeks. The amount and duration of extra expense could substantially exceed the insurance coverage. (6) Nuclear Fuel
Nuclear fuel is financed for the Operating Companies through leases with a special-purpose corporation. The total amount of financing currently available under these lease arrangements is $382 million ($232 million from intermediate-term notes and $150 million from bank credit arrangements). Financing in an amount up to $750 million is permitted. The intermediate-term notes mature in the period 1994-1997, with $75 million maturing in September 1994. At December 31, 1993, $370 million of nuclear fuel was financed. The Operating Companies severally lease their respective portions of the nuclear fuel and are obligated to pay for the fuel as it is consumed in a reactor. The lease rates are based on various intermediate-term note rates, bank rates and commercial paper rates.
The amounts financed include nuclear fuel in the Davis-Besse, Perry Unit 1 and Beaver Valley Unit 2 reactors with remaining lease payments of $110 million, $78 million and $46 million, respectively, at December 31, 1993. The nuclear fuel amounts financed and capitalized also included interest charges incurred by the lessors amounting to $14 million in 1993, $15 million in 1992 and $21 million in 1991. The estimated future lease amortization payments based on projected consumption are $111 million in 1994, $97 million in 1995, $87 million in 1996, $77 million in 1997 and $69 million in 1998.
(7) Regulatory Matters
Phase-in deferrals were recorded beginning in 1989 pursuant to the phase-in plans approved by the PUCO in January 1989 rate orders for the Operating Companies. The phase-in plans were designed so that the projected revenues resulting from the authorized rate increases and anticipated sales growth provided for the phase-in of certain nuclear costs over a ten-year period. The plans required the deferral of a portion of the operating expenses and both interest and equity carrying charges on the Operating Companies' deferred rate-based investments in Perry Unit 1 and Beaver Valley Unit 2 during the early years of the plans. The amortization and recovery of such deferrals were scheduled to be completed by 1998.
As we developed our strategic plan, we evaluated the future recovery of our deferred charges and continued application of the regulatory accounting measures we follow pursuant to PUCO orders. We concluded that projected revenues would not provide for the recovery of the phase-in deferrals as scheduled because of economic and competitive pressures. Accordingly, we wrote off the 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 million and $705 million, respectively (totaling $598 million after taxes). See Note 14. While recovery of our other regulatory deferrals remains probable, our current
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assessment of business conditions has prompted us to change our future plans. We 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 measures to the extent we have in the past.
In October 1992, the PUCO approved a Rate Stabilization Program that was designed to encourage economic growth in our service area by freezing base rates until 1996 and limiting subsequent rate increases to specified annual amounts not to exceed $216 million for Cleveland Electric and $89 million for Toledo Edison over the 1996-1998 period.
As part of the Rate Stabilization Program, the Operating Companies are allowed to defer and subsequently recover certain costs not currently recovered in rates and to accelerate amortization of certain benefits. Such regulatory accounting measures provide for rate stabilization by rescheduling the timing of rate recovery of certain costs and the amortization of certain benefits during the 1992-1995 period. The continued use of these regulatory accounting measures will be dependent upon our continuing assessment and conclusion that there will be probable recovery of such deferrals in future rates.
The regulatory accounting measures we are eligible to record through December 31, 1995 include the deferral of post-in-service interest carrying charges, depreciation expense and property taxes on assets placed in service after February 29, 1988 and the deferral of Toledo Edison operating expenses equivalent to an accumulated excess rent reserve for Beaver Valley Unit 2 (which resulted from the April 1992 refinancing of SLOBs as discussed in Note 2). The cost deferrals recorded in 1993 and 1992 pursuant to these provisions were $95 million and $84 million, respectively. Amortization and recovery of these deferrals will occur over the average life of the related assets and the remaining lease period, or approximately 30 years, and will commence with future rate recognition. The regulatory accounting measures also provide for the accelerated amortization of certain unrestricted excess deferred tax and unrestricted investment tax credit balances and interim spent fuel storage accrual balances for Davis-Besse. The total amount of such regulatory benefits recognized in 1993 and 1992 pursuant to these provisions was $46 million and $12 million, respectively. The Rate Stabilization Program also authorized the Operating Companies to defer and subsequently recover the incremental expenses associated with the adoption of the accounting standard for postretirement benefits other than pensions (SFAS 106). In 1993, we deferred $96 million pursuant to this provision. Amortization and recovery of this deferral will commence prior to 1998 and is expected to be completed by no later than 2012. See Note 9(b).
(8) Federal Income Tax
Federal income tax, computed by multiplying the income before taxes and preferred dividend requirements of subsidiaries by the statutory rate (35% in 1993 and 34% in both 1992 and 1991), is reconciled to the amount of federal income tax recorded on the books as follows:
Federal income tax expense is recorded in the Income Statement as follows:
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In August 1993, the 1993 Tax Act was enacted. Retroactive to January 1, 1993, the top marginal corporate income tax rate increased to 35%. The change in tax rate increased Accumulated Deferred Federal Income Taxes for the future tax obligation by approximately $90 million. Since the PUCO has historically permitted recovery of such taxes from customers when they become payable, the deferred charge, Amounts Due from Customers for Future Federal Income Taxes, also was increased by $90 million. The 1993 Tax Act is not expected to materially impact future results of operations or cash flow.
Under SFAS 109, temporary differences and carryforwards resulted in deferred tax assets of $619 million and deferred tax liabilities of $2.198 billion at December 31, 1993 and deferred tax assets of $563 million and deferred tax liabilities of $2.598 billion at December 31, 1992. These are summarized as follows:
For tax purposes, net operating loss (NOL) carryforwards of approximately $309 million are available to reduce future taxable income and will expire in 2003 through 2005. The 35% tax effect of the NOLs is $108 million.
The Tax Reform Act of 1986 provides for an alternative minimum tax (AMT) credit to be used to reduce the regular tax to the AMT level should the regular tax exceed the AMT. AMT credits of $171 million are available to offset future regular tax. The credits may be carried forward indefinitely.
(9) Retirement and Postemployment Benefits
(A) RETIREMENT INCOME PLAN
We sponsor a noncontributing pension plan which covers all employee groups. Two existing plans were merged into a single plan on December 31, 1993. The amount of retirement benefits generally depends upon the length of service. Under certain circumstances, benefits can begin as early as age 55. Our funding policy is to comply with the Employee Retirement Income Security Act of 1974 guidelines.
In 1993, we offered the VTP, an early retirement program. Operating expenses for 1993 included $205 million of pension plan accruals to cover enhanced VTP benefits and an additional $10 million of pension costs for VTP benefits paid to retirees from corporate funds. The $10 million is not included in the pension data reported below. A credit of $81 million resulting from a settlement of pension obligations through lump sum payments to almost all the VTP retirees partially offset the VTP expenses.
Net pension and VTP costs (credits) for 1991 through 1993 were comprised of the following components:
The following table presents a reconciliation of the funded status of the plan(s) at December 31, 1993 and 1992.
At December 31, 1993, the settlement (discount) rate and long-term rate of return on plan assets assumptions were 7.25% and 8.75%, respectively. The long-term rate of annual compensation increase assumption was 4.25%. At December 31, 1992, the settlement rate and long-term rate of return on plan assets assumptions were 8.5% and the long-term rate of annual compensation increase assumption was 5%.
Plan assets consist primarily of investments in common stock, bonds, guaranteed investment contracts, cash equivalent securities and real estate.
(Centerior Energy) (Centerior Energy)
(B) OTHER POSTRETIREMENT BENEFITS
We sponsor a postretirement benefit plan which provides all employee groups certain health care, death and other postretirement benefits other than pensions. The plan is contributory, with retiree contributions adjusted annually. The plan is not funded. A policy limiting the employer's contribution for retiree medical coverage for employees retiring after March 31, 1993 was implemented in February 1993.
We adopted SFAS 106, the accounting standard for postretirement benefits other than pensions, effective January 1, 1993. The standard requires the accrual of the expected costs of such benefits during the employees' years of service. Previously, the costs of these benefits were expensed as paid, which is consistent with ratemaking practices. Such costs totaled $9 million in 1992 and $10 million in 1991, which included medical benefits of $8 million in 1992 and $9 million in 1991. The total amount accrued for SFAS 106 costs for 1993 was $111 million, of which $5 million was capitalized and $106 million was expensed as other operation and maintenance expenses. In 1993, we deferred incremental SFAS 106 expenses totaling $96 million pursuant to a provision of the Rate Stabilization Program. See Note 7.
The components of the total postretirement benefit costs for 1993 were as follows:
The accumulated postretirement benefit obligation and accrued postretirement benefit cost at December 31, 1993 are summarized as follows:
At December 31, 1993, the settlement rate and the long-term rate of annual compensation increase assumptions were 7.25% and 4.25%, respectively. The assumed annual health care cost trend rates (applicable to gross eligible charges) are 9.5% for medical and 8% for dental in 1994. Both rates reduce gradually to a fixed rate of 4.75% in 1996 and later years. Elements of the obligation affected by contribution caps are significantly less sensitive to the health care cost trend rate than other elements. If the assumed health care cost trend rates were increased by 1% in each future year, the accumulated postretirement benefit obligation as of December 31, 1993 would increase by $11 million and the aggregate of the service and interest cost components of the annual postretirement benefit cost would increase by $1 million.
(C) POSTEMPLOYMENT BENEFITS
In 1993, we adopted SFAS 112, the new accounting standard which requires the accrual of postemployment benefit costs. Postemployment benefits are the benefits provided to former or inactive employees after employment but before retirement, such as worker's compensation, disability benefits and severance pay. The adoption of this accounting method did not materially affect our 1993 results of operations or financial position.
(10) Guarantees
Cleveland Electric has guaranteed certain loan and lease obligations of two mining companies under two long-term coal purchase arrangements. Toledo Edison is also a party to one of these guarantee arrangements. This arrangement requires payments to the mining company for any actual expenses (as advance payments for coal) when the mines are idle for reasons beyond the control of the mining company. At December 31, 1993, the principal amount of the mining companies' loan and lease obligations guaranteed by the Operating Companies was $80 million.
(11) Capitalization
(A) CAPITAL STOCK TRANSACTIONS
Shares sold, retired and purchased for treasury during the three years ended December 31, 1993 are listed in the following tables.
(Centerior Energy) (Centerior Energy)
Shares of common stock required for our stock plans in 1993 were either acquired in the open market, issued as new shares or issued from treasury stock.
The Board of Directors has authorized the purchase in the open market of up to 1,500,000 shares of our common stock until June 30, 1994. As of December 31, 1993, 225,500 shares had been purchased at a total cost of $4 million. Such shares are being held as treasury stock.
(B) COMMON SHARES RESERVED FOR ISSUE Common shares reserved for issue under the Employee Savings Plan and the Employee Purchase Plan were 1,962,174 and 469,457 shares, respectively, at December 31, 1993.
Stock options to purchase unissued shares of common stock under the 1978 Key Employee Stock Option Plan were granted at an exercise price of 100% of the fair market value at the date of the grant. No additional options may be granted. The exercise prices of option shares purchased during the three years ended December 31, 1993 ranged from $14.09 to $17.41 per share. Shares and price ranges of outstanding options held by employees were as follows:
(C) EQUITY DISTRIBUTION RESTRICTIONS
The Operating Companies make cash available for the funding of Centerior Energy's common stock dividends by paying dividends on their respective common stock, which are held solely by Centerior Energy. Federal law prohibits the Operating Companies from paying dividends out of capital accounts. However, the Operating Companies may pay preferred and common stock dividends out of appropriated retained earnings and current earnings. At December 31, 1993, Cleveland Electric and Toledo Edison had $125 million and $42 million, respectively, of appropriated retained earnings for the payment of dividends. However, Toledo Edison is prohibited from paying a common stock dividend by a provision in its mortgage.
(D) PREFERRED AND PREFERENCE STOCK
Amounts to be paid for preferred stock which must be redeemed during the next five years are $40 million in 1994, $51 million in 1995, $41 million in 1996, $31 million in 1997 and $16 million in 1998.
The annual mandatory redemption provisions are as follows:
* All outstanding shares to be redeemed on December 1, 2001.
In June 1993, Cleveland Electric issued $100 million principal amount of Serial Preferred Stock, $42.40 Series T. The Series T stock was deposited with an agent which issued Depositary Receipts, each representing 1/20 of a share of the Series T stock.
The annualized preferred dividend requirement for the Operating Companies at December 31, 1993 was $68 million.
The preferred dividend rates on Cleveland Electric's Series 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. Cleveland Electric's Series P had a 6.5% dividend rate in 1993 until it was redeemed in August 1993.
(Centerior Energy) (Centerior Energy)
Preference stock authorized for the Operating Companies are 3,000,000 shares without par value for Cleveland Electric and 5,000,000 shares with a $25 par value for Toledo Edison. No preference shares are currently outstanding for either company.
With respect to dividend and liquidation rights, each Operating Company's preferred stock is prior to its preference stock and common stock, and each Operating Company's preference stock is prior to its common stock.
(E) LONG-TERM DEBT AND OTHER BORROWING ARRANGEMENTS
Long-term debt, less current maturities, for the Operating Companies was as follows:
Long-term debt matures during the next five years as follows: $87 million in 1994, $317 million in 1995, $242 million in 1996, $94 million in 1997 and $117 million in 1998.
The Operating Companies issued $550 million aggregate principal amount of secured medium-term notes during the 1991-1993 period. The notes are secured by first mortgage bonds.
The mortgages of the Operating Companies constitute direct first liens on substantially all property owned and franchises held by them. Excluded from the liens, among other things, are cash, securities, accounts receivable, fuel, supplies and, in the case of Toledo Edison, automotive equipment.
Certain unsecured loan agreements of the Operating Companies contain covenants relating to capitalization ratios, fixed charge coverage ratios and limitations on secured financing other than through first mortgage bonds or certain other transactions. Two reimbursement agreements relating to separate letters of credit issued in connection with the sale and leaseback of Beaver Valley Unit 2 contain several financial covenants affecting Centerior Energy and the Operating Companies. Among these are covenants relating to fixed charge coverage ratios and capitalization ratios. The write-offs recorded at December 31, 1993 caused Centerior Energy and the Operating Companies to violate certain covenants contained in a Cleveland Electric loan agreement and the two reimbursement agreements. The affected creditors have waived those violations in exchange for our commitment to provide them with a second mortgage security interest on our property and other considerations. We expect to complete this process in the second quarter of 1994. We will provide the same security interest to certain other creditors because their agreements require equal treatment. We expect to provide second mortgage collateral for $219 million of unsecured debt, $228 million of bank letters of credit and a $205 million revolving credit facility.
(12) Short-Term Borrowing Arrangements
In May 1993, Centerior Energy arranged for a $205 million, three-year revolving credit facility. The facility may be renewed twice for one-year periods at the option of the participating banks. Centerior Energy and the Service Company may borrow under the facility, with all borrowings jointly and severally guaranteed by the Operating Companies. Centerior Energy plans to transfer any of its borrowed funds to the Operating Companies, while the Service Company may borrow up to $25 million for its own use. The banks' fee is 0.5% per annum payable quarterly in addition to interest on any borrowings. That fee is expected to increase to 0.625% when the facility agreement is amended as discussed below. There were no borrowings under the facility at December 31, 1993. The facility agreement contains covenants relating to capitalization and fixed charge coverage ratios. The write-offs recorded at December 31, 1993 caused the ratios to fall below those covenant requirements. The
(Centerior Energy) (Centerior Energy)
revolving credit facility is expected to be available for borrowings after the facility agreement is amended in the second quarter of 1994 to provide the participating creditors with a second mortgage security interest.
Short-term borrowing capacity authorized by the PUCO annually is $300 million for Cleveland Electric and $150 million for Toledo Edison. The Operating Companies are authorized by the PUCO to borrow from each other on a short-term basis.
At December 31, 1993, the Operating Companies had no commercial paper outstanding. The Operating Companies are unable to rely on the sale of commercial paper to provide short-term funds because of their below investment grade commercial paper credit ratings. (13) Financial Instruments' Fair Value
The estimated fair values at December 31, 1993 and 1992 of financial instruments that do not approximate their carrying amounts are as follows:
The fair value of the nuclear plant decommissioning trusts is estimated based on the quoted market prices for the investment securities. The fair value of the Operating Companies' preferred stock with mandatory redemption provisions and long-term debt is estimated based on the quoted market prices for the respective or similar issues or on the basis of the discounted value of future cash flows. The discounted value used current dividend or interest rates (or other appropriate rates) for similar issues and loans with the same remaining maturities.
The estimated fair values of all other financial instruments approximate their carrying amounts in the Balance Sheet at December 31, 1993 and 1992 because of their short-term nature.
(14) Quarterly Results of Operations (Unaudited)
The following is a tabulation of the unaudited quarterly results of operations for the two years ended December 31, 1993.
Earnings for the quarter ended September 30, 1993 were decreased by $81 million, or $.56 per share, as a result of the recording of $125 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 $583 million write-off of Perry Unit 2 (see Note 4(b)), the $877 million write-off of the phase-in deferrals (see Note 7) and $58 million of other charges. These adjustments decreased quarterly earnings by $1.06 billion, or $7.24 per share.
Earnings for the quarter ended September 30, 1992 were increased by $41 million, or $.29 per share, as a result of the recording of deferred operating expenses and carrying charges for the first nine months of 1992 totaling $61 million under the Rate Stabilization Program approved by the PUCO in October 1992. See Note 7.
(Centerior Energy) (Centerior Energy)
FINANCIAL AND STATISTICAL REVIEW - ----------------------------------------------------------------------
Operating Revenues (millions of dollars)
Operating Expenses (millions of dollars)
Income (Loss) (millions of dollars)
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.
(Centerior Energy) (Centerior Energy)
Investment (millions of dollars)
Capitalization (millions of dollars & %)
(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 1.11-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 Statement of Financial Accounting Standards 71.
(Centerior Energy) (Centerior Energy)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS - ----------------------------------------------------------------------
To the Share Owners of The Cleveland Electric [Logo] Illuminating Company:
We have audited the accompanying consolidated balance sheet and consolidated statement of preferred stock of The Cleveland Electric Illuminating Company (a wholly owned subsidiary of Centerior Energy Corporation) and subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1993. These financial statements and the schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of The Cleveland Electric Illuminating Company and subsidiaries as of December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
As discussed further in Notes 1 and 9, changes were made in the methods of accounting for nuclear plant depreciation in 1991 and for postretirement benefits other than pensions in 1993.
Our audits were made for the purposef of forming an opinion on the basic financial statements taken as a whole. The schedules of The Cleveland Electric Illuminating Company and subsidiaries listed in the Index to Schedules are presented for purposes of complying with the Securities and Exchange Commission rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Cleveland, Ohio February 14, 1994 (except with respect to the matter discussed in Note 15, as to which the date is March 25, 1994)
(Cleveland Electric) (Cleveland Electric)
MANAGEMENT'S FINANCIAL ANALYSIS - ---------------------------------------------------------------------- Results of Operations
1993 VS. 1992
Factors contributing to the 0.5% increase in 1993 operating revenues for The Cleveland Electric Illuminating Company (Company) are as follows:
The net revenue increase resulted primarily from the different weather conditions and the changes in the composition of the sales mix among customer categories. Weather accounted for approximately $36 million of the higher 1993 revenues. Hot summer weather in 1993 boosted residential, commercial and wholesale kilowatt-hour sales. In contrast, the 1992 summer was the coolest in 56 years in Northeastern Ohio. Residential and commercial sales also increased as a result of colder late-winter temperatures in 1993 which increased electric heating-related demand. As a result, total sales increased 2.9% in 1993. Residential and commercial sales increased 4.4% and 3.1%, respectively. Industrial sales decreased 1%. Lower sales to large steel industry customers were partially offset by increased sales to large automotive manufacturers and the broad-based, smaller industrial customer group. Other sales increased 11.9% because of increased sales to wholesale customers. The net decrease in 1993 fuel cost recovery revenues resulted from changes in the fuel cost factors. The weighted average of these factors decreased approximately 5%. Base rates and miscellaneous revenues decreased in 1993 primarily from lower revenues under contracts having reduced rates with certain large customers and a declining rate structure tied to usage. The contracts have been negotiated to meet competition and encourage economic growth.
Operating expenses increased 12.4% in 1993. The increase in total operation and maintenance expenses resulted from the $130 million of net benefit expenses related to an early retirement program, called the Voluntary Transition Program (VTP), other charges totaling $35 million and an increase in other operation and maintenance expenses. The VTP benefit expenses consisted of $102 million of costs for the Company plus $28 million for the Company's pro rata share of the costs for its affiliate, Centerior Service Company (Service Company). Other charges recorded at year-end 1993 related to a performance improvement plan for Perry Nuclear Power Plant Unit 1 (Perry Unit 1), postemployment benefits and other expense accruals. The increase in other operation and maintenance expenses resulted from higher environmental expenses, power restoration and repair expenses following a July 1993 storm, and an increase in other postretirement benefit expenses. See Note 9 for information on retirement and postemployment benefits. Deferred operating expenses decreased because of the write-off of the phase-in deferred operating expenses in 1993 as discussed in Note 7. Federal income taxes decreased as a result of lower pretax operating income.
As discussed in Note 4(b), $351 million of our Perry Nuclear Power Plant Unit 2 (Perry Unit 2) investment was written off in 1993. Credits for carrying charges recorded in nonoperating income decreased because of the write-off of the phase-in deferred carrying charges in 1993 as discussed in Note 7. The federal income tax credit for nonoperating income in 1993 resulted from the write-offs.
1992 VS. 1991
Factors contributing to the 4.5% decrease in 1992 operating revenues are as follows:
The revenue decreases resulted primarily from the different weather conditions and the changes in the composition of the sales mix among customer categories. Weather accounted for approximately $55 million of the lower 1992 revenues. Winter and spring in 1992 were milder than in 1991. In addition, the cooler summer in 1992 contrasted with the summer of 1991 which was much hotter than normal. As a result, total kilowatt-hour sales decreased 3.5% in 1992. Residential and commercial sales decreased 4.4% and 0.5%, respectively, as moderate temperatures in 1992 reduced electric heating and cooling demands. Industrial sales declined 0.4% as an 8.1% decrease in sales to the broad-based, smaller industrial customer group completely offset an 8.8% increase in sales to the larger industrial customer group. Sales to steel producers and auto manufacturers within the large industrial customer group rose 10.9% and 7%, respectively. Other sales decreased 16.1% because of decreased sales to wholesale customers and public authorities. The decrease in 1992 fuel cost recovery revenues resulted primarily because of the good performance of our generating units, which in turn decreased our fuel cost factors. The weighted averages of these factors decreased approximately 3%.
Operating expenses decreased 3.6% in 1992. Lower fuel and purchased power expense resulted from lower generation requirements stemming from less electric sales and less amortization of previously deferred fuel costs than the amount amortized in 1991. Federal income taxes decreased because of the amortization of certain tax benefits under the Rate Stabilization Program discussed
(Cleveland Electric) (Cleveland Electric)
in Note 7 and the effects of adopting the new accounting standard for income taxes (SFAS 109) in 1992. These decreases were partially offset by higher depreciation and amortization, caused primarily by the adoption of SFAS 109, and by higher taxes, other than federal income taxes, caused by increased Ohio property and gross receipts taxes. Deferred operating expenses increased as a result of the deferrals under the Rate Stabilization Program.
The federal income tax provision for nonoperating income decreased because of lower carrying charge credits and a greater tax allocation of interest charges to nonoperating activities. Credits for carrying charges recorded in nonoperating income decreased primarily because of lower phase-in-carrying charge credits. Interest charges decreased as a result of debt refinancings at lower interest rates and lower short-term borrowing requirements.
Outlook
RECENT ACTIONS
In January 1994, Centerior Energy Corporation (Centerior Energy), along with the Company and The Toledo Edison Company (Toledo Edison), announced a comprehensive strategic action plan to strengthen their financial and competitive positions. The Company and Toledo Edison are the two wholly owned electric utility subsidiaries of Centerior Energy. The plan established specific objectives and was designed to guide Centerior Energy and its subsidiaries through the year 2001. Several actions were taken at that time. Centerior Energy reduced its quarterly common stock dividend from $.40 per share to $.20 per share effective with the dividend payable February 15, 1994. This action was taken because projected financial results did not support continuation of the dividend at its former rate. The Company and Toledo Edison also wrote off their investments in Perry Unit 2 and certain deferred charges related to a January 1989 rate agreement (phase-in deferrals). The aggregate after-tax effect of these write-offs for the Company was $691 million which resulted in a net loss in 1993 and a retained earnings deficit. The write-offs are discussed in Notes 4(b) and 7. The Company also recognized other one-time charges totaling $25 million after taxes related to a performance improvement plan for Perry Unit 1, postemployment benefits and other expense accruals.
Also contributing to the net loss in 1993 was a charge of $51 million after taxes representing a portion of the VTP costs. The Company will realize approximately $30 million of savings in annual payroll and benefit costs beginning in 1994 as a result of the VTP.
STRATEGIC PLAN
The objectives of the strategic plan are to maximize share owner return on Centerior Energy common stock from corporate assets and resources, achieve profitable revenue growth, become an industry leader in customer satisfaction, build a winning team and attain increasingly competitive power supply costs. To achieve these objectives, the Company will continue controlling its operation and maintenance expenses and capital expenditures, reduce its outstanding debt, increase revenues by finding new uses for existing assets and resources, implement a broad range of new marketing programs, increase revenues by restructuring rates for various customers where appropriate, improve the operating performance of its plants and take other appropriate actions.
COMMON STOCK DIVIDENDS
Centerior Energy's common stock dividend has been funded in recent years primarily by common stock dividends 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 the common stock dividend demands placed on the Company. The Company intends to use the increased retained cash to repay debt more quickly than would otherwise be the case. This will help improve the Company's capitalization structure and interest coverage ratios.
COMPETITION
Our electric rates are among the highest in our region because we are recovering the substantial investment in our nuclear construction program. Accordingly, some of our customers continue to seek less costly alternatives, including switching to or working to create a municipal electric system. There are two municipal systems in our service area. In addition, we face threats of other municipalities in our service area establishing new systems and the expansion of an existing system. We have entered into agreements with some of the communities which considered establishing systems. Accordingly, they will not proceed with such development at this time in return for rate concessions and/or economic development funds. Others have determined that developing a system was not feasible. Cleveland Public Power continues to expand its operations into areas we have served exclusively. We have been successful in retaining most of the large industrial and commercial customers in those areas by providing economic incentive packages in exchange for sole-supplier contracts. We also have similar contracts with customers in other areas. Most of these contracts have remaining terms of one to five years. We will continue to address municipal system threats through aggressive marketing programs and emphasizing to our customers the value of our service and the risks of a municipal system.
The Energy Policy Act of 1992 (Energy Act) will provide additional competition in the electric utility industry by requiring utilities to wheel to municipal systems in their service areas electricity from other utilities. This provision of the Energy Act should not significantly increase the competitive threat to us since the operating licenses
(Cleveland Electric) (Cleveland Electric)
for our nuclear units have required us to wheel to municipal systems in our service area since 1977. The Energy Act also created a class of exempt wholesale generators which may increase competition in the wholesale power market. A further risk is the possibility that the government could mandate that utilities deliver power from another utility or generation source to their retail customers. As mentioned above, we have contracts with many of our large industrial and commercial customers. We will attempt to renew those contracts as they expire which will help us compete if retail wheeling is permitted in the future.
RATE MATTERS
Our Rate Stabilization Program remains in effect. Under this program, we agreed to freeze base rates until 1996 and limit rate increases through 1998. In exchange, we are permitted to defer through 1995 and subsequently recover certain costs not currently recovered in rates and to accelerate the amortization of certain benefits. The amortization and recovery of the deferrals will begin with future rate recognition and will continue over the average life of the related assets, or approximately 30 years. The continued use of these regulatory accounting measures will be dependent upon our continuing assessment and conclusion that there will be probable recovery of such deferrals in future rates.
The analysis leading to the year-end 1993 financial actions and strategic plan also included an evaluation of our regulatory accounting measures. We 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 measures to the extent we have in the past.
NUCLEAR OPERATIONS
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 extensions of scheduled outages because of equipment problems or new regulatory requirements. A major accident at a nuclear facility anywhere in the world could cause the Nuclear Regulatory Commission (NRC) to limit or prohibit the operation or licensing of any nuclear unit. If one of our nuclear units is taken out of service for an extended period of time for any reason, including an accident at such unit or any other nuclear facility, we cannot predict whether regulatory authorities would impose unfavorable rate treatment. Such treatment could include taking our affected unit out of rate base or disallowing certain construction or maintenance costs. An extended outage of one of our nuclear units coupled with unfavorable rate treatment could have a material adverse effect on our financial condition and results of operations.
We externally fund the estimated costs for the future decommissioning of our nuclear units. In 1993, we increased our decommissioning expense accruals for revisions in our cost estimates. We expect the increases associated with the new estimates will be recoverable in future rates. See Note 1(f).
HAZARDOUS WASTE DISPOSAL SITES
The Comprehensive Environmental Response, Compensation and Liability Act of 1980 as amended (Superfund) established programs addressing the cleanup of hazardous waste disposal sites, emergency preparedness and other issues. The Company has been named as a "potentially responsible party" (PRP) for three sites listed on the Superfund National Priorities List (Superfund List) and is aware of its potential involvement in the cleanup of several other sites not on such list. The allegations that the Company disposed of hazardous waste at these sites and the amounts involved are often unsubstantiated and subject to dispute. Superfund provides that all PRPs to a particular site can be held liable on a joint and several basis. Consequently, if the Company were held liable for 100% of the cleanup costs of all of the sites referred to above, the cost could be as high as $250 million. However, we believe that the actual cleanup costs will be substantially lower than $250 million, that the Company's share of any cleanup costs will be substantially less than 100% and that most of the other PRPs are financially able to contribute their share. The Company has accrued a liability totaling $13 million 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 will not have a material adverse effect on our financial condition or results of operations.
1993 TAX ACT
The Revenue Reconciliation Act of 1993 (1993 Tax Act), which was enacted in August 1993, provided for a 35% income tax rate in 1993. The 1993 Tax Act did not materially impact the results of operations for 1993, but did affect certain Balance Sheet accounts as discussed in Note 8. The 1993 Tax Act is not expected to materially impact future results of operations or cash flow.
INFLATION
Although the rate of inflation has eased in recent years, we are still affected by even modest inflation which causes increases in the unit cost of labor, materials and services.
(Cleveland Electric) (Cleveland Electric)
Capital Resources and Liquidity
1991-1993 CASH REQUIREMENTS
We need cash for normal corporate operations, the mandatory retirement of securities and an ongoing program of constructing new facilities and modifying existing facilities. The construction program is needed to meet anticipated demand for electric service, comply with governmental regulations and protect the environment. Over the three-year period of 1991-1993, these construction and mandatory retirement needs totaled approximately $970 million. In addition, we exercised various options to redeem and purchase approximately $430 million of our securities.
We raised $1.2 billion through security issues and term bank loans during the 1991-1993 period as shown in the Cash Flows statement. During the three-year period, the Company also utilized its short-term borrowing arrangements to help meet its cash needs.
Although the write-offs of Perry Unit 2 and the phase-in deferrals in 1993 negatively affected our earnings, they did not adversely affect our current cash flow.
1994 AND BEYOND CASH REQUIREMENTS
Estimated cash requirements for 1994-1998 for the Company are $791 million for its construction program and $715 million for the mandatory redemption of debt and preferred stock. The Company expects to finance internally all of its 1994 cash requirements of approximately $239 million. About 20% of the Company's 1995-1998 requirements are expected to be financed externally. If economical, additional securities may be redeemed under optional redemption provisions.
Our capital requirements are dependent upon our implementation strategy to achieve compliance with the Clean Air Act Amendments of 1990 (Clean Air Act). Cash expenditures for our plan are estimated to be approximately $87 million over the 1994-1998 period. See Note 4(a).
LIQUIDITY
Additional first mortgage bonds may be issued by the Company under its mortgage on the basis of property additions, cash or refundable first mortgage bonds. Under its mortgage, the Company may issue first mortgage bonds on the basis of property additions and, under certain circumstances, refundable bonds only if the applicable interest coverage test is met. At December 31, 1993, the Company would have been permitted to issue approximately $78 million of additional first mortgage bonds. After the fourth quarter of 1994, the Company's ability to issue first mortgage bonds is expected to increase substantially when its interest coverage ratio will no longer be affected by the write-offs recorded at December 31, 1993.
As discussed in Note 11(d), certain unsecured debt agreements contain covenants relating to capitalization, fixed charge coverage ratios and secured financings. The write-offs recorded at December 31, 1993 caused the Company, Toledo Edison and Centerior Energy to violate certain of those covenants. The affected creditors have waived those violations in exchange for commitments to provide them with a second mortgage security interest on property of the Company and Toledo Edison and other considerations. We expect to complete this process in the second quarter of 1994. We will provide the same security interest to certain other creditors because their agreements require equal treatment. We expect to provide second mortgage collateral for $47 million of unsecured debt, $228 million of bank letters of credit and a $205 million revolving credit facility. The bank letters of credit and revolving credit facility are joint and several obligations of the Company and Toledo Edison. For the next five years, the Company does not expect to raise funds through the sale of debt junior to 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 mortgage referred to above. The Company also is able to raise funds through the sale of preference and preferred stock.
The Company currently cannot sell commercial paper because of its low commercial paper ratings by Standard & Poor's Corporation (S&P) and Moody's Investors Service, Inc. (Moody's) of "B" and "Not Prime", respectively. The Company is a party to a $205 million revolving credit facility which will run through mid-1996. However, we currently cannot draw on this facility because the write-offs taken at year-end 1993 caused the Company, Toledo Edison and Centerior Energy to fail to meet certain capitalization and fixed charge coverage covenants. We expect to have this facility available to us again after it is amended in the second quarter of 1994 to provide the participating creditors with a second mortgage security interest.
These financing resources are expected to be sufficient for the Company's needs over the next several years. The availability and cost of capital to meet the Company's external financing needs, however, also depend upon such factors as financial market conditions and its credit ratings. Current credit ratings for the Company are as follows:
These ratings reflect a downgrade in December 1993. In addition, S&P has issued a negative outlook for the Company.
(Cleveland Electric) (Cleveland Electric)
INCOME STATEMENT THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES - --------------------------------------------------------------------------------
RETAINED EARNINGS - ----------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
(Cleveland Electric) (Cleveland Electric)
CASH FLOWS THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES - --------------------------------------------------------------------------------
The accompanying notes are an integral part of this statement.
(Cleveland Electric) (Cleveland Electric)
BALANCE SHEET - ----------------------------------------------------------------------
The accompanying notes are an integral part of this statement.
(Cleveland Electric) (Cleveland Electric)
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
(Cleveland Electric) (Cleveland Electric)
STATEMENT OF PREFERRED STOCK THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES - ----------------------------------------------------------------------
The accompanying notes are an integral part of this statement.
(Cleveland Electric) (Cleveland Electric)
NOTES TO THE FINANCIAL STATEMENTS - ---------------------------------------------------------------------- (1) Summary of Significant Accounting Policies
(A) GENERAL
The Company is an electric utility and a wholly owned subsidiary of Centerior Energy. Centerior Energy has two other wholly owned subsidiaries, Toledo Edison and the Service Company. The Company follows the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by The Public Utilities Commission of Ohio (PUCO). As a rate-regulated utility, the Company is subject to Statement of Financial Accounting Standards (SFAS) 71 which governs accounting for the effects of certain types of rate regulation. The financial statements include the accounts of the Company's wholly owned subsidiaries, which in the aggregate are not material.
The Company is a member of the Central Area Power Coordination Group (CAPCO). Other members are Toledo Edison, Duquesne Light Company, Ohio Edison Company and its wholly owned subsidiary, Pennsylvania Power Company. The members have constructed and operate generation and transmission facilities for their use.
(B) RELATED PARTY TRANSACTIONS
Operating revenues, operating expenses and interest charges include those amounts for transactions with affiliated companies in the ordinary course of business operations.
The Company's transactions with Toledo Edison are primarily for firm power, interchange power, transmission line rentals and jointly owned power plant operations and construction. See Notes 2 and 3.
The Service Company provides management, financial, administrative, engineering, legal and other services at cost to the Company and other affiliated companies. The Service Company billed the Company $180 million, $150 million and $138 million in 1993, 1992 and 1991, respectively, for such services.
(C) REVENUES
Customers are billed on a monthly cycle basis for their energy consumption based on rate schedules or contracts authorized by the PUCO. An accrual is made at the end of each month to record the estimated amount of unbilled revenues for kilowatt-hours sold in the current month but not billed by the end of that month.
A fuel factor is added to the base rates for electric service. This factor is designed to recover from customers the costs of fuel and most purchased power. It is reviewed and adjusted semiannually in a PUCO proceeding.
(D) FUEL EXPENSE
The cost of fossil fuel is charged to fuel expense based on inventory usage. The cost of nuclear fuel, including an interest component, is charged to fuel expense based on the rate of consumption. Estimated future nuclear fuel disposal costs are being recovered through the base rates.
The Company defers the differences between actual fuel costs and estimated fuel costs currently being recovered from customers through the fuel factor. This matches fuel expenses with fuel-related revenues.
Owners of nuclear generating plants are assessed by the federal government for the cost of decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy. The assessments are based upon the amount of enrichment services used in prior years and cannot be imposed for more than 15 years. The Company has accrued a liability for its share of the total assessments. These costs have been recorded in a deferred charge account since the PUCO is allowing the Company to recover the assessments through its fuel cost factors.
(E) DEFERRED CARRYING CHARGES AND OPERATING EXPENSES
The PUCO authorized the Company to defer operating expenses and carrying charges for Perry Unit 1 and Beaver Valley Power Station Unit 2 (Beaver Valley Unit 2) from their respective in-service dates in 1987 through December 1988. The annual amortization and recovery of these deferrals, called pre-phase-in deferrals, are $10 million which began in January 1989 and will continue over the lives of the related property.
Beginning in January 1989, the Company deferred certain operating expenses and both interest and equity carrying charges pursuant to a PUCO-approved rate phase-in plan for its investments in Perry Unit 1 and Beaver Valley Unit 2. These deferrals, called phase-in deferrals, were written off at December 31, 1993. See Note 7.
The Company also defers certain costs not currently recovered in rates under a Rate Stabilization Program approved by the PUCO in October 1992. See Notes 7 and 14.
(F) DEPRECIATION AND AMORTIZATION
The cost of property, plant and equipment is depreciated over their estimated useful lives on a straight-line basis. The annual straight-line depreciation provision for nonnuclear property expressed as a percent of average depre-
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ciable utility plant in service was 3.4% in 1993, 1992 and 1991. Effective January 1, 1991, the Company, after obtaining PUCO approval, changed its method of accounting for nuclear plant depreciation from the units-of-production method to the straight-line method at about a 3% rate. This change decreased 1991 depreciation expense $22 million and increased 1991 net income $17 million (net of $5 million of income taxes) from what they otherwise would have been. The PUCO subsequently approved in 1991 a change to lower the 3% rate to 2.5% retroactive to January 1, 1991.
Pursuant to a PUCO order, the Company currently uses external funding for the future decommissioning of its nuclear units at the end of their licensed operating lives. The estimated costs are based on the NRC's DECON method of decommissioning (prompt decontamination). Cash contributions are made to the trust funds on a straight-line basis over the remaining licensing period for each unit. The current level of annual expense being recovered from customers based on prior estimates is approximately $4 million. However, actual decommissioning costs are expected to significantly exceed those estimates. Current site-specific estimates for the Company's share of the future decommissioning costs are $51 million in 1992 dollars for Beaver Valley Unit 2 and $136 million and $154 million in 1993 dollars for Perry Unit 1 and the Davis-Besse Nuclear Power Station (Davis-Besse), respectively. The estimates for Perry Unit 1 and Davis-Besse are preliminary and are expected to be finalized by the end of the second quarter of 1994. The Company used these estimates to increase its decommissioning expense accruals in 1993. It is expected that the increases associated with the revised cost estimates will be recoverable in future rates. In the Balance Sheet at December 31, 1993, Accumulated Depreciation and Amortization included $41 million of decommissioning costs previously expensed and the earnings on the external funding. This amount exceeds the Balance Sheet amount of the external Nuclear Plant Decommissioning Trusts because the reserve began prior to the external trust funding.
(G) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment are stated at original cost less amounts ordered by the PUCO to be written off. Construction costs include related payroll taxes, pensions, fringe benefits, management and general overheads and allowance for funds used during construction (AFUDC). AFUDC represents the estimated composite debt and equity cost of funds used to finance construction. This noncash allowance is credited to income. The AFUDC rate was 9.63% in 1993, 10.56% in 1992 and 10.47% in 1991.
Maintenance and repairs are charged to expense as incurred. The cost of replacing plant and equipment is charged to the utility plant accounts. The cost of property retired plus removal costs, after deducting any salvage value, is charged to the accumulated provision for depreciation.
(H) DEFERRED GAIN FROM SALE OF UTILITY PLANT The sale and leaseback transaction discussed in Note 2 resulted in a net gain for the sale of the Bruce Mansfield Generating Plant (Mansfield Plant). The net gain was deferred and is being amortized over the term of leases. The amortization and the lease expense amounts are recorded as other operation and maintenance expenses.
(I) INTEREST CHARGES Debt Interest reported in the Income Statement does not include interest on obligations for nuclear fuel under construction. That interest is capitalized. See Note 6.
Losses and gains realized upon the reacquisition or redemption of long-term debt are deferred, consistent with the regulatory rate treatment. Such losses and gains are either amortized over the remainder of the original life of the debt issue retired or amortized over the life of the new debt issue when the proceeds of a new issue are used for the debt redemption. The amortizations are included in debt interest expense.
(J) FEDERAL INCOME TAXES The Financial Accounting Standards Board (FASB) issued SFAS 109, a new standard for accounting for income taxes, in February 1992. We adopted the new standard in 1992. The standard amended certain provisions of SFAS 96 which we had previously adopted. Adoption of SFAS 109 in 1992 did not materially affect our results of operations, but did affect certain Balance Sheet accounts. See Note 8.
The financial statements reflect the liability method of accounting for income taxes. This method requires that deferred taxes be recorded for all temporary differences between the book and tax bases of assets and liabilities. The majority of these temporary differences are attributable to property-related basis differences. Included in these basis differences is the equity component of AFUDC, which will increase future tax expense when it is recovered through rates. Since this component is not recognized for tax purposes, we must record a liability for our tax obligation. The PUCO permits recovery of such taxes from customers when they become payable. Therefore, the net amount due from customers through rates has been recorded as a deferred charge and will be recovered over the lives of the related assets.
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Investment tax credits are deferred and amortized over the lives of the applicable property as a reduction of depreciation expense. See Note 7 for a discussion of the amortization of certain unrestricted excess deferred taxes and unrestricted investment tax credits under the Rate Stabilization Program.
(2) Utility Plant Sale and Leaseback Transactions
The Company and Toledo Edison are co-lessees of 18.26% (150 megawatts) of Beaver Valley Unit 2 and 6.5% (51 megawatts), 45.9% (358 megawatts) and 44.38% (355 megawatts) of Units 1, 2 and 3 of the Mansfield Plant, respectively, all for terms of about 29 1/2 years. These leases are the result of sale and leaseback transactions completed in 1987.
Under these leases, the Company and Toledo Edison are responsible for paying all taxes, insurance premiums, operation and maintenance expenses and all other similar costs for their interests in the units sold and leased back. They may incur additional costs in connection with capital improvements to the units. The Company and Toledo Edison have options to buy the interests back at the end of the leases for the fair market value at that time or to renew the leases. Additional lease provisions provide other purchase options along with conditions for mandatory termination of the leases (and possible repurchase of the leasehold interests) for events of default. These events include noncompliance with several financial covenants discussed in Note 11(d).
As co-lessee with Toledo Edison, the Company is also obligated for Toledo Edison's lease payments. If Toledo Edison is unable to make its payments under the Beaver Valley Unit 2 and Mansfield Plant leases, the Company would be obligated to make such payments. No payments have been made on behalf of Toledo Edison to date.
Future minimum lease payments under the operating leases at December 31, 1993 are summarized as follows:
Rental expense is accrued on a straight-line basis over the terms of the leases. The amount recorded in 1993, 1992 and 1991 as annual rental expense for the Mansfield Plant leases was $70 million. Amounts charged to expense in excess of the lease payments are classified as Accumulated Deferred Rents in the Balance Sheet.
The Company is buying 150 megawatts of Toledo Edison's Beaver Valley Unit 2 leased capacity entitlement. We anticipate that this purchase will continue indefinitely. Purchased power expense for this transaction was $103 million, $108 million and $107 million in 1993, 1992 and 1991, respectively. The future minimum lease payments through the year 2017 associated with Beaver 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:
Depreciation for Eastlake Unit 5 has been accumulated with all other nonnuclear depreciable property rather than by specific units of depreciable property.
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(4) Construction and Contingencies
(A) CONSTRUCTION PROGRAM
The estimated cost of the Company's construction program for the 1994-1998 period is $829 million, including AFUDC of $38 million and excluding nuclear fuel.
The Clean Air Act will require, among other things, significant reductions in the emission of sulfur dioxide in two phases over a ten-year period and nitrogen oxides by fossil-fueled generating units.
Our compliance strategy provides for compliance with both phases through at least 2005 primarily through greater use of low-sulfur coal at some of our units and the banking of emission allowances. The plan will require capital expenditures over the 1994-2003 period of approximately $165 million for nitrogen oxide control equipment, emission monitoring equipment and plant modifications. In addition, higher fuel and other operation and maintenance expenses will be incurred. The anticipated rate increase associated with the capital expenditures and higher expenses would be about 1-2% in the late 1990s. The Company may need to install sulfur emission control technology at one of its generating plants after 2005 which could require additional expenditures at that time. The PUCO has approved this plan. We also are seeking United States Environmental Protection Agency (U.S. EPA) approval of the first phase of our plan.
We are continuing to monitor developments in new technologies that may be incorporated into our compliance strategy. If a different plan is required by the U.S. EPA, significantly higher capital expenditures could be required during the 1994-2003 period. We believe Ohio law permits the recovery of compliance costs from customers in rates.
(B) PERRY UNIT 2
Perry Unit 2, including its share of the facilities common with Perry Unit 1, was approximately 50% complete when construction was suspended in 1985 pending consideration of various options. These options included resumption of full construction with a revised estimated cost, conversion to a nonnuclear design, sale of all or part of our ownership share, or cancellation.
We wrote off our investment in Perry Unit 2 at December 31, 1993 after we determined that it would not be completed or sold. The write-off totaled $351 million ($258 million after taxes) for the Company's 44.85% ownership share of the unit. See Note 14.
(C) HAZARDOUS WASTE DISPOSAL SITES
The Company is aware of its potential involvement in the cleanup of three sites listed on the Superfund List and several other waste sites not on such list. The Company has accrued a liability totaling $13 million 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 will not have a material adverse effect on our financial condition or results of operations. See Management's Financial Analysis -- Outlook-Hazardous Waste Disposal Sites.
(5) Nuclear Operations and Contingencies (A) OPERATING NUCLEAR UNITS
The Company's three nuclear units may be impacted by activities or events beyond our control. An extended outage of one of our nuclear units for any reason, coupled with any unfavorable rate treatment, could have a material adverse effect on our financial condition and results of operations. See discussion of these risks in Management's Financial Analysis -- Outlook-Nuclear Operations.
(B) NUCLEAR INSURANCE
The Price-Anderson Act limits the liability of the owners of a nuclear power plant to the amount provided by private insurance and an industry assessment plan. In the event of a nuclear incident at any unit in the United States resulting in losses in excess of the level of private insurance (currently $200 million), the Company's maximum potential assessment under that plan would be $85 million (plus any inflation adjustment) per incident. The assessment is limited to $11 million per year for each nuclear incident. These assessment limits assume the other CAPCO companies contribute their proportionate share of any assessment.
The CAPCO companies have insurance coverage for damage to property at the Davis-Besse, Perry and Beaver Valley sites (including leased fuel and clean-up costs). Coverage amounted to $2.75 billion for each site as of January 1, 1994. Damage to property could exceed the insurance coverage by a substantial amount. If it does, the Company's share of such excess amount could have a material adverse effect on its financial condition and results of operations. Under these policies, the Company can be assessed a maximum of $14 million during a policy year if the reserves available to the insurer are inadequate to pay claims arising out of an accident at any nuclear facility covered by the insurer.
The Company also has extra expense insurance coverage. It includes the incremental cost of any replacement power purchased (over the costs which would have been
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incurred had the units been operating) and other incidental expenses after the occurrence of certain types of accidents at our nuclear units. The amounts of the coverage are 100% of the estimated extra expense per week during the 52-week period starting 21 weeks after an accident and 67% of such estimate per week for the next 104 weeks. The amount and duration of extra expense could substantially exceed the insurance coverage.
(6) Nuclear Fuel
Nuclear fuel is financed for the Company and Toledo Edison through leases with a special-purpose corporation. The total amount of financing currently available under these lease arrangements is $382 million ($232 million from intermediate-term notes and $150 million from bank credit arrangements). Financing in an amount up to $750 million is permitted. The intermediate-term notes mature in the period 1994-1997, with $75 million maturing in September 1994. At December 31, 1993, $216 million of nuclear fuel was financed for the Company. The Company and Toledo Edison severally lease their respective portions of the nuclear fuel and are obligated to pay for the fuel as it is consumed in a reactor. The lease rates are based on various intermediate-term note rates, bank rates and commercial paper rates.
The amounts financed include nuclear fuel in the Davis-Besse, Perry Unit 1 and Beaver Valley Unit 2 reactors with remaining lease payments for the Company of $57 million, $48 million and $26 million, respectively, at December 31, 1993. The nuclear fuel amounts financed and capitalized also included interest charges incurred by the lessors amounting to $9 million in both 1993 and 1992 and $12 million in 1991. The estimated future lease amortization payments based on projected consumption are $63 million in 1994, $56 million in 1995, $50 million in 1996, $44 million in 1997 and $39 million in 1998.
(7) Regulatory Matters
Phase-in deferrals were recorded beginning in 1989 pursuant to the phase-in plan approved by the PUCO in a January 1989 rate order for the Company. The phase-in plan was designed so that the projected revenues resulting from the authorized rate increases and anticipated sales growth provided for the phase-in of certain nuclear costs over a ten-year period. The plan required the deferral of a portion of the operating expenses and both interest and equity carrying charges on the Company's deferred rate-based investments in Perry Unit 1 and Beaver Valley Unit 2 during the early years of the plan. The amortization and recovery of such deferrals were scheduled to be completed by 1998.
As we developed our strategic plan, we evaluated the future recovery of our deferred charges and continued application of the regulatory accounting measures we follow pursuant to PUCO orders. We concluded that projected revenues would not provide for the recovery of the phase-in deferrals as scheduled because of economic and competitive pressures. Accordingly, we wrote off the cumulative balance of the phase-in deferrals. The total phase-in deferred operating expenses and carrying charges written off at December 31, 1993 by the Company were $117 million and $519 million, respectively (totaling $433 million after taxes). See Note 14. While recovery of our other regulatory deferrals remains probable, our current assessment of business conditions has prompted us to change our future plans. We 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 measures to the extent we have in the past.
In October 1992, the PUCO approved a Rate Stabilization Program that was designed to encourage economic growth in the Company's service area by freezing the Company's base rates until 1996 and limiting subsequent rate increases to specified annual amounts not to exceed $216 million over the 1996-1998 period.
As part of the Rate Stabilization Program, the Company is allowed to defer and subsequently recover certain costs not currently recovered in rates and to accelerate amortization of certain benefits. Such regulatory accounting measures provide for rate stabilization by rescheduling the timing of rate recovery of certain costs and the amortization of certain benefits during the 1992-1995 period. The continued use of these regulatory accounting measures will be dependent upon our continuing assessment and conclusion that there will be probable recovery of such deferrals in future rates.
The regulatory accounting measures we are eligible to record through December 31, 1995 include the deferral of post-in-service interest carrying charges, depreciation expense and property taxes on assets placed in service after February 29, 1988. The cost deferrals recorded in 1993 and 1992 pursuant to these provisions were $56 million and $52 million, respectively. Amortization and recovery of these deferrals will occur over the average life of the related assets, approximately 30 years, and will commence with future rate recognition. The regulatory accounting measures also provide for the accelerated amortization of certain unrestricted excess deferred tax and unrestricted investment tax credit balances and interim spent fuel storage accrual balances for Davis-Besse. The total amount of such regulatory benefits recognized in 1993 and 1992 pursuant to these provisions was $28 million and $7 million, respectively.
The Rate Stabilization Program also authorized the Company to defer and subsequently recover the incremental
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expenses associated with the adoption of the accounting standard for postretirement benefits other than pensions (SFAS 106). In 1993, we deferred $60 million pursuant to this provision. Amortization and recovery of this deferral will commence prior to 1998 and is expected to be completed by no later than 2012. See Note 9(b).
(8) Federal Income Tax
Federal income tax, computed by multiplying income before taxes by the statutory rate (35% in 1993 and 34% in both 1992 and 1991), is reconciled to the amount of federal income tax recorded on the books as follows:
Federal income tax expense is recorded in the Income Statement as follows:
The Company joins in the filing of a consolidated federal income tax return with its affiliated companies. The method of tax allocation reflects the benefits and burdens realized by each company's participation in the consolidated tax return, approximating a separate return result for each company.
In August 1993, the 1993 Tax Act was enacted. Retroactive to January 1, 1993, the top marginal corporate income tax rate increased to 35%. The change in tax rate increased Accumulated Deferred Federal Income Taxes for the future tax obligation by approximately $61 million. Since the PUCO has historically permitted recovery of such taxes from customers when they become payable, the deferred charge, Amounts Due from Customers for Future Federal Income Taxes, also was increased by $61 million. The 1993 Tax Act is not expected to materially impact future results of operations or cash flow.
Under SFAS 109, temporary differences and carryforwards resulted in deferred tax assets of $426 million and deferred tax liabilities of $1.531 billion at December 31, 1993 and deferred tax assets of $415 million and deferred tax liabilities of $1.807 billion at December 31, 1992. These are summarized as follows:
For tax purposes, net operating loss (NOL) carryforwards of approximately $197 million are available to reduce future taxable income and will expire in 2003 through 2005. The 35% tax effect of the NOLs is $69 million.
The Tax Reform Act of 1986 provides for an alternative minimum tax (AMT) credit to be used to reduce the regular tax to the AMT level should the regular tax exceed the AMT. AMT credits of $94 million are available to offset future regular tax. The credits may be carried forward indefinitely.
(9) Retirement and Postemployment Benefits (A) RETIREMENT INCOME PLAN
Prior to December 31, 1993, the Company and Service Company jointly sponsored a noncontributing pension plan which covered all employee groups. The plan was merged with another plan which covered the employees of Toledo Edison into a single plan on December 31, 1993. The amount of retirement benefits generally depends
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upon the length of service. Under certain circumstances, benefits can begin as early as age 55. The funding policy is to comply with the Employee Retirement Income Security Act of 1974 guidelines.
In 1993, the Company and Service Company offered the VTP, an early retirement program. Operating expenses for both companies for 1993 included $146 million of pension plan accruals to cover enhanced VTP benefits and an additional $7 million of pension costs for VTP benefits paid to retirees from corporate funds. The $7 million is not included in the pension data reported below. A credit of $66 million resulting from a settlement of pension obligations through lump sum payments to almost all the VTP retirees partially offset the VTP expenses.
Net pension and VTP costs (credits) for 1991 through 1993 were comprised of the following components:
The following table presents a reconciliation of the funded status of the former plan of the Company and Service Company at December 31, 1992 with comparable information for a portion of the merged plan at December 31, 1993. The December 31, 1993 benefit obligation estimates were derived from information for the former plans. Plan assets of the merged plan were allocated based on a pro rata share of the projected benefit obligation.
At December 31, 1993, the settlement (discount) rate and long-term rate of return on plan assets assumptions were 7.25% and 8.75%, respectively. The long-term rate of annual compensation increase assumption was 4.25%. At December 31, 1992, the settlement rate and long-term rate of return on plan assets assumptions were 8.5% and the long-term rate of annual compensation increase assumption was 5%.
Plan assets consist primarily of investments in common stock, bonds, guaranteed investment contracts, cash equivalent securities and real estate.
(B) OTHER POSTRETIREMENT BENEFITS
Centerior Energy sponsors jointly with its subsidiaries a postretirement benefit plan which provides all employee groups certain health care, death and other postretirement benefits other than pensions. The plan is contributory, with retiree contributions adjusted annually. The plan is not funded. A policy limiting the employer's contribution for retiree medical coverage for employees retiring after March 31, 1993 was implemented in February 1993.
The Company adopted SFAS 106, the accounting standard for postretirement benefits other than pensions, effective January 1, 1993. The standard requires the accrual of the expected costs of such benefits during the employees' years of service. Previously, the costs of these benefits were expensed as paid, which is consistent with ratemaking practices. Such costs for the Company totaled $5 million in 1992 and $6 million in 1991, which included medical benefits of $4 million in 1992 and $5 million in 1991. The total amount accrued by the Company for SFAS 106 costs for 1993 was $69 million, of which $4 million was capitalized and $65 million was expensed as other operation and maintenance expenses. In 1993, the Company deferred incremental SFAS 106 expenses totaling $60 million pursuant to a provision of the Rate Stabilization Program. See Note 7.
The components of the total postretirement benefit costs for 1993 were as follows:
These amounts included costs for the Company and a pro rata share of the Service Company's costs.
The accumulated postretirement benefit obligation and accrued postretirement benefit cost at December 31, 1993
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for the Company and its share of the Service Company's obligation are summarized as follows:
The Balance Sheet classification of Other Noncurrent Liabilities at December 31, 1993 includes only the Company's accrued postretirement benefit cost of $52 million and excludes the Service Company's portion since the Service Company's total accrued cost is carried on its books.
At December 31, 1993, the settlement rate and the long-term rate of annual compensation increase assumptions were 7.25% and 4.25%, respectively. The assumed annual health care cost trend rates (applicable to gross eligible charges) are 9.5% for medical and 8% for dental in 1994. Both rates reduce gradually to a fixed rate of 4.75% in 1996 and later years. Elements of the obligation affected by contribution caps are significantly less sensitive to the health care cost trend rate than other elements. If the assumed health care cost trend rates were increased by 1% in each future year, the accumulated postretirement benefit obligation as of December 31, 1993 would increase by $7 million and the aggregate of the service and interest cost components of the annual postretirement benefit cost would increase by $0.5 million.
(C) POSTEMPLOYMENT BENEFITS
In 1993, the Company adopted SFAS 112, the new accounting standard which requires the accrual of postemployment benefit costs. Postemployment benefits are the benefits provided to former or inactive employees after employment but before retirement, such as worker's compensation, disability benefits and severance pay. The adoption of this accounting method did not materially affect the Company's 1993 results of operations or financial position.
(10) Guarantees
The Company has guaranteed certain loan and lease obligations of two mining companies under two long-term coal purchase arrangements. One of these arrangements requires payments to the mining company for any actual expenses (as advance payments for coal) when the mines are idle for reasons beyond the control of the mining company. At December 31, 1993, the principal amount of the mining companies' loan and lease obligations guaranteed by the Company was $60 million.
(11) Capitalization
(A) CAPITAL STOCK TRANSACTIONS
Preferred stock shares sold and retired during the three years ended December 31, 1993 are listed in the following table.
(B) EQUITY DISTRIBUTION RESTRICTIONS
Federal law prohibits the Company from paying dividends out of capital accounts. However, the Company may pay preferred and common stock dividends out of appropriated retained earnings and current earnings. At December 31, 1993, the Company had $125 million of appropriated retained earnings for the payment of preferred and common stock dividends.
(C) PREFERRED AND PREFERENCE STOCK
Amounts to be paid for preferred stock which must be redeemed during the next five years are $29 million in 1994, $40 million in 1995, $30 million in both 1996 and 1997 and $15 million in 1998.
The annual preferred stock mandatory redemption provisions are as follows:
* All outstanding shares to be redeemed on December 1, 2001.
In June 1993, the Company issued $100 million principal amount of Serial Preferred Stock, $42.40 Series T. The Series T stock was deposited with an agent which issued
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Depositary Receipts, each representing 1/20 of a share of the Series T stock.
The annualized preferred dividend requirement at December 31, 1993 was $47 million.
The preferred dividend rates on the Company's Series L and M fluctuate based on prevailing interest rates and market conditions. The dividend rates for both issues averaged 7% in 1993. The Company's Series P had a 6.5% dividend rate in 1993 until it was redeemed in August 1993.
Preference stock authorized for the Company is 3,000,000 shares without par value. No preference shares are currently outstanding.
With respect to dividend and liquidation rights, the Company's preferred stock is prior to its preference stock and common stock, and its preference stock is prior to its common stock.
(D) LONG-TERM DEBT AND OTHER BORROWING ARRANGEMENTS
Long-term debt, less current maturities, was as follows:
Long-term debt matures during the next five years as follows: $42 million in 1994, $246 million in 1995, $151 million in 1996, $55 million in 1997 and $78 million in 1998.
The Company issued $275 million aggregate principal amount of secured medium-term notes during the 1991-1993 period. The notes are secured by first mortgage bonds.
The Company's mortgage constitutes a direct first lien on substantially all property owned and franchises held by the Company. Excluded from the lien, among other things, are cash, securities, accounts receivable, fuel and supplies.
An unsecured loan agreement of the Company contains covenants relating to capitalization ratios, fixed charge coverage ratios and limitations on secured financing other than through first mortgage bonds or certain other transactions. Two reimbursement agreements relating to separate letters of credit issued in connection with the sale and leaseback of Beaver Valley Unit 2 contain several financial covenants affecting the Company, Toledo Edison and Centerior Energy. Among these are covenants relating to fixed charge coverage ratios and capitalization ratios. The write-offs recorded at December 31, 1993 caused the Company, Toledo Edison and Centerior Energy to violate certain covenants contained in the loan agreement and the two reimbursement agreements. The affected creditors have waived those violations in exchange for commitments to provide them with a second mortgage security interest on property of the Company and Toledo Edison and other considerations. We expect to complete this process in the second quarter of 1994. We will provide the same security interest to certain other creditors because their agreements require equal treatment. We expect to provide second mortgage collateral for $47 million of unsecured debt, $228 million of bank letters of credit and a $205 million revolving credit facility. The bank letters of credit and revolving credit facility are joint and several obligations of the Company and Toledo Edison.
(12) Short-Term Borrowing Arrangements
In May 1993, Centerior Energy arranged for a $205 million, three-year revolving credit facility. The facility may be renewed twice for one-year periods at the option of the participating banks. Centerior Energy and the Service Company may borrow under the facility, with all borrowings jointly and severally guaranteed by the Company and Toledo Edison. Centerior Energy plans to transfer any of its borrowed funds to the Company and Toledo Edison, while the Service Company may borrow up to $25 million for its own use. The banks' fee is 0.5% per annum payable quarterly in addition to interest on any borrowings. That fee is expected to increase to 0.625% when the facility agreement is amended as discussed
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below. There were no borrowings under the facility at December 31, 1993. The facility agreement contains covenants relating to capitalization and fixed charge coverage ratios for the Company, Toledo Edison and Centerior Energy. The write-offs recorded at December 31, 1993 caused the ratios to fall below those covenant requirements. The revolving credit facility is expected to be available for borrowings after the facility agreement is amended in the second quarter of 1994 to provide the participating creditors with a second mortgage security interest.
Short-term borrowing capacity authorized by the PUCO annually is $300 million for the Company. The Company and Toledo Edison are authorized by the PUCO to borrow from each other on a short-term basis.
At December 31, 1993, the Company had no commercial paper outstanding. The Company is unable to rely on the sale of commercial paper to provide short-term funds because of its below investment grade commercial paper credit ratings.
(13) Financial Instruments' Fair Value
The estimated fair values at December 31, 1993 and 1992 of financial instruments that do not approximate their carrying amounts are as follows:
The fair value of the nuclear plant decommissioning trusts is estimated based on the quoted market prices for the investment securities. The fair value of the Company's preferred stock with mandatory redemption provisions and long-term debt is estimated based on the quoted market prices for the respective or similar issues or on the basis of the discounted value of future cash flows. The discounted value used current dividend or interest rates (or other appropriate rates) for similar issues and loans with the same remaining maturities.
The estimated fair values of all other financial instruments approximate their carrying amounts in the Balance Sheet at December 31, 1993 and 1992 because of their short-term nature.
(14) Quarterly Results of Operations (Unaudited)
The following is a tabulation of the unaudited quarterly results of operations for the two years ended December 31, 1993.
Earnings for the quarter ended September 30, 1993 were decreased by $46 million as a result of the recording of $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 $351 million write-off of Perry Unit 2 (see Note 4(b)), the $636 million write-off of the phase-in deferrals (see Note 7) and $38 million of other charges. These adjustments decreased quarterly earnings by $716 million.
Earnings for the quarter ended September 30, 1992 were increased by $26 million as a result of the recording of deferred operating expenses and carrying charges for the first nine months of 1992 totaling $39 million under the Rate Stabilization Program approved by the PUCO in October 1992. See Note 7.
(15) Pending Merger of the Company with Toledo Edison
On March 25, 1994, Centerior Energy announced that its operating utility subsidiaries, the Company and Toledo Edison, plan to merge into a single operating entity. Since the Company 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 merger of the two companies into a single entity is the completion of this consolidation process. Various aspects of the merger are subject to the approval of the FERC, the PUCO and other regulatory authorities. The merger must be approved by share owners of Toledo Edison's preferred stock. Share owners of the Company's preferred stock must approve the authorization of additional shares of preferred stock. Share owners of Toledo Edison's preferred stock will exchange their shares for preferred stock shares of the successor corporation having substantially the same terms, while the
(Cleveland Electric) (Cleveland Electric)
Company's preferred stock will automatically become shares of the successor corporation. Debt holders of the merging companies will become debt holders of the successor corporation. The merging companies plan to seek preferred stock share owner approval in the summer of 1994. The merger is expected to be effective in late 1994.
For the merging companies, the combined pro forma operating revenues were $2.475 billion, $2.439 billion and $2.561 billion and the combined pro forma net
income (loss) was $(876) million, $276 million and $296 million for the years ended December 31, 1993, 1992 and 1991, respectively. The pro forma data is based on accounting for the merger on a method similar to a pooling of interests. The pro forma data is not necessarily indicative of the results of operations which would have been reported had the merger been in effect during those years or which may be reported in the future. The pro forma data should be read in conjunction with the audited financial statements of both the Company and Toledo Edison.
(Cleveland Electric) (Cleveland Electric)
FINANCIAL AND STATISTICAL REVIEW - ----------------------------------------------------------------------
Operating Revenues (millions of dollars)
Operating Expenses (millions of dollars)
Income (Loss) (millions of dollars)
Income (Loss) (millions of dollars)
(a) Includes early retirement program expenses and other charges of $165 million in 1993. (b) Includes write-off of phase-in deferrals of $636 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 method at a 2.5% rate.
(Cleveland Electric) (Cleveland Electric)
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
(d) Includes write-off of Perry Unit 2 of $351 million in 1993.
(e) Restated for effects of capitalization of nuclear fuel lease and financing arrangements pursuant to Statement of Financial Accounting Standards 71.
(Cleveland Electric) (Cleveland Electric)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS - ----------------------------------------------------------------------
To the Share Owners of The Toledo [Logo] Edison Company:
We have audited the accompanying balance sheet and statement of preferred stock of The Toledo Edison Company (a wholly owned subsidiary of Centerior Energy Corporation) as of December 31, 1993 and 1992, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1993. These financial statements and the schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of The Toledo Edison Company as of December 31, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
As discussed further in Notes 1 and 9, changes were made in the methods of accounting for nuclear plant depreciation in 1991 and for postretirement benefits other than pensions in 1993.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules of The Toledo Edison Company listed in the Index to Schedules are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Cleveland, Ohio February 14, 1994 (except with respect to the matter discussed in Note 15, as to which the date is March 25, 1994)
(Toledo Edison) (Toledo Edison)
MANAGEMENT'S FINANCIAL ANALYSIS - -------------------------------------------------------------------------------- Results of Operations
1993 VS. 1992
Factors contributing to the 3.1% increase in 1993 operating revenues for The Toledo Edison Company (Company) are as follows:
The net revenue increase resulted primarily from the different weather conditions and the changes in the composition of the sales mix among customer categories. Weather accounted for approximately $17 million of the higher 1993 revenues. Hot summer weather in 1993 boosted residential and commercial kilowatt-hour sales. In contrast, the 1992 summer was the coolest in 56 years in Northwestern Ohio. Residential and commercial sales also increased as a result of colder late-winter temperatures in 1993 which increased electric heating-related demand. Residential and commercial sales increased 5.1% and 3.2%, respectively, in 1993. Industrial sales increased 6% as a result of increased sales to large automotive manufacturers, petroleum refiners and the broad-based, smaller industrial customer group. Other sales decreased 18.4% because of fewer sales to wholesale customers. Generating plant outages and retail customer demand limited power availability for bulk power transactions. As a result, total sales decreased 2.2% in 1993. Base rates and miscellaneous revenues decreased in 1993 primarily from lower revenues under contracts having reduced rates with certain large customers and a declining rate structure tied to usage. The contracts have been negotiated to meet competition and encourage economic growth. The net increase in 1993 fuel cost recovery revenues resulted from changes in the fuel cost factors. The weighted average of these factors increased about 2%.
Operating expenses increased 12.6% in 1993. The increase in total operation and maintenance expenses resulted from the $88 million of net benefit expenses related to an early retirement program, called the Voluntary Transition Program (VTP), other charges totaling $19 million and a slight increase in other operation and maintenance expenses. The VTP benefit expenses consisted of $75 million of costs for the Company plus $13 million for the Company's pro rata share of the costs for its affiliate, Centerior Service Company (Service Company). Other charges recorded at year-end 1993 related to a performance improvement plan for Perry Nuclear Power Plant Unit 1 (Perry Unit 1), postemployment benefits and other expense accruals. See Note 9 for information on retirement and postemployment benefits. Deferred operating expenses decreased because of the write-off of the phase-in deferred operating expenses in 1993 as discussed in Note 7. Federal income taxes decreased as a result of lower pretax operating income.
As discussed in Note 4(b), $232 million of our Perry Nuclear Power Plant Unit 2 (Perry Unit 2) investment was written off in 1993. Credits for carrying charges recorded in nonoperating income decreased because of the write-off of the phase-in deferred carrying charges in 1993 as discussed in Note 7. The federal income tax credit for nonoperating income in 1993 resulted from the write-offs.
1992 VS. 1991
Factors contributing to the 4.8% decrease in 1992 operating revenues are as follows:
The revenue decreases resulted primarily from the different weather conditions and the changes in the composition of the sales mix among customer categories. Weather accounted for approximately $22 million of the lower 1992 revenues. Winter and spring in 1992 were milder than in 1991. In addition, the cooler summer in 1992 contrasted with the summer of 1991 which was much hotter than normal. Total kilowatt-hour sales increased 0.2% in 1992. Residential and commercial sales decreased 4.9% and 3.8%, respectively, as moderate temperatures in 1992 reduced electric heating and cooling demands. Industrial sales increased 0.6% as increased sales to glass and metal manufacturers and to the broad-based, smaller industrial customer group offset lower sales to petroleum refining and auto manufacturing customers. Other sales increased 5.2% because of increased sales to wholesale customers. Operating revenues in 1991 included the recognition of $24 million of deferred revenues over the period of a refund to customers under a provision of a January 1989 rate order. No such revenues were reflected in 1992 as the refund period ended in December 1991.
Operating expenses decreased 4.4% in 1992. A reduction of $14 million in other operation and maintenance expenses resulted primarily from cost-cutting measures. Lower fuel and purchased power expense resulted from less amortization of previously deferred fuel costs than the amount amortized in 1991. These decreases were par- tially offset by higher depreciation and amortization, caused primarily by the adoption of the new accounting
(Toledo Edison) (Toledo Edison) standard for income taxes (SFAS 109) in 1992, and by higher taxes, other than federal income taxes, caused by increased Ohio property taxes. Deferred operating expenses increased as a result of the deferrals under the Rate Stabilization Program discussed in Note 7.
The federal income tax provision for nonoperating income decreased because of a greater tax allocation of interest charges to nonoperating activities. Credits for carrying charges recorded in nonoperating income increased primarily because of Rate Stabilization Program carrying charge credits. Interest charges decreased as a result of debt refinancings at lower interest rates and lower short-term borrowing requirements. Outlook RECENT ACTIONS
In January 1994, Centerior Energy Corporation (Centerior Energy), along with the Company and The Cleveland Electric Illuminating Company (Cleveland Electric), announced a comprehensive strategic action plan to strengthen their financial and competitive positions. The Company and Cleveland Electric are the two wholly owned electric utility subsidiaries of Centerior Energy. The plan established specific objectives and was designed to guide Centerior Energy and its subsidiaries through the year 2001. Several actions were taken at that time. Centerior Energy reduced its quarterly common stock dividend from $.40 per share to $.20 per share effective with the dividend payable February 15, 1994. This action was taken because projected financial results did not support continuation of the dividend at its former rate. The Company and Cleveland Electric also wrote off their investments in Perry Unit 2 and certain deferred charges related to a January 1989 rate agreement (phase-in deferrals). The aggregate after-tax effect of these write-offs for the Company was $332 million which resulted in a net loss in 1993 and a retained earnings deficit. The write-offs are discussed in Notes 4(b) and 7. The Company also recognized other one-time charges totaling $15 million after taxes related to a performance improvement plan for Perry Unit 1, postemployment benefits and other expense accruals.
Also contributing to the net loss in 1993 was a charge of $36 million after taxes representing a portion of the VTP costs. The Company will realize approximately $20 million of savings in annual payroll and benefit costs beginning in 1994 as a result of the VTP.
STRATEGIC PLAN
The objectives of the strategic plan are to maximize share owner return on Centerior Energy common stock from corporate assets and resources, achieve profitable revenue growth, become an industry leader in customer satisfaction, build a winning team and attain increasingly competitive power supply costs. To achieve these objectives, the Company will continue controlling its operation and maintenance expenses and capital expenditures, reduce its outstanding debt, increase revenues by finding new uses for existing assets and resources, implement a broad range of new marketing programs, increase revenues by restructuring rates for various customers where appropriate, improve the operating performance of its plants and take other appropriate actions.
COMMON STOCK DIVIDENDS
In recent years, the Company has retained all of its earnings available for common stock. The Company has not paid a common stock dividend to Centerior Energy since February 1991. Because the Company is currently prohibited from paying a common stock dividend by a provision in its mortgage (see Note 11(b)), the Company does not expect to pay any common stock dividends in the foreseeable future.
COMPETITION
Our electric rates are among the highest in our region because we are recovering the substantial investment in our nuclear construction program. Accordingly, some of our customers continue to seek less costly alternatives, including switching to or working to create a municipal electric system. There are a number of rural and municipal systems in our service area. In addition, we face threats of other municipalities in our service area establishing new systems. We have entered into agreements with some of the communities which considered establishing systems. Accordingly, they will not proceed with such development at this time in return for rate concessions and/or economic development funds. Others have determined that developing a system was not feasible. We will continue to address municipal system threats through aggressive marketing programs and emphasizing to our customers the value of our service and the risks of a municipal system.
The Energy Policy Act of 1992 (Energy Act) will provide additional competition in the electric utility industry by requiring utilities to wheel to municipal systems in their service areas electricity from other utilities. This provision of the Energy Act should not significantly increase the competitive threat to us since the operating licenses for our nuclear units have required us to wheel to municipal systems in our service area since 1977. The Energy Act also created a class of exempt wholesale generators which may increase competition in the wholesale power market. A further risk is the possibility that the government could mandate that utilities deliver power from another utility or generation source to their retail customers. We have entered into contracts with many of our
(Toledo Edison) (Toledo Edison)
large industrial and commercial customers which have remaining terms of one to five years. We will attempt to renew those contracts as they expire which will help us compete if retail wheeling is permitted in the future.
RATE MATTERS
Our Rate Stabilization Program remains in effect. Under this program, we agreed to freeze base rates until 1996 and limit rate increases through 1998. In exchange, we are permitted to defer through 1995 and subsequently recover certain costs not currently recovered in rates and to accelerate the amortization of certain benefits. The amortization and recovery of the deferrals will begin with future rate recognition and will continue over the average life of the related assets, or approximately 30 years. The continued use of these regulatory accounting measures will be dependent upon our continuing assessment and conclusion that there will be probable recovery of such deferrals in future rates.
The analysis leading to the year-end 1993 financial actions and strategic plan also included an evaluation of our regulatory accounting measures. We 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 measures to the extent we have in the past.
NUCLEAR OPERATIONS
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 extensions of scheduled outages because of equipment problems or new regulatory requirements. A major accident at a nuclear facility anywhere in the world could cause the Nuclear Regulatory Commission (NRC) to limit or prohibit the operation or licensing of any nuclear unit. If one of our nuclear units is taken out of service for an extended period of time for any reason, including an accident at such unit or any other nuclear facility, we cannot predict whether regulatory authorities would impose unfavorable rate treatment. Such treatment could include taking our affected unit out of rate base or disallowing certain construction or maintenance costs. An extended outage of one of our nuclear units coupled with unfavorable rate treatment could have a material adverse effect on our financial condition and results of operations.
We externally fund the estimated costs for the future decommissioning of our nuclear units. In 1993, we increased our decommissioning expense accruals for revisions in our cost estimates. We expect the increases associated with the new estimates will be recoverable in future rates. See Note 1(f).
HAZARDOUS WASTE DISPOSAL SITES
The Comprehensive Environmental Response, Compensation and Liability Act of 1980 as amended (Superfund) established programs addressing the cleanup of hazardous waste disposal sites, emergency preparedness and other issues. The Company is aware of its potential involvement in the cleanup of several sites. Although these sites are not on the Superfund National Priorities List, they are generally being administered by various governmental entities in the same manner as they would be administered if they were on such list. The allegations that the Company disposed of hazardous waste at these sites and the amounts involved are often unsubstantiated and subject to dispute. Superfund provides that all "potentially responsible parties" (PRPs) to a particular site can be held liable on a joint and several basis. Consequently, if the Company were held liable for 100% of the cleanup costs of all of the sites referred to above, the cost could be as high as $150 million. However, we believe that the actual cleanup costs will be substantially lower than $150 million, that the Company's share of any cleanup costs will be substantially less than 100% and that most of the other PRPs are financially able to contribute their share. The Company has accrued a liability totaling $6 million 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 will not have a material adverse effect on our financial condition or results of operations.
1993 TAX ACT
The Revenue Reconciliation Act of 1993 (1993 Tax Act), which was enacted in August 1993, provided for a 35% income tax rate in 1993. The 1993 Tax Act did not materially impact the results of operations for 1993, but did affect certain Balance Sheet accounts as discussed in Note 8. The 1993 Tax Act is not expected to materially impact future results of operations or cash flow.
INFLATION
Although the rate of inflation has eased in recent years, we are still affected by even modest inflation which causes increases in the unit cost of labor, materials and services.
Capital Resources and Liquidity
1991-1993 CASH REQUIREMENTS
We need cash for normal corporate operations, the mandatory retirement of securities and an ongoing pro-
(Toledo Edison) (Toledo Edison) gram of constructing new facilities and modifying existing facilities. The construction program is needed to meet anticipated demand for electric service, comply with governmental regulations and protect the environment. Over the three-year period of 1991-1993, these construction and mandatory retirement needs totaled approximately $440 million. In addition, we exercised various options to redeem approximately $490 million of our securities.
We raised $815 million through security issues and term bank loans during the 1991-1993 period as shown in the Cash Flows statement. During the three-year period, the Company also utilized its short-term borrowing arrangements to help meet its cash needs.
Although the write-offs of Perry Unit 2 and the phase-in deferrals in 1993 negatively affected our earnings, they did not adversely affect our current cash flow.
1994 AND BEYOND CASH REQUIREMENTS
Estimated cash requirements for 1994-1998 for the Company are $249 million for its construction program and $324 million for the mandatory redemption of debt and preferred stock. The Company expects to finance internally all of its 1994 cash requirements of approximately $109 million. About 15% of the Company's 1995-1998 requirements are expected to be financed externally. If economical, additional securities may be redeemed under optional redemption provisions, which will help improve the Company's capitalization structure and interest coverage ratios.
Our capital requirements are dependent upon our implementation strategy to achieve compliance with the Clean Air Act Amendments of 1990 (Clean Air Act). Cash expenditures for our plan are estimated to be approximately $41 million over the 1994-1998 period. See Note 4(a).
LIQUIDITY
Additional first mortgage bonds may be issued by the Company under its mortgage on the basis of property additions, cash or refundable first mortgage bonds. Under its mortgage, the Company may issue first mortgage bonds on the basis of property additions and, under certain circumstances, refundable bonds only if the applicable interest coverage test is met. At December 31, 1993, the Company would have been permitted to issue approximately $323 million of additional first mortgage bonds.
As discussed in Note 11(d), certain unsecured debt agreements contain covenants relating to capitalization, fixed charge coverage ratios and secured financings. The write-offs recorded at December 31, 1993 caused the Company, Cleveland Electric and Centerior Energy to violate certain of those covenants. The affected creditors have waived those violations in exchange for commitments to provide them with a second mortgage security interest on property of the Company and Cleveland Electric and other considerations. We expect to complete this process in the second quarter of 1994. We will provide the same security interest to certain other creditors because their agreements require equal treatment. We expect to provide second mortgage collateral for $172 million of unsecured debt, $228 million of bank letters of credit and a $205 million revolving credit facility. The bank letters of credit and revolving credit facility are joint and several obligations of the Company and Cleveland Electric. For the next five years, the Company does not expect to raise funds through the sale of debt junior to 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 mortgage referred to above. The Company also is able to raise funds through the sale of preference stock. The Company will be unable to issue preferred stock until it can meet the interest and preferred dividend coverage test in its articles of incorporation.
The Company currently cannot sell commercial paper because of its low commercial paper ratings by Standard & Poor's Corporation (S&P) and Moody's Investors Service, Inc. (Moody's) of "B" and "Not Prime", respectively. The Company is a party to a $205 million revolving credit facility which will run through mid-1996. However, we currently cannot draw on this facility because the write-offs taken at year-end 1993 caused the Company, Cleveland Electric and Centerior Energy to fail to meet certain capitalization and fixed charge coverage covenants. We expect to have this facility available to us again after it is amended in the second quarter of 1994 to provide the participating creditors with a second mortgage security interest.
These financing resources are expected to be sufficient for the Company's needs over the next several years. The availability and cost of capital to meet the Company's external financing needs, however, also depend upon such factors as financial market conditions and its credit ratings. Current credit ratings for the Company are as follows:
These ratings reflect a downgrade in December 1993. In addition, S&P has issued a negative outlook for the Company.
(Toledo Edison) (Toledo Edison)
INCOME STATEMENT THE TOLEDO EDISON COMPANY - ----------------------------------------------------------------------
RETAINED EARNINGS - ----------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
(Toledo Edison) (Toledo Edison)
CASH FLOWS THE TOLEDO EDISON COMPANY - ----------------------------------------------------------------------
The accompanying notes are an integral part of this statement.
(Toledo Edison) (Toledo Edison)
[THIS PAGE INTENTIONALLY LEFT BLANK]
BALANCE SHEET - ----------------------------------------------------------------------
The accompanying notes are an integral part of this statement.
(Toledo Edison) (Toledo Edison)
The Toledo Edison Company
(Toledo Edison) (Toledo Edison)
STATEMENT OF PREFERRED STOCK THE TOLEDO EDISON COMPANY - --------------------------------------------------------------------------------
The accompanying notes are an integral part of this statement.
(Toledo Edison) (Toledo Edison)
NOTES TO THE FINANCIAL STATEMENTS - -------------------------------------------------------------------------------- (1) Summary of Significant Accounting Policies (A) GENERAL
The Company is an electric utility and a wholly owned subsidiary of Centerior Energy. Centerior Energy has two other wholly owned subsidiaries, Cleveland Electric and the Service Company. The Company follows the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by The Public Utilities Commission of Ohio (PUCO). As a rate-regulated utility, the Company is subject to Statement of Financial Accounting Standards (SFAS) 71 which governs accounting for the effects of certain types of rate regulation.
The Company is a member of the Central Area Power Coordination Group (CAPCO). Other members are Cleveland Electric, Duquesne Light Company, Ohio Edison Company and its wholly owned subsidiary, Pennsylvania Power Company. The members have constructed and operate generation and transmission facilities for their use.
(B) RELATED PARTY TRANSACTIONS
Operating revenues, operating expenses and interest charges include those amounts for transactions with affiliated companies in the ordinary course of business operations.
The Company's transactions with Cleveland Electric are primarily for firm power, interchange power, transmission line rentals and jointly owned power plant operations and construction. See Notes 2 and 3.
The Service Company provides management, financial, administrative, engineering, legal and other services at cost to the Company and other affiliated companies. The Service Company billed the Company $76 million, $60 million and $61 million in 1993, 1992 and 1991, respectively, for such services.
(C) REVENUES
Customers are billed on a monthly cycle basis for their energy consumption based on rate schedules or contracts authorized by the PUCO or on ordinances of individual municipalities. An accrual is made at the end of each month to record the estimated amount of unbilled revenues for kilowatt-hours sold in the current month but not billed by the end of that month.
A fuel factor is added to the base rates for electric service. This factor is designed to recover from customers the costs of fuel and most purchased power. It is reviewed and adjusted semiannually in a PUCO proceeding.
(D) FUEL EXPENSE
The cost of fossil fuel is charged to fuel expense based on inventory usage. The cost of nuclear fuel, including an interest component, is charged to fuel expense based on the rate of consumption. Estimated future nuclear fuel disposal costs are being recovered through the base rates.
The Company defers the differences between actual fuel costs and estimated fuel costs currently being recovered from customers through the fuel factor. This matches fuel expenses with fuel-related revenues.
Owners of nuclear generating plants are assessed by the federal government for the cost of decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy. The assessments are based upon the amount of enrichment services used in prior years and cannot be imposed for more than 15 years. The Company has accrued a liability for its share of the total assessments. These costs have been recorded in a deferred charge account since the PUCO is allowing the Company to recover the assessments through its fuel cost factors.
(E) DEFERRED CARRYING CHARGES AND OPERATING EXPENSES
The PUCO authorized the Company to defer operating expenses and carrying charges for Perry Unit 1 and Beaver Valley Power Station Unit 2 (Beaver Valley Unit 2) from their respective in-service dates in 1987 through December 1988. The annual amortization and recovery of these deferrals, called pre-phase-in deferrals, are $7 million which began in January 1989 and will continue over the lives of the related property.
Beginning in January 1989, the Company deferred certain operating expenses and both interest and equity carrying charges pursuant to a PUCO-approved rate phase-in plan for its investments in Perry Unit 1 and Beaver Valley Unit 2. These deferrals, called phase-in deferrals, were written off at December 31, 1993. See Note 7.
The Company also defers certain costs not currently recovered in rates under a Rate Stabilization Program approved by the PUCO in October 1992. See Notes 7 and 14.
(F) DEPRECIATION AND AMORTIZATION
The cost of property, plant and equipment is depreciated over their estimated useful lives on a straight-line basis. The annual straight-line depreciation provision for nonnuclear property expressed as a percent of average depreciable utility plant in service was 3.6% in both 1993 and 1992 and 3.4% in 1991. Effective January 1, 1991, the Company, after obtaining PUCO approval, changed its method of accounting for nuclear plant depreciation from the units-of-production method to the straight-line method at about a 3% rate. This change decreased 1991 depreciation expense $14 million and increased 1991 net
(Toledo Edison) (Toledo Edison)
income $11 million (net of $3 million of income taxes) from what they otherwise would have been. The PUCO subsequently approved in 1991 a change to lower the 3% rate to 2.5% retroactive to January 1, 1991.
Pursuant to a PUCO order, the Company currently uses external funding for the future decommissioning of its nuclear units at the end of their licensed operating lives. The estimated costs are based on the NRC's DECON method of decommissioning (prompt decontamination). Cash contributions are made to the trust funds on a straight-line basis over the remaining licensing period for each unit. The current level of annual expense being recovered from customers based on prior estimates is approximately $4 million. However, actual decommissioning costs are expected to significantly exceed those estimates. Current site-specific estimates for the Company's share of the future decommissioning costs are $41 million in 1992 dollars for Beaver Valley Unit 2 and $87 million and $146 million in 1993 dollars for Perry Unit 1 and the Davis-Besse Nuclear Power Station (Davis-Besse), respectively. The estimates for Perry Unit 1 and Davis-Besse are preliminary and are expected to be finalized by the end of the second quarter of 1994. The Company used these estimates to increase its decommissioning expense accruals in 1993. It is expected that the increases associated with the revised cost estimates will be recoverable in future rates. In the Balance Sheet at December 31, 1993, Accumulated Depreciation and Amortization included $34 million of decommissioning costs previously expensed and the earnings on the external funding. This amount exceeds the Balance Sheet amount of the external Nuclear Plant Decommissioning Trusts because the reserve began prior to the external trust funding.
(G) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment are stated at original cost less amounts ordered by the PUCO to be written off. Construction costs include related payroll taxes, pensions, fringe benefits, management and general overheads and allowance for funds used during construction (AFUDC). AFUDC represents the estimated composite debt and equity cost of funds used to finance construction. This noncash allowance is credited to income. The AFUDC rate was 10.22% in 1993 and 10.96% in both 1992 and 1991.
Maintenance and repairs are charged to expense as incurred. The cost of replacing plant and equipment is charged to the utility plant accounts. The cost of property retired plus removal costs, after deducting any salvage value, is charged to the accumulated provision for depreciation.
(H) DEFERRED GAIN AND LOSS FROM SALES OF UTILITY PLANT The sale and leaseback transactions discussed in Note 2 resulted in a net gain for the sale of the Bruce Mansfield Generating Plant (Mansfield Plant) and a net loss for the sale of Beaver Valley Unit 2. The net gain and net loss were deferred and are being amortized over the terms of leases. These amortizations and the lease expense amounts are recorded as other operation and maintenance expenses.
(I) INTEREST CHARGES Debt Interest reported in the Income Statement does not include interest on obligations for nuclear fuel under construction. That interest is capitalized. See Note 6.
Losses and gains realized upon the reacquisition or redemption of long-term debt are deferred, consistent with the regulatory rate treatment. Such losses and gains are either amortized over the remainder of the original life of the debt issue retired or amortized over the life of the new debt issue when the proceeds of a new issue are used for the debt redemption. The amortizations are included in debt interest expense.
(J) FEDERAL INCOME TAXES The Financial Accounting Standards Board (FASB) issued SFAS 109, a new standard for accounting for income taxes, in February 1992. We adopted the new standard in 1992. The standard amended certain provisions of SFAS 96 which we had previously adopted. Adoption of SFAS 109 in 1992 did not materially affect our results of operations, but did affect certain Balance Sheet accounts. See Note 8.
The financial statements reflect the liability method of accounting for income taxes. This method requires that deferred taxes be recorded for all temporary differences between the book and tax bases of assets and liabilities. The majority of these temporary differences are attributable to property-related basis differences. Included in these basis differences is the equity component of AFUDC, which will increase future tax expense when it is recovered through rates. Since this component is not recognized for tax purposes, we must record a liability for our tax obligation. The PUCO permits recovery of such taxes from customers when they become payable. Therefore, the net amount due from customers through rates has been recorded as a deferred charge and will be recovered over the lives of the related assets.
Investment tax credits are deferred and amortized over the lives of the applicable property as a reduction of depreciation expense. See Note 7 for a discussion of the amortization of certain unrestricted excess deferred taxes and unrestricted investment tax credits under the Rate Stabilization Program.
(Toledo Edison) (Toledo Edison)
(2) Utility Plant Sale and Leaseback Transactions
The Company and Cleveland Electric are co-lessees of 18.26% (150 megawatts) of Beaver Valley Unit 2 and 6.5% (51 megawatts), 45.9% (358 megawatts) and 44.38% (355 megawatts) of Units 1, 2 and 3 of the Mansfield Plant, respectively, all for terms of about 29 1/2 years. These leases are the result of sale and leaseback transactions completed in 1987.
Under these leases, the Company and Cleveland Electric are responsible for paying all taxes, insurance premiums, operation and maintenance expenses and all other similar costs for their interests in the units sold and leased back. They may incur additional costs in connection with capital improvements to the units. The Company and Cleveland Electric have options to buy the interests back at the end of the leases for the fair market value at that time or to renew the leases. Additional lease provisions provide other purchase options along with conditions for mandatory termination of the leases (and possible repurchase of the leasehold interests) for events of default. These events include noncompliance with several financial covenants discussed in Note 11(d).
As co-lessee with Cleveland Electric, the Company is also obligated for Cleveland Electric's lease payments. If Cleveland Electric is unable to make its payments under the Mansfield Plant leases, the Company would be obligated to make such payments. No payments have been made on behalf of Cleveland Electric to date.
In April 1992, nearly all of the outstanding Secured Lease Obligation Bonds (SLOBs) issued by a special purpose corporation in connection with financing the sale and leaseback of Beaver Valley Unit 2 were refinanced through a tender offer and the sale of new bonds having a lower interest rate. As part of the refinancing transaction, the Company paid $43 million as supplemental rent to fund transaction expenses and part of the tender premium. This amount has been deferred and is being amortized over the remaining lease term. The refinancing transaction reduced the annual rental expense for the Beaver Valley Unit 2 lease by $9 million.
Future minimum lease payments under the operating leases at December 31, 1993 are summarized as follows:
Rental expense is accrued on a straight-line basis over the terms of the leases. The amount recorded in 1993, 1992 and 1991 as annual rental expense for the Mansfield Plant leases was $45 million. The amounts recorded in 1993, 1992 and 1991 as annual rental expense for the Beaver Valley Unit 2 lease were $63 million, $66 million and $72 million, respectively. Amounts charged to expense in excess of the lease payments are classified as Accumulated Deferred Rents in the Balance Sheet.
The Company is selling 150 megawatts of its Beaver Valley Unit 2 leased capacity entitlement to Cleveland Electric. We anticipate that this sale will continue indefinitely. Revenues recorded for this transaction were $103 million, $108 million and $107 million in 1993, 1992 and 1991, respectively. The future minimum lease payments through the year 2017 associated with Beaver 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 Company as a tenant in common with other utilities and Lessors:
(Toledo Edison) (Toledo Edison)
(4) Construction and Contingencies (A) CONSTRUCTION PROGRAM
The estimated cost of the Company's construction program for the 1994-1998 period is $259 million, including AFUDC of $10 million and excluding nuclear fuel.
The Clean Air Act will require, among other things, significant reductions in the emission of sulfur dioxide in two phases over a ten-year period and nitrogen oxides by fossil-fueled generating units.
Our compliance strategy provides for compliance with both phases through at least 2005 primarily through greater use of low-sulfur coal at some of our units and the banking of emission allowances. The plan will require capital expenditures over the 1994-2003 period of approximately $57 million for nitrogen oxide control equipment, emission monitoring equipment and plant modifications. In addition, higher fuel and other operation and maintenance expenses may be incurred. The anticipated rate increase associated with the capital expenditures and higher expenses would be less than 2% over the ten-year period. The PUCO has approved this plan. We also are seeking United States Environmental Protection Agency (U.S. EPA) approval of the first phase of our plan.
We are continuing to monitor developments in new technologies that may be incorporated into our compliance strategy. If a different plan is required by the U.S. EPA, significantly higher capital expenditures could be required during the 1994-2003 period. We believe Ohio law permits the recovery of compliance costs from customers in rates.
(B) PERRY UNIT 2
Perry Unit 2, including its share of the facilities common with Perry Unit 1, was approximately 50% complete when construction was suspended in 1985 pending consideration of various options. These options included resumption of full construction with a revised estimated cost, conversion to a nonnuclear design, sale of all or part of our ownership share, or cancellation.
We wrote off our investment in Perry Unit 2 at December 31, 1993 after we determined that it would not be completed or sold. The write-off totaled $232 million ($167 million after taxes) for the Company's 19.91% ownership share of the unit. See Note 14.
(C) HAZARDOUS WASTE DISPOSAL SITES
The Company is aware of its potential involvement in the cleanup of several hazardous waste disposal sites. The Company has accrued a liability totaling $6 million 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 will not have a material adverse effect on our financial condition or results of operations. See Management's Financial Analysis -- Outlook-Hazardous Waste Disposal Sites.
(5) Nuclear Operations and Contingencies (A) OPERATING NUCLEAR UNITS
The Company's three nuclear units may be impacted by activities or events beyond our control. An extended outage of one of our nuclear units for any reason, coupled with any unfavorable rate treatment, could have a material adverse effect on our financial condition and results of operations. See discussion of these risks in Management's Financial Analysis -- Outlook-Nuclear Operations.
(B) NUCLEAR INSURANCE
The Price-Anderson Act limits the liability of the owners of a nuclear power plant to the amount provided by private insurance and an industry assessment plan. In the event of a nuclear incident at any unit in the United States resulting in losses in excess of the level of private insurance (currently $200 million), the Company's maximum potential assessment under that plan would be $70 million (plus any inflation adjustment) per incident. The assessment is limited to $9 million per year for each nuclear incident. These assessment limits assume the other CAPCO companies contribute their proportionate share of any assessment.
The CAPCO companies have insurance coverage for damage to property at the Davis-Besse, Perry and Beaver Valley sites (including leased fuel and clean-up costs). Coverage amounted to $2.75 billion for each site as of January 1, 1994. Damage to property could exceed the insurance coverage by a substantial amount. If it does, the Company's share of such excess amount could have a material adverse effect on its financial condition and results of operations. Under these policies, the Company can be assessed a maximum of $11 million during a policy year if the reserves available to the insurer are inadequate to pay claims arising out of an accident at any nuclear facility covered by the insurer.
The Company also has extra expense insurance coverage. It includes the incremental cost of any replacement power purchased (over the costs which would have been incurred had the units been operating) and other incidental expenses after the occurrence of certain types of accidents at our nuclear units. The amounts of the coverage are 100% of the estimated extra expense per week during the 52-week period starting 21 weeks after an accident and 67% of such estimate per week for the next 104 weeks. The amount and duration of extra expense could substantially exceed the insurance coverage.
(Toledo Edison) (Toledo Edison)
(6) Nuclear Fuel
Nuclear fuel is financed for the Company and Cleveland Electric through leases with a special-purpose corporation. The total amount of financing currently available under these lease arrangements is $382 million ($232 million from intermediate-term notes and $150 million from bank credit arrangements). Financing in an amount up to $750 million is permitted. The intermediate-term notes mature in the period 1994-1997, with $75 million maturing in September 1994. At December 31, 1993, $154 million of nuclear fuel was financed for the Company. The Company and Cleveland Electric severally lease their respective portions of the nuclear fuel and are obligated to pay for the fuel as it is consumed in a reactor. The lease rates are based on various intermediate-term note rates, bank rates and commercial paper rates.
The amounts financed include nuclear fuel in the Davis-Besse, Perry Unit 1 and Beaver Valley Unit 2 reactors with remaining lease payments for the Company of $52 million, $29 million and $20 million, respectively, at December 31, 1993. The nuclear fuel amounts financed and capitalized also included interest charges incurred by the lessors amounting to $6 million in both 1993 and 1992 and $9 million in 1991. The estimated future lease amortization payments based on projected consumption are $49 million in 1994, $42 million in 1995, $37 million in 1996, $33 million in 1997 and $30 million in 1998.
(7) Regulatory Matters
Phase-in deferrals were recorded beginning in 1989 pursuant to the phase-in plan approved by the PUCO in a January 1989 rate order for the Company. The phase-in plan was designed so that the projected revenues resulting from the authorized rate increases and anticipated sales growth provided for the phase-in of certain nuclear costs over a ten-year period. The plan required the deferral of a portion of the operating expenses and both interest and equity carrying charges on the Company's deferred rate-based investments in Perry Unit 1 and Beaver Valley Unit 2 during the early years of the plan. The amortization and recovery of such deferrals were scheduled to be completed by 1998.
As we developed our strategic plan, we evaluated the future recovery of our deferred charges and continued application of the regulatory accounting measures we follow pursuant to PUCO orders. We concluded that projected revenues would not provide for the recovery of the phase-in deferrals as scheduled because of economic and competitive pressures. Accordingly, we wrote off the cumulative balance of the phase-in deferrals. The total phase-in deferred operating expenses and carrying charges written off at December 31, 1993 by the Company were $55 million and $186 million, respectively (totaling $165 million after taxes). See Note 14. While recovery of our other regulatory deferrals remains probable, our current assessment of business conditions has prompted us to change our future plans. We 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 measures to the extent we have in the past.
In October 1992, the PUCO approved a Rate Stabilization Program that was designed to encourage economic growth in the Company's service area by freezing the Company's base rates until 1996 and limiting subsequent rate increases to specified annual amounts not to exceed $89 million over the 1996-1998 period.
As part of the Rate Stabilization Program, the Company is allowed to defer and subsequently recover certain costs not currently recovered in rates and to accelerate amortization of certain benefits. Such regulatory accounting measures provide for rate stabilization by rescheduling the timing of rate recovery of certain costs and the amortization of certain benefits during the 1992-1995 period. The continued use of these regulatory accounting measures will be dependent upon our continuing assessment and conclusion that there will be probable recovery of such deferrals in future rates.
The regulatory accounting measures we are eligible to record through December 31, 1995 include the deferral of post-in-service interest carrying charges, depreciation expense and property taxes on assets placed in service after February 29, 1988 and the deferral of operating expenses equivalent to an accumulated excess rent reserve for Beaver Valley Unit 2 (which resulted from the April 1992 refinancing of SLOBs as discussed in Note 2). The cost deferrals recorded in 1993 and 1992 pursuant to these provisions were $39 million and $32 million, respectively. Amortization and recovery of these deferrals will occur over the average life of the related assets and the remaining lease period, or approximately 30 years, and will commence with future rate recognition. The regulatory accounting measures also provide for the accelerated amortization of certain unrestricted excess deferred tax and unrestricted investment tax credit balances and interim spent fuel storage accrual balances for Davis-Besse. The total amount of such regulatory benefits recognized in 1993 and 1992 pursuant to these provisions was $18 million and $5 million, respectively.
The Rate Stabilization Program also authorized the Company to defer and subsequently recover the incremental expenses associated with the adoption of the accounting standard for postretirement benefits other than pensions (SFAS 106). In 1993, we deferred $37 million pursuant to this provision. Amortization and recovery of this
(Toledo Edison) (Toledo Edison) deferral will commence prior to 1998 and is expected to be completed by no later than 2012. See Note 9(b).
(8) Federal Income Tax
Federal income tax, computed by multiplying income before taxes by the statutory rate (35% in 1993 and 34% in both 1992 and 1991), is reconciled to the amount of federal income tax recorded on the books as follows:
Federal income tax expense is recorded in the Income Statement as follows:
The Company joins in the filing of a consolidated federal income tax return with its affiliated companies. The method of tax allocation reflects the benefits and burdens realized by each company's participation in the consolidated tax return, approximating a separate return result for each company.
In August 1993, the 1993 Tax Act was enacted. Retroactive to January 1, 1993, the top marginal corporate income tax rate increased to 35%. The change in tax rate increased Accumulated Deferred Federal Income Taxes for the future tax obligation by approximately $29 million. Since the PUCO has historically permitted recovery of such taxes from customers when they become payable, the deferred charge, Amounts Due from Customers for Future Federal Income Taxes, also was increased by $29 million. The 1993 Tax Act is not expected to materially impact future results of operations or cash flow.
Under SFAS 109, temporary differences and carryforwards resulted in deferred tax assets of $178 million and deferred tax liabilities of $649 million at December 31, 1993 and deferred tax assets of $154 million and deferred tax liabilities of $794 million at December 31, 1992. These are summarized as follows:
For tax purposes, net operating loss (NOL) carryforwards of approximately $111 million are available to reduce future taxable income and will expire in 2003 through 2005. The 35% tax effect of the NOLs is $39 million.
The Tax Reform Act of 1986 provides for an alternative minimum tax (AMT) credit to be used to reduce the regular tax to the AMT level should the regular tax exceed the AMT. AMT credits of $77 million are available to offset future regular tax. The credits may be carried forward indefinitely.
(9) Retirement and Postemployment Benefits
(A) RETIREMENT INCOME PLAN
Prior to December 31, 1993, the Company sponsored a noncontributory pension plan which covered all employee groups. The plan was merged with another plan which covered employees of Cleveland Electric and the Service Company into a single plan on December 31, 1993. The amount of retirement benefits generally depends upon the length of service. Under certain circumstances, benefits can begin as early as age 55. The funding policy is to
(Toledo Edison) (Toledo Edison) comply with the Employee Retirement Income Security Act of 1974 guidelines.
In 1993, the Company offered the VTP, an early retirement program. Operating expenses for 1993 included $59 million of pension plan accruals to cover enhanced VTP benefits and an additional $3 million of pension costs for VTP benefits paid to retirees from corporate funds. The $3 million is not included in the pension data reported below. A credit of $15 million resulting from a settlement of pension obligations through lump sum payments to almost all the VTP retirees partially offset the VTP expenses.
Net pension and VTP costs for 1991 through 1993 were comprised of the following components:
The following table presents a reconciliation of the funded status of the Company's former plan at December 31, 1992 with comparable information for a portion of the merged plan at December 31, 1993. The December 31, 1993 benefit obligation estimates were derived from information for the former plans. Plan assets of the merged plan were allocated based on a pro rata share of the projected benefit obligation.
At December 31, 1993, the settlement (discount) rate and long-term rate of return on plan assets assumptions were 7.25% and 8.75%, respectively. The long-term rate of annual compensation increase assumption was 4.25%. At December 31, 1992, the settlement rate and long-term rate of return on plan assets assumptions were 8.5% and the long-term rate of annual compensation increase assumption was 5%.
Plan assets consist primarily of investments in common stock, bonds, guaranteed investment contracts, cash equivalent securities and real estate.
(B) OTHER POSTRETIREMENT BENEFITS
Centerior Energy sponsors jointly with its subsidiaries a postretirement benefit plan which provides all employee groups certain health care, death and other postretirement benefits other than pensions. The plan is contributory, with retiree contributions adjusted annually. The plan is not funded. A policy limiting the employer's contribution for retiree medical coverage for employees retiring after March 31, 1993 was implemented in February 1993.
The Company adopted SFAS 106, the accounting standard for postretirement benefits other than pensions, effective January 1, 1993. The standard requires the accrual of the expected costs of such benefits during the employees' years of service. Previously, the costs of these benefits were expensed as paid, which is consistent with ratemaking practices. Such costs for the Company totaled $4 million in both 1992 and 1991, which included medical benefits of $3 million in both years. The total amount accrued by the Company for SFAS 106 costs for 1993 was $42 million, of which $1 million was capitalized and $41 million was expensed as other operation and maintenance expenses. In 1993, the Company deferred incremental SFAS 106 expenses totaling $37 million pursuant to a provision of the Rate Stabilization Program. See Note 7.
The components of the total postretirement benefit costs for 1993 were as follows:
These amounts included costs for the Company and a pro rata share of the Service Company's costs.
The accumulated postretirement benefit obligation and accrued postretirement benefit cost at December 31, 1993
(Toledo Edison) (Toledo Edison) for the Company and its share of the Service Company's obligation are summarized as follows:
The Balance Sheet classification of Other Noncurrent Liabilities at December 31, 1993 includes only the Company's accrued postretirement benefit cost of $33 million and excludes the Service Company's portion since the Service Company's total accrued cost is carried on its books.
At December 31, 1993, the settlement rate and the long-term rate of annual compensation increase assumptions were 7.25% and 4.25%, respectively. The assumed annual health care cost trend rates (applicable to gross eligible charges) are 9.5% for medical and 8% for dental in 1994. Both rates reduce gradually to a fixed rate of 4.75% in 1996 and later years. Elements of the obligation affected by contribution caps are significantly less sensitive to the health care cost trend rate than other elements. If the assumed health care cost trend rates were increased by 1% in each future year, the accumulated postretirement benefit obligation as of December 31, 1993 would increase by $4 million and the aggregate of the service and interest cost components of the annual postretirement benefit cost would increase by $0.3 million.
(C) POSTEMPLOYMENT BENEFITS In 1993, the Company adopted SFAS 112, the new accounting standard which requires the accrual of postemployment benefit costs. Postemployment benefits are the benefits provided to former or inactive employees after employment but before retirement, such as worker's compensation, disability benefits and severance pay. The adoption of this accounting method did not materially affect the Company's 1993 results of operations or financial position.
(10) Guarantees
The Company has guaranteed certain loan and lease obligations of a mining company under a long-term coal purchase arrangement. This arrangement requires payments to the mining company for any actual expenses (as advance payments for coal) when the mines are idle for reasons beyond the control of the mining company. At December 31, 1993, the principal amount of the mining company's loan and lease obligations guaranteed by the Company was $20 million.
(11) Capitalization
(A) CAPITAL STOCK TRANSACTIONS
Preferred stock shares retired during the three years ended December 31, 1993 are listed in the following table.
(B) EQUITY DISTRIBUTION RESTRICTIONS
Federal law prohibits the Company from paying dividends out of capital accounts. However, the Company may pay dividends out of appropriated retained earnings and current earnings. At December 31, 1993, the Company had $42 million of appropriated retained earnings for the payment of preferred stock dividends. The Company is currently prohibited from paying a common stock dividend by a provision in its mortgage.
(C) PREFERRED AND PREFERENCE STOCK
Amounts to be paid for preferred stock which must be redeemed during the next five years are $12 million in each year 1994 through 1996 and $2 million in both 1997 and 1998.
The annual preferred stock mandatory redemption provisions are as follows:
The annualized preferred dividend requirement at December 31, 1993 was $21 million.
The preferred dividend rates on the Company's Series A and B fluctuate based on prevailing interest rates and market conditions. The dividend rates for these issues averaged 7.41% and 8.22%, respectively, in 1993.
Preference stock authorized for the Company is 5,000,000 shares with a $25 par value. No preference shares are currently outstanding.
With respect to dividend and liquidation rights, the Company's preferred stock is prior to its preference stock and common stock, and its preference stock is prior to its common stock.
(Toledo Edison) (Toledo Edison)
(D) LONG-TERM DEBT AND OTHER BORROWING ARRANGEMENTS
Long-term debt, less current maturities, was as follows:
Long-term debt matures during the next five years as follows: $45 million in 1994, $71 million in 1995, $91 million in 1996 and $39 million in both 1997 and 1998.
The Company issued $275 million aggregate principal amount of secured medium-term notes during the 1991-1993 period. The notes are secured by first mortgage bonds.
The Company's mortgage constitutes a direct first lien on substantially all property owned and franchises held by the Company. Excluded from the lien, among other things, are cash, securities, accounts receivable, fuel, supplies and automotive equipment.
Certain unsecured loan agreements of the Company contain covenants relating to capitalization ratios, fixed charge coverage ratios and limitations on secured financing other than through first mortgage bonds or certain other transactions. Two reimbursement agreements relating to separate letters of credit issued in connection with the sale and leaseback of Beaver Valley Unit 2 contain several financial covenants affecting the Company, Cleveland Electric and Centerior Energy. Among these are covenants relating to fixed charge coverage ratios and capitalization ratios. The write-offs recorded at December 31, 1993 caused the Company, Cleveland Electric and Centerior Energy to violate certain covenants contained in the two reimbursement agreements. The affected creditors have waived those violations in exchange for commitments to provide them with a second mortgage security interest on property of the Company and Cleveland Electric and other considerations. We expect to complete this process in the second quarter of 1994. We will provide the same security interest to certain other creditors because their agreements require equal treatment. We expect to provide second mortgage collateral for $172 million of unsecured debt, $228 million of bank letters of credit and a $205 million revolving credit facility. The bank letters of credit and revolving credit facility are joint and several obligations of the Company and Cleveland Electric.
(12) Short-Term Borrowing Arrangements
In May 1993, Centerior Energy arranged for a $205 million, three-year revolving credit facility. The facility may be renewed twice for one-year periods at the option of the participating banks. Centerior Energy and the Service Company may borrow under the facility, with all borrowings jointly and severally guaranteed by the Company and Cleveland Electric. Centerior Energy plans to transfer any of its borrowed funds to the Company and Cleveland Electric, while the Service Company may borrow up to $25 million for its own use. The banks' fee is 0.5% per annum payable quarterly in addition to interest on any borrowings. That fee is expected to increase to 0.625% when the facility agreement is amended as discussed below. There were no borrowings under the facility at December 31, 1993. The facility agreement contains covenants relating to capitalization and fixed charge coverage ratios for the Company, Cleveland Electric and Centerior Energy. The write-offs recorded at December 31, 1993 caused the ratios to fall below those covenant requirements. The revolving credit facility is expected to be available for borrowings after the facility agreement is amended in the second quarter of 1994 to provide the participating creditors with a second mortgage security interest.
Short-term borrowing capacity authorized by the PUCO annually is $150 million for the Company. The Company and Cleveland Electric are authorized by the PUCO to borrow from each other on a short-term basis.
At December 31, 1993, the Company had no commercial paper outstanding. The Company is unable to rely on the sale of commercial paper to provide short-term funds because of its below investment grade commercial paper credit ratings.
(Toledo Edison) (Toledo Edison)
(13) Financial Instruments' Fair Value
The estimated fair values at December 31, 1993 and 1992 of financial instruments that do not approximate their carrying amounts are as follows:
The fair value of the nuclear plant decommissioning trusts is estimated based on the quoted market prices for the investment securities. The fair value of the Company's preferred stock with mandatory redemption provisions and long-term debt is estimated based on the quoted market prices for the respective or similar issues or on the basis of the discounted value of future cash flows. The discounted value used current dividend or interest rates (or other appropriate rates) for similar issues and loans with the same remaining maturities.
The estimated fair values of all other financial instruments approximate their carrying amounts in the Balance Sheet at December 31, 1993 and 1992 because of their short-term nature.
(14) Quarterly Results of Operations (Unaudited)
The following is a tabulation of the unaudited quarterly results of operations for the two years ended December 31, 1993.
Earnings for the quarter ended September 30, 1993 were decreased by $35 million as a result of the recording of $54 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 $232 million write-off of Perry Unit 2 (see Note 4(b)), the $241 million write-off of the phase-in deferrals (see Note 7) and $19 million of other charges. These adjustments decreased quarterly earnings by $345 million.
Earnings for the quarter ended September 30, 1992 were increased by $15 million as a result of the recording of deferred operating expenses and carrying charges for the first nine months of 1992 totaling $22 million under the Rate Stabilization Program approved by the PUCO in October 1992. See Note 7.
(15) Pending Merger of the Company with Cleveland Electric
On March 25, 1994, Centerior Energy announced that its operating utility subsidiaries, the Company and Cleveland Electric, plan to merge into a single operating entity. Since the Company and Cleveland Electric affiliated in 1986, efforts have been made to consolidate operations and administration as much as possible to achieve maximum cost savings. The merger of the two companies into a single entity is the completion of this consolidation process. Various aspects of the merger are subject to the approval of the FERC, the PUCO and other regulatory authorities. The merger must be approved by share owners of the Company's preferred stock. Share owners of Cleveland Electric's preferred stock must approve the authorization of additional shares of preferred stock. Share owners of the Company's preferred stock will exchange their shares for preferred stock shares of the successor corporation having substantially the same terms, while Cleveland Electric's preferred stock will automatically become shares of the successor corporation. Debt holders of the merging companies will become debt holders of the successor corporation. The merging companies plan to seek preferred stock share owner approval in the summer of 1994. The merger is expected to be effective in late 1994.
For the merging companies, the combined pro forma operating revenues were $2.475 billion, $2.439 billion and $2.561 billion and the combined pro forma net income (loss) was $(876) million, $276 million and $296 million for the years ended December 31, 1993, 1992 and 1991, respectively. The pro forma data is based on accounting for the merger on a method similar to a pooling of interests. The pro forma data is not necessarily indicative of the results of operations which would have been reported had the merger been in effect during those years or which may be reported in the future. The pro forma data should be read in conjunction with the audited financial statements of both the Company and Cleveland Electric.
(Toledo Edison) (Toledo Edison)
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(a) Includes early retirement program expenses 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.
(Toledo Edison) (Toledo Edison)
The Toledo Edison Company
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(d) Includes write-off of Perry Unit 2 of $232 million in 1993.
(e) Restated for effects of capitalization of nuclear fuel lease and financing arrangements pursuant to Statement of Financial Accounting Standards 71.
(Toledo Edison) (Toledo Edison)
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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES AND THE TOLEDO EDISON COMPANY COMBINED PRO FORMA CONDENSED FINANCIAL STATEMENTS
The 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.
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P-2 COMBINED PRO FORMA CONDENSED INCOME STATEMENTS OF CLEVELAND ELECTRIC AND TOLEDO EDISON (Unaudited) (Millions of Dollars)
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. (E) Elimination of intercompany interest income and interest expense. (R) Rounding adjustments.
P-4 EXHIBIT INDEX
The exhibits designated with an 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.)
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Pursuant to Paragraph (b)(4)(iii)(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 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 $.25 per page, plus any postage or shipping expenses which would be incurred by the Registrants.
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