Item 1. Business - -----------------
THE CENTERIOR SYSTEM --------------------
Centerior Energy is a public utility holding company and the parent company of six wholly owned subsidiaries, including 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 population of about 2,450,000. At December 31, 1995, the Centerior System had 6,821 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, transmission, 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 electric utility companies and to two municipal electric systems (directly and through AMP-Ohio) in its service area. Cleveland Electric serves approximately 749,000 customers and derives approximately 77% of its total electric retail 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, 1995, Cleveland Electric had 3,636 employees of which about 55% 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 291,000 customers and derives approximately 54% of its total electric retail revenue from customers outside the City of Toledo. Principal industries served by Toledo Edison include 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, 1995, Toledo Edison had 1,809 employees of which about 59% were represented by three unions having collective bargaining agreements with Toledo Edison.
- 1 - 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 provides management, financial, administrative, engineering, legal, governmental and public relations and other services to Centerior Energy and the Operating Companies. At December 31, 1995, the Service Company had 1,373 employees.
Centerior's other three wholly owned subsidiaries are Centerior Properties Company, CCO Company and Market Responsive Energy, Inc. These three subsidiaries, individually or in the aggregate, do not have a material impact on the consolidated financial statements of Centerior.
MERGER OF THE OPERATING COMPANIES ---------------------------------
In March 1994, Centerior Energy announced a plan 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. In May 1994, the Operating Companies filed a joint application for authorization and approval of the merger with the FERC. The PUCO, AMP-Ohio and the cities of Cleveland, Clyde and Bryan, Ohio have intervened in the FERC proceedings. The PUCO intervened as the state commission having jurisdiction, but has not opposed the Cleveland Electric and Toledo Edison application. The PUCO approved the merger in December 1994. The PaPUC approved the merger in July 1994. The other intervenors have opposed the merger citing concerns primarily relating to the merger's impact on competition. In December 1994, the FERC advised the Operating Companies by letter that the application to merge would be rejected unless they provide additional information and file a single system open-access transmission tariff offering comparable service. In May 1995, Cleveland Electric and Toledo Edison filed the additional information requested by the FERC and an open-access transmission tariff offering comparable service. The FERC has deferred action on the merger application until the merits of the Operating Companies' proposed open-access transmission tariffs are addressed in hearings. The Operating Companies do not expect the NRC to take action on their request for authorization to transfer certain NRC licenses to the merged entity until approval has been obtained from the FERC.
On June 14, 1995, special meetings of the preferred stock share owners of each of the Operating Companies was held. Cleveland Electric preferred stock share owners approved the Amended Articles of Incorporation which provide for an increased number of authorized shares of Cleveland Electric preferred stock. Toledo Edison preferred stock share owners approved the Agreement of Merger between Toledo Edison and Cleveland Electric.
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.
- 2 -
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 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.
On October 18, 1995, Cleveland Electric filed a Demand for Arbitration seeking unpaid operating costs of Eastlake Unit 5 which had been invoiced to Duquesne in respect of Duquesne's partial ownership interest in that Unit. In that arbitration proceeding, Duquesne countered with allegations that certain management practices of Cleveland Electric in the operation of Unit 5 have been detrimental to Duquesne. Among the remedies sought by Duquesne is the partition of the property held as tenants in common. On October 24, 1995, Cleveland Electric filed a complaint for injunctive and declaratory relief against Duquesne in Lake County (Ohio) Common Pleas Court seeking a court order prohibiting Duquesne from taking action to partition or sell its ownership interest in Eastlake Unit 5. The Lake County action was removed to the United States District Court for the Northern District of Ohio, Eastern Division. Duquesne subsequently filed counterclaims in the federal court action restating all claims made in the arbitration proceeding.
All of the CAPCO Group companies are members of ECAR, which is comprised of 29 major electric power suppliers and 11 associate members located in nine east-central states, serving 36,000,000 people. ECAR's purpose is to improve reliability of bulk power supply through coordination of planning and operation of member companies' generation and transmission facilities.
- 3 - CONSTRUCTION AND FINANCING PROGRAMS -----------------------------------
Construction Program - --------------------
The Centerior System carries on a continuous program of constructing transmission, distribution and general facilities and modifying existing generating facilities to meet anticipated demand for electric service and to comply with governmental regulations. Centerior Energy's 1995 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 of 0.5% and 1.0%, respectively, after demand-side management considerations. The Centerior System's integrated resource plan for the 1990s (which is included in the long-term forecast) combines peak clipping demand-side management programs with maximum utilization of existing generating capacity to postpone the need for new generating units until the next decade. Lake Shore Unit 18, a 45,000-kilowatt unit which was placed on cold standby status in October 1993, is scheduled to resume active status in 2001.
According to the current long-term integrated resource plan, the Centerior System does not plan to put into service any new generating capacity until 2008.
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 1993, 1994 and 1995 and the estimated cost of their construction programs for 1996 through 2000, in each case including AFUDC and excluding nuclear fuel:
- 4 -
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 1993, 1994 and 1995 and their estimated nuclear fuel capital costs for 1996 through 2000 are as follows:
- 5 - 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 1995; debt and preferred stock redemption requirements during the 1996-2000 period; expected external financing needs during such period; restrictions 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 1996, Cleveland Electric and Toledo Edison expect to complete the sale of a AAA-rated security backed by their accounts receivable, thereby raising approximately $150,000,000. In addition, Cleveland Electric and Toledo Edison plan to arrange for alternate financing to replace $234,000,000 of nuclear fuel financing which expires in 1996 (see Note 6).
On February 28, 1996, Moody's Investors Service, Inc. announced that it had placed its ratings of securities issued by the Operating Companies under review for possible downgrade. The rating agency indicated that the ratings for the following securities were being reviewed: first mortgage bonds, debentures and preferred stock issued by the Operating Companies; secured pollution control bonds and unsecured pollution control notes issued by public authorities and secured by the Operating Companies' first mortgage bonds and notes; and secured lease obligation bonds issued by CTC Beaver Valley Funding Corporation, Beaver Valley II Funding Corporation and CTC Mansfield Funding Corporation which are secured by rental payments made by Cleveland Electric and Toledo Edison.
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.
- 6 - State Utility Commissions - -------------------------
The Operating Companies are subject to the jurisdiction of the PUCO with respect 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 disciplines. 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 the forecast. The PUCO and the OPSB are required to consider the record of such hearings in proceedings for approving facility sites, changing rates, approving security issues and initiating energy conservation programs. In April 1995, the PUCO approved Centerior Energy's 1994 long-term forecast. 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 July 1995, the PUCO approved Centerior's updated environmental compliance plan which was filed in January 1995.
The PUCO has jurisdiction over certain transactions by companies in an electric 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. Consequently, the Operating Companies must obtain PUCO
- 7 - approval to invest in, lend funds to, guarantee the obligations of or otherwise finance or transfer assets to any nonutility company in the Centerior 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, Centerior must obtain PUCO approval to make any investment in any nonutility subsidiaries, affiliates or associates if such investment would cause all such capital investments to exceed 15% of Centerior's consolidated capitalization 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 customers 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 commerce, 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 considerations 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 insurance 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.
- 8 - 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 1996-2000, $45,809,000 and $40,850,000, 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 regulation, the affected company has filed an appeal or has applied for permits, revisions to 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 conducted. 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 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 state implementation plan except for some particulate matter emissions and certain sulfur dioxide emissions.
In November 1990, the Clean Air Act Amendments imposed more stringent restrictions on nitrogen oxide emissions and sulfur dioxide emissions beginning in 1995. See Note 4(a) for a description of the Operating Companies' compliance strategy, which was included in the agreement approved by the PUCO in April 1995 in connection with the Operating Companies' 1994 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.
- 9 - Global warming, or the "greenhouse effect", has been the subject of scientific study and debate within the United States and internationally. One area of study involves the effect on global warming of the emissions of gases such as those resulting from the burning of coal. Based on a 1992 United Nations treaty, the United States has developed a voluntary plan to reduce the emissions of certain gases thought to contribute to global warming to 1990 levels by the year 2000. The Operating Companies will work with the DOE and other utilities to develop a plan for limiting such emissions.
Water Quality Control - ---------------------
The Clean Water Act requires that power plants obtain permits under the NPDES program 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. 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 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 in which a permit application is pending, the affected plant may continue 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.
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.
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 additional effluent limitations are not justified.
In March 1995, the U.S. EPA issued guidelines for water quality standards applicable to all states abutting the Great Lakes, including Ohio. These states are required to adopt state water quality standards and procedures consistent with the guidelines by April 1997. Preliminary reviews indicate that the cost of compliance could be significant. However, the Operating Companies cannot determine the operational impact of compliance until such guidelines are incorporated into Ohio regulations.
- 10 - Waste Disposal - --------------
See "Outlook--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 "Operations--Nuclear Units" for a discussion concerning the disposal of nuclear waste.
The Resource Conservation and Recovery Act exempts certain fossil fuel combustion waste products, such as fly ash, from hazardous waste disposal requirements and requires the U.S. EPA to evaluate the need for future regulation. On August 9, 1994, the U.S. EPA issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary.
ELECTRIC RATES -------------- General - -------
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 construction work in progress in rate base under certain conditions.
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 increase cannot be filed before the issuance of a final order in any prior pending 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.
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 "Operations--Competitive Conditions--Cleveland Electric" for information on a 1994 rate reduction ordinance in Garfield Heights.
- 11 - 1995 Rate Case - --------------
In April 1995, Cleveland Electric and Toledo Edison filed requests with the PUCO for price increases aggregating $119,000,000 annually to be effective in 1996. Cleveland Electric's requested increase of $84,000,000 in annual revenues reflects an average increase of 4.9% in Cleveland Electric's existing prices. Toledo Edison's requested increase of $35,000,000 reflects an average increase of 4.7% in Toledo Edison's existing prices.
The rate increases are necessary to recover capital investment and increases in costs incurred since the Operating Companies' last rate cases, which were decided in January 1989, and to recover certain costs deferred since 1992 pursuant to a Rate Stabilization Program that was approved by the PUCO for the Operating Companies in October 1992.
For a full discussion and analysis of the Operating Companies' 1995 rate case, the Rate Stabilization Program, financial accounting requirements and the potential implications of these accounting requirements for Centerior's and the Operating Companies' results of operations and financial position, see Note 7.
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 3.6% of the 1995 total electric operating revenues of Centerior Energy and Cleveland Electric, respectively. The loss of these facilities would reduce Centerior Energy's and Cleveland Electric's net income by about $28,000,000 based on 1995 sales levels.
The largest customer served by Toledo Edison is a major automobile manufacturer. Sales to this customer accounted for 1.5% and 4.3% of the 1995 total electric operating revenues of Centerior Energy and Toledo Edison, respectively. The loss of this customer would reduce Centerior Energy's and Toledo Edison's net income by about $16,000,000 based on 1995 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 1985 and 1991 through 1995, see the attached Pages and for Centerior Energy, and for Cleveland Electric and and for Toledo Edison.
- 12 - 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 responsibility 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, an additional 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.
In 1989, the PUCO approved nuclear plant performance standards for the Operating Companies based on rolling three-year industry averages of availability for pressurized water reactors and for boiling water reactors over the 1988-1998 period. Availability is the ratio of the number of hours a unit is available to generate electricity (whether or not the unit is operated) to the number of hours in the period, expressed as a percentage. The three-year 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 incremental 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 1993-1995 period (as of October 31, 1995) are 80.9% for pressurized water reactors such as Davis-Besse and Beaver Valley Unit 2 and 76.7% for boiling water reactors such as Perry Unit 1. The 1993-1995 combined availability average for Davis-Besse and Beaver Valley Unit 2 was 88.5% and the availability average for Perry Unit 1 was 61.6%. At December 31, 1995, the total banked benefit for the Operating Companies is estimated to be between $27,000,000 and $31,000,000.
All three nuclear units have received generally favorable evaluations from the NRC in their most recent SALP reviews, with Davis-Besse receiving the best possible scores. 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 maintained 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.
- 13 - The most recent review periods and SALP review scores for Beaver Valley Unit 2, Perry Unit 1 and Davis-Besse are:
In 1980, Congress passed the Low-Level Radioactive Waste Policy Act which provides that the disposal of low-level radioactive waste is the responsibility of the state where such waste is generated. The Act encourages states to form compacts among themselves to develop regional disposal facilities. Failure by a state or compact to begin implementation of a program could result in access denial to the two facilities currently accepting low-level radioactive waste. Ohio is part of the Midwest Compact and has responsibility for siting and constructing a disposal facility. In June 1995, the Ohio legislature authorized the siting, construction and operation of a disposal facility. In addition, the South Carolina legislature voted to allow out-of-region generators (such as Centerior's nuclear units) to resume shipments of low-level radioactive waste to the Barnwell disposal facility. Nonetheless, the Operating Companies' ability to ship offsite in the future depends on whether the State of Ohio proceeds with the development of a low-level radioactive waste disposal facility. As an interim solution to disposal availability, the Operating Companies have constructed storage facilities to house the waste at each nuclear site.
Off-site disposal of spent nuclear fuel is unavailable, but the CAPCO Group companies have contracts with the DOE which provide for the future acceptance of spent fuel for disposal by the federal government. Pursuant to the Nuclear Waste Policy Act of 1982, the federal government has indicated it will begin accepting spent fuel from utilities by the year 2010. On-site storage capacity at Davis-Besse, Perry Unit 1 and Beaver Valley Unit 2 should be sufficient through 2017, 2013 and 2011, respectively.
See Note 4(b) for a discussion of the write-off of Perry Unit 2, and see "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.
- 14 - The Operating Companies also compete with municipally owned electric systems within their respective service areas. Several communities have evaluated municipalization of electric service and decided to continue service from the Operating Companies. Officials in 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 customers to locate in their respective areas.
The Operating Companies 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 interconnections 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, 1996 provide the Centerior System with a net demonstrated capability of 5,996,000 kilowatts during the winter. These facilities include 20 fossil-fired steam electric generating units (3,650,000 kilowatts) at five generation stations; three nuclear generating units (1,856,000 kilowatts); a 351,000 kilowatt share of the Seneca Plant; seven combustion turbine generating units (135,000 kilowatts) and one diesel generator (4,000 kilowatts). In addition, two fossil-fired generating units (320,000 kilowatts) are currently on cold standby status. 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 1995 was 5,779,000 kilowatts and occurred on August 15. The net seasonal capability at the time of the 1995 peak load was 5,924,000 kilowatts. The Centerior System's 1996 native peak load is forecasted to be 5,220,000 kilowatts, after demand-side management considerations. The net seasonal capability expected to be available to serve the Centerior System's 1996 peak is 5,885,000 kilowatts. Over the 1996-1998 period, Centerior Energy forecasts its capacity margins at the time of the projected Centerior System peak loads to range from 10% to 12%, excluding the capacity on cold standby.
Each Operating Company owns the electric transmission and distribution facilities 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, 1996 provide a net demonstrated capability of 4,164,000 kilowatts during the winter. These
- 27 -
facilities include 16 fossil-fired steam electric generating units (2,725,000 kilowatts) at four generation stations; its share of three nuclear generating 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 generator (4,000 kilowatts). In addition, one fossil-fired generating unit (245,000 kilowatts) is currently on cold standby status. 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 1995 was 4,049,000 kilowatts and occurred on August 15. The capacity resources available at the time of the 1995 peak were 4,273,000 kilowatts. Cleveland Electric's 1996 native peak load is forecasted to be 3,700,000 kilowatts, after demand-side management considerations. The capacity resources expected to be available to serve Cleveland Electric's 1996 peak are 4,234,000 kilowatts. Over the 1996-1998 period, Cleveland Electric forecasts its capacity margins at the time of its projected peak loads to range from 12% to 13%, excluding the capacity on cold standby.
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 interconnections 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, 1996 provide a net demonstrated capability of 1,832,000 kilowatts during the winter. These facilities include six fossil-fired steam electric generating units (925,000 kilowatts) at two generation stations; its share of three nuclear generating units (830,000 kilowatts) and five combustion turbine generating units (77,000 kilowatts). In addition, one fossil-fired generating unit (75,000 kilowatts) is currently on cold standby status. 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 1995 was 1,738,000 kilowatts and occurred on August 15. The capacity resources available at the time of the 1995 peak were 1,651,000 kilowatts. Toledo Edison's 1996 native peak load is forecasted to be 1,540,000 kilowatts, after demand-side management considerations. The capacity resources expected to be available to serve Toledo Edison's 1996 peak are 1,651,000 kilowatts. Over the 1996-1998 period, Toledo Edison forecasts its capacity margins at the time of its projected peak loads to range from 3.7% to 7%, excluding the capacity on cold standby.
- 28 - Toledo Edison owns the facilities located in the area it serves for transmitting and distributing power to all its customers. Toledo Edison has interconnections with Ohio Edison, Ohio Power and Detroit Edison. The interconnection 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 interconnections 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 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, and an 18.26% undivided tenant-in-common interest in Beaver Valley Unit 2 located in Shippingport, Pennsylvania. These leases extend through 2017 and are the result of sale and leaseback transactions completed in September 1987. 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, 1995, the cost of Cleveland Electric's facilities, other than water intake and discharge facilities, located on such artificially filled land aggregated approximately $116,650,000. 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 Electric, 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
- 29 - 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.
Cleveland Electric has entered into an agreement with Jersey Central under which Jersey Central will lease Cleveland Electric's ownership share of the Seneca Plant (351,000 kilowatts). The lease will run for a period beginning on June 1, 1996 or on the date of receipt of appropriate regulatory approvals (whichever occurs later) and ending May 31, 2004.
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. As discussed under "Item 1. Business--CAPCO Group", Duquesne is attempting to partition its interest in Eastlake Unit 5.
- 30 -
Item 3.
Item 3. Legal Proceedings - --------------------------
PROCEEDINGS REGARDING AN ATTEMPT BY THE CITY OF CLYDE, OHIO TO REMOVE TOLEDO EDISON. See "Item 1. Business--Operations--Competitive Conditions--Toledo Edison".
PROCEEDINGS BEFORE THE PUCO REGARDING ACTIONS BY THE CITY OF GARFIELD HEIGHTS, OHIO TO REDUCE CLEVELAND ELECTRIC'S RATES WITHIN THE CITY. See "Item 1. Business--Operations--Competitive Conditions--Cleveland Electric".
PROCEEDINGS BEFORE THE FERC REGARDING THE PROPOSED MERGER OF THE OPERATING COMPANIES. See "Item 1. Business--Merger of the Operating Companies".
PROCEEDINGS BEFORE THE PUCO REGARDING THE REQUESTS FOR RATE INCREASES FILED BY THE OPERATING COMPANIES. See "Item 1. Business--Electric Rates--1995 Rate Case".
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. In December 1994, a jury rendered a verdict in favor of Westinghouse on a fraud claim. (The court had previously dismissed four other claims against Westinghouse.) The CAPCO Group companies have appealed the decision to the United States Court of Appeals for the Third Circuit. The Operating Companies believe that the outcome of this lawsuit will not have a materially adverse effect on their financial positions or results of operation.
DUQUESNE LAWSUIT. See "Item 1. Business--CAPCO Group".
PROCEEDINGS BEFORE THE PUCO AND THE FERC REGARDING THE ELECTRIC SERVICE CONTRACT BETWEEN CPP AND MEDICAL CENTER CO. See "Item 1. Business-- Operations--Competitive Conditions--Cleveland Electric".
PROCEEDINGS BEFORE WILLIAMS COUNTY (OHIO) COMMON PLEAS COURT RELATING TO ELECTRIC SERVICE BEING PROVIDED TO CHASE BRASS BY FOUR MUNICIPALS AND AMP-OHIO. See "Item 1. Business--Operations--Competitive Conditions--Toledo Edison".
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders - -------------------------------------------------------------
CENTERIOR ENERGY, CLEVELAND ELECTRIC AND TOLEDO EDISON ------------------------------------------------------
None.
- 31 - 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 1994 and 1995 were as follows:
Share Owners - ------------
As of March 5, 1996, Centerior Energy had 133,729 common stock share owners of record.
Dividends - ---------
See Note 14 to Centerior's Financial Statements for quarterly dividend payments in the last two years. Future dividend action by Centerior's 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.
At December 31, 1995, Centerior Energy had a retained earnings deficit of $336 million and capital surplus of $1.963 billion, resulting in an overall surplus of $1.627 billion that was available to pay dividends under Ohio law. Any current period earnings in 1996 will increase surplus under Ohio law. See Note 11(b) for discussions of dividend restrictions affecting Cleveland Electric and Toledo Edison.
Dividends paid in 1995 on each of the Operating Companies' outstanding series of preferred stock were fully taxable.
Item 6.
Item 6. Selected Financial Data - --------------------------------
CENTERIOR ENERGY ----------------
The information required by this Item is contained on Pages and attached hereto.
- 32 - 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 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 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and - ------------------------------------------------------------------------ Financial Disclosure - --------------------
CENTERIOR ENERGY, CLEVELAND ELECTRIC AND TOLEDO EDISON ------------------------------------------------------
None.
- 33 - 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 7 and Page 15 of Centerior's definitive proxy statement dated March 12, 1996. 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 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 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 and Society National Bank. (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 and Society National Bank. (1993)
Fred J. Lange, Jr. - ------------------
(1993)
*Also a director of Centerior Energy and the Service Company.
- 34 - 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 8 and the information concerning compensation of executive officers, stock option transactions, long-term incentive awards and pension benefits on Pages 21 through 24 of Centerior's definitive proxy statement dated March 12, 1996. 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 1995.
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, 1996:
- 35 - (2) Includes the following numbers of shares which are not owned but could have been purchased within 60 days after February 28, 1996 upon exercise of options to purchase shares of Centerior common stock: Mr. Farling - 10,000; Mr. Edelman - 5,000; Mr. Shelton - 3,400; Mr. Lange - 3,000; Mr. Temple - 2,150; and all directors and executive officers as a group - 33,550. None of those options have been exercised as of March 22, 1996.
(3) Owned by the Sisters of Notre Dame.
CLEVELAND ELECTRIC ------------------
Individual directors of Cleveland Electric, the named executive officers and all directors and executive officers of Cleveland Electric as a group beneficially owned the following number of shares of Centerior common stock as of February 28, 1996:
TOLEDO EDISON -------------
Individual directors of Toledo Edison, the named executive officers and all directors and executive officers of Toledo Edison as a group beneficially owned the following number of shares of Centerior common stock as of February 28, 1996:
- 36 -
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.
- 37 - 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, 1995, Centerior Energy, Cleveland Electric and Toledo Edison did not file any Current Reports on Form 8-K.
- 38 - 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 28, 1996 By J. T. PERCIO ------------------------- J. T. Percio, Secretary
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
- 39 - 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 28, 1996 By J. T. PERCIO ------------------------- J. T. Percio, Secretary
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
- 40 - 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 28, 1996 By J. T. PERCIO ----------------------- J. T. Percio, Secretary
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
- 41 -
INDEX TO -------- SELECTED FINANCIAL DATA; MANAGEMENT'S DISCUSSION ------------------------------------------------ AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF ------------------------------------------------- OPERATIONS; AND FINANCIAL STATEMENTS ------------------------------------
MANAGEMENT'S FINANCIAL ANALYSIS
OUTLOOK
STRATEGIC PLAN
We continued to make progress during the second year of our eight-year strategic plan, but we remain keenly aware of the magnitude of the problems that face us. The strategic plan was created to achieve two major goals: strengthening our financial condition and improving our competitive position. Its objectives are to maximize share owner return, achieve profitable revenue growth, become a leader in customer satisfaction, build a winning employee team and attain increasingly competitive power supply costs. We are not yet positioned to compete in a less regulated electric utility industry, but every major action being taken -- strategic planning, revenue enhancement, cost reduction, improvement of work practices and application for increased prices -- is part of a comprehensive effort to succeed in an increasingly competitive environment.
A primary objective of the strategic plan is continued and significant revenue growth even as our markets become more competitive. Retail revenues adjusted for weather and fuel costs have grown about 1% annually since 1990. During 1995, we took aggressive steps to increase revenues through enhanced marketing strategies. Also, our economic development efforts proved successful in attracting major new customers and supporting the expansion of existing ones. Although we are not satisfied with our growth rate, we expect that our marketing activity will improve revenue growth.
The rate case we filed with The Public Utilities Commission of Ohio (PUCO) in April 1995 is a critical factor to the success of the strategic plan. We do not see this rate case as a continuation of business as usual but as an important turning point which should, if we are successful in accomplishing the objectives discussed below, bring an end to price increases for the foreseeable future. A successful conclusion of the case would speed our transition to a more competitive company by providing additional cash to lower costs by accelerating the pay-down of debt and preferred stock. In our view, a successful conclusion would include approval of the full price increase requested with a regulatory commitment to maintain the established price levels over an appropriate transition period. This should be coupled with a means to accelerate recognition of regulatory assets (described in Note 7(a)) and nuclear generating assets concurrent with our cost control and revenue enhancement efforts in order to earn a fair return for share owners over time.
Another key part of our strategy is offering long-term contracts to those large customers who could have incentives to change power suppliers. In 1995, 68% of our industrial kilowatt-hour sales and 15% of our commercial kilowatt-hour sales were under long-term contracts. We are renegotiating contracts before they expire and in most cases are retaining customers under new long-term contracts.
We are continuing efforts to reduce fixed financing costs in order to strengthen our financial condition. During 1995, utilizing strong cash flow and refinancing at favorable terms, we reduced interest expense and preferred dividends by $8 million and outstanding debt and preferred stock by $134 million.
Our overall costs are high relative to many of our neighboring utilities as a result of our substantial nuclear investment. The strategic plan calls for making us more competitive by continuing to reduce operating expenses and capital expenditures. In 1995, to improve our focus on cost reduction and other strategic plan objectives, we restructured into six business groups. The new organization includes groups to manage our generation, distribution and transmission businesses; provide services and administrative functions; and invest in nonregulated enterprises. This arrangement will also enhance each group's ability to identify cost reductions by focusing on margins and improving work practices and customer service. We will also continue to aggressively pursue initiatives to reduce the heavy tax burden imposed upon us by the state and local tax structure in Ohio.
RATE CASE AND REGULATORY ACCOUNTING
In April 1995, our subsidiaries, The Cleveland Electric Illuminating Company (Cleveland Electric) and The Toledo Edison Company (Toledo Edison) (collectively, Operating Companies), filed requests with the PUCO for price increases aggregating $119 million annually to be effective in 1996. The price increases are necessary to recover cost increases and amortization of certain costs deferred since 1992 pursuant to the Rate Stabilization Program discussed below and in Note 7. If their requests are approved, the Operating Companies intend to freeze prices until at least 2002 with the expectation that increased sales and cost control measures will obviate the need for further price increases. If circumstances make it impossible to earn a fair return for share owners over time, we would ask for a further increase -- but only after taking all appropriate actions to make such a request unnecessary.
(Centerior Energy) (Centerior Energy)
In December 1995, the PUCO ordered an investigation into the financial conditions, rates and practices of the Operating Companies.
In its report on the Operating Companies' rate request, the PUCO Staff recommended approval of the $119 million requested, subject to a commitment by the Operating Companies to significantly revalue their assets. In late January 1996, the Staff proposed that the Operating Companies significantly revalue their nuclear plant and regulatory assets within a five-year period. The Staff's asset revaluation proposal is inconsistent with the Ohio statutes that define the rate-making process. The PUCO is not bound by the Staff's recommendations. A decision by the PUCO is anticipated in the second quarter of 1996.
The outcome of the rate case could affect the Operating Companies' ability to meet the criteria of Statement of Financial Accounting Standards (SFAS) 71 for all or part of their operations which could result in the write-off of all or a part of the regulatory assets shown in Note 7(a). In our changing industry, other events independent of the outcome of the rate case could also result in write-offs or write-downs of assets.
See Note 7 for a full discussion and analysis of the rate case, SFAS 71 and other financial accounting requirements and the potential implications of these accounting requirements for our results of operations and financial position.
RATE STABILIZATION PROGRAM
Under a Rate Stabilization Program approved by the PUCO in 1992, we agreed to freeze base rates until 1996 and limit rate increases through 1998. In exchange, we were permitted to defer through 1995 and subsequently recover certain costs not currently recovered in rates and to accelerate amortization of certain benefits. Deferral of those costs and amortization of those benefits were completed in November 1995 and aggregated $159 million in 1995. Recovery is expected to begin with the effective date of the PUCO's orders in the pending rate case. Annual amortization of the deferred costs is $25 million which began in December 1995. Consequently, earnings in 1996 will be sharply lower than in 1995. Also contributing to lower earnings are the expectations that the requested price increase will not be effective until the second quarter of 1996 and results from increased marketing and cost reduction efforts will take time to achieve.
COMPETITION
Major structural changes are taking place in the electric utility industry which are expected to place downward pressure on prices and to increase competition for customers' business. The changes are coming from both federal and state authorities. Many of the changes began when the Energy Policy Act of 1992 permitted competition in the electric utility industry through broader access to a utility's transmission system. In March 1995, the Federal Energy Regulatory Commission (FERC) issued proposed rules relating to open access transmission services by public utilities, recovery of stranded investment and other related matters. The open access transmission rules require utilities to deliver power from other utilities or generation sources to their wholesale customers. In May 1995, the Operating Companies filed open access transmission tariffs with the FERC which used the proposed rules as a guideline. These tariffs are currently pending.
Several groups in Ohio are studying the possible application of retail wheeling. Retail wheeling occurs when a customer obtains power from a utility company other than its local utility. The PUCO is sponsoring informal discussions among a group of business, utility and consumer interests to explore ways of promoting competitive options without unduly harming the interests of utility company share owners or customers. Legislative proposals are being drafted for submission to the Ohio House of Representatives and several utilities in the state have offered their own proposed transition plans for introduction of retail wheeling. The current retail wheeling efforts in Ohio are exploratory and we cannot predict when and to what extent retail wheeling will be implemented in Ohio.
The term "stranded investment" generally refers to fixed costs approved for recovery under traditional regulatory methods that would become unrecoverable, or "stranded", as a result of wider competition. Although competitive pressures are increasing, the traditional regulatory framework remains in place and is expected to continue for the foreseeable future. We cannot predict when and to what extent competition will be allowed. We believe that pure competition (unrestricted retail wheeling for all customer classifications) is at least several years away and that any transition to pure competition will be in phases. The FERC and the PUCO have acknowledged the need to provide at least partial recovery of stranded investment as greater competition is permitted and, therefore, we believe that there will be a mechanism developed for the recovery of stranded investment.
(Centerior Energy) (Centerior Energy)
However, due to the uncertainty involved, there is a risk that some of our assets may not be fully recovered.
In 1995, we continued to experience significant competition from municipal electric systems. Cleveland Public Power (CPP), the largest municipal system in our service area, continued to construct new distribution facilities extending into additional portions of Cleveland. Their progress has slowed significantly during the past year because of the discovery of a large number of safety violations in the CPP system resulting in substantial cost overruns. In Toledo, the City Council responded to a petition drive by appropriating funds to complete a consultant's study on whether to create a municipal electric utility. This study is expected to be completed by mid-1996.
In March 1995, one of Cleveland Electric's large commercial customers which has provided annual net income of $6 million, Medical Center Co., signed a five-year contract with CPP for electric service beginning in September 1996, when its contract with Cleveland Electric terminates. In both our appeal to the Ohio Supreme Court and petition to the FERC, it is our position that the purchase of power from CPP by this customer is in reality a direct purchase from another utility in violation of Ohio's certified territory statute. In October 1995, Chase Brass & Copper Co. Inc., which has provided annual net income of $2 million, terminated its service from Toledo Edison and began to receive its electric service from a consortium of other providers. Toledo Edison has filed lawsuits contending that this arrangement violates the legal limits of sales and delivery of power by municipal electric systems outside their boundaries. We will continue to pursue all legal and regulatory remedies to these situations.
In 1995, our economic development efforts proved successful in attracting major new customers, such as North Star BHP Steel, Worthington Steel and Aluminum Company of America, while supporting the expansion of existing ones, for example, American Steel & Wire and Ford Motor Company. We expect that our continued emphasis on economic development along with a newly developed market segment focus will be major ingredients in providing improved revenue growth.
NUCLEAR OPERATIONS
We have interests in three nuclear generating units -- Davis-Besse Nuclear Power Station (Davis-Besse), Perry Nuclear Power Plant Unit 1 (Perry Unit 1) and Beaver Valley Power Station Unit 2 (Beaver Valley Unit 2) -- and operate the first two. Davis-Besse and Beaver Valley Unit 2 both operated extremely well in 1995. Their average three-year unit availability factors at year-end 1995 of 90% and 87%, respectively, exceeded the industry average of 81% for similar reactors. In 1995, the availability factor for Davis-Besse was 100%. The plant continues to have its best run ever operating at or near full capacity for 463 straight days through February 21, 1996.
In 1995, Perry Unit 1 improved its average three-year unit availability factor to 62% with a 1995 availability factor of 93%. Perry Unit 1 operated at or near capacity for 506 of 531 days since the end of its last refueling and maintenance outage in August 1994. Work on the comprehensive course of action plan developed in 1993 to improve the operating performance of Perry Unit 1 will be completed during the current refueling outage which began January 27, 1996.
A significant part of the strategic plan involves ongoing efforts to increase the availability and lower the cost of production of our nuclear units. In 1995, we made great progress regarding unit availability while continuing to lower production costs. The goal of our nuclear improvement program is to replicate Davis-Besse's operational excellence and cost reduction gains at Perry Unit 1 while improving performance ratings.
We externally fund the estimated costs for the future decommissioning of our nuclear units. In 1993 and 1994, we increased our decommissioning expense accruals because of revisions in our cost estimates. See Note 1(d).
Our nuclear units may be impacted by activities or events beyond our control. Operating nuclear 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 to limit or prohibit the operation or licensing of any domestic nuclear unit. If one of our nuclear units is taken out of service for an extended period 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, thereby not permitting us to recover our investment in and earn a return on it, or disallowing certain construction or maintenance costs. An extended outage coupled with unfavorable rate treatment could have a material adverse effect on our financial condition
(Centerior Energy) (Centerior Energy)
and results of operations. Premature plant closings could also have a material adverse effect on our financial condition and results of operations because the estimated cost to decommission the plant exceeds the current funding in the decommissioning trust.
HAZARDOUS WASTE DISPOSAL SITES
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. Allegations that the Operating Companies disposed of hazardous waste at these sites, and the amount involved, are often unsubstantiated and subject to dispute. Federal law provides that all PRPs for a particular site be held liable on a joint and several basis. 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 $500 million. However, we believe that the actual cleanup costs will be substantially lower than $500 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 $12 million at December 31, 1995, 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.
MERGER OF THE OPERATING COMPANIES
We continue to seek the necessary regulatory approvals to complete the merger of the Operating Companies which we announced in 1994. The FERC has deferred action on the merger application until the merits of the Operating Companies' proposed open access transmission tariffs are addressed in hearings.
CAPITAL RESOURCES AND LIQUIDITY
1993-1995 CASH REQUIREMENTS
A key part of our strategic plan is to significantly reduce the Operating Companies' level of debt and preferred stock. In 1995, we were able to continue the reduction pattern begun in 1994. These obligations were reduced by $136 million in 1994 and by $134 million in 1995. We intend to continue and to accelerate redemptions.
We need cash for normal corporate operations, retirement of maturing securities, and an ongoing program of constructing and improving facilities to meet demand for electric service and to comply with government regulations. Our cash construction expenditures totaled $209 million in 1993, $205 million in 1994 and $201 million in 1995. Our debt and preferred stock maturities and sinking fund requirements totaled $368 million in 1993, $120 million in 1994 and $377 million in 1995. In addition, we optionally redeemed approximately $470 million in the period 1993-1995. This amount includes $237 million of tax-exempt issues refunded in 1995 resulting in approximately $7 million of interest savings. In May 1995, Cleveland Electric issued $300 million of first mortgage bonds due in 2005 with an interest rate of 9.50%. The embedded cost of the Operating Companies' debt at the end of 1995 was 8.98% versus 9.12% in 1994 and 9.06% in 1993. In 1995, the Operating Companies renewed for a four-year term approximately $225 million in bank letters of credit supporting the equity owner participants in the Beaver Valley Unit 2 lease. See Note 11(d).
1996 AND BEYOND CASH REQUIREMENTS
Our 1996 cash requirements for construction are $128 million for Cleveland Electric and $74 million for Toledo Edison and for debt and preferred stock maturities and sinking fund requirements are $177 million for Cleveland Electric and $58 million for Toledo Edison. We expect to meet these requirements with internal cash generation, cash reserves and about $150 million from the sale of a AAA-rated security backed by our accounts receivable.
We expect to meet all of our 1997-2000 cash requirements with internal cash generation. Estimated cash requirements for our construction program during this period total $603 million for Cleveland Electric and $262 million for Toledo Edison. Debt and preferred stock maturities and sinking fund requirements total $400 million and $233 million for Cleveland Electric and Toledo Edison, respectively, for the same period. If economical, additional securities may be redeemed under optional redemption provisions, with funding expected to be provided through internal cash generation. Additional funding may be required to support investments in nonregulated business opportunities.
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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. If the applicable interest coverage test is met, each Operating Company may issue first mortgage bonds on the basis of property additions and, under certain circumstances, refundable bonds. At December 31, 1995, Cleveland Electric and Toledo Edison would have been permitted to issue approximately $379 million and $288 million of additional first mortgage bonds, respectively.
The Operating Companies also are able to raise funds through the sale of debt and preferred and preference stock. Under its articles of incorporation, Toledo Edison cannot issue preferred stock unless certain earnings coverage requirements are met. At December 31, 1995, Toledo Edison would have been permitted to issue approximately $158 million of additional preferred stock at an assumed dividend rate of 10.5%. There are no restrictions on Cleveland Electric's ability to issue preferred or preference stock or Toledo Edison's ability to issue preference stock. Centerior Energy may raise funds through the sale of common stock under various employee and share owner plans.
The Operating Companies have $307 million in financing vehicles available to support their nuclear fuel leases, portions of which mature this year. See Note 6. We plan to renew a $125 million revolving credit facility which matures in May 1996. See Note 12. At the end of 1995, we had $179 million in cash and temporary investments.
The foregoing financing resources are expected to be sufficient for the Operating Companies' needs over the next several years. However, the availability and cost of capital to meet external financing needs also depend upon such factors as financial market conditions and their credit ratings. Current credit ratings for the Operating Companies are as follows:
RESULTS OF OPERATIONS
1995 VS. 1994
Factors contributing to the 3.9% increase in 1995 operating revenues are as follows:
For the third year in a row, industrial kilowatt-hour sales increased. The increase in 1995 was 0.8%, but sales grew 2.2% excluding reductions at two low-margin steel producers (representing 5% of industrial revenues). Residential and commercial sales increased 3.5% and 2.8%, respectively, primarily because of the hot summer weather, although there was about 1% nonweather-related growth in commercial sales. Other sales increased 26% because of a 43% increase in wholesale sales due principally to the hot summer and good availability of our generating units. Weather accounted for approximately $38 million of the $61 million increase in 1995 base rate (nonfuel) revenues. Higher 1995 fuel cost recovery revenues resulted from an increase in the fuel cost factor for Cleveland Electric. The weighted average of these fuel cost factors increased 7% for Cleveland Electric but decreased 6% for Toledo Edison.
For 1995, operating revenues were 32% residential, 30% commercial, 31% industrial and 7% other and kilowatt-hour sales were 23% residential, 25% commercial, 40% industrial and 12% other. The average prices per kilowatt-hour for residential, commercial and industrial customers were $.11, $.10 and $.06, respectively.
Operating expenses increased 4.5% in 1995. Fuel and purchased power expenses increased as higher fuel expense was partially offset by lower purchased power expense. The higher fuel expense was attributable to increased generation and more amortization of previously deferred fuel costs than the amount amortized in 1994. The higher other operation and maintenance expenses resulted primarily from charges for an ongoing inventory reduction program and the recognition of costs associated with preliminary engineering studies. Federal income taxes increased as a result of higher pretax operating income. Taxes, other than federal income taxes, increased primarily due to property tax increases resulting from plant additions, real estate valuation increases and a nonrecurring tax credit recorded in 1994.
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1994 VS. 1993
Factors contributing to the 2.1% decrease in 1994 operating revenues are as follows:
We experienced good retail kilowatt-hour sales growth in the industrial and commercial categories in 1994; the sales growth for the residential category was lessened by weather conditions, particularly during the summer. The revenue decrease resulted primarily from milder weather conditions in 1994 and 39% lower wholesale sales. Weather reduced base rate revenues approximately $15 million from the 1993 amount. Although total sales decreased by 1.9%, industrial sales increased 3.3% on the strength of increased sales to large automotive manufacturers and the broad-based, smaller industrial customer group. This growth substantiated an economic resurgence in our service area, particularly in Northwestern Ohio. Residential and commercial sales increased 0.1% and 2.4%, respectively. Other sales decreased by 28% because of the lower sales to wholesale customers attributable to expiration of a wholesale power agreement, softer wholesale market conditions and limited power availability for bulk power transactions at certain times because of generating plant outages. Lower 1994 fuel cost recovery revenues resulted from favorable changes in the fuel cost factors. The weighted averages of these factors dropped by 5% and 6% for Cleveland Electric and Toledo Edison, respectively.
For 1994, operating revenues were 31% residential, 30% commercial, 31% industrial and 8% other and kilowatt-hour sales were 24% residential, 25% commercial, 41% industrial and 10% other. The average prices per kilowatt-hour for residential, commercial and industrial customers were $.11, $.10 and $.06, respectively. The changes from 1993 were not significant.
Operating expenses were 15% lower in 1994. Operation and maintenance expenses for 1993 included $218 million of net benefit expenses related to an early retirement program, called the Voluntary Transition Program (VTP), and other charges totaling $54 million. A smaller work force and ongoing cost reduction measures also lowered operation and maintenance expenses. More nuclear generation and less coal-fired generation accounted for a large part of the lower fuel and purchased power expenses in 1994. Depreciation and amortization expenses increased primarily because of higher nuclear plant decommissioning expenses as discussed in Note 1(d). Deferred operating expenses were greater primarily because of the write-off of $172 million of phase-in deferred operating expenses in 1993 as discussed in Note 7(e). The 1993 deferrals also included $84 million of postretirement benefit curtailment cost deferrals related to the VTP. See Note 9(b). Federal income taxes increased as a result of higher pretax operating income.
As discussed in Note 4(b), $583 million of our Perry Unit 2 investment was written off in 1993. Also, as discussed in Note 7, phase-in deferred carrying charges of $705 million were written off in 1993. The change in the federal income tax credit amounts for nonoperating income was attributable to these write-offs.
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Share Owners and Board of Directors of 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, 1995 and 1994, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1995. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the schedule 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, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles.
As discussed further in Note 9, a change was made in the method of accounting 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 schedule of Centerior Energy Corporation and subsidiaries listed in the Index to Schedules is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states 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 LLP
Cleveland, Ohio February 21, 1996
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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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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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CASH FLOWS Centerior Energy Corporation and Subsidiaries
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(2) Increases in Nuclear Fuel and Nuclear Fuel Lease Obligations in the Balance Sheet resulting from the noncash capitalizations under nuclear fuel agreements are excluded from this statement.
The accompanying notes are an integral part of this statement.
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STATEMENT OF PREFERRED STOCK 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, with service areas in Northern Ohio. The consolidated financial statements also include the accounts of Centerior Energy's wholly owned subsidiary, Centerior Service Company (Service Company), and its three other wholly owned subsidiaries, which in the aggregate are not material. The Service Company provides management, financial, administrative, engineering, legal and other services at cost to Centerior Energy, the Operating Companies and the other subsidiaries. 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 FERC and adopted by the PUCO. Rate-regulated utilities are subject to SFAS 71 which governs accounting for the effects of certain types of rate regulation. Pursuant to SFAS 71, certain incurred costs are deferred for recovery in future rates. See Note 7. The Service Company follows the Uniform System of Accounts for Mutual Service Companies prescribed by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935.
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. The estimates are based on an analysis of the best information available. Actual results could differ from those estimates.
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 joint 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 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 (to 2007). 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) DEPRECIATION AND DECOMMISSIONING
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 1995, 3.4% in 1994 and 3.5% in 1993. The annual straight-line depreciation rate for nuclear property is 2.5%. In conjunction with the Operating Companies' pending rate case, we have asked the PUCO to approve an increase of this depreciation rate to approximately 3%.
The Operating Companies accrue the estimated costs of decommissioning their three nuclear generating units.
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The accruals are required to be funded in an external trust. The PUCO requires that the expense and payments to the external trusts be determined on a levelized basis by dividing the unrecovered decommissioning costs in current dollars by the remaining years in the licensing period of each unit. This methodology requires that the net earnings on the trusts be reinvested therein with the intent of having net earnings offset inflation. The PUCO requires that the estimated costs of decommissioning and the funding level be reviewed at least every five years.
In 1994, the Operating Companies increased their annual decommissioning expense accruals to $24 million from the $12 million level in 1993. The accruals are reflected in current rates. The increased accruals in 1994 were derived from updated, site-specific studies for each of the units. The revised estimates reflect the DECON method of decommissioning (prompt decontamination), and the locations and cost characteristics specific to the units, and include costs associated with decontamination, dismantlement and site restoration.
The revised estimates for the units in 1993 and 1992 dollars and in dollars at the time of license expiration, assuming a 4% annual inflation rate, are as follows:
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(1) Dollar amounts in 1993 dollars. (2) Dollar amount in 1992 dollars.
The updated estimates reflect substantial increases from the prior PUCO-recognized aggregate estimates of $257 million in 1987 and 1986 dollars.
The classification, Accumulated Depreciation and Amortization, in the Balance Sheet at December 31, 1995 includes $130 million of decommissioning costs previously expensed and the earnings on the external trust 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. The trust earnings are recorded as an increase to the trust assets and the related component of the decommissioning reserve (included in Accumulated Depreciation and Amortization).
The staff of the SEC has questioned certain of the current accounting practices of the electric utility industry, including those of the Operating Companies, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in the financial statements. In response to these questions, the Financial Accounting Standards Board (FASB) is reviewing the accounting for removal costs, including decommissioning. If current accounting practices are changed, the annual provision for decommissioning could increase; the estimated cost for decommissioning could be recorded as a liability rather than as accumulated depreciation; and trust fund income from the external decommissioning trusts could be reported as investment income rather than as a reduction to decommissioning expense. The FASB issued an exposure draft on the subject on February 7, 1996.
(E) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment are stated at original cost less amounts disallowed by the PUCO. Construction costs include related payroll taxes, retirement benefits, 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 11.5% in 1995, 9.8% in 1994 and 9.9% in 1993.
Maintenance and repairs for plant and equipment 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.
(F) 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. See Note 7(a). These amortizations and the lease expense amounts are reported in the Income Statement as Generation Facilities Rental Expense, Net.
(G) 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
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with the regulatory rate treatment. See Note 7(a). 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.
(H) FEDERAL INCOME TAXES We use the liability method of accounting for income taxes in accordance with SFAS 109. See Note 8. 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. See Note 7(a).
Investment tax credits are deferred and amortized over the lives of the applicable property as a reduction of depreciation expense. See Note 7(d) 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. These leases extend through 2017 and 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 renew the leases. The leases include conditions for mandatory termination (and possible repurchase of the leasehold interest) for events of default.
Future minimum lease payments under the operating leases at December 31, 1995 are summarized as follows:
Rental expense is accrued on a straight-line basis over the terms of the leases. The amount recorded in 1995, 1994 and 1993 as annual rental expense for the Mansfield Plant leases was $115 million. The amounts recorded in 1995, 1994 and 1993 as annual rental expense for the Beaver Valley Unit 2 lease were $63 million, $64 million and $63 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.
(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, 1995 includes the following
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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 1996-2000 period is $1.107 billion, including AFUDC of $40 million and excluding nuclear fuel.
The Clean Air Act Amendments of 1990 (Clean Air Act) requires, among other things, significant reductions in the emission of sulfur dioxide and nitrogen oxides by fossil-fueled generating units. Our strategy provides for compliance primarily through greater use of low-sulfur coal at some of our units and the use of emission allowances. Total capital expenditures from 1991 through 1995 in connection with Clean Air Act compliance amounted to $50 million. The plan will require additional capital expenditures over the 1996-2005 period of approximately $90 million for nitrogen oxide control equipment and other plant process modifications. In addition, higher fuel and other operation and maintenance expenses will be incurred. 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.
(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. 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.
(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 sites. The Operating Companies have accrued a liability totaling $12 million at December 31, 1995 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.
(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 the discussion of these and other risks in Management's Financial Analysis -- Outlook-Nuclear Operations.
(B) NUCLEAR INSURANCE
The Price-Anderson Act limits the public 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 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 utility owners and lessees of Davis-Besse, Perry and Beaver Valley also have insurance coverage for damage to property at these sites (including leased fuel and cleanup costs). Coverage amounted to $2.75 billion for each site as of January 1, 1996. 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. In addition, we can be assessed a maximum of $42 million under these policies 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.
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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 80% 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 $307 million ($157 million from intermediate-term notes and $150 million from bank credit arrangements). The intermediate-term notes mature in 1996 and 1997 ($84 million in September 1996 and $73 million in September 1997). The bank credit arrangements terminate in October 1996. The special-purpose corporation plans to obtain alternate financing in 1996 to replace the $234 million of financing expiring in 1996. At December 31, 1995, $236 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 $79 million, $55 million and $35 million, respectively, at December 31, 1995. The nuclear fuel amounts financed and capitalized also included interest charges incurred by the lessors amounting to $5 million in 1995, $11 million in 1994 and $14 million in 1993. The estimated future lease amortization payments based on projected consumption are $96 million in 1996, $82 million in 1997, $68 million in 1998, $65 million in 1999 and $62 million in 2000.
(7) REGULATORY MATTERS
(A) REGULATORY ACCOUNTING REQUIREMENTS AND REGULATORY ASSETS
The Operating Companies are subject to the provisions of SFAS 71 and have complied with its provisions. SFAS 71 provides, among other things, for the deferral of certain incurred costs that are probable of future recovery in rates. We monitor changes in market and regulatory conditions and consider the effects of such changes in assessing the continuing applicability of SFAS 71. Criteria that could give rise to discontinuation of the application of SFAS 71 include: (1) increasing competition which significantly restricts the Operating Companies' ability to charge prices which allow us to recover operating costs, earn a fair return on invested capital and recover the amortization of regulatory assets and (2) a significant change in the manner in which rates are set by the PUCO from cost-based regulation to some other form of regulation. Regulatory assets represent probable future revenues to the Operating Companies associated with certain incurred costs, which they will recover from customers through the rate-making process.
Effective January 1, 1996, the Operating Companies adopted SFAS 121 which imposes stricter criteria for carrying regulatory assets than SFAS 71 by requiring that such assets be probable of recovery at each balance sheet date. The criteria under SFAS 121 for plant assets require such assets to be written down only if the book value exceeds the projected net future cash flows.
Regulatory assets in the Balance Sheet are as follows:
* Represent deferrals of operating expenses and carrying charges for Perry Unit 1 and Beaver Valley Unit 2 in 1987 and 1988 which are being amortized over the lives of the related property.
As of December 31, 1995, customer rates provide for recovery of all the above regulatory assets, except those related to the Rate Stabilization Program discussed below. The remaining recovery periods for all of the regulatory assets listed above range from 16 to 33 years.
(B) RATE CASE
In April 1995, the Operating Companies filed requests with the PUCO for price increases aggregating $119 million annually to be effective in 1996. The price increases are necessary to recover cost increases and amortization of certain costs deferred since 1992 pursuant to the Rate Stabilization Program. If their requests are approved, the Operating Companies intend to freeze prices until at least 2002 with the expectation that increased sales and cost control measures will preclude the need for further price increases. If circumstances make it impossible to earn a fair return for share owners
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over time, we would ask for a further increase, but only after taking all appropriate actions to make such a request unnecessary.
In November 1995, the PUCO Staff issued its report addressing the Operating Companies' rate case. The Staff recommended that the PUCO grant the full $119 million price increase requested. However, the Staff also recommended that the price increase be conditioned upon the Operating Companies' commitment "to a significant revaluation of their asset bases over some finite period of time."
In December 1995, the PUCO ordered an investigation into the financial condition, rates and practices of the Operating Companies to identify outcomes and remedies other than those routinely applied during the rate case process.
In late January 1996, the Staff proposed an incremental reduction (currently, $1.25 billion) beyond the normal level in nuclear plant and regulatory assets within five years. The Staff proposed that the Operating Companies have flexibility to determine how to achieve this incremental asset revaluation, but no additional price increases to recover the accelerated asset revaluation were proposed. Any incremental revaluation of assets would be for regulatory purposes and would cause prices and revenues after the five-year period to be lower than they otherwise would be in conjunction with any rate case following such revaluation. The Staff's asset revaluation proposal represents a substantial change in the form of rate-making traditionally followed by the PUCO and is inconsistent with the Ohio statutes that define the rate-making process. The PUCO is not bound by the recommendations of the Staff. A decision by the PUCO is anticipated in the second quarter of 1996.
(C) ASSESSMENT OF POTENTIAL OUTCOMES
We continually assess the effects of competition and the changing industry and regulatory environment on operations, our ability to recover regulatory assets and our ability to continue application of SFAS 71. If, as a result of the pending rate case or other events, we determine that the Operating Companies no longer meet the criteria for SFAS 71, we would be required to record a before-tax charge to write off the regulatory assets shown above and evaluate whether property, plant and equipment should be written down. In the more likely event that only a portion of operations (such as nuclear operations) no longer meets the criteria of SFAS 71, a write-off would be limited to regulatory assets, if any, that are not reflected in our cost-based prices established for the remaining regulated operations. In addition, we would be required to evaluate whether the changes in the competitive and regulatory environment which led to discontinuing the application of SFAS 71 to a portion of our operations would also result in a write-down of property, plant and equipment pursuant to SFAS 121.
We believe application of SFAS 121 in that event will not result in a write-off of regulatory assets unless the PUCO denies recovery of such assets or if we conclude, as a result of the outcome of our pending rate case or some other event, that recovery is not probable for some or all of the regulatory assets. Furthermore, a write-down under SFAS 121 of property, plant and equipment is not expected.
(D) RATE STABILIZATION PROGRAM
The Rate Stabilization Program that the PUCO approved in October 1992 allowed the Operating Companies to defer and subsequently amortize and recover certain costs not currently recovered in rates and to accelerate amortization of certain benefits during the 1992-1995 period. Recovery of the deferrals will begin with the effective date of the PUCO's orders in the pending rate case. The regulatory assets recorded included the deferral of post-in-service interest carrying charges, depreciation expense and property taxes on assets placed in service after February 29, 1988, the deferral of incremental expenses resulting from the adoption of SFAS 106 (see Note 9(b)), and the deferral by Toledo Edison of the operating expenses equivalent to an accumulated excess rent reserve for Beaver Valley Unit 2 (which resulted from the April 1992 refinancing of Secured Lease Obligation Bonds issued by a special purpose corporation). The cost deferrals recorded in 1995, 1994 and 1993 pursuant to these provisions were $113 million, $112 million and $191 million, respectively. The regulatory accounting measures also provided for the accelerated amortization of certain unrestricted excess deferred tax and unrestricted investment tax credit balances and an excess interim spent fuel storage accrual balance for Davis-Besse. The total annual amount of such accelerated benefits was $46 million in 1995, 1994 and 1993.
(E) PHASE-IN DEFERRALS
In 1993, upon completing a comprehensive study which led to our strategic plan, we concluded that projected revenues would not provide for recovery of deferrals recorded pursuant to phase-in plans approved by the PUCO in 1989 and, consequently, that the deferrals would have to be written off. Such deferrals were scheduled to be recovered in 1994 through 1998. The total
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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).
(8) FEDERAL INCOME TAX The components of federal income tax expense (credit) recorded in the Income Statement were as follows:
The deferred federal income tax expense results from the temporary differences that arise from the different years certain expenses are recognized for tax purposes as opposed to financial reporting purposes. Such temporary differences affecting operating expenses relate principally to depreciation and deferred operating expenses whereas those affecting nonoperating income principally relate to deferred carrying charges and the 1993 write-offs.
Federal income tax, computed by multiplying the income before taxes and preferred dividend requirements of subsidiaries by the 35% statutory rate, is reconciled to the amount of federal income tax recorded on the books as follows:
For tax reporting purposes, the Perry Unit 2 abandonment was recognized in 1994 and resulted in a $327 million loss with a corresponding $114 million reduction in federal income tax liability. Because of the alternative minimum tax (AMT), $65 million of the $114 million was realized in 1994. The remaining $49 million will not be realized until 1999. Additionally, a repayment of approximately $29 million of previously allowed investment tax credits was recognized in 1994.
Under SFAS 109, temporary differences and carryforwards resulted in deferred tax assets of $604 million and deferred tax liabilities of $2.479 billion at December 31, 1995 and deferred tax assets of $596 million and deferred tax liabilities of $2.374 billion at December 31, 1994. These are summarized as follows:
For tax purposes, net operating loss (NOL) carryforwards of approximately $322 million are available to reduce future taxable income and will expire in 2005 through 2009. The 35% tax effect of the NOLs is $113 million. Additionally, AMT credits of $213 million that may be carried forward indefinitely are available to reduce future tax.
(9) RETIREMENT BENEFITS
(A) RETIREMENT INCOME PLAN
We sponsor a noncontributing pension plan which covers all employee groups. 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 offset by a credit of $81 million resulting from a settlement of pension obligations through lump sum payments to almost all the VTP retirees.
Pension and VTP costs (credits) for 1993 through 1995 were comprised of the following components:
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The following table presents a reconciliation of the funded status of the plan.
A September 30 measurement date was used for 1995 and 1994 reporting. At December 31, 1995, the settlement (discount) rate and long-term rate of return on plan assets assumptions were 8% and 11%, respectively. The long-term rate of annual compensation increase assumption was 3.5% in 1996 and 1997 and 4% thereafter. At December 31, 1994, the settlement rate and long-term rate of return on plan assets assumptions were 8.5% and 10%, respectively. The long-term rate of annual compensation increase assumption was 3.5% for 1995 and 1996 and 4% thereafter. Plan assets consist primarily of investments in common stock, bonds, guaranteed investment contracts, cash equivalent securities and real estate.
(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. 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. Prior to 1993, the costs of these benefits were expensed as paid, which was consistent with rate-making practices.
The components of the total postretirement benefit costs for 1993 through 1995 were as follows:
In 1995, 1994 and 1993, we deferred incremental SFAS 106 expenses (in excess of the amounts paid) of $4 million, $6 million and $96 million, respectively, pursuant to a provision of the Rate Stabilization Program. See Note 7(d).
The accumulated postretirement benefit obligation and accrued postretirement benefit cost are as follows:
A September 30 measurement date was used for 1995 and 1994 reporting. At December 31, 1995 and 1994, the settlement rate and the long-term rate of annual compensation increase assumptions were the same as those discussed for pension reporting in Note 9(a). At December 31, 1995, the assumed annual health care cost trend rates (applicable to gross eligible charges) were 8% for medical and 7.5% for dental in 1996. Both rates reduce gradually to a fixed rate of 4.75% by 2003. 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 one percentage point in each future year, the accumulated postretirement benefit obligation as of December 31, 1995 would increase by $6 million and the aggregate of the service and interest cost
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components of the annual postretirement benefit cost would increase by $0.5 million.
(10) GUARANTEES
Cleveland Electric has guaranteed certain loan and lease obligations of two coal suppliers under two long-term coal supply contracts. Toledo Edison is a party to one of these contracts. At December 31, 1995, the principal amount of the loan and lease obligations guaranteed by the Operating Companies under both contracts was $53 million. In addition, under the contract to which Toledo Edison is not a party, Cleveland Electric may be responsible for mine closing costs when the contract is terminated. At December 31, 1995, the unfunded costs of closing this mine as estimated by the supplier were $32 million.
The prices under both contracts which include certain minimum payments are sufficient to satisfy the loan and lease obligations and mine closing costs over the lives of the contracts. If either contract is terminated early for any reason, the Operating Companies would attempt to reduce the termination charges and would ask the PUCO to allow recovery of such charges from customers through the fuel factor of the respective Operating Company.
(11) CAPITALIZATION
(A) CAPITAL STOCK TRANSACTIONS AND COMMON SHARES RESERVED FOR ISSUE
Shares sold, retired and purchased for treasury during the three years ended December 31, 1995 are listed in the following table.
Shares of common stock required for our stock plans in 1995 were acquired in the open market.
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, 1996. As of December 31, 1995, 225,500 shares had been purchased at a total cost of $4 million. Such shares are being held as treasury stock.
The number of common stock shares reserved for issue under the Employee Savings Plan and the Employee Purchase Plan was 1,702,849 and 423,797, respectively, at December 31, 1995.
Under an Equity Compensation Plan (Plan) adopted in 1994, options to purchase shares of common stock and awards of restricted common stock were granted to management employees. In 1995, options were issued for 285,000 shares at an exercise price of $14.58. In 1994, options were issued for 264,900 shares at an exercise price of $13.20 but options for 9,500 shares were surrendered in 1995. The options expire 10 years from the date of the grant and vest over four years. The number of shares available for issuance under the Plan each year is determined by formula, generally 0.5% of outstanding shares. Shares of common stock required for the Plan may be either issued as new shares, issued from treasury stock or acquired in the open market specifically for distribution under the Plan.
In 1995, the FASB issued SFAS 123, a new accounting standard for stock-based compensation, effective for 1996. The standard encourages accounting for stock-based compensation awards based on their fair value at the grant date with the resulting cost recorded as an expense. Entities electing not to record the cost are required to disclose in the notes to the financial statements what the impact on net income and earnings per share would have been had they followed the suggested accounting. We expect to adopt the disclosure method of implementing SFAS 123, which will have no impact on our results of operations.
(B) EQUITY DISTRIBUTION RESTRICTIONS
The Operating Companies can make cash available for the funding of Centerior Energy's common stock dividends by paying dividends on their respective common stock, which is 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, 1995, Cleveland Electric and
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Toledo Edison had $212 million and $183 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 that essentially requires such dividends to be paid out of the total balance of retained earnings, which currently is a deficit. (C) PREFERRED AND PREFERENCE STOCK
Amounts to be paid for preferred stock which must be redeemed during the next five years are $32 million in 1996, $32 million in 1997, $16 million in 1998, $35 million in 1999 and $33 million in 2000. The annual mandatory redemption provisions are as follows:
* All outstanding shares to be redeemed on December 1, 2001. In 1995, Cleveland Electric purchased 1,000 shares of Serial Preferred Stock, $90.00 Series S, which will reduce the 2002 redemption requirement shown in the above table.
The annualized preferred dividend requirement for the Operating Companies at December 31, 1995 was $59 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 7.23%, 7.02%, 7.75% and 8.58%, respectively, in 1995.
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.
(D) LONG-TERM DEBT AND OTHER BORROWING ARRANGEMENTS
Long-term debt, less current maturities, for the Operating Companies was as follows:
* Secured by first mortgage bonds.
** Secured by subordinated mortgage collateral.
Long-term debt matures during the next five years as follows: $203 million in 1996, $90 million in 1997, $113 million in 1998, $273 million in 1999 and $41 million in 2000.
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 credit agreements of the Operating Companies contain covenants relating to fixed charge coverage ratios and limitations on secured financing other than through first mortgage bonds or certain other transactions. In June 1995, the Operating Companies replaced letters of credit in connection with the sale and leaseback of Beaver Valley Unit 2 that were due to expire with new letters of credit expiring in June 1999. The letters of credit are in an aggregate amount of approximately $225 million and are secured by first mortgage bonds of Cleveland Electric and
(Centerior Energy) (Centerior Energy)
Toledo Edison in the proportion of 40% and 60%, respectively. At December 31, 1995, the Operating Companies had outstanding $54 million of bank loans and notes secured by subordinated mortgage collateral.
(12) SHORT-TERM BORROWING ARRANGEMENTS
Centerior Energy has a $125 million revolving credit facility through May 1996. 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. The credit agreement is secured with first mortgage bonds of Cleveland Electric and Toledo Edison in the proportion of 40% and 60%, respectively. The banks' fee is 0.625% per annum payable quarterly in addition to interest on any borrowings. There were no borrowings under the facility at December 31, 1995. Also, the Operating Companies may borrow from each other on a short-term basis.
(13) FINANCIAL INSTRUMENTS
The estimated fair values at December 31, 1995 and 1994 of financial instruments that do not approximate their carrying amounts in the Balance Sheet are as follows:
Noncash investments in the Nuclear Plant Decommissioning Trusts are summarized in the following table.
The fair value of these trusts is estimated based on the quoted market prices for the investment securities. As a result of adopting the new accounting standard for certain investments in debt and equity securities, SFAS 115, in 1994, the carrying amount of these trusts approximates fair value. 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, 1995 and 1994 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, 1995.
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FINANCIAL AND STATISTICAL REVIEW
OPERATING REVENUES (millions of dollars)
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OPERATING EXPENSES (millions of dollars)
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INCOME (LOSS) (millions of dollars)
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INCOME (LOSS) (millions of dollars) COMMON STOCK (dollars per share & %)
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NOTE: 1985 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. (b) Includes write-off of phase-in deferrals of $877 million, consisting of $172 million of deferred operating expenses and $705 million of deferred carrying charges. (c) The Operating Companies adopted a change in accounting for nuclear plant depreciation, changing from the units-of-production method to the straight-line method at a 2.5% rate.
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Centerior Energy Corporation and Subsidiaries
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CAPITALIZATION (millions of dollars & %)
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(d) Includes write-off of Perry Unit 2 of $583 million.
(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) Reduced by net energy used by the Seneca Pumped Storage Plant for pumping.
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MANAGEMENT'S FINANCIAL ANALYSIS
OUTLOOK
STRATEGIC PLAN
We continued to make progress during the second year of our eight-year strategic plan, but we remain keenly aware of the magnitude of the problems that face us. The strategic plan was created by Centerior Energy Corporation (Centerior Energy), along with The Cleveland Electric Illuminating Company (Company) and The Toledo Edison Company (Toledo Edison), to achieve two major goals: strengthening their financial conditions and improving their competitive positions. The Company and Toledo Edison are the two wholly owned electric utility subsidiaries of Centerior Energy. The plan's objectives relate to the combined operations of all three companies. The objectives are to achieve profitable revenue growth, become a leader in customer satisfaction, build a winning employee team, attain increasingly competitive power supply costs and maximize share owner return on Centerior Energy common stock. We are not yet positioned to compete in a less regulated electric utility industry, but every major action being taken -- strategic planning, revenue enhancement, cost reduction, improvement of work practices and application for increased prices -- is part of a comprehensive effort to succeed in an increasingly competitive environment.
A primary objective of the strategic plan is continued and significant revenue growth even as our markets become more competitive. The Company's retail revenues adjusted for weather and fuel costs have grown about 1% annually since 1990. During 1995, we took aggressive steps to increase revenues through enhanced marketing strategies. Also, our economic development efforts proved successful in attracting new customers and supporting the expansion of existing ones. Although we are not satisfied with our growth rate, we expect that our marketing activity will improve revenue growth.
The rate case which the Company and Toledo Edison filed with The Public Utilities Commission of Ohio (PUCO) in April 1995 is a critical factor to the success of the strategic plan. We do not see this rate case as a continuation of business as usual but as an important turning point which should, if we are successful in accomplishing the objectives discussed below, bring an end to price increases for the foreseeable future. A successful conclusion of the case would speed our transition to a more competitive company by providing additional cash to lower costs by accelerating the pay-down of debt and preferred stock. In our view, a successful conclusion would include approval of the full price increase requested with a regulatory commitment to maintain the established price levels over an appropriate transition period. This should be coupled with a means to accelerate recognition of regulatory assets (described in Note 7(a)) and nuclear generating assets concurrent with our cost control and revenue enhancement efforts in order to earn a fair return for Centerior Energy common stock share owners over time.
Another key part of our strategy is offering long-term contracts to those large customers who could have incentives to change power suppliers. In 1995, 64% of our industrial kilowatt-hour sales and 24% of our commercial kilowatt-hour sales were under long-term contracts. We are renegotiating contracts before they expire and in most cases are retaining customers under new long-term contracts.
We are continuing efforts to reduce fixed financing costs in order to strengthen our financial condition. During 1995, utilizing strong cash flow and refinancing at favorable terms, the Company reduced interest expense and preferred dividends by $1 million and outstanding debt and preferred stock by $13 million.
Our overall costs are high relative to many of our neighboring utilities as a result of our substantial nuclear investment. The strategic plan calls for making us more competitive by continuing to reduce operating expenses and capital expenditures. In 1995, to improve the focus on cost reduction and other strategic plan objectives, Centerior Energy and its subsidiaries restructured into six business groups. The new organization includes groups to manage the generation, distribution and transmission businesses; provide services and administrative functions; and invest in nonregulated enterprises. This arrangement will also enhance each group's ability to identify cost reductions by focusing on margins and improving work practices and customer service. We will also continue to aggressively pursue initiatives to reduce the heavy tax burden imposed upon us by the state and local tax structure in Ohio.
RATE CASE AND REGULATORY ACCOUNTING
In April 1995, the Company and Toledo Edison filed requests with the PUCO for price increases aggregating
(Cleveland Electric) (Cleveland Electric)
$119 million annually to be effective in 1996. The price increases are necessary to recover cost increases and amortization of certain costs deferred since 1992 pursuant to the Rate Stabilization Program discussed below and in Note 7. If their requests are approved, the Company and Toledo Edison intend to freeze prices until at least 2002 with the expectation that increased sales and cost control measures will obviate the need for further price increases. If circumstances make it impossible to earn a fair return for Centerior Energy common stock share owners over time, the Company and Toledo Edison would ask for a further increase -- but only after taking all appropriate actions to make such a request unnecessary.
In December 1995, the PUCO ordered an investigation into the financial conditions, rates and practices of the Company and Toledo Edison.
In its report on the rate request, the PUCO Staff recommended approval of the $119 million requested ($84 million for the Company and $35 million for Toledo Edison), subject to a commitment by the Company and Toledo Edison to significantly revalue their assets. In late January 1996, the Staff proposed that the Company and Toledo Edison significantly revalue their nuclear plant and regulatory assets within a five-year period. The Staff's asset revaluation proposal is inconsistent with the Ohio statutes that define the rate-making process. The PUCO is not bound by the Staff's recommendations. A decision by the PUCO is anticipated in the second quarter of 1996.
The outcome of the rate case could affect the Company's ability to meet the criteria of Statement of Financial Accounting Standards (SFAS) 71 for all or part of its operations which could result in the write-off of all or a part of the regulatory assets shown in Note 7(a). In our changing industry, other events independent of the outcome of the rate case could also result in write-offs or write-downs of assets.
See Note 7 for a full discussion and analysis of the rate case, SFAS 71 and other financial accounting requirements and the potential implications of these accounting requirements for the Company's results of operations and financial position.
RATE STABILIZATION PROGRAM
Under a Rate Stabilization Program approved by the PUCO in 1992, we agreed to freeze base rates until 1996 and limit rate increases through 1998. In exchange, we were permitted to defer through 1995 and subsequently recover certain costs not currently recovered in rates and to accelerate amortization of certain benefits. Deferral of those costs and amortization of those benefits were completed in November 1995 and aggregated $103 million for the Company in 1995. Recovery is expected to begin with the effective date of the PUCO's order in the pending rate case. Annual amortization of the deferred costs for the Company is $15 million which began in December 1995. Consequently, earnings in 1996 will be sharply lower than in 1995. Also contributing to lower earnings are the expectations that the requested price increase will not be effective until the second quarter of 1996 and results from increased marketing and cost reduction efforts will take time to achieve.
COMPETITION
Major structural changes are taking place in the electric utility industry which are expected to place downward pressure on prices and to increase competition for customers' business. The changes are coming from both federal and state authorities. Many of the changes began when the Energy Policy Act of 1992 permitted competition in the electric utility industry through broader access to a utility's transmission system. In March 1995, the Federal Energy Regulatory Commission (FERC) issued proposed rules relating to open access transmission services by public utilities, recovery of stranded investment and other related matters. The open access transmission rules require utilities to deliver power from other utilities or generation sources to their wholesale customers. In May 1995, the Company and Toledo Edison filed open access transmission tariffs with the FERC which used the proposed rules as a guideline. These tariffs are currently pending.
Several groups in Ohio are studying the possible application of retail wheeling. Retail wheeling occurs when a customer obtains power from a utility company other than its local utility. The PUCO is sponsoring informal discussions among a group of business, utility and consumer interests to explore ways of promoting competitive options without unduly harming the interests of utility company share owners or customers. Legislative proposals are being drafted for submission to the Ohio House of Representatives and several utilities in the state have offered their own proposed transition plans for introduction of retail wheeling. The current retail wheeling efforts in Ohio
(Cleveland Electric) (Cleveland Electric)
are exploratory and we cannot predict when and to what extent retail wheeling will be implemented in Ohio.
The term "stranded investment" generally refers to fixed costs approved for recovery under traditional regulatory methods that would become unrecoverable, or "stranded", as a result of wider competition. Although competitive pressures are increasing, the traditional regulatory framework remains in place and is expected to continue for the foreseeable future. We cannot predict when and to what extent competition will be allowed. We believe that pure competition (unrestricted retail wheeling for all customer classifications) is at least several years away and that any transition to pure competition will be in phases. The FERC and the PUCO have acknowledged the need to provide at least partial recovery of stranded investment as greater competition is permitted and, therefore, we believe that there will be a mechanism developed for the recovery of stranded investment. However, due to the uncertainty involved, there is a risk that some of our assets may not be fully recovered.
In 1995, we continued to experience significant competition from Cleveland Public Power (CPP), the largest municipal electric system in our service area. CPP continued to construct new distribution facilities extending into additional portions of Cleveland. CPP's progress has slowed significantly during the past year because of the discovery of a large number of safety violations in its system resulting in substantial cost overruns.
In March 1995, one of our large commercial customers which has provided annual net income of $6 million, Medical Center Co., signed a five-year contract with CPP for electric service beginning in September 1996, when its contract with us terminates. In both our appeal to the Ohio Supreme Court and petition to the FERC, it is our position that the purchase of power from CPP by this customer is in reality a direct purchase from another utility in violation of Ohio's certified territory statute. We will continue to pursue all legal and regulatory remedies to this situation.
In 1995, our economic development efforts proved successful in attracting new customers, while supporting the expansion of existing ones, for example, American Steel & Wire and Ford Motor Company. We expect that our continued emphasis on economic development along with a newly developed market segment focus will be major ingredients in providing improved revenue growth.
NUCLEAR OPERATIONS
The Company has interests in three nuclear generating units -- Davis-Besse Nuclear Power Station (Davis-Besse), Perry Nuclear Power Plant Unit 1 (Perry Unit 1) and Beaver Valley Power Station Unit 2 (Beaver Valley Unit 2). Toledo Edison operates Davis-Besse and the Company operates Perry Unit 1. Davis-Besse and Beaver Valley Unit 2 both operated extremely well in 1995. Their average three-year unit availability factors at year-end 1995 of 90% and 87%, respectively, exceeded the industry average of 81% for similar reactors. In 1995, the availability factor for Davis-Besse was 100%. The plant continues to have its best run ever operating at or near full capacity for 463 straight days through February 21, 1996.
In 1995, Perry Unit 1 improved its average three-year unit availability factor to 62% with a 1995 availability factor of 93%. Perry Unit 1 operated at or near capacity for 506 of 531 days since the end of its last refueling and maintenance outage in August 1994. Work on the comprehensive course of action plan developed in 1993 to improve the operating performance of Perry Unit 1 will be completed during the current refueling outage which began January 27, 1996.
A significant part of the strategic plan involves ongoing efforts to increase the availability and lower the cost of production of our nuclear units. In 1995, we made great progress regarding unit availability while continuing to lower production costs. The goal of our nuclear improvement program is to replicate Davis-Besse's operational excellence and cost reduction gains at Perry Unit 1 while improving performance ratings.
We externally fund the estimated costs for the future decommissioning of our nuclear units. In 1993 and 1994, we increased our decommissioning expense accruals because of revisions in our cost estimates. See Note 1(e).
Our nuclear units may be impacted by activities or events beyond our control. Operating nuclear 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 domestic nuclear unit. If one of our nuclear units is taken out of service for an extended period for any reason, including an accident at such unit or any other nuclear facility, we cannot predict whether
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regulatory authorities would impose unfavorable rate treatment. Such treatment could include taking our affected unit out of rate base, thereby not permitting us to recover our investment in and earn a return on it, or disallowing certain construction or maintenance costs. An extended outage coupled with unfavorable rate treatment could have a material adverse effect on our financial condition and results of operations. Premature plant closings could also have a material adverse effect on our financial condition and results of operations because the estimated cost to decommission the plant exceeds the current funding in the decommissioning trust.
HAZARDOUS WASTE DISPOSAL SITES
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. Allegations that the Company disposed of hazardous waste at these sites, and the amount involved, are often unsubstantiated and subject to dispute. Federal law provides that all PRPs for a particular site be held liable on a joint and several basis. 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 $350 million. However, we believe that the actual cleanup costs will be substantially lower than $350 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 $7 million at December 31, 1995, 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.
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. In 1994, Centerior Energy lowered its common stock dividend which reduced its cash outflow by over $110 million annually. This action, in turn, reduced the common stock cash dividend demand on the Company. The Company is using the increased retained cash to redeem debt and preferred stock more quickly than would otherwise be the case.
MERGER OF TOLEDO EDISON INTO THE COMPANY
We continue to seek the necessary regulatory approvals to complete the merger of Toledo Edison into the Company which was announced in 1994. The FERC has deferred action on the merger application until the merits of the open access transmission tariffs proposed by the Company and Toledo Edison are addressed in hearings. See Note 15.
CAPITAL RESOURCES AND LIQUIDITY
1993-1995 CASH REQUIREMENTS
A key part of the strategic plan is to significantly reduce the Company's level of debt and preferred stock. In 1995, we were able to continue the reduction pattern begun in 1994. The Company's obligations were reduced by $77 million in 1994 and by $13 million in 1995. We intend to continue and to accelerate redemptions.
We need cash for normal corporate operations, retirement of maturing securities, and an ongoing program of constructing and improving facilities to meet demand for electric service and to comply with government regulations. Our cash construction expenditures totaled $167 million in 1993, $164 million in 1994 and $148 million in 1995. Our debt and preferred stock maturities and sinking fund requirements totaled $310 million in 1993, $62 million in 1994 and $286 million in 1995. In addition, we optionally redeemed approximately $270 million in the period 1993-1995. This amount includes $143 million of tax-exempt issues refunded in 1995 resulting in approximately $3 million of interest savings. In May 1995, the Company issued $300 million of first mortgage bonds due in 2005 with an interest rate of 9.50%. The embedded cost of the Company's debt at the end of 1995 was 8.88% versus 8.96% in 1994 and 8.82% in 1993. In 1995, the Company and Toledo Edison renewed for a four-year term approximately $225 million in bank letters of credit supporting the equity owner participants in the Beaver Valley Unit 2 lease. See Note 11(d).
The Company also utilized short-term borrowings to help meet its cash needs. The Company had $5 million of notes payable to affiliates at December 31, 1995. See Note 12.
1996 AND BEYOND CASH REQUIREMENTS
The Company's 1996 cash requirements for construction are $128 million and for debt and preferred stock maturities and sinking fund requirements are $177 million. We
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expect to meet these requirements with internal cash generation, cash reserves and about $110 million from the sale of a AAA-rated security backed by our accounts receivable.
We expect to meet all of our 1997-2000 cash requirements with internal cash generation. Estimated cash requirements for the Company's construction program during this period total $603 million. Debt and preferred stock maturities and sinking fund requirements total $400 million for the same period. If economical, additional securities may be redeemed under optional redemption provisions, with funding expected to be provided through internal cash generation.
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. If the applicable interest coverage test is met, the Company may issue first mortgage bonds on the basis of property additions and, under certain circumstances, refundable bonds. At December 31, 1995, the Company would have been permitted to issue approximately $379 million of additional first mortgage bonds.
The Company also is able to raise funds through the sale of debt and preferred and preference stock. There are no restrictions on the Company's ability to issue preferred or preference stock.
The Company and Toledo Edison have $307 million in financing vehicles available to support their nuclear fuel leases, portions of which mature this year. See Note 6. The Company is a party to a $125 million revolving credit facility which is expected to be renewed when it matures in May 1996. See Note 12. At the end of 1995, the Company had $70 million in cash and temporary investments.
The foregoing financing resources are expected to be sufficient for the Company's needs over the next several years. However, the availability and cost of capital to meet the Company's external financing needs also depend upon such factors as financial market conditions and its credit ratings. Current credit ratings for the Company are as follows:
RESULTS OF OPERATIONS
1995 VS. 1994
Factors contributing to the 4.2% increase in 1995 operating revenues are as follows:
For the second year in a row, industrial kilowatt-hour sales increased. The increase in 1995 was 0.3%, but sales grew 2.4% excluding reductions at two low-margin steel producers (representing 7.6% of industrial revenues). Residential and commercial sales increased 2.8% and 3%, respectively, primarily because of the hot summer weather, although there was about 2% nonweather-related growth in commercial sales. Other sales increased 36% because of a 58% increase in wholesale sales due principally to the hot summer and good availability of our generating units. Weather accounted for approximately $24 million of the $41 million increase in 1995 base rate (nonfuel) revenues. Higher 1995 fuel cost recovery revenues resulted from an increase in the fuel cost factors. The weighted average of these fuel cost factors increased approximately 7%. Miscellaneous revenues decreased in 1995 primarily because the 1994 amount included the billings to other utility owners and lessees for overhead expenses related to the 1994 refueling and maintenance outage of the jointly owned Perry Unit 1.
For 1995, operating revenues were 32% residential, 32% commercial, 29% industrial and 7% other and kilowatt-hour sales were 24% residential, 28% commercial, 38% industrial and 10% other. The average prices per kilowatt-hour for residential, commercial and industrial customers were $.11, $.09 and $.07, respectively.
Operating expenses increased 5.3% in 1995. Fuel and purchased power expenses increased as higher fuel expense was partially offset by lower purchased power expense. The higher fuel expense was attributable to increased generation and more amortization of previously deferred fuel costs than the amount amortized in 1994. The higher other operation and maintenance expenses resulted primarily from charges for an ongoing inventory reduction program and the recognition of costs associated with preliminary engineering studies. Federal income taxes increased as a result of higher pretax operating income. Taxes, other than federal income taxes, increased primarily due to property tax increases resulting from
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plant additions, real estate valuation increases and a nonrecurring tax credit recorded in 1994.
1994 VS. 1993
Factors contributing to the 3% decrease in 1994 operating revenues are as follows:
The Company experienced good retail kilowatt-hour sales growth in the commercial and industrial categories in 1994; the residential category was negatively impacted by weather conditions, particularly during the summer. The revenue decrease resulted primarily from milder weather conditions in 1994 and 53% lower wholesale sales. Weather reduced base rate revenues approximately $8 million from the 1993 amount. Although total sales decreased by 4.6%, commercial sales increased 2.4%. Industrial sales increased 0.7% on the strength of increased sales to large automotive manufacturers and the broad-based, smaller industrial customer group. This growth substantiated an economic resurgence in Northeastern Ohio. Residential sales declined 0.2% because of the weather factor. Other sales decreased by 42% because of the lower sales to wholesale customers attributable to expiration of a wholesale power agreement, softer wholesale market conditions and limited power availability for bulk power transactions at certain times because of generating plant outages. Lower 1994 fuel cost recovery revenues resulted from favorable changes in the fuel cost factors. The weighted average of these fuel cost factors dropped by approximately 5%.
For 1994, operating revenues were 31% residential, 32% commercial, 30% industrial and 7% other and kilowatt-hour sales were 24% residential, 29% commercial, 39% industrial and 8% other. The average prices per kilowatt-hour for residential, commercial and industrial customers were $.11, $.09 and $.06, respectively. The changes from 1993 were not significant.
Operating expenses were 15% lower in 1994. Operation and maintenance expenses for 1993 included $130 million of net benefit expenses related to an early retirement program, called the Voluntary Transition Program (VTP), and other charges totaling $35 million. The VTP benefit expenses in 1993 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). A smaller work force and ongoing cost reduction measures also lowered operation and maintenance expenses. More nuclear generation and less coal-fired generation accounted for a large part of the lower fuel and purchased power expenses in 1994. Depreciation and amortization expenses increased primarily because of higher nuclear plant decommissioning expenses as discussed in Note 1(e). Deferred operating expenses were greater primarily because of the write-off of $117 million of phase-in deferred operating expenses in 1993 as discussed in Note 7(e). The 1993 deferrals also included $52 million of postretirement benefit curtailment cost deferrals related to the VTP. See Note 9(b). Federal income taxes increased as a result of higher pretax operating income.
As discussed in Note 4(b), $351 million of our Perry Unit 2 investment was written off in 1993. Also, as discussed in Note 7(e), phase-in deferred carrying charges of $519 million were written off in 1993. The change in the federal income tax credit amounts for nonoperating income was attributable to these write-offs.
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INCOME STATEMENT The Cleveland Electric Illuminating Company and Subsidiaries
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(1) Includes purchased power expense of $102 million, $111 million and $120 million in 1995, 1994 and 1993, respectively, for all purchases from Toledo Edison.
RETAINED EARNINGS
The accompanying notes are an integral part of these statements.
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BALANCE SHEET
The accompanying notes are an integral part of this statement.
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The Cleveland Electric Illuminating Company and Subsidiaries
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CASH FLOWS The Cleveland Electric Illuminating Company and Subsidiaries
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(2) Increases in Nuclear Fuel and Nuclear Fuel Lease Obligations in the Balance Sheet resulting from the noncash capitalizations under nuclear fuel agreements are excluded from this statement.
The accompanying notes are an integral part of this statement.
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STATEMENT OF PREFERRED STOCK The Cleveland Electric Illuminating Company 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
The Company is an electric utility and a wholly owned subsidiary of Centerior Energy. The Company's financial statements have historically included the accounts of the Company's wholly owned subsidiaries, which in the aggregate were not material. In 1995, the Company formed a wholly owned subsidiary to serve as the transferor in connection with an asset-backed securitization expected to be completed in 1996. At December 31, 1995, the subsidiary was not yet funded. In 1994, the Company transferred its investments in three wholly owned subsidiaries to Centerior Energy at cost ($26 million) via property dividends.
The Company follows the Uniform System of Accounts prescribed by the FERC and adopted by the PUCO. Rate-regulated utilities are subject to SFAS 71 which governs accounting for the effects of certain types of rate regulation. Pursuant to SFAS 71, certain incurred costs are deferred for recovery in future rates. See Note 7.
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. The estimates are based on an analysis of the best information available. Actual results could differ from those estimates.
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 joint 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 $141 million, $136 million and $167 million in 1995, 1994 and 1993, 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 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 (to 2007). 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) DEPRECIATION AND DECOMMISSIONING
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 1995 and 3.4% in both 1994 and 1993. The annual straight-line depreciation rate for nuclear property is 2.5%. In conjunction with its pending rate case, the Company has asked the PUCO to
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approve an increase of this depreciation rate to approximately 3%.
The Company accrues the estimated costs of decommissioning its three nuclear generating units. The accruals are required to be funded in an external trust. The PUCO requires that the expense and payments to the external trusts be determined on a levelized basis by dividing the unrecovered decommissioning costs in current dollars by the remaining years in the licensing period of each unit. This methodology requires that the net earnings on the trusts be reinvested therein with the intent of having net earnings offset inflation. The PUCO requires that the estimated costs of decommissioning and the funding level be reviewed at least every five years.
In 1994, the Company increased its annual decommissioning expense accruals to $13 million from the $6 million level in 1993. The accruals are reflected in current rates. The increased accruals in 1994 were derived from updated, site-specific studies for each of the units. The revised estimates reflect the DECON method of decommissioning (prompt decontamination), and the locations and cost characteristics specific to the units, and include costs associated with decontamination, dismantlement and site restoration.
The revised estimates for the units in 1993 and 1992 dollars and in dollars at the time of license expiration, assuming a 4% annual inflation rate, are as follows:
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(1) Dollar amounts in 1993 dollars. (2) Dollar amount in 1992 dollars.
The updated estimates reflect substantial increases from the prior PUCO-recognized aggregate estimates of $142 million in 1987 and 1986 dollars.
The classification, Accumulated Depreciation and Amortization, in the Balance Sheet at December 31, 1995 includes $71 million of decommissioning costs previously expensed and the earnings on the external trust 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. The trust earnings are recorded as an increase to the trust assets and the related component of the decommissioning reserve (included in Accumulated Depreciation and Amortization).
The staff of the Securities and Exchange Commission has questioned certain of the current accounting practices of the electric utility industry, including those of the Company, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in the financial statements. In response to these questions, the Financial Accounting Standards Board (FASB) is reviewing the accounting for removal costs, including decommissioning. If current accounting practices are changed, the annual provision for decommissioning could increase; the estimated cost for decommis- sioning could be recorded as a liability rather than as accumulated depreciation; and trust fund income from the external decommissioning trusts could be reported as investment income rather than as a reduction to decommissioning expense. The FASB issued an exposure draft on the subject on February 7, 1996.
(F) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment are stated at original cost less amounts disallowed by the PUCO. Construction costs include related payroll taxes, retirement benefits, 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 10.33% in 1995, 9.68% in 1994 and 9.63% in 1993.
Maintenance and repairs for plant and equipment 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 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 the leases. The amortization and the lease expense amounts are reported in the Income Statement as Generation Facilities Rental Expense, Net.
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(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. See Note 7(a). 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.
(I) FEDERAL INCOME TAXES
The Company uses the liability method of accounting for income taxes in accordance with SFAS 109. See Note 8. 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, the Company must record a liability for its 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. See Note 7(a).
Investment tax credits are deferred and amortized over the lives of the applicable property as a reduction of depreciation expense. See Note 7(d) 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. These leases extend through 2017 and 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 renew the leases. The leases include conditions for mandatory termination (and possible repurchase of the leasehold interest) for events of default.
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 such payments have been made on behalf of Toledo Edison.
Future minimum lease payments under the operating leases at December 31, 1995 are summarized as follows:
Rental expense is accrued on a straight-line basis over the terms of the leases. The amount recorded in 1995, 1994 and 1993 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. Purchased power expense for this transaction was $98 million, $108 million and $103 million in 1995, 1994 and 1993, respectively. We anticipate that this purchase will continue indefinitely. The future minimum lease payments through 2017 associated with Beaver Valley Unit 2 aggregate $1.35 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
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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, 1995 includes the following facilities owned by the 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.
(4) CONSTRUCTION AND CONTINGENCIES
(A) CONSTRUCTION PROGRAM
The estimated cost of the Company's construction program for the 1996-2000 period is $761 million, including AFUDC of $30 million and excluding nuclear fuel.
The Clean Air Act Amendments of 1990 (Clean Air Act) requires, among other things, significant reductions in the emission of sulfur dioxide and nitrogen oxides by fossil-fueled generating units. Our strategy provides for compliance primarily through greater use of low-sulfur coal at some of our units and the use of emission allowances. Total capital expenditures from 1991 through 1995 in connection with Clean Air Act compliance amounted to $46 million. The plan will require additional capital expenditures over the 1996-2005 period of approximately $49 million for nitrogen oxide control equipment and other plant process modifications. In addition, higher fuel and other operation and maintenance expenses will be incurred. 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.
(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. 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.
(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 sites. The Company has accrued a liability totaling $7 million at December 31, 1995 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 the discussion of these and other risks in Management's Financial Analysis -- Outlook-Nuclear Operations.
(B) NUCLEAR INSURANCE
The Price-Anderson Act limits the public 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 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 utility owners and lessees of Davis-Besse, Perry and Beaver Valley also have insurance coverage for damage to property at these sites (including leased fuel and cleanup costs). Coverage amounted to $2.75 billion for each site
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as of January 1, 1996. 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. In addition, the Company can be assessed a maximum of $23 million under these policies 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 80% 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 $307 million ($157 million from intermediate-term notes and $150 million from bank credit arrangements). The intermediate-term notes mature in 1996 and 1997 ($84 million in September 1996 and $73 million in September 1997). The bank credit arrangements terminate in October 1996. The special-purpose corporation plans to obtain alternate financing in 1996 to replace the $234 million of financing expiring in 1996. At December 31, 1995, $142 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 $41 million, $34 million and $20 million, respectively, at December 31, 1995. The nuclear fuel amounts financed and capitalized also included interest charges incurred by the lessors amounting to $4 million in 1995, $7 million in 1994 and $9 million in 1993. The estimated future lease amortization payments for the Company based on projected consumption are $55 million in 1996, $48 million in 1997, $40 million in 1998, $37 million in 1999 and $35 million in 2000.
(7) REGULATORY MATTERS
(A) REGULATORY ACCOUNTING REQUIREMENTS AND REGULATORY ASSETS
The Company is subject to the provisions of SFAS 71 and has complied with its provisions. SFAS 71 provides, among other things, for the deferral of certain incurred costs that are probable of future recovery in rates. We monitor changes in market and regulatory conditions and consider the effects of such changes in assessing the continuing applicability of SFAS 71. Criteria that could give rise to discontinuation of the application of SFAS 71 include: (1) increasing competition which significantly restricts the Company's ability to charge prices which allow it to recover operating costs, earn a fair return on invested capital and recover the amortization of regulatory assets and (2) a significant change in the manner in which rates are set by the PUCO from cost-based regulation to some other form of regulation. Regulatory assets represent probable future revenues to the Company associated with certain incurred costs, which it will recover from customers through the rate-making process.
Effective January 1, 1996, the Company adopted SFAS 121 which imposes stricter criteria for carrying regulatory assets than SFAS 71 by requiring that such assets be probable of recovery at each balance sheet date. The criteria under SFAS 121 for plant assets require such assets to be written down only if the book value exceeds the projected net future cash flows.
Regulatory assets in the Balance Sheet are as follows:
* Represent deferrals of operating expenses and carrying charges for Perry Unit 1 and Beaver Valley Unit 2 in 1987 and 1988 which are being amortized over the lives of the related property.
As of December 31, 1995, customer rates provide for recovery of all the above regulatory assets, except those related to the Rate Stabilization Program discussed below. The remaining recovery periods for all of the regulatory assets listed above range from 16 to 33 years.
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(B) RATE CASE
In April 1995, the Company and Toledo Edison filed requests with the PUCO for price increases aggregating $119 million annually to be effective in 1996. The price increases are necessary to recover cost increases and amortization of certain costs deferred since 1992 pursuant to the Rate Stabilization Program. If their requests are approved, the Company and Toledo Edison intend to freeze prices until at least 2002 with the expectation that increased sales and cost control measures will preclude the need for further price increases. If circumstances make it impossible to earn a fair return for Centerior Energy common stock share owners over time, the Company and Toledo Edison would ask for a further increase, but only after taking all appropriate actions to make such a request unnecessary.
In November 1995, the PUCO Staff issued its report addressing the rate case. The Staff recommended that the PUCO grant the full $119 million price increase requested ($84 million for the Company and $35 million for Toledo Edison). However, the Staff also recommended that the price increase be conditioned upon the commitment by the Company and Toledo Edison "to a significant revaluation of their asset bases over some finite period of time."
In December 1995, the PUCO ordered an investigation into the financial conditions, rates and practices of the Company and Toledo Edison to identify outcomes and remedies other than those routinely applied during the rate case process.
In late January 1996, the Staff proposed an incremental reduction (currently, an aggregate of $1.25 billion for the Company and Toledo Edison) beyond the normal level in nuclear plant and regulatory assets within five years. The Staff proposed that the Company and Toledo Edison have flexibility to determine how to achieve this incremental asset revaluation, but no additional price increases to recover the accelerated asset revaluation were proposed. Any incremental revaluation of assets would be for regulatory purposes and would cause prices and revenues after the five-year period to be lower than they otherwise would be in conjunction with any rate case following such revaluation. The Staff's asset revaluation proposal represents a substantial change in the form of rate-making traditionally followed by the PUCO and is inconsistent with the Ohio statutes that define the rate-making process. The PUCO is not bound by the recommendations of the Staff. A decision by the PUCO is anticipated in the second quarter of 1996.
(C) ASSESSMENT OF POTENTIAL OUTCOMES
We continually assess the effects of competition and the changing industry and regulatory environment on operations, the Company's ability to recover regulatory assets and the Company's ability to continue application of SFAS 71. If, as a result of the pending rate case or other events, we determine that the Company no longer meets the criteria for SFAS 71, the Company would be required to record a before-tax charge to write off the regulatory assets shown above and evaluate whether the Company's property, plant and equipment should be written down. In the more likely event that only a portion of operations (such as nuclear operations) no longer meets the criteria of SFAS 71, a write-off would be limited to regulatory assets, if any, that are not reflected in the Company's cost-based prices established for the remaining regulated operations. In addition, we would be required to evaluate whether the changes in the competitive and regulatory environment which led to discontinuing the application of SFAS 71 to a portion of the Company's operations would also result in a write-down of the Company's property, plant and equipment pursuant to SFAS 121.
We believe application of SFAS 121 in that event will not result in a write-off of regulatory assets unless the PUCO denies recovery of such assets or if we conclude, as a result of the outcome of the Company's pending rate case or some other event, that recovery is not probable for some or all of the regulatory assets. Furthermore, a write-down under SFAS 121 of the Company's property, plant and equipment is not expected.
(D) RATE STABILIZATION PROGRAM
The Rate Stabilization Program that the PUCO approved in October 1992 allowed the Company to defer and subsequently amortize and recover certain costs not currently recovered in rates and to accelerate amortization of certain benefits during the 1992-1995 period. Recovery of the deferrals will begin with the effective date of the PUCO's order in the pending rate case. The regulatory assets recorded included 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 incremental expenses resulting from the adoption of SFAS 106 (see Note 9(b)). The cost deferrals recorded in 1995, 1994 and 1993 pursuant to these provisions were $75 million, $70 million and $116 million, respectively. The regulatory accounting measures also provided for the accelerated amortization of certain unrestricted excess deferred tax and unrestricted investment tax credit balances and an excess interim spent fuel
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storage accrual balance for Davis-Besse. The total annual amount of such accelerated benefits was $28 million in 1995, 1994 and 1993.
(E) PHASE-IN DEFERRALS
In 1993, upon completing a comprehensive study which led to our strategic plan, we concluded that projected revenues would not provide for recovery of deferrals recorded pursuant to a phase-in plan approved by the PUCO in 1989 and, consequently, that the deferrals would have to be written off. Such deferrals were scheduled to be recovered in 1994 through 1998. 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).
(8) FEDERAL INCOME TAX
The components of federal income tax expense (credit) recorded in the Income Statement were as follows:
The deferred federal income tax expense results from the temporary differences that arise from the different years certain expenses are recognized for tax purposes as opposed to financial reporting purposes. Such temporary differences affecting operating expenses relate principally to depreciation and deferred operating expenses whereas those affecting nonoperating income principally relate to deferred carrying charges and the 1993 write-offs.
Federal income tax, computed by multiplying income before taxes by the 35% statutory rate, is reconciled to the amount of federal income tax recorded on the books 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.
For tax reporting purposes, the Perry Unit 2 abandonment was recognized in 1994 and resulted in a $204 million loss with a corresponding $71 million reduction in federal income tax liability. Because of the alternative minimum tax (AMT), $40 million of the $71 million was realized in 1994. The remaining $31 million will not be realized until 1999. Additionally, a repayment of approximately $29 million of previously allowed investment tax credits was recognized in 1994.
Under SFAS 109, temporary differences and carryforwards resulted in deferred tax assets of $425 million and deferred tax liabilities of $1.723 billion at December 31, 1995 and deferred tax assets of $418 million and deferred tax liabilities of $1.652 billion at December 31, 1994. These are summarized as follows:
For tax purposes, net operating loss (NOL) carryforwards of approximately $192 million are available to reduce future taxable income and will expire in 2005 through 2009. The 35% tax effect of the NOLs is $67 million. Additionally, AMT credits of $133 million that may be carried forward indefinitely are available to reduce future tax.
(9) RETIREMENT BENEFITS
(A) RETIREMENT INCOME PLAN
Centerior Energy sponsors jointly with its subsidiaries a noncontributing pension plan (Centerior Pension Plan) which covers all employee groups. 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 comply with the Employee Retirement Income Security Act of 1974 guidelines.
In 1993, eligible employees were offered the VTP, an early retirement program. Operating expenses for Center-
(Cleveland Electric) (Cleveland Electric)
ior Energy and its subsidiaries in 1993 included $205 million of pension plan accruals to cover enhanced VTP benefits offset by a credit of $81 million resulting from a settlement of pension obligations through lump sum payments to almost all the VTP retirees.
Pension and VTP costs (credits) for Centerior Energy and its subsidiaries for 1993 through 1995 were comprised of the following components:
Pension and VTP costs (credits) for the Company and its pro rata share of the Service Company's costs were $(5) million, $2 million and $62 million for 1995, 1994 and 1993, respectively.
The following table presents a reconciliation of the funded status of the Centerior Pension Plan. The Company's share of the Centerior Pension Plan's total projected benefit obligation approximates 50%.
A September 30 measurement date was used for 1995 and 1994 reporting. At December 31, 1995, the settlement (discount) rate and long-term rate of return on plan assets assumptions were 8% and 11%, respectively. The long-term rate of annual compensation increase assumption was 3.5% in 1996 and 1997 and 4% thereafter. At December 31, 1994, the settlement rate and long-term rate of return on plan assets assumptions were 8.5% and 10%, respectively. The long-term rate of annual compensation increase assumption was 3.5% for 1995 and 1996 and 4% thereafter. At December 31, 1995 and 1994, the Company's net prepaid pension cost included in Regulatory and Other Assets -- Other in the Balance Sheet was $11 million and $7 million, respectively.
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. 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. Prior to 1993, the costs of these benefits were expensed as paid, which was consistent with rate-making practices.
The components of the total postretirement benefit costs for 1993 through 1995 were as follows:
These amounts included costs for the Company and its pro rata share of the Service Company's costs.
In 1995, 1994 and 1993, the Company deferred incremental SFAS 106 expenses (in excess of the amounts paid) of $3 million, $4 million and $60 million, respectively, pursuant to a provision of the Rate Stabilization Program. See Note 7(d).
(Cleveland Electric) (Cleveland Electric)
The accumulated postretirement benefit obligation and accrued postretirement benefit cost for the Company and its share of the Service Company's obligation are as follows:
The Balance Sheet classification of Retirement Benefits at December 31, 1995 and 1994 includes only the Company's accrued postretirement benefit cost of $65 million and $59 million, respectively, and excludes the Service Company's portion since the Service Company's total accrued cost is carried on its books. A September 30 measurement date was used for 1995 and 1994 reporting. At December 31, 1995 and 1994, the settlement rate and the long-term rate of annual compensation increase assumptions were the same as those discussed for pension reporting in Note 9(a). At December 31, 1995, the assumed annual health care cost trend rates (applicable to gross eligible charges) were 8% for medical and 7.5% for dental in 1996. Both rates reduce gradually to a fixed rate of 4.75% by 2003. 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 one percentage point in each future year, the accumulated postretirement benefit obligation as of December 31, 1995 would increase by $3 million and the aggregate of the service and interest cost components of the annual postretirement benefit cost would increase by $0.3 million.
(10) GUARANTEES
The Company has guaranteed certain loan and lease obligations of two coal suppliers under two long-term coal supply contracts. At December 31, 1995, the principal amount of the loan and lease obligations guaranteed by the Company under both contracts was $39 million. In addition, the Company may be responsible for mine closing costs when one of the contracts is terminated. At December 31, 1995, the unfunded costs of closing this mine as estimated by the supplier were $32 million.
The prices under both contracts which include certain minimum payments are sufficient to satisfy the loan and lease obligations and mine closing costs over the lives of the contracts. If either contract is terminated early for any reason, the Company would attempt to reduce the termination charges and would ask the PUCO to allow recovery of such charges from customers through the fuel factor.
(11) CAPITALIZATION
(A) CAPITAL STOCK TRANSACTIONS
Preferred stock shares sold and retired during the three years ended December 31, 1995 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, 1995, the Company had $212 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 $30 million in both 1996 and 1997, $15 million in 1998 and $33 million in both 1999 and 2000.
The annual preferred stock mandatory redemption provisions are as follows:
* All outstanding shares to be redeemed on December 1, 2001.
(Cleveland Electric) (Cleveland Electric)
In 1995, the Company purchased 1,000 shares of Serial Preferred Stock, $90.00 Series S, which will reduce the 2002 redemption requirement shown in the above table.
The annualized preferred dividend requirement at December 31, 1995 was $41 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 these issues averaged 7.23% and 7.02%, respectively, in 1995.
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:
* Secured by first mortgage bonds. Long-term debt matures during the next five years as follows: $147 million in 1996, $51 million in 1997, $74 million in 1998, $154 million in 1999 and $10 million in 2000.
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.
Certain credit agreements of the Company contain covenants relating to fixed charge coverage ratios and limitations on secured financing other than through first mortgage bonds or certain other transactions. In June 1995, the Company and Toledo Edison replaced letters of credit in connection with the sale and leaseback of Beaver Valley Unit 2 that were due to expire with new letters of credit expiring in June 1999. The letters of credit are in an aggregate amount of approximately $225 million and are secured by first mortgage bonds of the Company and Toledo Edison in the proportion of 40% and 60%, respectively. At December 31, 1995, the Company had outstanding $2 million of bank loans secured by subordinated mortgage collateral.
(12) SHORT-TERM BORROWING ARRANGEMENTS
Centerior Energy has a $125 million revolving credit facility through May 1996. 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. The credit agreement is secured with first mortgage bonds of the Company and Toledo Edison in the proportion of 40% and 60%, respectively. The banks' fee is 0.625% per annum payable quarterly in addition to interest on any borrowings. There were no borrowings under the facility at December 31, 1995. Also, the Company and Toledo Edison may borrow from each other on a short-term basis. At December 31, 1995, the Company had total short-term borrowings of $5 million from its affiliates with an interest rate of 6.25%.
(13) FINANCIAL INSTRUMENTS
The estimated fair values at December 31, 1995 and 1994 of financial instruments that do not approximate their carrying amounts in the Balance Sheet are as follows:
Noncash investments in the Nuclear Plant Decommissioning Trusts are summarized in the following table.
(Cleveland Electric) (Cleveland Electric)
The fair value of these trusts is estimated based on the quoted market prices for the investment securities. As a result of adopting the new accounting standard for certain investments in debt and equity securities, SFAS 115, in 1994, the carrying amount of these trusts approximates fair value. 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, 1995 and 1994 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, 1995.
(15) PENDING MERGER OF TOLEDO EDISON INTO THE COMPANY
In March 1994, Centerior Energy announced a plan to merge Toledo Edison into the Company. 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.
Various aspects of the merger are subject to the approval of the FERC and other regulatory authorities. The FERC has deferred action on the merger application until the merits of the open access transmission tariffs proposed by the Company and Toledo Edison are addressed in hearings. The PUCO and the Pennsylvania Public Utility Commission have approved the merger. NRC action on the request by the Company and Toledo Edison for authorization to transfer certain NRC licenses to the merged entity is not expected until approval has been obtained from the FERC.
In June 1995, share owners of Toledo Edison's preferred stock approved the merger and share owners of the Company's preferred stock approved the authorization of additional shares of preferred stock. When the merger becomes effective, share owners of Toledo Edison's preferred stock will exchange their shares for preferred stock shares of the Company having substantially the same terms. Debt holders of the merging companies will become debt holders of the Company.
For the merging companies, the combined pro forma operating revenues were $2.516 billion, $2.422 billion and $2.475 billion and the combined pro forma net income (loss) was $281 million, $268 million and $(876) million for the years 1995, 1994 and 1993, respectively. The pro forma data is based on accounting for the merger on a method similar to a pooling of interests. The pro forma data is not necessarily 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)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Share Owners and Board of Directors of The Cleveland Electric 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, 1995 and 1994, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1995. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the schedule 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, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles.
As discussed further in Note 9, a change was made in the method of accounting 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 schedule of The Cleveland Electric Illuminating Company and subsidiaries listed in the Index to Schedules is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states 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 LLP
Cleveland, Ohio February 21, 1996
(Cleveland Electric) (Cleveland Electric)
FINANCIAL AND STATISTICAL REVIEW
OPERATING REVENUES (millions of dollars)
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OPERATING EXPENSES (millions of dollars)
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INCOME (LOSS) (millions of dollars)
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INCOME (LOSS) (millions of dollars)
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(a) Includes early retirement program expenses and other charges of $165 million. (b) Includes write-off of phase-in deferrals of $636 million, consisting of $117 million of deferred operating expenses and $519 million of deferred carrying charges. (c) 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
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CAPITALIZATION (millions of dollars & %)
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(d) Includes write-off of Perry Unit 2 of $351 million.
(e) Reduced by net energy used by the Seneca Pumped Storage Plant for pumping.
(Cleveland Electric) (Cleveland Electric)
MANAGEMENT'S FINANCIAL ANALYSIS
OUTLOOK
STRATEGIC PLAN
We continued to make progress during the second year of our eight-year strategic plan, but we remain keenly aware of the magnitude of the problems that face us. The strategic plan was created by Centerior Energy Corporation (Centerior Energy), along with The Toledo Edison Company (Company) and The Cleveland Electric Illuminating Company (Cleveland Electric), to achieve two major goals: strengthening their financial conditions and improving their competitive positions. The Company and Cleveland Electric are the two wholly owned electric utility subsidiaries of Centerior Energy. The plan's objectives relate to the combined operations of all three companies. The objectives are to achieve profitable revenue growth, become a leader in customer satisfaction, build a winning employee team, attain increasingly competitive power supply costs and maximize share owner return on Centerior Energy common stock. We are not yet positioned to compete in a less regulated electric utility industry, but every major action being taken -- strategic planning, revenue enhancement, cost reduction, improvement of work practices and application for increased prices -- is part of a comprehensive effort to succeed in an increasingly competitive environment.
A primary objective of the strategic plan is continued and significant revenue growth even as our markets become more competitive. The Company's retail revenues adjusted for weather and fuel costs have grown about 1% annually since 1990. During 1995, we took aggressive steps to increase revenues through enhanced marketing strategies. Also, our economic development efforts proved successful in attracting major new customers and supporting the expansion of existing ones. Although we are not satisfied with our growth rate, we expect that our marketing activity will improve revenue growth.
The rate case which the Company and Cleveland Electric filed with The Public Utilities Commission of Ohio (PUCO) in April 1995 is a critical factor to the success of the strategic plan. We do not see this rate case as a continuation of business as usual but as an important turning point which should, if we are successful in accomplishing the objectives discussed below, bring an end to price increases for the foreseeable future. A successful conclusion of the case would speed our transition to a more competitive company by providing additional cash to lower costs by accelerating the pay-down of debt and preferred stock. In our view, a successful conclusion would include approval of the full price increase requested with a regulatory commitment to maintain the established price levels over an appropriate transition period. This should be coupled with a means to accelerate recognition of regulatory assets (described in Note 7(a)) and nuclear generating assets concurrent with our cost control and revenue enhancement efforts in order to earn a fair return for Centerior Energy common stock share owners over time.
Another key part of our strategy is offering long-term contracts to those large customers who could have incentives to change power suppliers. In 1995, 74% of our industrial kilowatt-hour sales and 13% of our commercial kilowatt-hour sales were under long-term contracts. We are renegotiating contracts before they expire and in most cases are retaining customers under new long-term contracts.
We are continuing efforts to reduce fixed financing costs in order to strengthen our financial condition. During 1995, utilizing strong cash flow and refinancing at favorable terms, the Company reduced interest expense and preferred dividends by $7 million and outstanding debt and preferred stock by $113 million.
Our overall costs are high relative to many of our neighboring utilities as a result of our substantial nuclear investment. The strategic plan calls for making us more competitive by continuing to reduce operating expenses and capital expenditures. In 1995, to improve the focus on cost reduction and other strategic plan objectives, Centerior Energy and its subsidiaries restructured into six business groups. The new organization includes groups to manage the generation, distribution and transmission businesses; provide services and administrative functions; and invest in nonregulated enterprises. This arrangement will also enhance each group's ability to identify cost reductions by focusing on margins and improving work practices and customer service. We will also continue to aggressively pursue initiatives to reduce the heavy tax burden imposed upon us by the state and local tax structure in Ohio.
RATE CASE AND REGULATORY ACCOUNTING
In April 1995, the Company and Cleveland Electric filed requests with the PUCO for price increases aggregating $119 million annually to be effective in 1996. The price increases are necessary to recover cost increases and amortization of certain costs deferred since 1992 pursuant to the Rate Stabilization Program discussed below and in
(Toledo Edison) (Toledo Edison)
Note 7. If their requests are approved, the Company and Cleveland Electric intend to freeze prices until at least 2002 with the expectation that increased sales and cost control measures will obviate the need for further price increases. If circumstances make it impossible to earn a fair return for Centerior Energy common stock share owners over time, the Company and Cleveland Electric would ask for a further increase -- but only after taking all appropriate actions to make such a request unnecessary.
In December 1995, the PUCO ordered an investigation into the financial conditions, rates and practices of the Company and Cleveland Electric.
In its report on the rate request, the PUCO Staff recommended approval of the $119 million requested ($35 million for the Company and $84 million for Cleveland Electric), subject to a commitment by the Company and Cleveland Electric to significantly revalue their assets. In late January 1996, the Staff proposed that the Company and Cleveland Electric significantly revalue their nuclear plant and regulatory assets within a five-year period. The Staff's asset revaluation proposal is inconsistent with the Ohio statutes that define the rate-making process. The PUCO is not bound by the Staff's recommendations. A decision by the PUCO is anticipated in the second quarter of 1996.
The outcome of the rate case could affect the Company's ability to meet the criteria of Statement of Financial Accounting Standards (SFAS) 71 for all or part of its operations which could result in the write-off of all or a part of the regulatory assets shown in Note 7(a). In our changing industry, other events independent of the outcome of the rate case could also result in write-offs or write-downs of assets.
See Note 7 for a full discussion and analysis of the rate case, SFAS 71 and other financial accounting requirements and the potential implications of these accounting requirements for the Company's results of operations and financial position.
RATE STABILIZATION PROGRAM
Under a Rate Stabilization Program approved by the PUCO in 1992, we agreed to freeze base rates until 1996 and limit rate increases through 1998. In exchange, we were permitted to defer through 1995 and subsequently recover certain costs not currently recovered in rates and to accelerate amortization of certain benefits. Deferral of those costs and amortization of those benefits were completed in November 1995 and aggregated $56 million for the Company in 1995. Recovery is expected to begin with the effective date of the PUCO's order in the pending rate case. Annual amortization of the deferred costs for the Company is $10 million which began in December 1995. Consequently, earnings in 1996 will be sharply lower than in 1995. Also contributing to lower earnings are the expectations that the requested price increase will not be effective until the second quarter of 1996 and results from increased marketing and cost reduction efforts will take time to achieve.
COMPETITION
Major structural changes are taking place in the electric utility industry which are expected to place downward pressure on prices and to increase competition for customers' business. The changes are coming from both federal and state authorities. Many of the changes began when the Energy Policy Act of 1992 permitted competition in the electric utility industry through broader access to a utility's transmission system. In March 1995, the Federal Energy Regulatory Commission (FERC) issued proposed rules relating to open access transmission services by public utilities, recovery of stranded investment and other related matters. The open access transmission rules require utilities to deliver power from other utilities or generation sources to their wholesale customers. In May 1995, the Company and Cleveland Electric filed open access transmission tariffs with the FERC which used the proposed rules as a guideline. These tariffs are currently pending.
Several groups in Ohio are studying the possible application of retail wheeling. Retail wheeling occurs when a customer obtains power from a utility company other than its local utility. The PUCO is sponsoring informal discussions among a group of business, utility and consumer interests to explore ways of promoting competitive options without unduly harming the interests of utility company share owners or customers. Legislative proposals are being drafted for submission to the Ohio House of Representatives and several utilities in the state have offered their own proposed transition plans for introduction of retail wheeling. The current retail wheeling efforts in Ohio are exploratory and we cannot predict when and to what extent retail wheeling will be implemented in Ohio.
The term "stranded investment" generally refers to fixed costs approved for recovery under traditional regulatory methods that would become unrecoverable, or "stranded", as a result of wider competition. Although
(Toledo Edison) (Toledo Edison)
competitive pressures are increasing, the traditional regulatory framework remains in place and is expected to continue for the foreseeable future. We cannot predict when and to what extent competition will be allowed. We believe that pure competition (unrestricted retail wheeling for all customer classifications) is at least several years away and that any transition to pure competition will be in phases. The FERC and the PUCO have acknowledged the need to provide at least partial recovery of stranded investment as greater competition is permitted and, therefore, we believe that there will be a mechanism developed for the recovery of stranded investment. However, due to the uncertainty involved, there is a risk that some of our assets may not be fully recovered.
In 1995, we continued to experience significant competition from municipal electric systems. Also, in Toledo, the City Council responded to a petition drive by appropriating funds to complete a consultant's study on whether to create a municipal electric utility. This study is expected to be completed by mid-1996.
In October 1995, Chase Brass & Copper Co. Inc., which has provided annual net income of $2 million, terminated its service from the Company and began to receive its electric service from a consortium of other providers. We have filed lawsuits contending that this arrangement violates the legal limits of sales and delivery of power by municipal electric systems outside their boundaries. We will continue to pursue all legal and regulatory remedies to this situation.
In 1995, our economic development efforts proved successful in attracting major new customers, such as North Star BHP Steel, Worthington Steel and Aluminum Company of America, while supporting the expansion of existing ones. We expect that our continued emphasis on economic development along with a newly developed market segment focus will be major ingredients in providing improved revenue growth.
NUCLEAR OPERATIONS
The Company has interests in three nuclear generating units -- Davis-Besse Nuclear Power Station (Davis-Besse), Perry Nuclear Power Plant Unit 1 (Perry Unit 1) and Beaver Valley Power Station Unit 2 (Beaver Valley Unit 2) -- and operates the first one. Cleveland Electric operates Perry Unit 1. Davis-Besse and Beaver Valley Unit 2 both operated extremely well in 1995. Their average three-year unit availability factors at year-end 1995 of 90% and 87%, respectively, exceeded the industry average of 81% for similar reactors. In 1995, the availability factor for Davis-Besse was 100%. The plant continues to have its best run ever operating at or near full capacity for 463 straight days through February 21, 1996.
In 1995, Perry Unit 1 improved its average three-year unit availability factor to 62% with a 1995 availability factor of 93%. Perry Unit 1 operated at or near capacity for 506 of 531 days since the end of its last refueling and maintenance outage in August 1994. Work on the comprehensive course of action plan developed in 1993 for Cleveland Electric to improve the operating performance of Perry Unit 1 will be completed during the current refueling outage which began January 27, 1996.
A significant part of the strategic plan involves ongoing efforts to increase the availability and lower the cost of production of our nuclear units. In 1995, we made great progress regarding unit availability while continuing to lower production costs. The goal of our nuclear improvement program is for Cleveland Electric to replicate Davis-Besse's operational excellence and cost reduction gains at Perry Unit 1 while improving performance ratings.
We externally fund the estimated costs for the future decommissioning of our nuclear units. In 1993 and 1994, we increased our decommissioning expense accruals because of revisions in our cost estimates. See Note 1(e).
Our nuclear units may be impacted by activities or events beyond our control. Operating nuclear 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 domestic nuclear unit. If one of our nuclear units is taken out of service for an extended period 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, thereby not permitting us to recover our investment in and earn a return on it, or disallowing certain construction or maintenance costs. An extended outage coupled with unfavorable rate treatment could have a material adverse effect on our financial condition and results of operations. Premature plant closings could also have a material adverse effect on our financial condition and results of operations because the estimated cost to decommission the plant exceeds the current funding in the decommissioning trust.
(Toledo Edison) (Toledo Edison)
HAZARDOUS WASTE DISPOSAL SITES
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. Allegations that the Company disposed of hazardous waste at these sites, and the amount involved, are often unsubstantiated and subject to dispute. Federal law provides that all "potentially responsible parties" (PRPs) for a particular site be held liable on a joint and several basis. 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 $5 million at December 31, 1995, 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.
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. 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 prior to its merger into Cleveland Electric, as discussed below.
MERGER OF THE COMPANY INTO CLEVELAND ELECTRIC
We continue to seek the necessary regulatory approvals to complete the merger of the Company into Cleveland Electric which was announced in 1994. The FERC has deferred action on the merger application until the merits of the open access transmission tariffs proposed by the Company and Cleveland Electric are addressed in hearings. See Note 15.
CAPITAL RESOURCES AND LIQUIDITY
1993-1995 CASH REQUIREMENTS
A key part of the strategic plan is to significantly reduce the Company's level of debt and preferred stock. In 1995, we were able to continue the reduction pattern begun in 1994. The Company's obligations were reduced by $66 million in 1994 and by $113 million in 1995. We intend to continue and to accelerate redemptions.
We need cash for normal corporate operations, retirement of maturing securities, and an ongoing program of constructing and improving facilities to meet demand for electric service and to comply with government regulations. Our cash construction expenditures totaled $42 million in 1993, $41 million in 1994 and $53 million in 1995. Our debt and preferred stock maturities and sinking fund requirements totaled $58 million in both 1993 and 1994 and $83 million in 1995. In addition, we optionally redeemed approximately $200 million in the period 1993-1995. This amount includes $94 million of tax-exempt issues refunded in 1995 resulting in approximately $4 million of interest savings. The embedded cost of the Company's debt at the end of 1995 was 9.23% versus 9.48% in 1994 and 9.59% in 1993. In 1995, the Company and Cleveland Electric renewed for a four-year term approximately $225 million in bank letters of credit supporting the equity owner participants in the Beaver Valley Unit 2 lease. See Note 11(d).
The Company also utilized short-term borrowings to help meet its cash needs. The Company had $21 million of notes payable to affiliates at December 31, 1995. See Note 12.
1996 AND BEYOND CASH REQUIREMENTS
The Company's 1996 cash requirements for construction are $74 million and for debt and preferred stock maturities and sinking fund requirements are $58 million. We expect to meet these requirements with internal cash generation, cash reserves and about $40 million from the sale of a AAA-rated security backed by our accounts receivable.
We expect to meet all of our 1997-2000 cash requirements with internal cash generation. Estimated cash requirements for the Company's construction program during this period total $262 million. Debt and preferred stock maturities and sinking fund requirements total $233 million for the same period. If economical, additional securities may be redeemed under optional redemption
(Toledo Edison) (Toledo Edison)
provisions, with funding expected to be provided through internal cash generation.
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. If the applicable interest coverage test is met, the Company may issue first mortgage bonds on the basis of property additions and, under certain circumstances, refundable bonds. At December 31, 1995, the Company would have been permitted to issue approximately $288 million of additional first mortgage bonds.
The Company also is able to raise funds through the sale of debt and preferred and preference stock. Under its articles of incorporation, the Company cannot issue preferred stock unless certain earnings coverage requirements are met. At December 31, 1995 the Company would have been permitted to issue approximately $158 million of additional preferred stock at an assumed dividend rate of 10.5%. There are no restrictions on the Company's ability to issue preference stock.
The Company and Cleveland Electric have $307 million in financing vehicles available to support their nuclear fuel leases, portions of which mature this year. See Note 6. The Company is a party to a $125 million revolving credit facility which is expected to be renewed when it matures in May 1996. See Note 12. At the end of 1995, the Company had $94 million in cash and temporary investments.
The foregoing financing resources are expected to be sufficient for the Company's needs over the next several years. However, the availability and cost of capital to meet the Company's external financing needs also depend upon such factors as financial market conditions and its credit ratings. Current credit ratings for the Company are as follows:
RESULTS OF OPERATIONS
1995 VS. 1994
Factors contributing to the 1% increase in 1995 operating revenues are as follows:
For the second year in a row, total kilowatt-hour sales increased. Total sales increased 2.2% in 1995 primarily because of the hot summer weather. Residential and commercial sales increased 5.2% and 2.2%, respectively, which included about 1% nonweather-related growth in residential sales. Industrial sales increased 1.8% on the strength of increased sales to large glass manufacturers and the broad-based, smaller industrial customer group. Other sales increased 0.5%. Weather accounted for approximately $13 million of the $21 million increase in 1995 base rate (nonfuel) revenues. Wholesale revenues decreased because of the lower revenues associated with the Beaver Valley Unit 2 capacity sale to Cleveland Electric. See Note 2. Lower 1995 fuel costs recovery revenues resulted from favorable changes in the fuel cost factors. The weighted average of these fuel cost factors decreased approximately 6%.
For 1995, operating revenues were 27% residential, 21% commercial, 29% industrial and 23% other and kilowatt-hour sales were 19% residential, 16% commercial, 37% industrial and 28% other. The average prices per kilowatt-hour for residential, commercial and industrial customers were $.11, $.11 and $.06, respectively.
Operating expenses increased 0.1% in 1995. Federal income taxes increased as a result of higher pretax operating income. Fuel and purchased power expenses decreased because of lower purchased power requirements resulting from the increased availability of the nuclear generating units in 1995.
Interest charges and preferred dividends decreased in 1995 because of the redemption of securities and refinancing at favorable terms.
(Toledo Edison) (Toledo Edison)
1994 VS. 1993
Factors contributing to the 0.7% decrease in 1994 operating revenues are as follows:
The Company experienced good retail kilowatt-hour sales growth in the industrial and commercial categories in 1994; the sales growth for the residential category was lessened by weather conditions, particularly during the summer. The revenue decrease resulted from milder weather conditions in 1994 and both lower wholesale and fuel cost recovery revenues. Weather reduced base rate revenues approximately $7 million from the 1993 amount. Total sales increased 7.8%. Industrial sales increased 8.6% on the strength of increased sales to large automotive manufacturers and the broad-based, smaller industrial customer group. This growth substantiated an economic resurgence in Northwestern Ohio. Residential and commercial sales increased 0.8% and 2.3%, respectively. Other sales increased 16% because of increased sales to wholesale customers, although the softer wholesale market conditions in 1994 resulted in lower wholesale revenues. Lower 1994 fuel cost recovery revenues resulted from favorable changes in the fuel cost factors. The weighted average of these fuel cost factors dropped by 6%.
For 1994, operating revenues were 26% residential, 21% commercial, 29% industrial and 24% other and kilowatt-hour sales were 19% residential, 16% commercial, 37% industrial and 28% other. The average prices per kilowatt-hour for residential, commercial and industrial customers were $.11, $.11 and $.06, respectively. The changes from 1993 were not significant.
Operating expenses were 12% lower in 1994. Operation and maintenance expenses for 1993 included $88 million of net benefit expenses related to an early retirement program, called the Voluntary Transition Program (VTP), and other charges totaling $19 million. The VTP benefit expenses in 1993 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). A smaller work force and ongoing cost reduction measures also lowered operation and maintenance expenses. Lower purchased power costs helped reduce fuel and purchased power expenses in 1994 despite an increase in the amount of power purchased. More nuclear generation and less coal-fired generation also accounted for a part of the lower fuel and purchased power expenses. Depreciation and amortization expenses increased primarily because of higher nuclear plant decommissioning expenses as discussed in Note 1(e). Deferred operating expenses were greater primarily because of the write-off of $55 million of phase-in deferred operating expenses in 1993 as discussed in Note 7(e). The 1993 deferrals also included $32 million of postretirement benefit curtailment cost deferrals related to the VTP. See Note 9(b). Federal income taxes increased as a result of higher pretax operating income.
As discussed in Note 4(b), $232 million of our Perry Unit 2 investment was written off in 1993. Also, as discussed in Note 7(e), phase-in deferred carrying charges of $186 million were written off in 1993. The change in the federal income tax credit amounts for nonoperating income was attributable to these write-offs.
(Toledo Edison) (Toledo Edison)
INCOME STATEMENT The Toledo Edison Company
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(1) Includes revenues from all bulk power sales to Cleveland Electric of $102 million, $111 million and $120 million in 1995, 1994 and 1993, respectively.
RETAINED EARNINGS
The accompanying notes are an integral part of these statements.
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(Toledo Edison) (Toledo Edison)
BALANCE SHEET
The accompanying notes are an integral part of this statement.
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The Toledo Edison Company
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CASH FLOWS The Toledo Edison Company
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(2) Increases in Nuclear Fuel and Nuclear Fuel Lease Obligations in the Balance Sheet resulting from the noncash capitalizations under nuclear fuel agreements are excluded from this statement.
The accompanying notes are an integral part of this statement.
(Toledo Edison) (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. The Company follows the Uniform System of Accounts prescribed by the FERC and adopted by the PUCO. Rate-regulated utilities are subject to SFAS 71 which governs accounting for the effects of certain types of rate regulation. Pursuant to SFAS 71, certain incurred costs are deferred for recovery in future rates. See Note 7.
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. The estimates are based on an analysis of the best information available. Actual results could differ from those estimates.
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 joint 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 $67 million, $59 million and $71 million in 1995, 1994 and 1993, 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 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 (to 2007). 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) DEPRECIATION AND DECOMMISSIONING
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 3.8% in 1995, 3.5% in 1994 and 3.6% in 1993. The annual straight-line depreciation rate for nuclear property is 2.5%. In conjunction with its pending rate case, the Company has asked the PUCO to approve an increase of this depreciation rate to approximately 3%.
The Company accrues the estimated costs of decommissioning its three nuclear generating units. The accruals are required to be funded in an external trust. The PUCO requires that the expense and payments to the external trusts be determined on a levelized basis by dividing the unrecovered decommissioning costs in current dollars by the remaining years in the licensing period of each unit. This methodology requires that the net earnings on the
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trusts be reinvested therein with the intent of having net earnings offset inflation. The PUCO requires that the estimated costs of decommissioning and the funding level be reviewed at least every five years.
In 1994, the Company increased its annual decommissioning expense accruals to $11 million from the $5 million level in 1993. The accruals are reflected in current rates. The increased accruals in 1994 were derived from updated, site-specific studies for each of the units. The revised estimates reflect the DECON method of decommissioning (prompt decontamination), and the locations and cost characteristics specific to the units, and include costs associated with decontamination, dismantlement and site restoration.
The revised estimates for the units in 1993 and 1992 dollars and in dollars at the time of license expiration, assuming a 4% annual inflation rate, are as follows:
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(1) Dollar amounts in 1993 dollars. (2) Dollar amount in 1992 dollars.
The updated estimates reflect substantial increases from the prior PUCO-recognized aggregate estimates of $115 million in 1987 and 1986 dollars.
The classification, Accumulated Depreciation and Amortization, in the Balance Sheet at December 31, 1995 includes $59 million of decommissioning costs previously expensed and the earnings on the external trust 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. The trust earnings are recorded as an increase to the trust assets and the related component of the decommissioning reserve (included in Accumulated Depreciation and Amortization).
The staff of the Securities and Exchange Commission has questioned certain of the current accounting practices of the electric utility industry, including those of the Company, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in the financial statements. In response to these questions, the Financial Accounting Standards Board (FASB) is reviewing the accounting for removal costs, including decommissioning. If current accounting practices are changed, the annual provision for decommissioning could increase; the estimated cost for decommis- sioning could be recorded as a liability rather than as accumulated depreciation; and trust fund income from the external decommissioning trusts could be reported as investment income rather than as a reduction to decommissioning expense. The FASB issued an exposure draft on the subject on February 7, 1996.
(F) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment are stated at original cost less amounts disallowed by the PUCO. Construction costs include related payroll taxes, retirement benefits, 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 12.6% in 1995, 9.87% in 1994 and 10.22% in 1993.
Maintenance and repairs for plant and equipment 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 the leases. See Note 7(a). These amortizations and the lease expense amounts are reported in the Income Statement as Generation Facilities Rental Expense, Net.
(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. See Note 7(a). 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.
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(I) FEDERAL INCOME TAXES
The Company uses the liability method of accounting for income taxes in accordance with SFAS 109. See Note 8. 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, the Company must record a liability for its 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. See Note 7(a).
Investment tax credits are deferred and amortized over the lives of the applicable property as a reduction of depreciation expense. See Note 7(d) 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 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. These leases extend through 2017 and 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 renew the leases. The leases include conditions for mandatory termination (and possible repurchase of the leasehold interest) for events of default.
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 such payments have been made on behalf of Cleveland Electric.
Future minimum lease payments under the operating leases at December 31, 1995 are summarized as follows:
Rental expense is accrued on a straight-line basis over the terms of the leases. The amount recorded in 1995, 1994 and 1993 as annual rental expense for the Mansfield Plant leases was $45 million. The amounts recorded in 1995, 1994 and 1993 as annual rental expense for the Beaver Valley Unit 2 lease were $63 million, $64 million and $63 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. Revenues recorded for this transaction were $98 million, $108 million and $103 million in 1995, 1994 and 1993, respectively. We anticipate that this sale will continue indefinitely. The future minimum lease payments through 2017 associated with Beaver Valley Unit 2 aggregate $1.35 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, 1995
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includes the following facilities owned by the Company as a tenant in common with other utilities and Lessors:
(4) CONSTRUCTION AND CONTINGENCIES
(A) CONSTRUCTION PROGRAM
The estimated cost of the Company's construction program for the 1996-2000 period is $345 million, including AFUDC of $10 million and excluding nuclear fuel.
The Clean Air Act Amendments of 1990 (Clean Air Act) requires, among other things, significant reductions in the emission of sulfur dioxide and nitrogen oxides by fossil-fueled generating units. Our strategy provides for compliance primarily through greater use of low-sulfur coal at some of our units and the use of emission allowances. Total capital expenditures from 1991 through 1995 in connection with Clean Air Act compliance amounted to $4 million. The plan will require additional capital expenditures over the 1996-2005 period of approximately $41 million for nitrogen oxide control equipment and other plant process modifications. In addition, higher fuel and other operation and maintenance expenses may be incurred.
(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. 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.
(C) HAZARDOUS WASTE DISPOSAL SITES
The Company is aware of its potential involvement in the cleanup of several sites. The Company has accrued a liability totaling $5 million at December 31, 1995 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 the discussion of these and other risks in Management's Financial Analysis -- Outlook-Nuclear Operations.
(B) NUCLEAR INSURANCE
The Price-Anderson Act limits the public 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 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 utility owners and lessees of Davis-Besse, Perry and Beaver Valley also have insurance coverage for damage to property at these sites (including leased fuel and cleanup costs). Coverage amounted to $2.75 billion for each site as of January 1, 1996. 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. In addition, the Company can be assessed a maximum of $19 million under these policies 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 80% of such estimate per week for the next
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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 Cleveland Electric through leases with a special-purpose corporation. The total amount of financing currently available under these lease arrangements is $307 million ($157 million from intermediate-term notes and $150 million from bank credit arrangements). The intermediate-term notes mature in 1996 and 1997 ($84 million in September 1996 and $73 million in September 1997). The bank credit arrangements terminate in October 1996. The special-purpose corporation plans to obtain alternate financing in 1996 to replace the $234 million of financing expiring in 1996. At December 31, 1995, $93 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 $37 million, $21 million and $15 million, respectively, at December 31, 1995. The nuclear fuel amounts financed and capitalized also included interest charges incurred by the lessors amounting to $2 million in 1995, $4 million in 1994 and $6 million in 1993. The estimated future lease amortization payments for the Company based on projected consumption are $41 million in 1996, $34 million in 1997, $29 million in 1998, $28 million in 1999 and $27 million in 2000.
(7) REGULATORY MATTERS
(A) REGULATORY ACCOUNTING REQUIREMENTS AND REGULATORY ASSETS
The Company is subject to the provisions of SFAS 71 and has complied with its provisions. SFAS 71 provides, among other things, for the deferral of certain incurred costs that are probable of future recovery in rates. We monitor changes in market and regulatory conditions and consider the effects of such changes in assessing the continuing applicability of SFAS 71. Criteria that could give rise to discontinuation of the application of SFAS 71 include: (1) increasing competition which significantly restricts the Company's ability to charge prices which allow it to recover operating costs, earn a fair return on invested capital and recover the amortization of regulatory assets and (2) a significant change in the manner in which rates are set by the PUCO from cost-based regulation to some other form of regulation. Regulatory assets represent probable future revenues to the Company associated with certain incurred costs, which it will recover from customers through the rate-making process.
Effective January 1, 1996, the Company adopted SFAS 121 which imposes stricter criteria for carrying regulatory assets than SFAS 71 by requiring that such assets be probable of recovery at each balance sheet date. The criteria under SFAS 121 for plant assets require such assets to be written down only if the book value exceeds the projected net future cash flows.
Regulatory assets in the Balance Sheet are as follows:
* Represent deferrals of operating expenses and carrying charges for Perry Unit 1 and Beaver Valley Unit 2 in 1987 and 1988 which are being amortized over the lives of the related property.
As of December 31, 1995, customer rates provide for recovery of all the above regulatory assets, except those related to the Rate Stabilization Program discussed below. The remaining recovery periods for all of the regulatory assets listed above range from 16 to 33 years.
(B) RATE CASE
In April 1995, the Company and Cleveland Electric filed requests with the PUCO for price increases aggregating $119 million annually to be effective in 1996. The price increases are necessary to recover cost increases and amortization of certain costs deferred since 1992 pursuant to the Rate Stabilization Program. If their requests are approved, the Company and Cleveland Electric intend to freeze prices until at least 2002 with the expectation that increased sales and cost control measures will preclude the need for further price increases. If circumstances make it impossible to earn a fair return for Centerior Energy common stock share owners over time, the Company and Cleveland Electric would ask for a further increase, but only after taking all appropriate actions to make such a request unnecessary.
In November 1995, the PUCO Staff issued its report addressing the rate case. The Staff recommended that the PUCO grant the full $119 million price increase requested ($35 million for the Company and $84 million
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for Cleveland Electric). However, the Staff also recommended that the price increase be conditioned upon the commitment by the Company and Cleveland Electric "to a significant revaluation of their asset bases over some finite period of time."
In December 1995, the PUCO ordered an investigation into the financial conditions, rates and practices of the Company and Cleveland Electric to identify outcomes and remedies other than those routinely applied during the rate case process.
In late January 1996, the Staff proposed an incremental reduction (currently, an aggregate of $1.25 billion for the Company and Cleveland Electric) beyond the normal level in nuclear plant and regulatory assets within five years. The Staff proposed that the Company and Cleveland Electric have flexibility to determine how to achieve this incremental asset revaluation, but no additional price increases to recover the accelerated asset revaluation were proposed. Any incremental revaluation of assets would be for regulatory purposes and would cause prices and revenues after the five-year period to be lower than they otherwise would be in conjunction with any rate case following such revaluation. The Staff's asset revaluation proposal represents a substantial change in the form of rate-making traditionally followed by the PUCO and is inconsistent with the Ohio statutes that define the rate-making process. The PUCO is not bound by the recommendations of the Staff. A decision by the PUCO is anticipated in the second quarter of 1996.
(C) ASSESSMENT OF POTENTIAL OUTCOMES
We continually assess the effects of competition and the changing industry and regulatory environment on operations, the Company's ability to recover regulatory assets and the Company's ability to continue application of SFAS 71. If, as a result of the pending rate case or other events, we determine that the Company no longer meets the criteria for SFAS 71, the Company would be required to record a before-tax charge to write off the regulatory assets shown above and evaluate whether the Company's property, plant and equipment should be written down. In the more likely event that only a portion of operations (such as nuclear operations) no longer meets the criteria of SFAS 71, a write-off would be limited to regulatory assets, if any, that are not reflected in the Company's cost-based prices established for the remaining regulated operations. In addition, we would be required to evaluate whether the changes in the competitive and regulatory environment which led to discontinuing the application of SFAS 71 to a portion of the Company's operations would also result in a write-down of the Company's property, plant and equipment pursuant to SFAS 121.
We believe application of SFAS 121 in that event will not result in a write-off of regulatory assets unless the PUCO denies recovery of such assets or if we conclude, as a result of the outcome of the Company's pending rate case or some other event, that recovery is not probable for some or all of the regulatory assets. Furthermore, a write-down under SFAS 121 of the Company's property, plant and equipment is not expected.
(D) RATE STABILIZATION PROGRAM
The Rate Stabilization Program that the PUCO approved in October 1992 allowed the Company to defer and subsequently amortize and recover certain costs not currently recovered in rates and to accelerate amortization of certain benefits during the 1992-1995 period. Recovery of the deferrals will begin with the effective date of the PUCO's order in the pending rate case. The regulatory assets recorded included the deferral of post-in-service interest carrying charges, depreciation expense and property taxes on assets placed in service after February 29, 1988, the deferral of incremental expenses resulting from the adoption of SFAS 106 (see Note 9(b)), and the deferral of the operating expenses equivalent to an accumulated excess rent reserve for Beaver Valley Unit 2 (which resulted from the April 1992 refinancing of Secured Lease Obligation Bonds issued by a special-purpose corporation). The cost deferrals recorded in 1995, 1994 and 1993 pursuant to these provisions were $38 million, $43 million and $76 million, respectively. The regulatory accounting measures also provided for the accelerated amortization of certain unrestricted excess deferred tax and unrestricted investment tax credit balances and an excess interim spent fuel storage accrual balance for Davis-Besse. The total annual amount of such accelerated benefits was $18 million in 1995, 1994 and 1993.
(E) PHASE-IN DEFERRALS
In 1993, upon completing a comprehensive study which led to our strategic plan, we concluded that projected revenues would not provide for recovery of deferrals recorded pursuant to a phase-in plan approved by the PUCO in 1989 and, consequently, that the deferrals would have to be written off. Such deferrals were scheduled to be recovered in 1994 through 1998. 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).
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(8) FEDERAL INCOME TAX
The components of federal income tax expense (credit) recorded in the Income Statement were as follows:
The deferred federal income tax expense results from the temporary differences that arise from the different years certain expenses are recognized for tax purposes as opposed to financial reporting purposes. Such temporary differences affecting operating expenses relate principally to depreciation and deferred operating expenses whereas those affecting nonoperating income principally relate to deferred carrying charges and the 1993 write-offs.
Federal income tax, computed by multiplying income before taxes by the 35% statutory rate, is reconciled to the amount of federal income tax recorded on the books 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.
For tax reporting purposes, the Perry Unit 2 abandonment was recognized in 1994 and resulted in a $122 million loss with a corresponding $43 million reduction in federal income tax liability. Because of the alternative minimum tax (AMT), $25 million of the $43 million was realized in 1994. The remaining $18 million will not be realized until 1999.
Under SFAS 109, temporary differences and carryforwards resulted in deferred tax assets of $179 million and deferred tax liabilities of $752 million at December 31, 1995 and deferred tax assets of $178 million and deferred tax liabilities of $719 million at December 31, 1994. These are summarized as follows:
For tax purposes, net operating loss (NOL) carryforwards of approximately $125 million are available to reduce future taxable income and will expire in 2005 through 2009. The 35% tax effect of the NOLs is $44 million. Additionally, AMT credits of $80 million that may be carried forward indefinitely are available to reduce future tax.
(9) RETIREMENT BENEFITS
(A) RETIREMENT INCOME PLAN
Centerior Energy sponsors jointly with its subsidiaries a noncontributing pension plan (Centerior Pension Plan) which covers all employee groups. 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 comply with the Employee Retirement Income Security Act of 1974 guidelines.
In 1993, eligible employees were offered the VTP, an early retirement program. Operating expenses for Centerior Energy and its subsidiaries in 1993 included $205 million of pension plan accruals to cover enhanced VTP benefits offset by a credit of $81 million resulting from a settlement of pension obligations through lump sum payments to almost all the VTP retirees.
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Pension and VTP costs (credits) for Centerior Energy and its subsidiaries for 1993 through 1995 were comprised of the following components:
Pension and VTP costs (credits) for the Company and its pro rata share of the Service Company's costs were $(3) million, $1 million and $53 million for 1995, 1994 and 1993, respectively.
The following table presents a reconciliation of the funded status of the Centerior Pension Plan. The Company's share of the Centerior Pension Plan's total projected benefit obligation approximates 30%.
A September 30 measurement date was used for 1995 and 1994 reporting. At December 31, 1995, the settlement (discount) rate and long-term rate of return on plan assets assumptions were 8% and 11%, respectively. The long-term rate of annual compensation increase assumption was 3.5% in 1996 and 1997 and 4% thereafter. At December 31, 1994, the settlement rate and long-term rate of return on plan assets assumptions were 8.5% and 10%, respectively. The long-term rate of annual compensation increase assumption was 3.5% for 1995 and 1996 and 4% thereafter. At December 31, 1995 and 1994, the Company's net accrued pension liability included in Retirement Benefits in the Balance Sheet was $64 million and $66 million, respectively.
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. 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. Prior to 1993, the costs of these benefits were expensed as paid, which was consistent with rate-making practices.
The components of the total postretirement benefit costs for 1993 through 1995 were as follows:
These amounts included costs for the Company and its pro rata share of the Service Company's costs.
In 1995, 1994 and 1993, the Company deferred incremental SFAS 106 expenses (in excess of the amounts paid) of $1 million, $2 million and $37 million, respectively, pursuant to a provision of the Rate Stabilization Program. See Note 7(d).
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The accumulated postretirement benefit obligation and accrued postretirement benefit cost for the Company and its share of the Service Company's obligation are as follows:
The Balance Sheet classification of Retirement Benefits at December 31, 1995 and 1994 includes only the Company's accrued postretirement benefit cost of $39 million and $37 million, respectively, and excludes the Service Company's portion since the Service Company's total accrued cost is carried on its books.
A September 30 measurement date was used for 1995 and 1994 reporting. At December 31, 1995 and 1994, the settlement rate and the long-term rate of annual compensation increase assumptions were the same as those discussed for pension reporting in Note 9(a). At December 31, 1995, the assumed annual health care cost trend rates (applicable to gross eligible charges) were 8% for medical and 7.5% for dental in 1996. Both rates reduce gradually to a fixed rate of 4.75% by 2003. 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 one percentage point in each future year, the accumulated postretirement benefit obligation as of December 31, 1995 would increase by $3 million and the aggregate of the service and interest cost components of the annual postretirement benefit cost would increase by $0.3 million.
(10) GUARANTEES
The Company has guaranteed certain loan and lease obligations of a coal supplier under a long-term coal supply contract. At December 31, 1995, the principal amount of the loan and lease obligations guaranteed by the Company was $14 million. The prices under the contract which includes certain minimum payments are sufficient to satisfy the loan and lease obligations and mine closing costs over the life of the contract. If the contract is terminated early for any reason, the Company would attempt to reduce the termination charges and would ask the PUCO to allow recovery of such charges from customers through the fuel factor.
(11) CAPITALIZATION
(A) CAPITAL STOCK TRANSACTIONS
Preferred stock shares retired during the three years ended December 31, 1995 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, 1995, the Company had $183 million of appropriated retained earnings for the payment of preferred stock dividends. The Company is prohibited from paying a common stock dividend by a provision in its mortgage that essentially requires such dividends to be paid out of the total balance of retained earnings, which currently is a deficit.
(C) PREFERRED AND PREFERENCE STOCK
Amounts to be paid for preferred stock which must be redeemed during the next five years are $1.665 million in each year 1996 through 1999 only.
The annual preferred stock mandatory redemption provisions are as follows:
The annualized preferred dividend requirement at December 31, 1995 was $17 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 7.75% and 8.58%, respectively, in 1995.
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:
* Secured by first mortgage bonds. ** Secured by subordinated mortgage collateral. Long-term debt matures during the next five years as follows: $56 million in 1996, $40 million in 1997, $39 million in 1998, $119 million in 1999 and $31 million in 2000. 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 credit agreements of the Company contain covenants relating to fixed charge coverage ratios and limitations on secured financing other than through first mortgage bonds or certain other transactions. In June 1995, the Company and Cleveland Electric replaced letters of credit in connection with the sale and leaseback of Beaver Valley Unit 2 that were due to expire with new letters of credit expiring in June 1999. The letters of credit are in an aggregate amount of approximately $225 million and are secured by first mortgage bonds of the Company and Cleveland Electric in the proportion of 60% and 40%, respectively. At December 31, 1995, the Company had outstanding $52 million of bank loans and notes secured by subordinated mortgage collateral.
(12) SHORT-TERM BORROWING ARRANGEMENTS
Centerior Energy has a $125 million revolving credit facility through May 1996. 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. The credit agreement is secured with first mortgage bonds of the Company and Cleveland Electric in the proportion of 60% and 40%, respectively. The banks' fee is 0.625% per annum payable quarterly in addition to interest on any borrowings. There were no borrowings under the facility at December 31, 1995. Also, the Company and Cleveland Electric may borrow from each other on a short-term basis. At December 31, 1995, the Company had total short-term borrowings of $21 million from its affiliates with a weighted average interest rate of 6.25%.
(13) FINANCIAL INSTRUMENTS
The estimated fair values at December 31, 1995 and 1994 of financial instruments that do not approximate their carrying amounts in the Balance Sheet are as follows:
Noncash investments in the Nuclear Plant Decommissioning Trusts are summarized in the following table.
The fair value of these trusts is estimated based on the quoted market prices for the investment securities. As a result of adopting the new accounting standard for certain investments in debt and equity securities, SFAS 115, in
(Toledo Edison) (Toledo Edison)
1994, the carrying amount of these trusts approximates fair value. 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, 1995 and 1994 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, 1995.
(15) PENDING MERGER OF THE COMPANY INTO CLEVELAND ELECTRIC
In March 1994, Centerior Energy announced a plan to merge the Company into Cleveland Electric. 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.
Various aspects of the merger are subject to the approval of the FERC and other regulatory authorities. The FERC has deferred action on the merger application until the merits of the open access transmission tariffs proposed by the Company and Cleveland Electric are addressed in hearings. The PUCO and the Pennsylvania Public Utility Commission have approved the merger. NRC action on the request by the Company and Cleveland Electric for authorization to transfer certain NRC licenses to the merged entity is not expected until approval has been obtained from the FERC.
In June 1995, share owners of the Company's preferred stock approved the merger and share owners of Cleveland Electric's preferred stock approved the authorization of additional shares of preferred stock. When the merger becomes effective, share owners of the Company's preferred stock will exchange their shares for preferred stock shares of Cleveland Electric having substantially the same terms. Debt holders of the merging companies will become debt holders of Cleveland Electric.
For the merging companies, the combined pro forma operating revenues were $2.516 billion, $2.422 billion and $2.475 billion and the combined pro forma net income (loss) was $281 million, $268 million and $(876) million for the years 1995, 1994 and 1993, respectively. The pro forma data is based on accounting for the merger on a method similar to a pooling of interests. The pro forma data is not necessarily 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)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Share Owners and Board of Directors of The Toledo 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, 1995 and 1994, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1995. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the schedule 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, 1995 and 1994, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles.
As discussed further in Note 9, a change was made in the method of accounting 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 schedule of The Toledo Edison Company listed in the Index to Schedules is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states 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 LLP
Cleveland, Ohio February 21, 1996
(Toledo Edison) (Toledo Edison)
FINANCIAL AND STATISTICAL REVIEW
OPERATING REVENUES (millions of dollars)
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OPERATING EXPENSES (millions of dollars)
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INCOME (LOSS) (millions of dollars)
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INCOME (LOSS) (millions of dollars)
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(a) Includes early retirement program expenses and other charges of $107 million. (b) Includes write-off of phase-in deferrals of $241 million, consisting of $55 million of deferred operating expenses and $186 million of deferred carrying charges.
(Toledo Edison) (Toledo Edison)
The Toledo Edison Company
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CAPITALIZATION (millions of dollars & %)
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(c) 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.
(d) Includes write-off of Perry Unit 2 of $232 million.
(Toledo Edison) (Toledo Edison)
Schedules other than those listed above are omitted for the reason that they are not required or are not applicable.
S-1
CENTERIOR ENERGY CORPORATION
SCHEDULE II - VALUATION AND QUALIFIYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
(THOUSANDS OF DOLLARS)
(a) Includes a provision and corresponding write-off of uncollectible accounts of $10,024,000, $4,695,000 and $4,550,000 in 1995, 1994 and 1993, respectively, relating to customers which qualify for the PUCO mandated Percentage of Income Payment Plan (PIPP). Such uncollectible accounts are recovered through a separate PUCO approved surcharge tariff.
(b) Includes amounts for collection of accounts previously written off and deferral of PIPP uncollectibles in excess of the amounts included in the last base rate cases. The amounts deferred for future recovery were $1,716,000, $2,382,000 and $971,000 in 1995, 1994 and 1993, respectively.
(c) Uncollectible accounts written off.
(d) Write-off of Perry Unit 2 investment.
S-2
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
(THOUSANDS OF DOLLARS)
(a) Includes a provision and corresponding write-off of uncollectible accounts of $6,584,000, $2,499,000 and $2,447,000 in 1995, 1994 and 1993, respectively, relating to customers which qualify for the PUCO mandated Percentage of Income Payment Plan (PIPP). Such uncollectible accounts are recovered through a separate PUCO approved surcharge amount.
(b) Includes amounts for collection of accounts previously written off and deferral of PIPP uncollectibles in excess of the amount included in the last base rate case. The amounts deferred for future recovery were $1,273,000, $1,971,000 and $507,000 in 1995, 1994 and 1993, respectively.
(c) Uncollectible accounts written off.
(d) Write-off of Perry Unit 2 investment.
S-3
THE TOLEDO EDISON COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
(THOUSANDS OF DOLLARS)
(a) Includes a provision and corresponding write-off of uncollectible accounts of $3,440,000, $2,196,000 and $2,103,000 in 1995, 1994 and 1993, respectively, relating to customers which qualify for the PUCO mandated Percentage of Income Payment Plan (PIPP). Such uncollectible accounts are recovered through a separate PUCO approved surcharge tariff.
(b) Includes amounts for collection of accounts previously written off and deferral of PIPP uncollectibles in excess of the amount included in the last base rate case. The amounts deferred for future recovery were $443,000, $411,000 and $464,000 in 1995, 1994 and 1993, respectively.
(c) Uncollectible accounts written off.
(d) Write-off of Perry Unit 2 investment.
S-4
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, 1995 and December 31, 1994 and their historical income statements for each of the three years ended December 31, 1995.
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.
P-1
P-2
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. (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 indicated in parenthesis following the description of such exhibits and are incorporated 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.)
E-1
E-2
E-3
E-4
E-5
CENTERIOR ENERGY EXHIBITS -------------------------
CLEVELAND ELECTRIC EXHIBITS ---------------------------
E-6
E-7
E-8
TOLEDO EDISON EXHIBITS ----------------------
E-9
E-10
December 31, 1995.
Pursuant to Paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, the Registrants 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 thereunder 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 furnished by the Registrants to share owners upon written request and upon receipt 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.
E-11
CENTERIOR EXHIBITS