-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, bVp12jKUCf2tUqaZGj6G8B53LG57cgpA84IdK/BpAY93fDJGkU5RE0suBACyfS37 PkkeghOtn85CD58N8ElXLg== 0000950152-94-000376.txt : 19940404 0000950152-94-000376.hdr.sgml : 19940404 ACCESSION NUMBER: 0000950152-94-000376 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 13 CONFORMED PERIOD OF REPORT: 19931231 FILED AS OF DATE: 19940331 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CENTERIOR ENERGY CORP CENTRAL INDEX KEY: 0000774197 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 341479083 STATE OF INCORPORATION: OH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 001-09130 FILM NUMBER: 94519762 BUSINESS ADDRESS: STREET 1: 6200 OAK TREE BLVD CITY: INDEPENDENCE STATE: OH ZIP: 44131 BUSINESS PHONE: 2164473100 MAIL ADDRESS: STREET 1: PO BOX 94661 CITY: CLEVELAND STATE: OH ZIP: 44101-4661 FORMER COMPANY: FORMER CONFORMED NAME: NORTH HOLDING CO /OH/ DATE OF NAME CHANGE: 19851002 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CLEVELAND ELECTRIC ILLUMINATING CO CENTRAL INDEX KEY: 0000020947 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 340150020 STATE OF INCORPORATION: OH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 001-02323 FILM NUMBER: 94519763 BUSINESS ADDRESS: STREET 1: 55 PUBLIC SQ CITY: CLEVELAND STATE: OH ZIP: 44101 BUSINESS PHONE: 2166229800 FILER: COMPANY DATA: COMPANY CONFORMED NAME: TOLEDO EDISON CO CENTRAL INDEX KEY: 0000352049 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 344375005 STATE OF INCORPORATION: OH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 001-03583 FILM NUMBER: 94519764 BUSINESS ADDRESS: STREET 1: 300 MADISON AVE CITY: TOLEDO STATE: OH ZIP: 43652 BUSINESS PHONE: 4192495000 10-K 1 CENTERIOR 10-K 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (Mark One) X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED] For the fiscal year ended December 31, 1993 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] For the transition period from _________________ to _________________ Commission Registrant; State of Incorporation; I.R.S. Employer File Number Address; and Telephone Number Identification No. 1-9130 CENTERIOR ENERGY CORPORATION 34-1479083 (An Ohio Corporation) 6200 Oak Tree Boulevard Independence, Ohio 44131 Telephone (216) 447-3100 1-2323 THE CLEVELAND ELECTRIC ILLUMINATING 34-0150020 COMPANY (An Ohio Corporation) 55 Public Square Cleveland, Ohio 44113 Telephone (216) 622-9800 1-3583 THE TOLEDO EDISON COMPANY 34-4375005 (An Ohio Corporation) 300 Madison Avenue Toledo, Ohio 43652 Telephone (419) 249-5000 Indicate by check mark whether each of the registrants (1) has filed all re- ports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X . No . Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] 2 The aggregate market value of Centerior Energy Corporation Common Stock, with- out par value, held by non-affiliates was $1,754,200,163 on February 28, 1994 based on the closing sale price of $11.875 as quoted for that date on a composite transactions basis in The Wall Street Journal and on the 147,722,119 shares of Common Stock outstanding on that date. Centerior Energy Corporation is the sole holder of the 79,590,689 shares and 39,133,887 shares of the outstanding common stock of The Cleveland Electric Illuminating Company and The Toledo Edison Company, respectively. 3
Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange Registrant Title of Each Class on Which Registered Centerior Energy Common Stock, Corporation without par value New York Stock Exchange Chicago Stock Exchange Pacific Stock Exchange The Cleveland Electric Cumulative Serial Preferred Illuminating Company Stock, without par value: $7.40 Series A New York Stock Exchange $7.56 Series B New York Stock Exchange Adjustable Rate, Series L New York Stock Exchange Depository Shares: 1993 Series A, each share representing 1/20 of a share of Serial Preferred Stock, $42.40 Series T (without par value) New York Stock Exchange First Mortgage Bonds: 4-3/8% Series due 1994 New York Stock Exchange 8-3/4% Series due 2005 New York Stock Exchange 9-1/4% Series due 2009 New York Stock Exchange 8-3/8% Series due 2011 New York Stock Exchange 8-3/8% Series due 2012 New York Stock Exchange The Toledo Edison Cumulative Preferred Stock, Company par value $100 per share: 4-1/4% Series American Stock Exchange 8.32% Series American Stock Exchange 7.76% Series American Stock Exchange 10% Series American Stock Exchange Cumulative Preferred Stock, par value $25 per share: 8.84% Series New York Stock Exchange $2.365 Series New York Stock Exchange Adjustable Rate, Series A New York Stock Exchange Adjustable Rate, Series B New York Stock Exchange $2.81 Series New York Stock Exchange First Mortgage Bonds: 7-1/2% Series due 2002 New York Stock Exchange 8% Series due 2003 New York Stock Exchange
4
Securities registered pursuant to Section 12(g) of the Act: Registrant Title of Each Class Centerior Energy None Corporation The Cleveland Electric None Illuminating Company The Toledo Edison Cumulative Preferred Stock, Company par value $100 per share: 4.56% Series and 4.25% Series ---------------------
DOCUMENTS INCORPORATED BY REFERENCE Part of Form 10-K Into Which Document Description Is Incorporated Portions of Proxy Statement of Centerior Energy Corporation, dated March 23, 1994 Part III 5 TABLE OF CONTENTS
Page Number Glossary of Terms iv PART I Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . 1 The Centerior System . . . . . . . . . . . . . . . . . . . . . . 1 CAPCO Group . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Construction and Financing Programs . . . . . . . . . . . . . . 3 Construction Program . . . . . . . . . . . . . . . . . . . . . 3 Financing Program . . . . . . . . . . . . . . . . . . . . . . 5 General Regulation . . . . . . . . . . . . . . . . . . . . . . . 5 Holding Company Regulation . . . . . . . . . . . . . . . . . . 5 State Utility Commissions . . . . . . . . . . . . . . . . . . 6 Ohio Power Siting Board . . . . . . . . . . . . . . . . . . . 7 Federal Energy Regulatory Commission . . . . . . . . . . . . . 7 Nuclear Regulatory Commission . . . . . . . . . . . . . . . . 7 Other Regulation . . . . . . . . . . . . . . . . . . . . . . . 7 Environmental Regulation . . . . . . . . . . . . . . . . . . . . 8 General . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Air Quality Control . . . . . . . . . . . . . . . . . . . . . 8 Water Quality Control . . . . . . . . . . . . . . . . . . . . 9 Waste Disposal . . . . . . . . . . . . . . . . . . . . . . . . 10 Electric Rates . . . . . . . . . . . . . . . . . . . . . . . . . 10 Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Sales of Electricity . . . . . . . . . . . . . . . . . . . . . 11 Operating Statistics . . . . . . . . . . . . . . . . . . . . . 12 Nuclear Units . . . . . . . . . . . . . . . . . . . . . . . . 12 Competitive Conditions . . . . . . . . . . . . . . . . . . . . 14 General . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Cleveland Electric . . . . . . . . . . . . . . . . . . . . . 15 Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . 16
- i - 6
Page Number Fuel Supply . . . . . . . . . . . . . . . . . . . . . . . . . 17 Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 Executive Officers of the Registrants and the Service Company . 20 Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . 26 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 The Centerior System . . . . . . . . . . . . . . . . . . . . . 26 Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . 27 Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . . 27 Title to Property . . . . . . . . . . . . . . . . . . . . . . . 28 Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . 30 Item 4. Submission of Matters to a Vote of Security Holders . . . 30 PART II Item 5. Market for Registrants' Common Equity and Related Stockholder Matters . . . . . . . . . . . . . . . . . . . 30 Market Information . . . . . . . . . . . . . . . . . . . . . . 31 Share Owners . . . . . . . . . . . . . . . . . . . . . . . . . 31 Dividends . . . . . . . . . . . . . . . . . . . . . . . . . . 31 Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . 31 Centerior Energy . . . . . . . . . . . . . . . . . . . . . . . . 31 Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . . 32 Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . . . 32 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . 32 Centerior Energy . . . . . . . . . . . . . . . . . . . . . . . . 32 Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . . 32 Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . . . 32
- ii - 7
Page Number Item 8. Financial Statements and Supplementary Data . . . . . . . 32 Centerior Energy . . . . . . . . . . . . . . . . . . . . . . . . 32 Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . . 32 Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . . . 32 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure . . . . . . . . . . . 32 PART III Item 10. Directors and Executive Officers of the Registrants . . 33 Centerior Energy . . . . . . . . . . . . . . . . . . . . . . . . 33 Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . . 33 Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . . . 33 Item 11. Executive Compensation . . . . . . . . . . . . . . . . . 34 Centerior Energy, Cleveland Electric and Toledo Edison . . . . . 34 Item 12. Security Ownership of Certain Beneficial Owners and Management . . . . . . . . . . . . . . . . . . . . . . . 34 Centerior Energy . . . . . . . . . . . . . . . . . . . . . . . . 34 Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . . 36 Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . . . 36 Item 13. Certain Relationships and Related Transactions . . . . . 37 Centerior Energy, Cleveland Electric and Toledo Edison . . . . . 37 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . . . . . . . . . . . . . . . . . . 37 Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 Index to Selected Financial Data; Management's Discussion and Analysis of Financial Condition and Results of Operations; and Financial Statements . . . . . . . . . . . . . . . . . . . . . F-1 Index to Schedules . . . . . . . . . . . . . . . . . . . . . . . . . S-1 The Cleveland Electric Illuminating Company and Subsidiaries and The Toledo Edison Company Combined Pro Forma Condensed Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . P-1 Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . . . E-1
- iii - 8 This combined Form 10-K is separately filed by Centerior Energy Corporation, The Cleveland Electric Illuminating Company and The Toledo Edison Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant, except that information relating to either or both of the Operating Companies is also attributed to Centerior Energy. GLOSSARY OF TERMS The following terms and abbreviations used in the text of this report are defined as indicated:
Term Definition AFUDC Allowance for Funds Used During Construction. AMP-Ohio American Municipal Power-Ohio, Inc., an Ohio not-for-profit corporation, the members of which are certain Ohio municipal electric systems. Beaver Valley Unit 2 Unit 2 of the Beaver Valley Power Station, in which the Operating Companies have ownership and leasehold interests. CAPCO Group Central Area Power Coordination Group. Centerior Energy or Centerior Centerior Energy Corporation. Centerior System Centerior Energy, the Operating Companies and the Service Company. Clean Air Act Federal Clean Air Act of 1970 as amended. Clean Air Act Amendments November 1990 Amendments to the Clean Air Act. Clean Water Act Federal Water Pollution Control Act as amended. Cleveland Electric The Cleveland Electric Illuminating Company, an electric utility subsidiary of Centerior Energy and a member of the CAPCO Group. Consol Consolidation Coal Company. CPP Cleveland Public Power, a municipal electric system operated by the City of Cleveland. CWIP Construction Work in Progress. Davis-Besse Davis-Besse Nuclear Power Station.
- iv - 9
Term Definition Detroit Edison Detroit Edison Company, an electric utility. District of Columbia United States Court of Appeals for the Dis- Circuit Appeals Court trict of Columbia Circuit. DOE United States Department of Energy. Duquesne Duquesne Light Company, an electric utility subsidiary of DQE, Inc. and a member of the CAPCO Group. ECAR East Central Area Reliability Coordination Group. Energy Act Energy Policy Act of 1992. Federal Power Act Federal Power Act, as amended, codified in Chapter 12 of Title 16 of the United States Code. FERC Federal Energy Regulatory Commission. General Electric General Electric Company. Holding Company Act Public Utility Holding Company Act of 1935. Mansfield Plant Bruce Mansfield Generating Plant, a coal- fired power plant, in which the Operating Companies have leasehold interests as joint and several lessees. Note or Notes Note or Notes to the Financial Statements in the Centerior Energy, Cleveland Electric and Toledo Edison Annual Reports for 1993 (Note or Notes, where used, refers to all three companies unless otherwise specified). NPDES National Pollutant Discharge Elimination System. NRC United States Nuclear Regulatory Commission. Ohio Edison Ohio Edison Company, an electric utility and a member of the CAPCO Group. Ohio EPA Ohio Environmental Protection Agency. Ohio Power Ohio Power Company, an electric utility sub- sidiary of American Electric Power Company, Inc.
- v - 10
Term Definition Ohio Valley The Ohio Valley Coal Company, the successor corporation to The Nacco Mining Company and a subsidiary of Ohio Valley Resources, Inc. Operating Companies Cleveland Electric and Toledo Edison. (individually, Operating Company) OPSB Ohio Power Siting Board. PaPUC Pennsylvania Public Utility Commission. Penelec Pennsylvania Electric Company, an electric utility subsidiary of GPU. Pennsylvania Power Pennsylvania Power Company, an electric utility subsidiary of Ohio Edison and a member of the CAPCO Group. Perry Plant Perry Nuclear Power Plant. Perry Unit 1 and Perry Unit 2 Unit 1 and Unit 2 of the Perry Plant, in which the Operating Companies have ownership interests. PUCO The Public Utilities Commission of Ohio. Quarto Quarto Mining Company, a subsidiary of Consol. SALP Systematic Assessment of Licensee Performance - the NRC's performance evaluation of a nuclear unit. SEC United States Securities and Exchange Commission. Seneca Plant Seneca Power Plant, a pumped-storage, hydro- electric generating station jointly owned by Cleveland Electric and Penelec. Service Company Centerior Service Company, a service sub- sidiary of Centerior Energy. Superfund Comprehensive Environmental Response, Com- pensation and Liability Act of 1980 and the Superfund Amendments and Reauthorization Act of 1986.
- vi - 11
Term Definition Toledo Edison The Toledo Edison Company, an electric utility subsidiary of Centerior Energy and a member of the CAPCO Group. U.S. EPA United States Environmental Protection Agency. Westinghouse Westinghouse Electric Corporation.
- vii - 12 PART I Item 1. Business THE CENTERIOR SYSTEM Centerior Energy is a public utility holding company and the parent company of the Operating Companies and the Service Company. Centerior was incorporated under the laws of the State of Ohio in 1985 for the purpose of enabling Cleveland Electric and Toledo Edison to affiliate by becoming wholly owned subsidiaries of Centerior. The affiliation of the Operating Companies became effective in April 1986. Nearly all of the consolidated operating revenues of the Centerior System are derived from the sale of electric energy by Cleveland Electric and Toledo Edison. The Operating Companies' combined service areas encompass approximately 4,200 square miles in northeastern and northwestern Ohio with an estimated popula- tion of about 2,600,000. At December 31, 1993, the Centerior System had 6,748 employees. Centerior Energy has no employees. Cleveland Electric, which was incorporated under the laws of the State of Ohio in 1892, is a public utility engaged in the generation, purchase, transmis- sion, distribution and sale of electric energy in an area of approximately 1,700 square miles in northeastern Ohio, including the City of Cleveland. Cleveland Electric also provides electric energy at wholesale to other elec- tric utility companies and to two municipal electric systems (directly and through AMP-Ohio) in its service area. Cleveland Electric serves approxi- mately 748,000 customers and derives approximately 75% of its total electric revenue from customers outside the City of Cleveland. Principal industries served by Cleveland Electric include those producing steel and other primary metals; automotive and other transportation equipment; chemicals; electrical and nonelectrical machinery; fabricated metal products; and rubber and plastic products. Nearly all of Cleveland Electric's operating revenues are derived from the sale of electric energy. At December 31, 1993, Cleveland Electric had 3,606 employees of which about 51% were represented by one union having a collective bargaining agreement with Cleveland Electric. Toledo Edison, which was incorporated under the laws of the State of Ohio in 1901, is a public utility engaged in the generation, purchase, transmission, distribution and sale of electric energy in an area of approximately 2,500 square miles in northwestern Ohio, including the City of Toledo. Toledo Edison also provides electric energy at wholesale to other electric utility companies and to 13 municipally owned distribution systems (through AMP-Ohio) and one rural electric cooperative distribution system in its service area. Toledo Edison serves approximately 285,000 customers and derives approximately 55% of its total electric revenue from customers outside the City of Toledo. Among the principal industries served by Toledo Edison are metal casting, forming and fabricating; petroleum refining; automotive equipment and assembly; food processing; and glass. Nearly all of Toledo Edison's operating revenues are derived from the sale of electric energy. At December 31, 1993, Toledo Edison had 1,909 employees of which about 55% were represented by three unions having collective bargaining agreements with Toledo Edison. 13 The Service Company, which was incorporated in 1986 under the laws of the State of Ohio, is also a wholly owned subsidiary of Centerior Energy. It pro- vides management, financial, administrative, engineering, legal, governmental and public relations and other services to Centerior Energy and the Operating Companies. At December 31, 1993, the Service Company had 1,233 employees. On March 25, 1994, Centerior Energy announced plans to merge Toledo Edison into Cleveland Electric. Since Cleveland Electric and Toledo Edison affiliated in 1986, efforts have been made to consolidate operations and administration as much as possible to achieve maximum cost savings. The merger of the two companies into a single entity is the completion of this consolidation process. Various aspects of the merger are subject to the approval of the FERC, the PUCO, the PaPUC and other regulatory authorities. The merger must be approved by Toledo Edison preferred stock share owners. Preferred stock share owners of Cleveland Electric must approve the authori- zation of additional shares of preferred stock. Upon the merger becoming effective, the outstanding shares of Toledo Edison preferred stock will be exchanged for shares of Cleveland Electric preferred stock having sub- stantially the same terms. Cleveland Electric and Toledo Edison plan to seek preferred share owner approval in the summer of 1994. The merger is expected to be effective late in 1994. See Note 15 to the Operating Companies' Financial Statements for further discussion of this matter and "3. Combined Pro Forma Condensed Financial Statements (Unaudited)" contained under Item 14. of this Report for selected historical and combined pro forma financial information of Cleveland Electric and Toledo Edison. CAPCO GROUP Cleveland Electric and Toledo Edison are members of the CAPCO Group, a power pool created in 1967 with Duquesne, Ohio Edison and Pennsylvania Power. This pool affords greater reliability and lower cost of providing electric service through coordinated generating unit operations and maintenance and generating reserve back-up among the five companies. In addition, the CAPCO Group has completed programs to construct larger, more efficient electric generating units and to strengthen interconnections within the pool. The CAPCO Group companies have placed in service nine major generating units, of which the Operating Companies have ownership or leasehold interests in seven (three nuclear and four coal-fired). Each CAPCO Group company owns, as a tenant-in-common, or leases a portion of certain of these generating units. Each company has the right to the net capability and associated energy of its respective ownership and leasehold portions of the units and is, severally and not jointly, obligated for the capital and operating costs equivalent to its respective ownership and leasehold portions of the units and the required fuel, except that the obligations of Pennsylvania Power are the joint and several obligations of that company and Ohio Edison and except that the leasehold obligations of Cleveland Electric and Toledo Edison are joint and several. (See "Operations--Fuel Supply".) For all plants but one, the company in whose service area a generating unit is located is responsible for the operation of that unit for all the owners, except for the procurement of nuclear fuel for a nuclear generating unit. The Mansfield Plant, which is located in Duquesne's service area, is operated by Pennsylvania Power. Each company owns the necessary interconnecting transmission facilities within its service area, and the other CAPCO Group companies contribute toward fixed charges and operating costs of those transmission facilities. 14 All of the CAPCO Group companies are members of ECAR, which is comprised of 28 electric companies located in nine contiguous states. ECAR's purpose is to improve reliability of bulk power supply through coordination of planning and operation of member companies' generation and transmission facilities. CONSTRUCTION AND FINANCING PROGRAMS Construction Program The Centerior System carries on a continuous program of constructing trans- mission, distribution and general facilities and modifying existing generating facilities to meet anticipated demand for electric service, to comply with governmental regulations and to protect the environment. The Operating Companies' 1993 long-term (20-year) forecast, as filed with the PUCO (see "General Regulation--State Utility Commissions"), projects long-term annual growth rates in peak demand and kilowatt-hour sales for the Operating Companies of 1.1% and 1.4%, respectively, after demand-side management con- siderations. The Centerior System's integrated resource plan for the 1990s (which is included in the long-term forecast) combines demand-side management programs with maximum utilization of existing generating capacity to postpone the need for new generating units until the next decade. Demand-side manage- ment programs, such as energy-efficient lighting and motors, curtailable load and energy management, are expected to assist customers in achieving greater energy efficiency. Centerior plans to invest up to $35,000,000 in demand-side programs in 1994 and 1995. Operable capacity margins over the next ten years are expected to be adequate without adding generating capacity. According to the current long-term integrated resource plan, the next increment of generating capacity that the Centerior System plans to put into service will be two 136,000-kilowatt units in 2003, with additional small, short-lead-time capacity in subsequent years. The following tables show, categorized by major components, the construction expenditures by Cleveland Electric and Toledo Edison and, by aggregating them, for the Centerior System during 1991, 1992 and 1993 and the estimated cost of their construction programs for 1994 through 1998, in each case including AFUDC and excluding nuclear fuel:
Actual Estimated 1991 1992 1993 1994 1995 1996 1997 1998 Cleveland Electric (Millions of Dollars) Perry Unit 2* $ 0 $ 3 $ 0 $ - $ - $ - $ - $ - Transmission, Distribution and General Facilities 77 73 85 76 82 86 96 97 Renovation and Modification of Generating Units Nuclear 25 23 16 18 14 15 14 11 Nonnuclear 48 56 65 55 70 36 29 41 Clean Air Act Amendments Compliance 0 1 9 27 22 3 4 33 Total $150 $156 $175 $176 $188 $140 $143 $182 Note: The footnote to the tables is on the following page.
15
Actual Estimated 1991 1992 1993 1994 1995 1996 1997 1998 Toledo Edison (Millions of Dollars) Perry Unit 2* $ 0 $ 0 $ 0 $ - $ - $ - $ - $ - Transmission, Distribution and General Facilities 30 25 22 23 27 26 25 20 Renovation and Modification of Generating Units Nuclear 17 12 15 15 10 12 10 8 Nonnuclear 7 7 6 11 9 6 6 8 Clean Air Act Amendments Compliance 0 0 0 6 4 11 11 11 Total $ 54 $ 44 $ 43 $ 55 $ 50 $ 55 $ 52 $ 47 Actual Estimated 1991 1992 1993 1994 1995 1996 1997 1998 Centerior System (Millions of Dollars) Perry Unit 2* $ 0 $ 3 $ 0 $ - $ - $ - $ - $ - Transmission, Distribution and General Facilities 107 98 107 99 109 112 121 117 Renovation and Modification of Generating Units Nuclear 42 35 31 33 24 27 24 19 Nonnuclear 55 63 71 66 79 42 35 49 Clean Air Act Amendments Compliance 0 1 9 33 26 14 15 44 Total $204 $200 $218 $231 $238 $195 $195 $229
*Construction of Perry Unit 2 was suspended in 1985. In 1992, Cleveland Electric purchased Duquesne's ownership share of Perry Unit 2 for $3,324,000. At December 31, 1993, Centerior Energy, Cleveland Electric and Toledo Edison wrote off their investment in Perry Unit 2 (see Note 4(b)). Each company in the CAPCO Group is responsible for financing the portion of the capital costs of nuclear fuel equivalent to its ownership and leased interest in the unit in which the fuel will be utilized. See "Operations-- Fuel Supply--Nuclear" for information regarding nuclear fuel supplies and Note 6 regarding leasing arrangements to finance nuclear fuel capital costs. Nuclear fuel capital costs incurred by Cleveland Electric, Toledo Edison and the Centerior System during 1991, 1992 and 1993 and their estimated nuclear fuel capital costs for 1994 through 1998 are as follows: 16
Actual Estimated 1991 1992 1993 1994 1995 1996 1997 1998 (Millions of Dollars) Cleveland Electric $ 32 $ 30 $ 26 $ 28 $ 18 $ 29 $ 33 $ 37 Toledo Edison $ 27 $ 22 $ 20 $ 23 $ 12 $ 30 $ 27 $ 28 Centerior System $ 59 $ 52 $ 46 $ 51 $ 30 $ 59 $ 60 $ 65
Financing Program Reference is made to Centerior Energy's, Cleveland Electric's and Toledo Edison's Management's Financial Analysis contained under Item 7 of this Report and to Notes 11 and 12 for discussions of the Centerior System's financing activity in 1993; debt and preferred stock redemption requirements during the 1994-1998 period; expected external financing needs during such period; re- strictions on the issuance of additional debt securities and preferred stock; short-term and long-term financing capability; and securities ratings for the Operating Companies. In the second quarter of 1994, Cleveland Electric and Toledo Edison expect to issue $46,100,000 and $30,500,000, respectively, of first mortgage bonds as collateral security for the sale by a public authority of equal principal amounts of tax-exempt bonds. The proceeds from the sales of the public authority's bonds will be used to refund $46,100,000 and $30,500,000, respec- tively, of tax-exempt bonds that were issued in 1988 and have been continu- ously remarketed on a floating rate basis. The new series of bonds will each be issued at a fixed rate of interest for the remaining term to July 1, 2023. Centerior expects to raise about $35,000,000 in 1994 from the sale of authorized but unissued common stock under certain of its employee and share owner stock purchase plans. GENERAL REGULATION Holding Company Regulation Centerior Energy is currently exempt from regulation under the Holding Company Act. The Energy Act contains, among other provisions, amendments to the Holding Company Act and the Federal Power Act. The Energy Act also adopted nuclear power licensing and related regulations, energy efficiency standards and incentives for the use of alternative transportation fuels. Amendments to the Holding Company Act create a new class of independent power producers known as "Exempt Wholesale Generators", which are exempt from the Holding Company Act corporate structure regulations and operate without SEC approval or regulation. Exempt Wholesale Generators may be owned by holding companies, electric utility companies or any other person. 17 State Utility Commissions - ------------------------- The Operating Companies are subject to the jurisdiction of the PUCO with re- spect to rates, service, accounting, issuance of securities and other matters. Under Ohio law, municipalities may regulate rates, subject to appeal to the PUCO if not acceptable to the utility. See "Electric Rates" for a description of certain aspects of Ohio rate-making law. The Operating Companies are also subject to the jurisdiction of the PaPUC in certain respects relating to their ownership interests in generating facilities located in Pennsylvania. The PUCO is composed of five commissioners appointed by the Governor of Ohio from nominees recommended by a Public Utility Commission Nominating Council. Nominees must have at least three years' experience in one of several disci- plines. Not more than three commissioners may belong to the same political party. Under Ohio law, a public utility must file annually with the PUCO a long-term forecast of customer loads, facilities needed to serve those loads and prospective sites for those facilities. This forecast must include the following: (1) Demand Forecast--the utility's 20-year forecast of sales and peak demand, before and after the effects of demand-side management programs. (2) Integrated Resource Plan (required biennially)--the utility's projected mix of resource options to meet the projected demand. (3) Short-Term Implementation Plan and Status Report (required biennially)-- the utility's discussion of how it plans to implement its integrated resource plan over the next four years. Estimates of annual expenditures and security issuances associated with the integrated resource plan over the four-year period must also be provided. The PUCO must hold a public hearing on the long-term forecast at least once every five years to determine the reasonableness of such forecast. The PUCO and the OPSB are required to consider the record of such hearings in proceed- ings for approving facility sites, changing rates, approving security issues and initiating energy conservation programs. Ohio law also permits electric utilities under PUCO jurisdiction to submit environmental compliance plans for PUCO review and approval. Ohio law requires that the PUCO make certain statutory findings prior to approving the environmental compliance plan, which includes that the plan is a reasonable least cost strategy for compliance with air quality requirements. In 1992, the PUCO held hearings on the Operating Companies' 1992 long-term forecast and environmental compliance plan. Centerior and the parties intervening in the proceeding reached agreement on the forecast and environmental compliance plan, and the agreement was sub- sequently approved by the PUCO in February 1993. The PUCO has jurisdiction over certain transactions by companies in an elec- tric utility holding company system if it includes at least one Ohio electric utility and is exempt from regulation under Section 3(a)(1) or (2) of the Holding Company Act. An Ohio electric utility in such a holding company 18 system, such as Centerior, must obtain PUCO approval to invest in, lend funds to, guarantee the obligations of or otherwise finance or transfer assets to any nonutility company in that holding company system, unless the transaction is in the ordinary course of business operations in which one company acts for or with respect to another company. Also, the holding company in such a hold- ing company system must obtain PUCO approval to make any investment in any nonutility subsidiaries, affiliates or associates of the holding company if such investment would cause all such capital investments to exceed 15% of the consolidated capitalization of the holding company unless such funds were provided by nonutility subsidiaries, affiliates or associates. The PUCO has a reserve capacity policy for electric utilities in Ohio stating that (i) 20% of service area peak load excluding interruptible load is an appropriate generic benchmark for an electric utility's reserve margin; (ii) a reserve margin exceeding 20% gives rise to a presumption of excess capacity, but may be appropriate if it confers a positive net present benefit to cus- tomers or is justified by unique system characteristics; and (iii) appropriate remedies for excess capacity (possibly including disallowance of costs in rates) will be determined by the PUCO on a case-by-case basis. Ohio Power Siting Board The OPSB has state-wide jurisdiction, except to the extent pre-empted by Federal law, over the location, need for and certain environmental aspects of electric generating units with a capacity of 50,000 kilowatts or more and transmission lines with a rating of at least 125 kV. Federal Energy Regulatory Commission The Operating Companies are each subject to the jurisdiction of the FERC with respect to the transmission and sale of power at wholesale in interstate com- merce, interconnections with other utilities, accounting and certain other matters. Cleveland Electric is also subject to FERC jurisdiction with respect to its ownership and operation of the Seneca Plant. Nuclear Regulatory Commission The nuclear generating units in which the Operating Companies have an interest are subject to regulation by the NRC. The NRC's jurisdiction encompasses broad supervisory and regulatory powers over the construction and operation of nuclear reactors, including matters of health and safety, antitrust considera- tions and environmental impacts. Owners of nuclear units are required to purchase the full amount of nuclear liability insurance available. See Note 5(b) for a description of nuclear in- surance coverages. Other Regulation The Operating Companies are subject to regulation by Federal, state and local authorities with regard to the location, construction and operation of certain facilities. The Operating Companies are also subject to regulation by local authorities with respect to certain zoning and planning matters. 19 ENVIRONMENTAL REGULATION General The Operating Companies are subject to regulation with respect to air quality, water quality and waste disposal matters. Federal environmental legislation affecting the operations and properties of the Operating Companies includes the Clean Air Act, the Clean Air Act Amendments, the Clean Water Act, Superfund, and the Resource Conservation and Recovery Act. The requirements of these statutes and related state and local laws are continually changing due to the promulgation of new or revised laws and regulations and the results of judicial and agency proceedings. Compliance with such laws and regulations may require the Operating Companies to modify, supplement, abandon or replace facilities and may delay or impede construction and operation of facilities, all at costs which could be substantial. The Operating Companies expect that the impact of such costs would eventually be reflected in their respective rate schedules. Cleveland Electric and Toledo Edison plan to spend, during the period 1994-1996, $70,000,000 and $20,000,000, respectively, for pollution control facilities, including Clean Air Act Amendments compliance costs. The Operating Companies believe that they are currently in compliance in all material respects with all applicable environmental laws and regulations, or to the extent that one or both of the Operating Companies may dispute the applicability or interpretation of a particular environmental law or regula- tion, the affected company has filed an appeal or has applied for permits, revisions in requirements, variances or extensions of deadlines. Concerns have been raised regarding the possible health effects associated with electric and magnetic fields. Although scientific research as to such effects has yielded inconclusive results, additional studies are being con- ducted. If electric and magnetic fields are ultimately found to pose a health risk, the Operating Companies may be required to modify transmission and distribution lines or other facilities. Air Quality Control Under the Clean Air Act, the Ohio EPA has adopted Ohio emission limitations for particulate matter and sulfur dioxide for each of the Operating Companies' plants. The Clean Air Act provides for civil penalties of up to $25,000 per day for each violation of an emission limitation. The U.S. EPA has approved the Ohio EPA's emission limitations and the related implementation plans ex- cept for some particulate matter emissions and certain sulfur dioxide emis- sions. The U.S. EPA has adopted separate sulfur dioxide emission limitations for each of the Operating Companies' plants. In November 1990, the Clean Air Act Amendments were signed into law imposing restrictions on nitrogen oxides emissions and making sulfur dioxide emission limitations significantly more severe beginning in 1995. See Note 4(a) for a description of the Operating Companies' compliance strategy, which was in- cluded in the agreement approved by the PUCO in February 1993 in connection with the Operating Companies' 1992 long-term forecast. The Clean Air Act 20 Amendments also require studies to be conducted on the emission of certain potentially hazardous air pollutants which could lead to additional restrictions. In 1985, the U.S. EPA issued revised regulations specifying the extent to which power plant stack height may be incorporated into the establishment of an emission limitation. Pursuant to the revised regulations, the Operating Companies submitted to the Ohio EPA information intended to support continua- tion of the stack height credit received under the previous regulations for stacks at Cleveland Electric's Avon Lake and Eastlake Plants and Toledo Edison's Bay Shore Station. The Ohio EPA has accepted the submissions and forwarded them to the U.S. EPA for approval. In January 1988, the District of Columbia Circuit Appeals Court remanded portions of the 1985 regulations to the U.S. EPA for further consideration; however, the U.S. EPA has not taken action specifically on this issue. Congress is considering legislation to reduce emissions of gases such as those resulting from the burning of coal that are thought to cause global warming. If such legislation is adopted, the cost of operating coal-fired plants could increase significantly and coal-fired generating capacity could decrease significantly. Water Quality Control The Clean Water Act requires that power plants obtain permits that contain certain effluent limitations (that is, limits on discharges of pollutants into bodies of water). It also requires the states to establish water quality standards (which could result in more stringent effluent limitations than those required under the Clean Water Act) and a permit system to be approved by the U.S. EPA. Violators of effluent limitations and water quality standards are subject to a civil penalty of up to $25,000 per day for each such violation. The Clean Water Act permits thermal effluent limitations to be established for a facility which are less stringent than those which otherwise would apply if the owner can demonstrate that such less stringent limitations are sufficient to assure the protection and propagation of aquatic and other wildlife in the affected body of water. By 1978, the Operating Companies had submitted to the Ohio EPA such demonstrations for review with respect to their Ashtabula, Avon Lake, Lake Shore, Eastlake, Acme and Bay Shore plants. The Ohio EPA has taken no action on the submittals. The Operating Companies have received NPDES permit renewals from the Ohio EPA or have applied for such renewals for all of their power plants. In those situations where a permit application is pending, the affected plant may con- tinue to operate under the expired permit while such application is pending. Any violation of an NPDES permit is considered to be a violation of the Clean Water Act subject to the penalty discussed above. 21 In 1990, the Ohio EPA issued revised water quality standards applicable to Lake Erie and waters of the State of Ohio. Based upon these revised water quality standards, the Ohio EPA placed additional effluent limitations in their most recent NPDES permits. The revised standards also may serve as the basis for more stringent effluent limitations in future NPDES permits. Such limitations could result in the installation of additional pollution control equipment and increased operating expenses. The Operating Companies are monitoring discharges at their plants to support their position that addi- tional effluent limitations are not justified. On April 16, 1993, the U.S. EPA issued proposed rules for water quality standards applicable to all states abutting the Great Lakes, including Ohio. These states would be required to adopt state water quality standards and procedures consistent with the rules within two years of final publication. Preliminary reviews indicate that the cost of complying with these rules could be significant. However, Centerior cannot determine what impact these rules will have on its operations until such rules are issued in final form and are incorporated into Ohio regulations. Waste Disposal See "Hazardous Waste Disposal Sites" in Management's Financial Analysis contained under Item 7 of this Report and Note 4(c) for a discussion of the Operating Companies' potential involvement in certain hazardous waste disposal sites, including those subject to Superfund. See "Nuclear Units" and "Fuel Supply--Nuclear" under "Operations", below, for discussions concerning the disposal of nuclear waste. The Resource Conservation and Recovery Act exempts certain fossil fuel com- bustion waste products, such as fly ash, from hazardous waste disposal re- quirements. The Operating Companies are unable to predict whether Congress will choose to amend this exemption in the future or, if so, the costs relat- ing to any required changes in the operations of the Operating Companies. ELECTRIC RATES Under Ohio law, rate base is the original cost less depreciation of a utility's total plant adjusted for certain items. The law permits the PUCO, in its discretion, to include CWIP in rate base when a construction project is at least 75% complete, but limits the amount included to 10% of rate base ex- cluding CWIP or, in the case of a project to construct pollution control fa- cilities which would remove sulfur and nitrous oxides from flue gas emissions, 20% of rate base excluding CWIP. When a project is completed, the portion of its cost which had been included in rate base as CWIP is excluded from rate base until the revenue received due to the CWIP inclusion is offset by the revenue lost due to its exclusion. During this period of time, an AFUDC-type credit is allowed on the portion of the project cost excluded from rate base. Also, the law permits inclusion of CWIP for a particular project for a period not longer than 48 consecutive months, plus any time needed to comply with 22 changed governmental regulations, standards or approvals. The PUCO is em- powered to permit inclusion for up to another 12 months for good cause shown. If a project is canceled or not completed within the allowable period of time after inclusion of its CWIP has started, then CWIP is excluded from rate base and any revenues which resulted from such prior inclusion are offset against future revenues over the same period of time as the CWIP was included. Current Ohio law further provides that requested rates can be collected by a public utility, subject to refund, if the PUCO does not make a decision within 275 days after the rate request application is filed. If the PUCO does not make its final decision within 545 days, revenues collected thereafter are not subject to refund. A notice of intent to file an application for a rate in- crease cannot be filed before the issuance of a final order in any prior pend- ing application for a rate increase or until 275 days after the filing of the prior application, whichever is earlier. The minimum period by which the notice of intent to file must precede the actual filing is 30 days. The test year for determining rates may not end more than nine months after the date the application for a rate increase is filed. Under Ohio law, electric rates are adjusted every six months to reflect changes in fuel costs. The PUCO reviews such adjustments annually. Any difference between actual fuel costs during a six-month period and the fuel revenues recovered in that period is deferred and is taken into account in setting the fuel recovery factor for a subsequent six-month period. The PUCO has authorized the Operating Companies to adjust their rates on a seasonal basis such that electric rates are higher in the summer. Also, under Ohio law, municipalities may regulate rates charged by a utility, subject to appeal to the PUCO if not acceptable to the utility. If municipally fixed rates are accepted by the utility, such rates are binding on both parties for the specified term and cannot be changed by the PUCO. See Note 7 and Management's Financial Analysis contained under Item 7 of this Report for information relating to the PUCO's January 1989 rate orders and the Rate Stabilization Program that was approved by the PUCO for the Operating Companies in October 1992. OPERATIONS Sales of Electricity Kilowatt-hour sales by the Operating Companies follow a seasonal pattern marked by increased customer usage in the summer for air conditioning and in the winter for heating. Historically, Cleveland Electric has experienced its heaviest demand for electric service during the summer months because of a significant air conditioning load on its system and a relatively low amount of electric heating load in the winter. Toledo Edison, although having a significant electric heating load, has experienced in recent years its heaviest demand for electric service during the summer months because of heavy air conditioning usage. 23 The Centerior System's largest customer is a steel manufacturer which has two major steel producing facilities served by Cleveland Electric. Sales to these facilities accounted for 2.5% and 3.5% of the 1993 total electric operating revenues of Centerior Energy and Cleveland Electric, respectively. The loss of these facilities (and the resultant loss of another large customer whose primary product is purchased by the two steel producing facilities) would reduce Centerior Energy's and Cleveland Electric's net income by about $34,000,000 based on 1993 sales levels. The largest customer served by Toledo Edison is a major automobile manufac- turer. Sales to this customer accounted for 1.4% and 3.9% of the 1993 total electric operating revenues of Centerior Energy and Toledo Edison, re- spectively. The loss of this customer would reduce Centerior Energy's and Toledo Edison's net income by about $10,000,000 based on 1993 sales levels. Operating Statistics For data on operating revenues by service category, electric sales by service category, customers by service category and electric energy generation for 1983 and 1989 through 1993, see the attached Pages F-23 and F-24 for Centerior Energy, F-46 and F-47 for Cleveland Electric and F-68 and F-69 for Toledo Edison. Nuclear Units The Operating Companies' generating facilities include, among others, three nuclear units owned or leased by the CAPCO Group--Perry Unit 1, Beaver Valley Unit 2 and Davis-Besse. These three units are in commercial operation. Cleveland Electric has responsibility for operating Perry Unit 1, Duquesne has responsibility for operating Beaver Valley Unit 2 and Toledo Edison has re- sponsibility for operating Davis-Besse. Cleveland Electric and Toledo Edison own, respectively, 31.11% and 19.91% of Perry Unit 1, 24.47% and 1.65% of Beaver Valley Unit 2 and 51.38% and 48.62% of Davis-Besse. Cleveland Electric and Toledo Edison also lease, as joint lessees, another 18.26% of Beaver Valley Unit 2 as a result of a September 1987 sale and leaseback transaction (see Note 2). Davis-Besse was placed in commercial operation in 1977, and its operating license expires in 2017. Perry Unit 1 and Beaver Valley Unit 2 were placed in commercial operation in 1987, and their operating licenses expire in 2026 and 2027, respectively. As part of its January 1989 rate orders, the PUCO approved nuclear plant performance standards for the Operating Companies based on rolling three-year industry averages of operating availability for pressurized water reactors and for boiling water reactors over the 1988-1998 period. Operating availability is the ratio of the number of hours a unit is available to generate elec- tricity (whether or not the unit is operated) to the number of hours in the period, expressed as a percentage. The three-year operating availability averages of the Operating Companies' nuclear units are compared against the industry averages for the same three-year period with a resultant penalty or banked benefit. If the industry performance standards are not met, a penalty 24 would be incurred which would require the Operating Companies to refund in- cremental replacement power costs to customers through the semiannual fuel cost rate adjustment. However, if the performance of the Operating Companies' nuclear units exceeds the industry standards, a banked benefit results which can be used to offset disallowances of incremental replacement power costs should future performance be below industry standards. The relevant industry standards for the 1991-1993 period are 78.0% for pressurized water reactors such as Davis-Besse and Beaver Valley Unit 2 and 72.8% for boiling water reactors such as Perry Unit 1. The 1991-1993 availability average for Davis-Besse and Beaver Valley Unit 2 was 87.1% and for Perry Unit 1 was 69.2%. At December 31, 1993, the total banked benefit for the Operating Companies is estimated to be between $18,000,000 and $20,000,000. All three nuclear units have received generally favorable evaluations from the NRC in their most recent SALP reviews. Each of the functional areas evaluated is rated according to three performance categories, with category 1 indicating performance substantially exceeding regulatory requirements and that reduced NRC attention may be appropriate; category 2 indicating performance above that needed to meet regulatory requirements and that NRC attention may be main- tained at normal levels; and category 3 indicating performance does not significantly exceed that needed to meet minimal regulatory requirements and that NRC attention should be increased above normal levels. The most recent review periods and SALP review scores for Perry Unit 1 and Davis-Besse are:
Perry Unit 1 Davis-Besse SALP Review Period 11/1/91-1/31/93 12/1/91-6/30/93 Plant Operations 2 2 Radiological Controls 2 2 Maintenance/Surveillance 2 1 Emergency Preparedness 1 1 Security and Safeguards 1 1 Engineering/Technical Support 2 1 Safety Assessment/Quality Verif. 3 1
The NRC increased its attention to Perry Unit 1 in 1993 and placed the unit on a newly created list for units identified as showing "safety performance trending downward." Centerior made specific organizational changes and developed a comprehensive course of action to improve the operating performance of Perry Unit 1. In response to this course of action, on January 27, 1994, the NRC removed Perry Unit 1 from the performance trending downward list. In 1993, the NRC revised the functional areas which comprise the SALP grading process. Plant Support is a new category which covers the areas previously covered by Security, Emergency Preparedness and Radiological Controls. The Safety Assessment/Quality Verification category is now an integral part of each category and is no longer being singled out. Beaver Valley Unit 2 is the only Centerior System unit to have been graded under the new system. Perry Unit 1 and Davis-Besse will be graded under the new system when their next 25 SALP scores are issued. The most recent review period and SALP review scores for Beaver Valley Unit 2 are: SALP Review Period 6/14/92-11/27/93 Operations 1 Engineering 2 Maintenance 2 Plant Support 1
The Operating Companies ship low-level radioactive waste produced at their nuclear plants to an offsite disposal facility which may not accept such shipments after mid-1994. The Operating Companies' ability to continue offsite disposal depends on whether the State of Ohio develops a low-level radioactive waste disposal facility within the next several years. If offsite disposal becomes unavailable, the Operating Companies have facilities to temporarily store such waste on site at each of the nuclear plants. However, the Operating Companies do not intend to store such waste on site until all available off-site options have been exhausted. See Note 4(b) for a discussion of the write-off of Perry Unit 2, and see Note 5(a) and "Outlook--Nuclear Operations" in Management's Financial Analysis contained under Item 7 of this Report for a discussion of potential risks facing Centerior and the Operating Companies as owners of nuclear generating units. Competitive Conditions General. The Operating Companies compete in their respective service areas with suppliers of natural gas to satisfy customers' energy needs with regard to heating and appliance usage. The Operating Companies also are engaged in competition to a lesser extent with suppliers of oil and liquefied natural gas for heating purposes and with suppliers of cogeneration equipment. One competitor provides steam for heating purposes and provides chilled water for cooling purposes in certain areas of downtown Cleveland. The Operating Companies also compete with municipally owned electric systems within their respective service areas. As discussed below, two of the munici- palities served by the Operating Companies, the City of Toledo and the City of Garfield Heights, are investigating the economic feasibility of establishing and operating municipally owned electric systems. A few other communities have evaluated municipalization of electric service and decided to continue service from Cleveland Electric and Toledo Edison. Officials in still other communities have indicated an interest in evaluating the municipalization issue. The Operating Companies face continuing competition from locations outside their service areas which are promoted by governmental and private agencies in attempts to influence potential and existing commercial and industrial cus- tomers to locate in their respective areas. 26 Cleveland Electric and Toledo Edison also periodically compete with other producers of electricity for sales to electric utilities which are in the market for bulk power purchases. The Operating Companies have inter- connections with other electric utilities (see "Item 2. Properties--General") and have a transmission system capable of transmitting ("wheeling") power between the Midwest and the East. Cleveland Electric. Located within Cleveland Electric's service area are two municipally owned electric systems. Cleveland Electric supplies a small portion of those systems' power needs at wholesale rates. One of those systems, CPP, is operated by the City of Cleveland in competition with Cleveland Electric. CPP is primarily an electric distribution system which currently supplies electric power in approximately 70% of the City's geographical area (expected to increase to 100% by the end of 1997) and to approximately 28% (about 59,000) of the electric consumers in the City--equal to about 8% of all customers served by Cleveland Electric. CPP's kilowatt- hour sales and revenues are equal to about 5% of Cleveland Electric's kilowatt-hour sales and revenues. Much of the area served by CPP overlaps that of Cleveland Electric. For all classes of customers, Cleveland Electric's rates are higher than CPP's rates due largely to CPP's exemption from taxation, its reliance on short- and medium-term power supply contracts and the spot market which are lower in cost and the lower-cost financing available to CPP. Cleveland Electric makes power available to CPP on a wholesale basis, subject to FERC regulation. In 1993, Cleveland Electric directly and through AMP-Ohio provided about 15% of CPP's energy requirements. The balance of CPP's power is purchased from other sources and wheeled over Cleveland Electric's transmission system. In cases currently pending, the FERC has been asked to determine whether Cleveland Electric is obligated to provide an additional inter- connection with CPP and to rule on Cleveland Electric's request for an increase in rates for power and services provided to CPP. Cleveland Electric believes that it is entitled to a higher level of compensation for the power and the services it provides because the rates currently paid by CPP do not adequately cover the cost of providing such power and services. CPP is constructing new transmission and distribution facilities extending into eastern portions of Cleveland and plans to expand to western portions of Cleveland, both of which now are served exclusively by Cleveland Electric. During the 1991-1993 period, Cleveland Electric had a net loss of about 7,000 customers, including several hundred commercial and industrial customers, to the CPP system which resulted in a reduction in Cleveland Electric's 1993 annual income of about $14,000,000. CPP's Phase I expansion, as now planned, could take away about 18,000 more of Cleveland Electric's customers, while its Phase II expansion could take away about 29,000 customers over the next several years. This could eventually reduce Cleveland Electric's net income by about $27,000,000. Cleveland Electric has retained many medium and large commercial and industrial customers in Cleveland despite CPP's expansion efforts. Long-term contracts with many of these customers provide them with economic incentives to remain with Cleveland Electric. Most of those contracts have remaining terms of one to five years. 27 In 1991, the City of Brook Park, located within the Cleveland Electric service territory, commissioned a feasibility study regarding the establishment of a municipal electric system. Ford Motor Company operates a large engine manu- facturing plant in Brook Park. In April 1993, Cleveland Electric entered into an agreement with Brook Park running through the year 2000 whereby Cleveland Electric would make available a total of $1,250,000 for demand-side manage- ment programs to help reduce the energy bills of Brook Park customers over the next five years and $400,000 to study the feasibility of a resource recovery plant in the City to process municipal waste. At the same time, Cleveland Electric entered into a five-year agreement with Ford Motor Company in Brook Park which provides pricing incentives to help Ford improve its competitive- ness and encourage economic growth in Cleveland Electric's service area. The agreement can be renewed, at Ford's option, through the year 2000. In March 1994, the City Council of Garfield Heights, a suburb of Cleveland, passed an ordinance calling for a 30% reduction in rates for Cleveland Electric's customers in that city. Cleveland Electric will appeal that ordinance to the PUCO which will allow the existing rates to stay in effect. The potential impact of the rate reduction on Cleveland Electric's annual revenues is $5,500,000. Currently, one commercial customer and one industrial customer of Cleveland Electric have cogeneration installations. A number of customers have inquired about cogeneration applications, but there were no new installations in 1991, 1992 or 1993. Toledo Edison. Located wholly or partly within Toledo Edison's service area are six rural electric cooperatives, five of which are supplied with power, transmitted in some cases over Toledo Edison's facilities, by Buckeye Power, Inc. (an affiliate of a number of Ohio rural electric cooperatives) and the sixth is supplied by Toledo Edison. Also located within Toledo Edison's service area are 16 municipally owned electric distribution systems, three of which are supplied by other electric systems. Toledo Edison provides a portion of the power purchased by the other 13 municipalities at wholesale rates through a contract with AMP-Ohio that expires in 2009. Rates under this agreement are permitted to increase annually to compensate for increased costs of operation. Less than 2% of Toledo Edison's total electric operating revenues in 1993 were derived from sales under the AMP-Ohio contract. In October 1989, the City of Toledo adopted an ordinance establishing an Electric Franchise Review Committee for the purpose of studying Toledo Edison's franchise agreement with the City to determine whether alternate energy sources may be utilized. The Committee investigated the feasibility of establishing a municipal electric system within the City of Toledo and the feasibility of utilizing other alternative electric power sources. In May 1992, the Committee recommended that the City negotiate with Toledo Edison with regard to rates and other customer initiatives rather than create its own municipal electric system. The Committee recommended that if negotiations with Toledo Edison were unsuccessful, the City should create a small municipal utility to serve approximately 20% of the City's electricity load, primarily 28 City facilities, such as the waste water treatment plant, and businesses with large electricity consumption. In March 1993, the City and Toledo Edison reached agreement on a non-exclusive franchise which runs through 2000. The franchise, which was approved by voters in November 1993, will terminate two years earlier if Toledo Edison files for a rate increase with the PUCO prior to 1999. The City also retains its right to establish a municipal electric system. In addition, Toledo Edison will provide $6,000,000 for demand-side management programs; energy efficiency programs for senior citizens, low income customers and small businesses; and economic development programs over a five-year period beginning in 1994. These expenditures will be in addition to the demand-side management expenditures currently planned by the Centerior System. The agreement does not call for a reduction in base electric rates. Meanwhile, the Electric Franchise Review Committee continues to explore the formation of a municipal system to serve 20% of the load in the City. The last commercial customer of Toledo Edison having a cogeneration unit ceased operation of its unit during the first quarter of 1992. Fuel Supply Generation by type of fuel for 1993 was 73% coal-fired and 27% nuclear for Cleveland Electric; 54% coal-fired and 46% nuclear for Toledo Edison; and 67% coal-fired and 33% nuclear for the Centerior System. Coal. In 1993, Cleveland Electric and Toledo Edison burned 6,238,000 tons and 2,138,000 tons of coal, respectively, for electric generation. Each utility normally maintains a reserve supply of coal sufficient for about 40 days of normal operations. On March 1, 1994, this reserve was about 24 days for plants operated by Cleveland Electric, 34 days for plants operated by Toledo Edison and 40 days for the Mansfield Plant, which is operated by Pennsylvania Power. In 1993, about 59% of Cleveland Electric's coal requirements were purchased under long-term contracts, with the longest remaining term being almost 10 years. In most cases, these contracts provide for adjusting the price of the coal on the basis of changes in coal quality and mining costs. The sulfur content of the coal purchased under these contracts ranges from less than 1% to about 4%. The balance of Cleveland Electric's coal was purchased on the spot market with sulfur content ranging from less than 1% to 3.5%. In 1993, about 66% of Toledo Edison's coal requirements were purchased under long-term contracts, with the longest remaining term being almost seven years. In most cases, these contracts provide for adjusting the price of the coal on the basis of changes in coal quality and mining costs. The sulfur content of the coal purchased under these contracts ranges from less than 1% to 4%. One of Cleveland Electric's long-term coal supply contracts is with Ohio Valley. Cleveland Electric has agreed to pay Ohio Valley certain amounts to cover Ohio Valley's costs regardless of the amount of coal actually delivered. Included in those costs are amounts sufficient to service certain long-term debt and lease obligations incurred by Ohio Valley. If the coal sales agree- ment is terminated for any reason, including the inability to use the coal, 29 Cleveland Electric must assume certain of Ohio Valley's debt and lease obli- gations and may incur other expenses including mine closing costs, if necessary. The principal amount of debt and termination values of leased property covered by Cleveland Electric's agreement was $27,116,000 at December 31, 1993. Cleveland Electric is considering terminating the Ohio Valley agreement as part of its least cost plan to comply with the requirements of the Clean Air Act Amendments. If the agreement is so terminated, Cleveland Electric would ask the PUCO to allow recovery of the termination charges from its customers through the fuel component. If the agreement is not terminated early, Cleveland Electric expects that Ohio Valley revenues from sales of coal will continue to be sufficient for Ohio Valley to meet its debt and lease obligations. The contract with Ohio Valley expires in September 1997. The CAPCO Group companies, including the Operating Companies, have a long-term contract with Quarto and Consol for the supply of about 75%-85% of the annual coal needs of the Mansfield Plant. The contract runs through at least the end of 1999, and the price of coal is adjustable to reflect changes in labor, materials, transportation and other costs. The CAPCO Group companies have guaranteed, severally and not jointly, the debt and lease obligations incurred by Quarto to develop, equip and operate two of the mines which supply the Mansfield Plant. At December 31, 1993, the total dollar amount of Quarto's debt and lease obligations guaranteed by Cleveland Electric was $33,380,000 and by Toledo Edison was $19,522,000. Centerior, Cleveland Electric and Toledo Edison expect that Quarto revenues from sales of coal to the CAPCO Group companies will continue to be sufficient for Quarto to meet its debt and lease obligations. The Operating Companies' least cost plan for complying with the Clean Air Act Amendments, which was included in the agreement approved by the PUCO in February 1993 in connection with the Operating Companies' 1992 long-term forecast, calls for greater use of low-sulfur coal and less use of high-sulfur coal. Some of the low-sulfur coal required to comply with Phase 1 of the Clean Air Act Amendments was contracted for in 1992. Additional supplies of low-sulfur coal will be contracted for in 1994. The only long-term coal contract affected by the Clean Air Act Amendments is Cleveland Electric's contract with Ohio Valley. Nuclear. The acquisition and utilization of nuclear fuel involves six dis- tinct steps: (i) supply of uranium oxide raw material, (ii) conversion to uranium hexafluoride, (iii) enrichment, (iv) fabrication into fuel assemblies, (v) utilization as fuel in a nuclear reactor and (vi) storing or disposing of spent fuel. The Operating Companies have inventories of raw material sufficient to provide nuclear fuel through 1996 for the operation of their nuclear generating units and have contracts for fabrication services for all of that fuel. The CAPCO Group companies have a 30-year contract with the DOE which will supply all of the needed enrichment services for their nuclear units' fuel supply through 1995. Beyond 1995, the amount of enrichment services under the DOE contract varies by CAPCO Group company, with Cleveland Electric's and Toledo Edison's enrichment services reduced to 70% in 1996-1999 and reduced to 0% in 2000-2002. The additional required enrichment services are available. Substantial additional fuel will have to be obtained in the 30 future over the remaining useful lives of the units. There is a plentiful supply of uranium oxide raw material to meet the industry's nuclear fuel needs. Off-site disposal of spent nuclear fuel is unavailable, but the CAPCO Group companies have contracts with the DOE which provide for the future acceptance 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 1996, 2009 and 2008, respectively. Any additional storage capacity needed for the period until the government accepts the fuel can be provided for either on-site or off-site by the time it is needed. Oil. The Operating Companies each have adequate supplies of oil and fuel for their oil-fired electric generating units which are used primarily as reserve and peaking capacity. 31 EXECUTIVE OFFICERS OF THE REGISTRANTS AND THE SERVICE COMPANY Set forth below are the names, ages as of March 15, 1994, and business experience during the past five years (effective dates of positions in parentheses) of the executive officers of Centerior Energy, the Service Company, Cleveland Electric and Toledo Edison. Positions currently held are designated with an asterisk (*).
Business Experience Name (Age) Centerior Energy Service Company Cleveland Electric Toledo Edison Robert J. Farling *Chairman of the *Chairman of the *Chairman of the *Chairman of the (57) Board and Chief Board and Chief Board and Chief Board and Chief Executive Officer Executive Executive Officer Executive Officer (March 1992) Officer (March (February 1989 to (October 1988 to *President 1992) April 1990; July April 1990; July (October 1988) *President (July 1993) 1993) 1988) Murray R. Edelman *Executive Vice *Executive Vice *President *Vice Chairman (54) President President- (November 1993) (November 1993) (July 1988) Operations & President (July 1988) Engineering (July 1993) Executive Vice President-Power Generation (April 1990)
32
Business Experience Name (Age) Centerior Energy Service Company Cleveland Electric Toledo Edison Fred J. Lange, Jr. *Senior Vice *Senior Vice *Vice President *President (November (44) President President- (April 1990) 1993) (July 1993) Fossil & Vice President (April Senior Vice Transmission 1990) President-Legal, and Distribution Human & Corporate Operations Affairs (March (July 1993) 1992) Senior Vice Vice President- President-Legal, Legal & Corporate Human & Affairs (April Corporate Affairs 1990) (March 1992) Vice President- Legal & Corporate Affairs (April 1990) General Attorney and Senior Director of Governmental Affairs (July 1989) Assistant General Counsel and Principal Corporate Counsel (November 1986) Donald C. Shelton *Senior Vice Vice President- (60) President-Nuclear Nuclear (August (July 1993) 1986) Vice President- Nuclear-Davis- Besse (April 1990)
33
Business Experience Name (Age) Centerior Energy Service Company Cleveland Electric Toledo Edison Jacquita K. Hauserman *Vice President- *Vice President (51) Customer Support (November 1993) (July 1993) Vice President- Vice President- Administration Customer Service (October 1988) & Community Affairs (April 1990) Gary R. Leidich *Vice President *Vice President- *Vice President & *Vice President & (43) (July 1993) Finance & Chief Financial Chief Financial Administration Officer (July Officer (July (July 1993) 1993) 1993) Director-Human Resources Dept. (August 1991) Director-System Planning Engineering Dept. (December 1987)
34
Business Experience Name (Age) Centerior Energy Service Company Cleveland Electric Toledo Edison Terrence G. Linnert *Vice President *Vice President- *Vice President *Vice President (47) (July 1993) Legal & (July 1993) (July 1993) Governmental Affairs and General Counsel (July 1993) Vice President- Legal and General Counsel (March 1992) General Counsel and Director- Legal Services Dept. (May 1990) General Counsel (July 1989) Principal Counsel (June 1987) David L. Monseau *Vice President- Vice President- (53) Transmission & Customer Distribution Operations Operations (September 1987) (April 1990)
35
Business Experience Name (Age) Centerior Energy Service Company Cleveland Electric Toledo Edison Robert A. Stratman *Vice President- General Manager- (45) Nuclear-Perry Perry Plant (December 1992) Operations Dept. (April 1990) Director-Perry Plant Nuclear Engineering Dept. (January 1989) Al R. Temple *Vice President- (48) Marketing (February 1994) WMX Technologies, Inc.: Alliance Executive (July 1992) Vice President/ General Manager, Midwest Region (April 1991) Director of Marketing, Chemical Waste Management (June 1989) Borg Warner Chemicals: General Mgr., Multi- National Accts. (November 1988)
36
Business Experience --------------------------------------------------------------------------------- Name (Age) Centerior Energy Service Company Cleveland Electric Toledo Edison - ---------- ---------------- --------------- ------------------ ------------- Paul G. Busby *Controller (April *Controller (June *Controller (April *Controller (April (45) 1988) 1986) 1990) 1990) Gary M. Hawkinson *Treasurer *Treasurer (April *Treasurer (April *Treasurer (April 1990) (45) (February 1986) 1986) 1990) Assistant Treasurer Assistant Treasurer (August 1987) (September 1986) E. Lyle Pepin *Secretary *Secretary (April *Secretary (October *Secretary (October (52) (February 1986) 1986) 1988) 1988)
37 All of the executive officers of Centerior Energy, the Service Company, Cleveland Electric and Toledo Edison are elected annually for a one-year term by the Board of Directors of Centerior, the Service Company, Cleveland Electric or Toledo Edison, as the case may be. No family relationship exists among any of the executive officers and direc- tors of any of the Centerior System companies. Item 2. Properties GENERAL The Centerior System The wholly owned, jointly owned and leased electric generating facilities of the Operating Companies in commercial operation as of February 28, 1994 pro- vide the Centerior System with a net demonstrated capability of 5,980,000 kilowatts during the winter. These facilities include 20 generating units (3,634,000 kilowatts) at seven fossil-fired steam electric generation sta- tions; three nuclear generating units (1,856,000 kilowatts); a 351,000 kilo- watt share of the Seneca Plant; seven combustion turbine generating units (135,000 kilowatts) and one diesel generator (4,000 kilowatts). Operations at two fossil-fired generating units (320,000 kilowatts) ceased in 1993 and the units are being preserved for future use. All of the Centerior System's generating facilities are located in Ohio and Pennsylvania. The Centerior System's net 60-minute peak load of its service area for 1993 was 5,397,000 kilowatts and occurred on August 27. At the time of the 1993 peak load, the operable capacity available to serve the load was 5,998,000 kilowatts. The Centerior System's 1994 service area peak load is forecasted to be 5,250,000 kilowatts, after demand-side management considerations. The operable capacity expected to be available to serve the Centerior System's 1994 peak is 5,670,000 kilowatts. Over the 1994-1996 period, Centerior Energy forecasts its operable capacity margins at the time of the projected Centerior System peak loads to range from 7% to 9.5%. Each Operating Company owns the electric transmission and distribution facili- ties located in its respective service area. Cleveland Electric and Toledo Edison are interconnected by 345 kV transmission facilities, some portions of which are owned and used by Ohio Edison. The Operating Companies have a long- term contract with the CAPCO Group companies, including Ohio Edison, relating to the use of these facilities. These interconnection facilities provide for the interchange of power between the two Operating Companies. The Centerior System is interconnected with Ohio Edison, Ohio Power, Penelec and Detroit Edison. 38 Cleveland Electric The wholly owned, jointly owned and leased electric generating facilities of Cleveland Electric in commercial operation as of February 28, 1994 provide a net demonstrated capability of 4,148,000 kilowatts during the winter. These facilities include 16 generating units (2,709,000 kilowatts) at five fossil- fired steam electric generation stations; its share of three nuclear generat- ing units (1,026,000 kilowatts); a 351,000 kilowatt share of the Seneca Plant; two combustion turbine generating units (58,000 kilowatts) and one diesel gen- erator (4,000 kilowatts). Operations at one fossil-fired generating unit (245,000 kilowatts) ceased in October 1993 and the unit is being preserved for future use. All of Cleveland Electric's generating facilities are located in Ohio and Pennsylvania. The net 60-minute peak load of Cleveland Electric's service area for 1993 was 3,862,000 kilowatts and occurred on July 28. The operable capacity at the time of the 1993 peak was 4,122,000 kilowatts. Cleveland Electric's 1994 service area peak load is forecasted to be 3,790,000 kilowatts, after demand- side management considerations. The operable capacity, which includes firm purchases, expected to be available to serve Cleveland Electric's 1994 peak is 4,018,000 kilowatts. Over the 1994-1996 period, Cleveland Electric forecasts its operable capacity margins at the time of its projected peak loads to range from 6% to 9%. Cleveland Electric owns the facilities located in the area it serves for transmitting and distributing power to all its customers. Cleveland Electric has interconnections with Ohio Edison, Ohio Power and Penelec. The intercon- nections with Ohio Edison provide for the interchange of electric power with the other CAPCO Group companies and for transmission of power from the tenant- in-common owned or leased CAPCO Group generating units as well as for the interchange of power with Toledo Edison. The interconnection with Penelec provides for transmission of power from Cleveland Electric's share of the Seneca Plant. In addition, these interconnections provide the means for the interchange of electric power with other utilities. Cleveland Electric has interconnections with each of the municipal systems operating within its service area. Toledo Edison The wholly owned, jointly owned and leased electric generating facilities of Toledo Edison in commercial operation as of February 28, 1994 provide a net demonstrated capability of 1,832,000 kilowatts during the winter. These facilities include six generating units (925,000 kilowatts) at three fossil- fired steam electric generation stations; its share of three nuclear generating units (830,000 kilowatts) and five combustion turbine generating units (77,000 kilowatts). Operations at one fossil-fired generating unit (75,000 kilowatts) ceased in July 1993 and the unit is being preserved for future use. All of Toledo Edison's generating facilities are located in Ohio and Pennsylvania. 39 The net 60-minute peak load of Toledo Edison's service area for 1993 was 1,568,000 kilowatts and occurred on August 27. The operable capacity at the time of the 1993 peak was 1,874,000 kilowatts. Toledo Edison's 1994 service area peak load is forecasted to be 1,490,000 kilowatts, after demand-side management considerations. The operable capacity, which includes the effect of firm sales, expected to be available to serve Toledo Edison's 1994 peak is 1,652,000 kilowatts. Over the 1994-1996 period, Toledo Edison forecasts its operable capacity margins at the time of its projected peak loads to range from 0% to 10%. Toledo Edison owns the facilities located in the area it serves for trans- mitting and distributing power to all its customers. Toledo Edison has interconnections with Ohio Edison, Ohio Power and Detroit Edison. The in- terconnection with Ohio Edison provides for the interchange of electric power with the other CAPCO Group companies and for transmission of power from the tenant-in-common owned or leased CAPCO Group generating units as well as for the interchange of power with Cleveland Electric. In addition, these inter- connections provide the means for the interchange of electric power with other utilities. Toledo Edison has interconnections with each of the municipal systems operating within its service area. TITLE TO PROPERTY The generating plants and other principal facilities of the Operating Companies are located on land owned in fee by them, except as follows: (1) Cleveland Electric and Toledo Edison lease from others for a term of about 29-1/2 years starting on October 1, 1987 undivided 6.5%, 45.9% and 44.38% tenant-in-common interests in Units 1, 2 and 3, respectively, of the Mansfield Plant located in Shippingport, Pennsylvania. Cleveland Electric and Toledo Edison lease from others for a term of about 29-1/2 years starting on October 1, 1987 an 18.26% undivided tenant-in-common interest in Beaver Valley Unit 2 located in Shippingport, Pennsylvania. Cleveland Electric and Toledo Edison own another 24.47% interest and 1.65% interest, respectively, in Beaver Valley Unit 2 as a tenant-in- common. Cleveland Electric and Toledo Edison continue to own as a tenant-in-common the land upon which the Mansfield Plant and Beaver Valley Unit 2 are located, but have leased to others certain portions of that land relating to the above-mentioned generating unit leases. (2) Most of the facilities of Cleveland Electric's Lake Shore Plant are situated on artificially filled land, extending beyond the natural shore- line of Lake Erie as it existed in 1910. As of December 31, 1993, the cost of Cleveland Electric's facilities, other than water intake and discharge facilities, located on such artificially filled land aggregated approximately $112,026,000. Title to land under the water of Lake Erie within the territorial limits of Ohio (including artificially filled land) is in the State of Ohio in trust for the people of the State for the public uses to which it may be adapted, subject to the powers of the 40 United States, the public rights of navigation, water commerce and fishery and the rights of upland owners to wharf out or fill to make use of the water. The State is required by statute, after appropriate pro- ceedings, to grant a lease to an upland owner, such as Cleveland Elec- tric, which erected and maintained facilities on such filled land prior to October 13, 1955. Cleveland Electric does not have such a lease from the State with respect to the artificially filled land on which its Lake Shore Plant facilities are located, but Cleveland Electric's position, on advice of counsel for Cleveland Electric, is that its facilities and occupancy may not be disturbed because they do not interfere with the free flow of commerce in navigable channels and constitute (at least in part) and are on land filled pursuant to the exercise by it of its property rights as owner of the land above the shoreline adjacent to the filled land. Cleveland Electric holds permits, under Federal statutes relating to navigation, to occupy such artificially filled land. (3) The facilities of Cleveland Electric's Seneca Plant in Warren County, Pennsylvania, are located on land owned by the United States and occupied by Cleveland Electric and Penelec pursuant to a license issued by the FERC for a 50-year period starting December 1, 1965 for the construction, operation and maintenance of a pumped-storage hydroelectric plant. (4) The water intake and discharge facilities at the electric generating plants of Cleveland Electric and Toledo Edison located along Lake Erie, the Maumee River and the Ohio River are extended into the lake and rivers under their property rights as owners of the land above the water line and pursuant to permits under Federal statutes relating to navigation. (5) The transmission systems of the Operating Companies are located on land, easements or rights-of-way owned by them. Their distribution systems also are located, in part, on interests in land owned by them, but, for the most part, their distribution systems are located on lands owned by others and on streets and highways. In most cases, permission has been obtained from the apparent owner of the property or, if the distribution system is located on streets and highways, from the apparent owner of the abutting property. Their electric underground transmission and distri- bution systems are located, for the most part, in public streets. The Pennsylvania portions of the main transmission lines from the Seneca Plant, the Mansfield Plant and Beaver Valley Unit 2 are not owned by Cleveland Electric or Toledo Edison. All Cleveland Electric and Toledo Edison properties, with certain exceptions, are subject to the lien of their respective mortgages. The fee titles which Cleveland Electric and Toledo Edison acquire as tenant- in-common owners, and the leasehold interests they have as joint lessees, of certain generating units do not include the right to require a partition or sale for division of proceeds of the units without the concurrence of all the other owners and their respective mortgage trustees and the trustees under Cleveland Electric's and Toledo Edison's mortgages. 41 Item 3. Legal Proceedings Regulatory Proceedings and Suits Contesting Sulfur Dioxide Emission Limitations and Related Regulations Applicable to the Operating Companies. See "Item 1. Business--Environmental Regulation--Air Quality Control". Westinghouse Lawsuit. In April 1991, the CAPCO Group companies filed a lawsuit against Westinghouse in the United States District Court for the Western District of Pennsylvania. The suit alleges that six steam generators supplied by Westinghouse for Beaver Valley Power Station Units 1 and 2 contain serious defects, particularly defects causing tube corrosion and cracking. Steam generator maintenance costs have increased due to these defects and will likely continue to increase. The condition of the steam generators is being monitored closely. If the corrosion and cracking continue, replacement of the steam generators could be required earlier than their 40-year design life. The suit seeks monetary and corrective relief. General Electric Lawsuit. On February 2, 1994, the CAPCO Group companies announced that a settlement had been reached with General Electric regarding the lawsuit filed by the CAPCO Group companies against General Electric in August 1991. In that suit which was filed in the United States District Court in Cleveland, the CAPCO Group companies as joint owners of the Perry Plant alleged that General Electric had provided defective design information relating to the containment vessels for Perry Units 1 and 2. The CAPCO Group companies also alleged that the required corrective actions caused extensive delays and cost increases in the construction of the Perry Plant. Under the settlement agreement, General Electric will provide the CAPCO Group companies with discounts on future purchases and cash payments. The value of the settlement depends on the volume of future purchases. Because the payments will be made over a period of years and the discounts will be offered over the life of the plant, they will not have a material impact on the financial results of Centerior, Cleveland Electric and Toledo Edison in any particular year or on their financial conditions. The terms of the settlement agreement are the subject of a confidentiality agreement. Item 4. Submission of Matters to a Vote of Security Holders CENTERIOR ENERGY, CLEVELAND ELECTRIC AND TOLEDO EDISON None. PART II 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. 42 Market Information Centerior Energy's common stock is traded on the New York, Chicago and Pacific Stock Exchanges. The quarterly high and low prices of Centerior common stock (as reported on the composite tape) in 1992 and 1993 were as follows:
1992 1993 High Low High Low 1st Quarter $20 $17-7/8 $20 $18-5/8 2nd Quarter 18-5/8 16-3/8 19-7/8 17-3/8 3rd Quarter 17-3/4 15-3/4 18-7/8 17-3/8 4th Quarter 20 17-1/8 17-7/8 12
Share Owners As of March 15, 1994, Centerior Energy had 159,506 common stock share owners of record. Dividends See Note 14 to Centerior's Financial Statements for quarterly dividend pay- ments in the last two years. See "Outlook--Common Stock Dividends" in Management's Financial Analysis contained under Item 7 of this Report for a discussion of the payment of future dividends by Centerior and the Operating Companies. At December 31, 1993, Centerior Energy had a retained earnings deficit of $523 million and capital surplus of $2 billion, resulting in an overall surplus of $1.477 billion that was available to pay dividends under Ohio law. Any current period earnings in 1994 will increase surplus under Ohio law. See Note 11(c) to Centerior's Financial Statements and Note 11(b) to the Operating Companies' Financial Statements for discussions of dividend restrictions affecting Cleveland Electric and Toledo Edison. Dividends paid in 1993 on each of the Operating Companies' outstanding series of preferred stock were fully taxable. The Operating Companies believe that all or a portion of their preferred stock dividends paid in 1994 will be a return of capital because they intend to take a deduction for the abandonment of Perry Unit 2. Item 6. Selected Financial Data CENTERIOR ENERGY The information required by this Item is contained on Pages F-23 and F-24 attached hereto. 43 CLEVELAND ELECTRIC The information required by this Item is contained on Pages F-46 and F-47 attached hereto. TOLEDO EDISON The information required by this Item is contained on Pages F-68 and F-69 attached hereto. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations CENTERIOR ENERGY The information required by this Item is contained on Pages F-3 through F-6 attached hereto. CLEVELAND ELECTRIC The information required by this Item is contained on Pages F-26 through F-29 attached hereto. TOLEDO EDISON The information required by this Item is contained on Pages F-49 through F-52 attached hereto. Item 8. Financial Statements and Supplementary Data CENTERIOR ENERGY The information required by this Item is contained on Pages F-2 and F-7 through F-22 attached hereto. CLEVELAND ELECTRIC The information required by this Item is contained on Pages F-25 and F-30 through F-45 attached hereto. TOLEDO EDISON The information required by this Item is contained on Pages F-48 and F-53 through F-67 attached hereto. Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure CENTERIOR ENERGY, CLEVELAND ELECTRIC AND TOLEDO EDISON None. 44 PART III Item 10. Directors and Executive Officers of the Registrants CENTERIOR ENERGY The information required by this Item for Centerior regarding directors is incorporated herein by reference to Pages 4 through 8 of Centerior's definitive proxy statement dated March 23, 1994. Reference is also made to "Executive Officers of the Registrants and the Service Company" in Part I of this Report for information regarding the executive officers of Centerior Energy. CLEVELAND ELECTRIC Set forth below are the name and other directorships held, if any, of each director of Cleveland Electric. The year in which the director was first elected to Cleveland Electric's Board of Directors is set forth in paren- thesis. Reference is made to "Executive Officers of the Registrants and the Service Company" in Part I of this Report for information regarding the directors and executive officers of Cleveland Electric. The directors received no remuneration in their capacity as directors. Robert J. Farling* Mr. Farling is a director of National City Bank. (1986) Murray R. Edelman Mr. Edelman is a director of Society Bank & Trust. (1993) Fred J. Lange, Jr. (1993) *Also a director of Centerior Energy and the Service Company. TOLEDO EDISON Set forth below are the name and other directorships held, if any, of each director of Toledo Edison. The year in which the director was first elected to Toledo Edison's Board of Directors is set forth in parenthesis. Reference is made to "Executive Officers of the Registrants and the Service Company" in Part I of this Report for information regarding the directors and the executive officers of Toledo Edison. The directors received no remuneration in their capacity as directors. 45 Robert J. Farling* Mr. Farling is a director of National City Bank. (1988) Murray R. Edelman Mr. Edelman is a director of Society Bank & Trust. (1993) Fred J. Lange, Jr. (1993) *Also a director of Centerior Energy and the Service Company. Item 11. Executive Compensation CENTERIOR ENERGY, CLEVELAND ELECTRIC AND TOLEDO EDISON The information required by this Item for Centerior is incorporated herein by reference to the information concerning compensation of directors on Page 9 and the information concerning compensation of executive officers, stock option transactions, long-term incentive awards and pension benefits on Pages 17 through 25 of Centerior's definitive proxy statement dated March 23, 1994. The named executive officers for Centerior are included for Cleveland Electric and Toledo Edison regardless of whether they were officers of Cleveland Electric or Toledo Edison because they were key policymakers for the Centerior System in 1993. Item 12. Security Ownership of Certain Beneficial Owners and Management CENTERIOR ENERGY The following table sets forth the beneficial ownership of Centerior common stock by individual directors of Centerior, the named executive officers and all directors and executive officers of Centerior Energy and the Service Company as a group as of February 28, 1994: 46
Name of Beneficial Number of Common Owner Shares Owned (1) Richard P. Anderson 1,444 Albert C. Bersticker 1,000 Leigh Carter 2,257 Thomas A. Commes 5,000 Wayne R. Embry 1,000 Robert J. Farling 23,970 (2) George H. Kaull 4,842 Richard A. Miller 12,027 Frank E. Mosier 1,591 Sister Mary Marthe Reinhard, SND 500 (3) Robert C. Savage 1,000 William J. Williams 1,649 Murray R. Edelman 7,488 (2) Donald C. Shelton 1,665 Fred J. Lange, Jr. 1,270 David L. Monseau 4,164 (2) Lyman C. Phillips (4) 706 All directors and executive officers as a group 89,726 (2)
(1) Beneficially owned shares include any shares with respect to which voting or investment power is attributed to a director or executive officer because of joint or fiduciary ownership of the shares or relationship to the record owner, such as a spouse, even though the director or executive officer does not consider himself or herself the beneficial owner. On February 28, 1994, all directors and executive officers of Centerior Energy and the Service Company as a group were considered to own bene- ficially 0.1% of Centerior's common stock and none of the preferred stock of Cleveland Electric and Toledo Edison. Certain individuals disclaim beneficial ownership of some of those shares. (2) Includes the following numbers of shares which are not owned but could have been purchased within 60 days after February 28, 1994 upon exercise of options to purchase shares of Centerior common stock: Mr. Farling - 6,832; Mr. Edelman - 5,550; Mr. Monseau - 1,665; and all directors and executive officers as a group - 15,612. None of those options have been exercised as of March 28, 1994. (3) Owned by the Sisters of Notre Dame. (4) Mr. Phillips is included in the table because he would have been one of the five most highly compensated executive officers had he not retired on November 1, 1993. 47 CLEVELAND ELECTRIC Individual directors of Cleveland Electric, the named executive officers and all directors and executive officers of Cleveland Electric as a group as of March 15, 1994 beneficially owned the following number of shares of Centerior common stock on February 28, 1994:
Name of Beneficial Number of Common Owner Shares Owned (1) Robert J. Farling 23,970 (2) Murray R. Edelman 7,488 (2) Donald C. Shelton 1,665 Fred J. Lange, Jr. 1,270 David L. Monseau 4,164 (2) Lyman C. Phillips (3) 706 All directors and executive officers as a group 51,602 (2)
(1) Beneficially owned shares include any shares with respect to which voting or investment power is attributed to a director or executive officer because of joint or fiduciary ownership of the shares or relationship to the record owner, such as a spouse, even though the director or executive officer does not consider himself or herself the beneficial owner. On February 28, 1994, all directors and executive officers of Cleveland Electric as a group were considered to own beneficially 0.03% of Centerior's common stock and none of Cleveland Electric's serial preferred stock. Certain individuals disclaim beneficial ownership of some of those shares. (2) Includes the following numbers of shares which are not owned but could have been purchased within 60 days after February 28, 1994 upon exercise of options to purchase shares of Centerior common stock: Mr. Farling - 6,832; Mr. Edelman - 5,550; Mr. Monseau - 1,665; and all directors and executive officers as a group - 15,612. None of those options have been exercised as of March 28, 1994. (3) Mr. Phillips is included in the table because he would have been one of the five most highly compensated executive officers had he not retired on November 1, 1993. TOLEDO EDISON Individual directors of Toledo Edison, the named executive officers and all directors and executive officers of Toledo Edison as a group as of March 15, 1994 beneficially owned the following number of shares of Centerior common stock on February 28, 1994: 48
Name of Beneficial Number of Common Owner Shares Owned (1) Robert J. Farling 23,970 (2) Murray R. Edelman 7,488 (2) Donald C. Shelton 1,665 Fred J. Lange, Jr. 1,270 David L. Monseau 4,164 (2) Lyman C. Phillips (3) 706 All directors and executive officers as a group 44,249 (2)
(1) Beneficially owned shares include any shares with respect to which voting or investment power is attributed to a director or executive officer because of joint or fiduciary ownership of the shares or relationship to the record owner, such as a spouse, even though the director or executive officer does not consider himself or herself the beneficial owner. On February 28, 1994, all directors and executive officers of Toledo Edison as a group were considered to own beneficially 0.03% of Centerior's common stock. Certain individuals disclaim beneficial ownership of some of those shares. (2) Includes the following numbers of shares which are not owned but could have been purchased within 60 days after February 28, 1994 upon exercise of options to purchase shares of Centerior common stock: Mr. Farling - 6,832; Mr. Edelman - 5,550; Mr. Monseau - 1,665; and all other executive officers as a group - 15,612. None of those options have been exercised as of March 28, 1994. (3) Mr. Phillips is included in the table because he would have been one of the five most highly compensated executive officers had he not retired on November 1, 1993. Item 13. Certain Relationships and Related Transactions CENTERIOR ENERGY, CLEVELAND ELECTRIC AND TOLEDO EDISON None. PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) Documents Filed as a Part of the Report 1. Financial Statements: Financial Statements for Centerior Energy, Cleveland Electric and Toledo Edison are listed in the Index to Selected Financial Data; Management's Discussion and Analysis of Financial Condition and Re- sults of Operations; and Financial Statements. See Page F-1. 49 2. Financial Statement Schedules: Financial Statement Schedules for Centerior Energy, Cleveland Electric and Toledo Edison are listed in the Index to Schedules. See Page S-1. 3. Combined Pro Forma Condensed Financial Statements (Unaudited): Combined Pro Forma Condensed Financial Statements (unaudited) for Cleveland Electric and Toledo Edison related to their pending merger. See Pages P-1 to P-4. 4. Exhibits: Exhibits for Centerior Energy, Cleveland Electric and Toledo Edison are listed in the Exhibit Index. See Page E-1. (b) Reports on Form 8-K During the quarter ended December 31, 1993, Centerior Energy, Cleveland Electric and Toledo Edison did not file any Current Reports on Form 8-K. 50 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. CENTERIOR ENERGY CORPORATION Registrant March 30, 1994 By *ROBERT J FARLING, Chairman of the Board, President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this re- port has been signed below by the following persons on behalf of the regi- strant and in the capacities and on the date indicated:
Signature Title Date Principal Executive Officer: ) *ROBERT J. FARLING Chairman of the Board, ) President and Chief ) Executive Officer ) Principal Financial Officer: ) *GARY R. LEIDICH Vice President and ) Chief Financial ) Officer ) Principal Accounting Officer: *PAUL G. BUSBY Controller ) Directors: ) *RICHARD P. ANDERSON Director ) *ALBERT C. BERSTICKER Director ) *LEIGH CARTER Director ) *THOMAS A. COMMES Director ) March 30, 1994 *WAYNE R. EMBRY Director ) *ROBERT J. FARLING Director ) *GEORGE H. KAULL Director ) *RICHARD A. MILLER Director ) *FRANK E. MOSIER Director ) *SR. MARY MARTHE REINHARD, SND Director ) *ROBERT C. SAVAGE Director ) *WILLIAM J. WILLIAMS Director )
*By J. T. PERCIO J. T. Percio, Attorney-in-Fact 51 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. THE CLEVELAND ELECTRIC ILLUMINATING COMPANY Registrant March 30, 1994 By *ROBERT J. FARLING, Chairman of the Board and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this re- port has been signed below by the following persons on behalf of the regi- strant and in the capacities and on the date indicated:
Signature Title Date Principal Executive Officer: ) *ROBERT J. FARLING Chairman of the Board ) and Chief Executive ) Officer ) Principal Financial Officer: ) *GARY R. LEIDICH Vice President and ) Chief Financial ) March 30, 1994 Officer ) Principal Accounting Officer: ) *PAUL G. BUSBY Controller ) Directors: ) *ROBERT J. FARLING Director ) *MURRAY R. EDELMAN Director ) *FRED J. LANGE, JR. Director )
*By J. T. PERCIO J. T. Percio, Attorney-in-Fact 52 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. THE TOLEDO EDISON COMPANY Registrant March 30, 1994 By *ROBERT J. FARLING, Chairman of the Board and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this re- port has been signed below by the following persons on behalf of the regi- strant and in the capacities and on the date indicated:
Signature Title Date Principal Executive Officer: ) *ROBERT J. FARLING Chairman of the Board ) and Chief Executive ) Officer ) Principal Financial Officer: ) *GARY R. LEIDICH Vice President and ) Chief Financial ) Officer ) Principal Accounting Officer: ) March 30, 1994 *PAUL G. BUSBY Controller ) Directors: ) *ROBERT J. FARLING Director ) *MURRAY R. EDELMAN Director ) *FRED J. LANGE, JR. Director )
*By J. T. PERCIO J. T. Percio, Attorney-in-Fact 53 INDEX TO SELECTED FINANCIAL DATA; MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS; AND FINANCIAL STATEMENTS
Page Centerior Energy Corporation and Subsidiaries: Report of Independent Public Accountants . . . . . . . . . . . . . F-2 Management's Financial Analysis . . . . . . . . . . . . . . . . . F-3 Income Statement for the Years Ended December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-7 Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-7 Balance Sheet as of December 31, 1993 and 1992 . . . . . . . . . . F-8 Cash Flows for the Years Ended December 31, 1993, 1992 and 1991 . F-10 Statement of Preferred Stock at December 31, 1993 and 1992 . . . . F-11 Notes to the Financial Statements . . . . . . . . . . . . . . . . F-12 Financial and Statistical Review . . . . . . . . . . . . . . . . . F-23 The Cleveland Electric Illuminating Company and Subsidiaries: Report of Independent Public Accountants . . . . . . . . . . . . . F-25 Management's Financial Analysis . . . . . . . . . . . . . . . . . F-26 Income Statement for the Years Ended December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-30 Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-30 Cash Flows for the Years Ended December 31, 1993, 1992 and 1991 . F-31 Balance Sheet as of December 31, 1993 and 1992 . . . . . . . . . . F-32 Statement of Preferred Stock at December 31, 1993 and 1992 . . . . F-34 Notes to the Financial Statements . . . . . . . . . . . . . . . . F-35 Financial and Statistical Review . . . . . . . . . . . . . . . . . F-46 The Toledo Edison Company: Report of Independent Public Accountants . . . . . . . . . . . . . F-48 Management's Financial Analysis . . . . . . . . . . . . . . . . . F-49 Income Statement for the Years Ended December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-53 Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-53 Cash Flows for the Years Ended December 31, 1993, 1992 and 1991 . F-54 Balance Sheet as of December 31, 1993 and 1992 . . . . . . . . . . F-55 Statement of Preferred Stock at December 31, 1993 and 1992 . . . . F-57 Notes to the Financial Statements . . . . . . . . . . . . . . . . F-58 Financial and Statistical Review . . . . . . . . . . . . . . . . . F-68
F-1 54 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS - -------------------------------------------------------------------------------- To the Share Owners and Board of Directors of [Logo] Centerior Energy Corporation: We have audited the accompanying consolidated balance sheet and consolidated statement of preferred stock of Centerior Energy Corporation (an Ohio corporation) and subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1993. These financial statements and the schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Centerior Energy Corporation and subsidiaries as of December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. As discussed further in Notes 1 and 9, changes were made in the methods of accounting for nuclear plant depreciation in 1991 and for postretirement benefits other than pensions in 1993. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules of Centerior Energy Corporation and subsidiaries listed in the Index to Schedules are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN & CO. Cleveland, Ohio February 14, 1994 (Centerior Energy) F-2 (Centerior Energy) 55 MANAGEMENT'S FINANCIAL ANALYSIS - -------------------------------------------------------------------------------- Results of Operations 1993 VS. 1992 Factors contributing to the 1.5% increase in 1993 operating revenues are as follows:
Millions Increase (Decrease) in Operating Revenues of Dollars - ------------------------------------------------ ----------- Sales Volume and Mix $ 65 Base Rates and Miscellaneous (18) Fuel Cost Recovery Revenues (11) ----- Total $ 36 ----- -----
The net revenue increase resulted primarily from the different weather conditions and the changes in the composition of the sales mix among customer categories. Weather accounted for approximately $53 million of the higher 1993 revenues. Hot summer weather in 1993 boosted residential, commercial and wholesale kilowatt-hour sales. In contrast, the 1992 summer was the coolest in 56 years in Northern Ohio. Residential and commercial sales also increased as a result of colder late-winter temperatures in 1993 which increased electric heating-related demand. As a result, total sales increased 3.1% in 1993. Residential and commercial sales increased 4.6% and 3.1%, respectively. Industrial sales increased 1.2%. Increased sales to large automotive manufacturers, petroleum refiners and the broad-based, smaller industrial group were partially offset by lower sales to large steel industry customers. Other sales increased 5.9% because of increased sales to wholesale customers. Base rates and miscellaneous revenues decreased in 1993 primarily from lower revenues under contracts having reduced rates with certain large customers and a declining rate structure tied to usage. The contracts have been negotiated to meet competition and encourage economic growth. The net decrease in 1993 fuel cost recovery revenues resulted from changes in the fuel cost factors. The weighted average of these factors increased slightly for The Toledo Edison Company (Toledo Edison) but decreased 5% for The Cleveland Electric Illuminating Company (Cleveland Electric). Operating expenses increased 13.7% in 1993. The increase in total operation and maintenance expenses resulted from the $218 million of net benefit expenses related to an early retirement program, called the Voluntary Transition Program (VTP), other charges totaling $54 million and an increase in other operation and maintenance expenses. Other charges recorded at year-end 1993 related to a performance improvement plan for Perry Nuclear Power Plant Unit 1 (Perry Unit 1), postemployment benefits and other expense accruals. The increase in other operation and maintenance expenses resulted from higher environmental expenses, power restoration and repair expenses following a July 1993 storm in the Cleveland area, and an increase in other postretirement benefit expenses. See Note 9 for information on retirement and postemployment benefits. Deferred operating expenses decreased because of the write-off of the phase-in deferred operating expenses in 1993 as discussed in Note 7. Federal income taxes decreased as a result of lower pretax operating income. As discussed in Note 4(b), $583 million of our Perry Nuclear Power Plant Unit 2 (Perry Unit 2) investment was written off in 1993. Credits for carrying charges recorded in nonoperating income decreased because of the write-off of the phase-in deferred carrying charges in 1993 as discussed in Note 7. The federal income tax credit for nonoperating income in 1993 resulted from the write-offs. 1992 VS. 1991 Factors contributing to the 4.8% decrease in 1992 operating revenues are as follows:
Millions Decrease in Operating Revenues of Dollars - ------------------------------------------------ ----------- Sales Volume and Mix $ 79 Base Rates and Miscellaneous 32 Fuel Cost Recovery Revenues 11 ----- Total $ 122 ----- -----
The revenue decreases resulted primarily from the different weather conditions and the changes in the composition of the sales mix among customer categories. Weather accounted for approximately $77 million of the lower 1992 revenues. Winter and spring in 1992 were milder than in 1991. In addition, the cooler summer in 1992 contrasted with the summer of 1991 which was much hotter than normal. As a result, total kilowatt-hour sales decreased 1.1% in 1992. Residential and commercial sales decreased 4.5% and 1.3%, respectively, as moderate temperatures in 1992 reduced electric heating and cooling demands. Industrial sales were virtually the same as in 1991 as sales increases to steel producers and auto manufacturers of 10.9% and 2.7%, respectively, offset a decline in sales to other industrial customers. Other sales increased 2.3% because of increased sales to wholesale customers. Operating revenues in 1991 included the recognition by Toledo Edison of $24 million of deferred revenues over the period of a refund to customers under a provision of its January 1989 rate order. No such revenues were reflected in 1992 as the refund period ended in December 1991. The decrease in 1992 fuel cost recovery revenues resulted from the good performance of our generating units, which in turn decreased our fuel cost factors. The weighted averages of these factors decreased approximately 3% for Cleveland Electric and Toledo Edison (Operating Companies). Operating expenses decreased 4% in 1992. Lower fuel and purchased power expense resulted from less amortization of previously deferred fuel costs than the amount amortized in 1991 and lower generation requirements stemming from less electric sales. A reduction of $17 million in other operation and maintenance expenses resulted primarily from cost-cutting measures. Federal income (Centerior Energy) F-3 (Centerior Energy) 56 taxes decreased because of the amortization of certain tax benefits under the Rate Stabilization Program discussed in Note 7 and the effects of adopting the new accounting standard for income taxes (SFAS 109) in 1992. These decreases were partially offset by higher depreciation and amortization, caused primarily by the adoption of SFAS 109, and by higher taxes, other than federal income taxes, caused by increased Ohio property and gross receipts taxes. Deferred operating expenses increased as a result of the deferrals under the Rate Stabilization Program. The federal income tax provision for nonoperating income decreased because of lower carrying charge credits and a greater tax allocation of interest charges to nonoperating activities. Credits for carrying charges recorded in nonoperating income decreased primarily because of lower phase-in carrying charge credits. Interest charges decreased as a result of debt refinancings at lower interest rates and lower short-term borrowing requirements. Outlook RECENT ACTIONS In January 1994, we announced a comprehensive strategic action plan to strengthen our financial and competitive position. The plan established specific objectives and was designed to guide us through the year 2001. While the plan has a long-term focus, it also required us to take some very difficult, but necessary, financial actions at that time. We reduced the quarterly common stock dividend from $.40 per share to $.20 per share effective with the dividend payable February 15, 1994. This action was taken because projected financial results did not support continuation of the dividend at its former rate. We also wrote off our investment in Perry Unit 2 and certain deferred charges related to a January 1989 rate agreement (phase-in deferrals). The aggregate after-tax effect of these write-offs was $1.023 billion which resulted in a net loss in 1993 and a retained earnings deficit. The write-offs are discussed in Notes 4(b) and 7. We also recognized other one-time charges totaling $39 million after taxes related to a performance improvement plan for Perry Unit 1, postemployment benefits and other expense accruals. Also contributing to the net loss in 1993 was a charge of $87 million after taxes representing a portion of the VTP costs. We will realize approximately $50 million of savings in annual payroll and benefit costs beginning in 1994 as a result of the VTP. STRATEGIC PLAN The objectives of our strategic plan are to maximize share owner return from corporate assets and resources, achieve profitable revenue growth, become an industry leader in customer satisfaction, build a winning team and attain increasingly competitive power supply costs. To achieve these objectives, we will continue controlling our operation and maintenance expenses and capital expenditures, reduce our outstanding debt, increase revenues by finding new uses for existing assets and resources, implement a broad range of new marketing programs, increase revenues by restructuring rates for various customers where appropriate, improve the operating performance of our plants and take other appropriate actions. COMMON STOCK DIVIDENDS The indicated quarterly common stock dividend is $.20 per share. We believe that the new level is sustainable barring unforeseen circumstances and that the new strategic plan will provide the opportunity to grow the dividend as the objectives are achieved. Nevertheless, future dividend action by our Board of Directors will continue to be decided on a quarter-to-quarter basis after the evaluation of financial results, potential earning capacity and cash flow. The lower dividend reduces our cash outflow by about $120 million annually, which we intend to use to repay debt more quickly than would otherwise be the case. This will help improve our capitalization structure and interest coverage ratios, both of which are key measures considered by securities rating agencies in determining credit ratings. Improved credit ratings and less outstanding debt, in turn, will lower our interest costs. COMPETITION Our electric rates are among the highest in our region because we are recovering the substantial investment in our nuclear construction program. Accordingly, some of our customers continue to seek less costly alternatives, including switching to or working to create a municipal electric system. There are a number of rural and municipal systems in our service area. In addition, we face threats of other municipalities in our service area establishing new systems and the expansion of an existing system. We have entered into agreements with some of the communities which considered establishing systems. Accordingly, they will not proceed with such development at this time in return for rate concessions and/or economic development funds. Others have determined that developing a system was not feasible. Cleveland Public Power continues to expand its operations into areas we have served exclusively. We have been successful in retaining most of the large industrial and commercial customers in those areas by providing economic incentive packages in exchange for sole-supplier contracts. We also have similar contracts with customers in other areas. Most of these contracts have remaining terms of one to five years. We will continue to address municipal system threats through aggressive marketing programs and emphasizing to our customers the value of our service and the risks of a municipal system. (Centerior Energy) F-4 (Centerior Energy) 57 The Energy Policy Act of 1992 (Energy Act) will provide additional competition in the electric utility industry by requiring utilities to wheel to municipal systems in their service areas electricity from other utilities. This provision of the Energy Act should not significantly increase the competitive threat to us since the operating licenses for our nuclear units have required us to wheel to municipal systems in our service area since 1977. The Energy Act also created a class of exempt wholesale generators which may increase competition in the wholesale power market. A further risk is the possibility that the government could mandate that utilities deliver power from another utility or generation source to their retail customers. RATE MATTERS Our Rate Stabilization Program remains in effect. Under this program, we agreed to freeze base rates until 1996 and limit rate increases through 1998. In exchange, we are permitted to defer through 1995 and subsequently recover certain costs not currently recovered in rates and to accelerate the amortization of certain benefits. The amortization and recovery of the deferrals will begin with future rate recognition and will continue over the average life of the related assets, or approximately 30 years. The continued use of these regulatory accounting measures will be dependent upon our continuing assessment and conclusion that there will be probable recovery of such deferrals in future rates. Our analysis leading to the year-end 1993 financial actions and strategic plan also included an evaluation of our regulatory accounting measures. We decided that, once the deferral of expenses and acceleration of benefits under our Rate Stabilization Program are completed in 1995, we should no longer plan to use regulatory accounting measures to the extent we have in the past. NUCLEAR OPERATIONS Our three nuclear units may be impacted by activities or events beyond our control. Operating nuclear generating units have experienced unplanned outages or extensions of scheduled outages because of equipment problems or new regulatory requirements. A major accident at a nuclear facility anywhere in the world could cause the Nuclear Regulatory Commission (NRC) to limit or prohibit the operation or licensing of any nuclear unit. If one of our nuclear units is taken out of service for an extended period of time for any reason, including an accident at such unit or any other nuclear facility, we cannot predict whether regulatory authorities would impose unfavorable rate treatment. Such treatment could include taking our affected unit out of rate base or disallowing certain construction or maintenance costs. An extended outage of one of our nuclear units coupled with unfavorable rate treatment could have a material adverse effect on our financial condition and results of operations. We externally fund the estimated costs for the future decommissioning of our nuclear units. In 1993, we increased our decommissioning expense accruals for revisions in our cost estimates. We expect the increases associated with the new estimates will be recoverable in future rates. See Note 1(e). HAZARDOUS WASTE DISPOSAL SITES The Comprehensive Environmental Response, Compensation and Liability Act of 1980 as amended (Superfund) established programs addressing the cleanup of hazardous waste disposal sites, emergency preparedness and other issues. The Operating Companies have been named as "potentially responsible parties" (PRPs) for three sites listed on the Superfund National Priorities List (Superfund List) and are aware of their potential involvement in the cleanup of several other sites not on such list. The allegations that the Operating Companies disposed of hazardous waste at these sites and the amounts involved are often unsubstantiated and subject to dispute. Superfund provides that all PRPs to a particular site can be held liable on a joint and several basis. Consequently, if the Operating Companies were held liable for 100% of the cleanup costs of all of the sites referred to above, the cost could be as high as $400 million. However, we believe that the actual cleanup costs will be substantially lower than $400 million, that the Operating Companies' share of any cleanup costs will be substantially less than 100% and that most of the other PRPs are financially able to contribute their share. The Operating Companies have accrued a liability totaling $19 million at December 31, 1993 based on estimates of the costs of cleanup and their proportionate responsibility for such costs. We believe that the ultimate outcome of these matters will not have a material adverse effect on our financial condition or results of operations. 1993 TAX ACT The Revenue Reconciliation Act of 1993 (1993 Tax Act), which was enacted in August 1993, provided for a 35% income tax rate in 1993. The 1993 Tax Act did not materially impact the results of operations for 1993, but did affect certain Balance Sheet accounts as discussed in Note 8. The 1993 Tax Act is not expected to materially impact future results of operations or cash flow. INFLATION Although the rate of inflation has eased in recent years, we are still affected by even modest inflation which causes increases in the unit cost of labor, materials and services. Capital Resources and Liquidity 1991-1993 CASH REQUIREMENTS We need cash for normal corporate operations, the mandatory retirement of securities and an ongoing pro- (Centerior Energy) F-5 (Centerior Energy) 58 gram of constructing new facilities and modifying existing facilities. The construction program is needed to meet anticipated demand for electric service, comply with governmental regulations and protect the environment. Over the three-year period of 1991-1993, these construction and mandatory retirement needs totaled approximately $1.4 billion. In addition, we exercised various options to redeem and purchase approximately $900 million of our securities. We raised $2.2 billion through security issues and term bank loans during the 1991-1993 period as shown in the Cash Flows statement. During the three-year period, the Operating Companies also utilized their short-term borrowing arrangements to help meet their cash needs. Although the write-offs of Perry Unit 2 and the phase-in deferrals in 1993 negatively affected our earnings, they did not adversely affect our current cash flow. 1994 AND BEYOND CASH REQUIREMENTS Estimated cash requirements for 1994-1998 for Cleveland Electric and Toledo Edison, respectively, are $791 million and $249 million for their construction programs and $715 million and $324 million for the mandatory redemption of debt and preferred stock. Cleveland Electric and Toledo Edison expect to finance internally all of their 1994 cash requirements of approximately $239 million and $109 million, respectively. About 15-20% of the Operating Companies' 1995-1998 requirements are expected to be financed externally. If economical, additional securities may be redeemed under optional redemption provisions. Our capital requirements are dependent upon our implementation strategy to achieve compliance with the Clean Air Act Amendments of 1990 (Clean Air Act). Cash expenditures for our plan are estimated to be approximately $128 million over the 1994-1998 period. See Note 4(a). LIQUIDITY Additional first mortgage bonds may be issued by the Operating Companies under their respective mortgages on the basis of property additions, cash or refundable first mortgage bonds. Under their respective mortgages, each Operating Company may issue first mortgage bonds on the basis of property additions and, under certain circumstances, refundable bonds only if the applicable interest coverage test is met. At December 31, 1993, Cleveland Electric and Toledo Edison would have been permitted to issue approximately $78 million and $323 million of additional first mortgage bonds, respectively. After the fourth quarter of 1994, Cleveland Electric's ability to issue first mortgage bonds is expected to increase substantially when its interest coverage ratio will no longer be affected by the write-offs recorded at December 31, 1993. As discussed in Note 11(e), certain unsecured debt agreements contain covenants relating to capitalization, fixed charge coverage ratios and secured financings. The write-offs recorded at December 31, 1993 caused Centerior Energy Corporation (Centerior Energy) and the Operating Companies to violate certain of those covenants. The affected creditors have waived those violations in exchange for our commitment to provide them with a second mortgage security interest on our property and other considerations. We expect to complete this process in the second quarter of 1994. We will provide the same security interest to certain other creditors because their agreements require equal treatment. We expect to provide second mortgage collateral for $219 million of unsecured debt, $228 million of bank letters of credit and a $205 million revolving credit facility. For the next five years, the Operating Companies do not expect to raise funds through the sale of debt junior to first mortgage bonds. However, if necessary or desirable, the Operating Companies believe that they could raise funds through the sale of unsecured debt or debt secured by the second mortgage referred to above. The Operating Companies also are able to raise funds through the sale of preference stock and, in the case of Cleveland Electric, preferred stock. Toledo Edison will be unable to issue preferred stock until it can meet the interest and preferred dividend coverage test in its articles of incorporation. Centerior Energy will continue to raise funds through the sale of common stock. The Operating Companies currently cannot sell commercial paper because of their low commercial paper ratings by Standard & Poor's Corporation (S&P) and Moody's Investors Service, Inc. (Moody's) of "B" and "Not Prime", respectively. We have a $205 million revolving credit facility which will run through mid-1996. However, we currently cannot draw on this facility because the write-offs taken at year-end 1993 caused us to fail to meet certain capitalization and fixed charge coverage covenants. We expect to have this facility available to us again after it is amended in the second quarter of 1994 to provide the participating creditors with a second mortgage security interest. These financing resources are expected to be sufficient for the Operating Companies' needs over the next several years. The availability and cost of capital to meet our external financing needs, however, also depend upon such factors as financial market conditions and our credit ratings. Current credit ratings for both Operating Companies are as follows:
S&P Moody's ----------- ------------- First mortgage bonds BB Ba2 Unsecured notes B+ Ba3 Preferred stock B b1
These ratings reflect a downgrade in December 1993. In addition, S&P has issued a negative outlook for the Operating Companies. (Centerior Energy) F-6 (Centerior Energy) 59 INCOME STATEMENT CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES - -------------------------------------------------------------------------------
For the years ended December 31, -------------------------------- 1993 1992 1991 ------ ------ ------ (millions of dollars, except per share amounts) OPERATING REVENUES $2,474 $2,438 $2,560 ------ ------ ------ OPERATING EXPENSES Fuel and purchased power 474 473 500 Other operation and maintenance 811 784 801 Early retirement program expenses and other 272 -- -- ------ ------ ------ Total operation and maintenance 1,557 1,257 1,301 Depreciation and amortization 258 256 243 Taxes, other than federal income taxes 312 318 305 Deferred operating expenses, net 23 (52) (6) Federal income taxes 11 122 138 ------ ------ ------ 2,161 1,901 1,981 ------ ------ ------ OPERATING INCOME 313 537 579 ------ ------ ------ NONOPERATING INCOME (LOSS) Allowance for equity funds used during construction 5 2 9 Other income and deductions, net (6) 9 6 Write-off of Perry Unit 2 (583) -- -- Deferred carrying charges, net (649) 100 110 Federal income taxes -- credit (expense) 398 (7) (30) ------ ------ ------ (835) 104 95 ------ ------ ------ INCOME (LOSS) BEFORE INTEREST CHARGES AND PREFERRED DIVIDENDS (522) 641 674 ------ ------ ------ INTEREST CHARGES AND PREFERRED DIVIDENDS Debt interest 359 365 381 Allowance for borrowed funds used during construction (5) (1) (5) Preferred dividend requirements of subsidiaries 67 65 61 ------ ------ ------ 421 429 437 ------ ------ ------ NET INCOME (LOSS) $ (943) $ 212 $ 237 ------ ------ ------ ------ ------ ------ AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (MILLIONS) 144.9 141.7 139.1 ------ ------ ------ ------ ------ ------ EARNINGS (LOSS) PER COMMON SHARE $(6.51) $ 1.50 $ 1.71 ------ ------ ------ ------ ------ ------ DIVIDENDS DECLARED PER COMMON SHARE $ 1.60 $ 1.60 $ 1.60 ------ ------ ------ ------ ------ ------
RETAINED EARNINGS - ----------------------------------------------------------------------
For the years ended December 31, -------------------------------- 1993 1992 1991 ------- ------ ------ (millions of dollars) RETAINED EARNINGS AT BEGINNING OF YEAR $ 652 $ 669 $ 655 ------- ------ ------ ADDITIONS Net income (loss) (943) 212 237 DEDUCTIONS Common stock dividends (231) (226) (222) Other, primarily preferred stock redemption expenses of subsidiaries (1) (3) (1) ------- ------ ------ Net Increase (Decrease) (1,175) (17) 14 ------- ------ ------ RETAINED EARNINGS (DEFICIT) AT END OF YEAR $ (523) $ 652 $ 669 ------- ------ ------ ------- ------ ------
The accompanying notes are an integral part of these statements. (Centerior Energy) F-7 (Centerior Energy) 60 CASH FLOWS CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES - ----------------------------------------------------------------------
For the years ended December 31, ---------------------------- 1993 1992 1991 ------ ------ ------ (millions of dollars) CASH FLOWS FROM OPERATING ACTIVITIES (1) Net Income (Loss) $ (943) $ 212 $ 237 ------ ------ ------ Adjustments to Reconcile Net Income (Loss) to Cash from Operating Activities: Depreciation and amortization 258 256 243 Deferred federal income taxes (452) 95 85 Investment tax credits, net -- (14) 43 Deferred and unbilled revenues (10) (6) (51) Deferred fuel 5 1 18 Deferred carrying charges, net 649 (100) (110) Leased nuclear fuel amortization 86 126 123 Deferred operating expenses, net 23 (52) (6) Allowance for equity funds used during construction (5) (2) (9) Noncash early retirement program expenses, net 208 -- -- Write-off of Perry Unit 2 583 -- -- Changes in amounts due from customers and others, net 1 7 14 Changes in inventories 26 (10) (22) Changes in accounts payable 45 (5) (49) Changes in working capital affecting operations 25 8 19 Other noncash items 18 3 1 ------ ------ ------ Total Adjustments 1,460 307 299 ------ ------ ------ Net Cash from Operating Activities 517 519 536 ------ ------ ------ CASH FLOWS FROM FINANCING ACTIVITIES (2) Bank loans, commercial paper and other short-term debt (50) 50 (110) Debt issues: First mortgage bonds 300 600 -- Secured medium-term notes 128 138 285 Term bank loans and other long-term debt 40 135 108 Preferred stock issues 100 74 125 Common stock issues 71 53 32 Reacquired common stock 1 (3) -- Maturities, redemptions and sinking funds (434) (1,013) (312) Nuclear fuel lease obligations (106) (117) (116) Common stock dividends paid (231) (226) (222) Premiums, discounts and expenses (13) (14) (7) ------ ------ ------ Net Cash from Financing Activities (194) (323) (217) ------ ------ ------ CASH FLOWS FROM INVESTING ACTIVITIES (2) Cash applied to construction (209) (200) (189) Interest capitalized as allowance for borrowed funds used during construction (5) (1) (5) Sale and leaseback restructuring fees -- (43) -- Other cash received (applied) 23 (36) (1) ------ ------ ------ Net Cash from Investing Activities (191) (280) (195) ------ ------ ------ NET CHANGE IN CASH AND TEMPORARY CASH INVESTMENTS 132 (84) 124 ------ ------ ------ CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF YEAR 93 177 53 ------ ------ ------ CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR $ 225 $ 93 $ 177 ------ ------ ------ ------ ------ ------
(1) Interest paid (net of amounts capitalized) was $295 million, $299 million and $339 million in 1993, 1992 and 1991, respectively. Income taxes paid were $50 million, $32 million and $57 million in 1993, 1992 and 1991, respectively. (2) Increases in Nuclear Fuel and Nuclear Fuel Lease Obligations in the Balance Sheet resulting from the noncash capitalizations under nuclear fuel agreements are excluded from this statement. The accompanying notes are an integral part of this statement. (Centerior Energy) F-8 (Centerior Energy) 61 BALANCE SHEET - ----------------------------------------------------------------------
December 31, ------------------ 1993 1992 ------- ------- (millions of dollars) ASSETS PROPERTY, PLANT AND EQUIPMENT Utility plant in service $ 9,571 $ 9,449 Less: accumulated depreciation and amortization 2,677 2,488 ------- ------- 6,894 6,961 Construction work in progress 181 167 Perry Unit 2 -- 614 ------- ------- 7,075 7,742 Nuclear fuel, net of amortization 344 385 Other property, less accumulated depreciation 41 39 ------- ------- 7,460 8,166 ------- ------- CURRENT ASSETS Cash and temporary cash investments 225 93 Amounts due from customers and others, net 221 222 Unbilled revenues 124 114 Materials and supplies, at average cost 136 129 Fossil fuel inventory, at average cost 32 65 Taxes applicable to succeeding years 250 247 Other 5 7 ------- ------- 993 877 ------- ------- DEFERRED CHARGES AND OTHER ASSETS Amounts due from customers for future federal income taxes 968 975 Unamortized loss from Beaver Valley Unit 2 sale 105 110 Unamortized loss on reacquired debt 92 101 Carrying charges and operating expenses 862 1,533 Nuclear plant decommissioning trusts 56 42 Other 174 267 ------- ------- 2,257 3,028 ------- ------- Total Assets $10,710 $12,071 ------- ------- ------- -------
The accompanying notes are an integral part of this statement. (Centerior Energy) F-9 (Centerior Energy) 62 CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES
December 31, ------------------- 1993 1992 ------- ------- (millions of dollars) CAPITALIZATION AND LIABILITIES CAPITALIZATION Common shares, without par value (stated value of $345 million and $274 million for 1993 and 1992, respectively): 180 million authorized; 147 million (excluding 2.7 million shares in Treasury) and 142.9 million (excluding 2.7 million shares in Treasury) outstanding in 1993 and 1992, respectively $ 2,308 $ 2,237 Retained earnings (deficit) (523) 652 ------- ------- Common stock equity 1,785 2,889 Preferred stock With mandatory redemption provisions 313 364 Without mandatory redemption provisions 451 354 Long-term debt 4,019 3,694 ------- ------- 6,568 7,301 ------- ------- OTHER NONCURRENT LIABILITIES Nuclear fuel lease obligations 254 303 Other 195 119 ------- ------- 449 422 ------- ------- CURRENT LIABILITIES Current portion of long-term debt and preferred stock 127 368 Current portion of nuclear fuel lease obligations 111 118 Notes payable to banks and others -- 50 Accounts payable 188 143 Accrued taxes 378 368 Accrued interest 87 84 Other 75 59 ------- ------- 966 1,190 ------- ------- DEFERRED CREDITS Unamortized investment tax credits 329 353 Accumulated deferred federal income taxes 1,579 2,035 Unamortized gain from Bruce Mansfield Plant sale 551 578 Accumulated deferred rents for Bruce Mansfield Plant and Beaver Valley Unit 2 128 116 Other 140 76 ------- ------- 2,727 3,158 ------- ------- Total Capitalization and Liabilities $10,710 $12,071 ------- ------- ------- -------
(Centerior Energy) F-10 (Centerior Energy) 63 STATEMENT OF PREFERRED STOCK CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES - ----------------------------------------------------------------------
Current December 31, 1993 Shares Call Price ------------- Outstanding Per Share 1993 1992 ----------- ---------- ---- ---- (millions of dollars) CLEVELAND ELECTRIC Without par value, 4,000,000 preferred shares authorized Subject to mandatory redemption: $7.35 Series C 150,000 $ 101.00 $ 15 $ 16 88.00 Series E 21,000 1,022.96 21 24 Adjustable Series M 200,000 100.00 20 30 9.125 Series N 600,000 103.04 59 74 91.50 Series Q 75,000 -- 75 75 88.00 Series R 50,000 -- 50 50 90.00 Series S 75,000 -- 74 74 ---- ---- 314 343 Less: Current maturities 29 29 ---- ---- 285 314 ---- ---- Not subject to mandatory redemption: $7.40 Series A 500,000 101.00 50 50 7.56 Series B 450,000 102.26 45 45 Adjustable Series L 500,000 103.00 49 49 Remarketed Series P -- -- -- 9 42.40 Series T 200,000 -- 97 -- ---- ---- 241 153 Less: Current maturities -- 9 ---- ---- 241 144 ---- ---- TOLEDO EDISON $100 par value, 3,000,000 preferred shares authorized and $25 par value, 12,000,000 preferred shares authorized Subject to mandatory redemption: $100 par $9.375 100,150 102.47 10 12 25 par 2.81 1,200,000 25.94 30 50 ---- ---- 40 62 Less: Current maturities 12 12 ---- ---- 28 50 ---- ---- Not subject to mandatory redemption: $100 par $ 4.25 160,000 104.625 16 16 4.56 50,000 101.00 5 5 4.25 100,000 102.00 10 10 8.32 100,000 102.46 10 10 7.76 150,000 102.437 15 15 7.80 150,000 101.65 15 15 10.00 190,000 101.00 19 19 25 par 2.21 1,000,000 25.25 25 25 2.365 1,400,000 27.75 35 35 Series A Adjustable 1,200,000 25.75 30 30 Series B Adjustable 1,200,000 25.75 30 30 ---- ---- 210 210 ---- ---- CENTERIOR ENERGY Without par value, 5,000,000 preferred shares authorized, none outstanding -- -- ---- ---- TOTAL PREFERRED STOCK, WITH MANDATORY REDEMPTION PROVISIONS $313 $364 ---- ---- ---- ---- TOTAL PREFERRED STOCK, WITHOUT MANDATORY REDEMPTION PROVISIONS $451 $354 ---- ---- ---- ----
The accompanying notes are an integral part of this statement. (Centerior Energy) F-11 (Centerior Energy) 64 NOTES TO THE FINANCIAL STATEMENTS - -------------------------------------------------------------------------------- (1) Summary of Significant Accounting Policies (A) GENERAL Centerior Energy is a holding company with two electric utility subsidiaries, Cleveland Electric and Toledo Edison. The consolidated financial statements also include the accounts of Centerior Energy's other wholly owned subsidiary, Centerior Service Company (Service Company), and Cleveland Electric's wholly owned subsidiaries. The Service Company provides management, financial, administrative, engineering, legal and other services at cost to Centerior Energy and the Operating Companies. The Operating Companies operate as separate companies, each serving the customers in its service area. The preferred stock, first mortgage bonds and other debt obligations of the Operating Companies are outstanding securities of the issuing utility. All significant intercompany items have been eliminated in consolidation. Centerior Energy and the Operating Companies follow the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission and adopted by The Public Utilities Commission of Ohio (PUCO). As rate-regulated utilities, the Operating Companies are subject to Statement of Financial Accounting Standards (SFAS) 71 which governs accounting for the effects of certain types of rate regulation. The Service Company follows the Uniform System of Accounts for Mutual Service Companies prescribed by the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935. The Operating Companies are members of the Central Area Power Coordination Group (CAPCO). Other members are Duquesne Light Company, Ohio Edison Company and its wholly owned subsidiary, Pennsylvania Power Company. The members have constructed and operate generation and transmission facilities for their use. (B) REVENUES Customers are billed on a monthly cycle basis for their energy consumption based on rate schedules or contracts authorized by the PUCO or on ordinances of individual municipalities. An accrual is made at the end of each month to record the estimated amount of unbilled revenues for kilowatt-hours sold in the current month but not billed by the end of that month. A fuel factor is added to the base rates for electric service. This factor is designed to recover from customers the costs of fuel and most purchased power. It is reviewed and adjusted semiannually in a PUCO proceeding. (C) FUEL EXPENSE The cost of fossil fuel is charged to fuel expense based on inventory usage. The cost of nuclear fuel, including an interest component, is charged to fuel expense based on the rate of consumption. Estimated future nuclear fuel disposal costs are being recovered through the base rates. The Operating Companies defer the differences between actual fuel costs and estimated fuel costs currently being recovered from customers through the fuel factor. This matches fuel expenses with fuel-related revenues. Owners of nuclear generating plants are assessed by the federal government for the cost of decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy. The assessments are based upon the amount of enrichment services used in prior years and cannot be imposed for more than 15 years. The Operating Companies have accrued the liability for their share of the total assessments. These costs have been recorded in a deferred charge account since the PUCO is allowing the Operating Companies to recover the assessments through their fuel cost factors. (D) DEFERRED CARRYING CHARGES AND OPERATING EXPENSES The PUCO authorized the Operating Companies to defer operating expenses and carrying charges for Perry Unit 1 and Beaver Valley Power Station Unit 2 (Beaver Valley Unit 2) from their respective in-service dates in 1987 through December 1988. The annual amortization and recovery of these deferrals, called pre-phase-in deferrals, are $17 million which began in January 1989 and will continue over the lives of the related property. Beginning in January 1989, the Operating Companies deferred certain operating expenses and both interest and equity carrying charges pursuant to PUCO-approved rate phase-in plans for their investments in Perry Unit 1 and Beaver Valley Unit 2. These deferrals, called phase-in deferrals, were written off at December 31, 1993. See Note 7. The Operating Companies also defer certain costs not currently recovered in rates under a Rate Stabilization Program approved by the PUCO in October 1992. See Notes 7 and 14. (Centerior Energy) F-12 (Centerior Energy) 65 (E) DEPRECIATION AND AMORTIZATION The cost of property, plant and equipment is depreciated over their estimated useful lives on a straight-line basis. The annual straight-line depreciation provision for nonnuclear property expressed as a percent of average depreciable utility plant in service was 3.5% in 1993 and 3.4% in both 1992 and 1991. Effective January 1, 1991, the Operating Companies, after obtaining PUCO approval, changed their method of accounting for nuclear plant depreciation from the units-of-production method to the straight-line method at about a 3% rate. This change decreased 1991 depreciation expense $36 million and increased 1991 net income $28 million (net of $8 million of income taxes) and earnings per share $.20 from what they otherwise would have been. The PUCO subsequently approved in 1991 a change to lower the 3% rate to 2.5% retroactive to January 1, 1991. Pursuant to a PUCO order, the Operating Companies currently use external funding for the future decommissioning of their nuclear units at the end of their licensed operating lives. The estimated costs are based on the NRC's DECON method of decommissioning (prompt decontamination). Cash contributions are made to the trust funds on a straight-line basis over the remaining licensing period for each unit. The current level of annual expense being recovered from customers based on prior estimates is approximately $8 million. However, actual decommissioning costs are expected to significantly exceed those estimates. Current site-specific estimates for the Operating Companies' share of the future decommissioning costs are $92 million in 1992 dollars for Beaver Valley Unit 2 and $223 million and $300 million in 1993 dollars for Perry Unit 1 and the Davis-Besse Nuclear Power Station (Davis-Besse), respectively. The estimates for Perry Unit 1 and Davis-Besse are preliminary and are expected to be finalized by the end of the second quarter of 1994. The Operating Companies used these estimates to increase their decommissioning expense accruals in 1993. It is expected that the increases associated with the revised cost estimates will be recoverable in future rates. In the Balance Sheet at December 31, 1993, Accumulated Depreciation and Amortization included $74 million of decommissioning costs previously expensed and the earnings on the external funding. This amount exceeds the Balance Sheet amount of the external Nuclear Plant Decommissioning Trusts because the reserve began prior to the external trust funding. (F) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment are stated at original cost less amounts ordered by the PUCO to be written off. Construction costs include related payroll taxes, pensions, fringe benefits, management and general overheads and allowance for funds used during construction (AFUDC). AFUDC represents the estimated composite debt and equity cost of funds used to finance construction. This noncash allowance is credited to income. The AFUDC rates averaged 9.9% in 1993, 10.8% in 1992 and 10.7% in 1991. Maintenance and repairs are charged to expense as incurred. The cost of replacing plant and equipment is charged to the utility plant accounts. The cost of property retired plus removal costs, after deducting any salvage value, is charged to the accumulated provision for depreciation. (G) DEFERRED GAIN AND LOSS FROM SALES OF UTILITY PLANT The sale and leaseback transactions discussed in Note 2 resulted in a net gain for the sale of the Bruce Mansfield Generating Plant (Mansfield Plant) and a net loss for the sale of Beaver Valley Unit 2. The net gain and net loss were deferred and are being amortized over the terms of leases. These amortizations and the lease expense amounts are recorded as other operation and maintenance expenses. (H) INTEREST CHARGES Debt Interest reported in the Income Statement does not include interest on obligations for nuclear fuel under construction. That interest is capitalized. See Note 6. Losses and gains realized upon the reacquisition or redemption of long-term debt are deferred, consistent with the regulatory rate treatment. Such losses and gains are either amortized over the remainder of the original life of the debt issue retired or amortized over the life of the new debt issue when the proceeds of a new issue are used for the debt redemption. The amortizations are included in debt interest expense. (Centerior Energy) F-13 (Centerior Energy) 66 (I) FEDERAL INCOME TAXES The Financial Accounting Standards Board (FASB) issued SFAS 109, a new standard for accounting for income taxes, in February 1992. We adopted the new standard in 1992. The standard amended certain provisions of SFAS 96 which we had previously adopted. Adoption of SFAS 109 in 1992 did not materially affect our results of operations, but did affect certain Balance Sheet accounts. See Note 8. The financial statements reflect the liability method of accounting for income taxes. This method requires that deferred taxes be recorded for all temporary differences between the book and tax bases of assets and liabilities. The majority of these temporary differences are attributable to property-related basis differences. Included in these basis differences is the equity component of AFUDC, which will increase future tax expense when it is recovered through rates. Since this component is not recognized for tax purposes, we must record a liability for our tax obligation. The PUCO permits recovery of such taxes from customers when they become payable. Therefore, the net amount due from customers through rates has been recorded as a deferred charge and will be recovered over the lives of the related assets. Investment tax credits are deferred and amortized over the lives of the applicable property as a reduction of depreciation expense. See Note 7 for a discussion of the amortization of certain unrestricted excess deferred taxes and unrestricted investment tax credits under the Rate Stabilization Program. (2) Utility Plant Sale and Leaseback Transactions The Operating Companies are co-lessees of 18.26% (150 megawatts) of Beaver Valley Unit 2 and 6.5% (51 megawatts), 45.9% (358 megawatts) and 44.38% (355 megawatts) of Units 1, 2 and 3 of the Mansfield Plant, respectively, all for terms of about 29 1/2 years. These leases are the result of sale and leaseback transactions completed in 1987. Under these leases, the Operating Companies are responsible for paying all taxes, insurance premiums, operation and maintenance expenses and all other similar costs for their interests in the units sold and leased back. They may incur additional costs in connection with capital improvements to the units. The Operating Companies have options to buy the interests back at the end of the leases for the fair market value at that time or to renew the leases. Additional lease provisions provide other purchase options along with conditions for mandatory termination of the leases (and possible repurchase of the leasehold interests) for events of default. These events include noncompliance with several financial covenants discussed in Note 11(e). In April 1992, nearly all of the outstanding Secured Lease Obligation Bonds (SLOBs) issued by a special purpose corporation in connection with financing the sale and leaseback of Beaver Valley Unit 2 were refinanced through a tender offer and the sale of new bonds having a lower interest rate. As part of the refinancing transaction, Toledo Edison paid $43 million as supplemental rent to fund transaction expenses and part of the tender premium. This amount has been deferred and is being amortized over the remaining lease term. The refinancing transaction reduced the annual rental expense for the Beaver Valley Unit 2 lease by $9 million. Future minimum lease payments under the operating leases at December 31, 1993 are summarized as follows:
Year Amount - ------------------------------------------------- ------------ (millions of dollars) 1994 $ 166 1995 165 1996 188 1997 165 1998 165 Later Years 3,412 ------ Total Future Minimum Lease Payments $4,261 ======
Rental expense is accrued on a straight-line basis over the terms of the leases. The amount recorded in 1993, 1992 and 1991 as annual rental expense for the Mansfield Plant leases was $115 million. The amounts recorded in 1993, 1992 and 1991 as annual rental expense for the Beaver Valley Unit 2 lease were $63 million, $66 million and $72 million, respectively. Amounts charged to expense in excess of the lease payments are classified as Accumulated Deferred Rents in the Balance Sheet. Toledo Edison is selling 150 megawatts of its Beaver Valley Unit 2 leased capacity entitlement to Cleveland Electric. We anticipate that this sale will continue indefinitely. (Centerior Energy) F-14 (Centerior Energy) 67 (3) Property Owned with Other Utilities and Investors The Operating Companies own, as tenants in common with other utilities and those investors who are owner-participants in various sale and leaseback transactions (Lessors), certain generating units as listed below. Each owner owns an undivided share in the entire unit. Each owner has the right to a percentage of the generating capability of each unit equal to its ownership share. Each utility owner is obligated to pay for only its respective share of the construction costs and operating expenses. Each Lessor has leased its capacity rights to a utility which is obligated to pay for such Lessor's share of the construction costs and operating expenses. The Operating Companies' share of the operating expenses of these generating units is included in the Income Statement. The Balance Sheet classification of Property, Plant and Equipment at December 31, 1993 includes the following facilities owned by the Operating Companies as tenants in common with other utilities and Lessors:
In- Plant Construction Service Ownership Ownership Power in Work in Accumulated Generating Unit Date Share Megawatts Source Service Progress Depreciation - ------------------------------- ------- --------- --------- -------- ------- ------------ ------------ (millions of dollars) Seneca Pumped Storage 1970 80.00% 351 Hydro $ 67 $ -- $ 22 Eastlake Unit 5 1972 68.80 411 Coal 156 2 -- Perry Unit 1 1987 51.02 609 Nuclear 2,832 11 473 Beaver Valley Unit 2 and Common Facilities (Note 2) 1987 26.12 214 Nuclear 1,480 5 255 ------- --- ----- Total $4,535 $ 18 $750 ------- --- ----- ------- --- -----
Depreciation for Eastlake Unit 5 has been accumulated with all other nonnuclear depreciable property rather than by specific units of depreciable property. (4) Construction and Contingencies (A) CONSTRUCTION PROGRAM The estimated cost of our construction program for the 1994-1998 period is $1.088 billion, including AFUDC of $48 million and excluding nuclear fuel. The Clean Air Act will require, among other things, significant reductions in the emission of sulfur dioxide in two phases over a ten-year period and nitrogen oxides by fossil-fueled generating units. Our compliance strategy provides for compliance with both phases through at least 2005 primarily through greater use of low-sulfur coal at some of our units and the banking of emission allowances. The plan will require capital expenditures over the 1994-2003 period of approximately $222 million for nitrogen oxide control equipment, emission monitoring equipment and plant modifications. In addition, higher fuel and other operation and maintenance expenses will be incurred. The anticipated rate increase associated with the capital expenditures and higher expenses would be about 1-2% in the late 1990s. Cleveland Electric may need to install sulfur emission control technology at one of its generating plants after 2005 which could require additional expenditures at that time. The PUCO has approved this plan. We also are seeking United States Environmental Protection Agency (U.S. EPA) approval of the first phase of our plan. We are continuing to monitor developments in new technologies that may be incorporated into our compliance strategy. If a different plan is required by the U.S. EPA, significantly higher capital expenditures could be required during the 1994-2003 period. We believe Ohio law permits the recovery of compliance costs from customers in rates. (B) PERRY UNIT 2 Perry Unit 2, including its share of the facilities common with Perry Unit 1, was approximately 50% complete when construction was suspended in 1985 pending consideration of various options. These options included resumption of full construction with a revised estimated cost, conversion to a nonnuclear design, sale of all or part of our ownership share, or cancellation. We wrote off our investment in Perry Unit 2 at December 31, 1993 after we determined that it would not be completed or sold. The write-off totaled $583 million ($425 million after taxes) for our 64.76% ownership share of the unit. See Note 14. (C) HAZARDOUS WASTE DISPOSAL SITES The Operating Companies are aware of their potential involvement in the cleanup of three sites listed on the Superfund List and several other waste sites not on such list. The Operating Companies have accrued a liability totaling $19 million at December 31, 1993 based on estimates of the costs of cleanup and their proportionate responsibility for such costs. We believe that the ultimate outcome of these matters will not have a material adverse effect on our financial condition or results of operations. See Management's Financial Analysis -- Outlook-Hazardous Waste Disposal Sites. (Centerior Energy) F-15 (Centerior Energy) 68 (5) Nuclear Operations and Contingencies (A) OPERATING NUCLEAR UNITS Our three nuclear units may be impacted by activities or events beyond our control. An extended outage of one of our nuclear units for any reason, coupled with any unfavorable rate treatment, could have a material adverse effect on our financial condition and results of operations. See discussion of these risks in Management's Financial Analysis -- Outlook-Nuclear Operations. (B) NUCLEAR INSURANCE The Price-Anderson Act limits the liability of the owners of a nuclear power plant to the amount provided by private insurance and an industry assessment plan. In the event of a nuclear incident at any unit in the United States resulting in losses in excess of the level of private insurance (currently $200 million), our maximum potential assessment under that plan would be $155 million (plus any inflation adjustment) per incident. The assessment is limited to $20 million per year for each nuclear incident. These assessment limits assume the other CAPCO companies contribute their proportionate share of any assessment. The CAPCO companies have insurance coverage for damage to property at the Davis-Besse, Perry and Beaver Valley sites (including leased fuel and clean-up costs). Coverage amounted to $2.75 billion for each site as of January 1, 1994. Damage to property could exceed the insurance coverage by a substantial amount. If it does, our share of such excess amount could have a material adverse effect on our financial condition and results of operations. Under these policies, we can be assessed a maximum of $25 million during a policy year if the reserves available to the insurer are inadequate to pay claims arising out of an accident at any nuclear facility covered by the insurer. We also have extra expense insurance coverage. It includes the incremental cost of any replacement power purchased (over the costs which would have been incurred had the units been operating) and other incidental expenses after the occurrence of certain types of accidents at our nuclear units. The amounts of the coverage are 100% of the estimated extra expense per week during the 52-week period starting 21 weeks after an accident and 67% of such estimate per week for the next 104 weeks. The amount and duration of extra expense could substantially exceed the insurance coverage. (6) Nuclear Fuel Nuclear fuel is financed for the Operating Companies through leases with a special-purpose corporation. The total amount of financing currently available under these lease arrangements is $382 million ($232 million from intermediate-term notes and $150 million from bank credit arrangements). Financing in an amount up to $750 million is permitted. The intermediate-term notes mature in the period 1994-1997, with $75 million maturing in September 1994. At December 31, 1993, $370 million of nuclear fuel was financed. The Operating Companies severally lease their respective portions of the nuclear fuel and are obligated to pay for the fuel as it is consumed in a reactor. The lease rates are based on various intermediate-term note rates, bank rates and commercial paper rates. The amounts financed include nuclear fuel in the Davis-Besse, Perry Unit 1 and Beaver Valley Unit 2 reactors with remaining lease payments of $110 million, $78 million and $46 million, respectively, at December 31, 1993. The nuclear fuel amounts financed and capitalized also included interest charges incurred by the lessors amounting to $14 million in 1993, $15 million in 1992 and $21 million in 1991. The estimated future lease amortization payments based on projected consumption are $111 million in 1994, $97 million in 1995, $87 million in 1996, $77 million in 1997 and $69 million in 1998. (7) Regulatory Matters Phase-in deferrals were recorded beginning in 1989 pursuant to the phase-in plans approved by the PUCO in January 1989 rate orders for the Operating Companies. The phase-in plans were designed so that the projected revenues resulting from the authorized rate increases and anticipated sales growth provided for the phase-in of certain nuclear costs over a ten-year period. The plans required the deferral of a portion of the operating expenses and both interest and equity carrying charges on the Operating Companies' deferred rate-based investments in Perry Unit 1 and Beaver Valley Unit 2 during the early years of the plans. The amortization and recovery of such deferrals were scheduled to be completed by 1998. As we developed our strategic plan, we evaluated the future recovery of our deferred charges and continued application of the regulatory accounting measures we follow pursuant to PUCO orders. We concluded that projected revenues would not provide for the recovery of the phase-in deferrals as scheduled because of economic and competitive pressures. Accordingly, we wrote off the cumulative balance of the phase-in deferrals. The total phase-in deferred operating expenses and carrying charges written off at December 31, 1993 were $172 million and $705 million, respectively (totaling $598 million after taxes). See Note 14. While recovery of our other regulatory deferrals remains probable, our current (Centerior Energy) F-16 (Centerior Energy) 69 assessment of business conditions has prompted us to change our future plans. We decided that, once the deferral of expenses and acceleration of benefits under our Rate Stabilization Program are completed in 1995, we should no longer plan to use regulatory accounting measures to the extent we have in the past. In October 1992, the PUCO approved a Rate Stabilization Program that was designed to encourage economic growth in our service area by freezing base rates until 1996 and limiting subsequent rate increases to specified annual amounts not to exceed $216 million for Cleveland Electric and $89 million for Toledo Edison over the 1996-1998 period. As part of the Rate Stabilization Program, the Operating Companies are allowed to defer and subsequently recover certain costs not currently recovered in rates and to accelerate amortization of certain benefits. Such regulatory accounting measures provide for rate stabilization by rescheduling the timing of rate recovery of certain costs and the amortization of certain benefits during the 1992-1995 period. The continued use of these regulatory accounting measures will be dependent upon our continuing assessment and conclusion that there will be probable recovery of such deferrals in future rates. The regulatory accounting measures we are eligible to record through December 31, 1995 include the deferral of post-in-service interest carrying charges, depreciation expense and property taxes on assets placed in service after February 29, 1988 and the deferral of Toledo Edison operating expenses equivalent to an accumulated excess rent reserve for Beaver Valley Unit 2 (which resulted from the April 1992 refinancing of SLOBs as discussed in Note 2). The cost deferrals recorded in 1993 and 1992 pursuant to these provisions were $95 million and $84 million, respectively. Amortization and recovery of these deferrals will occur over the average life of the related assets and the remaining lease period, or approximately 30 years, and will commence with future rate recognition. The regulatory accounting measures also provide for the accelerated amortization of certain unrestricted excess deferred tax and unrestricted investment tax credit balances and interim spent fuel storage accrual balances for Davis-Besse. The total amount of such regulatory benefits recognized in 1993 and 1992 pursuant to these provisions was $46 million and $12 million, respectively. The Rate Stabilization Program also authorized the Operating Companies to defer and subsequently recover the incremental expenses associated with the adoption of the accounting standard for postretirement benefits other than pensions (SFAS 106). In 1993, we deferred $96 million pursuant to this provision. Amortization and recovery of this deferral will commence prior to 1998 and is expected to be completed by no later than 2012. See Note 9(b). (8) Federal Income Tax Federal income tax, computed by multiplying the income before taxes and preferred dividend requirements of subsidiaries by the statutory rate (35% in 1993 and 34% in both 1992 and 1991), is reconciled to the amount of federal income tax recorded on the books as follows:
1993 1992 1991 ------- ---- ---- (millions of dollars) Book Income (Loss) Before Federal Income Tax $(1,263) $406 $466 ------- ---- ---- ------- ---- ---- Tax (Credit) on Book Income (Loss) at Statutory Rate $ (442) $138 $158 Increase (Decrease) in Tax: Write-off of Perry Unit 2 46 -- -- Write-off of phase-in deferrals 28 -- -- Depreciation (6) (9) 1 Rate Stabilization Program (30) (7) -- Other items 17 7 9 ------- ---- ---- Total Federal Income Tax Expense (Credit) $ (387) $129 $168 ------- ---- ---- ------- ---- ----
Federal income tax expense is recorded in the Income Statement as follows:
1993 1992 1991 ----- ----- ----- (millions of dollars) Operating Expenses: Current Tax Provision $ 99 $ 71 $ 88 Changes in Accumulated Deferred Federal Income Tax: Write-off of deferred operating expenses (39) -- -- Accelerated depreciation and amortization 95 39 17 Alternative minimum tax credit (57) (31) (46) Retirement and postemployment benefits (43) -- -- Sale and leaseback transactions and amortization 9 8 4 Taxes, other than federal income taxes (25) 19 -- Rate Stabilization Program (9) 4 -- Reacquired debt costs (3) 10 22 Deferred fuel costs (2) (1) (9) Other items (14) 3 23 Investment Tax Credits -- -- 39 ----- ----- ----- Total Charged to Operating Expenses 11 122 138 ----- ----- ----- Nonoperating Income: Current Tax Provision (34) (38) (46) Changes in Accumulated Deferred Federal Income Tax: Write-off of deferred carrying charges (240) -- -- Write-off of Perry Unit 2 (158) -- -- Disallowed nuclear costs 20 14 -- Rate Stabilization Program 11 11 -- AFUDC and carrying charges 12 24 41 Net operating loss carryforward (7) -- 35 Other items (2) (4) -- ----- ----- ----- Total Expense (Credit) to Nonoperating Income (398) 7 30 ----- ----- ----- Total Federal Income Tax Expense (Credit) $(387) $ 129 $ 168 ----- ----- ----- ----- ----- -----
(Centerior Energy) F-17 (Centerior Energy) 70 In August 1993, the 1993 Tax Act was enacted. Retroactive to January 1, 1993, the top marginal corporate income tax rate increased to 35%. The change in tax rate increased Accumulated Deferred Federal Income Taxes for the future tax obligation by approximately $90 million. Since the PUCO has historically permitted recovery of such taxes from customers when they become payable, the deferred charge, Amounts Due from Customers for Future Federal Income Taxes, also was increased by $90 million. The 1993 Tax Act is not expected to materially impact future results of operations or cash flow. Under SFAS 109, temporary differences and carryforwards resulted in deferred tax assets of $619 million and deferred tax liabilities of $2.198 billion at December 31, 1993 and deferred tax assets of $563 million and deferred tax liabilities of $2.598 billion at December 31, 1992. These are summarized as follows:
December 31, --------------- 1993 1992 ------ ------ (millions of dollars) Property, plant and equipment $1,845 $2,125 Deferred carrying charges and operating 206 368 expenses Net operating loss carryforwards (108) (137) Investment tax credits (183) (190) Other (181) (131) ------ ------ Net deferred tax liability $1,579 $2,035 ------ ------ ------ ------
For tax purposes, net operating loss (NOL) carryforwards of approximately $309 million are available to reduce future taxable income and will expire in 2003 through 2005. The 35% tax effect of the NOLs is $108 million. The Tax Reform Act of 1986 provides for an alternative minimum tax (AMT) credit to be used to reduce the regular tax to the AMT level should the regular tax exceed the AMT. AMT credits of $171 million are available to offset future regular tax. The credits may be carried forward indefinitely. (9) Retirement and Postemployment Benefits (A) RETIREMENT INCOME PLAN We sponsor a noncontributing pension plan which covers all employee groups. Two existing plans were merged into a single plan on December 31, 1993. The amount of retirement benefits generally depends upon the length of service. Under certain circumstances, benefits can begin as early as age 55. Our funding policy is to comply with the Employee Retirement Income Security Act of 1974 guidelines. In 1993, we offered the VTP, an early retirement program. Operating expenses for 1993 included $205 million of pension plan accruals to cover enhanced VTP benefits and an additional $10 million of pension costs for VTP benefits paid to retirees from corporate funds. The $10 million is not included in the pension data reported below. A credit of $81 million resulting from a settlement of pension obligations through lump sum payments to almost all the VTP retirees partially offset the VTP expenses. Net pension and VTP costs (credits) for 1991 through 1993 were comprised of the following components:
1993 1992 1991 ---- ---- ----- (millions of dollars) Pension Costs (Credits): Service cost for benefits earned during the period $ 15 $ 15 $ 14 Interest cost on projected benefit obligation 37 38 36 Actual return on plan assets (65) (24) (129) Net amortization and deferral 4 (45) 65 ---- ---- ----- Net pension costs (credits) (9) (16) (14) VTP cost 205 -- -- Settlement gain (81) -- -- ---- ---- ----- Net costs (credits) $115 $(16) $ (14) ---- ---- ----- ---- ---- -----
The following table presents a reconciliation of the funded status of the plan(s) at December 31, 1993 and 1992.
1993 1992 ---- ---- (millions of dollars) Actuarial present value of benefit obligations: Vested benefits $333 $310 Nonvested benefits 37 40 ---- ---- Accumulated benefit obligation 370 350 Effect of future compensation levels 53 121 ---- ---- Total projected benefit obligation 423 471 Plan assets at fair market value 386 754 ---- ---- Funded status (37) 283 Unrecognized net loss (gain) from variance between assumptions and experience 11 (140) Unrecognized prior service cost 10 12 Transition asset at January 1, 1987 being amortized over 19 years (43) (99) ---- ---- Net prepaid pension cost (accrued pension liability) included in other deferred charges (credits) in the Balance Sheet $(59) $ 56 ---- ---- ---- ----
At December 31, 1993, the settlement (discount) rate and long-term rate of return on plan assets assumptions were 7.25% and 8.75%, respectively. The long-term rate of annual compensation increase assumption was 4.25%. At December 31, 1992, the settlement rate and long-term rate of return on plan assets assumptions were 8.5% and the long-term rate of annual compensation increase assumption was 5%. Plan assets consist primarily of investments in common stock, bonds, guaranteed investment contracts, cash equivalent securities and real estate. (Centerior Energy) F-18 (Centerior Energy) 71 (B) OTHER POSTRETIREMENT BENEFITS We sponsor a postretirement benefit plan which provides all employee groups certain health care, death and other postretirement benefits other than pensions. The plan is contributory, with retiree contributions adjusted annually. The plan is not funded. A policy limiting the employer's contribution for retiree medical coverage for employees retiring after March 31, 1993 was implemented in February 1993. We adopted SFAS 106, the accounting standard for postretirement benefits other than pensions, effective January 1, 1993. The standard requires the accrual of the expected costs of such benefits during the employees' years of service. Previously, the costs of these benefits were expensed as paid, which is consistent with ratemaking practices. Such costs totaled $9 million in 1992 and $10 million in 1991, which included medical benefits of $8 million in 1992 and $9 million in 1991. The total amount accrued for SFAS 106 costs for 1993 was $111 million, of which $5 million was capitalized and $106 million was expensed as other operation and maintenance expenses. In 1993, we deferred incremental SFAS 106 expenses totaling $96 million pursuant to a provision of the Rate Stabilization Program. See Note 7. The components of the total postretirement benefit costs for 1993 were as follows:
Millions of Dollars ---------- Service cost for benefits earned $ 3 Interest cost on accumulated postretirement benefit obligation 16 Amortization of transition obligation at January 1, 1993 of $167 million over 20 years 8 VTP curtailment cost (includes $16 million transition obligation adjustment) 84 ----- Total costs $111 ----- -----
The accumulated postretirement benefit obligation and accrued postretirement benefit cost at December 31, 1993 are summarized as follows:
Millions of Dollars ---------- Accumulated postretirement benefit obligation attributable to: Retired participants $ (229) Fully eligible active plan participants (1) Other active plan participants (28) ---------- Accumulated postretirement benefit obligation (258) Unrecognized net loss from variance between assumptions and experience 14 Unamortized transition obligation 143 ---------- Accrued postretirement benefit cost included in other noncurrent liabilities in the Balance Sheet $ (101) ---------- ----------
At December 31, 1993, the settlement rate and the long-term rate of annual compensation increase assumptions were 7.25% and 4.25%, respectively. The assumed annual health care cost trend rates (applicable to gross eligible charges) are 9.5% for medical and 8% for dental in 1994. Both rates reduce gradually to a fixed rate of 4.75% in 1996 and later years. Elements of the obligation affected by contribution caps are significantly less sensitive to the health care cost trend rate than other elements. If the assumed health care cost trend rates were increased by 1% in each future year, the accumulated postretirement benefit obligation as of December 31, 1993 would increase by $11 million and the aggregate of the service and interest cost components of the annual postretirement benefit cost would increase by $1 million. (C) POSTEMPLOYMENT BENEFITS In 1993, we adopted SFAS 112, the new accounting standard which requires the accrual of postemployment benefit costs. Postemployment benefits are the benefits provided to former or inactive employees after employment but before retirement, such as worker's compensation, disability benefits and severance pay. The adoption of this accounting method did not materially affect our 1993 results of operations or financial position. (10) Guarantees Cleveland Electric has guaranteed certain loan and lease obligations of two mining companies under two long-term coal purchase arrangements. Toledo Edison is also a party to one of these guarantee arrangements. This arrangement requires payments to the mining company for any actual expenses (as advance payments for coal) when the mines are idle for reasons beyond the control of the mining company. At December 31, 1993, the principal amount of the mining companies' loan and lease obligations guaranteed by the Operating Companies was $80 million. (11) Capitalization (A) CAPITAL STOCK TRANSACTIONS Shares sold, retired and purchased for treasury during the three years ended December 31, 1993 are listed in the following tables.
1993 1992 1991 ----- ----- ----- (thousands of shares) Centerior Energy Common Stock: Dividend Reinvestment and Stock Purchase Plan 3,542 2,570 1,422 Employee Savings Plan 544 322 348 Employee Purchase Plan 52 -- -- ----- ----- ----- Total Common Stock Sales 4,138 2,892 1,770 Treasury Shares 26 (172) (11) ----- ----- ----- Net Increase 4,164 2,720 1,759 ----- ----- ----- ----- ----- -----
(Centerior Energy) F-19 (Centerior Energy) 72
1993 1992 1991 ----- ----- ----- (thousands of shares) Preferred Stock of Subsidiaries Subject to Mandatory Redemption: Cleveland Electric Sales $ 91.50 Series Q -- -- 75 88.00 Series R -- -- 50 90.00 Series S -- 75 -- Cleveland Electric Retirements $ 7.35 Series C (10) (10) (10) 88.00 Series E (3) (3) (3) 75.00 Series F -- -- (2) 145.00 Series I -- -- (14) 113.50 Series K -- -- (10) Adjustable Series M (100) (100) (100) 9.125 Series N (150) -- -- Toledo Edison Retirements $100 par $11.00 -- (25) (10) 9.375 (17) (17) (17) 25 par 2.81 (800) -- -- Preferred Stock of Subsidiaries Not Subject to Mandatory Redemption: Cleveland Electric Sales $ 42.40 Series T 200 -- -- Cleveland Electric Retirements Remarketed Series P -- (1) -- ----- ----- ----- Net (Decrease) (880) (81) (41) ----- ----- ----- ----- ----- -----
Shares of common stock required for our stock plans in 1993 were either acquired in the open market, issued as new shares or issued from treasury stock. The Board of Directors has authorized the purchase in the open market of up to 1,500,000 shares of our common stock until June 30, 1994. As of December 31, 1993, 225,500 shares had been purchased at a total cost of $4 million. Such shares are being held as treasury stock. (B) COMMON SHARES RESERVED FOR ISSUE Common shares reserved for issue under the Employee Savings Plan and the Employee Purchase Plan were 1,962,174 and 469,457 shares, respectively, at December 31, 1993. Stock options to purchase unissued shares of common stock under the 1978 Key Employee Stock Option Plan were granted at an exercise price of 100% of the fair market value at the date of the grant. No additional options may be granted. The exercise prices of option shares purchased during the three years ended December 31, 1993 ranged from $14.09 to $17.41 per share. Shares and price ranges of outstanding options held by employees were as follows:
1993 1992 1991 --------- --------- --------- Options Outstanding at December 31: Shares 37,627 93,312 129,798 Option Prices $14.09 to $14.09 to $14.09 to $20.73 $20.73 $20.73
(C) EQUITY DISTRIBUTION RESTRICTIONS The Operating Companies make cash available for the funding of Centerior Energy's common stock dividends by paying dividends on their respective common stock, which are held solely by Centerior Energy. Federal law prohibits the Operating Companies from paying dividends out of capital accounts. However, the Operating Companies may pay preferred and common stock dividends out of appropriated retained earnings and current earnings. At December 31, 1993, Cleveland Electric and Toledo Edison had $125 million and $42 million, respectively, of appropriated retained earnings for the payment of dividends. However, Toledo Edison is prohibited from paying a common stock dividend by a provision in its mortgage. (D) PREFERRED AND PREFERENCE STOCK Amounts to be paid for preferred stock which must be redeemed during the next five years are $40 million in 1994, $51 million in 1995, $41 million in 1996, $31 million in 1997 and $16 million in 1998. The annual mandatory redemption provisions are as follows:
Shares Price To Be Beginning Per Redeemed in Share -------- --------- ------ Cleveland Electric Preferred: $ 7.35 Series C 10,000 1984 $ 100 88.00 Series E 3,000 1981 1,000 Adjustable Series M 100,000 1991 100 9.125 Series N 150,000 1993 100 91.50 Series Q 10,714 1995 1,000 88.00 Series R 50,000 2001* 1,000 90.00 Series S 18,750 1999 1,000 Toledo Edison Preferred: $100 par $9.375 16,650 1985 100 25 par 2.81 400,000 1993 25
* All outstanding shares to be redeemed on December 1, 2001. In June 1993, Cleveland Electric issued $100 million principal amount of Serial Preferred Stock, $42.40 Series T. The Series T stock was deposited with an agent which issued Depositary Receipts, each representing 1/20 of a share of the Series T stock. The annualized preferred dividend requirement for the Operating Companies at December 31, 1993 was $68 million. The preferred dividend rates on Cleveland Electric's Series L and M and Toledo Edison's Series A and B fluctuate based on prevailing interest rates and market conditions. The dividend rates for these issues averaged 7%, 7%, 7.41% and 8.22%, respectively, in 1993. Cleveland Electric's Series P had a 6.5% dividend rate in 1993 until it was redeemed in August 1993. (Centerior Energy) F-20 (Centerior Energy) 73 Preference stock authorized for the Operating Companies are 3,000,000 shares without par value for Cleveland Electric and 5,000,000 shares with a $25 par value for Toledo Edison. No preference shares are currently outstanding for either company. With respect to dividend and liquidation rights, each Operating Company's preferred stock is prior to its preference stock and common stock, and each Operating Company's preference stock is prior to its common stock. (E) LONG-TERM DEBT AND OTHER BORROWING ARRANGEMENTS Long-term debt, less current maturities, for the Operating Companies was as follows:
Actual or Average Interest Rate at December 31, December 31, --------------- Year of Maturity 1993 1993 1992 - -------------------------------- ------------ ------ ------ (millions of dollars) First mortgage bonds: 1994 4.375% $ -- $ 25 1994 13.75 -- 4 1995 13.75 4 4 1995 7.00 1 1 1996 13.75 4 4 1996 7.00 1 1 1997 10.88 6 6 1997 13.75 4 4 1997 7.00 1 1 1997 6.125 31 31 1998 10.88 6 6 1998 13.75 4 4 1998 7.00 1 1 1998 10.00 1 1 1999-2003 7.89 568 468 2004-2008 8.14 260 264 2009-2013 7.68 436 436 2014-2018 8.07 513 513 2019-2023 7.89 733 583 ------ ------ 2,574 2,357 Secured medium term notes due 1995-2021 8.77 963 860 Term bank loans due 1995-1996 7.41 154 121 Notes due 1995-1997 9.63 43 60 Debentures due 2002 8.70 135 135 Pollution control notes due 1995-2015 10.11 158 158 Other -- net -- (8) 3 ------ ------ Total Long-Term Debt $4,019 $3,694 ------ ------ ------ ------
Long-term debt matures during the next five years as follows: $87 million in 1994, $317 million in 1995, $242 million in 1996, $94 million in 1997 and $117 million in 1998. The Operating Companies issued $550 million aggregate principal amount of secured medium-term notes during the 1991-1993 period. The notes are secured by first mortgage bonds. The mortgages of the Operating Companies constitute direct first liens on substantially all property owned and franchises held by them. Excluded from the liens, among other things, are cash, securities, accounts receivable, fuel, supplies and, in the case of Toledo Edison, automotive equipment. Certain unsecured loan agreements of the Operating Companies contain covenants relating to capitalization ratios, fixed charge coverage ratios and limitations on secured financing other than through first mortgage bonds or certain other transactions. Two reimbursement agreements relating to separate letters of credit issued in connection with the sale and leaseback of Beaver Valley Unit 2 contain several financial covenants affecting Centerior Energy and the Operating Companies. Among these are covenants relating to fixed charge coverage ratios and capitalization ratios. The write-offs recorded at December 31, 1993 caused Centerior Energy and the Operating Companies to violate certain covenants contained in a Cleveland Electric loan agreement and the two reimbursement agreements. The affected creditors have waived those violations in exchange for our commitment to provide them with a second mortgage security interest on our property and other considerations. We expect to complete this process in the second quarter of 1994. We will provide the same security interest to certain other creditors because their agreements require equal treatment. We expect to provide second mortgage collateral for $219 million of unsecured debt, $228 million of bank letters of credit and a $205 million revolving credit facility. (12) Short-Term Borrowing Arrangements In May 1993, Centerior Energy arranged for a $205 million, three-year revolving credit facility. The facility may be renewed twice for one-year periods at the option of the participating banks. Centerior Energy and the Service Company may borrow under the facility, with all borrowings jointly and severally guaranteed by the Operating Companies. Centerior Energy plans to transfer any of its borrowed funds to the Operating Companies, while the Service Company may borrow up to $25 million for its own use. The banks' fee is 0.5% per annum payable quarterly in addition to interest on any borrowings. That fee is expected to increase to 0.625% when the facility agreement is amended as discussed below. There were no borrowings under the facility at December 31, 1993. The facility agreement contains covenants relating to capitalization and fixed charge coverage ratios. The write-offs recorded at December 31, 1993 caused the ratios to fall below those covenant requirements. The (Centerior Energy) F-21 (Centerior Energy) 74 revolving credit facility is expected to be available for borrowings after the facility agreement is amended in the second quarter of 1994 to provide the participating creditors with a second mortgage security interest. Short-term borrowing capacity authorized by the PUCO annually is $300 million for Cleveland Electric and $150 million for Toledo Edison. The Operating Companies are authorized by the PUCO to borrow from each other on a short-term basis. At December 31, 1993, the Operating Companies had no commercial paper outstanding. The Operating Companies are unable to rely on the sale of commercial paper to provide short-term funds because of their below investment grade commercial paper credit ratings. (13) Financial Instruments' Fair Value The estimated fair values at December 31, 1993 and 1992 of financial instruments that do not approximate their carrying amounts are as follows:
December 31, ---------------------------------- 1993 1992 ---------------- ---------------- Carrying Fair Carrying Fair Amount Value Amount Value -------- ------ -------- ------ (millions of dollars) Nuclear Plant Decommissioning Trusts $ 56 $ 59 $ 42 $ 45 Preferred Stock, with Mandatory Redemption Provisions (including current portion) 354 349 405 408 Long-Term Debt (including current portion) 4,113 4,260 4,017 4,107
The fair value of the nuclear plant decommissioning trusts is estimated based on the quoted market prices for the investment securities. The fair value of the Operating Companies' preferred stock with mandatory redemption provisions and long-term debt is estimated based on the quoted market prices for the respective or similar issues or on the basis of the discounted value of future cash flows. The discounted value used current dividend or interest rates (or other appropriate rates) for similar issues and loans with the same remaining maturities. The estimated fair values of all other financial instruments approximate their carrying amounts in the Balance Sheet at December 31, 1993 and 1992 because of their short-term nature. (14) Quarterly Results of Operations (Unaudited) The following is a tabulation of the unaudited quarterly results of operations for the two years ended December 31, 1993.
Quarters Ended ---------------------------------------- March 31, June 30, Sept. 30, Dec. 31, --------- -------- --------- -------- (millions of dollars, except per share amounts) 1993 Operating Revenues $ 598 $589 $ 709 $ 578 Operating Income (Loss) $ 122 $126 $ 106 $ (42) Net Income (Loss) $ 35 $ 34 $ 17 $(1,029) Average Common Shares (millions) 143.4 144.4 145.3 146.4 Earnings (Loss) Per Common Share $ .25 $.23 $ .12 $ (7.02) Dividends Paid Per Common Share $ .40 $.40 $ .40 $ .40 1992 Operating Revenues $ 592 $581 $ 665 $ 600 Operating Income $ 122 $115 $ 191 $ 109 Net Income $ 23 $ 20 $ 122 $ 47 Average Common Shares (millions) 140.6 141.6 142.0 142.5 Earnings Per Common Share $ .16 $.14 $ .86 $ .33 Dividends Paid Per Common Share $ .40 $.40 $ .40 $ .40
Earnings for the quarter ended September 30, 1993 were decreased by $81 million, or $.56 per share, as a result of the recording of $125 million of VTP pension-related benefits. Earnings for the quarter ended December 31, 1993 were decreased as a result of year-end adjustments for the $583 million write-off of Perry Unit 2 (see Note 4(b)), the $877 million write-off of the phase-in deferrals (see Note 7) and $58 million of other charges. These adjustments decreased quarterly earnings by $1.06 billion, or $7.24 per share. Earnings for the quarter ended September 30, 1992 were increased by $41 million, or $.29 per share, as a result of the recording of deferred operating expenses and carrying charges for the first nine months of 1992 totaling $61 million under the Rate Stabilization Program approved by the PUCO in October 1992. See Note 7. (Centerior Energy) F-22 (Centerior Energy) 75 FINANCIAL AND STATISTICAL REVIEW - ---------------------------------------------------------------------- Operating Revenues (millions of dollars)
Steam Total Total Total Heating Operating Year Residential Commercial Industrial Other Retail Wholesale Electric & Gas Revenues - ----------------------------------------------------------------------------------------------------------------------------------- 1993 $ 768 716 754 143 2 381 93 2 474 -- $ 2 474 1992 732 706 766 143 2 347 91 2 438 -- 2 438 1991 777 723 783 188 2 471 89 2 560 -- 2 560 1990 719 669 779 190 2 357 70 2 427 -- 2 427 1989 686 617 747 204 2 254 107 2 361 -- 2 361 1983 546 440 600 83 1 669 29 1 698 25 1 723 - -----------------------------------------------------------------------------------------------------------------------------------
Operating Expenses (millions of dollars)
Other Deferred Fuel & Operation Depreciation Taxes, Operating Federal Total Purchased & & Other Than Expenses, Income Operating Year Power Maintenance Amortization FIT Net Taxes Expenses - ------------------------------------------------------------------------------------------------------------------ 1993 $ 474 1 083(a) 258 312 23(b) 11 $ 2 161 1992 473 784 256 318 (52) 122 1 901 1991 500 801 243(c) 305 (6) 138 1 981 1990 472 863 242 283 (34) 96 1 922 1989 473 860 273 260 (59) 122 1 929 1983 464 384 145 172 -- 184 1 349 - ------------------------------------------------------------------------------------------------------------------
Income (Loss) (millions of dollars)
Federal Income Other Deferred Income (Loss) Income & Carrying Tax-- Before Operating AFUDC-- Deductions, Charges, Credit Interest Debt Year Income Equity Net Net (Expense) Charges Interest - ----------------------------------------------------------------------------------------------------------- 1993 $ 313 5 (589)(d) (649)(b) 398 (522) 359 1992 537 2 9 100 (7) 641 365 1991 579 9 6 110 (30) 674 381 1990 505 8 (1) 205 (13) 704 384 1989 432 17 14 299 (73) 689 369 1983 374 153 5 -- 47 579 258 - -----------------------------------------------------------------------------------------------------------
Income (Loss) (millions of dollars) Common Stock (dollars per share & %) Return on Preferred & Average Average Preference Net Shares Common AFUDC-- Stock Income Outstanding Earnings Stock Dividends Year Debt Dividends (Loss) (millions) (Loss) Equity Declared - ------------------------------------------------------------------------------------------------------------------------ 1993 $ (5) 67 $ (943) 144.9 $ (6.51) (40.3)% $ 1.60 1992 (1) 65 212 141.7 1.50 7.4 1.60 1991 (5) 61 237 139.1 1.71 8.4 1.60 1990 (6) 62 264 138.9 1.90 9.4 1.60 1989 (13) 66 267 140.5 1.90 9.6 1.60 1983 (54) 69 306 98.2(e) 3.11(e) 15.7 2.19(e) - ------------------------------------------------------------------------------------------------------------------------
Book Year Value - ---------- ----------- 1993 $12.14 1992 20.22 1991 20.37 1990 20.30 1989 19.99 1983 20.24(e) - ----------------------------
NOTE: 1983 data is the result of combining and restating data for the Operating Companies. (a) Includes early retirement program expenses and other charges of $272 million in 1993. (b) Includes write-off of phase-in deferrals of $877 million in 1993, consisting of $172 million of deferred operating expenses and $705 million of deferred carrying charges. (c) In 1991, the Operating Companies adopted a change in accounting for nuclear plant depreciation, changing from the units-of-production method to the straight-line method at a 2.5% rate. (Centerior Energy) F-23 (Centerior Energy) 76
CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES Electric Sales (millions of KWH) Electric Customers (year end) Industrial Year Residential Commercial Industrial Wholesale Other Total Residential Commercial & Other - ----------------------------------------------------------------------------------------- -------------------------------------- 1993 6 974 7 306 11 687 3 027 1 022 30 016 924 227 96 491 12 219 1992 6 666 7 086 11 551 2 814 1 011 29 128 925 099 96 813 12 741 1991 6 981 7 176 11 559 2 690 1 048 29 454 921 995 96 449 12 843 1990 6 666 6 848 12 168 2 487 959 29 128 918 965 94 522 12 906 1989 6 806 6 830 12 520 3 235 996 30 387 914 020 93 833 12 763 1983 6 327 5 606 10 641 703 854 24 131 886 024 85 769 11 557 Residential Usage Average Average Average Price Revenue KWH Per Per Per Year Total Customer KWH Customer - ------- ----------- --------------------------------- 1993 1 032 937 7 546 11.01cent $830.99 1992 1 034 653 7 227 10.98 793.68 1991 1 031 287 7 410 11.16 827.10 1990 1 026 393 7 079 10.82 765.93 1989 1 020 616 7 295 10.08 737.58 1983 983 350 6 967 8.64 603.22 - --------------------------------------------------------------------------------
Load (MW & %) Energy (millions of KWH) Fuel Operable Capacity Company Generated at Time Peak Capacity Load ----------------------------- Purchased Fuel Cost Year of Peak Load Margin Factor Fossil Nuclear Total Power Total Per KWH - -------------------------------------------------------- --------------------------------------------------------- ---------- 1993 5 998 5 397 10.0% 61.6% 21 105 10 435 31 540 273 31 813 1.39cent 1992 6 430 5 091 20.8 63.4 17 371 13 814 31 185 (122) 31 063 1.45 1991 6 453 5 361 16.9 62.9 18 041 13 454 31 495 40 31 535 1.48 1990 6 437 5 261 18.3 63.6 21 114 9 481 30 595 413 31 008 1.52 1989 6 430 5 389 16.2 63.3 20 174 12 122 32 296 21 32 317 1.47 1983 6 218 4 717 24.1 63.1 19 487 4 895 24 382 1 650 26 032 1.72 Efficiency-- BTU Per Year KWH - -------- ---------- 1993 10 276 1992 10 395 1991 10 442 1990 10 354 1989 10 435 1983 10 419 - --------------------------------------------------------------------------------
Investment (millions of dollars)
Construction Utility Work In Total Plant Accumulated Progress Nuclear Property, Utility In Depreciation & Net & Perry Fuel and Plant and Plant Total Year Service Amortization Plant Unit 2 Other Equipment Additions Assets - ------------------------------------------------------------------------------------------------ ------- -------- 1993 $9 571 2 677 6 894 181 385 $ 7 460 $ 218 $10 710 1992 9 449 2 488 6 961 781 424 8 166 200 12 071 1991 8 888 2 274 6 614 853 503 7 970 204 11 829 1990 8 636 2 039 6 597 921 568 8 086 251 11 681 1989 8 398 1 824 6 574 945 592 8 111 217 11 454 1983 4 180 1 047 3 133 2 710 392(f) 6 235 785 6 922 - --------------------------------------------------------------------------------
Capitalization (millions of dollars & %)
Preferred & Preference Preferred Stock, with Stock, without Mandatory Mandatory Common Stock Redemption Redemption Year Equity Provisions Provisions Long-Term Debt Total - ------------------------------------------------------------------------------------------------------- 1993 $1 785 27% 313 5% 451 7% 4 019 61% $6 568 1992 2 889 39 364 5 354 5 3 694 51 7 301 1991 2 855 38 332 4 427 6 3 841 52 7 455 1990 2 810 39 237 3 427 6 3 729 52 7 203 1989 2 795 40 281 4 427 6 3 534 50 7 037 1983 2 065 39 412 8 344 6 2 504 47 5 325 - --------------------------------------------------------------------------------
(d) Includes write-off of Perry Unit 2 of $583 million in 1993. (e) Average shares outstanding and related per share computations reflect the Cleveland Electric 1.11-for-one exchange ratio and the Toledo Edison one-for-one exchange ratio for Centerior Energy shares at the date of affiliation, April 29, 1986. (f) Restated for effects of capitalization of nuclear fuel lease and financing arrangements pursuant to Statement of Financial Accounting Standards 71. (Centerior Energy) F-24 (Centerior Energy) 77 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS - ---------------------------------------------------------------------- To the Share Owners of The Cleveland Electric [Logo] Illuminating Company: We have audited the accompanying consolidated balance sheet and consolidated statement of preferred stock of The Cleveland Electric Illuminating Company (a wholly owned subsidiary of Centerior Energy Corporation) and subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1993. These financial statements and the schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of The Cleveland Electric Illuminating Company and subsidiaries as of December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. As discussed further in Notes 1 and 9, changes were made in the methods of accounting for nuclear plant depreciation in 1991 and for postretirement benefits other than pensions in 1993. Our audits were made for the purposef of forming an opinion on the basic financial statements taken as a whole. The schedules of The Cleveland Electric Illuminating Company and subsidiaries listed in the Index to Schedules are presented for purposes of complying with the Securities and Exchange Commission rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN & CO. Cleveland, Ohio February 14, 1994 (except with respect to the matter discussed in Note 15, as to which the date is March 25, 1994) (Cleveland Electric) F-25 (Cleveland Electric) 78 MANAGEMENT'S FINANCIAL ANALYSIS - ---------------------------------------------------------------------- Results of Operations 1993 VS. 1992 Factors contributing to the 0.5% increase in 1993 operating revenues for The Cleveland Electric Illuminating Company (Company) are as follows:
Millions Increase (Decrease) in Operating Revenues of Dollars - ------------------------------------------------ ----------- Sales Volume and Mix $ 27 Fuel Cost Recovery Revenues (13) Base Rates and Miscellaneous (10) Wholesale Sales 4 ----- Total $ 8 ----- -----
The net revenue increase resulted primarily from the different weather conditions and the changes in the composition of the sales mix among customer categories. Weather accounted for approximately $36 million of the higher 1993 revenues. Hot summer weather in 1993 boosted residential, commercial and wholesale kilowatt-hour sales. In contrast, the 1992 summer was the coolest in 56 years in Northeastern Ohio. Residential and commercial sales also increased as a result of colder late-winter temperatures in 1993 which increased electric heating-related demand. As a result, total sales increased 2.9% in 1993. Residential and commercial sales increased 4.4% and 3.1%, respectively. Industrial sales decreased 1%. Lower sales to large steel industry customers were partially offset by increased sales to large automotive manufacturers and the broad-based, smaller industrial customer group. Other sales increased 11.9% because of increased sales to wholesale customers. The net decrease in 1993 fuel cost recovery revenues resulted from changes in the fuel cost factors. The weighted average of these factors decreased approximately 5%. Base rates and miscellaneous revenues decreased in 1993 primarily from lower revenues under contracts having reduced rates with certain large customers and a declining rate structure tied to usage. The contracts have been negotiated to meet competition and encourage economic growth. Operating expenses increased 12.4% in 1993. The increase in total operation and maintenance expenses resulted from the $130 million of net benefit expenses related to an early retirement program, called the Voluntary Transition Program (VTP), other charges totaling $35 million and an increase in other operation and maintenance expenses. The VTP benefit expenses consisted of $102 million of costs for the Company plus $28 million for the Company's pro rata share of the costs for its affiliate, Centerior Service Company (Service Company). Other charges recorded at year-end 1993 related to a performance improvement plan for Perry Nuclear Power Plant Unit 1 (Perry Unit 1), postemployment benefits and other expense accruals. The increase in other operation and maintenance expenses resulted from higher environmental expenses, power restoration and repair expenses following a July 1993 storm, and an increase in other postretirement benefit expenses. See Note 9 for information on retirement and postemployment benefits. Deferred operating expenses decreased because of the write-off of the phase-in deferred operating expenses in 1993 as discussed in Note 7. Federal income taxes decreased as a result of lower pretax operating income. As discussed in Note 4(b), $351 million of our Perry Nuclear Power Plant Unit 2 (Perry Unit 2) investment was written off in 1993. Credits for carrying charges recorded in nonoperating income decreased because of the write-off of the phase-in deferred carrying charges in 1993 as discussed in Note 7. The federal income tax credit for nonoperating income in 1993 resulted from the write-offs. 1992 VS. 1991 Factors contributing to the 4.5% decrease in 1992 operating revenues are as follows:
Millions Decrease in Operating Revenues of Dollars - ------------------------------------------------ ----------- Sales Volume and Mix $50 Base Rates and Miscellaneous 23 Fuel Cost Recovery Revenues 10 --- $83 --- ---
The revenue decreases resulted primarily from the different weather conditions and the changes in the composition of the sales mix among customer categories. Weather accounted for approximately $55 million of the lower 1992 revenues. Winter and spring in 1992 were milder than in 1991. In addition, the cooler summer in 1992 contrasted with the summer of 1991 which was much hotter than normal. As a result, total kilowatt-hour sales decreased 3.5% in 1992. Residential and commercial sales decreased 4.4% and 0.5%, respectively, as moderate temperatures in 1992 reduced electric heating and cooling demands. Industrial sales declined 0.4% as an 8.1% decrease in sales to the broad-based, smaller industrial customer group completely offset an 8.8% increase in sales to the larger industrial customer group. Sales to steel producers and auto manufacturers within the large industrial customer group rose 10.9% and 7%, respectively. Other sales decreased 16.1% because of decreased sales to wholesale customers and public authorities. The decrease in 1992 fuel cost recovery revenues resulted primarily because of the good performance of our generating units, which in turn decreased our fuel cost factors. The weighted averages of these factors decreased approximately 3%. Operating expenses decreased 3.6% in 1992. Lower fuel and purchased power expense resulted from lower generation requirements stemming from less electric sales and less amortization of previously deferred fuel costs than the amount amortized in 1991. Federal income taxes decreased because of the amortization of certain tax benefits under the Rate Stabilization Program discussed (Cleveland Electric) F-26 (Cleveland Electric) 79 in Note 7 and the effects of adopting the new accounting standard for income taxes (SFAS 109) in 1992. These decreases were partially offset by higher depreciation and amortization, caused primarily by the adoption of SFAS 109, and by higher taxes, other than federal income taxes, caused by increased Ohio property and gross receipts taxes. Deferred operating expenses increased as a result of the deferrals under the Rate Stabilization Program. The federal income tax provision for nonoperating income decreased because of lower carrying charge credits and a greater tax allocation of interest charges to nonoperating activities. Credits for carrying charges recorded in nonoperating income decreased primarily because of lower phase-in-carrying charge credits. Interest charges decreased as a result of debt refinancings at lower interest rates and lower short-term borrowing requirements. Outlook RECENT ACTIONS In January 1994, Centerior Energy Corporation (Centerior Energy), along with the Company and The Toledo Edison Company (Toledo Edison), announced a comprehensive strategic action plan to strengthen their financial and competitive positions. The Company and Toledo Edison are the two wholly owned electric utility subsidiaries of Centerior Energy. The plan established specific objectives and was designed to guide Centerior Energy and its subsidiaries through the year 2001. Several actions were taken at that time. Centerior Energy reduced its quarterly common stock dividend from $.40 per share to $.20 per share effective with the dividend payable February 15, 1994. This action was taken because projected financial results did not support continuation of the dividend at its former rate. The Company and Toledo Edison also wrote off their investments in Perry Unit 2 and certain deferred charges related to a January 1989 rate agreement (phase-in deferrals). The aggregate after-tax effect of these write-offs for the Company was $691 million which resulted in a net loss in 1993 and a retained earnings deficit. The write-offs are discussed in Notes 4(b) and 7. The Company also recognized other one-time charges totaling $25 million after taxes related to a performance improvement plan for Perry Unit 1, postemployment benefits and other expense accruals. Also contributing to the net loss in 1993 was a charge of $51 million after taxes representing a portion of the VTP costs. The Company will realize approximately $30 million of savings in annual payroll and benefit costs beginning in 1994 as a result of the VTP. STRATEGIC PLAN The objectives of the strategic plan are to maximize share owner return on Centerior Energy common stock from corporate assets and resources, achieve profitable revenue growth, become an industry leader in customer satisfaction, build a winning team and attain increasingly competitive power supply costs. To achieve these objectives, the Company will continue controlling its operation and maintenance expenses and capital expenditures, reduce its outstanding debt, increase revenues by finding new uses for existing assets and resources, implement a broad range of new marketing programs, increase revenues by restructuring rates for various customers where appropriate, improve the operating performance of its plants and take other appropriate actions. COMMON STOCK DIVIDENDS Centerior Energy's common stock dividend has been funded in recent years primarily by common stock dividends paid by the Company. We expect this practice to continue for the foreseeable future. Centerior Energy's lower common stock dividend reduces its cash outflow by about $120 million annually which, in turn, reduces the common stock dividend demands placed on the Company. The Company intends to use the increased retained cash to repay debt more quickly than would otherwise be the case. This will help improve the Company's capitalization structure and interest coverage ratios. COMPETITION Our electric rates are among the highest in our region because we are recovering the substantial investment in our nuclear construction program. Accordingly, some of our customers continue to seek less costly alternatives, including switching to or working to create a municipal electric system. There are two municipal systems in our service area. In addition, we face threats of other municipalities in our service area establishing new systems and the expansion of an existing system. We have entered into agreements with some of the communities which considered establishing systems. Accordingly, they will not proceed with such development at this time in return for rate concessions and/or economic development funds. Others have determined that developing a system was not feasible. Cleveland Public Power continues to expand its operations into areas we have served exclusively. We have been successful in retaining most of the large industrial and commercial customers in those areas by providing economic incentive packages in exchange for sole-supplier contracts. We also have similar contracts with customers in other areas. Most of these contracts have remaining terms of one to five years. We will continue to address municipal system threats through aggressive marketing programs and emphasizing to our customers the value of our service and the risks of a municipal system. The Energy Policy Act of 1992 (Energy Act) will provide additional competition in the electric utility industry by requiring utilities to wheel to municipal systems in their service areas electricity from other utilities. This provision of the Energy Act should not significantly increase the competitive threat to us since the operating licenses (Cleveland Electric) F-27 (Cleveland Electric) 80 for our nuclear units have required us to wheel to municipal systems in our service area since 1977. The Energy Act also created a class of exempt wholesale generators which may increase competition in the wholesale power market. A further risk is the possibility that the government could mandate that utilities deliver power from another utility or generation source to their retail customers. As mentioned above, we have contracts with many of our large industrial and commercial customers. We will attempt to renew those contracts as they expire which will help us compete if retail wheeling is permitted in the future. RATE MATTERS Our Rate Stabilization Program remains in effect. Under this program, we agreed to freeze base rates until 1996 and limit rate increases through 1998. In exchange, we are permitted to defer through 1995 and subsequently recover certain costs not currently recovered in rates and to accelerate the amortization of certain benefits. The amortization and recovery of the deferrals will begin with future rate recognition and will continue over the average life of the related assets, or approximately 30 years. The continued use of these regulatory accounting measures will be dependent upon our continuing assessment and conclusion that there will be probable recovery of such deferrals in future rates. The analysis leading to the year-end 1993 financial actions and strategic plan also included an evaluation of our regulatory accounting measures. We decided that, once the deferral of expenses and acceleration of benefits under our Rate Stabilization Program are completed in 1995, we should no longer plan to use regulatory accounting measures to the extent we have in the past. NUCLEAR OPERATIONS The Company's three nuclear units may be impacted by activities or events beyond our control. Operating nuclear generating units have experienced unplanned outages or extensions of scheduled outages because of equipment problems or new regulatory requirements. A major accident at a nuclear facility anywhere in the world could cause the Nuclear Regulatory Commission (NRC) to limit or prohibit the operation or licensing of any nuclear unit. If one of our nuclear units is taken out of service for an extended period of time for any reason, including an accident at such unit or any other nuclear facility, we cannot predict whether regulatory authorities would impose unfavorable rate treatment. Such treatment could include taking our affected unit out of rate base or disallowing certain construction or maintenance costs. An extended outage of one of our nuclear units coupled with unfavorable rate treatment could have a material adverse effect on our financial condition and results of operations. We externally fund the estimated costs for the future decommissioning of our nuclear units. In 1993, we increased our decommissioning expense accruals for revisions in our cost estimates. We expect the increases associated with the new estimates will be recoverable in future rates. See Note 1(f). HAZARDOUS WASTE DISPOSAL SITES The Comprehensive Environmental Response, Compensation and Liability Act of 1980 as amended (Superfund) established programs addressing the cleanup of hazardous waste disposal sites, emergency preparedness and other issues. The Company has been named as a "potentially responsible party" (PRP) for three sites listed on the Superfund National Priorities List (Superfund List) and is aware of its potential involvement in the cleanup of several other sites not on such list. The allegations that the Company disposed of hazardous waste at these sites and the amounts involved are often unsubstantiated and subject to dispute. Superfund provides that all PRPs to a particular site can be held liable on a joint and several basis. Consequently, if the Company were held liable for 100% of the cleanup costs of all of the sites referred to above, the cost could be as high as $250 million. However, we believe that the actual cleanup costs will be substantially lower than $250 million, that the Company's share of any cleanup costs will be substantially less than 100% and that most of the other PRPs are financially able to contribute their share. The Company has accrued a liability totaling $13 million at December 31, 1993 based on estimates of the costs of cleanup and its proportionate responsibility for such costs. We believe that the ultimate outcome of these matters will not have a material adverse effect on our financial condition or results of operations. 1993 TAX ACT The Revenue Reconciliation Act of 1993 (1993 Tax Act), which was enacted in August 1993, provided for a 35% income tax rate in 1993. The 1993 Tax Act did not materially impact the results of operations for 1993, but did affect certain Balance Sheet accounts as discussed in Note 8. The 1993 Tax Act is not expected to materially impact future results of operations or cash flow. INFLATION Although the rate of inflation has eased in recent years, we are still affected by even modest inflation which causes increases in the unit cost of labor, materials and services. (Cleveland Electric) F-28 (Cleveland Electric) 81 Capital Resources and Liquidity 1991-1993 CASH REQUIREMENTS We need cash for normal corporate operations, the mandatory retirement of securities and an ongoing program of constructing new facilities and modifying existing facilities. The construction program is needed to meet anticipated demand for electric service, comply with governmental regulations and protect the environment. Over the three-year period of 1991-1993, these construction and mandatory retirement needs totaled approximately $970 million. In addition, we exercised various options to redeem and purchase approximately $430 million of our securities. We raised $1.2 billion through security issues and term bank loans during the 1991-1993 period as shown in the Cash Flows statement. During the three-year period, the Company also utilized its short-term borrowing arrangements to help meet its cash needs. Although the write-offs of Perry Unit 2 and the phase-in deferrals in 1993 negatively affected our earnings, they did not adversely affect our current cash flow. 1994 AND BEYOND CASH REQUIREMENTS Estimated cash requirements for 1994-1998 for the Company are $791 million for its construction program and $715 million for the mandatory redemption of debt and preferred stock. The Company expects to finance internally all of its 1994 cash requirements of approximately $239 million. About 20% of the Company's 1995-1998 requirements are expected to be financed externally. If economical, additional securities may be redeemed under optional redemption provisions. Our capital requirements are dependent upon our implementation strategy to achieve compliance with the Clean Air Act Amendments of 1990 (Clean Air Act). Cash expenditures for our plan are estimated to be approximately $87 million over the 1994-1998 period. See Note 4(a). LIQUIDITY Additional first mortgage bonds may be issued by the Company under its mortgage on the basis of property additions, cash or refundable first mortgage bonds. Under its mortgage, the Company may issue first mortgage bonds on the basis of property additions and, under certain circumstances, refundable bonds only if the applicable interest coverage test is met. At December 31, 1993, the Company would have been permitted to issue approximately $78 million of additional first mortgage bonds. After the fourth quarter of 1994, the Company's ability to issue first mortgage bonds is expected to increase substantially when its interest coverage ratio will no longer be affected by the write-offs recorded at December 31, 1993. As discussed in Note 11(d), certain unsecured debt agreements contain covenants relating to capitalization, fixed charge coverage ratios and secured financings. The write-offs recorded at December 31, 1993 caused the Company, Toledo Edison and Centerior Energy to violate certain of those covenants. The affected creditors have waived those violations in exchange for commitments to provide them with a second mortgage security interest on property of the Company and Toledo Edison and other considerations. We expect to complete this process in the second quarter of 1994. We will provide the same security interest to certain other creditors because their agreements require equal treatment. We expect to provide second mortgage collateral for $47 million of unsecured debt, $228 million of bank letters of credit and a $205 million revolving credit facility. The bank letters of credit and revolving credit facility are joint and several obligations of the Company and Toledo Edison. For the next five years, the Company does not expect to raise funds through the sale of debt junior to first mortgage bonds. However, if necessary or desirable, we believe that the Company could raise funds through the sale of unsecured debt or debt secured by the second mortgage referred to above. The Company also is able to raise funds through the sale of preference and preferred stock. The Company currently cannot sell commercial paper because of its low commercial paper ratings by Standard & Poor's Corporation (S&P) and Moody's Investors Service, Inc. (Moody's) of "B" and "Not Prime", respectively. The Company is a party to a $205 million revolving credit facility which will run through mid-1996. However, we currently cannot draw on this facility because the write-offs taken at year-end 1993 caused the Company, Toledo Edison and Centerior Energy to fail to meet certain capitalization and fixed charge coverage covenants. We expect to have this facility available to us again after it is amended in the second quarter of 1994 to provide the participating creditors with a second mortgage security interest. These financing resources are expected to be sufficient for the Company's needs over the next several years. The availability and cost of capital to meet the Company's external financing needs, however, also depend upon such factors as financial market conditions and its credit ratings. Current credit ratings for the Company are as follows:
S&P Moody's ----------- ------------- First mortgage bonds BB Ba2 Unsecured notes B+ Ba3 Preferred stock B b1
These ratings reflect a downgrade in December 1993. In addition, S&P has issued a negative outlook for the Company. (Cleveland Electric) F-29 (Cleveland Electric) 82 INCOME STATEMENT THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES - --------------------------------------------------------------------------------
For the years ended December 31, ---------------------------- 1993 1992 1991 ------ ------ ------ (millions of dollars) OPERATING REVENUES $1,751 $1,743 $1,826 ------ ------ ------ OPERATING EXPENSES Fuel and purchased power (1) 423 434 455 Other operation and maintenance 489 465 470 Early retirement program expenses and other 165 -- -- ------ ------ ------ Total operation and maintenance 1,077 899 925 Depreciation and amortization 182 179 171 Taxes, other than federal income taxes 221 226 216 Deferred operating expenses, net 27 (35) (7) Federal income taxes 22 89 106 ------ ------ ------ 1,529 1,358 1,411 ------ ------ ------ OPERATING INCOME 222 385 415 ------ ------ ------ NONOPERATING INCOME (LOSS) Allowance for equity funds used during construction 4 1 8 Other income and deductions, net (5) 8 6 Write-off of Perry Unit 2 (351) -- -- Deferred carrying charges, net (487) 59 88 Federal income taxes -- credit (expense) 270 (5) (24) ------ ------ ------ (569) 63 78 ------ ------ ------ INCOME (LOSS) BEFORE INTEREST CHARGES (347) 448 493 ------ ------ ------ INTEREST CHARGES Debt interest 244 243 251 Allowance for borrowed funds used during construction (4) -- (4) ------ ------ ------ 240 243 247 ------ ------ ------ NET INCOME (LOSS) (587) 205 246 PREFERRED DIVIDEND REQUIREMENTS 45 41 36 ------ ------ ------ EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK $ (632) $ 164 $ 210 ------ ------ ------ ------ ------ ------ - --------------- (1) Includes purchased power expense of $120 million, $130 million and $128 million in 1993, 1992 and 1991, respectively, for all purchases from Toledo Edison.
RETAINED EARNINGS - ----------------------------------------------------------------------
For the years ended December 31, ---------------------------- 1993 1992 1991 ------ ------ ------ (millions of dollars) RETAINED EARNINGS AT BEGINNING OF YEAR $ 545 $ 578 $ 564 ------ ------ ------ ADDITIONS Net income (loss) (587) 205 246 DEDUCTIONS Dividends declared: Common stock (189) (195) (194) Preferred stock (48) (41) (36) Other, primarily preferred stock redemption expenses (1) (2) (2) ------ ------ ------ Net Increase (Decrease) (825) (33) 14 ------ ------ ------ RETAINED EARNINGS (DEFICIT) AT END OF YEAR $ (280) $ 545 $ 578 ------ ------ ------ ------ ------ ------
The accompanying notes are an integral part of these statements. (Cleveland Electric) F-30 (Cleveland Electric) 83 CASH FLOWS THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES - --------------------------------------------------------------------------------
For the years ended December 31, ------------------------- 1993 1992 1991 ----- ----- ----- (millions of dollars) CASH FLOWS FROM OPERATING ACTIVITIES (1) Net Income (Loss) $(587) $ 205 $ 246 ----- ----- ----- Adjustments to Reconcile Net Income (Loss) to Cash from Operating Activities: Depreciation and amortization 182 179 171 Deferred federal income taxes (292) 66 51 Investment tax credits, net -- (8) 13 Deferred and unbilled revenues (6) (7) (25) Deferred fuel 4 6 13 Deferred carrying charges, net 487 (59) (88) Leased nuclear fuel amortization 47 70 69 Deferred operating expenses, net 27 (35) (7) Allowance for equity funds used during construction (4) (1) (8) Noncash early retirement program expenses, net 125 -- -- Write-off of Perry Unit 2 351 -- -- Changes in amounts due from customers and others, net 5 6 12 Changes in inventories 17 (2) (15) Changes in accounts payable 18 7 (24) Changes in working capital affecting operations 29 (4) 37 Other noncash items 5 (11) (13) ----- ----- ----- Total Adjustments 995 207 186 ----- ----- ----- Net Cash from Operating Activities 408 412 432 ----- ----- ----- CASH FLOWS FROM FINANCING ACTIVITIES (2) Bank loans, commercial paper and other short-term debt (10) 10 (87) Notes payable to affiliates (11) (13) 7 Debt issues: First mortgage bonds 280 324 -- Secured medium-term notes 35 90 150 Term bank loan 40 -- -- Preferred stock issues 100 74 125 Maturities, redemptions and sinking funds (345) (481) (133) Nuclear fuel lease obligations (59) (65) (64) Dividends paid (232) (235) (230) Premiums, discounts and expenses (11) (7) (5) ----- ----- ----- Net Cash from Financing Activities (213) (303) (237) ----- ----- ----- CASH FLOWS FROM INVESTING ACTIVITIES (2) Cash applied to construction (167) (152) (138) Interest capitalized as allowance for borrowed funds used during construction (4) -- (4) Loans to affiliates -- -- 11 Other cash received (applied) 19 (20) 2 ----- ----- ----- Net Cash from Investing Activities (152) (172) (129) ----- ----- ----- NET CHANGE IN CASH AND TEMPORARY CASH INVESTMENTS 43 (63) 66 ----- ----- ----- CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF YEAR 34 97 31 ----- ----- ----- CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR $ 77 $ 34 $ 97 ----- ----- ----- ----- ----- ----- - --------------- (1) Interest paid (net of amounts capitalized) was $204 million, $205 million and $221 million in 1993, 1992 and 1991, respectively. Income taxes paid were $28 million in both 1993 and 1992 and $50 million in 1991. (2) Increases in Nuclear Fuel and Nuclear Fuel Lease Obligations in the Balance Sheet resulting from the noncash capitalizations under nuclear fuel agreements are excluded from this statement.
The accompanying notes are an integral part of this statement. (Cleveland Electric) F-31 (Cleveland Electric) 84 BALANCE SHEET - ----------------------------------------------------------------------
December 31, ---------------- 1993 1992 ------ ------ (millions of dollars) ASSETS PROPERTY, PLANT AND EQUIPMENT Utility plant in service $6,734 $6,602 Less: accumulated depreciation and amortization 1,889 1,728 ------ ------ 4,845 4,874 Construction work in progress 141 130 Perry Unit 2 -- 371 ------ ------ 4,986 5,375 Nuclear fuel, net of amortization 202 224 Other property, less accumulated depreciation 41 37 ------ ------ 5,229 5,636 ------ ------ CURRENT ASSETS Cash and temporary cash investments 77 34 Amounts due from customers and others, net 156 161 Amounts due from affiliates 5 10 Unbilled revenues 99 93 Materials and supplies, at average cost 93 90 Fossil fuel inventory, at average cost 20 40 Taxes applicable to succeeding years 179 176 Other 3 3 ------ ------ 632 607 ------ ------ DEFERRED CHARGES AND OTHER ASSETS Amounts due from customers for future federal income taxes 586 583 Unamortized loss on reacquired debt 60 64 Carrying charges and operating expenses 519 1,033 Nuclear plant decommissioning trusts 30 23 Other 103 177 ------ ------ 1,298 1,880 ------ ------ Total Assets $7,159 $8,123 ------ ------ ------ ------
The accompanying notes are an integral part of this statement. (Cleveland Electric) F-32 (Cleveland Electric) 85 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
December 31, ----------------- 1993 1992 ------ ------ (millions of dollars) CAPITALIZATION AND LIABILITIES CAPITALIZATION Common shares, without par value: 105 million authorized; 79.6 million outstanding in 1993 and 1992 $1,241 $1,241 Other paid-in-capital 79 79 Retained earnings (deficit) (280) 545 ------ ------ Common stock equity 1,040 1,865 Preferred stock With mandatory redemption provisions 285 314 Without mandatory redemption provisions 241 144 Long-term debt 2,793 2,515 ------ ------ 4,359 4,838 ------ ------ OTHER NONCURRENT LIABILITIES Nuclear fuel lease obligations 151 177 Other 96 57 ------ ------ 247 234 ------ ------ CURRENT LIABILITIES Current portion of long-term debt and preferred stock 70 310 Current portion of nuclear fuel lease obligations 63 67 Notes payable to banks and others -- 10 Accounts payable 122 104 Accounts and notes payable to affiliates 61 50 Accrued taxes 305 291 Accrued interest 60 55 Other 52 37 ------ ------ 733 924 ------ ------ DEFERRED CREDITS Unamortized investment tax credits 235 250 Accumulated deferred federal income taxes 1,105 1,392 Unamortized gain from Bruce Mansfield Plant sale 343 359 Accumulated deferred rents for Bruce Mansfield Plant 77 70 Other 60 56 ------ ------ 1,820 2,127 ------ ------ Total Capitalization and Liabilities $7,159 $8,123 ------ ------ ------ ------
(Cleveland Electric) F-33 (Cleveland Electric) 86 STATEMENT OF PREFERRED STOCK THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES - ----------------------------------------------------------------------
Current December 31, 1993 Shares Call Price ------------- Outstanding Per Share 1993 1992 ----------- ---------- ---- ---- (millions of dollars) Without par value, 4,000,000 preferred shares authorized Subject to mandatory redemption: $ 7.35 Series C 150,000 $ 101.00 $ 15 $ 16 88.00 Series E 21,000 1,022.96 21 24 Adjustable Series M 200,000 100.00 20 30 9.125 Series N 600,000 103.04 59 74 91.50 Series Q 75,000 -- 75 75 88.00 Series R 50,000 -- 50 50 90.00 Series S 75,000 -- 74 74 ---- ---- 314 343 Less: Current maturities 29 29 ---- ---- TOTAL PREFERRED STOCK, WITH MANDATORY REDEMPTION PROVISIONS $285 $314 ---- ---- ---- ---- Not subject to mandatory redemption: $ 7.40 Series A 500,000 101.00 $ 50 $ 50 7.56 Series B 450,000 102.26 45 45 Adjustable Series L 500,000 103.00 49 49 Remarketed Series P -- -- -- 9 42.40 Series T 200,000 -- 97 -- ---- ---- 241 153 Less: Current maturities -- 9 ---- ---- TOTAL PREFERRED STOCK, WITHOUT MANDATORY REDEMPTION PROVISIONS $241 $144 ---- ---- ---- ----
The accompanying notes are an integral part of this statement. (Cleveland Electric) F-34 (Cleveland Electric) 87 NOTES TO THE FINANCIAL STATEMENTS - ---------------------------------------------------------------------- (1) Summary of Significant Accounting Policies (A) GENERAL The Company is an electric utility and a wholly owned subsidiary of Centerior Energy. Centerior Energy has two other wholly owned subsidiaries, Toledo Edison and the Service Company. The Company follows the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by The Public Utilities Commission of Ohio (PUCO). As a rate-regulated utility, the Company is subject to Statement of Financial Accounting Standards (SFAS) 71 which governs accounting for the effects of certain types of rate regulation. The financial statements include the accounts of the Company's wholly owned subsidiaries, which in the aggregate are not material. The Company is a member of the Central Area Power Coordination Group (CAPCO). Other members are Toledo Edison, Duquesne Light Company, Ohio Edison Company and its wholly owned subsidiary, Pennsylvania Power Company. The members have constructed and operate generation and transmission facilities for their use. (B) RELATED PARTY TRANSACTIONS Operating revenues, operating expenses and interest charges include those amounts for transactions with affiliated companies in the ordinary course of business operations. The Company's transactions with Toledo Edison are primarily for firm power, interchange power, transmission line rentals and jointly owned power plant operations and construction. See Notes 2 and 3. The Service Company provides management, financial, administrative, engineering, legal and other services at cost to the Company and other affiliated companies. The Service Company billed the Company $180 million, $150 million and $138 million in 1993, 1992 and 1991, respectively, for such services. (C) REVENUES Customers are billed on a monthly cycle basis for their energy consumption based on rate schedules or contracts authorized by the PUCO. An accrual is made at the end of each month to record the estimated amount of unbilled revenues for kilowatt-hours sold in the current month but not billed by the end of that month. A fuel factor is added to the base rates for electric service. This factor is designed to recover from customers the costs of fuel and most purchased power. It is reviewed and adjusted semiannually in a PUCO proceeding. (D) FUEL EXPENSE The cost of fossil fuel is charged to fuel expense based on inventory usage. The cost of nuclear fuel, including an interest component, is charged to fuel expense based on the rate of consumption. Estimated future nuclear fuel disposal costs are being recovered through the base rates. The Company defers the differences between actual fuel costs and estimated fuel costs currently being recovered from customers through the fuel factor. This matches fuel expenses with fuel-related revenues. Owners of nuclear generating plants are assessed by the federal government for the cost of decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy. The assessments are based upon the amount of enrichment services used in prior years and cannot be imposed for more than 15 years. The Company has accrued a liability for its share of the total assessments. These costs have been recorded in a deferred charge account since the PUCO is allowing the Company to recover the assessments through its fuel cost factors. (E) DEFERRED CARRYING CHARGES AND OPERATING EXPENSES The PUCO authorized the Company to defer operating expenses and carrying charges for Perry Unit 1 and Beaver Valley Power Station Unit 2 (Beaver Valley Unit 2) from their respective in-service dates in 1987 through December 1988. The annual amortization and recovery of these deferrals, called pre-phase-in deferrals, are $10 million which began in January 1989 and will continue over the lives of the related property. Beginning in January 1989, the Company deferred certain operating expenses and both interest and equity carrying charges pursuant to a PUCO-approved rate phase-in plan for its investments in Perry Unit 1 and Beaver Valley Unit 2. These deferrals, called phase-in deferrals, were written off at December 31, 1993. See Note 7. The Company also defers certain costs not currently recovered in rates under a Rate Stabilization Program approved by the PUCO in October 1992. See Notes 7 and 14. (F) DEPRECIATION AND AMORTIZATION The cost of property, plant and equipment is depreciated over their estimated useful lives on a straight-line basis. The annual straight-line depreciation provision for nonnuclear property expressed as a percent of average depre- (Cleveland Electric) F-35 (Cleveland Electric) 88 ciable utility plant in service was 3.4% in 1993, 1992 and 1991. Effective January 1, 1991, the Company, after obtaining PUCO approval, changed its method of accounting for nuclear plant depreciation from the units-of-production method to the straight-line method at about a 3% rate. This change decreased 1991 depreciation expense $22 million and increased 1991 net income $17 million (net of $5 million of income taxes) from what they otherwise would have been. The PUCO subsequently approved in 1991 a change to lower the 3% rate to 2.5% retroactive to January 1, 1991. Pursuant to a PUCO order, the Company currently uses external funding for the future decommissioning of its nuclear units at the end of their licensed operating lives. The estimated costs are based on the NRC's DECON method of decommissioning (prompt decontamination). Cash contributions are made to the trust funds on a straight-line basis over the remaining licensing period for each unit. The current level of annual expense being recovered from customers based on prior estimates is approximately $4 million. However, actual decommissioning costs are expected to significantly exceed those estimates. Current site-specific estimates for the Company's share of the future decommissioning costs are $51 million in 1992 dollars for Beaver Valley Unit 2 and $136 million and $154 million in 1993 dollars for Perry Unit 1 and the Davis-Besse Nuclear Power Station (Davis-Besse), respectively. The estimates for Perry Unit 1 and Davis-Besse are preliminary and are expected to be finalized by the end of the second quarter of 1994. The Company used these estimates to increase its decommissioning expense accruals in 1993. It is expected that the increases associated with the revised cost estimates will be recoverable in future rates. In the Balance Sheet at December 31, 1993, Accumulated Depreciation and Amortization included $41 million of decommissioning costs previously expensed and the earnings on the external funding. This amount exceeds the Balance Sheet amount of the external Nuclear Plant Decommissioning Trusts because the reserve began prior to the external trust funding. (G) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment are stated at original cost less amounts ordered by the PUCO to be written off. Construction costs include related payroll taxes, pensions, fringe benefits, management and general overheads and allowance for funds used during construction (AFUDC). AFUDC represents the estimated composite debt and equity cost of funds used to finance construction. This noncash allowance is credited to income. The AFUDC rate was 9.63% in 1993, 10.56% in 1992 and 10.47% in 1991. Maintenance and repairs are charged to expense as incurred. The cost of replacing plant and equipment is charged to the utility plant accounts. The cost of property retired plus removal costs, after deducting any salvage value, is charged to the accumulated provision for depreciation. (H) DEFERRED GAIN FROM SALE OF UTILITY PLANT The sale and leaseback transaction discussed in Note 2 resulted in a net gain for the sale of the Bruce Mansfield Generating Plant (Mansfield Plant). The net gain was deferred and is being amortized over the term of leases. The amortization and the lease expense amounts are recorded as other operation and maintenance expenses. (I) INTEREST CHARGES Debt Interest reported in the Income Statement does not include interest on obligations for nuclear fuel under construction. That interest is capitalized. See Note 6. Losses and gains realized upon the reacquisition or redemption of long-term debt are deferred, consistent with the regulatory rate treatment. Such losses and gains are either amortized over the remainder of the original life of the debt issue retired or amortized over the life of the new debt issue when the proceeds of a new issue are used for the debt redemption. The amortizations are included in debt interest expense. (J) FEDERAL INCOME TAXES The Financial Accounting Standards Board (FASB) issued SFAS 109, a new standard for accounting for income taxes, in February 1992. We adopted the new standard in 1992. The standard amended certain provisions of SFAS 96 which we had previously adopted. Adoption of SFAS 109 in 1992 did not materially affect our results of operations, but did affect certain Balance Sheet accounts. See Note 8. The financial statements reflect the liability method of accounting for income taxes. This method requires that deferred taxes be recorded for all temporary differences between the book and tax bases of assets and liabilities. The majority of these temporary differences are attributable to property-related basis differences. Included in these basis differences is the equity component of AFUDC, which will increase future tax expense when it is recovered through rates. Since this component is not recognized for tax purposes, we must record a liability for our tax obligation. The PUCO permits recovery of such taxes from customers when they become payable. Therefore, the net amount due from customers through rates has been recorded as a deferred charge and will be recovered over the lives of the related assets. (Cleveland Electric) F-36 (Cleveland Electric) 89 Investment tax credits are deferred and amortized over the lives of the applicable property as a reduction of depreciation expense. See Note 7 for a discussion of the amortization of certain unrestricted excess deferred taxes and unrestricted investment tax credits under the Rate Stabilization Program. (2) Utility Plant Sale and Leaseback Transactions The Company and Toledo Edison are co-lessees of 18.26% (150 megawatts) of Beaver Valley Unit 2 and 6.5% (51 megawatts), 45.9% (358 megawatts) and 44.38% (355 megawatts) of Units 1, 2 and 3 of the Mansfield Plant, respectively, all for terms of about 29 1/2 years. These leases are the result of sale and leaseback transactions completed in 1987. Under these leases, the Company and Toledo Edison are responsible for paying all taxes, insurance premiums, operation and maintenance expenses and all other similar costs for their interests in the units sold and leased back. They may incur additional costs in connection with capital improvements to the units. The Company and Toledo Edison have options to buy the interests back at the end of the leases for the fair market value at that time or to renew the leases. Additional lease provisions provide other purchase options along with conditions for mandatory termination of the leases (and possible repurchase of the leasehold interests) for events of default. These events include noncompliance with several financial covenants discussed in Note 11(d). As co-lessee with Toledo Edison, the Company is also obligated for Toledo Edison's lease payments. If Toledo Edison is unable to make its payments under the Beaver Valley Unit 2 and Mansfield Plant leases, the Company would be obligated to make such payments. No payments have been made on behalf of Toledo Edison to date. Future minimum lease payments under the operating leases at December 31, 1993 are summarized as follows:
For For the Toledo Year Company Edison - ------------------------------------ ------- ------------- (millions of dollars) 1994 $ 63 $ 103 1995 63 102 1996 63 125 1997 63 102 1998 63 102 Later Years 1,391 2,021 ------- ------ Total Future Minimum Lease Payments $1,706 $ 2,555 ------- ------ ------- ------
Rental expense is accrued on a straight-line basis over the terms of the leases. The amount recorded in 1993, 1992 and 1991 as annual rental expense for the Mansfield Plant leases was $70 million. Amounts charged to expense in excess of the lease payments are classified as Accumulated Deferred Rents in the Balance Sheet. The Company is buying 150 megawatts of Toledo Edison's Beaver Valley Unit 2 leased capacity entitlement. We anticipate that this purchase will continue indefinitely. Purchased power expense for this transaction was $103 million, $108 million and $107 million in 1993, 1992 and 1991, respectively. The future minimum lease payments through the year 2017 associated with Beaver Valley Unit 2 aggregate $1.47 billion. (3) Property Owned with Other Utilities and Investors The Company owns, as a tenant in common with other utilities and those investors who are owner-participants in various sale and leaseback transactions (Lessors), certain generating units as listed below. Each owner owns an undivided share in the entire unit. Each owner has the right to a percentage of the generating capability of each unit equal to its ownership share. Each utility owner is obligated to pay for only its respective share of the construction costs and operating expenses. Each Lessor has leased its capacity rights to a utility which is obligated to pay for such Lessor's share of the construction costs and operating expenses. The Company's share of the operating expenses of these generating units is included in the Income Statement. The Balance Sheet classification of Property, Plant and Equipment at December 31, 1993 includes the following facilities owned by the Operating Company as a tenant in common with other utilities and Lessors:
In- Plant Construction Service Ownership Ownership Power in Work in Accumulated Generating Unit Date Share Megawatts Source Service Progress Depreciation - ------------------------------- ------- --------- --------- -------- ------- ------------ ----------- (millions of dollars) Seneca Pumped Storage 1970 80.00% 351 Hydro $ 67 $ -- $ 22 Eastlake Unit 5 1972 68.80 411 Coal 156 2 -- Davis-Besse 1977 51.38 454 Nuclear 700 5 179 Perry Unit 1 1987 31.11 371 Nuclear 1,781 8 287 Beaver Valley Unit 2 and Common Facilities (Note 2) 1987 24.47 201 Nuclear 1,277 2 219 ------- --- ----- Total $3,981 $ 17 $ 707 ------- --- ----- ------- --- -----
Depreciation for Eastlake Unit 5 has been accumulated with all other nonnuclear depreciable property rather than by specific units of depreciable property. (Cleveland Electric) F-37 (Cleveland Electric) 90 (4) Construction and Contingencies (A) CONSTRUCTION PROGRAM The estimated cost of the Company's construction program for the 1994-1998 period is $829 million, including AFUDC of $38 million and excluding nuclear fuel. The Clean Air Act will require, among other things, significant reductions in the emission of sulfur dioxide in two phases over a ten-year period and nitrogen oxides by fossil-fueled generating units. Our compliance strategy provides for compliance with both phases through at least 2005 primarily through greater use of low-sulfur coal at some of our units and the banking of emission allowances. The plan will require capital expenditures over the 1994-2003 period of approximately $165 million for nitrogen oxide control equipment, emission monitoring equipment and plant modifications. In addition, higher fuel and other operation and maintenance expenses will be incurred. The anticipated rate increase associated with the capital expenditures and higher expenses would be about 1-2% in the late 1990s. The Company may need to install sulfur emission control technology at one of its generating plants after 2005 which could require additional expenditures at that time. The PUCO has approved this plan. We also are seeking United States Environmental Protection Agency (U.S. EPA) approval of the first phase of our plan. We are continuing to monitor developments in new technologies that may be incorporated into our compliance strategy. If a different plan is required by the U.S. EPA, significantly higher capital expenditures could be required during the 1994-2003 period. We believe Ohio law permits the recovery of compliance costs from customers in rates. (B) PERRY UNIT 2 Perry Unit 2, including its share of the facilities common with Perry Unit 1, was approximately 50% complete when construction was suspended in 1985 pending consideration of various options. These options included resumption of full construction with a revised estimated cost, conversion to a nonnuclear design, sale of all or part of our ownership share, or cancellation. We wrote off our investment in Perry Unit 2 at December 31, 1993 after we determined that it would not be completed or sold. The write-off totaled $351 million ($258 million after taxes) for the Company's 44.85% ownership share of the unit. See Note 14. (C) HAZARDOUS WASTE DISPOSAL SITES The Company is aware of its potential involvement in the cleanup of three sites listed on the Superfund List and several other waste sites not on such list. The Company has accrued a liability totaling $13 million at December 31, 1993 based on estimates of the costs of cleanup and its proportionate responsibility for such costs. We believe that the ultimate outcome of these matters will not have a material adverse effect on our financial condition or results of operations. See Management's Financial Analysis -- Outlook-Hazardous Waste Disposal Sites. (5) Nuclear Operations and Contingencies (A) OPERATING NUCLEAR UNITS The Company's three nuclear units may be impacted by activities or events beyond our control. An extended outage of one of our nuclear units for any reason, coupled with any unfavorable rate treatment, could have a material adverse effect on our financial condition and results of operations. See discussion of these risks in Management's Financial Analysis -- Outlook-Nuclear Operations. (B) NUCLEAR INSURANCE The Price-Anderson Act limits the liability of the owners of a nuclear power plant to the amount provided by private insurance and an industry assessment plan. In the event of a nuclear incident at any unit in the United States resulting in losses in excess of the level of private insurance (currently $200 million), the Company's maximum potential assessment under that plan would be $85 million (plus any inflation adjustment) per incident. The assessment is limited to $11 million per year for each nuclear incident. These assessment limits assume the other CAPCO companies contribute their proportionate share of any assessment. The CAPCO companies have insurance coverage for damage to property at the Davis-Besse, Perry and Beaver Valley sites (including leased fuel and clean-up costs). Coverage amounted to $2.75 billion for each site as of January 1, 1994. Damage to property could exceed the insurance coverage by a substantial amount. If it does, the Company's share of such excess amount could have a material adverse effect on its financial condition and results of operations. Under these policies, the Company can be assessed a maximum of $14 million during a policy year if the reserves available to the insurer are inadequate to pay claims arising out of an accident at any nuclear facility covered by the insurer. The Company also has extra expense insurance coverage. It includes the incremental cost of any replacement power purchased (over the costs which would have been (Cleveland Electric) F-38 (Cleveland Electric) 91 incurred had the units been operating) and other incidental expenses after the occurrence of certain types of accidents at our nuclear units. The amounts of the coverage are 100% of the estimated extra expense per week during the 52-week period starting 21 weeks after an accident and 67% of such estimate per week for the next 104 weeks. The amount and duration of extra expense could substantially exceed the insurance coverage. (6) Nuclear Fuel Nuclear fuel is financed for the Company and Toledo Edison through leases with a special-purpose corporation. The total amount of financing currently available under these lease arrangements is $382 million ($232 million from intermediate-term notes and $150 million from bank credit arrangements). Financing in an amount up to $750 million is permitted. The intermediate-term notes mature in the period 1994-1997, with $75 million maturing in September 1994. At December 31, 1993, $216 million of nuclear fuel was financed for the Company. The Company and Toledo Edison severally lease their respective portions of the nuclear fuel and are obligated to pay for the fuel as it is consumed in a reactor. The lease rates are based on various intermediate-term note rates, bank rates and commercial paper rates. The amounts financed include nuclear fuel in the Davis-Besse, Perry Unit 1 and Beaver Valley Unit 2 reactors with remaining lease payments for the Company of $57 million, $48 million and $26 million, respectively, at December 31, 1993. The nuclear fuel amounts financed and capitalized also included interest charges incurred by the lessors amounting to $9 million in both 1993 and 1992 and $12 million in 1991. The estimated future lease amortization payments based on projected consumption are $63 million in 1994, $56 million in 1995, $50 million in 1996, $44 million in 1997 and $39 million in 1998. (7) Regulatory Matters Phase-in deferrals were recorded beginning in 1989 pursuant to the phase-in plan approved by the PUCO in a January 1989 rate order for the Company. The phase-in plan was designed so that the projected revenues resulting from the authorized rate increases and anticipated sales growth provided for the phase-in of certain nuclear costs over a ten-year period. The plan required the deferral of a portion of the operating expenses and both interest and equity carrying charges on the Company's deferred rate-based investments in Perry Unit 1 and Beaver Valley Unit 2 during the early years of the plan. The amortization and recovery of such deferrals were scheduled to be completed by 1998. As we developed our strategic plan, we evaluated the future recovery of our deferred charges and continued application of the regulatory accounting measures we follow pursuant to PUCO orders. We concluded that projected revenues would not provide for the recovery of the phase-in deferrals as scheduled because of economic and competitive pressures. Accordingly, we wrote off the cumulative balance of the phase-in deferrals. The total phase-in deferred operating expenses and carrying charges written off at December 31, 1993 by the Company were $117 million and $519 million, respectively (totaling $433 million after taxes). See Note 14. While recovery of our other regulatory deferrals remains probable, our current assessment of business conditions has prompted us to change our future plans. We decided that, once the deferral of expenses and acceleration of benefits under our Rate Stabilization Program are completed in 1995, we should no longer plan to use regulatory accounting measures to the extent we have in the past. In October 1992, the PUCO approved a Rate Stabilization Program that was designed to encourage economic growth in the Company's service area by freezing the Company's base rates until 1996 and limiting subsequent rate increases to specified annual amounts not to exceed $216 million over the 1996-1998 period. As part of the Rate Stabilization Program, the Company is allowed to defer and subsequently recover certain costs not currently recovered in rates and to accelerate amortization of certain benefits. Such regulatory accounting measures provide for rate stabilization by rescheduling the timing of rate recovery of certain costs and the amortization of certain benefits during the 1992-1995 period. The continued use of these regulatory accounting measures will be dependent upon our continuing assessment and conclusion that there will be probable recovery of such deferrals in future rates. The regulatory accounting measures we are eligible to record through December 31, 1995 include the deferral of post-in-service interest carrying charges, depreciation expense and property taxes on assets placed in service after February 29, 1988. The cost deferrals recorded in 1993 and 1992 pursuant to these provisions were $56 million and $52 million, respectively. Amortization and recovery of these deferrals will occur over the average life of the related assets, approximately 30 years, and will commence with future rate recognition. The regulatory accounting measures also provide for the accelerated amortization of certain unrestricted excess deferred tax and unrestricted investment tax credit balances and interim spent fuel storage accrual balances for Davis-Besse. The total amount of such regulatory benefits recognized in 1993 and 1992 pursuant to these provisions was $28 million and $7 million, respectively. The Rate Stabilization Program also authorized the Company to defer and subsequently recover the incremental (Cleveland Electric) F-39 (Cleveland Electric) 92 expenses associated with the adoption of the accounting standard for postretirement benefits other than pensions (SFAS 106). In 1993, we deferred $60 million pursuant to this provision. Amortization and recovery of this deferral will commence prior to 1998 and is expected to be completed by no later than 2012. See Note 9(b). (8) Federal Income Tax Federal income tax, computed by multiplying income before taxes by the statutory rate (35% in 1993 and 34% in both 1992 and 1991), is reconciled to the amount of federal income tax recorded on the books as follows:
1993 1992 1991 ----- ---- ---- (millions of dollars) Book Income (Loss) Before Federal Income Tax $(835) $299 $376 ----- ---- ---- ----- ---- ---- Tax (Credit) on Book Income (Loss) at Statutory Rate $(292) $102 $128 Increase (Decrease) in Tax: Write-off of Perry Unit 2 30 -- -- Write-off of phase-in deferrals 20 -- -- Depreciation 6 (3) (2) Rate Stabilization Program (20) (5) -- Other items 8 -- 4 ----- ---- ---- Total Federal Income Tax Expense (Credit) $(248) $ 94 $130 ----- ---- ---- ----- ---- ----
Federal income tax expense is recorded in the Income Statement as follows:
1993 1992 1991 ----- ---- ---- (millions of dollars) Operating Expenses: Current Tax Provision $ 64 $ 47 $ 75 Changes in Accumulated Deferred Federal Income Tax: Write-off of deferred operating expenses (26) -- -- Accelerated depreciation and amortization 60 32 9 Alternative minimum tax credit (19) (18) (3) Retirement and postemployment benefits (24) -- -- Sale and leaseback transactions and amortization 4 4 (9) Taxes, other than federal income taxes (18) 14 -- Rate Stabilization Program (8) 2 -- Reacquired debt costs (2) 6 16 Deferred fuel costs (2) (2) (5) Other items (7) 4 12 Investment Tax Credits -- -- 11 ----- ---- ---- Total Charged to Operating Expenses 22 89 106 ----- ---- ---- Nonoperating Income: Current Tax Provision (20) (19) (8) Changes in Accumulated Deferred Federal Income Tax: Write-off of deferred carrying charges (177) -- -- Write-off of Perry Unit 2 (93) -- -- Disallowed nuclear costs 6 7 -- Rate Stabilization Program 7 6 -- AFUDC and carrying charges 7 14 32 Other items -- (3) -- ----- ---- ---- Total Expense (Credit) to Nonoperating Income (270) 5 24 ----- ---- ---- Total Federal Income Tax Expense (Credit) $(248) $ 94 $130 ----- ---- ---- ----- ---- ----
The Company joins in the filing of a consolidated federal income tax return with its affiliated companies. The method of tax allocation reflects the benefits and burdens realized by each company's participation in the consolidated tax return, approximating a separate return result for each company. In August 1993, the 1993 Tax Act was enacted. Retroactive to January 1, 1993, the top marginal corporate income tax rate increased to 35%. The change in tax rate increased Accumulated Deferred Federal Income Taxes for the future tax obligation by approximately $61 million. Since the PUCO has historically permitted recovery of such taxes from customers when they become payable, the deferred charge, Amounts Due from Customers for Future Federal Income Taxes, also was increased by $61 million. The 1993 Tax Act is not expected to materially impact future results of operations or cash flow. Under SFAS 109, temporary differences and carryforwards resulted in deferred tax assets of $426 million and deferred tax liabilities of $1.531 billion at December 31, 1993 and deferred tax assets of $415 million and deferred tax liabilities of $1.807 billion at December 31, 1992. These are summarized as follows:
December 31, --------------- 1993 1992 ------ ------ (millions of dollars) Property, plant and equipment $1,311 $1,468 Deferred carrying charges and operating 127 249 expenses Sale and leaseback transactions (126) (123) Net operating loss carryforwards (69) (79) Investment tax credits (128) (132) Other (10) 9 ------ ------ Net deferred tax liability $1,105 $1,392 ------ ------ ------ ------
For tax purposes, net operating loss (NOL) carryforwards of approximately $197 million are available to reduce future taxable income and will expire in 2003 through 2005. The 35% tax effect of the NOLs is $69 million. The Tax Reform Act of 1986 provides for an alternative minimum tax (AMT) credit to be used to reduce the regular tax to the AMT level should the regular tax exceed the AMT. AMT credits of $94 million are available to offset future regular tax. The credits may be carried forward indefinitely. (9) Retirement and Postemployment Benefits (A) RETIREMENT INCOME PLAN Prior to December 31, 1993, the Company and Service Company jointly sponsored a noncontributing pension plan which covered all employee groups. The plan was merged with another plan which covered the employees of Toledo Edison into a single plan on December 31, 1993. The amount of retirement benefits generally depends (Cleveland Electric) F-40 (Cleveland Electric) 93 upon the length of service. Under certain circumstances, benefits can begin as early as age 55. The funding policy is to comply with the Employee Retirement Income Security Act of 1974 guidelines. In 1993, the Company and Service Company offered the VTP, an early retirement program. Operating expenses for both companies for 1993 included $146 million of pension plan accruals to cover enhanced VTP benefits and an additional $7 million of pension costs for VTP benefits paid to retirees from corporate funds. The $7 million is not included in the pension data reported below. A credit of $66 million resulting from a settlement of pension obligations through lump sum payments to almost all the VTP retirees partially offset the VTP expenses. Net pension and VTP costs (credits) for 1991 through 1993 were comprised of the following components:
1993 1992 1991 ---- ---- ---- (millions of dollars) Pension Costs (Credits): Service cost for benefits earned during the period $ 10 $ 10 $ 9 Interest cost on projected benefit obligation 26 27 25 Actual return on plan assets (50) (19) (99) Net amortization and deferral 2 (35) 50 ---- ---- ---- Net pension costs (credits) (12) (17) (15) VTP cost 146 -- -- Settlement gain (66) -- -- ---- ---- ---- Net costs (credits) $ 68 $(17) $(15) ---- ---- ---- ---- ---- ----
The following table presents a reconciliation of the funded status of the former plan of the Company and Service Company at December 31, 1992 with comparable information for a portion of the merged plan at December 31, 1993. The December 31, 1993 benefit obligation estimates were derived from information for the former plans. Plan assets of the merged plan were allocated based on a pro rata share of the projected benefit obligation.
1993 1992 ---- ---- (millions of dollars) Actuarial present value of benefit obligations: Vested benefits $231 $215 Nonvested benefits 26 28 ---- ---- Accumulated benefit obligation 257 243 Effect of future compensation levels 37 86 ---- ---- Total projected benefit obligation 294 329 Plan assets at fair market value 268 585 ---- ---- Funded status (26) 256 Unrecognized net loss (gain) from variance between assumptions and experience 61 (107) Unrecognized prior service cost 6 7 Transition asset at January 1, 1987 being amortized over 19 years (35) (82) ---- ---- Net prepaid pension cost $ 6 $ 74 ---- ---- ---- ----
At December 31, 1993, the settlement (discount) rate and long-term rate of return on plan assets assumptions were 7.25% and 8.75%, respectively. The long-term rate of annual compensation increase assumption was 4.25%. At December 31, 1992, the settlement rate and long-term rate of return on plan assets assumptions were 8.5% and the long-term rate of annual compensation increase assumption was 5%. Plan assets consist primarily of investments in common stock, bonds, guaranteed investment contracts, cash equivalent securities and real estate. (B) OTHER POSTRETIREMENT BENEFITS Centerior Energy sponsors jointly with its subsidiaries a postretirement benefit plan which provides all employee groups certain health care, death and other postretirement benefits other than pensions. The plan is contributory, with retiree contributions adjusted annually. The plan is not funded. A policy limiting the employer's contribution for retiree medical coverage for employees retiring after March 31, 1993 was implemented in February 1993. The Company adopted SFAS 106, the accounting standard for postretirement benefits other than pensions, effective January 1, 1993. The standard requires the accrual of the expected costs of such benefits during the employees' years of service. Previously, the costs of these benefits were expensed as paid, which is consistent with ratemaking practices. Such costs for the Company totaled $5 million in 1992 and $6 million in 1991, which included medical benefits of $4 million in 1992 and $5 million in 1991. The total amount accrued by the Company for SFAS 106 costs for 1993 was $69 million, of which $4 million was capitalized and $65 million was expensed as other operation and maintenance expenses. In 1993, the Company deferred incremental SFAS 106 expenses totaling $60 million pursuant to a provision of the Rate Stabilization Program. See Note 7. The components of the total postretirement benefit costs for 1993 were as follows:
Millions of Dollars ---------- Service cost for benefits earned $ 2 Interest cost on accumulated postretirement benefit obligation 10 Amortization of transition obligation at January 1, 1993 of $104 million over 20 years 5 VTP curtailment cost (includes $10 million transition obligation adjustment) 52 --- Total costs $ 69 --- ---
These amounts included costs for the Company and a pro rata share of the Service Company's costs. The accumulated postretirement benefit obligation and accrued postretirement benefit cost at December 31, 1993 (Cleveland Electric) F-41 (Cleveland Electric) 94 for the Company and its share of the Service Company's obligation are summarized as follows:
Millions of Dollars ---------- Accumulated postretirement benefit obligation attributable to: Retired participants $ (141) Fully eligible active plan participants (1) Other active plan participants (19) ---------- Accumulated postretirement benefit obligation (161) Unrecognized net loss from variance between assumptions and experience 9 Unamortized transition obligation 89 ---------- Accrued postretirement benefit cost $ (63) ---------- ----------
The Balance Sheet classification of Other Noncurrent Liabilities at December 31, 1993 includes only the Company's accrued postretirement benefit cost of $52 million and excludes the Service Company's portion since the Service Company's total accrued cost is carried on its books. At December 31, 1993, the settlement rate and the long-term rate of annual compensation increase assumptions were 7.25% and 4.25%, respectively. The assumed annual health care cost trend rates (applicable to gross eligible charges) are 9.5% for medical and 8% for dental in 1994. Both rates reduce gradually to a fixed rate of 4.75% in 1996 and later years. Elements of the obligation affected by contribution caps are significantly less sensitive to the health care cost trend rate than other elements. If the assumed health care cost trend rates were increased by 1% in each future year, the accumulated postretirement benefit obligation as of December 31, 1993 would increase by $7 million and the aggregate of the service and interest cost components of the annual postretirement benefit cost would increase by $0.5 million. (C) POSTEMPLOYMENT BENEFITS In 1993, the Company adopted SFAS 112, the new accounting standard which requires the accrual of postemployment benefit costs. Postemployment benefits are the benefits provided to former or inactive employees after employment but before retirement, such as worker's compensation, disability benefits and severance pay. The adoption of this accounting method did not materially affect the Company's 1993 results of operations or financial position. (10) Guarantees The Company has guaranteed certain loan and lease obligations of two mining companies under two long-term coal purchase arrangements. One of these arrangements requires payments to the mining company for any actual expenses (as advance payments for coal) when the mines are idle for reasons beyond the control of the mining company. At December 31, 1993, the principal amount of the mining companies' loan and lease obligations guaranteed by the Company was $60 million. (11) Capitalization (A) CAPITAL STOCK TRANSACTIONS Preferred stock shares sold and retired during the three years ended December 31, 1993 are listed in the following table.
1993 1992 1991 ----- ----- ----- (thousands of shares) Subject to Mandatory Redemption: Sales $ 91.50 Series Q -- -- 75 88.00 Series R -- -- 50 90.00 Series S -- 75 -- Retirements $ 7.35 Series C (10) (10) (10) 88.00 Series E (3) (3) (3) 75.00 Series F -- -- (2) 145.00 Series I -- -- (14) 113.50 Series K -- -- (10) Adjustable Series M (100) (100) (100) 9.125 Series N (150) -- -- Not Subject to Mandatory Redemption: Sales $ 42.40 Series T 200 -- -- Retirements Remarketed Series P -- (1) -- ----- ----- ----- Net (Decrease) (63) (39) (14) ----- ----- ----- ----- ----- -----
(B) EQUITY DISTRIBUTION RESTRICTIONS Federal law prohibits the Company from paying dividends out of capital accounts. However, the Company may pay preferred and common stock dividends out of appropriated retained earnings and current earnings. At December 31, 1993, the Company had $125 million of appropriated retained earnings for the payment of preferred and common stock dividends. (C) PREFERRED AND PREFERENCE STOCK Amounts to be paid for preferred stock which must be redeemed during the next five years are $29 million in 1994, $40 million in 1995, $30 million in both 1996 and 1997 and $15 million in 1998. The annual preferred stock mandatory redemption provisions are as follows:
Shares Price To Be Beginning Per Redeemed in Share -------- --------- ------ $ 7.35 Series C 10,000 1984 $ 100 88.00 Series E 3,000 1981 1,000 Adjustable Series M 100,000 1991 100 9.125 Series N 150,000 1993 100 91.50 Series Q 10,714 1995 1,000 88.00 Series R 50,000 2001* 1,000 90.00 Series S 18,750 1999 1,000
* All outstanding shares to be redeemed on December 1, 2001. In June 1993, the Company issued $100 million principal amount of Serial Preferred Stock, $42.40 Series T. The Series T stock was deposited with an agent which issued (Cleveland Electric) F-42 (Cleveland Electric) 95 Depositary Receipts, each representing 1/20 of a share of the Series T stock. The annualized preferred dividend requirement at December 31, 1993 was $47 million. The preferred dividend rates on the Company's Series L and M fluctuate based on prevailing interest rates and market conditions. The dividend rates for both issues averaged 7% in 1993. The Company's Series P had a 6.5% dividend rate in 1993 until it was redeemed in August 1993. Preference stock authorized for the Company is 3,000,000 shares without par value. No preference shares are currently outstanding. With respect to dividend and liquidation rights, the Company's preferred stock is prior to its preference stock and common stock, and its preference stock is prior to its common stock. (D) LONG-TERM DEBT AND OTHER BORROWING ARRANGEMENTS Long-term debt, less current maturities, was as follows:
Actual or Average Interest Rate at December 31, December 31, --------------- Year of Maturity 1993 1993 1992 - -------------------------------- ------------ ------ ------ (millions of dollars) First mortgage bonds: 1994 4.375% $ -- $ 25 1994 13.75 -- 4 1995 13.75 4 4 1995 7.00 1 1 1996 13.75 4 4 1996 7.00 1 1 1997 10.88 6 6 1997 13.75 4 4 1997 7.00 1 1 1998 10.88 6 6 1998 13.75 4 4 1998 7.00 1 1 1999-2003 8.06 406 306 2004-2008 8.48 115 119 2009-2013 8.08 405 405 2014-2018 8.07 513 513 2019-2023 8.23 518 368 ------ ------ 1,989 1,772 Secured medium term notes due 1995-2021 8.88 713 678 Term bank loans due 1995-1996 4.07 45 8 Pollution control notes due 1995-2012 6.31 53 53 Other -- net -- (7) 4 ------ ------ Total Long-Term Debt $2,793 $2,515 ------ ------ ------ ------
Long-term debt matures during the next five years as follows: $42 million in 1994, $246 million in 1995, $151 million in 1996, $55 million in 1997 and $78 million in 1998. The Company issued $275 million aggregate principal amount of secured medium-term notes during the 1991-1993 period. The notes are secured by first mortgage bonds. The Company's mortgage constitutes a direct first lien on substantially all property owned and franchises held by the Company. Excluded from the lien, among other things, are cash, securities, accounts receivable, fuel and supplies. An unsecured loan agreement of the Company contains covenants relating to capitalization ratios, fixed charge coverage ratios and limitations on secured financing other than through first mortgage bonds or certain other transactions. Two reimbursement agreements relating to separate letters of credit issued in connection with the sale and leaseback of Beaver Valley Unit 2 contain several financial covenants affecting the Company, Toledo Edison and Centerior Energy. Among these are covenants relating to fixed charge coverage ratios and capitalization ratios. The write-offs recorded at December 31, 1993 caused the Company, Toledo Edison and Centerior Energy to violate certain covenants contained in the loan agreement and the two reimbursement agreements. The affected creditors have waived those violations in exchange for commitments to provide them with a second mortgage security interest on property of the Company and Toledo Edison and other considerations. We expect to complete this process in the second quarter of 1994. We will provide the same security interest to certain other creditors because their agreements require equal treatment. We expect to provide second mortgage collateral for $47 million of unsecured debt, $228 million of bank letters of credit and a $205 million revolving credit facility. The bank letters of credit and revolving credit facility are joint and several obligations of the Company and Toledo Edison. (12) Short-Term Borrowing Arrangements In May 1993, Centerior Energy arranged for a $205 million, three-year revolving credit facility. The facility may be renewed twice for one-year periods at the option of the participating banks. Centerior Energy and the Service Company may borrow under the facility, with all borrowings jointly and severally guaranteed by the Company and Toledo Edison. Centerior Energy plans to transfer any of its borrowed funds to the Company and Toledo Edison, while the Service Company may borrow up to $25 million for its own use. The banks' fee is 0.5% per annum payable quarterly in addition to interest on any borrowings. That fee is expected to increase to 0.625% when the facility agreement is amended as discussed (Cleveland Electric) F-43 (Cleveland Electric) 96 below. There were no borrowings under the facility at December 31, 1993. The facility agreement contains covenants relating to capitalization and fixed charge coverage ratios for the Company, Toledo Edison and Centerior Energy. The write-offs recorded at December 31, 1993 caused the ratios to fall below those covenant requirements. The revolving credit facility is expected to be available for borrowings after the facility agreement is amended in the second quarter of 1994 to provide the participating creditors with a second mortgage security interest. Short-term borrowing capacity authorized by the PUCO annually is $300 million for the Company. The Company and Toledo Edison are authorized by the PUCO to borrow from each other on a short-term basis. At December 31, 1993, the Company had no commercial paper outstanding. The Company is unable to rely on the sale of commercial paper to provide short-term funds because of its below investment grade commercial paper credit ratings. (13) Financial Instruments' Fair Value The estimated fair values at December 31, 1993 and 1992 of financial instruments that do not approximate their carrying amounts are as follows:
December 31, ---------------------------------- 1993 1992 ---------------- ---------------- Carrying Fair Carrying Fair Amount Value Amount Value -------- ------ -------- ------ (millions of dollars) Nuclear Plant Decommissioning Trusts $ 30 $ 32 $ 23 $ 24 Preferred Stock, with Mandatory Redemption Provisions (including current portion) 314 307 343 342 Long-Term Debt (including current portion) 2,841 2,946 2,793 2,886
The fair value of the nuclear plant decommissioning trusts is estimated based on the quoted market prices for the investment securities. The fair value of the Company's preferred stock with mandatory redemption provisions and long-term debt is estimated based on the quoted market prices for the respective or similar issues or on the basis of the discounted value of future cash flows. The discounted value used current dividend or interest rates (or other appropriate rates) for similar issues and loans with the same remaining maturities. The estimated fair values of all other financial instruments approximate their carrying amounts in the Balance Sheet at December 31, 1993 and 1992 because of their short-term nature. (14) Quarterly Results of Operations (Unaudited) The following is a tabulation of the unaudited quarterly results of operations for the two years ended December 31, 1993.
Quarters Ended ---------------------------------------- March 31, June 30, Sept. 30, Dec. 31, --------- -------- --------- -------- (millions of dollars) 1993 Operating Revenues $ 421 $417 $ 507 $ 406 Operating Income (Loss) 82 85 89 (32) Net Income (Loss) 33 30 39 (689) Earnings (Loss) Available for Common Stock 23 19 27 (701) 1992 Operating Revenues $ 422 $415 $ 479 $ 427 Operating Income 83 85 139 77 Net Income 27 33 102 43 Earnings Available for Common Stock 17 23 92 32
Earnings for the quarter ended September 30, 1993 were decreased by $46 million as a result of the recording of $71 million of VTP pension-related benefits. Earnings for the quarter ended December 31, 1993 were decreased as a result of year-end adjustments for the $351 million write-off of Perry Unit 2 (see Note 4(b)), the $636 million write-off of the phase-in deferrals (see Note 7) and $38 million of other charges. These adjustments decreased quarterly earnings by $716 million. Earnings for the quarter ended September 30, 1992 were increased by $26 million as a result of the recording of deferred operating expenses and carrying charges for the first nine months of 1992 totaling $39 million under the Rate Stabilization Program approved by the PUCO in October 1992. See Note 7. (15) Pending Merger of the Company with Toledo Edison On March 25, 1994, Centerior Energy announced that its operating utility subsidiaries, the Company and Toledo Edison, plan to merge into a single operating entity. Since the Company and Toledo Edison affiliated in 1986, efforts have been made to consolidate operations and administration as much as possible to achieve maximum cost savings. The merger of the two companies into a single entity is the completion of this consolidation process. Various aspects of the merger are subject to the approval of the FERC, the PUCO and other regulatory authorities. The merger must be approved by share owners of Toledo Edison's preferred stock. Share owners of the Company's preferred stock must approve the authorization of additional shares of preferred stock. Share owners of Toledo Edison's preferred stock will exchange their shares for preferred stock shares of the successor corporation having substantially the same terms, while the (Cleveland Electric) F-44 (Cleveland Electric) 97 Company's preferred stock will automatically become shares of the successor corporation. Debt holders of the merging companies will become debt holders of the successor corporation. The merging companies plan to seek preferred stock share owner approval in the summer of 1994. The merger is expected to be effective in late 1994. For the merging companies, the combined pro forma operating revenues were $2.475 billion, $2.439 billion and $2.561 billion and the combined pro forma net income (loss) was $(876) million, $276 million and $296 million for the years ended December 31, 1993, 1992 and 1991, respectively. The pro forma data is based on accounting for the merger on a method similar to a pooling of interests. The pro forma data is not necessarily indicative of the results of operations which would have been reported had the merger been in effect during those years or which may be reported in the future. The pro forma data should be read in conjunction with the audited financial statements of both the Company and Toledo Edison. (Cleveland Electric) F-45 (Cleveland Electric) 98 FINANCIAL AND STATISTICAL REVIEW - ---------------------------------------------------------------------- Operating Revenues (millions of dollars)
Total Total Total Steam Operating Year Residential Commercial Industrial Other Retail Wholesale Electric Heating Revenues - ------------------------------------------------------------------------------------------------------------------------------------ 1993 $ 539 536 510 98 1 683 68 1 751 -- $ 1 751 1992 517 531 530 101 1 679 64 1 743 -- 1 743 1991 547 540 547 117 1 751 75 1 826 -- 1 826 1990 495 494 544 123 1 656 35 1 691 -- 1 691 1989 470 453 520 117 1 560 74 1 634 -- 1 634 1983 385 335 430 43 1 193 9 1 202 16 1 218 - ------------------------------------------------------------------------------------------------------------------------------------
Operating Expenses (millions of dollars)
Other Deferred Fuel & Operation Depreciation Taxes, Operating Federal Total Purchased & & Other Than Expenses, Income Operating Year Power Maintenance Amortization FIT Net Taxes Expenses - ------------------------------------------------------------------------------------------------------------------------------------ 1993 $ 423 654(a) 182 221 27(b) 22 $ 1 529 1992 434 465 179 226 (35) 89 1 358 1991 455 470 171(c) 216 (7) 106 1 411 1990 412 514 170 197 (24) 75 1 344 1989 427 508 188 183 (42) 85 1 349 1983 341 270 94 127 -- 127 959 - ------------------------------------------------------------------------------------------------------------------------------------
Income (Loss) (millions of dollars)
Federal Income Other Deferred Income (Loss) Income & Carrying Taxes-- Before Operating AFUDC-- Deductions, Charges, Credit Interest Year Income Equity Net Net (Expense) Charges - ------------------------------------------------------------------------------------------------------------------------------------ 1993 $ 222 4 (356)(d) (487)(b) 270 $ (347) 1992 385 1 8 59 (5) 448 1991 415 8 6 88 (24) 493 1990 347 5 1 162 (20) 495 1989 285 8 9 235 (56) 481 1983 259 87 4 -- 23 373 - ------------------------------------------------------------------------------------------------------------------------------------
Income (Loss) (millions of dollars)
Earnings Preferred & (Loss) Net Preference Available for Debt AFUDC-- Income Stock Common Year Interest Debt (Loss) Dividends Stock - ------------------------------------------------------------------------------------------------------------------------------------ 1993 $ 244 (4) (587) 45 $(632) 1992 243 -- 205 41 164 1991 251 (4) 246 36 210 1990 255 (3) 243 37 206 1989 238 (7) 250 40 210 1983 154 (27) 246 38 208 - ------------------------------------------------------------------------------------------------------------------------------------
(a) Includes early retirement program expenses and other charges of $165 million in 1993. (b) Includes write-off of phase-in deferrals of $636 million in 1993, consisting of $117 million of deferred operating expenses and $519 million of deferred carrying charges. (c) In 1991, a change in accounting for nuclear plant depreciation was adopted, changing from the units-of-production method to the straight-line method at a 2.5% rate. (Cleveland Electric) F-46 (Cleveland Electric) 99 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
Electric Sales (millions of KWH) Electric Customers (year end) Industrial Year Residential Commercial Industrial Wholesale Other Total Residential Commercial & Other - ----------------------------------------------------------------------------------------- --------------------------------------- 1993 4 934 5 634 7 911 2 290 532 21 301 669 118 70 442 8 149 1992 4 725 5 467 7 988 1 989 533 20 702 669 800 70 943 8 375 1991 4 940 5 493 8 017 2 442 565 21 457 667 495 70 405 8 398 1990 4 716 5 234 8 551 1 607 463 20 571 665 000 68 700 8 351 1989 4 789 5 208 8 780 2 132 501 21 410 660 786 68 030 8 329 1983 4 412 4 265 7 514 263 426 16 880 643 065 62 075 7 693 Residential Usage Average Average Average Price Revenue KWH Per Per Per Year Total Customer KWH Customer - ------ ------- --------------------------------- 1993 747 709 7 373 10.93c $805.68 1992 749 118 7 071 10.94 773.77 1991 746 298 7 170 11.08 797.25 1990 742 051 6 867 10.53 723.15 1989 737 145 7 025 9.81 691.83 1983 712 833 6 608 8.77 579.49 - -----------------------------------------------------------------------------------------------------------------------------------
Load (MW & %) Energy (millions of KWH) Fuel Operable Capacity Company Generated at Time Peak Capacity Load ----------------------------- Purchased Fuel Cost Year of Peak Load Margin Factor Fossil Nuclear Total Power Total Per KWH - -------------------------------------------------------- --------------------------------------------------------- --------- 1993 4 122 3 862 6.3% 59.9% 15 557 5 644 21 201 1 454 22 655 1.37c 1992 4 703 3 605 23.3 63.0 12 715 7 521 20 236 1 649 21 885 1.47 1991 4 695 3 886 17.2 61.8 13 193 7 451 20 644 2 144 22 788 1.49 1990 4 685 3 778 19.4 63.3 15 579 5 262 20 841 964 21 805 1.52 1989 4 536 3 866 14.8 65.2 14 968 6 570 21 538 1 268 22 806 1.49 1983 4 441 3 404 23.4 61.9 14 804 2 512 17 316 937 18 253 1.77 Efficiency-- BTU Per Year KWH - ----------- --------- 1993 10 339 1992 10 456 1991 10 503 1990 10 417 1989 10 506 1983 10 452 - -----------------------------------------------------------------------------------------------------------------------------------
Investment (millions of dollars) Construction Utility Work In Total Plant Accumulated Progress Nuclear Property, Utility In Depreciation & Net & Perry Fuel and Plant and Plant Total Year Service Amortization Plant Unit 2 Other Equipment Additions Assets - ----------------------------------------------------------------------------------------------- ------- -------- 1993 $6 734 1 889 4 845 141 243 $ 5 229 $ 175 $7 159 1992 6 602 1 728 4 874 501 261 5 636 156 8 123 1991 6 196 1 565 4 631 545 305 5 481 150 7 942 1990 6 032 1 398 4 634 572 344 5 550 165 7 821 1989 5 869 1 259 4 610 603 354 5 567 144 7 546 1983 2 838 722 2 116 1 617 228(e) 3 961 491 4 425 - -----------------------------------------------------------------------------------------------------------------------------------
Capitalization (millions of dollars & %) Preferred & Preference Preferred Stock, with Stock, without Mandatory Mandatory Common Stock Redemption Redemption Year Equity Provisions Provisions Long-Term Debt Total - ------------------------------------------------------------------------------------------------------ 1993 $1 040 24% 285 7% 241 5% 2 793 64% $4 359 1992 1 865 39 314 6 144 3 2 515 52 4 838 1991 1 898 38 268 5 217 4 2 683 53 5 066 1990 1 884 38 171 3 217 4 2 632 55 4 904 1989 1 828 40 212 4 217 5 2 336 51 4 593 1983 1 355 41 318 9 144 4 1 519 46 3 336 - -----------------------------------------------------------------------------------------------------------------------------------
(d) Includes write-off of Perry Unit 2 of $351 million in 1993. (e) Restated for effects of capitalization of nuclear fuel lease and financing arrangements pursuant to Statement of Financial Accounting Standards 71. (Cleveland Electric) F-47 (Cleveland Electric) 100 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS - ---------------------------------------------------------------------- To the Share Owners of The Toledo [Logo] Edison Company: We have audited the accompanying balance sheet and statement of preferred stock of The Toledo Edison Company (a wholly owned subsidiary of Centerior Energy Corporation) as of December 31, 1993 and 1992, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1993. These financial statements and the schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of The Toledo Edison Company as of December 31, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. As discussed further in Notes 1 and 9, changes were made in the methods of accounting for nuclear plant depreciation in 1991 and for postretirement benefits other than pensions in 1993. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules of The Toledo Edison Company listed in the Index to Schedules are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN & CO. Cleveland, Ohio February 14, 1994 (except with respect to the matter discussed in Note 15, as to which the date is March 25, 1994) (Toledo Edison) F-48 (Toledo Edison) 101 MANAGEMENT'S FINANCIAL ANALYSIS - -------------------------------------------------------------------------------- Results of Operations 1993 VS. 1992 Factors contributing to the 3.1% increase in 1993 operating revenues for The Toledo Edison Company (Company) are as follows:
Millions Increase (Decrease) in Operating Revenues of Dollars - ------------------------------------------------ ----------- Sales Volume and Mix $ 38 Wholesale Sales (11) Base Rates and Miscellaneous (3) Fuel Cost Recovery Revenues 2 ----- Total $ 26 ----- -----
The net revenue increase resulted primarily from the different weather conditions and the changes in the composition of the sales mix among customer categories. Weather accounted for approximately $17 million of the higher 1993 revenues. Hot summer weather in 1993 boosted residential and commercial kilowatt-hour sales. In contrast, the 1992 summer was the coolest in 56 years in Northwestern Ohio. Residential and commercial sales also increased as a result of colder late-winter temperatures in 1993 which increased electric heating-related demand. Residential and commercial sales increased 5.1% and 3.2%, respectively, in 1993. Industrial sales increased 6% as a result of increased sales to large automotive manufacturers, petroleum refiners and the broad-based, smaller industrial customer group. Other sales decreased 18.4% because of fewer sales to wholesale customers. Generating plant outages and retail customer demand limited power availability for bulk power transactions. As a result, total sales decreased 2.2% in 1993. Base rates and miscellaneous revenues decreased in 1993 primarily from lower revenues under contracts having reduced rates with certain large customers and a declining rate structure tied to usage. The contracts have been negotiated to meet competition and encourage economic growth. The net increase in 1993 fuel cost recovery revenues resulted from changes in the fuel cost factors. The weighted average of these factors increased about 2%. Operating expenses increased 12.6% in 1993. The increase in total operation and maintenance expenses resulted from the $88 million of net benefit expenses related to an early retirement program, called the Voluntary Transition Program (VTP), other charges totaling $19 million and a slight increase in other operation and maintenance expenses. The VTP benefit expenses consisted of $75 million of costs for the Company plus $13 million for the Company's pro rata share of the costs for its affiliate, Centerior Service Company (Service Company). Other charges recorded at year-end 1993 related to a performance improvement plan for Perry Nuclear Power Plant Unit 1 (Perry Unit 1), postemployment benefits and other expense accruals. See Note 9 for information on retirement and postemployment benefits. Deferred operating expenses decreased because of the write-off of the phase-in deferred operating expenses in 1993 as discussed in Note 7. Federal income taxes decreased as a result of lower pretax operating income. As discussed in Note 4(b), $232 million of our Perry Nuclear Power Plant Unit 2 (Perry Unit 2) investment was written off in 1993. Credits for carrying charges recorded in nonoperating income decreased because of the write-off of the phase-in deferred carrying charges in 1993 as discussed in Note 7. The federal income tax credit for nonoperating income in 1993 resulted from the write-offs. 1992 VS. 1991 Factors contributing to the 4.8% decrease in 1992 operating revenues are as follows:
Millions Increase (Decrease) in Operating Revenues of Dollars - ------------------------------------------------ ----------- Sales Volume and Mix $ (29) Base Rates and Miscellaneous (24) Wholesale Sales 11 ----- Total $ (42) ----- -----
The revenue decreases resulted primarily from the different weather conditions and the changes in the composition of the sales mix among customer categories. Weather accounted for approximately $22 million of the lower 1992 revenues. Winter and spring in 1992 were milder than in 1991. In addition, the cooler summer in 1992 contrasted with the summer of 1991 which was much hotter than normal. Total kilowatt-hour sales increased 0.2% in 1992. Residential and commercial sales decreased 4.9% and 3.8%, respectively, as moderate temperatures in 1992 reduced electric heating and cooling demands. Industrial sales increased 0.6% as increased sales to glass and metal manufacturers and to the broad-based, smaller industrial customer group offset lower sales to petroleum refining and auto manufacturing customers. Other sales increased 5.2% because of increased sales to wholesale customers. Operating revenues in 1991 included the recognition of $24 million of deferred revenues over the period of a refund to customers under a provision of a January 1989 rate order. No such revenues were reflected in 1992 as the refund period ended in December 1991. Operating expenses decreased 4.4% in 1992. A reduction of $14 million in other operation and maintenance expenses resulted primarily from cost-cutting measures. Lower fuel and purchased power expense resulted from less amortization of previously deferred fuel costs than the amount amortized in 1991. These decreases were par- tially offset by higher depreciation and amortization, caused primarily by the adoption of the new accounting (Toledo Edison) F-49 (Toledo Edison) 102 standard for income taxes (SFAS 109) in 1992, and by higher taxes, other than federal income taxes, caused by increased Ohio property taxes. Deferred operating expenses increased as a result of the deferrals under the Rate Stabilization Program discussed in Note 7. The federal income tax provision for nonoperating income decreased because of a greater tax allocation of interest charges to nonoperating activities. Credits for carrying charges recorded in nonoperating income increased primarily because of Rate Stabilization Program carrying charge credits. Interest charges decreased as a result of debt refinancings at lower interest rates and lower short-term borrowing requirements. Outlook RECENT ACTIONS In January 1994, Centerior Energy Corporation (Centerior Energy), along with the Company and The Cleveland Electric Illuminating Company (Cleveland Electric), announced a comprehensive strategic action plan to strengthen their financial and competitive positions. The Company and Cleveland Electric are the two wholly owned electric utility subsidiaries of Centerior Energy. The plan established specific objectives and was designed to guide Centerior Energy and its subsidiaries through the year 2001. Several actions were taken at that time. Centerior Energy reduced its quarterly common stock dividend from $.40 per share to $.20 per share effective with the dividend payable February 15, 1994. This action was taken because projected financial results did not support continuation of the dividend at its former rate. The Company and Cleveland Electric also wrote off their investments in Perry Unit 2 and certain deferred charges related to a January 1989 rate agreement (phase-in deferrals). The aggregate after-tax effect of these write-offs for the Company was $332 million which resulted in a net loss in 1993 and a retained earnings deficit. The write-offs are discussed in Notes 4(b) and 7. The Company also recognized other one-time charges totaling $15 million after taxes related to a performance improvement plan for Perry Unit 1, postemployment benefits and other expense accruals. Also contributing to the net loss in 1993 was a charge of $36 million after taxes representing a portion of the VTP costs. The Company will realize approximately $20 million of savings in annual payroll and benefit costs beginning in 1994 as a result of the VTP. STRATEGIC PLAN The objectives of the strategic plan are to maximize share owner return on Centerior Energy common stock from corporate assets and resources, achieve profitable revenue growth, become an industry leader in customer satisfaction, build a winning team and attain increasingly competitive power supply costs. To achieve these objectives, the Company will continue controlling its operation and maintenance expenses and capital expenditures, reduce its outstanding debt, increase revenues by finding new uses for existing assets and resources, implement a broad range of new marketing programs, increase revenues by restructuring rates for various customers where appropriate, improve the operating performance of its plants and take other appropriate actions. COMMON STOCK DIVIDENDS In recent years, the Company has retained all of its earnings available for common stock. The Company has not paid a common stock dividend to Centerior Energy since February 1991. Because the Company is currently prohibited from paying a common stock dividend by a provision in its mortgage (see Note 11(b)), the Company does not expect to pay any common stock dividends in the foreseeable future. COMPETITION Our electric rates are among the highest in our region because we are recovering the substantial investment in our nuclear construction program. Accordingly, some of our customers continue to seek less costly alternatives, including switching to or working to create a municipal electric system. There are a number of rural and municipal systems in our service area. In addition, we face threats of other municipalities in our service area establishing new systems. We have entered into agreements with some of the communities which considered establishing systems. Accordingly, they will not proceed with such development at this time in return for rate concessions and/or economic development funds. Others have determined that developing a system was not feasible. We will continue to address municipal system threats through aggressive marketing programs and emphasizing to our customers the value of our service and the risks of a municipal system. The Energy Policy Act of 1992 (Energy Act) will provide additional competition in the electric utility industry by requiring utilities to wheel to municipal systems in their service areas electricity from other utilities. This provision of the Energy Act should not significantly increase the competitive threat to us since the operating licenses for our nuclear units have required us to wheel to municipal systems in our service area since 1977. The Energy Act also created a class of exempt wholesale generators which may increase competition in the wholesale power market. A further risk is the possibility that the government could mandate that utilities deliver power from another utility or generation source to their retail customers. We have entered into contracts with many of our (Toledo Edison) F-50 (Toledo Edison) 103 large industrial and commercial customers which have remaining terms of one to five years. We will attempt to renew those contracts as they expire which will help us compete if retail wheeling is permitted in the future. RATE MATTERS Our Rate Stabilization Program remains in effect. Under this program, we agreed to freeze base rates until 1996 and limit rate increases through 1998. In exchange, we are permitted to defer through 1995 and subsequently recover certain costs not currently recovered in rates and to accelerate the amortization of certain benefits. The amortization and recovery of the deferrals will begin with future rate recognition and will continue over the average life of the related assets, or approximately 30 years. The continued use of these regulatory accounting measures will be dependent upon our continuing assessment and conclusion that there will be probable recovery of such deferrals in future rates. The analysis leading to the year-end 1993 financial actions and strategic plan also included an evaluation of our regulatory accounting measures. We decided that, once the deferral of expenses and acceleration of benefits under our Rate Stabilization Program are completed in 1995, we should no longer plan to use regulatory accounting measures to the extent we have in the past. NUCLEAR OPERATIONS The Company's three nuclear units may be impacted by activities or events beyond our control. Operating nuclear generating units have experienced unplanned outages or extensions of scheduled outages because of equipment problems or new regulatory requirements. A major accident at a nuclear facility anywhere in the world could cause the Nuclear Regulatory Commission (NRC) to limit or prohibit the operation or licensing of any nuclear unit. If one of our nuclear units is taken out of service for an extended period of time for any reason, including an accident at such unit or any other nuclear facility, we cannot predict whether regulatory authorities would impose unfavorable rate treatment. Such treatment could include taking our affected unit out of rate base or disallowing certain construction or maintenance costs. An extended outage of one of our nuclear units coupled with unfavorable rate treatment could have a material adverse effect on our financial condition and results of operations. We externally fund the estimated costs for the future decommissioning of our nuclear units. In 1993, we increased our decommissioning expense accruals for revisions in our cost estimates. We expect the increases associated with the new estimates will be recoverable in future rates. See Note 1(f). HAZARDOUS WASTE DISPOSAL SITES The Comprehensive Environmental Response, Compensation and Liability Act of 1980 as amended (Superfund) established programs addressing the cleanup of hazardous waste disposal sites, emergency preparedness and other issues. The Company is aware of its potential involvement in the cleanup of several sites. Although these sites are not on the Superfund National Priorities List, they are generally being administered by various governmental entities in the same manner as they would be administered if they were on such list. The allegations that the Company disposed of hazardous waste at these sites and the amounts involved are often unsubstantiated and subject to dispute. Superfund provides that all "potentially responsible parties" (PRPs) to a particular site can be held liable on a joint and several basis. Consequently, if the Company were held liable for 100% of the cleanup costs of all of the sites referred to above, the cost could be as high as $150 million. However, we believe that the actual cleanup costs will be substantially lower than $150 million, that the Company's share of any cleanup costs will be substantially less than 100% and that most of the other PRPs are financially able to contribute their share. The Company has accrued a liability totaling $6 million at December 31, 1993 based on estimates of the costs of cleanup and its proportionate responsibility for such costs. We believe that the ultimate outcome of these matters will not have a material adverse effect on our financial condition or results of operations. 1993 TAX ACT The Revenue Reconciliation Act of 1993 (1993 Tax Act), which was enacted in August 1993, provided for a 35% income tax rate in 1993. The 1993 Tax Act did not materially impact the results of operations for 1993, but did affect certain Balance Sheet accounts as discussed in Note 8. The 1993 Tax Act is not expected to materially impact future results of operations or cash flow. INFLATION Although the rate of inflation has eased in recent years, we are still affected by even modest inflation which causes increases in the unit cost of labor, materials and services. Capital Resources and Liquidity 1991-1993 CASH REQUIREMENTS We need cash for normal corporate operations, the mandatory retirement of securities and an ongoing pro- (Toledo Edison) F-51 (Toledo Edison) 104 gram of constructing new facilities and modifying existing facilities. The construction program is needed to meet anticipated demand for electric service, comply with governmental regulations and protect the environment. Over the three-year period of 1991-1993, these construction and mandatory retirement needs totaled approximately $440 million. In addition, we exercised various options to redeem approximately $490 million of our securities. We raised $815 million through security issues and term bank loans during the 1991-1993 period as shown in the Cash Flows statement. During the three-year period, the Company also utilized its short-term borrowing arrangements to help meet its cash needs. Although the write-offs of Perry Unit 2 and the phase-in deferrals in 1993 negatively affected our earnings, they did not adversely affect our current cash flow. 1994 AND BEYOND CASH REQUIREMENTS Estimated cash requirements for 1994-1998 for the Company are $249 million for its construction program and $324 million for the mandatory redemption of debt and preferred stock. The Company expects to finance internally all of its 1994 cash requirements of approximately $109 million. About 15% of the Company's 1995-1998 requirements are expected to be financed externally. If economical, additional securities may be redeemed under optional redemption provisions, which will help improve the Company's capitalization structure and interest coverage ratios. Our capital requirements are dependent upon our implementation strategy to achieve compliance with the Clean Air Act Amendments of 1990 (Clean Air Act). Cash expenditures for our plan are estimated to be approximately $41 million over the 1994-1998 period. See Note 4(a). LIQUIDITY Additional first mortgage bonds may be issued by the Company under its mortgage on the basis of property additions, cash or refundable first mortgage bonds. Under its mortgage, the Company may issue first mortgage bonds on the basis of property additions and, under certain circumstances, refundable bonds only if the applicable interest coverage test is met. At December 31, 1993, the Company would have been permitted to issue approximately $323 million of additional first mortgage bonds. As discussed in Note 11(d), certain unsecured debt agreements contain covenants relating to capitalization, fixed charge coverage ratios and secured financings. The write-offs recorded at December 31, 1993 caused the Company, Cleveland Electric and Centerior Energy to violate certain of those covenants. The affected creditors have waived those violations in exchange for commitments to provide them with a second mortgage security interest on property of the Company and Cleveland Electric and other considerations. We expect to complete this process in the second quarter of 1994. We will provide the same security interest to certain other creditors because their agreements require equal treatment. We expect to provide second mortgage collateral for $172 million of unsecured debt, $228 million of bank letters of credit and a $205 million revolving credit facility. The bank letters of credit and revolving credit facility are joint and several obligations of the Company and Cleveland Electric. For the next five years, the Company does not expect to raise funds through the sale of debt junior to first mortgage bonds. However, if necessary or desirable, we believe that the Company could raise funds through the sale of unsecured debt or debt secured by the second mortgage referred to above. The Company also is able to raise funds through the sale of preference stock. The Company will be unable to issue preferred stock until it can meet the interest and preferred dividend coverage test in its articles of incorporation. The Company currently cannot sell commercial paper because of its low commercial paper ratings by Standard & Poor's Corporation (S&P) and Moody's Investors Service, Inc. (Moody's) of "B" and "Not Prime", respectively. The Company is a party to a $205 million revolving credit facility which will run through mid-1996. However, we currently cannot draw on this facility because the write-offs taken at year-end 1993 caused the Company, Cleveland Electric and Centerior Energy to fail to meet certain capitalization and fixed charge coverage covenants. We expect to have this facility available to us again after it is amended in the second quarter of 1994 to provide the participating creditors with a second mortgage security interest. These financing resources are expected to be sufficient for the Company's needs over the next several years. The availability and cost of capital to meet the Company's external financing needs, however, also depend upon such factors as financial market conditions and its credit ratings. Current credit ratings for the Company are as follows:
S&P Moody's ----------- ------------- First mortgage bonds BB Ba2 Unsecured notes B+ Ba3 Preferred stock B b1
These ratings reflect a downgrade in December 1993. In addition, S&P has issued a negative outlook for the Company. (Toledo Edison) F-52 (Toledo Edison) 105 INCOME STATEMENT THE TOLEDO EDISON COMPANY - ----------------------------------------------------------------------
For the years ended December 31, ----------------------- 1993 1992 1991 ----- ---- ---- (millions of dollars) OPERATING REVENUES (1) $ 871 $845 $887 ----- ---- ---- OPERATING EXPENSES Fuel and purchased power 173 169 178 Other operation and maintenance 349 342 356 Early retirement program expenses and other 107 -- -- ----- ---- ---- Total operation and maintenance 629 511 534 Depreciation and amortization 76 77 72 Taxes, other than federal income taxes 91 91 89 Deferred operating expenses, net (4) (17) 1 Federal income taxes (credit) (10) 33 32 ----- ---- ---- 782 695 728 ----- ---- ---- OPERATING INCOME 89 150 159 ----- ---- ---- NONOPERATING INCOME (LOSS) Allowance for equity funds used during construction 1 1 1 Other income and deductions, net -- 1 5 Write-off of Perry Unit 2 (232) -- -- Deferred carrying charges, net (161) 41 22 Federal income taxes -- credit (expense) 129 (1) (6) ----- ---- ---- (263) 42 22 ----- ---- ---- INCOME (LOSS) BEFORE INTEREST CHARGES (174) 192 181 ----- ---- ---- INTEREST CHARGES Debt interest 116 122 132 Allowance for borrowed funds used during construction (1) (1) (1) ----- ---- ---- 115 121 131 ----- ---- ---- NET INCOME (LOSS) (289) 71 50 PREFERRED DIVIDEND REQUIREMENTS 23 24 25 ----- ---- ---- EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK $(312) $ 47 $ 25 ----- ---- ---- ----- ---- ---- - --------------- (1) Includes revenues from all bulk power sales to Cleveland Electric of $120 million, $130 million and $128 million in 1993, 1992 and 1991, respectively.
RETAINED EARNINGS - ----------------------------------------------------------------------
For the years ended December 31, ----------------------- 1993 1992 1991 ----- ---- ---- (millions of dollars) RETAINED EARNINGS AT BEGINNING OF YEAR $ 137 $ 90 $ 83 ----- ---- ---- ADDITIONS Net income (loss) (289) 71 50 DEDUCTIONS Dividends declared: Common stock -- -- (18) Preferred stock (23) (24) (25) ----- ---- ---- Net Increase (Decrease) (312) 47 7 ----- ---- ---- RETAINED EARNINGS (DEFICIT) AT END OF YEAR $(175) $137 $ 90 ----- ---- ---- ----- ---- ----
The accompanying notes are an integral part of these statements. (Toledo Edison) F-53 (Toledo Edison) 106 CASH FLOWS THE TOLEDO EDISON COMPANY - ----------------------------------------------------------------------
For the years ended December 31, ------------------------- 1993 1992 1991 ----- ----- ----- (millions of dollars) CASH FLOWS FROM OPERATING ACTIVITIES (1) Net Income (Loss) $(289) $ 71 $ 50 ----- ----- ----- Adjustments to Reconcile Net Income (Loss) to Cash from Operating Activities: Depreciation and amortization 76 77 72 Deferred federal income taxes (160) 28 32 Investment tax credits, net -- (5) 30 Deferred and unbilled revenues (4) 1 (26) Deferred fuel -- (4) 4 Deferred carrying charges, net 161 (41) (22) Leased nuclear fuel amortization 38 56 54 Deferred operating expenses, net (4) (17) 1 Allowance for equity funds used during construction (1) (1) (1) Noncash early retirement program expenses, net 83 -- -- Write-off of Perry Unit 2 232 -- -- Changes in amounts due from customers and others, net (3) -- 3 Changes in inventories 10 (9) (7) Changes in accounts payable 16 (8) (13) Changes in working capital affecting operations 21 7 (26) Other noncash items 14 13 14 ----- ----- ----- Total Adjustments 479 97 115 ----- ----- ----- Net Cash from Operating Activities 190 168 165 ----- ----- ----- CASH FLOWS FROM FINANCING ACTIVITIES (2) Bank loans, commercial paper and other short-term debt (40) 40 (23) Notes payable to affiliates -- (30) 14 Debt issues: First mortgage bonds 20 276 -- Secured medium-term notes 93 48 135 Term bank loans and other long-term debt -- 135 108 Maturities, redemptions and sinking funds (89) (531) (179) Nuclear fuel lease obligations (47) (52) (52) Dividends paid (23) (24) (43) Premiums, discounts and expenses (1) (8) (1) ----- ----- ----- Net Cash from Financing Activities (87) (146) (41) ----- ----- ----- CASH FLOWS FROM INVESTING ACTIVITIES (2) Cash applied to construction (42) (48) (51) Interest capitalized as allowance for borrowed funds used during construction (1) (1) (1) Loans to affiliates -- 12 (12) Sale and leaseback restructuring fees -- (43) -- Other cash received (applied) 6 (5) (3) ----- ----- ----- Net Cash from Investing Activities (37) (85) (67) ----- ----- ----- NET CHANGE IN CASH AND TEMPORARY CASH INVESTMENTS 66 (63) 57 ----- ----- ----- CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF YEAR 16 79 22 ----- ----- ----- CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR $ 82 $ 16 $ 79 ----- ----- ----- ----- ----- ----- - --------------- (1) Interest paid (net of amounts capitalized) was $92 million, $95 million and $120 million in 1993, 1992 and 1991, respectively. Income taxes paid were $7 million, $3 million and $9 million in 1993, 1992 and 1991, respectively. (2) Increases in Nuclear Fuel and Nuclear Fuel Lease Obligations in the Balance Sheet resulting from the noncash capitalizations under nuclear fuel agreements are excluded from this statement.
The accompanying notes are an integral part of this statement. (Toledo Edison) F-54 (Toledo Edison) 107 [THIS PAGE INTENTIONALLY LEFT BLANK] 108 BALANCE SHEET - ----------------------------------------------------------------------
December 31, ---------------- 1993 1992 ------ ------ (millions of dollars) ASSETS PROPERTY, PLANT AND EQUIPMENT Utility plant in service $2,837 $2,847 Less: accumulated depreciation and amortization 788 760 ------ ------ 2,049 2,087 Construction work in progress 40 37 Perry Unit 2 -- 243 ------ ------ 2,089 2,367 Nuclear fuel, net of amortization 142 161 Other property, less accumulated depreciation -- 3 ------ ------ 2,231 2,531 ------ ------ CURRENT ASSETS Cash and temporary cash investments 82 16 Amounts due from customers and others, net 63 60 Amounts due from affiliates 16 23 Unbilled revenues 25 21 Materials and supplies, at average cost 43 40 Fossil fuel inventory, at average cost 12 25 Taxes applicable to succeeding years 71 71 Other 2 2 ------ ------ 314 258 ------ ------ DEFERRED CHARGES AND OTHER ASSETS Amounts due from customers for future federal income taxes 382 391 Unamortized loss from Beaver Valley Unit 2 sale 105 110 Unamortized loss on reacquired debt 32 37 Carrying charges and operating expenses 343 500 Nuclear plant decommissioning trusts 26 20 Other 77 92 ------ ------ 965 1,150 ------ ------ Total Assets $3,510 $3,939 ------ ------ ------ ------
The accompanying notes are an integral part of this statement. (Toledo Edison) F-55 (Toledo Edison) 109 The Toledo Edison Company
December 31, ----------------- 1993 1992 ------ ------ (millions of dollars) CAPITALIZATION AND LIABILITIES CAPITALIZATION Common shares, $5 par value: 60 million authorized; 39.1 million outstanding in 1993 and 1992 $ 196 $ 196 Premium on capital stock 481 481 Other paid-in capital 121 121 Retained earnings (deficit) (175) 137 ------ ------ Common stock equity 623 935 Preferred stock With mandatory redemption provisions 28 50 Without mandatory redemption provisions 210 210 Long-term debt 1,225 1,178 ------ ------ 2,086 2,373 ------ ------ OTHER NONCURRENT LIABILITIES Nuclear fuel lease obligations 103 126 Other 83 62 ------ ------ 186 188 ------ ------ CURRENT LIABILITIES Current portion of long-term debt and preferred stock 57 58 Current portion of nuclear fuel lease obligations 49 51 Notes payable to banks and others -- 40 Accounts payable 63 47 Accounts payable to affiliates 27 16 Accrued taxes 90 78 Accrued interest 27 28 Other 16 14 ------ ------ 329 332 ------ ------ DEFERRED CREDITS Unamortized investment tax credits 94 103 Accumulated deferred federal income taxes 471 640 Unamortized gain from Bruce Mansfield Plant sale 208 218 Accumulated deferred rents for Bruce Mansfield Plant and Beaver Valley Unit 2 50 46 Other 86 39 ------ ------ 909 1,046 ------ ------ Total Capitalization and Liabilities $3,510 $3,939 ------ ------ ------ ------
(Toledo Edison) F-56 (Toledo Edison) 110 STATEMENT OF PREFERRED STOCK THE TOLEDO EDISON COMPANY - --------------------------------------------------------------------------------
Current Call Price December 31, 1993 Shares Per ------------- Outstanding Share 1993 1992 ----------- -------- ---- ---- (millions of dollars) $100 par value, 3,000,000 preferred shares authorized and $25 par value, 12,000,000 preferred shares authorized Subject to mandatory redemption: $100 par $9.375 100,150 $102.47 $ 10 $ 12 25 par 2.81 1,200,000 25.94 30 50 ---- ---- 40 62 Less: Current maturities 12 12 ---- ---- TOTAL PREFERRED STOCK, WITH MANDATORY REDEMPTION PROVISIONS $ 28 $ 50 ---- ---- ---- ---- Not subject to mandatory redemption: $100 par $ 4.25 160,000 104.625 $ 16 $ 16 4.56 50,000 101.00 5 5 4.25 100,000 102.00 10 10 8.32 100,000 102.46 10 10 7.76 150,000 102.437 15 15 7.80 150,000 101.65 15 15 10.00 190,000 101.00 19 19 25 par 2.21 1,000,000 25.25 25 25 2.365 1,400,000 27.75 35 35 Series A Adjustable 1,200,000 25.75 30 30 Series B Adjustable 1,200,000 25.75 30 30 ---- ---- TOTAL PREFERRED STOCK, WITHOUT MANDATORY REDEMPTION PROVISIONS $210 $210 ---- ---- ---- ----
The accompanying notes are an integral part of this statement. (Toledo Edison) F-57 (Toledo Edison) 111 NOTES TO THE FINANCIAL STATEMENTS - -------------------------------------------------------------------------------- (1) Summary of Significant Accounting Policies (A) GENERAL The Company is an electric utility and a wholly owned subsidiary of Centerior Energy. Centerior Energy has two other wholly owned subsidiaries, Cleveland Electric and the Service Company. The Company follows the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by The Public Utilities Commission of Ohio (PUCO). As a rate-regulated utility, the Company is subject to Statement of Financial Accounting Standards (SFAS) 71 which governs accounting for the effects of certain types of rate regulation. The Company is a member of the Central Area Power Coordination Group (CAPCO). Other members are Cleveland Electric, Duquesne Light Company, Ohio Edison Company and its wholly owned subsidiary, Pennsylvania Power Company. The members have constructed and operate generation and transmission facilities for their use. (B) RELATED PARTY TRANSACTIONS Operating revenues, operating expenses and interest charges include those amounts for transactions with affiliated companies in the ordinary course of business operations. The Company's transactions with Cleveland Electric are primarily for firm power, interchange power, transmission line rentals and jointly owned power plant operations and construction. See Notes 2 and 3. The Service Company provides management, financial, administrative, engineering, legal and other services at cost to the Company and other affiliated companies. The Service Company billed the Company $76 million, $60 million and $61 million in 1993, 1992 and 1991, respectively, for such services. (C) REVENUES Customers are billed on a monthly cycle basis for their energy consumption based on rate schedules or contracts authorized by the PUCO or on ordinances of individual municipalities. An accrual is made at the end of each month to record the estimated amount of unbilled revenues for kilowatt-hours sold in the current month but not billed by the end of that month. A fuel factor is added to the base rates for electric service. This factor is designed to recover from customers the costs of fuel and most purchased power. It is reviewed and adjusted semiannually in a PUCO proceeding. (D) FUEL EXPENSE The cost of fossil fuel is charged to fuel expense based on inventory usage. The cost of nuclear fuel, including an interest component, is charged to fuel expense based on the rate of consumption. Estimated future nuclear fuel disposal costs are being recovered through the base rates. The Company defers the differences between actual fuel costs and estimated fuel costs currently being recovered from customers through the fuel factor. This matches fuel expenses with fuel-related revenues. Owners of nuclear generating plants are assessed by the federal government for the cost of decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy. The assessments are based upon the amount of enrichment services used in prior years and cannot be imposed for more than 15 years. The Company has accrued a liability for its share of the total assessments. These costs have been recorded in a deferred charge account since the PUCO is allowing the Company to recover the assessments through its fuel cost factors. (E) DEFERRED CARRYING CHARGES AND OPERATING EXPENSES The PUCO authorized the Company to defer operating expenses and carrying charges for Perry Unit 1 and Beaver Valley Power Station Unit 2 (Beaver Valley Unit 2) from their respective in-service dates in 1987 through December 1988. The annual amortization and recovery of these deferrals, called pre-phase-in deferrals, are $7 million which began in January 1989 and will continue over the lives of the related property. Beginning in January 1989, the Company deferred certain operating expenses and both interest and equity carrying charges pursuant to a PUCO-approved rate phase-in plan for its investments in Perry Unit 1 and Beaver Valley Unit 2. These deferrals, called phase-in deferrals, were written off at December 31, 1993. See Note 7. The Company also defers certain costs not currently recovered in rates under a Rate Stabilization Program approved by the PUCO in October 1992. See Notes 7 and 14. (F) DEPRECIATION AND AMORTIZATION The cost of property, plant and equipment is depreciated over their estimated useful lives on a straight-line basis. The annual straight-line depreciation provision for nonnuclear property expressed as a percent of average depreciable utility plant in service was 3.6% in both 1993 and 1992 and 3.4% in 1991. Effective January 1, 1991, the Company, after obtaining PUCO approval, changed its method of accounting for nuclear plant depreciation from the units-of-production method to the straight-line method at about a 3% rate. This change decreased 1991 depreciation expense $14 million and increased 1991 net (Toledo Edison) F-58 (Toledo Edison) 112 income $11 million (net of $3 million of income taxes) from what they otherwise would have been. The PUCO subsequently approved in 1991 a change to lower the 3% rate to 2.5% retroactive to January 1, 1991. Pursuant to a PUCO order, the Company currently uses external funding for the future decommissioning of its nuclear units at the end of their licensed operating lives. The estimated costs are based on the NRC's DECON method of decommissioning (prompt decontamination). Cash contributions are made to the trust funds on a straight-line basis over the remaining licensing period for each unit. The current level of annual expense being recovered from customers based on prior estimates is approximately $4 million. However, actual decommissioning costs are expected to significantly exceed those estimates. Current site-specific estimates for the Company's share of the future decommissioning costs are $41 million in 1992 dollars for Beaver Valley Unit 2 and $87 million and $146 million in 1993 dollars for Perry Unit 1 and the Davis-Besse Nuclear Power Station (Davis-Besse), respectively. The estimates for Perry Unit 1 and Davis-Besse are preliminary and are expected to be finalized by the end of the second quarter of 1994. The Company used these estimates to increase its decommissioning expense accruals in 1993. It is expected that the increases associated with the revised cost estimates will be recoverable in future rates. In the Balance Sheet at December 31, 1993, Accumulated Depreciation and Amortization included $34 million of decommissioning costs previously expensed and the earnings on the external funding. This amount exceeds the Balance Sheet amount of the external Nuclear Plant Decommissioning Trusts because the reserve began prior to the external trust funding. (G) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment are stated at original cost less amounts ordered by the PUCO to be written off. Construction costs include related payroll taxes, pensions, fringe benefits, management and general overheads and allowance for funds used during construction (AFUDC). AFUDC represents the estimated composite debt and equity cost of funds used to finance construction. This noncash allowance is credited to income. The AFUDC rate was 10.22% in 1993 and 10.96% in both 1992 and 1991. Maintenance and repairs are charged to expense as incurred. The cost of replacing plant and equipment is charged to the utility plant accounts. The cost of property retired plus removal costs, after deducting any salvage value, is charged to the accumulated provision for depreciation. (H) DEFERRED GAIN AND LOSS FROM SALES OF UTILITY PLANT The sale and leaseback transactions discussed in Note 2 resulted in a net gain for the sale of the Bruce Mansfield Generating Plant (Mansfield Plant) and a net loss for the sale of Beaver Valley Unit 2. The net gain and net loss were deferred and are being amortized over the terms of leases. These amortizations and the lease expense amounts are recorded as other operation and maintenance expenses. (I) INTEREST CHARGES Debt Interest reported in the Income Statement does not include interest on obligations for nuclear fuel under construction. That interest is capitalized. See Note 6. Losses and gains realized upon the reacquisition or redemption of long-term debt are deferred, consistent with the regulatory rate treatment. Such losses and gains are either amortized over the remainder of the original life of the debt issue retired or amortized over the life of the new debt issue when the proceeds of a new issue are used for the debt redemption. The amortizations are included in debt interest expense. (J) FEDERAL INCOME TAXES The Financial Accounting Standards Board (FASB) issued SFAS 109, a new standard for accounting for income taxes, in February 1992. We adopted the new standard in 1992. The standard amended certain provisions of SFAS 96 which we had previously adopted. Adoption of SFAS 109 in 1992 did not materially affect our results of operations, but did affect certain Balance Sheet accounts. See Note 8. The financial statements reflect the liability method of accounting for income taxes. This method requires that deferred taxes be recorded for all temporary differences between the book and tax bases of assets and liabilities. The majority of these temporary differences are attributable to property-related basis differences. Included in these basis differences is the equity component of AFUDC, which will increase future tax expense when it is recovered through rates. Since this component is not recognized for tax purposes, we must record a liability for our tax obligation. The PUCO permits recovery of such taxes from customers when they become payable. Therefore, the net amount due from customers through rates has been recorded as a deferred charge and will be recovered over the lives of the related assets. Investment tax credits are deferred and amortized over the lives of the applicable property as a reduction of depreciation expense. See Note 7 for a discussion of the amortization of certain unrestricted excess deferred taxes and unrestricted investment tax credits under the Rate Stabilization Program. (Toledo Edison) F-59 (Toledo Edison) 113 (2) Utility Plant Sale and Leaseback Transactions The Company and Cleveland Electric are co-lessees of 18.26% (150 megawatts) of Beaver Valley Unit 2 and 6.5% (51 megawatts), 45.9% (358 megawatts) and 44.38% (355 megawatts) of Units 1, 2 and 3 of the Mansfield Plant, respectively, all for terms of about 29 1/2 years. These leases are the result of sale and leaseback transactions completed in 1987. Under these leases, the Company and Cleveland Electric are responsible for paying all taxes, insurance premiums, operation and maintenance expenses and all other similar costs for their interests in the units sold and leased back. They may incur additional costs in connection with capital improvements to the units. The Company and Cleveland Electric have options to buy the interests back at the end of the leases for the fair market value at that time or to renew the leases. Additional lease provisions provide other purchase options along with conditions for mandatory termination of the leases (and possible repurchase of the leasehold interests) for events of default. These events include noncompliance with several financial covenants discussed in Note 11(d). As co-lessee with Cleveland Electric, the Company is also obligated for Cleveland Electric's lease payments. If Cleveland Electric is unable to make its payments under the Mansfield Plant leases, the Company would be obligated to make such payments. No payments have been made on behalf of Cleveland Electric to date. In April 1992, nearly all of the outstanding Secured Lease Obligation Bonds (SLOBs) issued by a special purpose corporation in connection with financing the sale and leaseback of Beaver Valley Unit 2 were refinanced through a tender offer and the sale of new bonds having a lower interest rate. As part of the refinancing transaction, the Company paid $43 million as supplemental rent to fund transaction expenses and part of the tender premium. This amount has been deferred and is being amortized over the remaining lease term. The refinancing transaction reduced the annual rental expense for the Beaver Valley Unit 2 lease by $9 million. Future minimum lease payments under the operating leases at December 31, 1993 are summarized as follows:
For For the Cleveland Year Company Electric - ---------------------------------------- ------- --------- (millions of dollars) 1994.................................... $ 103 $ 63 1995.................................... 102 63 1996.................................... 125 63 1997.................................... 102 63 1998.................................... 102 63 Later Years............................. 2,021 1,391 ------- --------- Total Future Minimum Lease Payments........................ $2,555 $ 1,706 ------- --------- ------- ---------
Rental expense is accrued on a straight-line basis over the terms of the leases. The amount recorded in 1993, 1992 and 1991 as annual rental expense for the Mansfield Plant leases was $45 million. The amounts recorded in 1993, 1992 and 1991 as annual rental expense for the Beaver Valley Unit 2 lease were $63 million, $66 million and $72 million, respectively. Amounts charged to expense in excess of the lease payments are classified as Accumulated Deferred Rents in the Balance Sheet. The Company is selling 150 megawatts of its Beaver Valley Unit 2 leased capacity entitlement to Cleveland Electric. We anticipate that this sale will continue indefinitely. Revenues recorded for this transaction were $103 million, $108 million and $107 million in 1993, 1992 and 1991, respectively. The future minimum lease payments through the year 2017 associated with Beaver Valley Unit 2 aggregate $1.47 billion. (3) Property Owned with Other Utilities and Investors The Company owns, as a tenant in common with other utilities and those investors who are owner-participants in various sale and leaseback transactions (Lessors), certain generating units as listed below. Each owner owns an undivided share in the entire unit. Each owner has the right to a percentage of the generating capability of each unit equal to its ownership share. Each utility owner is obligated to pay for only its respective share of the construction costs and operating expenses. Each Lessor has leased its capacity rights to a utility which is obligated to pay for such Lessor's share of the construction costs and operating expenses. The Company's share of the operating expenses of these generating units is included in the Income Statement. The Balance Sheet classification of Property, Plant and Equipment at December 31, 1993 includes the following facilities owned by the Company as a tenant in common with other utilities and Lessors:
In- Plant Construction Service Ownership Ownership Power in Work in Accumulated Generating Unit Date Share Megawatts Source Service Progress Depreciation - ------------------------------- ------- --------- --------- -------- ------- ------------ ----------- (millions of dollars) Davis-Besse 1977 48.62% 429 Nuclear $ 679 $ 10 $ 163 Perry Unit 1 1987 19.91 238 Nuclear 1,051 3 186 Beaver Valley Unit 2 and Common Facilities (Note 2) 1987 1.65 13 Nuclear 203 3 36 ------- --- ----- Total $1,933 $ 16 $ 385 ------- --- ----- ------- --- -----
(Toledo Edison) F-60 (Toledo Edison) 114 (4) Construction and Contingencies (A) CONSTRUCTION PROGRAM The estimated cost of the Company's construction program for the 1994-1998 period is $259 million, including AFUDC of $10 million and excluding nuclear fuel. The Clean Air Act will require, among other things, significant reductions in the emission of sulfur dioxide in two phases over a ten-year period and nitrogen oxides by fossil-fueled generating units. Our compliance strategy provides for compliance with both phases through at least 2005 primarily through greater use of low-sulfur coal at some of our units and the banking of emission allowances. The plan will require capital expenditures over the 1994-2003 period of approximately $57 million for nitrogen oxide control equipment, emission monitoring equipment and plant modifications. In addition, higher fuel and other operation and maintenance expenses may be incurred. The anticipated rate increase associated with the capital expenditures and higher expenses would be less than 2% over the ten-year period. The PUCO has approved this plan. We also are seeking United States Environmental Protection Agency (U.S. EPA) approval of the first phase of our plan. We are continuing to monitor developments in new technologies that may be incorporated into our compliance strategy. If a different plan is required by the U.S. EPA, significantly higher capital expenditures could be required during the 1994-2003 period. We believe Ohio law permits the recovery of compliance costs from customers in rates. (B) PERRY UNIT 2 Perry Unit 2, including its share of the facilities common with Perry Unit 1, was approximately 50% complete when construction was suspended in 1985 pending consideration of various options. These options included resumption of full construction with a revised estimated cost, conversion to a nonnuclear design, sale of all or part of our ownership share, or cancellation. We wrote off our investment in Perry Unit 2 at December 31, 1993 after we determined that it would not be completed or sold. The write-off totaled $232 million ($167 million after taxes) for the Company's 19.91% ownership share of the unit. See Note 14. (C) HAZARDOUS WASTE DISPOSAL SITES The Company is aware of its potential involvement in the cleanup of several hazardous waste disposal sites. The Company has accrued a liability totaling $6 million at December 31, 1993 based on estimates of the costs of cleanup and its proportionate responsibility for such costs. We believe that the ultimate outcome of these matters will not have a material adverse effect on our financial condition or results of operations. See Management's Financial Analysis -- Outlook-Hazardous Waste Disposal Sites. (5) Nuclear Operations and Contingencies (A) OPERATING NUCLEAR UNITS The Company's three nuclear units may be impacted by activities or events beyond our control. An extended outage of one of our nuclear units for any reason, coupled with any unfavorable rate treatment, could have a material adverse effect on our financial condition and results of operations. See discussion of these risks in Management's Financial Analysis -- Outlook-Nuclear Operations. (B) NUCLEAR INSURANCE The Price-Anderson Act limits the liability of the owners of a nuclear power plant to the amount provided by private insurance and an industry assessment plan. In the event of a nuclear incident at any unit in the United States resulting in losses in excess of the level of private insurance (currently $200 million), the Company's maximum potential assessment under that plan would be $70 million (plus any inflation adjustment) per incident. The assessment is limited to $9 million per year for each nuclear incident. These assessment limits assume the other CAPCO companies contribute their proportionate share of any assessment. The CAPCO companies have insurance coverage for damage to property at the Davis-Besse, Perry and Beaver Valley sites (including leased fuel and clean-up costs). Coverage amounted to $2.75 billion for each site as of January 1, 1994. Damage to property could exceed the insurance coverage by a substantial amount. If it does, the Company's share of such excess amount could have a material adverse effect on its financial condition and results of operations. Under these policies, the Company can be assessed a maximum of $11 million during a policy year if the reserves available to the insurer are inadequate to pay claims arising out of an accident at any nuclear facility covered by the insurer. The Company also has extra expense insurance coverage. It includes the incremental cost of any replacement power purchased (over the costs which would have been incurred had the units been operating) and other incidental expenses after the occurrence of certain types of accidents at our nuclear units. The amounts of the coverage are 100% of the estimated extra expense per week during the 52-week period starting 21 weeks after an accident and 67% of such estimate per week for the next 104 weeks. The amount and duration of extra expense could substantially exceed the insurance coverage. (Toledo Edison) F-61 (Toledo Edison) 115 (6) Nuclear Fuel Nuclear fuel is financed for the Company and Cleveland Electric through leases with a special-purpose corporation. The total amount of financing currently available under these lease arrangements is $382 million ($232 million from intermediate-term notes and $150 million from bank credit arrangements). Financing in an amount up to $750 million is permitted. The intermediate-term notes mature in the period 1994-1997, with $75 million maturing in September 1994. At December 31, 1993, $154 million of nuclear fuel was financed for the Company. The Company and Cleveland Electric severally lease their respective portions of the nuclear fuel and are obligated to pay for the fuel as it is consumed in a reactor. The lease rates are based on various intermediate-term note rates, bank rates and commercial paper rates. The amounts financed include nuclear fuel in the Davis-Besse, Perry Unit 1 and Beaver Valley Unit 2 reactors with remaining lease payments for the Company of $52 million, $29 million and $20 million, respectively, at December 31, 1993. The nuclear fuel amounts financed and capitalized also included interest charges incurred by the lessors amounting to $6 million in both 1993 and 1992 and $9 million in 1991. The estimated future lease amortization payments based on projected consumption are $49 million in 1994, $42 million in 1995, $37 million in 1996, $33 million in 1997 and $30 million in 1998. (7) Regulatory Matters Phase-in deferrals were recorded beginning in 1989 pursuant to the phase-in plan approved by the PUCO in a January 1989 rate order for the Company. The phase-in plan was designed so that the projected revenues resulting from the authorized rate increases and anticipated sales growth provided for the phase-in of certain nuclear costs over a ten-year period. The plan required the deferral of a portion of the operating expenses and both interest and equity carrying charges on the Company's deferred rate-based investments in Perry Unit 1 and Beaver Valley Unit 2 during the early years of the plan. The amortization and recovery of such deferrals were scheduled to be completed by 1998. As we developed our strategic plan, we evaluated the future recovery of our deferred charges and continued application of the regulatory accounting measures we follow pursuant to PUCO orders. We concluded that projected revenues would not provide for the recovery of the phase-in deferrals as scheduled because of economic and competitive pressures. Accordingly, we wrote off the cumulative balance of the phase-in deferrals. The total phase-in deferred operating expenses and carrying charges written off at December 31, 1993 by the Company were $55 million and $186 million, respectively (totaling $165 million after taxes). See Note 14. While recovery of our other regulatory deferrals remains probable, our current assessment of business conditions has prompted us to change our future plans. We decided that, once the deferral of expenses and acceleration of benefits under our Rate Stabilization Program are completed in 1995, we should no longer plan to use regulatory accounting measures to the extent we have in the past. In October 1992, the PUCO approved a Rate Stabilization Program that was designed to encourage economic growth in the Company's service area by freezing the Company's base rates until 1996 and limiting subsequent rate increases to specified annual amounts not to exceed $89 million over the 1996-1998 period. As part of the Rate Stabilization Program, the Company is allowed to defer and subsequently recover certain costs not currently recovered in rates and to accelerate amortization of certain benefits. Such regulatory accounting measures provide for rate stabilization by rescheduling the timing of rate recovery of certain costs and the amortization of certain benefits during the 1992-1995 period. The continued use of these regulatory accounting measures will be dependent upon our continuing assessment and conclusion that there will be probable recovery of such deferrals in future rates. The regulatory accounting measures we are eligible to record through December 31, 1995 include the deferral of post-in-service interest carrying charges, depreciation expense and property taxes on assets placed in service after February 29, 1988 and the deferral of operating expenses equivalent to an accumulated excess rent reserve for Beaver Valley Unit 2 (which resulted from the April 1992 refinancing of SLOBs as discussed in Note 2). The cost deferrals recorded in 1993 and 1992 pursuant to these provisions were $39 million and $32 million, respectively. Amortization and recovery of these deferrals will occur over the average life of the related assets and the remaining lease period, or approximately 30 years, and will commence with future rate recognition. The regulatory accounting measures also provide for the accelerated amortization of certain unrestricted excess deferred tax and unrestricted investment tax credit balances and interim spent fuel storage accrual balances for Davis-Besse. The total amount of such regulatory benefits recognized in 1993 and 1992 pursuant to these provisions was $18 million and $5 million, respectively. The Rate Stabilization Program also authorized the Company to defer and subsequently recover the incremental expenses associated with the adoption of the accounting standard for postretirement benefits other than pensions (SFAS 106). In 1993, we deferred $37 million pursuant to this provision. Amortization and recovery of this (Toledo Edison) F-62 (Toledo Edison) 116 deferral will commence prior to 1998 and is expected to be completed by no later than 2012. See Note 9(b). (8) Federal Income Tax Federal income tax, computed by multiplying income before taxes by the statutory rate (35% in 1993 and 34% in both 1992 and 1991), is reconciled to the amount of federal income tax recorded on the books as follows:
1993 1992 1991 ----- ---- ---- (millions of dollars) Book Income (Loss) Before Federal Income Tax $(428) $105 $88 ----- ---- ---- ----- ---- ---- Tax (Credit) on Book Income (Loss) at Statutory Rate $(150) $ 36 $30 Increase (Decrease) in Tax: Write-off of Perry Unit 2 16 -- -- Write-off of phase-in deferrals 8 -- -- Depreciation (12) (6) 3 Rate Stabilization Program (10) (2) -- Sale and leaseback transactions and amortization 5 5 5 Other items 4 1 -- ----- ---- ---- Total Federal Income Tax Expense (Credit) $(139) $ 34 $38 ----- ---- ---- ----- ---- ----
Federal income tax expense is recorded in the Income Statement as follows:
1993 1992 1991 ----- ---- ---- (millions of dollars) Operating Expenses: Current Tax Provision $ 36 $ 26 $ 14 Changes in Accumulated Deferred Federal Income Tax: Write-off of deferred operating expenses (13) -- -- Accelerated depreciation and amortization 35 7 9 Alternative minimum tax credit (37) (13) (44) Retirement and postemployment benefits (20) -- -- Sale and leaseback transactions and amortization 5 4 13 Taxes, other than federal income taxes (7) 5 -- Rate Stabilization Program (1) 2 -- Reacquired debt costs (1) 4 7 Deferred fuel costs -- 1 (4) Other items (7) (3) 10 Investment Tax Credits -- -- 27 ----- ---- ---- Total Expense (Credit) to Operating Expenses (10) 33 32 ----- ---- ---- Nonoperating Income: Current Tax Provision (15) (20) (38) Changes in Accumulated Deferred Federal Income Tax: Write-off of deferred carrying charges (63) -- -- Write-off of Perry Unit 2 (65) -- -- Disallowed nuclear costs 14 7 -- Rate Stabilization Program 4 5 -- AFUDC and carrying charges 5 9 9 Net operating loss carryforward (7) -- 35 Other items (2) -- -- ----- ---- ---- Total Expense (Credit) to Nonoperating Income (129) 1 6 ----- ---- ---- Total Federal Income Tax Expense (Credit) $(139) $ 34 $ 38 ----- ---- ---- ----- ---- ----
The Company joins in the filing of a consolidated federal income tax return with its affiliated companies. The method of tax allocation reflects the benefits and burdens realized by each company's participation in the consolidated tax return, approximating a separate return result for each company. In August 1993, the 1993 Tax Act was enacted. Retroactive to January 1, 1993, the top marginal corporate income tax rate increased to 35%. The change in tax rate increased Accumulated Deferred Federal Income Taxes for the future tax obligation by approximately $29 million. Since the PUCO has historically permitted recovery of such taxes from customers when they become payable, the deferred charge, Amounts Due from Customers for Future Federal Income Taxes, also was increased by $29 million. The 1993 Tax Act is not expected to materially impact future results of operations or cash flow. Under SFAS 109, temporary differences and carryforwards resulted in deferred tax assets of $178 million and deferred tax liabilities of $649 million at December 31, 1993 and deferred tax assets of $154 million and deferred tax liabilities of $794 million at December 31, 1992. These are summarized as follows:
December 31, ----------- 1993 1992 ---- ---- (millions of dollars) Property, plant and equipment $534 $656 Deferred carrying charges and operating expenses 79 119 Net operating loss carryforwards (39) (56) Investment tax credits (55) (58) Other (48) (21) ---- ---- Net deferred tax liability $471 $640 ---- ---- ---- ----
For tax purposes, net operating loss (NOL) carryforwards of approximately $111 million are available to reduce future taxable income and will expire in 2003 through 2005. The 35% tax effect of the NOLs is $39 million. The Tax Reform Act of 1986 provides for an alternative minimum tax (AMT) credit to be used to reduce the regular tax to the AMT level should the regular tax exceed the AMT. AMT credits of $77 million are available to offset future regular tax. The credits may be carried forward indefinitely. (9) Retirement and Postemployment Benefits (A) RETIREMENT INCOME PLAN Prior to December 31, 1993, the Company sponsored a noncontributory pension plan which covered all employee groups. The plan was merged with another plan which covered employees of Cleveland Electric and the Service Company into a single plan on December 31, 1993. The amount of retirement benefits generally depends upon the length of service. Under certain circumstances, benefits can begin as early as age 55. The funding policy is to (Toledo Edison) F-63 (Toledo Edison) 117 comply with the Employee Retirement Income Security Act of 1974 guidelines. In 1993, the Company offered the VTP, an early retirement program. Operating expenses for 1993 included $59 million of pension plan accruals to cover enhanced VTP benefits and an additional $3 million of pension costs for VTP benefits paid to retirees from corporate funds. The $3 million is not included in the pension data reported below. A credit of $15 million resulting from a settlement of pension obligations through lump sum payments to almost all the VTP retirees partially offset the VTP expenses. Net pension and VTP costs for 1991 through 1993 were comprised of the following components:
1993 1992 1991 ---- ---- ---- (millions of dollars) Pension Costs: Service cost for benefits earned during the period $ 5 $ 5 $ 5 Interest cost on projected benefit obligation 11 11 11 Actual return on plan assets (15) (5) (30) Net amortization and deferral 2 (10) 15 ---- ---- ---- Net pension costs 3 1 1 VTP cost 59 -- -- Settlement gain (15) -- -- ---- ---- ---- Net costs $ 47 $ 1 $ 1 ---- ---- ---- ---- ---- ----
The following table presents a reconciliation of the funded status of the Company's former plan at December 31, 1992 with comparable information for a portion of the merged plan at December 31, 1993. The December 31, 1993 benefit obligation estimates were derived from information for the former plans. Plan assets of the merged plan were allocated based on a pro rata share of the projected benefit obligation.
1993 1992 ---- ---- (millions of dollars) Actuarial present value of benefit obligations: Vested benefits $102 $ 95 Nonvested benefits 11 12 ---- ---- Accumulated benefit obligation 113 107 Effect of future compensation levels 16 35 ---- ---- Total projected benefit obligation 129 142 Plan assets at fair market value 118 169 ---- ---- Funded status (11) 27 Unrecognized net gain from variance between assumptions and experience (50) (33) Unrecognized prior service cost 4 5 Transition asset at January 1, 1987 being amortized over 19 years (8) (17) ---- ---- Net accrued pension liability included in Deferred Credits - Other in the Balance Sheet $(65) $(18) ---- ---- ---- ----
At December 31, 1993, the settlement (discount) rate and long-term rate of return on plan assets assumptions were 7.25% and 8.75%, respectively. The long-term rate of annual compensation increase assumption was 4.25%. At December 31, 1992, the settlement rate and long-term rate of return on plan assets assumptions were 8.5% and the long-term rate of annual compensation increase assumption was 5%. Plan assets consist primarily of investments in common stock, bonds, guaranteed investment contracts, cash equivalent securities and real estate. (B) OTHER POSTRETIREMENT BENEFITS Centerior Energy sponsors jointly with its subsidiaries a postretirement benefit plan which provides all employee groups certain health care, death and other postretirement benefits other than pensions. The plan is contributory, with retiree contributions adjusted annually. The plan is not funded. A policy limiting the employer's contribution for retiree medical coverage for employees retiring after March 31, 1993 was implemented in February 1993. The Company adopted SFAS 106, the accounting standard for postretirement benefits other than pensions, effective January 1, 1993. The standard requires the accrual of the expected costs of such benefits during the employees' years of service. Previously, the costs of these benefits were expensed as paid, which is consistent with ratemaking practices. Such costs for the Company totaled $4 million in both 1992 and 1991, which included medical benefits of $3 million in both years. The total amount accrued by the Company for SFAS 106 costs for 1993 was $42 million, of which $1 million was capitalized and $41 million was expensed as other operation and maintenance expenses. In 1993, the Company deferred incremental SFAS 106 expenses totaling $37 million pursuant to a provision of the Rate Stabilization Program. See Note 7. The components of the total postretirement benefit costs for 1993 were as follows:
Millions of Dollars ---------- Service cost for benefits earned $ 1 Interest cost on accumulated postretirement benefit obligation 6 Amortization of transition obligation at January 1, 1993 of $63 million over 20 years 3 VTP curtailment cost (includes $6 million transition obligation adjustment) 32 --- Total costs $ 42 --- ---
These amounts included costs for the Company and a pro rata share of the Service Company's costs. The accumulated postretirement benefit obligation and accrued postretirement benefit cost at December 31, 1993 (Toledo Edison) F-64 (Toledo Edison) 118 for the Company and its share of the Service Company's obligation are summarized as follows:
Millions of Dollars ---------- Accumulated postretirement benefit obligation attributable to: Retired participants $(88) Other active plan participants (9) ----- Accumulated postretirement benefit obligation (97) Unrecognized net loss from variance between assumptions and experience 5 Unamortized transition obligation 54 ----- Accrued postretirement benefit cost $(38) ----- -----
The Balance Sheet classification of Other Noncurrent Liabilities at December 31, 1993 includes only the Company's accrued postretirement benefit cost of $33 million and excludes the Service Company's portion since the Service Company's total accrued cost is carried on its books. At December 31, 1993, the settlement rate and the long-term rate of annual compensation increase assumptions were 7.25% and 4.25%, respectively. The assumed annual health care cost trend rates (applicable to gross eligible charges) are 9.5% for medical and 8% for dental in 1994. Both rates reduce gradually to a fixed rate of 4.75% in 1996 and later years. Elements of the obligation affected by contribution caps are significantly less sensitive to the health care cost trend rate than other elements. If the assumed health care cost trend rates were increased by 1% in each future year, the accumulated postretirement benefit obligation as of December 31, 1993 would increase by $4 million and the aggregate of the service and interest cost components of the annual postretirement benefit cost would increase by $0.3 million. (C) POSTEMPLOYMENT BENEFITS In 1993, the Company adopted SFAS 112, the new accounting standard which requires the accrual of postemployment benefit costs. Postemployment benefits are the benefits provided to former or inactive employees after employment but before retirement, such as worker's compensation, disability benefits and severance pay. The adoption of this accounting method did not materially affect the Company's 1993 results of operations or financial position. (10) Guarantees The Company has guaranteed certain loan and lease obligations of a mining company under a long-term coal purchase arrangement. This arrangement requires payments to the mining company for any actual expenses (as advance payments for coal) when the mines are idle for reasons beyond the control of the mining company. At December 31, 1993, the principal amount of the mining company's loan and lease obligations guaranteed by the Company was $20 million. (11) Capitalization (A) CAPITAL STOCK TRANSACTIONS Preferred stock shares retired during the three years ended December 31, 1993 are listed in the following table.
1993 1992 1991 ---- --- --- (thousands of shares) Subject to Mandatory Redemption: $100 par $11.00 -- (25) (10) 9.375 (17) (17) (17) 25 par 2.81 (800) -- -- ---- --- --- Total (817) (42) (27) ---- --- --- ---- --- ---
(B) EQUITY DISTRIBUTION RESTRICTIONS Federal law prohibits the Company from paying dividends out of capital accounts. However, the Company may pay dividends out of appropriated retained earnings and current earnings. At December 31, 1993, the Company had $42 million of appropriated retained earnings for the payment of preferred stock dividends. The Company is currently prohibited from paying a common stock dividend by a provision in its mortgage. (C) PREFERRED AND PREFERENCE STOCK Amounts to be paid for preferred stock which must be redeemed during the next five years are $12 million in each year 1994 through 1996 and $2 million in both 1997 and 1998. The annual preferred stock mandatory redemption provisions are as follows:
Shares Price To Be Beginning Per Redeemed in Share -------- --------- ----- $100 par $9.375 16,650 1985 $100 25 par 2.81 400,000 1993 25
The annualized preferred dividend requirement at December 31, 1993 was $21 million. The preferred dividend rates on the Company's Series A and B fluctuate based on prevailing interest rates and market conditions. The dividend rates for these issues averaged 7.41% and 8.22%, respectively, in 1993. Preference stock authorized for the Company is 5,000,000 shares with a $25 par value. No preference shares are currently outstanding. With respect to dividend and liquidation rights, the Company's preferred stock is prior to its preference stock and common stock, and its preference stock is prior to its common stock. (Toledo Edison) F-65 (Toledo Edison) 119 (D) LONG-TERM DEBT AND OTHER BORROWING ARRANGEMENTS Long-term debt, less current maturities, was as follows:
Actual or Average Interest Rate at December 31, December 31, --------------- Year of Maturity 1993 1993 1992 - -------------------------------- ------------ ------ ------ (millions of dollars) First mortgage bonds: 1997 6.125% $ 31 $ 31 1998 10.00 1 1 1999-2003 7.46 162 162 2004-2008 7.88 145 145 2009-2013 2.50 31 31 2019-2023 7.06 215 215 ------ ------ 585 585 Secured medium term notes due 1995-2021 8.44 250 182 Term bank loans due 1995-1996 8.77 109 113 Notes due 1995-1997 9.63 43 60 Debentures due 2002 8.70 135 135 Pollution control notes due 1995-2015 12.02 105 105 Other -- net -- (2) (2) ------ ------ Total Long-Term Debt $1,225 $1,178 ------ ------ ------ ------
Long-term debt matures during the next five years as follows: $45 million in 1994, $71 million in 1995, $91 million in 1996 and $39 million in both 1997 and 1998. The Company issued $275 million aggregate principal amount of secured medium-term notes during the 1991-1993 period. The notes are secured by first mortgage bonds. The Company's mortgage constitutes a direct first lien on substantially all property owned and franchises held by the Company. Excluded from the lien, among other things, are cash, securities, accounts receivable, fuel, supplies and automotive equipment. Certain unsecured loan agreements of the Company contain covenants relating to capitalization ratios, fixed charge coverage ratios and limitations on secured financing other than through first mortgage bonds or certain other transactions. Two reimbursement agreements relating to separate letters of credit issued in connection with the sale and leaseback of Beaver Valley Unit 2 contain several financial covenants affecting the Company, Cleveland Electric and Centerior Energy. Among these are covenants relating to fixed charge coverage ratios and capitalization ratios. The write-offs recorded at December 31, 1993 caused the Company, Cleveland Electric and Centerior Energy to violate certain covenants contained in the two reimbursement agreements. The affected creditors have waived those violations in exchange for commitments to provide them with a second mortgage security interest on property of the Company and Cleveland Electric and other considerations. We expect to complete this process in the second quarter of 1994. We will provide the same security interest to certain other creditors because their agreements require equal treatment. We expect to provide second mortgage collateral for $172 million of unsecured debt, $228 million of bank letters of credit and a $205 million revolving credit facility. The bank letters of credit and revolving credit facility are joint and several obligations of the Company and Cleveland Electric. (12) Short-Term Borrowing Arrangements In May 1993, Centerior Energy arranged for a $205 million, three-year revolving credit facility. The facility may be renewed twice for one-year periods at the option of the participating banks. Centerior Energy and the Service Company may borrow under the facility, with all borrowings jointly and severally guaranteed by the Company and Cleveland Electric. Centerior Energy plans to transfer any of its borrowed funds to the Company and Cleveland Electric, while the Service Company may borrow up to $25 million for its own use. The banks' fee is 0.5% per annum payable quarterly in addition to interest on any borrowings. That fee is expected to increase to 0.625% when the facility agreement is amended as discussed below. There were no borrowings under the facility at December 31, 1993. The facility agreement contains covenants relating to capitalization and fixed charge coverage ratios for the Company, Cleveland Electric and Centerior Energy. The write-offs recorded at December 31, 1993 caused the ratios to fall below those covenant requirements. The revolving credit facility is expected to be available for borrowings after the facility agreement is amended in the second quarter of 1994 to provide the participating creditors with a second mortgage security interest. Short-term borrowing capacity authorized by the PUCO annually is $150 million for the Company. The Company and Cleveland Electric are authorized by the PUCO to borrow from each other on a short-term basis. At December 31, 1993, the Company had no commercial paper outstanding. The Company is unable to rely on the sale of commercial paper to provide short-term funds because of its below investment grade commercial paper credit ratings. (Toledo Edison) F-66 (Toledo Edison) 120 (13) Financial Instruments' Fair Value The estimated fair values at December 31, 1993 and 1992 of financial instruments that do not approximate their carrying amounts are as follows:
December 31, ---------------------------------- 1993 1992 ---------------- ---------------- Carrying Fair Carrying Fair Amount Value Amount Value -------- ------ -------- ------ (millions of dollars) Nuclear Plant Decommissioning Trusts $ 26 $ 27 $ 20 $ 21 Preferred Stock, with Mandatory Redemption Provisions (including current portion) 40 42 62 66 Long-Term Debt (including current portion) 1,271 1,314 1,225 1,221
The fair value of the nuclear plant decommissioning trusts is estimated based on the quoted market prices for the investment securities. The fair value of the Company's preferred stock with mandatory redemption provisions and long-term debt is estimated based on the quoted market prices for the respective or similar issues or on the basis of the discounted value of future cash flows. The discounted value used current dividend or interest rates (or other appropriate rates) for similar issues and loans with the same remaining maturities. The estimated fair values of all other financial instruments approximate their carrying amounts in the Balance Sheet at December 31, 1993 and 1992 because of their short-term nature. (14) Quarterly Results of Operations (Unaudited) The following is a tabulation of the unaudited quarterly results of operations for the two years ended December 31, 1993.
Quarters Ended ---------------------------------------- March 31, June 30, Sept. 30, Dec. 31, --------- -------- --------- -------- (millions of dollars) 1993 Operating Revenues $ 215 $210 $ 239 $ 207 Operating Income (Loss) 39 42 17 (10) Net Income (Loss) 18 20 (5) (323) Earnings (Loss) Available for Common Stock 12 14 (10) (328) 1992 Operating Revenues $ 207 $202 $ 225 $ 210 Operating Income 38 29 52 31 Net Income 11 4 36 20 Earnings (Loss) Available for Common Stock 5 (3) 30 14
Earnings for the quarter ended September 30, 1993 were decreased by $35 million as a result of the recording of $54 million of VTP pension-related benefits. Earnings for the quarter ended December 31, 1993 were decreased as a result of year-end adjustments for the $232 million write-off of Perry Unit 2 (see Note 4(b)), the $241 million write-off of the phase-in deferrals (see Note 7) and $19 million of other charges. These adjustments decreased quarterly earnings by $345 million. Earnings for the quarter ended September 30, 1992 were increased by $15 million as a result of the recording of deferred operating expenses and carrying charges for the first nine months of 1992 totaling $22 million under the Rate Stabilization Program approved by the PUCO in October 1992. See Note 7. (15) Pending Merger of the Company with Cleveland Electric On March 25, 1994, Centerior Energy announced that its operating utility subsidiaries, the Company and Cleveland Electric, plan to merge into a single operating entity. Since the Company and Cleveland Electric affiliated in 1986, efforts have been made to consolidate operations and administration as much as possible to achieve maximum cost savings. The merger of the two companies into a single entity is the completion of this consolidation process. Various aspects of the merger are subject to the approval of the FERC, the PUCO and other regulatory authorities. The merger must be approved by share owners of the Company's preferred stock. Share owners of Cleveland Electric's preferred stock must approve the authorization of additional shares of preferred stock. Share owners of the Company's preferred stock will exchange their shares for preferred stock shares of the successor corporation having substantially the same terms, while Cleveland Electric's preferred stock will automatically become shares of the successor corporation. Debt holders of the merging companies will become debt holders of the successor corporation. The merging companies plan to seek preferred stock share owner approval in the summer of 1994. The merger is expected to be effective in late 1994. For the merging companies, the combined pro forma operating revenues were $2.475 billion, $2.439 billion and $2.561 billion and the combined pro forma net income (loss) was $(876) million, $276 million and $296 million for the years ended December 31, 1993, 1992 and 1991, respectively. The pro forma data is based on accounting for the merger on a method similar to a pooling of interests. The pro forma data is not necessarily indicative of the results of operations which would have been reported had the merger been in effect during those years or which may be reported in the future. The pro forma data should be read in conjunction with the audited financial statements of both the Company and Cleveland Electric. (Toledo Edison) F-67 (Toledo Edison) 121 FINANCIAL AND STATISTICAL REVIEW - ---------------------------------------------------------------------- Operating Revenues (millions of dollars)
Steam Total Total Heating Year Residential Commercial Industrial Other Retail Wholesale Electric & Gas - ----------------------------------------------------------------------------------------------------------------------- 1993 $ 229 180 244 71 724 147 871 -- 1992 215 175 236 61 687 158 845 -- 1991 230 184 236 90 740 147 887 -- 1990 224 175 236 78 713 150 863 -- 1989 216 164 227 99 706 160 866 -- 1983 161 105 170 42 478 21 499 9 Operating Year Revenues - ---------- ---------- 1993 $ 871 1992 845 1991 887 1990 863 1989 866 1983 508
- -------------------------------------------------------------------------------- Operating Expenses (millions of dollars)
Other Deferred Federal Fuel & Operation Depreciation Taxes, Operating Income Total Purchased & & Other Than Expenses, Taxes Operating Year Power Maintenance Amortization FIT Net (Credit) Expenses - ------------------------------------------------------------------------------------------------------------------ 1993 $ 173 456(a) 76 91 (4)(b) (10) $ 782 1992 169 342 77 91 (17) 33 695 1991 178 356 72(c) 89 1 32 728 1990 174 373 73 79 (10) 21 710 1989 172 373 85 72 (16) 37 723 1983 125 115 51 45 -- 57 393
- -------------------------------------------------------------------------------- Income (Loss) (millions of dollars)
Federal Income Other Deferred Income (Loss) Income & Carrying Taxes-- Before Operating AFUDC-- Deductions, Charges, Credit Interest Year Income Equity Net Net (Expense) Charges - ---------------------------------------------------------------------------------------------- 1993 $ 89 1 (232)(d) (161)(b) 129 $ (174) 1992 150 1 1 41 (1) 192 1991 159 1 5 22 (6) 181 1990 153 3 5 43 9 213 1989 143 9 20 82 (22) 232 1983 115 66 1 -- 24 206
- -------------------------------------------------------------------------------- Income (Loss) (millions of dollars)
Earnings (Loss) Net Preferred Available for Debt AFUDC-- Income Stock Common Year Interest Debt (Loss) Dividends Stock - -------------------------------------------------------------------------------- 1993 $116 (1) (289) 23 $(312) 1992 122 (1) 71 24 47 1991 132 (1) 50 25 25 1990 135 (3) 81 25 56 1989 145 (5) 92 25 67 1983 104 (26) 128 30 98
- -------------------------------------------------------------------------------- (a) Includes early retirement program expenses and other charges of $107 million in 1993. (b) Includes write-off of phase-in deferrals of $241 million in 1993, consisting of $55 million of deferred operating expenses and $186 million of deferred carrying charges. (c) In 1991, a change in accounting for nuclear plant depreciation was adopted, changing from the units-of-production method to the straight-line method at a 2.5% rate. (Toledo Edison) F-68 (Toledo Edison) 122 The Toledo Edison Company
Electric Sales (millions of KWH) Electric Customers (year end) Industrial Year Residential Commercial Industrial Wholesale Other Total Residential Commercial & Other - --------------------------------------------------------------------------------------- --------------------------------------- 1993 2 039 1 672 3 776 2 146 490 10 123 255 109 26 049 4 076 1992 1 941 1 619 3 563 2 753 478 10 354 255 299 25 870 4 372 1991 2 041 1 683 3 543 2 587 482 10 336 254 500 26 044 4 444 1990 1 950 1 614 3 617 2 333 496 10 010 253 965 25 822 4 555 1989 2 017 1 622 3 740 3 138 495 11 012 253 234 25 803 4 434 1983 1 915 1 341 3 127 476 428 7 287 242 959 23 694 3 864 Residential Usage Average Average Average Price Revenue KWH Per Per Per Year Total Customer KWH Customer - ------- --------- --------------------------------- 1993 285 234 7 997 11.23c $897.65 1992 285 541 7 632 11.08 845.99 1991 284 988 7 990 11.26 897.41 1990 284 342 7 692 11.48 882.99 1989 283 471 7 989 10.71 855.29 1983 270 517 7 900 8.44 665.43
- --------------------------------------------------------------------------------
Load (MW & %) Energy (millions of KWH) Fuel Operable Capacity Company Generated at Time Peak Capacity Load ----------------------------- Purchased Fuel Cost Year of Peak Load Margin Factor Fossil Nuclear Total Power Total Per KWH - -------------------------------------------------------- --------------------------------------------------------- --------- 1993 1 874 1 568 16.3% 64.3% 5 548 4 791 10 339 196 10 535 1.42c 1992 1 727 1 514 12.3 63.2 4 656 6 293 10 949 (82) 10 867 1.41 1991 1 758 1 510 14.1 64.5 4 848 6 003 10 851 95 10 946 1.44 1990 1 752 1 516 13.5 63.0 5 535 4 219 9 754 902 10 656 1.50 1989 1 894 1 526 19.4 65.2 5 206 5 552 10 758 788 11 546 1.42 1983 1 777 1 325 25.4 65.6 4 683 2 383 7 066 749 7 815 1.67 Efficiency-- BTU Per Year KWH - ------------ ---------- 1993 10 146 1992 10 284 1991 10 327 1990 10 220 1989 10 293 1983 10 337
- -------------------------------------------------------------------------------- Investment (millions of dollars)
Construction Utility Work In Total Plant Accumulated Progress Nuclear Property, Utility In Depreciation & Net & Perry Fuel and Plant and Plant Total Year Service Amortization Plant Unit 2 Other Equipment Additions Assets - ----------------------------------------------------------------------------------------------- --------- ------- 1993 $2 837 788 2 049 40 142 $ 2 231 $ 43 $3 510 1992 2 847 760 2 087 280 164 2 531 44 3 939 1991 2 692 709 1 983 308 198 2 489 54 3 926 1990 2 604 640 1 964 349 224 2 537 87 3 913 1989 2 528 565 1 963 342 237 2 542 73 4 051 1983 1 342 325 1 017 1 094 164(e) 2 275 294 2 501
- --------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------- 1993 $623 30% 28 1% 210 10% 1 225 59% $2 086 1992 935 39 50 2 210 9 1 178 50 2 373 1991 888 38 64 3 210 9 1 158 50 2 320 1990 881 39 66 3 210 9 1 097 49 2 254 1989 898 38 69 3 210 9 1 197 50 2 374 1983 716 36 94 5 200 10 985 49 1 995
- -------------------------------------------------------------------------------- (d) Includes write-off of Perry Unit 2 of $232 million in 1993. (e) Restated for effects of capitalization of nuclear fuel lease and financing arrangements pursuant to Statement of Financial Accounting Standards 71. (Toledo Edison) F-69 (Toledo Edison) 123 INDEX TO SCHEDULES
Page Centerior Energy Corporation and Subsidiaries: Schedule V Property, Plant and Equipment for the Years S-2 Ended December 31, 1993, 1992 and 1991 Schedule VI Accumulated Depreciation and Amortization of S-5 Property, Plant and Equipment for the Years Ended December 31, 1993, 1992 and 1991 Schedule VII Guarantees of Securities of Other Issuers for S-8 the Year Ended December 31, 1993 Schedule VIII Valuation and Qualifying Accounts for the S-9 Years Ended December 31, 1993, 1992 and 1991 Schedule IX Short-Term Borrowings for the Years Ended S-10 December 31, 1993, 1992 and 1991 Schedule X Supplementary Income Statement Information for S-11 the Years Ended December 31, 1993, 1992 and 1991 The Cleveland Electric Illuminating Company and Subsidiaries: Schedule V Property, Plant and Equipment for the Years S-12 Ended December 31, 1993, 1992 and 1991 Schedule VI Accumulated Depreciation and Amortization of S-15 Property, Plant and Equipment for the Years Ended December 31, 1993, 1992 and 1991 Schedule VII Guarantees of Securities of Other Issuers for S-18 the Year Ended December 31, 1993 Schedule VIII Valuation and Qualifying Accounts for the S-19 Years Ended December 31, 1993, 1992 and 1991 Schedule IX Short-Term Borrowings for the Years Ended S-20 December 31, 1993, 1992 and 1991 Schedule X Supplementary Income Statement Information for S-21 the Years Ended December 31, 1993, 1992 and 1991 The Toledo Edison Company: Schedule V Property, Plant and Equipment for the Years S-22 Ended December 31, 1993, 1992 and 1991 Schedule VI Accumulated Depreciation and Amortization of S-25 Property, Plant and Equipment for the Years Ended December 31, 1993, 1992 and 1991 Schedule VII Guarantees of Securities of Other Issuers for S-28 the Year Ended December 31, 1993 Schedule VIII Valuation and Qualifying Accounts for the S-29 Years Ended December 31, 1993, 1992 and 1991 Schedule IX Short-Term Borrowings for the Years Ended S-30 December 31, 1993, 1992 and 1991 Schedule X Supplementary Income Statement Information for S-31 the Years Ended December 31, 1993, 1992 and 1991 Schedules other than those listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the financial statements or notes thereto.
S-1 124 CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars)
Balance at Retirements Balance at Beginning of Additions or End of Classification Period at Cost Sales Other Period - -------------- ------------ ------------ ------------ ------------ ------------ Utility Plant (Electric): Intangible $35,040 ($72) $0 $0 $34,968 Production: Steam 1,401,660 53,173 (5,251) (44,745)(a) 1,404,837 Nuclear 5,648,748 35,382 (17,782) 0 5,666,348 Hydraulic 59,857 4,335 (1) 0 64,191 Other 14,750 33 (10) 0 14,773 Transmission 736,331 27,952 (1,625) 1,010 (a) 763,668 Distribution 1,330,851 73,245 (6,731) 0 1,397,365 General 221,763 4,062 (852) 1 224,974 ------------ ------------ ------------ ------------ ------------ Total Utility Plant 9,449,000 198,110 (32,252) (43,734) 9,571,124 Perry Unit 2 (b) 826,674 (31,436) 0 (795,238)(c) 0 Construction Work in Progress 167,139 26,082 (72) (12,218)(a) 180,931 Nuclear Fuel 1,038,327 45,823 0 0 1,084,150 Other Property 47,343 51 (18) 55,953 (a) 103,329 ------------ ------------ ------------ ------------ ------------ Total Property, Plant and Equipment $11,528,483 $238,630 ($32,342) ($795,237) $10,939,534 ============ ============ ============ ============ ============ (a) Transfer of Acme Plant Unit 2 to future use and nonutility property and reclassification of future use property. (b) Includes Perry Unit 2 AFUDC. See Schedule VIII. (c) Write-off of Perry Unit 2 investment.
S-2 125 CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1992 (Thousands of Dollars)
Balance at Retirements Balance at Beginning of Additions or End of Classification Period at Cost Sales Other Period -------------- ------------ ------------ ------------ ------------ ------------ Utility Plant (Electric): Intangible $34,774 $266 $0 $0 $35,040 Production: Steam 1,413,761 45,619 (72,212) 14,492 (a) 1,401,660 Nuclear 5,227,393 78,403 (12,128) 355,080 (a) 5,648,748 Hydraulic 55,427 5,024 (594) 0 59,857 Other 14,750 0 0 0 14,750 Transmission 710,217 19,467 (1,051) 7,698 (a) 736,331 Distribution 1,233,176 99,503 (3,948) 2,120 (a) 1,330,851 General 198,721 24,809 (1,767) 0 221,763 ------------ ------------ ------------ ------------ ------------ Total Utility Plant 8,888,219 273,091 (91,700) 379,390 9,449,000 Perry Unit 2 (b) 850,573 (23,899) 0 0 826,674 Construction Work in Progress 215,855 (48,434) (282) 0 167,139 Nuclear Fuel 985,781 52,546 0 0 1,038,327 Other Property 64,763 (671) (16,749) 0 47,343 ------------ ------------ ------------ ------------ ------------ Total Property, Plant and Equipment $11,005,191 $252,633 ($108,731) $379,390 $11,528,483 ============ ============ ============ ============ ============ (a) Results from adoption of SFAS 109 in 1992, which requires the presentation of amounts on a pre-tax basis. Such amounts were previously stated on a net-of-tax basis. (b) Includes Perry Unit 2 AFUDC. See Schedule VIII.
S-3 126 CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1991 (Thousands of Dollars)
Balance at Retirements Balance at Beginning of Additions or End of Classification Period at Cost Sales Other Period -------------- ------------ ------------ ------------ ------------ ------------ Utility Plant (Electric): Intangible $22,035 $12,739 $0 $0 $34,774 Production: Steam 1,338,332 80,909 (5,480) 0 1,413,761 Nuclear 5,123,492 105,296 (1,395) 0 5,227,393 Hydraulic 56,354 (557) (370) 0 55,427 Other 14,693 48 9 0 14,750 Transmission 694,181 16,667 (631) 0 710,217 Distribution 1,199,941 37,674 (4,439) 0 1,233,176 General 187,191 18,174 (6,644) 0 198,721 ------------ ------------ ------------ ------------ ------------ Total Utility Plant 8,636,219 270,950 (18,950) 0 8,888,219 Perry Unit 2 (a) 865,149 (14,576) 0 0 850,573 Construction Work in Progress 268,386 (52,531) 0 0 215,855 Nuclear Fuel 927,268 58,513 0 0 985,781 Other Property 63,524 1,254 (15) 0 64,763 ------------ ------------ ------------ ------------ ------------ Total Property, Plant and Equipment $10,760,546 $263,610 ($18,965) $0 $11,005,191 ============ ============ ============ ============ ============ (a) Includes Perry Unit 2 AFUDC. See Schedule VIII.
S-4 127 CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars)
Additions Deductions ---------------------------- ------------------------------ Balance at Charged to Removal Cost Balance at Beginning of Income Net of Salvage End of Description Period Statement Other Retirements Add/(Deduct) Period - ----------- ------------ ------------ ------------ ------------ -------------- ------------ Utility Plant: Electric - Depreciation $2,466,961 $276,251 ($47,780)(a)(b) ($32,095) ($14,782) $2,648,555 - Amortization 21,476 7,337 0 0 0 28,813 ------------ ------------ ------------ ------------ ------------ ------------ Total Utility Plant 2,488,437 283,588 (c) (47,780) (32,095) (14,782) 2,677,368 Other Property - Depreciation 8,166 1,480 (d) 52,875 (b) 0 0 62,521 ------------ ------------ ------------ ------------ ------------ ------------ Total $2,496,603 $285,068 $5,095 ($32,095) ($14,782) $2,739,889 ============ ============ ============ ============ ============ ============ Nuclear Fuel - Amortization $653,776 $85,732 (e) $0 $0 $0 $739,508 ============ ============ ============ ============ ============ ============ (a) Includes nuclear plant decommissioning trust earnings charged to the trust accounts and depreciation charged to construction work in progress. (b) Transfer of accumulated depreciation for Acme Plant Unit 2 and reclassification of accumulated depreciation for future use property. (c) Depreciation and amortization, as reported in the Income Statement, includes approximately $27 million of amortization of investment tax credits. (d) Nonutility plant expense charged to other income and deductions, net. (e) Charged to fuel and purchased power expense.
S-5 128 CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1992 (Thousands of Dollars)
Additions Deductions ---------------------------- ------------------------------ Balance at Charged to Removal Cost Balance at Beginning of Income Net of Salvage End of Description Period Statement Other Retirements Add/(Deduct) Period - ----------- ------------ ------------ ------------ ------------ -------------- ------------ Utility Plant: Electric - Depreciation $2,260,186 $261,943 $52,593 (a) ($91,982) ($15,779) $2,466,961 - Amortization 14,303 7,173 0 0 0 21,476 ------------ ------------ ------------ ------------ ------------ ------------ Total Utility Plant 2,274,489 269,116 (b) 52,593 (91,982) (15,779) 2,488,437 Other Property - Depreciation 20,250 2,049 (c) 0 (14,129) (4) 8,166 ------------ ------------ ------------ ------------ ------------ ------------ Total $2,294,739 $271,165 $52,593 ($106,111) ($15,783) $2,496,603 ============ ============ ============ ============ ============ ============ Nuclear Fuel - Amortization $527,367 $126,409 (d) $0 $0 $0 $653,776 ============ ============ ============ ============ ============ ============ (a) Includes adjustment resulting from adoption of SFAS 109 in 1992 ($48.1 million), nuclear plant decommissioning trust earnings charged to the trust accounts, and depreciation charged to construction work in progress. (b) Depreciation and amortization, as reported in the Income Statement, includes approximately $13 million of amortization of investment tax credits. (c) Nonutility plant expense charged to other income and deductions, net. (d) Charged to fuel and purchased power expense.
S-6 129 CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1991 (Thousands of Dollars)
Additions Deductions ---------------------------- ------------------------------ Balance at Charged to Removal Cost Balance at Beginning of Income Net of Salvage End of Description Period Statement Other Retirements Add/(Deduct) Period - ----------- ------------ ------------ ------------ ------------ -------------- ------------ Utility Plant: Electric - Depreciation $2,030,437 $248,231 $3,555 (a)(b) ($18,950) ($3,087) $2,260,186 - Amortization 8,073 5,679 551 (b) 0 0 14,303 ------------ ------------ ------------ ------------ ------------ ------------ Total Utility Plant 2,038,510 253,910 (c) 4,106 (18,950) (3,087) 2,274,489 Other Property - Depreciation 18,072 2,178 (d) 0 0 0 20,250 ------------ ------------ ------------ ------------ ------------ ------------ Total $2,056,582 $256,088 $4,106 ($18,950) ($3,087) $2,294,739 ============ ============ ============ ============ ============ ============ Nuclear Fuel - Amortization $404,596 $122,771 (e) $0 $0 $0 $527,367 ============ ============ ============ ============ ============ ============ (a) Includes nuclear plant decommissioning trust earnings charged to the trust accounts and depreciation charged to construction work in progress. (b) Transfer from accumulated depreciation to accumulated amortization. (c) Depreciation and amortization, as reported in the Income Statement, includes approximately $11 million of amortization of investment tax credits. (d) Nonutility plant expense charged to other income and deductions, net. (e) Charged to fuel and purchased power expense.
S-7 130 CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE VII - GUARANTEES OF SECURITIES OF OTHER ISSUERS YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars)
Principal Amount Name of Issuer of Guaranteed and Securities Guaranteed Title of Issue (a) Outstanding (a) Nature of Guarantee - -------------------------------- ----------------------------- --------------- ------------------- Quarto Mining Company (b) Guaranteed Mortgage Bonds, due 2000 Series A 8.25% $821 Principal and Interest Series B 9.70% 801 Principal and Interest Series C 9.40% 4,007 Principal and Interest Series EA 10.25% 954 Principal and Interest Series FA 10.50% 731 Principal and Interest Series G 9.05% 12,098 Principal and Interest Series HA 7.75% 9,308 Principal and Interest Series HB 8.31% 5,395 Principal and Interest Guaranteed Refunding Bonds, Series I, 7.45%, due 1997 7,381 Principal and Interest Unsecured Note, interest at prime (6% effective 7/1/93 and applicable through 12/31/93) plus 2%, due 2000 2,849 Principal and Interest Equipment Leases 8,557 Termination Value per Agreements -------- 52,902 -------- The 0hio Valley Coal Company First Mortgage Notes, Series D, 8.00%, due 1994 to 1997 5,200 Principal and Interest Series E, 10.25%, due 1994 to 1997 2,310 Principal and Interest Equipment Leases 4,129 Stipulated Loss Value per Agreements Term Notes, 9.53%, due 1994 to 1996 1,525 Principal and Interest 10.85%, due 1994 to 1997 13,952 Principal and Interest -------- 27,116 -------- $80,018 ======== (a) None of the securities were owned by the Operating Companies; none were held in the treasury of the issuer; and none were in default. (b) The Operating Companies and the other CAPCO Group Companies have agreed to guarantee severally, and not jointly, their proportionate shares of Quarto Mining Company debt and lease obligations incurred while developing and equipping the mines. The amounts shown are the Operating Companies' proportionate share of the total obligations.
S-8 131 CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (Thousands of Dollars)
Additions Deductions ---------------------------------------- ------------------------ Balance at Charged to Deductions Balance at Beginning Income from End of Description of Period Statement Other Reserves Other Period - ----------- ---------- --------- ------- ---------- ------- -------- Reflected as Reductions to the Related Assets: Accumulated Provision for Uncollectible Accounts (Deduction from Amounts Due from Customers and Others) 1993 $3,723 $14,139 (a) $3,516 (b) $17,675 (a)(c) $0 $3,703 1992 3,703 19,673 (a) 2,376 (b) 22,029 (a)(c) 0 3,723 1991 3,026 20,567 (a) 3,192 (b) 23,082 (a)(c) 0 3,703 Reserve for Perry Unit 2 Allowance for Funds Used During Construction (Deduction from Perry Unit 2) 1993 $212,693 $0 $0 $212,693 (d) $0 $0 1992 212,693 0 0 0 0 212,693 1991 212,693 0 0 0 0 212,693 (a) Includes a provision and corresponding write-off of uncollectible accounts of $4,550,000, $5,968,000 and $6,020,000 in 1993, 1992 and 1991, respectively, relating to customers which qualify for the PUCO mandated Percentage of Income Payment Plan (PIPP). Such uncollectible accounts are recovered through a separate 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 cases. The amounts deferred for future recovery were $971,000 and $37,000 in 1993 and 1992, respectively. (c) Uncollectible accounts written off. (d) Write-off of Perry Unit 2 investment.
S-9 132 CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE IX - SHORT-TERM BORROWINGS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (Thousands of Dollars)
Average Weighted Daily Average Average Maximum Weighted Daily Balance Interest Amount Amount Weighted at End Rate at Outstanding Outstanding Interest of End of During the During the Rate During Category Period Period Period Period the Period -------- ------------ ------------ ------------- ------------ ------------ Commercial Paper ---------------- 1993 $0 0.0% $36,900 $2,688 (a) 4.1% (b) 1992 0 0.0 101,800 16,823 (a) 4.5 (b) 1991 0 0.0 170,900 61,781 (a) 7.4 (b) Uncommitted Financing Facility ------------------------------ 1993 $0 0.0% $80,001 $19,710 (a) 3.8% (b) 1992 49,502 4.4 80,003 38,952 (a) 4.1 (b) Not applicable for 1991. (a) Computed by dividing the total of the daily outstanding balances for the year by 365 days (366 for 1992). (b) Computed by dividing total interest expense for the year by the average daily balance outstanding.
S-10 133 CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (Thousands of Dollars)
Item 1993 1992 1991 ---- ------------ ------------ ------------ Maintenance and Repairs -- Charged to Operating Expenses $174,332 $184,183 $174,121 ============ ============ ============ Taxes, Other Than Payroll and Income Taxes: Charged to Operating Expenses: Real and Personal Property Taxes $170,346 $171,603 $163,123 Ohio State Excise Taxes 109,865 111,316 106,672 Other 9,371 11,452 11,883 ------------ ------------ ------------ Total Charged to Operating Expenses 289,582 294,371 281,678 Total Charged to Nonoperating Income 622 129 684 ------------ ------------ ------------ Total $290,204 $294,500 $282,362 ============ ============ ============
S-11 134 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars)
Balance at Retirements Balance at Beginning of Additions or End of Classification Period at Cost Sales Other Period -------------- ------------ ------------ ------------ ------------ ------------ Utility Plant (Electric): Intangible $22,647 ($21) $0 $0 $22,626 Production: Steam 1,121,056 50,631 (4,177) 0 1,167,510 Nuclear 3,737,103 19,314 (11,474) 0 3,744,943 Hydraulic 59,857 4,335 (1) 0 64,191 Other 8,075 0 0 0 8,075 Transmission 584,813 23,935 (1,038) 0 607,710 Distribution 923,022 52,425 (5,797) 0 969,650 General 145,223 4,983 (781) 0 149,425 ------------ ------------ ------------ ------------ ------------ Total Utility Plant 6,601,796 155,602 (23,268) 0 6,734,130 Perry Unit 2 (a) 495,296 (20,361) 0 (474,935)(b) 0 Construction Work in Progress 130,327 21,783 (72) (10,616)(c) 141,422 Nuclear Fuel 582,380 26,053 0 0 608,433 Other Property 43,260 50 (18) 10,616 (c) 53,908 ------------ ------------ ------------ ------------ ------------ Total Property, Plant and Equipment $7,853,059 $183,127 ($23,358) ($474,935) $7,537,893 ============ ============ ============ ============ ============ (a) Includes Perry Unit 2 AFUDC. See Schedule VIII. (b) Write-off of Perry Unit 2 investment. (c) Reclassification of future use property.
S-12 135 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1992 (Thousands of Dollars)
Balance at Retirements Balance at Beginning of Additions or End of Classification Period at Cost Sales Other Period -------------- ------------ ------------ ------------ ------------ ------------ Utility Plant (Electric): Intangible $22,462 $185 $0 $0 $22,647 Production: Steam 1,104,815 38,830 (35,012) 12,423 (a) 1,121,056 Nuclear 3,461,108 51,556 (6,298) 230,737 (a) 3,737,103 Hydraulic 55,427 5,024 (594) 0 59,857 Other 8,075 0 0 0 8,075 Transmission 561,188 17,597 (1,028) 7,056 (a) 584,813 Distribution 857,392 66,747 (3,038) 1,921 (a) 923,022 General 125,478 20,512 (767) 0 145,223 ------------ ------------ ------------ ------------ ------------ Total Utility Plant 6,195,945 200,451 (46,737) 252,137 6,601,796 Perry Unit 2 (b) 507,806 (12,510) 0 0 495,296 Construction Work in Progress 161,890 (31,281) (282) 0 130,327 Nuclear Fuel 551,934 30,446 0 0 582,380 Other Property 60,667 (688) (16,719) 0 43,260 ------------ ------------ ------------ ------------ ------------ Total Property, Plant and Equipment $7,478,242 $186,418 ($63,738) $252,137 $7,853,059 ------------ ------------ ------------ ------------ ------------ (a) Results from adoption of SFAS 109 in 1992, which requires the presentation of amounts on a pre-tax basis. Such amounts were previously stated on a net-of-tax basis. (b) Includes Perry Unit 2 AFUDC. See Schedule VIII.
S-13 136 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1991 (Thousands of Dollars)
Balance at Retirements Balance at Beginning of Additions or End of Classification Period at Cost Sales Other Period - -------------- ------------ ------------ ------------ ------------ ------------ Utility Plant (Electric): Intangible $18,499 $3,963 $0 $0 $22,462 Production: Steam 1,046,921 63,374 (5,480) 0 1,104,815 Nuclear 3,405,230 56,601 (723) 0 3,461,108 Hydraulic 56,354 (557) (370) 0 55,427 Other 7,967 99 9 0 8,075 Transmission 547,300 14,518 (630) 0 561,188 Distribution 833,153 27,823 (3,584) 0 857,392 General 116,912 11,184 (2,618) 0 125,478 ------------ ------------ ------------ ------------ ------------ Total Utility Plant 6,032,336 177,005 (13,396) 0 6,195,945 Perry Unit 2 (a) 521,464 (13,658) 0 0 507,806 Construction Work in Progress 175,232 (13,342) 0 0 161,890 Nuclear Fuel 520,762 31,172 0 0 551,934 Other Property 60,221 461 (15) 0 60,667 ------------ ------------ ------------ ------------ ------------ Total Property, Plant and Equipment $7,310,015 $181,638 ($13,411) $0 $7,478,242 ============ ============ ============ ============ ============ (a) Includes Perry Unit 2 AFUDC. See Schedule VIII.
S-14 137 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars)
Additions Deductions ---------------------------- ------------------------------ Balance at Charged to Removal Cost Balance at Beginning of Income Net of Salvage End of Description Period Statement Other Retirements Add/(Deduct) Period - ----------- ------------ ------------ ------------ ------------ -------------- ------------ Utility Plant: Electric - Depreciation $1,711,620 $193,085 ($1,762)(a)(b) ($23,111) ($11,456) $1,868,376 - Amortization 16,496 4,712 0 0 0 21,208 ------------ ------------ ------------ ------------ ------------ ------------ Total Utility Plant 1,728,116 197,797 (c) (1,762) (23,111) (11,456) 1,889,584 Other Property - Depreciation 6,694 1,409 (d) 4,764 (b) 0 0 12,867 ------------ ------------ ------------ ------------ ------------ ------------ Total $1,734,810 $199,206 $3,002 ($23,111) ($11,456) $1,902,451 ============ ============ ============ ============ ============ ============ Nuclear Fuel - Amortization $358,861 $47,372 (e) $0 $0 $0 $406,233 ============ ============ ============ ============ ============ ============ (a) Includes nuclear plant decommissioning trust earnings charged to the trust accounts and depreciation charged to construction work in progress. (b) Reclassification of accumulated depreciation for future use property. (c) Depreciation and amortization, as reported in the Income Statement, includes approximately $17 million of amortization of investment tax credits. (d) Nonutility plant expense charged to other income and deductions, net. (e) Charged to fuel and purchased power expense.
S-15 138 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1992 (Thousands of Dollars)
Additions Deductions ---------------------------- ------------------------------ Balance at Charged to Removal Cost Balance at Beginning of Income Net of Salvage End of Description Period Statement Other Retirements Add/(Deduct) Period - ----------- ------------ ------------ ------------ ------------ -------------- ------------ Utility Plant: Electric - Depreciation $1,552,870 $182,706 $34,385 (a) ($47,019) ($11,322) $1,711,620 - Amortization 12,114 4,382 0 0 0 16,496 ------------ ------------ ------------ ------------ ------------ ------------ Total Utility Plant 1,564,984 187,088 (b) 34,385 (47,019) (11,322) 1,728,116 Other Property - Depreciation 18,833 1,960 (c) 0 (14,099) 0 6,694 ------------ ------------ ------------ ------------ ------------ ------------ Total $1,583,817 $189,048 $34,385 ($61,118) ($11,322) $1,734,810 ============ ============ ============ ============ ============ ============ Nuclear Fuel - Amortization $288,805 $70,056 (d) $0 $0 $0 $358,861 ============ ============ ============ ============ ============ ============ (a) Includes adjustment resulting from adoption of SFAS 109 in 1992 ($31.5 million), nuclear plant decommissioning trust earnings charged to the trust accounts, and depreciation charged to construction work in progress. (b) Depreciation and amortization, as reported in the Income Statement, includes approximately $8 million of amortization of investment tax credits. (c) Nonutility plant expense charged to other income and deductions, net. (d) Charged to fuel and purchased power expense.
S-16 139 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1991 (Thousands of Dollars)
Additions Deductions ---------------------------- ------------------------------ Balance at Charged to Removal Cost Balance at Beginning of Income Net of Salvage End of Description Period Statement Other Retirements Add/(Deduct) Period - ----------- ------------ ------------ ------------ ------------ -------------- ------------ Utility Plant: Electric - Depreciation $1,391,080 $173,126 $1,794 (a)(b) ($13,396) $266 $1,552,870 - Amortization 7,178 4,385 551 (b) 0 0 12,114 ------------ ------------ ------------ ------------ ------------ ------------ Total Utility Plant 1,398,258 177,511 (c) 2,345 (13,396) 266 1,564,984 Other Property - Depreciation 16,793 2,040 (d) 0 0 0 18,833 ------------ ------------ ------------ ------------ ------------ ------------ Total $1,415,051 $179,551 $2,345 ($13,396) $266 $1,583,817 ============ ============ ============ ============ ============ ============ Nuclear Fuel - Amortization $219,938 $68,867 (e) $0 $0 $0 $288,805 ============ ============ ============ ============ ============ ============ (a) Includes nuclear plant decommissioning trust earnings charged to the trust accounts and depreciation charged to construction work in progress. (b) Transfer from accumulated depreciation to accumulated amortization. (c) Depreciation and amortization, as reported in the Income Statement, includes approximately $7 million of amortization of investment tax credits. (d) Nonutility plant expense charged to other income and deductions, net. (e) Charged to fuel and purchased power expense.
S-17 140 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES SCHEDULE VII - GUARANTEES OF SECURITIES OF OTHER ISSUERS YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars)
Principal Amount Name of Issuer of Guaranteed and Securities Guaranteed Title of Issue (a) Outstanding (a) Nature of Guarantee - ------------------------------ ------------------------------- ---------------- ----------------------- Quarto Mining Company (b) Guaranteed Mortgage Bonds, due 2000 Series A 8.25% $550 Principal and Interest Series B 9.70% 537 Principal and Interest Series C 9.40% 2,684 Principal and Interest Series EA 10.25% 596 Principal and Interest Series FA 10.50% 457 Principal and Interest Series G 9.05% 7,448 Principal and Interest Series HA 7.75% 5,730 Principal and Interest Series HB 8.31% 3,321 Principal and Interest Guaranteed Refunding Bonds, Series I, 7.45%, due 1997 4,544 Principal and Interest Unsecured Note, interest at prime (6% effective 7/1/93 and applicable through 12/31/93) plus 2%, due 2000 1,781 Principal and Interest Equipment Leases 5,732 Termination Value per Agreements -------- 33,380 -------- The 0hio Valley Coal Company First Mortgage Notes, Series D, 8.00%, due 1994 to 1997 5,200 Principal and Interest Series E, 10.25%, due 1994 to 1997 2,310 Principal and Interest Equipment Leases 4,129 Stipulated Loss Value per Agreements Term Notes, 9.53%, due 1994 to 1996 1,525 Principal and Interest 10.85%, due 1994 to 1997 13,952 Principal and Interest -------- 27,116 -------- $60,496 -------- (a) None of the securities were owned by Cleveland Electric; none were held in the treasury of the issuer; and none were in default. (b) Cleveland Electric and the other CAPCO Group Companies have agreed to guarantee severally, and not jointly, their proportionate shares of Quarto Mining Company debt and lease obligations incurred while developing and equipping the mines. The amounts shown are Cleveland Electric's proportionate share of the total obligations.
S-18 141 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (Thousands of Dollars)
Additions Deductions ---------------------------------------- ------------------------ Balance at Charged to Deductions Balance Beginning Income from End of Description of Period Statement Other Reserves Other Period - ----------- ---------- --------- ------- ---------- ------- -------- Reflected as Reductions to the Related Assets: Accumulated Provision for Uncollectible Accounts (Deduction from Amounts Due from Customers and Others) 1993 $2,333 $9,280 (a) $1,813 (b) $11,113 (a)(c) $0 $2,313 1992 2,313 16,359 (a) 1,309 (b) 17,648 (a)(c) 0 2,333 1991 1,826 15,669 (a) 1,686 (b) 16,868 (a)(c) 0 2,313 Reserve for Perry Unit 2 Allowance for Funds Used During Construction (Deduction from Perry Unit 2) 1993 $124,398 $0 $0 $124,398 (d) $0 $0 1992 124,398 0 0 0 0 124,398 1991 124,398 0 0 0 0 124,398 (a) Includes a provision and corresponding write-off of uncollectible accounts of $2,447,000, $5,269,000 $5,616,000 in 1993, 1992 and 1991, 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 amount deferred for future recovery was $507,000 in 1993. (c) Uncollectible accounts written off. (d) Write-off of Perry Unit 2 investment.
S-19 142 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES SCHEDULE IX - SHORT-TERM BORROWINGS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (Thousands of Dollars)
Average Weighted Daily Average Average Maximum Weighted Daily Balance Interest Amount Amount Weighted at End Rate at Outstanding Outstanding Interest of End of During the During the Rate During Category Period Period Period Period the Period - -------- ------ -------- ------------- ------------ ----------- Commercial Paper - ---------------- 1993 $0 0.0% $36,900 $2,688 (a) 4.1% (b) 1992 0 0.0 75,000 9,473 (a) 4.3 (b) 1991 0 0.0 133,100 45,825 (a) 7.5 (b) Uncommitted Financing Facility - ------------------------------ 1993 $0 0.0% $40,001 $8,303 (a) 3.6% (b) 1992 10,000 4.3 40,001 17,180 (a) 4.1 (b) Not applicable for 1991. (a) Computed by dividing the total of the daily outstanding balances for the year by 365 days (366 for 1992). (b) Computed by dividing total interest expense for the year by the average daily balance outstanding.
S-20 143 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (Thousands of Dollars)
Item 1993 1992 1991 - ---- ---------- ---------- ---------- Maintenance and Repairs -- Charged to Operating Expenses $114,915 $122,789 $115,816 ========== ========== ========== Taxes, Other Than Payroll and Income Taxes: Charged to Operating Expenses: Real and Personal Property Taxes $122,405 $125,200 $119,613 Ohio State Excise Taxes 77,647 78,518 73,644 Other 9,608 10,560 11,366 ---------- ---------- ---------- Total Charged to Operating Expenses 209,660 214,278 204,623 Total Charged to Nonoperating Income 551 38 593 ---------- ---------- ---------- Total $210,211 $214,316 $205,216 ========== ========== ==========
S-21 144 THE TOLEDO EDISON COMPANY SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars)
Balance at Retirements Balance at Beginning of Additions or End of Classification Period at Cost Sales Other Period - -------------- ------------ --------- ------------ ------- ----------- Utility Plant (Electric): Intangible $12,393 ($51) $0 $0 $12,342 Production: Steam 280,604 2,542 (1,074) (44,745)(a) 237,327 Nuclear 1,911,645 16,068 (6,308) 0 1,921,405 Other 6,675 33 (10) 0 6,698 Transmission 151,518 4,017 (587) 1,010 (a) 155,958 Distribution 407,829 20,820 (934) 0 427,715 General 76,540 (921) (71) 0 75,548 ------------ --------- ------------ -------- ----------- Total Utility Plant 2,847,204 42,508 (8,984) (43,735) 2,836,993 Perry Unit 2 (b) 331,378 (11,075) 0 (320,303)(c) 0 Construction Work in Progress 36,812 4,299 0 (1,602)(a) 39,509 Nuclear Fuel 455,947 19,770 0 0 475,717 Other Property 4,083 1 0 45,337 (a) 49,421 ------------ --------- ------------ -------- ----------- Total Property, Plant and Equipment $3,675,424 $55,503 ($8,984) ($320,303) $3,401,640 ============ ========= ============ ======== =========== (a) Transfer of Acme Plant Unit 2 to future use and nonutility property and reclassification of future use property. (b) Includes Perry Unit 2 AFUDC. See Schedule VIII. (c) Write-off of Perry Unit 2 investment.
S-22 145 THE TOLEDO EDISON COMPANY SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1992 (Thousands of Dollars)
Balance at Retirements Balance at Beginning of Additions or End of Classification Period at Cost Sales Other Period - -------------- ------------ ------------ ------------ ------------ ------------ Utility Plant (Electric): Intangible $12,312 $81 $0 $0 $12,393 Production: Steam 308,946 6,789 (37,200) 2,069 (a) 280,604 Nuclear 1,766,285 26,847 (5,830) 124,343 (a) 1,911,645 Other 6,675 0 0 0 6,675 Transmission 149,029 1,870 (23) 642 (a) 151,518 Distribution 375,784 32,756 (910) 199 (a) 407,829 General 73,243 4,297 (1,000) 0 76,540 ------------ ------------ ------------ ------------ ------------ Total Utility Plant 2,692,274 72,640 (44,963) 127,253 2,847,204 Perry Unit 2 (b) 342,767 (11,389) 0 0 331,378 Construction Work in Progress 53,965 (17,153) 0 0 36,812 Nuclear Fuel 433,847 22,100 0 0 455,947 Other Property 4,096 17 (30) 0 4,083 ------------ ------------ ------------ ------------ ------------ Total Property, Plant and Equipment $3,526,949 $66,215 ($44,993) $127,253 $3,675,424 ============ ============ ============ ============ ============ (a) Results from adoption of SFAS 109 in 1992, which requires the presentation of amounts on a pre-tax basis. Such amounts were previously stated on a net-of-tax basis. (b) Includes Perry Unit 2 AFUDC. See Schedule VIII.
S-23 146 THE TOLEDO EDISON COMPANY SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1991 (Thousands of Dollars)
Balance at Retirements Balance at Beginning of Additions or End of Classification Period at Cost Sales Other Period - -------------- ------------ ------------ ------------ ------------ ------------ Utility Plant (Electric): Intangible $3,536 $8,776 $0 $0 $12,312 Production: Steam 291,411 17,535 0 0 308,946 Nuclear 1,718,262 48,695 (672) 0 1,766,285 Other 6,726 (51) 0 0 6,675 Transmission 146,881 2,149 (1) 0 149,029 Distribution 366,788 9,851 (855) 0 375,784 General 70,279 6,990 (4,026) 0 73,243 ------------ ------------ ------------ ------------ ------------ Total Utility Plant 2,603,883 93,945 (5,554) 0 2,692,274 Perry Unit 2 (a) 343,685 (918) 0 0 342,767 Construction Work in Progress 93,154 (39,189) 0 0 53,965 Nuclear Fuel 406,506 27,341 0 0 433,847 Other Property 3,303 793 0 0 4,096 ------------ ------------ ------------ ------------ ------------ Total Property, Plant and Equipment $3,450,531 $81,972 ($5,554) $0 $3,526,949 ============ ============ ============ ============ ============ (a) Includes Perry Unit 2 AFUDC. See Schedule VIII.
S-24 147 THE TOLEDO EDISON COMPANY SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars)
Additions Deductions ------------------------------- ------------------------------ Balance at Charged to Removal Cost Balance at Beginning of Income Net of Salvage End of Description Period Statement Other Retirements Add/(Deduct) Period - ----------- ------------ ------------ ------------ ------------ -------------- ------------ Utility Plant: Electric - Depreciation $755,341 $83,166 ($46,018)(a)(b) ($8,984) ($3,326) $780,179 - Amortization 4,980 2,625 0 0 0 7,605 ------------ ------------ ------------ ------------ ------------ ------------ Total Utility Plant 760,321 85,791 (c) (46,018) (8,984) (3,326) 787,784 Other Property - Depreciation 1,472 72 (d) 48,111 (b) 0 0 49,655 ------------ ------------ ------------ ------------ ------------ ------------ Total $761,793 $85,863 $2,093 ($8,984) ($3,326) $837,439 ============ ============ ============ ============ ============ ============ Nuclear Fuel - Amortization $294,915 $38,360 (e) $0 $0 $0 $333,275 ============ ============ ============ ============ ============ ============ (a) Includes nuclear plant decommissioning trust earnings charged to the trust accounts and depreciation charged to construction work in progress. (b) Transfer of accumulated depreciation for Acme Plant Unit 2. (c) Depreciation and amortization, as reported in the Income Statement, includes approximately $10 million of amortization of investment tax credits. (d) Nonutility plant expense charged to other income and deductions, net. (e) Charged to fuel and purchased power expense.
S-25 148 THE TOLEDO EDISON COMPANY SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1992 (Thousands of Dollars)
Additions Deductions ------------------------------- ------------------------------ Balance at Charged to Removal Cost Balance at Beginning of Income Net of Salvage End of Description Period Statement Other Retirements Add/(Deduct) Period - ----------- ------------ ------------ ------------ ------------ -------------- ------------ Utility Plant: Electric - Depreciation $707,316 $79,237 $18,208 (a) ($44,963) ($4,457) $755,341 - Amortization 2,189 2,791 0 0 0 4,980 ------------ ------------ ------------ ------------ ------------ ------------ Total Utility Plant 709,505 82,028 (b) 18,208 (44,963) (4,457) 760,321 Other Property - Depreciation 1,417 89 (c) 0 (30) (4) 1,472 ------------ ------------ ------------ ------------ ------------ ------------ Total $710,922 $82,117 $18,208 ($44,993) ($4,461) $761,793 ============ ============ ============ ============ ============ ============ Nuclear Fuel - Amortization $238,562 $56,353 (d) $0 $0 $0 $294,915 ============ ============ ============ ============ ============ ============ (a) Includes adjustment resulting from adoption of SFAS 109 in 1992 ($16.6 million), nuclear plant decommissioning trust earnings charged to the trust accounts, and depreciation charged to construction work in progress. (b) Depreciation and amortization, as reported in the Income Statement, includes approximately $5 million of amortization of investment tax credits. (c) Nonutility plant expense charged to other income and deductions, net. (d) Charged to fuel and purchased power expense.
S-26 149 THE TOLEDO EDISON COMPANY SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR ENDED DECEMBER 31, 1991 (Thousands of Dollars)
Additions Deductions ------------------------------- ------------------------------ Balance at Charged to Removal Cost Balance at Beginning of Income Net of Salvage End of Description Period Statement Other Retirements Add/(Deduct) Period - ----------- ------------ ------------ ------------ ------------ -------------- ------------ Utility Plant: Electric - Depreciation $639,357 $75,105 $1,761 (a) ($5,554) ($3,353) $707,316 - Amortization 895 1,294 0 0 0 2,189 ------------ ------------ ------------ ------------ ------------ ------------ Total Utility Plant 640,252 76,399 (b) 1,761 (5,554) (3,353) 709,505 Other Property - Depreciation 1,279 138 (c) 0 0 0 1,417 ------------ ------------ ------------ ------------ ------------ ------------ Total $641,531 $76,537 $1,761 ($5,554) ($3,353) $710,922 ============ ============ ============ ============ ============ ============ Nuclear Fuel - Amortization $184,658 $53,904 (d) $0 $0 $0 $238,562 ============ ============ ============ ============ ============ ============ (a) Includes nuclear plant decommissioning trust earnings charged to the trust accounts and depreciation charged to construction work in progress. (b) Depreciation and amortization, as reported in the Income Statement, includes approximately $4 million of amortization of investment tax credits. (c) Nonutility plant expense charged to other income and deductions, net. (d) Charged to fuel and purchased power expense.
S-27 150 THE TOLEDO EDISON COMPANY SCHEDULE VII - GUARANTEES OF SECURITIES OF OTHER ISSUERS YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars)
Principal Amount Name of Issuer of Guaranteed and Securities Guaranteed Title of Issue (a) Outstanding (a) Nature of Guarantee - -------------------------------- ----------------------------------- --------------- -------------------- Quarto Mining Company (b) Guaranteed Mortgage Bonds, due 2000 Series A 8.25% $271 Principal and Interest Series B 9.70% 264 Principal and Interest Series C 9.40% 1,323 Principal and Interest Series EA 10.25% 358 Principal and Interest Series FA 10.50% 274 Principal and Interest Series G 9.05% 4,650 Principal and Interest Series HA 7.75% 3,578 Principal and Interest Series HB 8.31% 2,074 Principal and Interest Guaranteed Refunding Bonds, Series I, 7.45%, due 1997 2,837 Principal and Interest Unsecured Note, interest at prime (6% effective 7/1/93 and applicable through 12/31/93) plus 2%, due 2000 1,068 Principal and Interest Equipment Leases 2,825 Termination Value per Agreements -------- $19,522 ======== (a) None of the securities were owned by Toledo Edison; none were held in the treasury of the issuer; and none were in default. (b) Toledo Edison and the other CAPCO Group Companies have agreed to guarantee severally, and not jointly, their proportionate shares of Quarto Mining Company debt and lease obligations incurred while developing and equipping the mines. The amounts shown are Toledo Edison's proportionate share of the total obligations.
S-28 151 THE TOLEDO EDISON COMPANY SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (Thousands of Dollars)
Additions Deductions ---------------------------- ---------------------------- Balance at Charged to Deductions Balance at Beginning Income from End of Description of Period Statement Other Reserves Other Period ----------- ------------ ------------ ------------ ------------ --------- ------------ Reflected as Reductions to the Related Assets: Accumulated Provision for Uncollectible Accounts (Deduction from Amounts Due from Customers and Others) 1993 $1,390 $4,859 (a) $1,703 (b) $6,562 (a)(c) $0 $1,390 1992 1,390 3,314 (a) 1,067 (b) 4,381 (a)(c) 0 1,390 1991 1,200 4,898 (a) 1,506 (b) 6,214 (a)(c) 0 1,390 Reserve for Perry Unit 2 Allowance for Funds Used During Construction (Deduction from Perry Unit 2) 1993 $88,295 $0 $0 $88,295 (d) $0 $0 1992 88,295 0 0 0 0 88,295 1991 88,295 0 0 0 0 88,295 (a) Includes a provision and corresponding write-off of uncollectible accounts of $2,103,000, $699,000 and $404,000 in 1993, 1992 and 1991, respectively, relating to customers which qualify for the 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 $464,000 and $37,000 in 1993 and 1992, respectively. (c) Uncollectible accounts written off. (d) Write-off of Perry Unit 2 investment.
S-29 152 THE TOLEDO EDISON COMPANY SCHEDULE IX - SHORT-TERM BORROWINGS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (Thousands of Dollars)
Average Weighted Daily Average Average Maximum Weighted Daily Balance Interest Amount Amount Weighted at End Rate at Outstanding Outstanding Interest of End of During the During the Rate During Category Period Period Period Period the Period - -------- ------------ ------------ ------------ ------------ ------------ Commercial Paper - ---------------- 1993 $0 0.0% $0 $0 (a) 0.0%(b) 1992 0 0.0 31,000 7,350 (a) 4.7 (b) 1991 0 0.0 45,000 15,956 (a) 7.1 (b) Uncommitted Financing Facility - ------------------------------ 1993 $0 0.0% $40,001 $11,407 (a) 3.9%(b) 1992 39,502 4.4 40,003 21,772 (a) 4.0 (b) Not applicable for 1991. (a) Computed by dividing the total of the daily outstanding balances for the year by 365 days (366 for 1992). (b) Computed by dividing total interest expense for the year by the average daily balance outstanding.
S-30 153 THE TOLEDO EDISON COMPANY SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (Thousands of Dollars)
Item 1993 1992 1991 - ---- ------------ ------------ ------------ Maintenance and Repairs -- Charged to Operating Expenses $59,417 $61,394 $58,305 ============ ============ ============ Taxes, Other Than Payroll and Income Taxes: Charged to Operating Expenses: Real and Personal Property Taxes $47,941 $46,403 $43,510 Ohio State Excise Taxes 32,218 32,798 33,028 Other 3,568 5,014 4,217 ------------ ------------ ------------ Total Charged to Operating Expenses 83,727 84,215 80,755 Total Charged to Nonoperating Income 71 91 91 ------------ ------------ ------------ Total $83,798 $84,306 $80,846 ============ ============ ============
S-31 154 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES AND THE TOLEDO EDISON COMPANY COMBINED PRO FORMA CONDENSED FINANCIAL STATEMENTS The following pro forma condensed balance sheets and income statements give effect to the agreement between Cleveland Electric and Toledo Edison to merge Toledo Edison into Cleveland Electric. These statements are unaudited and based on accounting for the merger on a method similar to a pooling of interests. These statements combine the two companies' historical balance sheets at December 31, 1993 and December 31, 1992 and their historical income statements for each of the three years ended December 31, 1993. The following pro forma data is not necessarily indicative of the results of operations or the financial condition which would have been reported had the merger been in effect during those periods or which may be reported in the future. The statements should be read in conjunction with the accompanying notes and with the audited financial statements of both Cleveland Electric and Toledo Edison. COMBINED PRO FORMA CONDENSED BALANCE SHEETS OF CLEVELAND ELECTRIC AND TOLEDO EDISON (Unaudited) (Millions of Dollars)
At December 31, 1993 ------------------------------------------------------ Historical ----------------------- Cleveland Toledo Adjust- Pro Forma Electric Edison ments Totals ------ ------- -------- ------- Assets Property, Plant and Equipment $7,538 $3,402 $ - $10,940 Less: Accumulated Depreciation and Amortization 2,309 1,171 - 3,480 ------ ------ -------- ------- Net Property, Plant and Equipment 5,229 2,231 - 7,460 Current Assets 632 314 (20)(A) 926 Deferred Charges and Other Assets 1,298 965 (9)(B) 2,254 ------ ------ -------- ------- Total Assets $7,159 $3,510 $(29) $10,640 ====== ====== ======== =======
P-1 155
At December 31, 1993 ----------------------------------------------------- Historical ---------------------- Cleveland Toledo Adjust- Pro Forma Electric Edison ments Totals --------- ------ -------- ------- Capitalization and Liabilities Capitalization: Common Stock Equity $1,040 $ 623 $ (1)(R) $ 1,662 Preferred Stock: With Mandatory Redemption Provisions 285 28 - 313 Without Mandatory Redemption Provisions 241 210 - 451 Long-Term Debt 2,793 1,225 1(R) 4,019 ------ ------ -------- ------- Total Capitalization 4,359 2,086 - 6,445 Other Noncurrent Liabilities 247 186 - 433 Current Liabilities 733 329 (21)(A) 1,041 Deferred Credits 1,820 909 (8)(A,B) 2,721 ------ ------ -------- ------- Total Capitalization and Liabilities $7,159 $3,510 $(29) $10,640 ====== ====== ======== =======
At December 31, 1992 ------------------------------------------------------ Historical --------------------------- Cleveland Toledo Adjust- Pro Forma Electric Edison ments Totals ------ ------ -------- ------- Assets Property, Plant and Equipment $7,729 $3,587 $ - $11,316 Less: Accumulated Depreciation and Amortization 2,093 1,056 1(R) 3,150 ------ ------ -------- ------- Net Property, Plant and Equipment 5,636 2,531 (1) 8,166 Current Assets 607 258 (33)(A,R) 832 Deferred Charges and Other Assets 1,880 1,150 (17)(A,B) 3,013 ------ ------ -------- ------- Total Assets $8,123 $3,939 $(51) $12,011 ====== ====== ======== ======= Capitalization and Liabilities Capitalization: Common Stock Equity $1,865 $ 935 $ (1)(R) $ 2,799 Preferred Stock: With Mandatory Redemption Provisions 314 50 - 364 Without Mandatory Redemption Provisions 144 210 - 354 Long-Term Debt 2,515 1,178 1(R) 3,694 ------ ------ -------- ------- Total Capitalization 4,838 2,373 - 7,211 Other Noncurrent Liabilities 234 188 - 422 Current Liabilities 924 332 (32)(A) 1,224 Deferred Credits 2,127 1,046 (19)(B) 3,154 ------ ------ -------- ------- Total Capitalization and Liabilities $8,123 $3,939 $(51) $12,011 ====== ====== ======== =======
P-2 156 COMBINED PRO FORMA CONDENSED INCOME STATEMENTS OF CLEVELAND ELECTRIC AND TOLEDO EDISON (Unaudited) (Millions of Dollars)
Year Ended December 31, 1993 ---------------------------- Historical ---------- Cleveland Toledo Adjust- Pro Forma Electric Edison ments Totals Operating Revenues $1,751 $ 871 $(147)(C) $2,475 Operating Expenses 1,529 782 (148)(C,D) 2,163 ------ ----- ------ ------ Operating Income 222 89 1 312 Nonoperating (Loss) (569) (263) (1)(D) (833) ------ ----- ------ ------ (Loss) Before Interest Charges (347) (174) - (521) Interest Charges 240 115 - 355 ------ ----- ------ ------ Net (Loss) (587) (289) - (876) Preferred Dividend Requirements 45 23 - 68 ------ ----- ------ ------ (Loss) Available for Common Stock $ (632) $(312) $ - $ (944) ====== ===== ===== ======
Year Ended December 31, 1992 ---------------------------- Historical ---------- Cleveland Toledo Adjust- Pro Forma Electric Edison ments Totals -------- ------ ----- ------ Operating Revenues $1,743 $ 845 $(149)(C) $2,439 Operating Expenses 1,358 695 (150)(C,D) 1,903 ------ ------ ------ ------ Operating Income 385 150 1 536 Nonoperating Income 63 42 (1)(D) 104 ------ ------ ------ ------ Income Before Interest Charges 448 192 - 640 Interest Charges 243 121 - 364 ------ ------ ------ ------ Net Income 205 71 - 276 Preferred Dividend Requirements 41 24 - 65 ------ ------ ------ ------ Earnings Available for Common Stock $ 164 $ 47 $ - $ 211 ====== ===== ===== ======
Year Ended December 31, 1991 ---------------------------- Historical ---------- Cleveland Toledo Adjust- Pro Forma Electric Edison ments Totals -------- ------ ----- ------ Operating Revenues $1,826 $ 887 $(152)(C) $2,561 Operating Expenses 1,411 728 (153)(C,D) 1,986 ------ ------ ------ ------ Operating Income 415 159 1 575 Nonoperating Income 78 22 (2)(D,E) 98 ------ ------ ------ ------ Income Before Interest Charges 493 181 (1) 673 Interest Charges 247 131 (1)(E) 377 ------ ------ ------ ------ Net Income 246 50 - 296 Preferred Dividend Requirements 36 25 - 61 ------ ------ ------ ------ Earnings Available for Common Stock $ 210 $ 25 $ - $ 235 ====== ===== ===== ======
P-3 157 NOTES TO COMBINED PRO FORMA CONDENSED BALANCE SHEETS AND INCOME STATEMENTS (Unaudited) The Pro Forma Financial Statements include the following adjustments: (A) Elimination of intercompany accounts and notes receivable and accounts and notes payable. (B) Reclassification of prepaid pension costs or pension liabilities. (C) Elimination of intercompany operating revenues and operating expenses. (D) Elimination of intercompany working capital transactions. (E) Elimination of intercompany interest income and interest expense. (R) Rounding adjustments. P-4 158 EXHIBIT INDEX The exhibits designated with an asterisk (*) are filed herewith. The exhibits not so designated have previously been filed with the SEC in the file indi- cated in parenthesis following the description of such exhibits and are in- corporated herein by reference. An exhibit designated with a pound sign (#) is a management contract or compensatory plan or arrangement. COMMON EXHIBITS (The following documents are exhibits to the reports of Centerior Energy, Cleveland Electric and Toledo Edison.)
Exhibit Number Document 10b(1)(a) CAPCO Administration Agreement dated November 1, 1971, as of September 14, 1967, among the CAPCO Group members re- garding the organization and procedures for implementing the objectives of the CAPCO Group (Exhibit 5(p), Amendment No. 1, File No. 2-42230, filed by Cleveland Electric). 10b(1)(b) Amendment No. 1, dated January 4, 1974, to CAPCO Adminis- tration Agreement among the CAPCO Group members (Exhibit 5(c)(3), File No. 2-68906, filed by Ohio Edison). 10b(2) CAPCO Transmission Facilities Agreement dated November 1, 1971, as of September 14, 1967, among the CAPCO Group members regarding the installation, operation and mainte- nance of transmission facilities to carry out the objec- tives of the CAPCO Group (Exhibit 5(q), Amendment No. 1, File No. 2-42230, filed by Cleveland Electric). 10b(2)(1) *Amendment No. 1 to CAPCO Transmission Facilities Agree- ment, dated December 23, 1993 and effective as of January 1, 1993, among the CAPCO Group members regarding requirements for payment of invoices at specified times, for payment of interest on non-timely paid invoices, for restricting adjustment of invoices after a four-year period, and for revising the method for computing the Investment Responsibility charge for use of a member's transmission facilities. 10b(3) *CAPCO Basic Operating Agreement As Amended January 1, 1993 among the CAPCO Group members regarding coordinated operation of the members' systems. 10b(4) *Agreement for the Termination or Construction of Certain Agreements By and Among the CAPCO Group members, dated December 23, 1993 and effective as of September 1, 1980. 10b(5) Construction Agreement, dated July 22, 1974, among the CAPCO Group members and relating to the Perry Nuclear Plant (Exhibit 5(yy), File No. 2-52251, filed by Toledo Edison). 10b(6) Contract, dated as of December 5, 1975, among the CAPCO Group members for the construction of Beaver Valley Unit No. 2 (Exhibit 5(g), File No. 2-52996, filed by Cleveland Electric).
E-1 159
Exhibit Number Document 10b(7) Amendment No. 1, dated May 1, 1977, to Contract, dated as of December 5, 1975, among the CAPCO Group members for the construction of Beaver Valley Unit No. 2 (Exhibit 5(d)(4), File No. 2-60109, filed by Ohio Edison). 10d(1)(a) Form of Collateral Trust Indenture among CTC Beaver Valley Funding Corporation, Cleveland Electric, Toledo Edison and Irving Trust Company, as Trustee (Exhibit 4(a), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(1)(b) Form of Supplemental Indenture to Collateral Trust In- denture constituting Exhibit 10d(1)(a) above, including form of Secured Lease Obligation Bond (Exhibit 4(b), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(1)(c) Form of Collateral Trust Indenture among Beaver Valley II Funding Corporation, The Cleveland Electric Illuminating Company and The Toledo Edison Company and The Bank of New York, as Trustee (Exhibit (4)(a), File No. 33-46665, filed by Cleveland Electric and Toledo Edison). 10d(1)(d) Form of Supplemental Indenture to Collateral Trust Indenture constituting Exhibit 10d(1)(c) above, including form of Secured Lease Obligation Bond (Exhibit (4)(b), File No. 33-46665, filed by Cleveland Electric and Toledo Edison). 10d(2)(a) Form of Collateral Trust Indenture among CTC Mansfield Funding Corporation, Cleveland Electric, Toledo Edison and IBJ Schroder Bank & Trust Company, as Trustee (Exhibit 4(a), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(2)(b) Form of Supplemental Indenture to Collateral Trust In- denture constituting Exhibit 10d(2)(a) above, including forms of Secured Lease Obligation Bonds (Exhibit 4(b), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(3)(a) Form of Facility Lease dated as of September 15, 1987 be- tween The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the limited partnership Owner Participant named therein, Lessor, and Cleveland Electric and Toledo Edison, Lessees (Exhibit 4(c), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(3)(b) Form of Amendment No. 1 to Facility Lease constituting Exhibit 10d(3)(a) above (Exhibit 4(e), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(4)(a) Form of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the corporate Owner Participant named therein, Lessor, and Cleveland Electric and Toledo Edison, Lessees (Exhibit 4(d), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(4)(b) Form of Amendment No. 1 to Facility Lease constituting Exhibit 10d(4)(a) above (Exhibit 4(f), File No. 33-18755, filed by Cleveland Electric and Toledo Edison).
E-2 160
Exhibit Number Document 10d(5)(a) Form of Facility Lease dated as of September 30, 1987 be- tween Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Lessor, and Cleveland Electric and Toledo Edison, Lessees (Exhibit 4(c), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(5)(b) Form of Amendment No. 1 to the Facility Lease constituting Exhibit 10d(5)(a) above (Exhibit 4(f), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(6)(a) Form of Participation Agreement dated as of September 15, 1987 among the limited partnership Owner Participant named therein, the Original Loan Participants listed in Schedule 1 thereto, as Original Loan Participants, CTC Beaver Valley Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Cleveland Electric and Toledo Edison, as Lessees (Exhibit 28(a), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(6)(b) Form of Amendment No. 1 to Participation Agreement consti- tuting Exhibit 10d(6)(a) above (Exhibit 28(c), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(7)(a) Form of Participation Agreement dated as of September 15, 1987 among the corporate Owner Participant named therein, the Original Loan Participants listed in Schedule 1 thereto, as Original Loan Participants, CTC Beaver Valley Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Cleveland Electric and Toledo Edison, as Lessees (Exhibit 28(b), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(7)(b) Form of Amendment No. 1 to Participation Agreement consti- tuting Exhibit 10d(7)(a) above (Exhibit 28(d), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(8)(a) Form of Participation Agreement dated as of September 30, 1987 among the Owner Participant named therein, the Origi- nal Loan Participants listed in Schedule II thereto, as Original Loan Participants, CTC Mansfield Funding Corpora- tion, Meridian Trust Company, as Owner Trustee, IBJ Schroder Bank & Trust Company, as Indenture Trustee, and Cleveland Electric and Toledo Edison, as Lessees (Exhibit 28(a), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(8)(b) Form of Amendment No. 1 to the Participation Agreement constituting Exhibit 10d(8)(a) above (Exhibit 28(b), File No. 33-20128, filed by Cleveland Electric and Toledo Edison).
E-3 161
Exhibit Number Document 10d(9) Form of Ground Lease dated as of September 15, 1987 be- tween Toledo Edison, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, Tenant (Exhibit 28(e), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(10) Form of Site Lease dated as of September 30, 1987 between Toledo Edison, Lessor, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Tenant (Exhibit 28(c), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(11) Form of Site Lease dated as of September 30, 1987 between Cleveland Electric, Lessor, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Tenant (Exhibit 28(d), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(12) Form of Amendment No. 1 to the Site Leases constituting Exhibits 10d(10) and 10d(11) above (Exhibit 4(f), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(13) Form of Assignment, Assumption and Further Agreement dated as of September 15, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, Cleveland Electric, Duquesne, Ohio Edison, Pennsylvania Power and Toledo Edison (Exhibit 28(f), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(14) Form of Additional Support Agreement dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, and Toledo Edison (Exhibit 28(g), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(15) Form of Support Agreement dated as of September 30, 1987 between Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named there, Toledo Edison, Cleveland Electric, Duquesne, Ohio Edison and Pennsylvania Power (Exhibit 28(e), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(16) Form of Indenture, Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between Toledo Edison, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, Buyer (Exhibit 28(h), File No. 33-18755, filed by Cleveland Electric and Toledo Edison).
E-4 162
Exhibit Number Document 10d(17) Form of Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between Toledo Edison, Seller, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Buyer (Exhibit 28(f), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(18) Form of Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between Cleveland Electric, Seller, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Buyer (Exhibit 28(g), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(19) Forms of Refinancing Agreement, including exhibits thereto, among the Owner Participant named therein, as Owner Participant, CTC Beaver Valley Funding Corporation, as Funding Corporation, Beaver Valley II Funding Corporation, as New Funding Corporation, The Bank of New York, as Indenture Trustee, The Bank of New York, as Collateral Trust Trustee, The Bank of New York, as New Collateral Trust Trustee, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, as Lessees (Exhibit (28)(e)(i), File No. 33-46665, filed by Cleveland Electric and Toledo Edison). 10e(1) *#Employment agreement, dated May 25, 1993, between Centerior Service Company and Donald C. Shelton effective June 4, 1993 and extending until June 30, 1995. 10e(2) *#Employment agreement, dated February 2, 1994 and accepted on February 8, 1994, between Centerior Energy and Al R. Temple effective through December 1996. 18a Letter regarding change in accounting principles (Exhibit 18, June 30, 1991 Form 10-Q, File Nos. 1-9130, 1-2323 and 1-3583). 99a Financial Statements of the Centerior Energy Corporation Employee Savings Plan for the fiscal year ended December 31, 1993 (to be filed by amendment).
E-5 163 CENTERIOR ENERGY EXHIBITS
Exhibit Number Document 3a Amended Articles of Incorporation of Centerior Energy ef- fective April 29, 1986 (Exhibit 4(a), File No. 33-4790). 3b Regulations of Centerior Energy effective April 28, 1987 (Exhibit 3b, 1987 Form 10-K, File No. 1-9130). 10a *Indemnity Agreements between Centerior and certain of its current directors and officers. 10e #Employment and Consulting Agreement, dated November 30, 1989, with P. M. Smart regarding his employment with Toledo Edison through August 31, 1990 and his providing consulting services to Centerior and Toledo Edison for the period September 1, 1990 through January 31, 1994 (Exhibit 10e(2), 1989 Form 10-K, File No. 1-9130). 21 List of subsidiaries (Exhibit 22, 1986 Form 10-K, File No. 1-9130). 23a *Consent of Independent Accountants. 23b *Consent of Counsel for Centerior Energy. 24a Power of Attorney of Centerior Energy and certified resolution of Centerior Energy's Board of Directors authorizing the signing on behalf of Centerior pursuant to a power of attorney (Exhibit 25(a), March 31, 1993 Form 10-Q, File No. 1-9130). 24b *Powers of Attorney of Centerior Energy directors and officers required to sign the Report.
CLEVELAND ELECTRIC EXHIBITS
Exhibit Number Document 3a *Amended Articles of Incorporation of Cleveland Electric, as amended, effective May 28, 1993. 3b Regulations of Cleveland Electric, dated April 29, 1981, as amended effective October 1, 1988 and April 24, 1990 (Exhibit 3b, 1990 Form 10-K, File No. 1-2323). 4b(1) Mortgage and Deed of Trust between Cleveland Electric and Guaranty Trust Company of New York (now Morgan Guaranty Trust Company of New York), as Trustee, dated July 1, 1940 (Exhibit 7(a), File No. 2-4450). Supplemental Indentures between Cleveland Electric and the Trustee, supplemental to Exhibit 4b(1), dated as follows:
E-6 164
Exhibit Number Document 4b(2) July 1, 1940 (Exhibit 7(b), File No. 2-4450). 4b(3) August 18, 1944 (Exhibit 4(c), File No. 2-9887). 4b(4) December 1, 1947 (Exhibit 7(d), File No. 2-7306). 4b(5) September 1, 1950 (Exhibit 7(c), File No. 2-8587). 4b(6) June 1, 1951 (Exhibit 7(f), File No. 2-8994). 4b(7) May 1, 1954 (Exhibit 4(d), File No. 2-10830). 4b(8) March 1, 1958 (Exhibit 2(a)(4), File No. 2-13839). 4b(9) April 1, 1959 (Exhibit 2(a)(4), File No. 2-14753). 4b(10) December 20, 1967 (Exhibit 2(a)(4), File No. 2-30759). 4b(11) January 15, 1969 (Exhibit 2(a)(5), File No. 2-30759). 4b(12) November 1, 1969 (Exhibit 2(a)(4), File No. 2-35008). 4b(13) June 1, 1970 (Exhibit 2(a)(4), File No. 2-37235). 4b(14) November 15, 1970 (Exhibit 2(a)(4), File No. 2-38460). 4b(15) May 1, 1974 (Exhibit 2(a)(4), File No. 2-50537). 4b(16) April 15, 1975 (Exhibit 2(a)(4), File No. 2-52995). 4b(17) April 16, 1975 (Exhibit 2(a)(4), File No. 2-53309). 4b(18) May 28, 1975 (Exhibit 2(c), June 5, 1975 Form 8-A, File No. 1-2323). 4b(19) February 1, 1976 (Exhibit 3(d)(6), 1975 Form 10-K, File No. 1-2323). 4b(20) November 23, 1976 (Exhibit 2(a)(4), File No. 2-57375). 4b(21) July 26, 1977 (Exhibit 2(a)(4), File No. 2-59401). 4b(22) September 27, 1977 (Exhibit 2(a)(5), File No. 2-67221). 4b(23) May 1, 1978 (Exhibit 2(b), June 30, 1978 Form 10-Q, File No. 1-2323). 4b(24) September 1, 1979 (Exhibit 2(a), September 30, 1979 Form 10-Q, File No. 1-2323). 4b(25) April 1, 1980 (Exhibit 4(a)(2), September 30, 1980 Form 10-Q, File No. 1-2323). 4b(26) April 15, 1980 (Exhibit 4(b), September 30, 1980 Form 10-Q, File No. 1-2323). 4b(27) May 28, 1980 (Exhibit 2(a)(4), Amendment No. 1, File No. 2-67221). 4b(28) June 9, 1980 (Exhibit 4(d), September 30, 1980 Form 10-Q, File No. 1-2323). 4b(29) December 1, 1980 (Exhibit 4(b)(29), 1980 Form 10-K, File No. 1-2323). 4b(30) July 28, 1981 (Exhibit 4(a), September 30, 1981, Form 10-Q, File No. 1-2323). 4b(31) August 1, 1981 (Exhibit 4(b), September 30, 1981, Form 10-Q, File No. 1-2323). 4b(32) March 1, 1982 (Exhibit 4(b)(3), Amendment No. 1, File No. 2-76029). 4b(33) July 15, 1982 (Exhibit 4(a), September 30, 1982 Form 10-Q, File No. 1-2323). 4b(34) September 1, 1982 (Exhibit 4(a)(1), September 30, 1982 Form 10-Q, File No. 1-2323). 4b(35) November 1, 1982 (Exhibit 4(a)(2), September 30, 1982 Form 10-Q, File No. 1-2323). 4b(36) November 15, 1982 (Exhibit 4(b)(36), 1982 Form 10-K, File No. 1-2323).
E-7 165
Exhibit Number Document 4b(37) May 24, 1983 (Exhibit 4(a), June 30, 1983 Form 10-Q, File No. 1-2323). 4b(38) May 1, 1984 (Exhibit 4, June 30, 1984 Form 10-Q, File No. 1-2323). 4b(39) May 23, 1984 (Exhibit 4, May 22, 1984 Form 8-K, File No. 1-2323). 4b(40) June 27, 1984 (Exhibit 4, June 11, 1984 Form 8-K, File No. 1-2323). 4b(41) September 4, 1984 (Exhibit 4b(41), 1984 Form 10-K, File No. 1-2323). 4b(42) November 14, 1984 (Exhibit 4b(42), 1984 Form 10-K, File No. 1-2323). 4b(43) November 15, 1984 (Exhibit 4b(43), 1984 Form 10-K, File No. 1-2323). 4b(44) April 15, 1985 (Exhibit 4(a), May 8, 1985 Form 8-K, File No. 1-2323). 4b(45) May 28, 1985 (Exhibit 4(b), May 8, 1985 Form 8-K, File No. 1-2323). 4b(46) August 1, 1985 (Exhibit 4, September 30, 1985 Form 10-Q, File No. 1-2323). 4b(47) September 1, 1985 (Exhibit 4, September 30, 1985 Form 8-K, File No. 1-2323). 4b(48) November 1, 1985 (Exhibit 4, January 31, 1986 Form 8-K, File No. 1-2323). 4b(49) April 15, 1986 (Exhibit 4, March 31, 1986 Form 10-Q, File No. 1-2323). 4b(50) May 14, 1986 (Exhibit 4(a), June 30, 1986 Form 10-Q, File No. 1-2323). 4b(51) May 15, 1986 (Exhibit 4(b), June 30, 1986 Form 10-Q, File No. 1-2323). 4b(52) February 25, 1987 (Exhibit 4b(52), 1986 Form 10-K, File No. 1-2323). 4b(53) October 15, 1987 (Exhibit 4, September 30, 1987 Form 10-Q, File No. 1-2323). 4b(54) February 24, 1988 (Exhibit 4b(54), 1987 Form 10-K, File No. 1-2323). 4b(55) September 15, 1988 (Exhibit 4b(55), 1988 Form 10-K, File No. 1-2323). 4b(56) May 15, 1989 (Exhibit 4(a)(2)(i), File No. 33-32724). 4b(57) June 13, 1989 (Exhibit 4(a)(2)(ii), File No. 33-32724). 4b(58) October 15, 1989 (Exhibit 4(a)(2)(iii), File No. 33-32724). 4b(59) January 1, 1990 (Exhibit 4b(59), 1989 Form 10-K, File No. 1-2323). 4b(60) June 1, 1990 (Exhibit 4(a), September 30, 1990 Form 10-Q, File No. 1-2323). 4b(61) August 1, 1990 (Exhibit 4(b), September 30, 1990 Form 10-Q, File No. 1-2323). 4b(62) May 1, 1991 (Exhibit 4(a), June 30, 1991 Form 10-Q, File No. 1-2323).
E-8 166
Exhibit Number Document 4b(63) May 1, 1992 (Exhibit 4(a)(3), File No. 33-48845). 4b(64) July 31, 1992 (Exhibit 4(a)(3), File No. 33-57292). 4b(65) January 1, 1993 (Exhibit 4b(65), 1992 Form 10-K, File No. 1-2323). 4b(66) February 1, 1993 (Exhibit 4b(66), 1992 Form 10-K, File No. 1-2323). 4b(67) May 20, 1993 (Exhibit 4(a), July 14, 1993 Form 8-K, File No. 1-2323). 4b(68) June 1, 1993 (Exhibit 4(b), July 14, 1993 Form 8-K, File No. 1-2323). 10a Indemnity Agreements between Cleveland Electric and cer- tain of its current directors (Exhibit 10a, 1988 Form 10-K, File No. 1-2323). 10a(1) #1978 Key Employee Stock Option Plan (Exhibit 1, File No. 2-61712). 21 List of subsidiaries (Exhibit 22, 1991 Form 10-K, File No. 1-2323). 24a Power of Attorney of Cleveland Electric and certified resolution of Cleveland Electric's Board of Directors authorizing the signing on behalf of Cleveland Electric pursuant to a power of attorney (Exhibit 25(b), March 31, 1993 Form 10-Q, File No. 1-2323). 24b *Powers of Attorney of Cleveland Electric directors and officers required to sign the Report.
TOLEDO EDISON EXHIBITS
Exhibit Number Document 3a Amended Articles of Incorporation of Toledo Edison, as amended effective October 2, 1992 (Exhibit 3a, 1992 Form 10-K, File No. 1-3583). 3b Code of Regulations of Toledo Edison dated January 28, 1987, as amended effective July 1 and October 1, 1988 and April 24, 1990 (Exhibit 3b, 1990 Form 10-K, File No. 1-3583). 4b(1) Indenture, dated as of April 1, 1947, between the Company and The Chase National Bank of the City of New York (now The Chase Manhattan Bank (National Association)) (Exhibit 2(b), File No. 2-26908). Supplemental Indentures between Toledo Edison and the Trustee, Supplemental to Exhibit 4b(1), dated as follows:
E-9 167
Exhibit Number Document 4b(2) September 1, 1948 (Exhibit 2(d), File No. 2-26908). 4b(3) April 1, 1949 (Exhibit 2(e), File No. 2-26908). 4b(4) December 1, 1950 (Exhibit 2(f), File No. 2-26908). 4b(5) March 1, 1954 (Exhibit 2(g), File No. 2-26908). 4b(6) February 1, 1956 (Exhibit 2(h), File No. 2-26908). 4b(7) May 1, 1958 (Exhibit 5(g), File No. 2-59794). 4b(8) August 1, 1967 (Exhibit 2(c), File No. 2-26908). 4b(9) November 1, 1970 (Exhibit 2(c), File No. 2-38569). 4b(10) August 1, 1972 (Exhibit 2(c), File No. 2-44873). 4b(11) November 1, 1973 (Exhibit 2(c), File No. 2-49428). 4b(12) July 1, 1974 (Exhibit 2(c), File No. 2-51429). 4b(13) October 1, 1975 (Exhibit 2(c), File No. 2-54627). 4b(14) June 1, 1976 (Exhibit 2(c), File No. 2-56396). 4b(15) October 1, 1978 (Exhibit 2(c), File No. 2-62568). 4b(16) September 1, 1979 (Exhibit 2(c), File No. 2-65350). 4b(17) September 1, 1980 (Exhibit 4(s), File No. 2-69190). 4b(18) October 1, 1980 (Exhibit 4(c), File No. 2-69190). 4b(19) April 1, 1981 (Exhibit 4(c), File No. 2-71580). 4b(20) November 1, 1981 (Exhibit 4(c), File No. 2-74485). 4b(21) June 1, 1982 (Exhibit 4(c), File No. 2-77763). 4b(22) September 1, 1982 (Exhibit 4(x), File No. 2-87323). 4b(23) April 1, 1983 (Exhibit 4(c), March 31, 1983 Form 10-Q, File No. 1-3583). 4b(24) December 1, 1983 (Exhibit 4(x), 1983 Form 10-K, File No. 1-3583). 4b(25) April 1, 1984 (Exhibit 4(c), File No. 2-90059). 4b(26) October 15, 1984 (Exhibit 4(z), 1984 Form 10-K, File No. 1-3583). 4b(27) October 15, 1984 (Exhibit 4(aa), 1984 Form 10-K, File No. 1-3583). 4b(28) August 1, 1985 (Exhibit 4(dd), File No. 33-1689). 4b(29) August 1, 1985 (Exhibit 4(ee), File No. 33-1689). 4b(30) December 1, 1985 (Exhibit 4(c), File No. 33-1689). 4b(31) March 1, 1986 (Exhibit 4b(31), 1986 Form 10-K, File No. 1-3583). 4b(32) October 15, 1987 (Exhibit 4, September 30, 1987 Form 10-Q, File No. 1-3583). 4b(33) September 15, 1988 (Exhibit 4b(33), 1988 Form 10-K, File No. 1-3583). 4b(34) June 15, 1989 (Exhibit 4b(34), 1989 Form 10-K, File No. 1-3583). 4b(35) October 15, 1989 (Exhibit 4b(35), 1989 Form 10-K, File No. 1-3583). 4b(36) May 15, 1990 (Exhibit 4, June 30, 1990 Form 10-Q, File No. 1-3583). 4b(37) March 1, 1991 (Exhibit 4(b), June 30, 1991 Form 10-Q, File No. 1-3583). 4b(38) May 1, 1992 (Exhibit 4(a)(3), File No. 33-48844). 4b(39) August 1, 1992 (Exhibit 4b(39), 1992 Form 10-K, File No. 1-3583).
E-10 168
Exhibit Number Document 4b(40) October 1, 1992 (Exhibit 4b(40), 1992 Form 10-K, File No. 1-3583). 4b(41) January 1, 1993 (Exhibit 4b(41), 1992 Form 10-K, File No. 1-3583). 10a Indemnity Agreements between Toledo Edison and certain of its current directors (Exhibit 10a, 1988 Form 10-K, File No. 1-3583). 24a Powers of Attorney of Toledo Edison and certified resolution of Toledo Edison's Board of Directors authorizing the signing on behalf of Toledo Edison pursuant to a power of attorney (Exhibit 25(c), March 31, 1993 Form 10-Q, File No. 1-3583). 24b *Powers of Attorney of Toledo Edison directors and officers required to sign the Report.
Pursuant to Paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, the Regis- trants have not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the total amount of securities authorized there- under does not exceed 10% of the total assets of the applicable Registrant and its subsidiaries on a consolidated basis, but each hereby agrees to furnish to the Securities and Exchange Commission on request any such instruments. Pursuant to Rule 14a-3(b)(10) under the Securities Exchange Act of 1934, copies of exhibits filed by the Registrants with this Form 10-K will be fur- nished by the Registrants to share owners upon written request and upon re- ceipt in advance of the aggregate fee for preparation of such exhibits at a rate of $.25 per page, plus any postage or shipping expenses which would be incurred by the Registrants. E-11 EX-10.B2.1 2 EXHIBIT FOR CENTERIOR 1 EXHIBIT 10b(2)(1) AMENDMENT NO. 1 TO CAPCO TRANSMISSION FACILITIES AGREEMENT THIS AGREEMENT, effective as of the 1st day of January 1, 1993, by and among The Cleveland Electric Illuminating Company, an Ohio corporation ("CEI"); Duquesne Light Company, a Pennsylvania corporation ("DL"); Ohio Edison Company, an Ohio corporation; Pennsylvania Power Company, a Pennsylvania corporation ("PP") and a wholly-owned subsidiary of Ohio Edison Company which Company and its said subsidiary, except as otherwise provided herein, are considered as a single Party for the purposes of this Agreement and referred to as ("OE"); and The Toledo Edison Company, an Ohio corporation ("TE"), each of which is sometimes referred to as a Party, and collectively as the Parties. W I T N E S S E T H: WHEREAS, the Parties entered into the CAPCO Transmission Facilities Agreement as of September 14, 1967 (herein referred to as the "Agreement"); and WHEREAS, the Parties entered into an Agreement on January 7, 1993, and approved an Addendum to the CAPCO Accounting and Procedure Manual to supersede applicable sections of the manual on a prospective basis as of January 1, 1993 (said Agreement being herein referred to as the "Addendum to CAPCO Accounting and Procedure Manual" or "Addendum"); and 2 WHEREAS, the provisions of the Addendum to the CAPCO Accounting and Procedure Manual are intended to supersede any provisions of the Agreement which conflict with or are inconsistent with the Addendum, so that such conflicts and inconsistencies shall be removed by appropriate written amend- ments to the Agreement or by other appropriate action; and WHEREAS, the Parties desire to further amend the Agreement as hereinafter set forth; NOW, THEREFORE, in consideration of the premises and of the mutual covenants herein set forth, the Parties agree as follows: 1. Section 7.02 of the Agreement is amended to read as follows: The Party owning a CAPCO Line or portion thereof shall bill each other Party monthly for such other Party's Investment Responsibility with respect thereto. The invoice date shall be established as soon as possible after the close of each calendar month, and the owning Party shall prepare and make all reasonable efforts to transmit invoices on or before the invoice date to each other Party for such other Party's Investment Responsibility. The amount billed will be payable in good funds the 15th calendar day after the invoice date except that, if the 15th calendar day is not a business day, the amount billed will be payable the next business day. Good funds shall consist of checks received at least one business day prior to the due 3 date and wire transfers received by noon on the due date. Interest on unpaid invoice amounts will be compounded monthly and prorated for any partial month based on a 365-day year, and will accrue at a rate equal to Chase Manhattan Bank's prime rate on the first day of the then current calendar quarter plus two percentage points for a period of up to one year and for any period thereafter at the higher of this rate or a rate equal to the billing Party's cost of capital which shall consist of the weighted average of the billing Party's long-term debt cost and preferred stock cost rates determined for issues outstanding on December 31 of the prior year and a common equity cost rate to be effective January 1 of each year equal to the average return on common equity for at least 50 major electric utilities with positive returns on common equity as reported in the prior year's December issue of the C.A. Turner Utility Reports or as reported in the prior year's latest issue of another report mutually agreed to by the Parties. The weighting for this calculation shall be the billing Party's capital structure at December 31 of the prior year, consisting solely of long-term debt, preferred stock and common equity, as reported in its FERC Form 1 or in another mutually agreed upon source. Invoices may not be changed or adjusted after four years from the invoice date, and invoice amounts to be refunded by the billing Party shall accrue interest as noted above, but invoice amounts payable to the billing Party for additional amounts shall not accrue interest. 4 To the extent practicable all charges payable or receivable under this Agreement shall be offset and reduced to a net basis in order to provide a minimum practicable number of payments among the Parties. Such statements may be rendered on an estimated basis subject to corrective adjustments in subsequent statements. 2. Section 17.01 of the Agreement is amended to read as follows: Any waiver at any time by any Party of its rights with respect to any matter arising in connection with this Agreement shall not be deemed a waiver with respect to any subsequent similar matter. Any delay, short of the statutory period of limitation, in asserting or enforcing any right under this Agreement, shall not be deemed a waiver of such right, except as provided in Section 7.02 and Section 14.01. 3. Exhibit B - Computation of Investment Responsibility of the Agreement is amended to read as attached: 4. Except as herein above amended, all of the terms and conditions of the Agreement shall remain in full force and effect. 5 IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be executed by their duly authorized officers this 23rd day of December, 1993. THE CLEVELAND ELECTRIC ILLUMINATING COMPANY By: TERRENCE G. LINNERT Title: Vice President DUQUESNE LIGHT COMPANY By: G.R. BRANDENBERGER Title: Vice President OHIO EDISON COMPANY By: ARTHUR P. GARFIELD Title: Vice President PENNSYLVANIA POWER COMPANY By: J. R. EDGERLY Title: Vice President THE TOLEDO EDISON COMPANY By: TERRENCE G. LINNERT Title: Vice President 6 EXHIBIT B Page 1 of 5 COMPUTATION OF INVESTMENT RESPONSIBILITY In General The capital carrying charges for a billing period shall be the capital revenue requirements for the aggregate of the adjusted CAPCO investment vintages related to the CAPCO facility. All vintage investments associated with a facility are considered to be supported by the same pool of capital sources as reflected currently on the books of the CAPCO company owning the facility. All income taxes are calculated using statutory tax rates (Federal and state) currently in effect for the billing period. Investment Basis 1. The original vintage investments committed to a facility will remain the basis for all calculations throughout the agreed-upon book depreciation life, undiminished by any retirements which may occur. The purpose of this provision is to ensure the complete recovery of the investment principal placed into service by a given company for the mutual benefit of the participating CAPCO companies. 2. The existing investment at January 1 of each year shall become the basis for calculating an annual fixed charge for that year, billable in monthly increments. 3. New investments placed in service during a given year will incur carrying charges, excluding both book and tax depreciation effects, billable monthly effective with the first month following the month in which the investment is placed in-service. Full fixed charge computations for these new investments, including both book and tax depreciation effects, will begin January 1 of the following year (see 2. above). For these purposes, the initial year (i.e., year #1) for each vintage for book and tax depreciation purposes shall begin with the first full calendar year following the initial in-service year. Book Depreciation Book depreciation, current and accumulated, shall be calculated for each vintage in accordance with the straight-line method utilizing agreed-upon lives for the facilities involved, without regard for any possible interim investment retirements. Tax Depreciation Tax depreciation, current and accumulated, shall be calculated for each vintage investment in accordance with the applicable tax depreciation system in effect at the time of the original investment for that vintage. 7 EXHIBIT B Page 2 of 5 Property Insurance Rates The billing Party shall use a current rate per gross plant investment dollar to incorporate property insurance costs into the carrying charges for a facility. Capital Structure and Cost Rates Capital Structure: The billing Party will use its capital structure at December 31 of the prior year, consisting solely of long-term debt, preferred stock and common equity, as reported in its FERC Form 1 or other mutually agreed upon source. Capital Cost Rates: 1. Debt and preferred stock cost rates are the billing Party long-term debt cost and preferred stock cost rates, determined for issues outstanding at December 31 of the prior year. 2. The common equity cost rate for CAPCO billing purposes is equal to the average return on common equity for major electric utilities. The rate to be effective January 1 of each year will be the average rate reported in the prior year's December issue of the "C.A. Turner Utility Reports" or as reported in the prior year's latest issue of another report mutually agreed to by the Parties. Individual utilities with "zero" or negative returns on common equity will be excluded from the calculation of the average return. This average shall include the return on common equity for at least 50 electric utilities. Tax Rates 1. Federal Income Tax: The billing Party shall use the current federal statutory income tax rate for all calculations. 2. State Income Tax: The billing Party shall use its current state statutory income tax rate for all calculations. 3. Other Taxes: The billing Party shall use its current rates or rate equivalents for all calculations. Computation Each Party's Investment Responsibility with respect to a CAPCO Line or portion thereof shall be an amount equal to the sum of (1), (2) and (3) below: 8 EXHIBIT B Page 3 of 5 (1) The product of (a) Fixed Charges on the CAPCO Investment Basis and (b) such Party's allocation percentage. Fixed Charges are defined as the sum of (i) book depreciation on the Investment Basis for the period, plus (ii) return on debt and on common and preferred equity, computed by applying the weighted capital cost rate for each capital component to the average undepreciated balance for the period for each investment vintage, plus (iii) income taxes on the equity portions of return adjusted for the effect of any differential in the book and tax depreciation amounts for the period. For the purpose of this subparagraph (1), retirements of property from land Account 350 shall be deducted from the adjusted investment basis of a given facility, but retirements from depreciable Accounts 352, 353 and Accounts 354, 355, 356, 359 and 397 shall not be deducted from the adjusted investment basis of the facility. Additions to or replacements of property in a given facility in depreciable Accounts 352, 353 and 354, 355, 356, 359 and 397 shall be treated as new facilities with new vintage dates except that all such additions or replacements occurring in the same calendar year will be considered to have a common vintage month. (2) The product of (a) the Party's allocation percentage of Investment Responsibility and (b) the sum of the applicable insurance charges, property taxes, capital stock taxes, gross receipts tax, or other taxes incurred by the owning Party in respect to the Line. (3) The product of (a) the Party's allocation percentage of Investment Responsibility and (b) the sum of the balances of the Cost, as defined in Section 2.03, of the Line carried in Accounts 352 and 353 on the owning Party's books at the end of the preceding month multiplied by the monthly operation and maintenance expense factor applicable to transmission substations determined as provided below, and such Cost balances of the Line carried in Accounts 354, 355, 356, 359 and 397 on the owning Party's books at the end of the preceding month multiplied by the monthly operation and maintenance expense factor applicable to transmission lines, determined as provided below. 9 EXHIBIT B Page 4 of 5 The monthly operation and maintenance expense factor referred to above for transmission substations is one-twelfth (1/12) of a three-year moving average ratio, calculated annually, in which the numerator is the most recent three-calendar-year sum of operation and maintenance expenses incurred by the billing Party in respect of all 345 kV or higher voltage transmission substations operated by the billing company and the denominator is the sum of the calendar year-end Cost balances of such transmission substations carried in Plant Accounts 352 and 353 on the books of the billing Party for the corresponding three years. The operation and maintenance expenses and Cost balances of main step-up transformers and of the electrical connections and supports from the transformer to the dead-end insulator attached to the switchyard structures shall be excluded in determining the expense factor for transmission substations. The monthly expense factor for transmission lines is one-twelfth (1/12) of a three-year moving average ratio, calculated annually, in which the numerator is the most recent three-calendar-year sum of operation and maintenance expenses incurred by the billing company in respect of all 345 kV or higher voltage transmission lines operated by the billing company and the denominator is the sum of the calendar year-end Cost balances of such transmission lines carried in Plant Accounts 354, 355, 356, 359 and 397 on the books of the billing company for the corre- sponding three years. The operation and maintenance expenses reflected in the expense factors shall consist of the following types of expenses: a. Direct expenses of operation and maintenance. b. An allocation of general transmission operation and maintenance expenses which are associated with all transmission facilities and functions, such as load dispatching. c. An allocation of administrative and general expenses. d. Applicable labor and material additive costs. For purposes of this Exhibit B, adjusted investment basis is the Cost of the asset, as defined in Section 2.03, of a CAPCO Line remaining after giving effect to the following exclusions as applicable: a. Investment tax credit. b. Contributions in aid of construction. c. Reimbursements. 10 EXHIBIT B Page 5 of 5 d. Accumulated book depreciation or amortization prior to designation as a CAPCO Line. e. Payroll taxes and pensions capitalized for book purposes but expensed currently for tax purposes, multiplied by the applicable composite income tax rate. f. Other adjustments as required to avoid inequity. EX-10.B.3 3 EXHIBIT FOR CENTERIOR 1 Exhibit 10b(3) CAPCO BASIC OPERATING AGREEMENT As Amended January 1, 1993 * * * The Cleveland Electric Illuminating Company Duquesne Light Company Ohio Edison Company Pennsylvania Power Company The Toledo Edison Company 2 IN WITNESS WHEREOF, the Partis hereto have caused this Agreement to be executed by their duly authorized officers this 23rd day of December, 1993. THE CLEVELAND ELECTRIC ILLUMINATING COMPANY By: TERRENCE G. LINNERT Title: Vice President DUQUESNE LIGHT COMPANY By: G. R. BRANDENBERGER Title: Vice President OHIO EDISON COMPANY By: ARTHUR P. GARFIELD Title: Vice President PENNSYLVANIA POWER COMPANY By: J. R. Edgerly Title: Vice President THE TOLEDO EDISON COMPANY By: TERRENCE G. LINNERT Title: Vice President 3 TABLE OF CONTENTS Page No. Article 1 -- Purpose of Agreement 2 Article 2 -- Definitions 2 Article 3 -- Operating Committee 5 Article 4 -- Operating Conditions 7 4.01 Parallel Operation 7 4.02 Frequency 8 4.03 Megavars 8 4.04 Unscheduled Energy 9 4.05 Transmission Operation 9 4.06 Coordinated Maintenance 10 4.07 Unit Availability 10 4.08 Utilization of CAPCO Units 11 Article 5 -- Coordinated Maintenance and CAPCO Back-Up Power 11 5.01 Coordinated Maintenance 11 5.02 CAPCO Back-Up Power 11 5.03 Scheduling CAPCO Back-Up Power 12 5.04 Obligation to Provide CAPCO Back-Up Power 12 5.05 Proportional Supply of CAPCO Back-Up Power 13 Article 6 -- Communications 14 Article 7 -- Services 15 Article 8 -- Executive Committee 16 Article 9 -- Ohio Edison System 17 Article 10 -- Interconnection Metering 17 Article 11 -- Records 19 Article 12 -- Statements, Billings, Settlements and Payments 19 Article 13 -- Government Approvals 22 Article 14 -- Notices 22 Article 15 -- Non-Waiver 22 4 TABLE OF CONTENTS (Cont'd) Page No. Article 16 -- Arbitration 23 Article 17 -- Assignment 26 Article 18 -- Governing Law 26 Article 19 -- Other Agreements 27 Article 20 -- Term of Agreement 28 Article 21 -- Separate Identities 28 Article 22 -- Force Majeure 29 Article 23 -- Liability 29 Schedule A -- Back-Up Power 32 Schedule B -- Short Term Power 35 Schedule C -- Non-Displacement Power 39 Schedule D -- Economy Power 42 Schedule E -- Unit Power 47 Schedule F -- Out-of-Pocket Cost 52 Schedule G -- Emergency Power 54 Schedule H -- Transmission of Non-CAPCO Power 57 Schedule I -- Replacement Power 58 5 CAPCO BASIC OPERATING AGREEMENT (As Amended January 1, 1993) This Agreement, effective as of the 1st day of January, 1993, by and among The Cleveland Electric Illuminating Company, an Ohio corporation ("CEI"); Duquesne Light Company, a Pennsylvania corporation ("DL"); Ohio Edison Company, an Ohio corporation; Pennsylvania Power Company, a Pennsylvania corporation and a wholly-owned subsidiary of Ohio Edison Company which company and its said subsidiary, except as otherwise provided herein, are considered as a single Party for the purposes of this Agreement and referred to as ("OE"); and The Toledo Edison Company, an Ohio corporation ("TE"); each of which is sometimes referred to as a Party, or Owner, and collectively as the Parties, Owners or CAPCO, W I T N E S S E T H: 0.01 The Parties own electric utility systems located in Western Pennsylvania, Northern and Central Ohio, and are engaged in the generation, transmission and distribution of electric power. 0.02 The systems of the Parties are interconnected directly or indirectly and are operated in synchronism. 6 ARTICLE 1 Purpose of Agreement 1.01 It is the purpose of this Agreement to provide for the coordinated operation of the systems of the Parties, so as to (1) provide for the utilization by each of the Parties of facilities heretofore provided for by the Parties; (2) provide a degree of mutual support; (3) provide for capacity and energy transactions by and among the Parties; (4) permit coordi- nation of the operation of the systems of the Parties; and (5) achieve an equitable sharing of the responsibilities, risks and expenses and of the resulting benefits of coordinated operation of the systems of the Parties. ARTICLE 2 Definitions The definitions in this Article shall apply to this Agreement and to the Schedules hereto, unless otherwise expressly provided in such Schedules. 2.01 Actual Capacity of a Party shall mean the sum of the Net Demonstrated Capability of its ownership shares in CAPCO Units, plus its Individual Capacity (in all cases to the extent then in commercial operation) adjusted in all cases for seasonal factors existing at the time pursuant to the document entitled, "CAPCO Group Common Method of Rating Generating Equip- ment," dated October 17, 1969, as amended from time to time, plus such Party's individual purchases less such Party's individual sales (but shall exclude 7 power scheduled to be received by a Party to provide for deliveries to cooperative or municipal systems or other Parties or non-CAPCO parties' systems). 2.02 CAPCO Unit shall mean any one of the following listed Units: W. H. Sammis Generating Station Unit No. 7, Bruce Mansfield Unit No. 1, Bruce Mansfield Unit No. 2, Bruce Mansfield Unit No. 3, Davis-Besse Nuclear Power Station Unit No. 1, Beaver Valley Power Station Unit No. 1, Beaver Valley Power Station Unit No. 2, Eastlake Generating Station Unit No. 5, Perry Nuclear Power Plant Unit No. 1 and Perry Nuclear Power Plant Unit No. 2. 2.03 Coordinated Maintenance Schedule means the schedule established under the direction of the Operating Committee pursuant to Section 5.01. 2.04 Individual Capacity of a Party as of any date is the sum of the following: (a) The Net Demonstrated Capabilities of the generating units or portions thereof owned or leased by such Party in commercial opera- tion and not placed in cold reserve, but exclusive of ownership of CAPCO Units. (b) The equivalent Net Demonstrated Capability of such Party's portion of the Ohio Valley Electric Corporation ("OVEC") capacity. 8 2.05 Interruptible Load of a Party is the total of megawatt- hours delivered during any clock hour to its retail customers or to municipal or cooperative systems which the Party, in its sole discretion, is privileged to curtail or completely interrupt in accordance with a rate schedule or contractual arrangement with such customer or customers. 2.06 Load of a Party during any clock hour is the total during any such clock hour (eliminating on an agreed basis any distortion arising out of deliveries between systems where material) of megawatthours (a) delivered by the Party to its retail customers and its municipal systems, but excluding that portion of municipal system Load which is purchased from other Parties or systems, (b) used by the Party on its own system, exclusive of use for station auxiliary power, and (c) lost and unaccounted for on the system of the Party; but shall exclude Interruptible Load. 2.07 Minimum Operating Reserve of a Party, unless otherwise determined by the Operating Committee, shall mean a spinning reserve of not less than 3% of the projected daily Peak Load of such Party. 2.08 Net Demonstrated Capability of a generating unit as of any time means that most recently determined pursuant to the methods and principles set forth in the document entitled, "CAPCO Group Common Method of Rating Generating Equipment," dated October 17, 1969, as amended from time to time. 9 2.09 Operating Capacity of a Party during a particular day shall mean that portion of a Party's Actual Capacity to the extent actually in operation or expected to be in operation. 2.10 Operating Reserve of a Party means that component of Operating Capacity which is unloaded, plus Quick Start Capacity and Inter- ruptible Load to the extent they can be so included in accordance with rules and procedures established by the Operating Committee. 2.11 Peak Load of a Party for any period of time is the maximum Load of the Party for any clock hour of the period. 2.12 Power shall include electric capacity and energy expressed in megawatts and megawatthours. 2.13 Quick Start Capacity means generating capacity which can be started, synchronized to the system and loaded within a time period as specified by the Operating Committee. ARTICLE 3 Operating Committee 3.01 The Operating Committee shall be that established pursuant to the CAPCO Administration Agreement dated as of September 14, 1967, as the same may be amended from time to time. 10 3.02 Each Party shall make available to the Operating Committee all data and information reasonably required to enable it to perform its duties. 3.03 The Operating Committee shall be responsible for establishing, maintaining and revising as necessary the Coordinated Maintenance Schedule. 3.04 The Operating Committee shall be responsible for the establishment and administration of rules and procedures to coordinate the operation of the systems of the Parties to effectuate the purpose of this Agreement. Without limiting the generality of the foregoing, the Operating Committee shall establish rules and procedures for: (a) The determination of billing costs and other factors used for scheduling and billing of transactions hereunder; (b) The determination of the increase or decrease of electrical losses incurred as the result of transactions hereunder; (c) The establishment and periodic revision of the Coordinated Maintenance Schedule which shall be reviewed at least annually; 11 (d) The determination of the Minimum Operating Reserve for each Party; (e) The scheduling of CAPCO Back-Up Power as provided in Article 5; and (f) Accumulating and recording load, capacity and other operating data needed to evaluate performance under the various CAPCO agreements. 3.05 The Operating Committee shall conduct studies of the coordinated operation of the systems of the Parties for the purposes of this Agreement, and make recommendations with respect thereto, including recom- mendations with respect to the development and coordination of an adequate communication system. The Operating Committee is authorized to create task forces for particular studies and to appoint the members thereof who need not be members of the Operating Committee. Subject to such limitations as may be imposed by the Executive Committee, the Operating Committee is authorized on behalf of the Parties to hire consultants and computer time and to incur other expenses in the making of any of its studies. ARTICLE 4 Operating Conditions 4.01 Each party shall operate its system continuously in parallel with each other Party with which it is interconnected. Unless otherwise mutually agreed which agreement shall not be unreasonably withheld, 12 all existing interconnections between the systems of the Parties operating at nominal voltages of 138,000 volts and above shall normally be operated closed. Each Party shall maintain and operate its system so as to minimize the likelihood and effect of disturbances on its system which might impair the service on the system of any other Party. Each Party shall be the sole judge whether service on its system is being impaired by conditions on the system of another Party and may itself take, or request such other Party to take, appropriate corrective action to restore normal operating conditions as soon as reasonably practicable. Power which is supplied by one Party to another Party through interconnections normally operated open or through a temporary interconnection point shall be compensated for by the other Party delivering to the first Party through other interconnections equivalent Power adjusted for losses. It is the intent of the Parties that, whenever feasible, such compensation shall be made simultaneously with the delivery of Power through such interconnections. 4.02 Each Party shall use its best efforts to operate its system so as to aid in maintaining the frequency on the systems of the Parties at a nominal 60 Hz within the limits for normal operating deviations as established from time to time by the Operating Committee. 4.03 Each Party shall, to the extent practicable, operate its system so as to avoid the creation of objectionable operating conditions on the system of another Party due to the transfer of megavars. Subject to the foregoing, the Operating Committee shall (a) establish operating procedures 13 for the coordination of megavar supply associated with flows of Power pursuant to this Agreement, and (b) determine the circumstances under which a Party shall compensate another for supplying megavars in connection with flows of Power pursuant to this Agreement and recommend the amount of such compensation. 4.04 Each Party shall exercise reasonable care to minimize, to the extent practicable, unscheduled deliveries or receipts of electric energy. The Parties recognize, however, that despite their best efforts such unscheduled deliveries or receipts of electric energy may occur. Electric energy delivered or received in such event shall be settled for by return of equivalent energy. It shall be returned at times when the load conditions of the returning Party are equivalent to the load conditions of such Party at the time the energy for which it is returned was received, unless otherwise agreed. 4.05 The Parties recognize that in the day-to-day operation of their systems the transmission facilities of any Party may, as a natural result of the physical and electrical characteristics of the interconnected network of transmission lines of which the transmission lines of the Parties are a part, carry Power from one portion of the system of one of the Parties to another portion of that Party's system, or carry Power intended to be transmitted to or from the system of one of the Parties from or to the system of another Party or other systems. The Parties will use their best efforts to resolve promptly any operating problems thereby created, including but not limited to curtailing or interrupting Interruptible Load and Economy Power transactions with other Parties and/or other systems. 14 4.06 Each Party shall, to the fullest extent practicable: (a) Maintain generating units in accordance with the Coordinated Maintenance Schedule. (b) Coordinate with the other Parties the scheduled outages of transmission facilities operating at nominal voltages of 138,000 volts or above. (c) Return generation and transmission facilities to service in good operating condition with reasonable promptness. (d) Advise the other Parties as to its maintenance practices and policies and any changes therein, and cooperate in attempts to accelerate or defer maintenance of generation and transmission facilities in emergency situations. 4.07 Each Party shall be the sole judge as to whether, due to physical conditions beyond its reasonable control, a generating unit operated by such Party is unavailable for operation or unavailable for continued opera- tion or must be derated or temporarily removed from service; provided, however, that unavailability for operation or continued operation, or derating, for reasons of limitations of fuel supply for a CAPCO unit, shall be determined in accordance with rules and procedures established by the Operating Committee. 15 4.08 Each Party shall be entitled to the full utilization, with respect to capacity and energy, when a CAPCO Unit is available and based on and in proportion to the actual day-by-day operating capacity, of (a) its ownership share of capacity in that Unit, plus (b) its entitlement to receive capacity from another Party's ownership share in such Unit, and minus (c) its obligation to provide capacity from such Unit. Scheduling of such capacity and energy entitlements shall be adjusted appropriately for transmission line losses. ARTICLE 5 Coordinated Maintenance and CAPCO Back-Up Power 5.01 The Parties shall coordinate the outages for maintenance of all CAPCO Units and such other units of the Parties as are identified by the Operating Committee and for such purpose the Coordinated Maintenance Schedule shall be developed and maintained in accordance with rules and procedures established pursuant to Section 3.04. 5.02 In order to provide back-up for CAPCO Unit outages, each Party shall have an entitlement to receive or an obligation to provide operating capacity and associated energy in the form of CAPCO Back-Up Power. CAPCO Back-Up Power shall be calculated as specified in the next paragraph in this Section and shall be compensated for as specified in Schedule A of this Agreement; provided, however, such CAPCO Back-Up Power shall not be available for any nuclear CAPCO Unit during those periods in which such CAPCO Unit is out of service for the reasons set forth in Schedule I. 16 In the event of the forced or scheduled outage of any CAPCO Unit in commercial operation (except those Units in cold reserve), each Party agrees to provide or shall have the right to receive, as the case may be, CAPCO Back-Up Power in an amount equal to the difference between such Party's ownership share in the CAPCO Unit out of service, expressed in megawatts, and a value determined by multiplying the Net Demonstrated Capability of the CAPCO Unit out of service by the ratio of such Party's ownership share of the Net Demonstrated Capability of all of the CAPCO Units in commercial operation to the total Net Demonstrated Capability of all of the CAPCO Units in commercial operation. Each Party shall use its best efforts to operate its system so as to provide the amounts of Minimum Operating Reserve determined consistent with the rules and procedures established pursuant to Section 3.04. 5.03 Pursuant to rules and procedures established by the Operating Committee, CAPCO Back-Up Power for the next succeeding day shall be arranged on a net basis, initially at 1200 hours on the preceding day or such other time mutually agreed upon by the Operating Committee, and shall be scheduled as requested by the receiving Party. The receiving Party shall have the right to receive all or any part of such Party's net entitlement to CAPCO Back-Up Power. 5.04 Each Party is obligated to provide CAPCO Back-Up Power after supplying its Load and meeting its Minimum Operating Reserve, except when the delivery of such Power would, in the judgment of the supplying Party, 17 have to be interrupted or reduced to preserve the integrity of or to prevent or limit any instability on the supplying Party's system. If a Party having an obligation to supply does not have sufficient capacity available on its own system to meet the obligation, it is obligated to purchase capacity and associated energy if available to provide CAPCO Back-Up Power. For each day that a Party is unable to fulfill all or any part of its obligation to provide CAPCO Back-Up Power because it is supplying Power other than CAPCO Back-Up Power to another Party or to a non-CAPCO party, except pursuant to obligations imposed by governmental authorities, agreements referred to in Article 19, and any additional agreements excepted by the Parties, such Party shall pay an amount equal to twice the maximum daily demand charge for the CAPCO Back-Up Power not provided by such Party to the other Parties to be shared in proportion to the entitlements which were not fulfilled. In the event any Party is unable to provide CAPCO Back-Up Power in any substantial amount over an extended period and reserves substantial CAPCO Back-Up Power from others, the Parties shall develop corrective measures such as, but not limited to, increasing the demand charge rate. 5.05 CAPCO Back-Up Power will be made available in proportion to Party entitlements from supplying Parties in proportion to their obliga- tions, and will be made available from the least-cost available Power. In the event that a receiving Party or Parties reserve less than its or their entitlement of CAPCO Back-Up Power, the remaining CAPCO Back-Up Power will be made available from the supplying Parties in proportion to their obligations to the other receiving Parties in proportion to their entitlements from such 18 least-cost available Power. CAPCO Back-Up Power obligations not reserved by the receiving Parties shall be deemed released to the supplying Parties. ARTICLE 6 Communications 6.01 The Parties will establish communication facilities as may be required to provide voice communication, telemetering, automatic generation control, monitoring, tie-line control, and other functions as may be determined from time to time by the Operating Committee, or as required by other agreements among the Parties. Such communication facilities will consist of existing communication links owned or leased by the Parties as well as communication links to be built or leased by the Parties. It is understood that extensive use of microwave links will be made pursuant to the CAPCO Microwave Sharing Agreement, as amended January 1, 1993 and as it may be amended from time to time, although carrier current and wire communication facilities will be used as deemed appropriate by the Operating Committee. Communication links other than microwave will be provided, operated and paid for as determined by the Operating Committee following as closely as possible the principles established in said sharing Agreement. 19 ARTICLE 7 Services 7.01 The specific services and transactions among the Parties pursuant to this Agreement shall be in conformance with the terms and condi- tions of this Agreement and as set forth in Schedules arranged from time to time among the Parties. The following Schedules are agreed to and hereby made a part of this Agreement: Schedule A - CAPCO Back-Up Power Schedule B - Short Term Power Schedule C - Non-Displacement Power Schedule D - Economy Power Schedule E - Unit Power Schedule F - Out-of-Pocket Cost Schedule G - Emergency Power Schedule H - Transmission of Non-CAPCO Power Schedule I - Replacement Power The Parties may, from time to time, agree on modifications to or additional Schedules, and upon execution thereof by the Parties any such modification or addition shall become a part of this Agreement. 7.02 Energy transactions (other than those arising under Schedule E) shall be scheduled as if there were zero transmission losses. A 20 Party receiving such energy from another Party (whether such Party is acting as a supplying or transmitting Party arising under Schedule D of this Agree- ment) shall be charged with any increase in transmission losses and/or shall receive credit for any decrease in transmission losses associated with the transmission of the energy through the systems of Parties other than that of the supplying Party. Transmission losses will be accounted for by separate calculation in a manner prescribed by the Operating Committee. Loss imbalances shall be repaid through loss-payback schedules arranged among the Parties. 7.03 If any transaction results in material interference with the facilities or operation of the system of any other Party, the Parties to the transaction promptly shall take appropriate actions which may include, among other things, modification of the transaction to eliminate such interferences and provide compensation to the Party affected for increased operating costs or damage to facilities. ARTICLE 8 Executive Committee 8.01 The Executive Committee shall be that established pursuant to the CAPCO Administration Agreement, dated as of September 14, 1967, as the same may be amended from time to time. 8.02 The Executive Committee shall have the duties and powers conferred on it by this Agreement, including the making of any decision or 21 determination necessary under any provision of this Agreement and not expressly specified to be decided or determined by any other person or persons. ARTICLE 9 Ohio Edison System 9.01 Ohio Edison Company and Pennsylvania Power Company shall be considered to be separate Parties under this Agreement whenever and to the extent that separate corporate action is required of such Companies in order to accomplish the purpose of this Agreement, but their liability and respon- sibility for the performance of any obligation of OE hereunder to the other Parties shall be joint and several. The allocation between Ohio Edison Company and Pennsylvania Power Company of their collective obligations here- under as OE shall be the sole responsibility of said Companies, but they undertake that they will, during the period that they shall be obligated under this Agreement, have in force one or more arrangements for the allocation of the whole of such collective obligations and will, upon the request of any of the other Parties hereto, furnish the requesting Party or Parties satisfactory evidence of the existence of their then effective arrangements relating to such allocation. ARTICLE 10 Interconnection Metering 10.01 Electricity flowing across an interconnection shall be measured by suitable metering equipment at metering points agreed upon by the 22 Parties to the interconnection. The equipment at such metering points shall be provided, owned and maintained as agreed by the affected Parties. 10.02 Measurements of electric energy for the purpose of effecting settlements shall be made by standard types of electric meters installed and maintained by the owners at the metering points. The timing devices of all meters having such devices shall be maintained in time synchronism as closely as practicable. The meters shall be sealed and the seals shall be broken only upon occasions when the meters are to be tested or adjusted. 10.03 The aforesaid standard metering equipment shall be tested by the owners at suitable intervals and its accuracy of registration maintained in accordance with good practice. On request of any affected Party, a special test may be made at the expense of the Party requesting such special test. Representatives of all affected Parties shall be afforded opportunity to be present at all routine or special tests and upon occasions when any readings, for purposes of settlements, are taken from meters not bearing an automatic record. For the purpose of checking the records of the metering equipment installed by a Party as provided above, the other affected Party shall have the right to install check metering equipment at its own expense at the metering points referred to in Section 10.01. 10.04 If any test of metering equipment shall disclose an inaccuracy greater than 2%, the accounts among the affected Parties for service theretofore delivered shall, unless otherwise agreed by the affected Parties, be adjusted to correct for the inaccuracy disclosed over the shorter 23 of the following two periods: (1) from 30 days prior to the receipt of written request of the test until the meter is corrected; or (2) for the period that such inaccuracy may be determined to have existed. Should the metering equipment at any time fail to register under load conditions, or registers during times of zero flow, the electric energy delivered shall be determined from the best available data. ARTICLE 11 Records 11.01 Each Party shall keep such records as may be reasonably required by the Executive Committee or the Operating Committee, and shall furnish to such committees such records, reports and other information as they may reasonably require. ARTICLE 12 Statements, Billings, Settlements and Payments 12.01 As promptly as practicable within 10 days after the end of each calendar month, the Parties shall prepare and furnish to every other Party a statement showing the debits and credits to each Party for Power transactions hereunder during such month and, to the extent appropriate, offset or reduce said transactions to a net basis. From the Party balances so determined, each billing Party shall prepare and send to each other Party, as appropriate, a billing statement for all transactions which occurred during the month and involve payment of money. The billing Party shall take all reasonable measures to ensure that billing statements are mailed or otherwise 24 transmitted on the billing statement date. Billing statements may be rendered on an estimated basis subject to corrective adjustments in subsequent statements. Other than as required by law or regulatory action or by billing adjustments must be made for power purchases from non-CAPCO companies, corrective adjustments for power purchases as defined in Schedules A, B, C, D, G, H and I must be made within one (1) year of the rendering of the initial billing statement and corrective adjustments for all other CAPCO billings must be made within four (4) years of the rendering of the initial billing statement. 12.02 Billing statements rendered pursuant to Section 12.01 shall be due and payable in good funds the fifteenth calendar day after the billing statement date of any such statement except that, if the 15th calendar day is not a business day, the amount billed will be payable the next business day. Good funds shall consist of checks received at least one business day prior to the due date and wire transfers received by noon on the due date. Interest on unpaid billing statement amounts will be compounded monthly and prorated for any partial month based on a 365-day year, and will accrue at a rate equal to Chase Manhattan Bank's prime rate on the first day of the then current calendar quarter plus two percentage points for a period of up to one year and for any period thereafter at the higher of this rate or a rate equal to the billing Party's cost of capital which shall consist of the weighted average of the billing Party's long-term debt cost and preferred stock cost rates determined for issues outstanding on December 31 of the prior year and a common equity cost rate to be effective January 1 of each year equal to the average return on common equity for at least 50 major electric utilities with positive returns on common equity as reported in the prior year's December 25 issue of the C.A. Turner Utility Reports or as reported in the prior year's latest issue of another report mutually agreed to by the Parties. The weighting for this calculation shall be the billing Party's capital structure at December 31 of the prior year, consisting solely of long-term debt, preferred stock and common equity, as reported in such Party's FERC Form 1 or in another mutually agreed upon source. Billing adjustments which represent amounts to be refunded by the billing Party shall accrue interest as noted above, but billing adjustments payable to the billing Party for additional amounts shall not accrue interest. Notwithstanding the foregoing, any billing statement shall not be due and payable to the extent that (1) any non-CAPCO party system fails to compensate a Party for amounts owed hereunder in which event such Party shall exercise its best efforts to collect such compensation from such non-CAPCO party system and will not compromise or settle any claim for such compensation without prior consent of all other affected parties, or (2) any non-CAPCO party system's payment date is later that the fifteen days stated above in which case such billing statement shall be due and payable on the same date as that of the non-CAPCO party system's payment date. To the extent that any non-CAPCO party system compensates a Party in an amount less than the amount the non-CAPCO party system owes the Parties under the Party's billing statement for amounts owed hereunder, each Party shall be entitled to be first compensated for Out-of-Pocket Costs associated with the transaction hereunder and so much of the balance as will result in a sharing of the remainder among the Parties in proportion to the amounts owed to such Parties for their respective unpaid charges. 26 ARTICLE 13 Government Approvals 13.01 The obligations of each of the Parties hereunder are subject to the obtaining of any requisite orders, approvals, permits, certif- icates or licenses from any government authorities having jurisdiction. 13.02 This Agreement is made subject to the jurisdiction of any government authority or authorities having jurisdiction in the premises. Nothing contained in this Agreement or any Schedule of this Agreement shall be construed as affecting in any way the right of any Party to unilaterally make application to the Federal Energy Regulatory Commission for a change in rates under the Federal Power Act and pursuant to the Commission's Rules and Regulations promulgated thereunder. ARTICLE 14 Notices 14.01 Notices or requests, when required under this Agreement to be in writing, shall be delivered in person or mailed to the addressee at such Party's general office. Other notices or requests required under this Agreement may be given orally and, if required by the other Party, shall thereafter be confirmed in writing within three working days. Copies of notices or requests, confirmations of oral notices or requests, and informa- tion as to oral notices or requests shall be provided to the Office in accordance with procedures established by the Operating Committee. 27 ARTICLE 15 Non-Waiver 15.01 Any waiver at any time by any Party of its rights with respect to any matter arising in connection with this Agreement shall not be deemed a waiver with respect to any subsequent similar matter. Any delay, short of the statutory period of limitation, in asserting or enforcing any right under this Agreement, shall not be deemed a waiver of such right, except as provided in Sections 12.01 and 12.02 and in Section 16.01. ARTICLE 16 Arbitration 16.01 Any controversy or claim arising out of this Agreement, including the refusal by any Party to perform the whole or any part hereof, shall, upon demand of any Party aggrieved, be settled by an Arbitration Board, which shall consist of three nonrepresentative members and such additional representative members as hereinafter provided in this Section. No person shall be eligible for appointment as a nonrepresentative member of the Arbitration Board who is an officer, employee, shareholder of, or otherwise interested in, any Party or any affiliate thereof or in the matter sought to be arbitrated. Unless otherwise agreed, no demand for arbitration shall be made more than one year after the Parties have reached an impasse as to the controversy or claim involved. The Party or Parties demanding arbitration shall serve written notice upon the other Party or Parties to the controversy, 28 setting forth in detail the matter or matters with respect to which arbitration is demanded, and shall serve copies of such notice upon any other Parties hereto. Within a period of 10 days from the date of receipt of the aforesaid written notice, each Party to the controversy shall appoint a representative to serve as a member of the Arbitration Board; and, within a period of 30 days from such date of receipt of such written notice, such representative members shall unanimously agree upon the persons who shall serve as the three nonrepresentative members of the Arbitration Board. If the representative members are not so appointed within the specified 30-day period, or if the representative members shall fail to unanimously agree under the appointment of any or all of the three non- representative members of the Arbitration Board within the specified 30-day period, any Party to the controversy may, upon written notice to the other Parties to the controversy, request the American Arbitration Association to submit to the Parties to the controversy a list from its panels of arbitrators of the names of at least seven persons from which the nonrepresentative member or members who have not been so appointed shall be selected in accordance with the Commercial Arbitration Rules of such Association. If any Party to the controversy shall fail to appoint its representative member within the specified 10-day period, such Party shall be deemed to have waived its right to appoint such representative member and the Arbitration Board shall consist of the three nonrepresentative members and such representative members, if any, as shall have been appointed in accordance with the provisions of this Section 16.01. 29 The arbitration proceedings shall be conducted at a place, to be designated by the Arbitration Board, within the service area of one of the Parties to the controversy. The Arbitration Board shall afford adequate opportunity to each Party to the controversy to present information with respect to the controversy or claim submitted to arbitration and may request further information from any such Party. Except as provided in the preceding sentence, the Parties to the controversy may, by mutual agreement, specify the rules which are to govern any proceeding before the Arbitration Board and limit the matters to be considered by the Arbitration Board, in which event the Arbitration Board shall be governed by the terms and conditions of such agreement. To the extent of the absence of any such agreement specifying the rules which are to govern any proceeding, the then current applicable rules of the American Arbitration Association for the conduct of commercial arbitration shall govern the proceedings. The arbitration shall be limited to the matter or matters specified in the initial notice demanding arbitration and the award of the Board shall not affect or change any provision of this Agreement or any other transaction between the Parties. Procedural matters pertaining to the conduct of the arbitration and the award of the Arbitration Board shall be determined by a majority of the nonrepresentative members thereof; provided, however, that the representa- tive members shall have full right and authority to participate in all meetings and deliberations of the Arbitration Board leading to the award. The findings and award of the Arbitration Board, so made upon a determination of a 30 majority of the nonrepresentative members thereof, shall be final and conclu- sive with respect to the controversy or claim submitted for arbitration and shall be binding upon the Parties to the controversy except as otherwise provided by law. Such award of the Arbitration Board shall specify the manner and extent of the division of the costs of the arbitration proceedings among the Parties to the controversy. Judgment upon the award may be entered in any court, State or Federal, having jurisdiction. ARTICLE 17 Assignment 17.01 No Party may, without the prior written consent of the others, assign this Agreement, except as the same may be assigned (a) volun- tarily or otherwise under its first mortgage, or (b) to a successor to all or substantially all of the assets of the Party by way of merger, consolidation, sale or otherwise, where the successor assumes and becomes liable for all the obligations of the Party hereunder. ARTICLE 18 Governing Law 18.01 This Agreement is made under and shall be governed by the laws of the State of Ohio insofar as applicable. 31 ARTICLE 19 Other Agreements 19.01 During the term of this Agreement, its terms, conditions and Schedules shall be applicable to transactions among the Parties. This Agreement is not to be interpreted as conflicting or interfering with the performance of any agreement including modifications or amendments thereto between any Party and any system not a Party to this Agreement, effective prior to August 31, 1980. The Parties hereto shall be free to enter into any new agree- ments with other Parties or with other systems which do not impair operations under this Agreement or the ability of a Party to perform its obligations under this Agreement. The following agreements identified by FERC rate schedule numbers shown for each listed company are hereby terminated:
Company FERC Rate Schedule Number(s) The Cleveland Electric Illuminating Company 25 Duquesne Light Company 21 Ohio Edison Company 157 Pennsylvania Power Company 44 The Toledo Edison Company 35
32 ARTICLE 20 Term of Agreement 20.01 Except as provided in Section 20.03, this Agreement shall continue in effect until such time as all CAPCO Units are retired. 20.02 Any Party may withdraw from this Agreement by giving one year's advance notice in writing to the members of the Executive Committee of the other Parties, provided that in the event of such withdrawal, the provi- sions of this Agreement relating to coordinated maintenance of CAPCO Units, CAPCO Back-Up Power, and CAPCO Replacement Power shall continue in effect until such time as all CAPCO Units are retired. 20.03 Notwithstanding the retirement of all CAPCO Units under Section 20.01 and the withdrawal of any Party under Section 20.02, this Agreement shall continue in effect for those Parties who do not withdraw from this Agreement. ARTICLE 21 Separate Identities 21.01 The duties, obligations and liabilities of the Parties are intended to be several and not joint or collective, and nothing herein contained shall ever be construed to create an association, joint venture, trust or partnership or to impose a trust or partnership duty, obligation or liability on or with regard to any Party. Each Party shall be individually responsible for its own obligations as herein provided. No Party shall be 33 under the control of or shall be deemed to control another Party by virtue of this Agreement. No Party shall have a right or power to bind another without its or their express written consent, except as expressly provided in this Agreement. ARTICLE 22 Force Majeure 22.01 No Party shall be considered to be in default in the performance of any of the obligations hereunder if failure of performance shall be due to uncontrollable forces. The term "uncontrollable forces" shall mean any cause beyond the control of the Party affected, including but not limited to the failure of facilities, flood, earthquake, storm, fire, lightning, epidemic, war, riot, civil disturbance, labor dispute, sabotage, restraint by Court order or public authority or inability to obtain necessary licenses or permits. Nothing herein shall be construed so as to require a Party to settle any strike or labor dispute in which it may be involved. Any Party which is unable to fulfill any obligations by reason of uncontrollable forces shall exercise due diligence to remove such inability with all reasonable dispatch. ARTICLE 23 Liability 23.01 All claims arising out of any bodily injury, death or damages to property or business of third persons (other than customers, as such, of any of the Parties) arising because of operations under this 34 Agreement caused or sustained on the system of a Party (the Defending Party) shall be defended or in its discretion settled by such Party. In the event any action on any such claim is brought against any other Party, such other Party shall promptly notify the Defending Party in writing, and the Defending Party shall be entitled to and shall take over and direct the defense and disposition of the case. Any amounts paid by way of settlement or in satisfaction of any judgment and all expenses associated with such defense or settlement shall be the responsibility of the Defending Party. The provisions of this Section do not apply to claims of the employees of any Party under any workers' compensation law, for which the employing Party shall be responsible. 23.02 Each Party hereby waives any and all claims it may have against any other Party arising from negligence or other fault of another Party in connection with operations under this Agreement, except as otherwise provided in Section 7.03. 35 IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be executed by their duly authorized officers this 23rd day of December, 1993. THE CLEVELAND ELECTRIC ILLUMINATING COMPANY By: TERRENCE G. LINNERT Title: Vice President DUQUESNE LIGHT COMPANY By: G. R. BRANDENBERGER Title: Vice President OHIO EDISON COMPANY By: ARTHUR P. GARFIELD Title: Vice President PENNSYLVANIA POWER COMPANY By: J. R. EDGERLY Title: Vice President THE TOLEDO EDISON COMPANY By: TERRENCE G. LINNERT Title: Vice President 36 CAPCO BASIC OPERATING AGREEMENT SCHEDULE A CAPCO BACK-UP POWER Section 1 - Applicability 1.1 This Schedule A is applicable to CAPCO Back-Up Power transactions among the Parties pursuant to the provisions of Article 5 of the CAPCO Basic Operating Agreement ("Agreement"). Section 2 - Compensation for CAPCO Back-Up Power 2.1 Demand Charge Receiving Party shall pay the supplying Party a demand charge calculated on a daily basis for the net amount of CAPCO Back-Up Power reserved at a rate not to exceed $323 per MW per day, plus the excess demand charge, if any, of the amount paid therefor by the supplying Party over such demand charge for each megawatt of capacity that is purchased by a supplying Party from a Party or a non-CAPCO party system to provide CAPCO Back-Up Power. If at any time during a day a supplying Party is unable to provide all or any portion of the capacity reserved, the demand charge for the capacity not provided will be canceled for that day. Supplying Parties will communicate to the Receiving Parties significant changes in estimated energy costs occurring during the day. If the supplying Party's estimated Out-of-Pocket Costs for energy increase beyond 37 limits established by the Operating Committee from the estimate which was used as the basis for the reservation, a receiving Party shall have the right to cancel all or any part of the balance of the daily reservation (other than any specific reservation from third parties) which will include the cancellation of the daily demand charge for the capacity canceled. In the event the total energy cost of a supplying Party for a particular day (other than the cost of the specific reservation from third parties) exceeded the total energy cost quoted by such Party for that day beyond limits established by the Operating Committee, such Party's demand charge for that day shall not be payable. 2.2 Capacity Charge Receiving Party shall pay the supplying Party a charge not to exceed the supplying Party's Out-of-Pocket Cost of providing operating capacity; plus a charge not to exceed $2.40 per MW-hr for operating capacity provided from a supplying Party's system; or plus a charge not to exceed $1.00 per MW-hr for operating capacity purchased from a non-CAPCO party system. 2.3 Capacity and Energy Receiving Party shall pay the supplying Party a charge not to exceed the supplying Party's Out-of-Pocket Cost of providing operating capacity and energy; plus a charge not to exceed $2.40 per MWh for operating 38 capacity and energy provided from the supplying Party's system; or plus a charge not to exceed $1.00 per MWh for operating capacity and energy purchased from a non-CAPCO party system. 2.4 Total Compensation Notwithstanding the rates stated in Subsections 2.1, 2.2 and 2.3 above for any CAPCO Party generating CAPCO Back-Up Power, the sum of the demand, capacity and the capacity and energy charges provided in such subsections for each specific reservation made pursuant to this Schedule A shall not be less than 100% of the total Out-of-Pocket Cost of supplying the CAPCO Back-Up Power for such reservation; plus any demand charges paid to a non-CAPCO party and provided additionally, however, that any incremental or decremental transmission losses incurred on the system of any other Party resulting from the transmission of such energy shall be treated in accordance with Article 7. 39 CAPCO BASIC OPERATING AGREEMENT SCHEDULE B SHORT TERM POWER Section 1 - Services to be Rendered Any Party may arrange to reserve from another Party for periods of one or more days or weeks Short Term Power whenever, in the sole judgment of the Party requested to supply the same, such Short Term Power is available. As used herein, the term "week" shall mean any seven consecutive days. 1.1 Prior to each reservation of Short Term Power, the number of mega- watts to be reserved and the period of the reservation shall be determined by the Parties to the transaction. Such determination shall be confirmed in writing. If during such period conditions arise that could not have been reasonably foreseen at the time of reservation and cause the reservation to be burdensome to the supplying Party, such Party may by oral or written notice to the receiving Party, reduce the number of megawatts to be reserved by such amount and for such times as it shall specify in such notice. 1.2 During each period that Short Term Power has been reserved, the supplying Party shall upon call provide Short Term Operating Capacity up to and including the number of megawatts then reserved and deliver Short Term Energy to the receiving Party, as scheduled by the receiving Party, in an amount during each hour up to and including the number of megawatts of Short Term Operating Capacity then being provided. 40 Section 2 - Compensation 2.1 Demand Charge The receiving Party shall pay the supplying Party for any week that Short Term Power is reserved, a demand charge in an amount not to exceed $2,121 per MW reserved for that week, less one-sixth of such demand charge per MW of reduction for each day (other than Sunday) during any part of which the amount of such Short Term Power is reduced by the supplying Party; or for any period less than a week but not less than a day that Short Term Power is reserved, a demand charge in an amount not to exceed $424 per MW per day, less such demand charge per MW of reduction for each day during any part of which the amount of such Short Term Power is reduced by the supplying Party; plus The receiving Party shall pay the supplying Party for each megawatt of capacity reserved under this Schedule that is purchased by the supplying Party from a non-CAPCO party system, the excess, if any, of the amount paid therefor by the supplying Party over the demand charge therefor agreed to under Paragraph 1 of Subsection 2.1 above (or, if such amount is less than such agreed to demand charge, minus the deficiency); plus for such trans- actions a demand charge not to exceed $447 per MW week or $89.40 per MW day shall apply based on the agreed upon period. The supplying CAPCO Party will determine the demand charge for each transaction; plus 41 2.2 Capacity Charge Receiving Party shall pay the supplying Party a charge not to exceed the supplying Party's Out-of-Pocket Cost of providing operating capacity; plus a charge not to exceed $2.40 per MW-hr for operating capacity provided from a supplying Party's system; or plus a charge not to exceed $1.00 per MW-hr for operating capacity purchased from a non-CAPCO party system. 2.3 Capacity and Energy Receiving Party shall pay the supplying Party a charge not to exceed the supplying Party's Out-of-Pocket Cost of providing operating capacity and energy; plus a charge not to exceed $2.40 per MWh for operating capacity and energy provided from the supplying Party's system; or plus a charge not to exceed $1.00 per MWh for operating capacity and energy purchased from a non-CAPCO party system. 2.4 Total Compensation Notwithstanding the rates stated in Subsections 2.1, 2.2 and 2.3 above for any CAPCO Party generating Short Term Power, the sum of the demand, capacity and the capacity and energy charges provided in such subsections for each specific reservation made pursuant to this Schedule B shall not be less than 100% of the total Out-of-Pocket Cost of supplying the Short Term Energy for such reservation; plus any demand charges paid to a non-CAPCO party and 42 provided additionally, however, that any incremental or decremental transmission losses incurred on the system of any other Party resulting from the transmission of such energy shall be treated in accordance with Article 7. 43 CAPCO BASIC OPERATING AGREEMENT SCHEDULE C NON-DISPLACEMENT POWER Section 1 - Services to be Rendered 1.1 Transactions not specifically provided for under other Schedules may be mutually advantageous and may be arranged between Parties when one Party has operating capacity and/or energy it is willing to make available to another Party as Non-Displacement Power. Such transactions shall be arranged in advance and shall specify the amount of operating capacity to be provided, if any, and the hours it is to be provided. Energy to be delivered under this Schedule shall be as scheduled by the receiving Party. Section 2 - Compensation 2.1 Demand Charge Non-Displacement Power shall be compensated for at the option of the supplying Party (1) by return-in-kind or (2) by payment of a demand charge not to exceed $26.51 per MWh, the charge in any one day not to exceed $424 times the maximum MW(s) reserved in any one hour of that day and the charge in that week not to exceed $2,121 times the maximum MW(s) reserved in any one hour of that week when supplied from a CAPCO party system; plus For each megawatt of capacity reserved under this Schedule that is purchased by the supplying Party from a non-CAPCO party system, the excess, if 44 any, of the amount paid therefor by the supplying Party over the demand charge therefor agreed to under Paragraph 1 of Subsection 2.1 above (or, if such amount is less than such agreed to demand charge, minus the deficiency); plus for such transactions a demand charge not to exceed $5.59 per MWh shall apply. However, the charge in any one day is not to exceed $89.40 times the maximum MW(s) reserved in any one hour in that day and the charge in that week not to exceed $447 times the maximum MW(s) reserved in any one hour in that week. The supplying CAPCO Party will determine the demand charge for each transaction; plus 2.2 Capacity Charge Receiving Party shall pay the supplying Party a charge not to exceed the supplying Party's Out-of-Pocket Cost of providing operating capacity; plus a charge not to exceed $2.40 per MW-hr for operating capacity from a supplying Party's system; or plus a charge not to exceed $1.00 per MW-hr for operating capacity or purchased from a non-CAPCO party system. 2.3 Capacity and Energy Charge or Energy Only Charge Receiving Party shall pay the supplying Party a charge not to exceed the supplying Party's Out-of-Pocket Cost of providing operating capacity and energy; plus a charge not to exceed $2.40 per MWh for operating capacity and energy provided from the supplying Party's system; or plus a charge not to exceed $1.00 per MWh for operating capacity and energy purchased from a non-CAPCO party system. 45 2.4 Total Compensation Notwithstanding the rates stated in Subsections 2.1, 2.2 and 2.3 above for any CAPCO Party generating Non-Displacement Power, the sum of the demand, capacity and energy charges provided in such subsections for each reservation made pursuant to this Schedule C shall not be less than 100% of the total Out-of-Pocket Cost of supplying the Non-Displacement Energy for such reservation; plus any demand charges paid to a non-CAPCO party and provided additionally, however, that incremental or decremental transmission losses incurred on the system of any other Party resulting from the transmission of such energy shall be treated in accordance with Article 7. 46 CAPCO BASIC OPERATING AGREEMENT SCHEDULE D ECONOMY POWER Section 1 - Services to be Rendered 1.1 Economy Capacity Any Party may arrange to purchase from any other Party Economy Capacity whenever, in the sole judgment of the Party requested to provide the same, such Economy Capacity can be made available. Prior to its being made available, the amount of Economy Capacity to be provided, the period during which it is to be provided, and the charge therefor shall be determined by the Parties to the transaction. The charge agreed to shall not be subject to later review or adjustment. Economy Capacity may also be arranged to be obtained from or delivered to non-CAPCO party systems interconnected with a Party. 1.2 Economy Energy or Power Any Party may arrange to purchase from any other Party Economy Energy or Power whenever it is possible to effect a saving thereby and, in the sole judgment of the Party requested to supply the same, such Economy Energy or Power is available. Prior to each delivery of Economy Energy or Power, the amount and time of delivery and the charge therefor shall be determined by the Parties to the transaction. The charge agreed to shall not be subject to later review or adjustment. Economy Energy or Power may also be arranged to be obtained from or delivered to non-CAPCO party systems interconnected with a Party. 47 Section 2 - Discontinuance of Services 2.1 Service being provided under this Schedule may be discontinued at any time provided, however, that a Party making available Economy Capacity shall allow the other Party a reasonable opportunity to restore its own operating capacity or make other arrangements before discontinuing such Economy Capacity; and provided further that the receiving Party shall be obligated to pay to the supplying Party an amount not less than the Out-of- Pocket Cost of the supplying Party. Section 3 - Compensation 3.1 Economy Capacity The charge for Economy Capacity shall be based on the principle that the Party purchasing it shall pay the Out-of-Pocket Cost of providing it, and that the resulting savings to such Party shall be shared by the supplying and receiving Parties as determined by the supplying Party. When Economy Capacity is obtained from or delivered to non-CAPCO party systems inter- connected with a Party, payments shall be based on the Out-of-Pocket Cost of supplying the Economy Capacity and an allocation of the gross savings which are defined as the difference between (1) what the Out-of-Pocket Costs of the receiving Party or system would have been to supply such Economy Capacity, and (2) the Out-of-Pocket Cost of the supplying Party or system providing the Economy Capacity. Such allocation shall be made as provided in Subsections 3.11 and 3.12. 48 3.11 Each Party or system participating in the transaction other than the supplying and receiving Parties or systems, shall be paid (a) its cost of purchasing the Economy Operating Capacity supplied, plus an amount not to exceed (b) the greater of (i) 15% of the gross savings or (ii) the sum of a demand charge of $5.59 (however, the charge in any one day is not to exceed $89.40 times the maximum MW(s) reserved in any one hour of that day and the charge in that week not not to exceed $447 times the maximum MW(s) reserved in any one hour in that week) per MW reserved per hour plus $1.00 per MWh from a third party, plus any incremental costs or taxes incurred that would not otherwise have been incurred. In the event a Party or system participating in the transaction (other than the supplying and receiving Parties or systems) is to be compensated at a different amount of gross savings or demand charge under the terms and conditions of that Party's or system's interconnection agreement with a non-CAPCO party receiving the Power, then that Party or system shall be compensated at the rate specified in the interconnection agreement with the non-CAPCO party system receiving the Power. 3.12 The supplying Party or system shall be paid its Out-of-Pocket Cost of providing the Economy Capacity, plus a portion of the gross savings as determined by the supplying Party remaining after deducting payments made under Subsection 3.11 (b). The receiving Party or system shall be entitled to the remaining gross savings. 49 3.2 Economy Energy or Power The charge for Economy Energy or Power shall be based on the prin- ciple that the Party purchasing it shall pay the Out-of-Pocket Cost of pro- viding it and that the resulting savings to such Party shall be shared by the supplying and receiving Parties as determined by the supplying Party. When Economy Energy or Power is obtained from or delivered to non-CAPCO party systems interconnected with a Party, payments shall be based on the Out-of- Pocket Cost of supplying the Economy Energy or Power and an allocation of the gross savings which are defined as the difference between (1) what the Out-of-Pocket Costs of the receiving Party or system would have been to generate such Economy Energy or Power, and (2) the Out-of-Pocket Cost of the supplying Party or system providing the Economy Energy or Power. Such allocation shall be made as provided in Subsections 3.21 and 3.22. 3.21 Each Party or system participating in the transaction other than the supplying and receiving Parties or systems, shall be paid (a) its cost of purchasing the Economy Energy or Power supplied, plus (b) its cost of addi- tional transmission losses incurred, plus (c) an amount not to exceed the greater of (i) 15% of the gross savings remaining after deducting all such payments for transmission losses, if any or (ii) the sum of a demand charge of $5.59 (however, the charge in any one day is not to exceed $89.40 times the maximum MW(s) reserved in any one hour of that day and the charge in that week not not to exceed $447 times the maximum MW(s) reserved in any one hour in that week) per MW reserved per hour plus $1.00 per MWh from a third party, plus any incremental costs or taxes incurred that would not otherwise have been incurred. In the event a Party or system participating in the 50 transaction (other than the supplying and receiving Parties or systems) is to be compensated at a different amount of gross savings or demand charges under the terms and conditions of that Party's or system's interconnection agreement with a non-CAPCO party receiving the Power in the transaction, then that Party or system shall be compensated at the rate specified in the interconnection agreement with the non-CAPCO party system receiving the Power and provided additionally, however, that any incremental or decremental transmission losses incurred on the system of any other Party resulting from the transmission of such energy shall be treated in accordance with Article 7. 3.22 The supplying Party or system shall be paid its Out-of-Pocket Cost of providing the Economy Energy or Power, plus a portion of the gross savings remaining as determined by the supplying Party after deducting all payments made under Subsections 3.21 (b) and (c). The receiving Party or system shall be entitled to the remaining gross savings and provided additionally, however, that any incremental or decremental transmission losses incurred on the system of any other Party resulting from the transmission of such energy shall be treated in accordance with Article 7. 51 CAPCO BASIC OPERATING AGREEMENT SCHEDULE E UNIT POWER Availability This Schedule is available to a Party ("receiving Party") which has agreed with another Party ("supplying Party") to purchase for a specified period of time a specified amount of capacity out of the portion of a particular CAPCO Unit owned by the supplying Party. Section 1 - Services to be Rendered 1.1 The amount of capacity purchased by a receiving Party shall be expressed as a fraction of the Unit's Net Demonstrated Capability of which the numerator is the receiving Party's entitlement in MW as purchased and the denominator is the Unit's Net Demonstrated Capability in MW at the time of the purchase. Unless otherwise agreed by the Parties to the transaction, such fraction shall remain the same notwithstanding any redetermination of the Unit's Net Demonstrated Capability. The supplying Party shall be obligated to provide and the receiving Party shall be entitled to receive in any hour upon request by the receiving Party up to an amount of capacity and energy equal to the Unit's expected capability for that hour multiplied by such fraction. 1.2 In the event the receiving Party schedules less than its full entitlement, the balance of its entitlement shall remain as unloaded capacity available to it. 52 1.3 At any time when the Unit is operated at minimum net generation re- quired for safe operation of the Unit, each receiving Party shall be obligated to schedule an amount of energy equal to the Unit's minimum net safe genera- tion for the hour multiplied by the fraction determined in Subsection 1.1; provided that, if any Party having an entitlement shall schedule more than its percentage entitlement of such minimum net safe generation, the other Party or Parties shall be obligated to schedule an amount of energy not less than the balance of such minimum net safe generation in proportion to its percentage entitlement in the Unit. 1.4 The amount of capacity and energy scheduled under Subsections 1.1, 1.2 and 1.3 above, subject to adjustment for proportionate use of all plant auxiliary Power assignable to the operation of the Unit, and adjusted for a proportionate share of the generation step-up transformer losses if the metering is located at the low voltage terminals, shall constitute scheduled billing values (net) as of the Unit's generator transformer high voltage terminals. The supplying Party shall schedule for delivery from its system, an amount of energy equal to the energy billing value less the increase, or plus the decrease, as the case may be, in electrical losses, incurred on the system of the supplying Party resulting from the transmission of such energy. The receiving Party shall schedule for receipt into its system an equivalent amount of energy to that scheduled for delivery by the supplying Party. The losses incurred on the system of any Party other than the supplying or receiving Parties resulting from the transmission of such energy shall be banked. Any such other Party so affected shall schedule for delivery from its system the decrease in losses it incurred or shall schedule for receipt into its system the increase in losses it incurred in accordance with rules and 53 procedures established by the Operating Committee. Electrical losses shall be determined in accordance with rules and procedures established by the Operating Committee. Section 2 - Adjustments 2.1 If the supplying Party's records indicate that the receiving Party was entitled to schedule (or was obligated to schedule) values less than, or more than those determined pursuant to Section 1 above for any extended period of time, adjustments in future scheduling will be made by agreement of the Parties to the transactions to compensate for such differences. Section 3 - Auxiliary Power for Maintenance 3.1 During the period of the transaction, the receiving Party shall be obligated to the supplying Party for maintenance auxiliary energy. 3.2 The amount of maintenance auxiliary energy obligation shall be a figure in MWh equal to the total auxiliary Power used by the Unit's auxiliary equipment when the Unit is off for maintenance multiplied by the fraction determined pursuant to Subsection 1.1. 3.3 Such obligation for maintenance auxiliary energy shall be dis- charged by reimbursement to the operating Owner at the operating Owner's system average cost (including net purchase Power costs) for supplying net energy for load during the current calendar month, adjusted to exclude the output and cost during the current calendar month of the Unit to which such 54 maintenance auxiliary energy was supplied. In the event actual costs are not available, estimated costs will be used for the current month's calculations and an adjustment, based upon the deviation of estimated actual costs will be made in the next succeeding month. Section 4 - Compensation 4.1 The receiving Party shall compensate the supplying Party for Opera- tion and Maintenance costs, monthly, on a basis consistent with the method used to compensate the operating Owner by nonoperating Owners. 4.2 Additionally, the receiving Party shall pay the supplying Party, monthly, Fixed Charges which shall cover Return on Investment, Depreciation and Income Tax. In the event that a CAPCO Unit is placed in commercial operation at a capability which is not within a reasonable range of the expected Net Demon- strated Capability, a proportional amount of the capital costs of such Unit will be retained in FERC Account 107, Construction Work in Progress, and will continue to accrue allowance for funds used during construction. Such portion shall be excluded from the determination of Fixed Charges payable by the receiving Party. In the event that the final Net Demonstrated Capability of a Unit proves to be different from the original expected Net Demonstrated Capability, the remaining portion of the capital costs shall be transferred to FERC Account 101, Electric Plant In-Service, and all of the capital costs shall then be 55 included in the determination of Fixed Charges payable by the receiving Party. The operating Owner shall have the responsibility for determining the timing and level of the final Net Demonstrated Capability. In any event, the amount of investment in FERC Account 101, Electric Plant In-Service, shall be the basis for determining Fixed Charges to be paid. 4.3 The supplying Party shall also bill the receiving Party for its share of property, franchise, business or other taxes and insurance applicable to its share of the Unit, based on the fraction determined pursuant to Subsection 1.1 specifically identifying these items on the invoice. To the extent that such taxes and insurance are charged to the operating expenses of the Unit, because it is impractical or inequitable to segregate them, they will be billed as part of the normal operating expense of the Unit. 4.4 Specific charges applicable to each transaction under this Schedule from a particular Unit supplying the capacity and energy shall be set forth in appropriate Appendices to this Schedule, or in separate agreements to be attached to or referred to in appropriate Appendices to this Schedule. 56 APPENDICES TO SCHEDULE E TO THE CAPCO BASIC OPERATING AGREEMENT As Amended January 1, 1993 (1) APPENDIX 1 TO SCHEDULE E, which was filed as part of Exhibit 10b(3), 1992 Form 10-K, File Nos. 1-9130, 1-2323 and 1-3583, filed by Centerior Energy, Cleveland Electric and Toledo Edison, remains in full force and effect, except for SM-7 Pages 16-22, 19-22, 20-22 and 21-22, revised copies of which are filed herewith. (2) APPENDIX 2 TO SCHEDULE E has been revised from previous filings and is filed in full herewith. (3) APPENDIX 3 TO SCHEDULE E, which was filed as part of Exhibit 10.24, 1980 Form 10-K, File No. 1-956, filed by Duquesne, remains in full force and effect, except for MF-1 Pages 17-21, 18-21, 19-21 and 20-21, revised copies of which are filed herewith. (4) APPENDIX 4 TO SCHEDULE E, which was filed as part of Exhibit 10.24, 1980 Form 10-K, File No. 1-956, filed by Duquesne, remains in full force and effect, except for BV-1 Pages 20-25, 21-25, 22-25, 23-25 and 24-25, revised copies of which are filed herewith. (5) APPENDIX 5 TO SCHEDULE E, which was filed as part of Exhibit 10.24, 1980 Form 10-K, File No. 1-956, filed by Duquesne, remains in full force and effect, except for MF-2 Pages 17-21, 18-21, 19-21 and 20-21, revised copies of which are filed herewith. (6) APPENDIX 6 TO SCHEDULE E has been revised from previous filings and is filed in full herewith. (7) APPENDIX 7 TO SCHEDULE E, which was filed as part of Exhibit 10b(3), 1992 Form 10-K, File Nos. 1-9130, 1-2323 and 1-3583, filed by Centerior Energy, Cleveland Electric and Toledo Edison, remains in full force and effect, except for PY-1 Pages 11-18, 12-18, 13-18, 16-18 and 17-18, revised copies of which are filed herewith. (8) APPENDIX 8 TO SCHEDULE E has been revised from previous filings and is filed in full herewith. 57 APPENDIX 1 TO SCHEDULE E, which was filed as part of Exhibit 10b(3), 1992 Form 10-K, File Nos. 1-9130, 1-2323 and 1-3583, filed by Centerior Energy, Cleveland Electric and Toledo Edison, remains in full force and effect, except for SM-7 Pages 16-22, 19-22, 20-22 and 21-22, revised copies of which are filed herewith. 58 SM-7 (Page 16 of 22) CODE BASIS - (Cont'd) SY(IR) Coal Allocation Ratio The portion of the cost to charge to a Purchaser(s) during the current month shall be (a) the total tons of coal allocated to the Purchaser(s) for the preceding 12-month period determined as set forth in Section IV divided by (b) the tons of coal charged to OE for the Sammis Unit No. 7 for the same 12-month period. Section IV - Fuel In determining fuel costs the Purchaser(s) shall be treated in the same manner as an owner. The tons of coal and the costs thereof shall be allocated in proportion to the Btu's consumed to produce the kilowatt hours taken by each of those sharing in the output of the unit, taking into account the Btu's consumed during start-ups of the unit. OE's share of Btu's used during a start-up (including Btu's which may be supplied by transfers of steam from steam sources other than that unit's own steam source) and Btu's computed to have been used during periods of synchronized on-line operation of the unit to maintain zero load on the unit (the "Y" intercept, or no load input, of the standard Input/Output equation for the unit) shall be allocated among those sharing in the OE's share of the output of the unit in proportion to their investment responsibilities in the unit during the month for which allocation is being made. Btu's consumed during periods of synchronized on-line operation in excess of those used to maintain zero load on the unit (see preceding statement) shall be allocated each hour in proportion to the net kilowatt hours determined to have been taken from the unit by each of those sharing in the output of the unit. Section V - Other Expenses For billing costs to the Purchaser, labor and material additive costs at current rates prevailing in the industry as adjusted from time to time shall be added to the labor and material components of direct operation and maintenance costs of W. H. Sammis Unit No. 7 to which such rates are applicable and shall be shared by Purchasers on the same bases on which the primary labor and material costs are shared. In addition, an allocation will be made of Account 556, System Control and Load Dispatching costs related to production, and Account 557, Other Production Expenses. These costs would be allocated to W. H. Sammis Unit No. 7 on a direct basis where a direct relationship exists, or by using a net generating capability ratio (O(IR)) where a direct relationship does not exist. Account 556 will include only those load dispatching costs incurred by OE that are attributable to W. H. Sammis Unit No. 7. Included in Account 557, Other Production Expenses, are such items as insurance premiums and recoveries and other production expenses not directly assignable to the other production accounts. The invoice will identify amounts billed that were included in Account 557. 59 SM-7 (Page 19-22) Sales of Capacity and Energy from Base Load Units to Purchasers: W. H. Sammis Unit No. 7 Exhibit C - Reimbursement of Working Capital Costs I. Fuel (Coal and Oil) Inventory - Working capital cost applicable to a purchaser. Reimbursement by Monthly Carrying Charge in Lieu of Deposit The charge for a given month per megawatt of capacity purchased (or shared) shall be based on the Supplying Party's total dollar balance in Fuel (Coal and Oil) inventory at the end of the month in which service was rendered, and shall be calculated as follows: W. J. Sammis Unit No. 7 - The Product Of: (a) Total Dollars in Supplying Party's Fuel (Coal and Oil) Inventory at the Entire Plant (b) The Ratio of Total Megawatt Capacity Purchased (or Shared) to the Total Megawatts of Supplying Party's Plant Capacity. (c) One-Twelfth* of the Supplying Party's Current Annual Capital Cost Rate, augmented to Include Supplying Party's Income Tax Liability on the Equity Component. II. Monthly Operation & Maintenance Expenses - Working capital cost applicable to a purchaser or to a participant. Reimbursement by Monthly Carrying Charge in Lieu of Deposit The monthly charge shall be calculated each month for the Unit as the product of (a) and (b) for capacity owned and as the product of (a), (b) and (c) for capacity purchased. (a) The current month's direct operating expenses (Accounts 500-554, 556, 557, 562 and 570) for each Participant for the Unit, including overheads, less fuel and lease payments, and any other inappropriate items. (b) One-Twelfth* of the Operating Company's Current Annual Capital Cost Rate plus the Operating Company's income tax liability on the equity component. (c) The Purchaser's entitlement share of megawatt capacity in the Unit. *Fraction used to calculate working capital for purposes of this Exhibit 60 SM-7 (Page 20-22) III. Monthly Working Capital on M&S Inventory (Excluding Coal and Oil) - Working capital cost applicable to a purchaser or to a participant. Reimbursement by Monthly Carrying Charge in Lieu of Deposit The monthly charge shall be calculated each month for the Unit as a product of (a), (b), (c) and (d) for capacity purchased. (a) The Operating Company's balance in M&S Inventory (excluding coal and oil) at the plant. (b) The ratio of megawatt capacity owned is required for units in which the plant materials and operating supplies inventory is not owned by the CAPCO partners and shall be calculated as follows: A = C B Where: A= An owning Company's megawatt share in the unit. B= Total megawatt capacity of all units on site excluding short lead time capacity units. C= Ratio of an owning Company's portion of megawatt capacity owned. c) One-Twelfth* of the Operating Company's Current Annual Capital Cost Rate plus the Operating Company's income tax liability on the equity component. d) The Purchaser's entitlement share of megawatt capacity in the Unit. *Fraction used to calculate working capital for purposes of this Exhibit 61 SM-7 (Page 21 of 22) (BLANK) 62 APPENDIX 2 TO SCHEDULE E has been revised from previous filings and is filed in full herewith. 63 EL-5 (Page 1 of 13) APPENDIX 2 TO SCHEDULE E Charges Applicable to Transactions from Eastlake Unit No. 5 Pursuant to Schedule E This Appendix provides for specific charges applicable to transactions made from Eastlake Unit No. 5 pursuant to Schedule E. Costs will be shared on a basis equivalent to that of the joint owners with certain modifications specified herein. The following are the components of the costs to be included. A. Fixed Costs of Invested Capital 1. It is expected that sales out of production units will occur pre- dominantly over a relative short time period in the early part of the unit's life. However, this Appendix develops a consistent basis which is applicable throughout the life cycle. 2. Amortization and tax calculations are based on the following: Amortization Period - 35 Years (420 Months) DDB Tax Life 28 Years (336 Months) Estimated Salvage Rate -5% Accounting Treatment Flow-Through
3. DDB tax depreciation is assumed, with switch to straight line method effective the first month in which the straight line remaining life depreciation exceeds DDB depreciation, with remaining life stretched out in the straight line calculations to extend to the end of the book amortization period. The switch occurs at the end of the 221st month. 4. All fixed charges are on a month-to-month declining basis. The investment base from which fixed charges are developed shall be the CAPCO investment basis as defined in the Accounting and Procedure Manual under Procedures for Discharging Investment Responsibility. 5. The monthly finance charge rate applicable to all additions from the in-service date through the last month of the calendar year in which the construction job order is closed out shall be one-twelfth the specified annual rate. 6. The finance charge rate for ordinary additions in years subsequent to the calendar year in which the construction job order was closed out shall be the specified rate. 64 EL-5 (Page 2 of 13) 7. Amortization and other charges and adjustments shall be billed each month. Each month's additions to plant in-service shall constitute a vintage investment. However, in order to simplify the billing process, the monthly vintages of any particular calendar year may be combined into a composite vintage, either on an ongoing basis or at the end of the calendar year, providing the same billing results. Since finance charge rates are recalculated each year, vintages of different calendar years will not be composited. 8. The tax plant ratio to amortizable plant (CAPCO investment basis) shall be established from data for the total project as estimated at the in-service date, as described in Paragraph 5. This ratio will be used in developing fixed charge rates for the initial placements and all subsequent additions; except that in the case of major capital additions, at seller's option and with buyers' concurrence, a completely new vintage may be developed and the fixed charge factor recalculated using the new tax plant ratio and other pertinent data as appropriate. 9. When a production unit, or a major capital addition such as described in Paragraph 7, is placed in commercial service, the first fixed charge billing shall begin effective with the in-service date. For subsequent month-to-month additions, the billing shall begin with the first full calendar month after the addition is made. 10. Where sales are initiated out of an existing production facility to a new buyer, a single-vintage CAPCO investment basis may be calculated with an appropriate adjustment for depreciation incurred to date. The amortization component of the fixed charge factor will be calcu- lated on the basis of remaining life of the original amortization period or by mutual agreement. 11. The specific fixed charge rate for Eastlake Unit No. 5 is developed in Exhibit B. B. Operating and Maintenance Costs 1. The methods specified in the attached Exhibit A shall be used to allocate between the supplying Party and the receiving Party(s) or Purchaser(s) all costs, including overheads directly or indirectly applicable to the operation and maintenance of the supplying Party's participation in such unit. 2. The supplying Party will prepare, revise from time to time as appropriate and furnish to the Purchaser(s) an annual estimate of the amount to be billed by months (a) for the cost of energy during the term of the purchase from a unit, and (b) any other costs which shall accrue during this period. The supplying Party will furnish any reasonable request for estimates for longer periods if required by the Purchaser(s). 65 EL-5 (Page 3 of 13) 3. The supplying Party will maintain the records used in the deter- mination of the Purchaser(s) bill in order that the Purchaser(s) and their independent auditors shall have access at all reasonable times to such records and the supplying Party will furnish copies of such records as requested. The supplying Party shall preserve and maintain the originals of such records for at least such periods of time as the Purchaser(s) may request, having in mind the requirements of regulatory authorities having jurisdiction and the policies and practices of the parties with respect to the retention of records. 4. The cost of preparing, preserving and making copies of such budgets, records and accounts shall be borne by the companies in proportion to their respective capacity entitlements except that any costs incurred at the special request of the Purchaser(s) shall be borne by them. 5. The supplying Party shall have special audits conducted with respect to the matters provided for in this Appendix, either internally or by independent auditors, according to such programs and procedures as agreed to be necessary to conform to the auditing requirements of each company, and shall furnish copies of the reports of such audits to the Purchaser(s). The cost of making such audits, including any participation by the auditors of the Purchaser(s) agreed to be desirable and necessary, shall be shared by the companies in relation to the current capacity entitlement ratio. The Purchaser(s) may, at their own expense, make such further audits, using their internal or independent auditors or both, as it may be deemed desirable. 6. If requested by the Purchaser(s), the supplying Party will make such examinations, analyses or studies as needed to support the reason- ableness of the specific costs so allocated, or provide a basis for modification to achieve such reasonableness with respect to either the specific or the indirect cost allocations. Shareable costs which are incurred by the Purchaser(s) shall be accumulated and billed on a direct charge basis from specific records or reasonable estimates with applicable additives as agreed upon by the companies. 7. Except as otherwise provided herein, the accounting methods and practices normally in use at the time by each of the companies in determining and assigning operating and maintenance costs, generally, are to be used by such company for the purposes of this Appendix unless otherwise agreed, provided such methods and practices are consistent with sound accounting practices. 8. The supplying Party will bill the Purchaser(s) for its share of property, franchise, business or other taxes applicable to its share of the unit, specifically identifying these items on the invoice when such taxes are payable by the supplying Party. To the extent that such taxes are charged to the operating expenses of the Unit because it is impractical or inequitable to segregate them, they will be billed as part of the normal operating expense of the Unit. 66 EL-5 (Page 4 of 13) 9. As soon as possible after the close of each calendar month, prefer- ably on or before the 8th working day of the following month, the supplying Party shall advise the Purchaser(s) of its proportionate share of estimated operating expenses, fixed charges, displacement training costs and working capital for the preceding month. Any costs payable will be paid pursuant to Section 12.02 of the CAPCO Basic Operating Agreement, as amended. C. Working Capital It is recognized that the operating company undertakes certain obligations to provide expenditures in advance of compensation by the purchasers of capacity and energy. These purchases include, but may not be limited to, payroll, fuel and material and supplies purchases, and coal and material and supplies inventories. A reasonable allowance for this investment in working capital funds shall be considered a shareable cost to be compen- sated for as set out in detail in Exhibit C. D. Displacement Training Costs The CAPCO companies have agreed that the costs which an operating company will incur in training personnel at existing stations in order to be able to transfer experienced personnel to a new CAPCO generating unit should be shared by the joint owners. Purchasers of capacity and energy shall also share in these costs. 1. For each new CAPCO unit, the cost basis of $1/kW of the installed capacity is determined to be a reasonable estimate of the present-day cost which a company will incur within its existing plants as a result of assigning experienced company personnel to a new CAPCO generating unit. Installed capacity for this purpose is defined as the Net Demonstrated Capability of the CAPCO generating unit. 2. It is recognized that these costs will increase as labor costs increase. Therefore, this cost determination factor of $1/kW shall be subject to escalation for units planned to be in-service after Davis-Besse No. 1 based on an index of the composite labor costs of CAPCO companies as agreed to by the CAPCO Accounting and Finance Committee using 1972 as the base year equaling 100.0. The index to be applied shall be that calculated for the period two years prior to the actual in-service date for fossil-fired generating units and for the period three years prior to the actual in-service date for nuclear units. 3. The Purchasers of capacity and energy shall share in these costs for the periods they are involved. An amount of 1/420 of the cost basis for each kW of the purchasing company's capacity entitlement shall be included in the monthly billing. 4. The cost basis provided for herein shall be shown in Exhibit D. 67 EL-5 (Page 5 of 13) ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Eastlake Unit No. 5 EXHIBIT A Section I - Introduction This Exhibit pertains to all agreements related to the Sales of Capacity and Energy from the Owners of Eastlake Unit No. 5 to Purchasers. In the event any Purchaser does not schedule part or any of its generation entitlement share as stated in the applicable agreement, the balance of its entitlement shall remain as capacity available to the Purchaser, provided that, if the Unit is operated at minimum load required for safe operation of the Unit, the Purchaser shall be obligated to schedule an amount of energy equal to that Unit's minimum load for the hour, multiplied by a fraction of which the numerator is the Purchaser's entitlement under the applicable agreement and the denominator is the applicable Unit's Net Demonstrated Capability. The amount of energy determined above, subject to adjustment for proportionate use of all plant auxiliary power assignable to the operation of the Unit, shall constitute a scheduled (billing) MWH value (net) as of each Unit's generator transformer high voltage terminals. Each Participant shall schedule for delivery from the Unit, and each Purchaser shall schedule for receipt into its system, an amount of energy equal to such billing value less the increase, or plus the decrease, as the case may be, in electrical losses incurred on its system resulting from the transmission of such energy as determined by the Planning Committee under terms of the CAPCO Transmission Facilities Agreement. Section II - Accounting Concepts The basis for allocating the operation and maintenance costs of Eastlake Unit No. 5 between the joint Owners is set forth in Exhibit A of the Operating Agreement for this unit. This Exhibit prescribes the method of determining the portion of that cost of an Owner which will be billed to a Purchaser. The costs to be billed to a Purchaser will be segregated as to those that are directly identified with a Purchaser and to those that are allocated either on an investment responsibility or a fuel consumed basis. The codes for these segregations are defined at the end of Section III. In addition to the direct costs for operating and maintaining the Unit, an Owner shall bill a Purchaser for an appropriate portion of indirect overheads and taxes other than income taxes as defined in Section V. Section III - Allocation of Costs The operation and maintenance costs identified by FERC account number are assigned to a Purchaser either directly or on the basis of appropriate allocation codes as set forth in the following table. 68 EL-5 (Page 6 of 13) ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Eastlake Unit No. 5
Direct Owner's Costs to be Basis Allocated to the Purchaser Account to Allocation Codes Number Purchaser O(IR) SY(IR) OPERATION ACCOUNTS 500 Supervision and Engineering* X 501 Fuel: Cost of Fuel Consumed X 501 Fuel* X 501 Fuel: Other Costs X 502 Steam Expenses* X 505 Electric Expenses X 506 Misc. Steam Power Expenses* X MAINTENANCE ACCOUNTS 510 Supervision and Engineering* X 511 Structures* X 512 Boiler Plant X 512 Boiler Plant: Feedwater and X Accessory Steam Plant Equipment* 513 Electric Plant* X 514 Misc. Steam Plant X OTHER ACCOUNTS 556 System Control and Load X Dispatching (Power Supply) 557 Other Expenses (Power Supply) X 562 Transmission Station Expenses X (Step-Up Transformer and Connection to Switch Yard Only) 570 Maintenance of Station Equipment X (Step-Up Transformer and Connection to Switch Yard Only)
*Charges made to primary accounts (500, 501, 502, etc.) will include distribu- tions from clearing accounts for such costs as non-productive time and plant stores handling costs. Direct charges will be made to a Purchaser for fuel consumed as determined in accordance with Section IV. 69 ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Eastlake Unit No. 5 Code Basis O(IR) Investment Responsibility Ratio The portion of an Owner's operation and maintenance costs for the Unit to be billed to a Purchaser for the current month shall be a fraction of which the numerator is a Purchaser's entitlement from the Unit as specified in the applicable agreement and the denomi- nator is an Owner's interest in that Unit, both figures rounded to the nearest whole megawatt. An Owner's interest in the Unit shall be the product of the prevailing Net Demonstrated Capability (NDC) of the Unit multiplied by that Owner's net generation entitlement share in the Unit. If the capacity of the Unit is reduced by operating problems, a Purchaser will be entitled to his O(IR) ratio multiplied by the Owner's entitlement of the output of the Unit on an hour-to-hour basis. SY(IR) Coal Allocation Ratio The portion of an Owner's cost for the Unit to be billed to a Purchaser for the current month shall be a fraction of which the numerator is the total tons of coal allocated to the Purchaser for the preceding 12-month period, and the denominator is the tons of coal charged to the Owner during that same preceding 12-month period. Prior to the time that this data is available on a 12-month basis, available data will be used to determine the allocation ratio. Section IV - Fuel In determining fuel costs, a Purchaser shall be treated in the same manner as an Owner. The fuel cost shall be allocated in proportion to the Btu's consumed to produce the kilowatt-hours taken by each of those sharing in the output of the unit, taking into account the Btu's consumed during start-ups of the unit. Btu used during a start-up (including Btu which may be supplied by transfers of steam from steam sources other than that unit's own steam source) and Btu computed to have been used during periods of synchronized on-line operation of the unit to maintain zero load on the unit (the "Y" intercept, or no load input, of the standard Input/Output equation for the unit) shall be allocated among those sharing in the output of the unit in proportion to their investment responsibilities in the unit during the month for which the allocation is being made. Btu consumed during periods of synchronized on-line operation in excess of those used to maintain zero load on the unit (see preceding statement) shall be allocated each hour in proportion to the net kilowatt-hours determined to have been taken from the unit by each of those sharing in the output of the unit. 70 EL-5 (Page 8 of 13) ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Eastlake Unit No. 5 Section V - Other Expenses For billing costs to the Purchaser, labor and material additive costs at current rates prevailing in the industry as adjusted from time to time shall be added to the labor and material components of direct operation and maintenance costs of Eastlake Unit No. 5 to which such rates are applicable and shall be shared by Purchasers on the same bases on which the primary labor and material costs are shared. In addition, an allocation will be made of Account 556, System Control and Load Dispatching costs related to production, and Account 557, Other Production Expenses. These costs would be allocated to Eastlake Unit No. 5 on a direct basis where a direct relationship exists, or by using a net generating capability ratio (O(IR)) where a direct relationship does not exist. Account 556 will include only those load dispatching costs incurred by CEI that are attributable to Eastlake Unit No. 5. Included in Account 557, Other Production Expenses, are such items as insurance premiums and recoveries and other production expenses not directly assignable to the other production accounts. The invoice will identify amounts billed that were included in Account 557. For billing costs to Purchasers, labor fringe benefit additive costs shall be allocated to Eastlake Unit No. 5 on the basis of a rate representative of labor additive rates experienced by public utilities in the United States, as calculated from information contained in the U.S. Chamber of Commerce annual Employee Benefit Survey or in another mutually agreed upon source. The rate, expressed as a percent of total payroll cost, shall include the employer's share of employee benefit costs for legally required payments, retirement and savings plan payments, life insurance and death benefit payments, medical and medically related payments, and other miscellaneous benefit payments; but excluding benefits paid in the form of direct compensation to employees for time not worked such as paid rest periods, lunch or travel periods, holidays, vacations, sick time, parental leave and other similar payments. The rate produced in this manner is 31.3% for the billing year 1993 based on U.S. Chamber of Commerce survey data from benefit year 1991, and the rate for subsequent years will be computed annually based on the then most current U.S. Chamber of Commerce Survey data or other mutually agreed upon data available, and will become effective January 1 of each such subsequent year. The amount of labor additive costs to be allocated to each Purchaser during a given period shall be the product of the above rate multiplied by the direct labor expense allocated to the Purchaser for that period. 71 EL-5 (Page 9 of 13) ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Eastlake Unit No. 5 For billing costs to Purchasers, administrative and general (A&G) expense shall be allocated to Eastlake Unit No. 5 on the basis of a rate representative of A&G rates in the utility industry as calculated from information contained in the Utility Data Institute (UDI) compilation of utilities' FERC Form 1 data or in another mutually agreed upon source. The rate shall be equal to the ratio of: A. the sum of the base year of all amounts for all data base companies in FERC Accounts 920, 921 and 922, divided by B. the sum for the base year for the same companies of all amounts in FERC Accounts 500 through 916, minus the amounts representing fuel and purchase power expenses in FERC Accounts 501, 518, 547, 555 and 557. The rate produced by this calculation is 12.70% for the billing year 1993 based on UDI data from 1991, and the rate for subsequent years will be computed annually based on the then most current UDI or other mutually agreed upon data available and will become effective January 1 of each such subse- quent year. The amount of Administrative and General Expenses to be allocated to each Purchaser during a given period shall be the product of the above ratio multiplied by the total operation and maintenance expenses and labor additives excluding Account 501 allocated to the Purchaser for that period. In addition, a Purchaser shall pay to the Owner, at times payable by the Owner, amounts determined by multiplying (a) the property taxes and any other taxes except Federal Income Tax, payable by the Owner with respect to the Unit for the periods a Purchaser was involved by, (b) and O(IR) ratio for that period. 72 EL-5 (Page 10 of 13) EXHIBIT B FIXED COSTS OF INVESTED CAPITAL The monthly fixed charge for a vintage addition shall be calculated as the algebraic sum of the following components: A. Amortization(1) -- The product of (XX) multiplied by the ratio in Note (5). B. Finance Charge(2) -- The product of (AA) multiplied by the Seller's net unamortized investment base as of the beginning of the month being billed times the ratio in Note (5). C. Gross Income Tax(3) The product of (BB) multiplied by the net unamortized investment base as of the beginning of the month being billed. D. Income Tax Adjustment(4) The product of (.34/1-34)) times the difference between the amortization (Item A) less the tax depreciation. If the incremental federal tax rate is different from 34% in any month of such period, the factor used as the multiplier shall be adjusted to reflect such difference from 34%. NOTE: This adjustment may be a negative or positive value during the period of the contract. NOTES: (1) (XX) equals the sum of the Seller's investment base less land divided by 420 months. The Seller's adjusted investment base equals his total investment for Eastlake Unit No. 5 and Common Facilities as of the beginning of the month for which service is being billed. (2) The Seller's net unamortized adjusted investment base equals the adjusted investment base, less the accumulated amortization previously reflected in rates, less investment tax credit attributed to the adjusted investment base, less the net tax deduction associated with capitalized overheads attributable to the adjusted investment base. (AA) is the monthly finance charge rate, which equals 1/12 of the Seller's weighted cost of capital as defined in the CAPCO Accounting and Procedures Manual under Procedures for Discharging Investment Responsibility. 73 EL-5 (Page 11 of 13) EXHIBIT B FIXED COSTS OF INVESTED CAPITAL NOTES: (Cont'd) (3) (BB) is the monthly gross income tax charge rates applicable to 1987 and post-1987 billing periods. It is the product of 1/12 of the sum of the weighted costs of common equity, preferred equity and unamortized gain on the annual finance charge multiplied by the federal income tax rate divided by the complement of the income tax rate. The tax rate may be augmented to include state income taxes as defined in the CAPCO Accounting and Procedures Manual under Procedures for Discharging Invest- ment Responsibility, i.e., 1/12 x (Seller's Equity Component of Capital) x (Tax Rate/(1-Tax Rate)) (4) The income tax adjustment results from the difference between book amortization and tax depreciation, and from the agreement between the parties of the extent to which such difference should be recognized in the price paid. (5) The ratio shall be the Ratio of Total Megawatt Capacity Purchased (or Shared) to the Total Megawatts of Seller's Plant Capacity. 74 EL-5 (Page 12 of 13) EXHIBIT C REIMBURSEMENT OF WORKING CAPITAL COSTS I. Materials and Supplies Inventory - Working capital cost applicable to a purchaser. Reimbursement by Monthly Carrying Charge in Lieu of Deposit The charge for a given month per megawatt of capacity purchased (or shared) shall be based on the supplying Party's total dollar balance in M&S inventory at the end of the month in which service was rendered, and shall be calculated as follows: (a) Total Dollars in supplying Party's M&S Inventory at the Entire Plant (b) The Ratio of Total Megawatt Capacity Purchased (or Shared) to the Total Megawatts of supplying Party's Plant Capacity. (c) One-Twelfth* of the supplying Party's Current Annual Capital Cost Rate, augmented to Include supplying Party's Income Tax Liability on the Equity Component. *Fraction used to calculate working capital for purposes of this Exhibit. II. Monthly Operation & Maintenance Expenses - Working capital cost appli- cable to a purchaser or to an Owner. The monthly charge shall be calculated each month for the Unit as the product of (a) and (b) for capacity owned and as the product of (a), (b) and (c) for capacity purchased. (a) The current month's direct operating expenses (Accounts 500-554, 556, 557, 562 and 570) for each Owner for the Unit, including overheads, less fuel and lease payments, and any other inappropriate items. (b) One-Twelfth* of the Operating Company's Current Annual Capital Cost Rate plus the Operating Company's income tax liability on the equity component. (c) The Purchaser's entitlement share of megawatt capacity in the Unit. *Fraction used to calculate working capital for purposes of this Exhibit. 75 EL-5 (Page 13 of 13) EXHIBIT D DISPLACEMENT TRAINING COSTS Installed Capacity at Eastlake Unit No. 5 650,000 kW Generation Entitlement Share Cleveland Electric Illuminating Company 447,000 kW Duquesne Light Company 203,000 kW 650,000 kW The participants' respective shares of the displacement training costs, based on $1.00/kW, are: Cleveland Electric Illuminating Company $447,000 Duquesne Light Company $203,000
Therefore, under the terms of this Agreement, each purchaser will share in these costs, based on its entitlement at the rate of 1/420 of the cost basis, for each billing month beginning with the effective purchase date. 76 APPENDIX 3 TO SCHEDULE E, which was filed as part of Exhibit 10.24, 1980 Form 10-K, File No. 1-956, filed by Duquesne, remains in full force and effect, except for MF-1 Pages 17-21, 18-21, 19-21 and 20-21, revised copies of which are filed herewith. 77 MF-1 (Page 17 of 21) Section V - Other Expenses For billing costs to the Purchaser, labor and material additive costs at current rates prevailing in the industry as adjusted from time to time shall be added to the labor and material components of direct operation and maintenance costs of Bruce Mansfield Unit No. 1 to which such rates are applicable and shall be shared by Purchasers on the same bases on which the primary labor and material costs are shared. In addition, an allocation will be made of Account 556, System Control and Load Dispatching costs related to production, and Account 557, Other Production Expenses. These costs would be allocated to Bruce Mansfield Unit No. 1 on a direct basis where a direct relationship exists, or by using a net generating capacity ratio (O(IR)) where a direct relationship does not exist. Account 556 will include only those load dispatching costs incurred by PP that a reattributable to Bruce Mansfield Unit No. 1. Included in Account 557, Other Production Expenses, are such items as insurance premiums and recoveries and other production expenses not directly assignable to the other production accounts. The invoice will identify amounts billed that were included in Account 557. For billing costs to Purchasers, labor fringe benefit additive costs shall be allocated to Bruce Mansfield Unit No. 1 on the basis of a rate representative of labor additive rates experienced by public utilities in the United States, as calculated from information contained in the U.S. Chamber of Commerce annual Employee Benefit Survey or in another mutually agreed upon source. The rate, expressed as a percent of total payroll cost, shall include the employer's share of employee benefit costs for legally required payments, retirement and savings plan payments, life insurance and death benefit payments, medical and medically related payments, and other miscellaneous benefit payments; but excluding benefits paid in the form of direct compensation to employees for time not worked such as paid rest periods, lunch or travel periods, holidays, vacations, sick time, parental leave and other similar payments. The rate produced in this manner is 31.3% for the billing year 1993 based on U.S. Chamber of Commerce survey data from benefit year 1991, and the rate for subsequent years will be computed annually based on the then most current U.S. Chamber of Commerce Survey data or other mutually agreed upon data available, and will become effective January 1 of each such subsequent year. The amount of labor additive costs to be allocated to each Purchaser during a given period shall be the product of the above rate multiplied by the direct labor expense allocated to the Purchaser for that period. For billing costs to Purchasers, administrative and general (A&G) expense shall be allocated to Bruce Mansfield Unit No. 1 on the basis of a rate representative of A&G rates in the utility industry as calculated from information contained in the Utility Data Institute (UDI) compilation of utilities' FERC Form 1 data or in another mutually agreed upon source. The rate shall be equal to the ratio of: 78 MF-1 (Page 18 of 21) A. the sum of the base year of all amounts for all data base companies in FERC Accounts 920, 921 and 922, divided by B. the sum for the base year for the same companies of all amounts in FERC Accounts 500 through 916, minus the amounts representing fuel and purchase power expenses in FERC Accounts 501, 518, 547, 555 and 557. The rate produced by this calculation is 12.70% for the billing year 1993 based on UDI data from 1991, and the rate for subsequent years will be computed annually based on the then most current UDI or other mutually agreed upon data available and will become effective January 1 to each such subsequent year. The amount of Administrative and General expenses to be allocated to each Purchaser during a given period shall be the product of the above ratio multiplied by the total operation and maintenance expenses and labor additive excluding Account 501 allocated to the Purchaser for that period. In addition, a Purchaser shall pay to the Participant, at times payable by the Participant, amounts determined by multiplying (a) the property taxes and any other taxes except Federal Income Tax, payable by the Participant with respect to the Unit for the periods a Purchaser was involved by, (b) and O(IR) ratio for that period. 79 MF-1 (Page 19-21) Sales of Capacity and Energy from Base Load Units to Purchasers: B. Mansfield Unit No. 1 Exhibit C - Reimbursement of Working Capital Costs I. Fuel (Coal and Oil) and Material and Supplies Inventory - Working capital cost applicable to a purchaser. Reimbursement by Monthly Carrying Charge in Lieu of Deposit The charge for a given month per megawatt of capacity purchased (or shared) shall be based on the Supplying Party's total dollar balance in Fuel (Coal and Oil) and Material and Supplies Inventory at the end of the month in which service was rendered, and shall be calculated as follows: B. Mansfield Unit No. 1 - The Product Of: (a) Total Dollars in Supplying Party's Fuel (Coal and Oil) and Material and Supplies Inventory at the Entire Plant (b) The Ratio of Total Megawatt Capacity Purchased (or Shared) to the Total Megawatts of Supplying Party's Plant Capacity. (c) One-Twelfth* of the Supplying Party's Current Annual Capital Cost Rate, augmented to Include Supplying Party's Income Tax Liability on the Equity Component. II. Monthly Operation & Maintenance Expenses - Working capital cost appli- cable to a purchaser or to a participant. Reimbursement by Monthly Carrying Charge in Lieu of Deposit The monthly charge shall be calculated each month for the Unit as the product of (a) and (b) for capacity owned and as the product of (a), (b) and (c) for capacity purchased. (a) The current month's direct operating expenses (Accounts 500-554, 556, 57, 562 and 570) for each Participant for the Unit, including overheads, less fuel and lease pay- ments, and any other inappropriate items. (b) One-Twelfth* of the Operating Company's Current Annual Capital Cost Rate plus the Operating Company's income tax liability on the equity component. (c) The Purchaser's entitlement share of megawatt capacity in the Unit. *Fraction used to calculate working capital for purposes of this Exhibit 80 MF-1 (Page 20-21) (BLANK) 81 APPENDIX 4 TO SCHEDULE E, which was filed as part of Exhibit 10.24, 1980 Form 10-K, File No. 1-956, filed by Duquesne, remains in full force and effect, except for BV-1 Pages 20-25, 21-25, 22-25, 23-25 and 24-25, revised copies of which are filed herewith. 82 BV-1 (Page 20-25) C. Monthly payments not related to burnup made by Owners to the Lessor pertaining to the period after the beginning of commercial operation of the leased nuclear fuel shall be calculated as follows: MPLc = Rc (Cc) Where: MPLc = The current payments not related to burnup made by the Owners to the Lessor. Rc = The current lease rate as defined in the lease agreement expressed as the decimal equivalent of percent per month. Cc = The lessor's net investment (acquisition cost as defined in the lease agreement less burnup expenses prior to the current accounting month) at the beginning of the current accounting month. Section V - Other Expenses For billing costs to the Purchaser, labor and material additive costs at current rates prevailing in the industry as adjusted from time to time shall be added to the labor and material components of direct operation and maintenance costs of Beaver Valley Unit No. 1 to which such rates are applicable and shall be shared by Purchasers on the same bases on which the primary labor and material costs are shared. In addition, an allocation will be made of Account 556, System Control and Load Dispatching costs related to production, and Account 557, Other Production Expenses. These costs would be allocated to Beaver Valley Unit No. 1 on a direct basis where a direct relationship exists, or by using a net generating capacity ratio (O(IR)) where a direct relationship does not exist. Account 556 will include only those load dispatching costs incurred by DL that are attributable to Beaver Valley Unit No. 1. Included in Account 557, Other Production Expenses, are such items as insurance premiums and recoveries and other production expenses not directly assignable to the other production accounts. The invoice will identify amounts billed that were included in Account 557. For billing costs to Purchasers, labor fringe benefit additive costs shall be allocated to Beaver Valley Unit No. 1 on the basis of a rate representative of labor additive rates experienced by public utilities in the United States, as calculated from information contained in the U.S. Chamber of Commerce annual Employee Benefit Survey or in another mutually agreed upon source. The rate, expressed as a percent of total payroll cost, shall include the employer's share of employee benefit costs for legally required payments, retirement and savings plan payments, life insurance and death benefit payments, medical and medically related payments, and other miscellaneous benefit payments; but excluding 83 BV-1 (Page 21 of 25) benefits paid in the form of direct compensation to employees for time not worked such as paid rest periods, lunch or travel periods, holidays, vacations, sick time, parental leave and other similar payments. The rate produced in this manner is 31.3% for the billing year 1993 based on U.S. Chamber of Commerce survey data from benefit year 1991, and the rate for subsequent years will be computed annually based on the then most current U.S. Chamber of Commerce Survey data or other mutually agreed upon data available, and will become effective January 1 of each such subsequent year. The amount of labor additive costs to be allocated to each Purchaser during a given period shall be the product of the above rate multiplied by the direct labor expense allocated to the Purchaser for that period. For billing costs to Purchasers, administrative and general (A&G) expense shall be allocated to Beaver Valley Unit No. 1 on the basis of a rate representative of A&G rates in the utility industry as calculated from information contained in the Utility Data Institute (UDI) compilation of utilities' FERC Form 1 data or in another mutually agreed upon source. The rate shall be equal to the ratio of: A. the sum of the base year of all amounts for all data base companies in FERC Accounts 920, 921 and 922, divided by B. the sum for the base year for the same companies of all amounts in FERC Accounts 500 through 916, minus the amounts representing fuel and purchase power expenses in FERC Accounts 501, 518, 547, 555 and 557. The rate produced by this calculation is 12.70% for the billing year 1993 based on UDI data from 1991, and the rate for subsequent years will be computed annually based on the then most current UDI or other mutually agreed upon data available and will become effective January 1 of each such subsequent year. The amount of Administrative and General Expenses to be allocated to each Purchaser during a given period shall be the product of the above ratio multiplied by the total operation and maintenance expenses and labor additive excluding Account 501 allocated to the Purchaser for that period. In addition, a Purchaser shall pay to the Participant, at times payable by the Participant, amounts determined by multiplying (a) the property taxes and any other taxes except Federal Income Tax, payable by the Participant with respect to the Unit for the periods a Purchaser was involved by, (b) and O(IR) ratio for that period. 84 BV-1 (Page 22-25) (BLANK) 85 BV-1 (Page 23-25) EXHIBIT C REIMBURSEMENT OF WORKING CAPITAL COSTS I. Accumulated Deferred Fuel Expense - Working Capital Costs Applicable to a Purchaser of Capacity and Energy Reimbursement by Monthly Carrying Charge in Lieu of Deposit The charge for a given month per megawatt of capacity purchased shall be based on the Supplying Party's unamortized accumulated deferred expenses (not related to burnup) pertaining to the period prior to the beginning of commercial operation of the leased nuclear fuel per megawatt of capacity, to include the unamortized deferred depletion balance, if any, at the end of the month in which service was rendered and shall be calculated as follows: The Product of (a) (b) (c) (a) The Unamortized Accumulated Deferred Expenses (Not Related to Burnup) pertaining to the period prior to the beginning of Commercial Operation of the leased Nuclear Fuel to include the unamortized deferred depletion balance, if any. (b) The Ratio of Total Megawatt Capacity Purchased to the Supplying Party's Total Megawatt Capacity in Service. (c) One-Twelfth* of the Supplying Party's Current Annual Capital Cost Rate, plus the Supplying Party's income tax liability on the Equity Component. II. Materials and Supplies Inventory - Working capital cost applicable to a purchaser. Reimbursement by Monthly Carrying Charge in Lieu of Deposit The charge for a given month per megawatt of capacity purchased (or shared) shall be based on the Supplying Party's total dollar balance in M&S inventory at the end of the month in which service was rendered, and shall be calculated as follows: Beaver Valley Unit No. 1 - The Product Of: (a) Total Dollars in Supplying Party's M&S Inventory at the Entire Plant (b) The Ration of Total Megawatt Capacity Purchased (or Shared) to the Total Megawatts of Supplying Party's Plant Capacity. *FRACTION USED TO CALCULATE WORKING CAPITAL FOR PURPOSES OF THIS EXHIBIT. 86 BV-1 (Page 24-25) (c) One-twelfth* of the Supplying Party's Current Annual Capital Cost Rate, augmented to include Supplying Party's Income Tax Liability on the Equity Component. III. Monthly Operation & Maintenance Expenses - Working capital cost applicable to a purchaser or to a participant. The monthly charge shall be calculated each month for the Unit as the product of (a) and (b) for capacity owned and as the product of (a), (b) and (c) for capacity purchased. (a) The current monthly's direct operating expenses (Accounts 500- 554, 556, 557, 562 and 570) for each Participant for the Unit, including overheads, less fuel and lease payments, and any other inappropriate items. (b) One-Twelfth& of the Operating Company's Current Annual Capital Cost Rate plus the Operating Company's income tax liability on the equity component. (c) The Purchaser's entitlement share of megawatt capacity in the Unit. 87 APPENDIX 5 TO SCHEDULE E, which was filed as part of Exhibit 10.24, 1980 Form 10-K, File No. 1-956, filed by Duquesne, remains in full force and effect, except for MF-2 Pages 17-21, 18-21, 19-21 and 20-21, revised copies of which are filed herewith. 88 MF-2 (Page 17 of 21) Section V - Other Expenses For billing costs to the Purchaser, labor and material additive costs at current rates prevailing in the industry as adjusted from time to time shall be added to the labor and material components of direct operation and maintenance costs of Bruce Mansfield Unit No. 2 to which such rates are applicable and shall be shared by Purchasers on the same bases on which the primary labor and material costs are shared. In addition, an allocation will be made of Account 556, System Control and Load Dispatching costs related to production, and Account 557, Other Production Expenses. These costs would be allocated to Bruce Mansfield Unit No. 2 on a direct basis where a direct relationship exists, or by using a net generating capacity ratio (O(IR)) where a direct relationship does not exist. Account 556 will include only those load dispatching costs incurred by PP that a reattributable to Bruce Mansfield Unit No. 2. Included in Account 557, Other Production Expenses, are such items as insurance premiums and recoveries and other production expenses not directly assignable to the other production accounts. The invoice will identify amounts billed that were included in Account 557. For billing costs to Purchasers, labor fringe benefit additive costs shall be allocated to Bruce Mansfield Unit No. 2 on the basis of a rate representative of labor additive rates experienced by public utilities in the United States, as calculated from information contained in the U.S. Chamber of Commerce annual Employee Benefit Survey or in another mutually agreed upon source. The rate, expressed as a percent of total payroll cost, shall include the employer's share of employee benefit costs for legally required payments, retirement and savings plan payments, life insurance and death benefit payments, medical and medically related payments, and other miscellaneous benefit payments; but excluding benefits paid in the form of direct compensation to employees for time not worked such as paid rest periods, lunch or travel periods, holidays, vacations, sick time, parental leave and other similar payments. The rate produced in this manner is 31.3% for the billing year 1993 based on U.S. Chamber of Commerce survey data from benefit year 1991, and the rate for subsequent years will be computed annually based on the then most current U.S. Chamber of Commerce Survey data or other mutually agreed upon data available, and will become effective January 1 of each such subsequent year. The amount of labor additive costs to be allocated to each Purchaser during a given period shall be the product of the above rate multiplied by the direct labor expense allocated to the Purchaser for that period. For billing costs to Purchasers, administrative and general (A&G) expense shall be allocated to Bruce Mansfield Unit No. 2 on the basis of a rate representative of A&G rates in the utility industry as calculated from information contained in the Utility Data Institute (UDI) compilation of utilities' FERC Form 1 data or in another mutually agreed upon source. The rate shall be equal to the ratio of: 89 MF-2 (Page 18 of 21) A. the sum of the base year of all amounts for all data base companies in FERC Accounts 920, 921 and 922, divided by B. the sum for the base year for the same companies of all amounts in FERC Accounts 500 through 916, minus the amounts representing fuel and purchase power expenses in FERC Account 501, 518, 547, 555 and 557. The rate produced by this calculation is 12.70% for the billing year 1993 based on UDI data from 1991, and the rate for subsequent years will be computed annually based on the then most current UDI or other mutually agreed upon data available and will become effective January 1 of each such subsequent year. The amount of Administrative and General expenses to be allocated to each Purchaser during a given period shall be the product of the above ratio multiplied by the total operation and maintenance expenses and labor additives excluding Account 501 allocated to the Purchaser for that period. In addition, a Purchaser shall pay to the Participant, at times payable by the Participant, amounts determined by multiplying (a) the property taxes and any other taxes except Federal Income Tax, payable by the Participant with respect to the Unit for the periods a Purchaser was involved by, (b) and O(IR) ratio for that period. 90 MF-2 (Page 19-21) Sales of Capacity and Energy from Base Load Units to Purchasers: B. Mansfield Unit No. 2 Exhibit C - Reimbursement of Working Capital Costs I. Fuel (Coal and Oil) Inventory - Working capital cost applicable to a purchaser. Reimbursement by Monthly Carrying Charge in Lieu of Deposit The charge for a given month per megawatt of capacity purchased (or shared) shall be based on the Supplying Party's total dollar balance in Fuel (Coal and Oil) and Material and Supplies Inventory at the end of the month in which service was rendered, and shall be calculated as follows: B. Mansfield Unit No. 2 - The Product Of: (a) Total Dollars in Supplying Party's Fuel (Coal and Oil) and Material and Supplies Inventory at the Entire Plant (b) The Ratio of Total Megawatt Capacity Purchased (or Shared) to the Total Megawatts of Supplying Party's Plant Capacity. (c) One-Twelfth* of the Supplying Party's Current Annual Capital Cost Rate, augmented to Include Supplying Party's Income Tax Liability on the Equity Component. II. Monthly Operation & Maintenance Expenses - Working capital cost applicable to a purchaser or to a participant. Reimbursement by Monthly Carrying Charge in Lieu of Deposit The monthly charge shall be calculated each month for the Unit as the product of (a) and (b) for capacity owned and as the product of (a), (b) and (c) for capacity purchased. (a) The current month's direct operating expenses (Accounts 500-554, 556, 557, 562 and 570) for each Participant for the Unit, including overheads, less fuel and lease payments, and any other inappropriate items. (b) One-Twelfth* of the Operating Company's Current Annual Capital Cost Rate plus the Operating Company's income tax liability on the equity component. (c) The Purchaser's entitlement share of megawatt capacity in the Unit. *Fraction used to calculate working capital for purposes of this Exhibit 91 MF-2 (Page 20-21) (BLANK) 92 APPENDIX 6 TO SCHEDULE E has been revised from previous filings and is filed in full herewith. 93 DB-1 (Page 1 of 17) APPENDIX 6 TO SCHEDULE E Charges Applicable to Transactions from Davis-Besse Unit No. 1 Pursuant to Schedule E This Appendix provides for specific charges applicable to transactions made from Davis-Besse Unit No. 1 pursuant to Schedule E. Costs will be shared on a basis equivalent to that of the joint owners with certain modifications specified herein. The following are the components of the costs to be included. A. Fixed Costs of Invested Capital 1. It is expected that sales out of production units will occur pre- dominantly over a relative short time period in the early part of the unit's life. However, this Appendix develops a consistent basis which is applicable throughout the life cycle. 2. Amortization and tax calculations are based on the following: Amortization Period - 35 Years (420 Months) Plant DDB Tax Life 28 Years (336 Months) Estimated Salvage Rate -10% Accounting Treatment Flow-Through
3. DDB tax depreciation is assumed, with switch to straight line method effective the first month in which the straight line remaining life depreciation exceeds DDB depreciation, with remaining life stretched out in the straight line calculations to extend to the end of the book amortization period. The switch occurs at the end of the 221st month. 4. All fixed charges are on a month-to-month declining basis. The investment base from which fixed charges are developed shall be the CAPCO investment basis as defined in the Accounting and Procedure Manual under Procedures for Discharging Investment Responsibility. 5. The monthly finance charge rate applicable to all additions from the in-service date through the last month of the calendar year in which the construction job order is closed out shall be one-twelfth the specified annual rate. 6. The finance charge rate for ordinary additions in years subsequent to the calendar year in which the construction job order was closed out shall be the specified rate. 94 DB-1 (Page 2 of 17) 7. Amortization and other charges and adjustments shall be billed each month. Each month's additions to plant in-service shall constitute a vintage investment. However, in order to simplify the billing process, the monthly vintages of any particular calendar year may be combined into a composite vintage, either on an ongoing basis or at the end of the calendar year, providing the same billing results. Since finance charge rates are recalculated each year, vintages of different calendar years will not be composited. 8. The tax plant ratio to amortizable plant (CAPCO investment basis) shall be established from data for the total project as estimated at the in-service date, as described in Paragraph 5. This ratio will be used in developing fixed charge rates for the initial placements and all subsequent additions; except that in the case of major capital additions, at seller's option and with buyers' concurrence, a completely new vintage may be developed and the fixed charge factor recalculated using the new tax plant ratio and other pertinent data as appropriate. 9. When a production unit, or a major capital addition such as described in Paragraph 7, is placed in commercial service, the first fixed charge billing shall begin effective with the in-service date. For subsequent month-to-month additions, the billing shall begin with the first full calendar month after the addition is made. 10. Where sales are initiated out of an existing production facility to a new buyer, a single-vintage CAPCO investment basis may be calculated with an appropriate adjustment for depreciation incurred to date. The amortization component of the fixed charge factor will be calcu- lated on the basis of remaining life of the original amortization period or by mutual agreement. 11. The specific fixed charge rate for Davis-Besse Unit No. 1 is developed in Exhibit B. B. Operating and Maintenance Costs 1. The methods specified in the attached Exhibit A shall be used to allocate between the supplying Party and the receiving Party(s) or Purchaser(s) all costs, including overheads directly or indirectly applicable to the operation and maintenance of the supplying Party's participation in such unit. 2. The supplying Party will prepare, revise from time to time as appropriate and furnish to the Purchaser(s) an annual estimate of the amount to be billed by months (a) for the cost of energy during the term of the purchase from a unit, and (b) any other costs which shall accrue during this period. The supplying Party will furnish any reasonable request for estimates for longer periods if required by the Purchaser(s). 95 DB-1 (Page 3 of 17) 3. The supplying Party will maintain the records used in the deter- mination of the Purchaser(s) bill in order that the Purchaser(s) and their independent auditors shall have access at all reasonable times to such records and the supplying Party will furnish copies of such records as requested. The supplying Party shall preserve and maintain the originals of such records for at least such periods of time as the Purchaser(s) may request, having in mind the requirements of regulatory authorities having jurisdiction and the policies and practices of the parties with respect to the retention of records. 4. The cost of preparing, preserving and making copies of such budgets, records and accounts shall be borne by the companies in proportion to their respective capacity entitlements except that any costs incurred at the special request of the Purchaser(s) shall be borne by them. 5. The supplying Party shall have special audits conducted with respect to the matters provided for in this Appendix, either internally or by independent auditors, according to such programs and procedures as agreed to be necessary to conform to the auditing requirements of each company, and shall furnish copies of the reports of such audits to the Purchaser(s). The cost of making such audits, including any participation by the auditors of the Purchaser(s) agreed to be desirable and necessary, shall be shared by the companies in relation to the current capacity entitlement ratio. The Purchaser(s) may, at their own expense, make such further audits, using their internal or independent auditors or both, as it may be deemed desirable. 6. If requested by the Purchaser(s), the supplying Party will make such examinations, analyses or studies as needed to support the reason- ableness of the specific costs so allocated, or provide a basis for modification to achieve such reasonableness with respect to either the specific or the indirect cost allocations. Shareable costs which are incurred by the Purchaser(s) shall be accumulated and billed on a direct charge basis from specific records or reasonable estimates with applicable additives as agreed upon by the companies. 7. Except as otherwise provided herein, the accounting methods and practices normally in use at the time by each of the companies in determining and assigning operating and maintenance costs, generally, are to be used by such company for the purposes of this Appendix unless otherwise agreed, provided such methods and practices are consistent with sound accounting practices. 8. The supplying Party will bill the Purchaser(s) for its share of property, franchise, business or other taxes applicable to its share of the unit, specifically identifying these items on the invoice when such taxes are payable by the supplying Party. To the extent that such taxes are charged to the operating expenses of the Unit because it is impractical or inequitable to segregate them, they will be billed as part of the normal operating expense of the Unit. 96 DB-1 (Page 4 of 17) 9. As soon as possible after the close of each calendar month, prefer- ably on or before the 8th working day of the following month, the supplying Party shall advise the Purchaser(s) of its proportionate share of estimated operating expenses, fixed charges, displacement training costs and working capital for the preceding month. Any costs payable will be paid pursuant to Section 12.02 of the CAPCO Basic Operating Agreement, as amended. C. Working Capital It is recognized that the operating company undertakes certain obligations to provide expenditures in advance of compensation by the purchasers of capacity and energy. These purchases include, but may not be limited to, payroll, fuel and material and supplies purchases, and material and supplies inventories. A reasonable allowance for this investment in working capital funds shall be considered a shareable cost to be compen- sated for as set out in detail in Exhibit C. D. Displacement Training Costs The CAPCO companies have agreed that the costs which an operating company will incur in training personnel at existing stations in order to be able to transfer experienced personnel to a new CAPCO generating unit should be shared by the joint owners. Purchasers of capacity and energy shall also share in these costs. 1. For each new CAPCO unit, the cost basis of $1/kW of the installed capacity is determined to be a reasonable estimate of the present-day cost which a company will incur within its existing plants as a result of assigning experienced company personnel to a new CAPCO generating unit. Installed capacity for this purpose is defined as the Net Demonstrated Capability of the CAPCO generating unit. 2. It is recognized that these costs will increase as labor costs increase. Therefore, this cost determination factor of $1/kW shall be subject to escalation for units planned to be in-service after Davis-Besse No. 1 based on an index of the composite labor costs of CAPCO companies as agreed to by the CAPCO Accounting and Finance Committee using 1972 as the base year equaling 100.0. The index to be applied shall be that calculated for the period two years prior to the actual in-service date for fossil-fired generating units and for the period three years prior to the actual in-service date for nuclear units. 3. The Purchasers of capacity and energy shall share in these costs for the periods they are involved. An amount of 1/420 of the cost basis for each kW of the purchasing company's capacity entitlement shall be included in the monthly billing. 4. The cost basis provided for herein shall be shown in Exhibit D. 97 DB-1 (Page 5 of 17) ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Davis-Besse Station Unit No. 1 EXHIBIT A Section I - Introduction This Exhibit pertains to all agreements related to the Sales of Capacity and Energy from the Owners of Davis-Besse Unit No. 1 to Purchasers. In the event any Purchaser does not schedule part or any of its generation entitlement share as stated in the applicable agreement, the balance of its entitlement shall remain as capacity available to the Purchaser, provided that, if the Unit is operated at minimum load required for safe operation of the Unit, the Purchaser shall be obligated to schedule an amount of energy equal to that Unit's minimum load for the hour, multiplied by a fraction of which the numerator is the Purchaser's entitlement under the applicable agreement and the denominator is the applicable Unit's Net Demonstrated Capability. The amount of energy determined above, subject to adjustment for proportionate use of all plant auxiliary power assignable to the operation of the Unit, shall constitute a scheduled (billing) MWH value (net) as of each Unit's generator transformer high voltage terminals. Each Participant shall schedule for delivery from the Unit, and each Purchaser shall schedule for receipt into its system, an amount of energy equal to such billing value less the increase, or plus the decrease, as the case may be, in electrical losses incurred on its system resulting from the transmission of such energy as determined by the Planning Committee under terms of the CAPCO Transmission Facilities Agreement. Section II - Accounting Concepts The basis for allocating the operation and maintenance costs of Davis-Besse Unit No. 1 between the joint Owners is set forth in Exhibit A of the Operating Agreement for this unit. This Exhibit prescribes the method of determining the portion of that cost of an Owner which will be billed to a Purchaser. The costs to be billed to a Purchaser will be segregated as to those that are directly identified with a Purchaser and to those that are allocated either on an investment responsibility or a fuel consumed basis. The codes for these segregations are defined at the end of Section III. In addition to the direct costs for operating and maintaining the Unit, an Owner shall bill a Purchaser for an appropriate portion of indirect overheads and taxes other than income taxes as defined in Section V. Section III - Allocation of Costs The operation and maintenance costs identified by FERC account number are assigned to a Purchaser either directly or on the basis of appropriate allocation codes as set forth in the following table. 98 DB-1 (Page 6 of 17) ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Davis-Besse Station Unit No. 1
Direct Participants' Costs to be Basis Allocated to the Purchaser Account to Allocation Codes Number Purchaser O(IR) HY(IR) OPERATION ACCOUNTS 517 Supervision and Engineering X 518 Nuclear Fuel Expense X 519 Coolants and Water* X 519 Coolants and Water* X 520 Steam Expenses* X 520 Steam Expenses* X 523 Electric Expenses X 524 Misc. Nuclear Power Expenses X 525 Rents X MAINTENANCE ACCOUNTS 528 Supervision and Engineering X 529 Structures X 530 Reactor Plant and Equipment* X 530 Reactor Plant and Equipment* X 531 Electric Plant X 532 Misc. Nuclear Plant X OTHER ACCOUNTS 562 Operation - Station Expenses X 570 Maintenance of Station Equipment X
*See Exhibit A of the Davis-Besse Station Operating Agreement for breakdown of these accounts. Direct charges will be made to a Purchaser for fuel consumed as determined in accordance with Section IV. Code Basis O(IR) The portion of an Owner's operation and maintenance costs for the Unit to be billed to a Purchaser for the current month shall be a fraction of which the numerator is a Purchaser's entitlement from the Unit as specified in the applicable agreement and the denomi- nator is an Owner's interest in that Unit, both figures rounded to the nearest whole megawatt. An Owner's interest in the Unit shall be the product of the prevailing Net Demonstrated Capability (NDC) of the Unit multiplied by that Owner's net generation entitlement share in the Unit. 99 ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Davis-Besse Station Unit No. 1 Code Basis If the capacity of the Unit is reduced by operating problems, a Purchaser will be entitled to his O(IR) ratio multiplied by the Owner's entitlement of the output of the Unit on an hour-to-hour basis. HY(IR) The portion of an Owner's cost for the Unit to be billed to a Purchaser for the current month shall be a fraction of which the numerator is the portion of the BTU input to the main unit turbine used to produce the kilowatthours of energy taken from the Unit by the Purchaser during the preceding 12-month period and the denomi- nator is the portion of the BTU input to the main turbine used to produce the kilowatthours of energy taken from the Unit by the Owner during that same preceding 12-month period. Prior to the time that this data is available on a 12-month basis, available data will be used to determine the allocation ratio. Section IV - Fuel In determining fuel costs, a Purchaser shall be treated in the same manner as an Owner. The following basic principles shall govern the calculation of depletion (amortization) of fuel assemblies installed in the reactor for heat production and the billing of fuel costs to Purchasers. 1. Nuclear fuel assemblies shall be considered to be producing heat only during periods of zero or positive net generation. 2. During periods of negative net generation, it will be considered that installed nuclear fuel assemblies are not producing heat and are not thus consumed. During periods of negative net generation, records of station service electric energy supplied by the system shall be maintained and the participants in the Unit shall be invoiced for such electric energy in proportion to their investment responsibilities in the Unit as the operating Owner's system average production cost (including net purchased power costs) during the current calendar month adjusted to exclude the output and cost during the current calendar month of the Unit to which such station service energy was supplied. 3. During periods of zero or positive net generation, the components of consumption of heat from nuclear fuel assemblies shall be considered to consist of a fixed heat consumption component and a variable heat consumption component. The components of heat consumption are illustrated by the current turbine-generator heat consumption curve for the Unit as agreed to by the Owners. The fixed portion of heat consumption consists of the heat produced by the reactor required to supply station service electric energy plus heat losses in the plant. 100 DB-1 (Page 8 of 17) ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Davis-Besse Station Unit No. 1 4. During periods of zero or positive net generation, the fixed and variable portions of the total Unit heat consumption shall be calculated on an hour-by-hour basis. The fixed portion of the Unit heat consumption shall be the product of service hours accumulated during periods of zero or positive net generation times the fixed unit heat consumption as indicated on the current turbine-generator heat consumption curve for the Unit as agreed to by the Owners. The variable portion of the Unit heat consumption shall be the total net main unit generation in MWe hr/hr converted to BTU/hr excluding the fixed unit heat consumption utilizing the relationship between MWe hr/hr versus BTU/hr as represented on the current turbine-generator heat consumption curve for each Unit as agreed to by the Owners. The total unit heat consumption shall be the sum of fixed and variable portions of the unit heat consumption. 5. In calculations for determining the cost of nuclear fuel consumed, Toledo Edison Company shall take into account the original acquisition cost of the materials and services required to provide the fuel as originally installed, and predicted total heat output of the assemblies and the estimated net value of salvage materials. TE shall calculate such cost of nuclear fuel consumed using methods and/or computer codes generally considered acceptable by the CAPCO Companies for this purpose. 6. For owned nuclear fuel, the total monthly nuclear fuel expense for the Purchaser shall be determined by the formula FCc = Ec (Ac - Sf) --------- Ef where: FCc = Nuclear Fuel expense during the current accounting month. Ec = The energy received by the Purchaser during the current accounting month. Ef = The energy expected to be produced from the fuel component. Fuel component can be a fuel assembly, sub-region, region or entire core. Ac = The Owner's current net costs. Sf = Anticipated salvage value of the fuel with related deductions including, but not limited to, shipping, reprocessing and waste disposal costs. When the Owner adjusts its Ac, Sf and Ef factors, these same factors will be adjusted in a similar manner for the Purchaser. 101 DB-1 (Page 9 of 17) ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Davis-Besse Station Unit No. 1 7. For leased nuclear fuel, the total monthly nuclear fuel expense for the Purchaser is composed of a) a burnup expense related to energy resource consumption, b) amortization of accumulated deferred expenses not related to burnup pertaining to the period prior to the beginning of commercial operation of the leased nuclear fuel, and c) monthly payments not related to burnup made by the Owners to the Lessor pertaining to the period after the beginning of commercial operation of the leased nuclear fuel. A. The monthly burnup expense shall be calculated as follows: Bc = Ec (Cc - Sf) --------- Ef where: Bc = Burnup expense for the current accounting month. Ec = The energy received by the Purchaser during the current accounting month. Ef = The energy expected to be produced from the fuel component. Fuel component can be a fuel assembly, sub-region or entire core. Cc = The Lessor's current net costs. Sf = Anticipated salvage value of the fuel with related deductions including, but not limited to, shipping, reprocessing and waste disposal costs. B. The amortization of accumulated deferred expenses not related to burnup pertaining to the period prior to the beginning of commercial operation of the leased nuclear fuel shall be calculated as follows: PDAc = Ec (Dp) ---- Ef where: PDAc = The current month amortization of deferred expenses not related to burnup pertaining to the period prior to the beginning of commercial operation of the leased nuclear fuel. Ec = The energy received by the Purchaser during the current accounting month. Ef = The energy expected to be produced from the fuel component. 102 DB-1 (Page 10 of 17) ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Davis-Besse Unit No. 1 Dp = The unamortized portion at the beginning of the current accounting month of the deferred expense not related to burnup pertaining to the period prior to the beginning of commercial operation of the leased nuclear fuel. C. Monthly payments not related to burnup made by Owners to the Lessor pertaining to the period after the beginning of commercial operation of the leased nuclear fuel billable to the Purchaser shall be calculated as follows: MPLc = Rc (Cc) (O(IR)) where: MPLc = The current payments not related to burnup made by the Owner to the Lessor. Rc = The current lease rate as defined in the lease agreement expressed as the decimal equivalent of percent month. Cc = The Lessor's current net costs. O(IR) As defined in Section III. Section V - Other Expenses For billing costs to the Purchaser, labor and material additive costs at current rates prevailing in the industry as adjusted from time to time shall be added to the labor and material components of direct operation and maintenance costs of Davis-Besse Unit No. 1 to which such rates are applicable and shall be shared by Purchasers on the same bases on which the primary labor and material costs are shared. In addition, an allocation will be made of Account 556, System Control and Load Dispatching costs related to production, and Account 557, Other Production Expenses. These costs would be allocated to Davis-Besse Unit No. 1 on a direct basis where a direct relationship exists, or by using a net generating capability ratio (O(IR)) where a direct relationship does not exist. Account 556 will include only those load dispatching costs incurred by TE that are attributable to Davis-Besse Unit No. 1. Included in Account 557, Other Production Expenses, are such items as insurance premiums and recoveries and other production expenses not directly assignable to the other production accounts. The invoice will identify amounts billed that were included in Account 557. 103 DB-1 (Page 11 of 17) ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Davis-Besse Station Unit No. 1 For billing costs to Purchasers, labor fringe benefit additive costs shall be allocated to Davis-Besse Unit No. 1 on the basis of a rate representative of labor additive rates experienced by public utilities in the United States, as calculated from information contained in the U.S. Chamber of Commerce annual Employee Benefit Survey or in another mutually agreed upon source. The rate, expressed as a percent of total payroll cost, shall include the employer's share of employee benefit costs for legally required payments, retirement and savings plan payments, life insurance and death benefit payments, medical and medically related payments, and other miscellaneous benefit payments; but excluding benefits paid in the form of direct compensation to employees for time not worked such as paid rest periods, lunch or travel periods, holidays, vacations, sick time, parental leave and other similar payments. The rate produced in this manner is 31.3% for the billing year 1993 based on U.S. Chamber of Commerce survey data from benefit year 1991, and the rate for subsequent years will be computed annually based on the then most current U.S. Chamber of Commerce Survey data or other mutually agreed upon data available, and will become effective January 1 of each such subsequent year. The amount of labor additive costs to be allocated to each Purchaser during a given period shall be the product of the above rate multiplied by the direct labor expense allocated to the Purchaser for that period. For billing costs to Purchasers, administrative and general (A&G) expense shall be allocated to Davis-Besse Unit No. 1 on the basis of a rate representative of A&G rates in the utility industry as calculated from information contained in the Utility Data Institute (UDI) compilation of utilities' FERC Form 1 data or in another mutually agreed upon source. The rate shall be equal to the ratio of: A. the sum of the base year of all amounts for all data base companies in FERC Accounts 920, 921 and 922, divided by B. the sum for the base year for the same companies of all amounts in FERC Accounts 500 through 916, minus the amounts representing fuel and purchase power expenses in FERC Accounts 501, 518, 547, 555 and 557. The rate produced by this calculation is 12.70% for the billing year 1993 based on UDI data from 1991, and the rate for subsequent years will be computed annually based on the then most current UDI or other mutually agreed upon data available and will become effective January 1 of each such subse- quent year. The amount of Administrative and General Expenses to be allocated to each Purchaser during a given period shall be the product of the above ratio multiplied by the total operation and maintenance expenses and labor additives excluding Account 518 allocated to the Purchaser for that period. 104 DB-1 (Page 12 of 17) ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Davis-Besse Station Unit No. 1 In addition, a Purchaser shall pay to the Owner, at times payable by the Owner, amounts determined by multiplying (a) the property taxes and any other taxes except Federal Income Tax, payable by the Owner with respect to the Unit for the periods a Purchaser was involved by, (b) and O(IR) ratio for that period. 105 EXHIBIT B FIXED COSTS OF INVESTED CAPITAL The monthly fixed charge for a vintage addition shall be calculated as the algebraic sum of the following components: A. Amortization(1) -- The product of (XX) multiplied by the ratio in Note (5). B. Finance Charge(2) -- The product of (AA) multiplied by the Seller's net unamortized investment base as of the beginning of the month being billed times the ratio in Note (5). C. Gross Income Tax(3) (i) For billing months after 1987, the product of (BB) multiplied by the net unamortized investment base as of the beginning of the month being billed. If the incremental federal tax rate is different from 34% in any month of such period, the factor used as the multiplier shall be adjusted to reflect such difference from 34%. D. Income Tax Adjustment(4) For billing months after 1987, the product of (.34/1-34)) times the difference between the amortization (Item A) less the tax depreciation. If the incremental federal tax rate is different from 34% in any month of such period, the factor used as the multiplier shall be adjusted to reflect such difference from 34%. NOTE: This adjustment may be a negative or positive value during the period of the contract. NOTES: (1) (XX) equals the sum of the Seller's investment base less land divided by 420 months. The Seller's adjusted investment base equals his total investment for Beaver Valley Unit No. 2 and Common Facilities as of the beginning of the month for which service is being billed. (2) The Seller's net unamortized adjusted investment base equals the adjusted investment base, less the accumulated amortization previously reflected in rates, less investment tax credit attributed to the adjusted investment base, less the net tax deduction associated with capitalized overheads attributable to the adjusted investment base. (AA) is the monthly finance charge rate, which equals 1/12 of the Seller's weighted cost of capital as defined in the CAPCO Accounting and Procedures Manual under Procedures for Discharging Investment Responsibility. 106 DB-1 (Page 14 of 17) EXHIBIT B FIXED COSTS OF INVESTED CAPITAL NOTES: (Cont'd) (3) (BB) is the monthly gross income tax charge rates applicable to 1987 and post-1987 billing periods. It is the product of 1/12 of the sum of the weighted costs of common equity, preferred equity and unamortized gain on the annual finance charge multiplied by the federal income tax rate divided by the complement of the income tax rate. The tax rate may be augmented to include state income taxes as defined in the CAPCO Accounting and Procedures Manual under Procedures for Discharging Invest- ment Responsibility, i.e., 1/12 x (Seller's Equity Component of Capital) x (Tax Rate/(1-Tax Rate)) (4) The income tax adjustment results from the difference between book amortization and tax depreciation, and from the agreement between the parties of the extent to which such difference should be recognized in the price paid. (5) The ratio shall be the Ratio of Total Megawatt Capacity Purchased (or Shared) to the Total Megawatts of Seller's Plant Capacity. 107 EXHIBIT C REIMBURSEMENT OF WORKING CAPITAL COSTS I. Accumulated Deferred Fuel Expense - Working Capital Costs Applicable to a Purchaser of Capacity and Energy Reimbursement by Monthly Carrying Charge in Lieu of Deposit The charge for a given month per megawatt of capacity purchased shall be based on the supplying Party's unamortized accumulated deferred expenses (not related to burnup) pertaining to the period prior to the the beginning of commercial operation of the leased nuclear fuel per megawatt of capacity, to include the unamortized deferred depletion balance, if any, at the end of the month in which service was rendered and shall be calculated as follows: The Product of (a) (b) (c) (a) The Unamortized Accumulated Deferred Expenses (Not Related to Burnup) pertaining to the period prior to the beginning of Commercial Operation of the leased Nuclear Fuel to include the unamortized deferred depletion balance, if any. (b) The Ratio of Total Megawatt Capacity Purchased to the supplying Party's Total Megawatt Capacity in Service. (c) One-Twelfth* of the supplying Party's Current Annual Capital Cost Rate, plus the supplying Party's income tax liability on the Equity Component. II. Materials and Supplies Inventory - Working capital cost applicable to a purchaser. Reimbursement by Monthly Carrying Charge in Lieu of Deposit The charge for a given month per megawatt of capacity purchased (or shared) shall be based on the supplying Party's total dollar balance in M&S inventory at the end of the month in which service was rendered, and shall be calculated as follows: (a) Total Dollars in supplying Party's M&S Inventory at the Entire Plant (b) The Ratio of Total Megawatt Capacity Purchased (or Shared) to the Total Megawatts of supplying Party's Plant Capacity. (c) One-Twelfth* of the supplying Party's Current Annual Capital Cost Rate, augmented to Include supplying Party's Income Tax Liability on the Equity Component. *Fraction used to calculate working capital for purposes of this Exhibit. 108 DB-1 (Page 16 of 17) EXHIBIT C REIMBURSEMENT OF WORKING CAPITAL COSTS III. Monthly Operation & Maintenance Expenses - Working capital cost appli- cable to a purchaser or to an Owner. The monthly charge shall be calculated each month for the Unit as the product of (a) and (b) for capacity owned and as the product of (a), (b) and (c) for capacity purchased. (a) The current month's direct operating expenses (Accounts 500-554, 556, 557, 562 and 570) for each Owner for the Unit, including overheads, less fuel and lease payments, and any other inappropriate items. (b) One-Twelfth* of the Operating Company's Current Annual Capital Cost Rate plus the Operating Company's income tax liability on the equity component. (c) The Purchaser's entitlement share of megawatt capacity in the Unit. *Fraction used to calculate working capital for purposes of this Exhibit. 109 DB-1 (Page 17 of 17) EXHIBIT D DISPLACEMENT TRAINING COSTS Installed Capacity at Davis-Besse Station No. 1 906,000 kW Generation Entitlement Share Cleveland Electric Illuminating Company 51.38% Toledo Edison Company 48.62% 100.00% The participants' respective shares of the displacement training costs, based on $1.00/kW, are: Cleveland Electric Illuminating Company $465,500 Toledo Edison Company $440,500
Therefore, under the terms of this Agreement, each purchaser will share in these costs, based on its entitlement at the rate of 1/420 of the cost basis, for each billing month beginning with the effective purchase date. 110 APPENDIX 7 TO SCHEDULE E, which was filed as part of Exhibit 10b(3), 1992 Form 10-K, File Nos. 1-9130, 1-2323 and 1-3583, filed by Centerior Energy, Cleveland Electric and Toledo Edison, remains in full force and effect, except for PY-1 Pages 11-18, 12-18, 13-18, 16-18 and 17-18, revised copies of which are filed herewith. 111 PY-1 (Page 11-18) ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Perry Plant Unit No. 1 Dp = The unamortized portion at the beginning of the current accounting month of the deferred expense not related to burnup pertaining to the period prior to the beginning of commercial operation of the leased nuclear fuel. C. Monthly payments not related to burnup made by Participants to the Lessor pertaining to the period after the beginning of commercial operation of the leased nuclear fuel billable to the Purchaser shall be calculated as follows: MPLc = Rc(Cc)(O(IR)) Where: MPLc = The current payments not related to burnup made by the Participant to the Lessor. Rc = The current lease rate as defined in the lease agreement expressed as the decimal equivalent of percent per month. Cc = The Lessor's current net costs. O(IR) As defined in Section III. Section V - Other Expenses For billing costs to the Purchaser, labor and material additive costs at current rates prevailing in the industry as adjusted from time to time shall be added to the labor and material components of direct operation and maintenance costs of Perry Unit No. 1 to which such rates are applicable and shall be shared by Purchasers on the same bases on which the primary labor and material costs are shared. In addition, an allocation will be made of Account 556, System Control and Load Dispatching costs related to production, and Account 557, Other Production Expenses. These costs would be allocated to Perry Unit No. 1 on a direct basis where a direct relationship exists, or by using a net generating capability ratio (O(IR)) where a direct relationship does not exist. Account 556 will include only those load dispatching costs incurred by CEI that are attributable to Perry Unit No. 1. Included in Account 557, Other Production Expenses, are such items as insurance premiums and recoveries and other production expenses not directly assignable to the other production accounts. The invoice will identify amounts billed that were included in Account 557. For billing costs to Purchasers, labor fringe benefit additive costs shall be allocated to Perry Unit No. 1 on the basis of a rate representative of labor additive rates experienced by public utilities in the United States, as calculated from information contained in the U.S. Chamber of Commerce annual Employee Benefit Survey or in another mutually agreed upon source. 112 PY-1 (Page 12 of 18) ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Perry Plant Unit No. 1 The rate, expressed as a percent of total payroll cost, shall include the employer's share of employee benefit costs for legally required payments, retirement and savings plan payments, life insurance and death benefit payments, medical and medically related payments, and other miscellaneous benefit payments; but excluding benefits paid in the form of direct compensation to employees for time not worked such as paid rest periods, lunch or travel periods, holidays, vacations, sick time, parental leave and other similar payments. The rate produced in this manner is 31.3% for the billing year 1993 based on U.S. Chamber of Commerce survey data from benefit year 1991, and the rate for subsequent years will be computed annually based on the then most current U.S. Chamber of Commerce Survey data or other mutually agreed upon data available, and will become effective January 1 of each such subsequent year. The amount of labor additive costs to be allocated to each Purchaser during a given period shall be the product of the above rate multiplied by the direct labor expense allocated to the Purchaser for that period. For billing costs to Purchasers, administrative and general (A&G) expense shall be allocated to Perry Unit No. 1 on the basis of a rate representative of A&G rates in the utility industry as calculated from information contained in the Utility Data Institute (UDI) compilation of utilities' FERC Form 1 data or in another mutually agreed upon source. The rate shall be equal to the ratio of: A. the sum of the base year of all amounts for all data base companies in FERC Accounts 920, 921 and 922, divided by B. the sum for the base year for the same companies of all amounts in FERC Accounts 500 through 916, minus the amounts representing fuel and purchase power expenses in FERC Accounts 501, 518, 547, 555 and 557. The rate produced by this calculation is 12.70% for the billing year 1993 based on UDI data from 1991, and the rate for subsequent years will be computed annually based on the then most current UDI or other mutually agreed upon data available and will become effective January 1 of each such subsequent year. The amount of Administrative and General Expenses to be allocated to each Purchaser during a given period shall be the product of the above ratio multiplied by the total operation and maintenance expenses and labor additives excluding Account 501 allocated to the Purchaser for that period. In addition, a Purchaser shall pay to the Participant, at times payable by the Participant, amounts determined by multiplying (a) the property taxes and any other taxes except Federal Income Tax, payable by the Participant with respect to the Unit for the periods a Purchaser was involved by, (b) and O(IR) ratio for that period. 113 PY-1 (Page 13 of 18) (BLANK) 114 PY-1 (Page 16-18) EXHIBIT C REIMBURSEMENT OF WORKING CAPITAL COSTS I. Accumulated Deferred Fuel Expense - Working Capital Costs Applicable to a Purchaser of Capacity and Energy Reimbursement by Monthly Carrying Charge in Lieu of Deposit The charge for a given month per megawatt of capacity purchased shall be based on the Supplying Party's unamortized accumulated deferred expenses (not related to burnup) pertaining to the period prior to the beginning of commercial operation of the leased nuclear fuel per megawatt of capacity, to include the unamortized deferred depletion balance, if any, at the end of the month in which service was rendered and shall be calculated as follows: The Product of (a) (b) (c) (a) The Unamortized Accumulated Deferred Expenses (Not Related to Burnup) pertaining to the period prior to the beginning of Commercial Operation of the leased Nuclear Fuel to include the unamortized deferred depletion balance, if any. (b) The Ratio of Total Megawatt Capacity Purchased to the Supplying Party's Total Megawatt Capacity in Service. (c) One-Twelfth* of the Supplying Party's Current Annual Capital Cost Rate, plus the Supplying Party's income tax liability on the Equity Component. II. Materials and Supplies Inventory - Working capital cost applicable to a purchaser. Reimbursement by Monthly Carrying Charge in Lieu of Deposit The charge for a given month per megawatt of capacity purchased (or shared) shall be based on the Supplying Party's total dollar balance in M&S inventory at the end of the month in which service was rendered, and shall be calculated as follows: Perry Unit No. 1 - The Product Of: (a) Total Dollars in Supplying Party's M&S Inventory at the Entire Plant (b) The Ratio of Total Megawatt Capacity Purchased (or Shared) to the Total Megawatts of Supplying Party's Plant Capacity. *FRACTION USED TO CALCULATE WORKING CAPITAL FOR PURPOSES OF THIS EXHIBIT. 115 PY-1 (Page 17-18) (c) One-twelfth* of the Supplying Party's current Annual Capital Cost Rate, augmented to include Supplying Party's Income Tax Liability on the Equity Component. III. Monthly Operation & Maintenance Expenses - Working capital cost applicable to a purchaser or to a participant. The monthly charge shall be calculated each month for the Unit as the product of (a) and (b) for capacity owned and as the product of (a), (b) and (c) for capacity purchased. (a) The current monthly's direct operating expenses (Accounts 500- 554, 556, 557, 562 and 570) for each Participant for the Unit, including overheads, less fuel and lease payments, and any other inappropriate items. (b) One-Twelfth* of the Operating Company's Current Annual Capital Cost Rate plus the Operating Company's income tax liability on the equity component. (c) The Purchaser's entitlement share of megawatt capacity in the Unit. *FRACTION USED TO CALCULATE WORKING CAPITAL FOR PURPOSES OF THIS EXHIBIT. 116 APPENDIX 8 TO SCHEDULE E has been revised from previous filings and is filed in full herewith. 117 APPENDIX 8 TO SCHEDULE E Charges Applicable to Transactions from Beaver Valley Power Station Unit No. 2 Pursuant to Schedule E This Appendix provides for specific charges applicable to transactions made from Beaver Valley Power Station Unit No. 2 pursuant to Schedule E. Costs will be shared on a basis equivalent to that of the joint participants with certain modifications specified herein. The following are the components of the costs to be included. A. Fixed Costs of Invested Capital 1. It is expected that sales out of production units will occur pre- dominantly over a relative short time period in the early part of the unit's life. However, this Appendix develops a consistent basis which is applicable throughout the life cycle. 2. Amortization and tax calculations are based on the following: Amortization Period - 35 Years (420 Months) Plant Amortization Period - 40 Years (480 Months) Decommissioning ACRS Tax Life 10 Years (120 Months) Estimated Salvage Rate $142.4 Million Decommissioning Cost Accounting Treatment Flow-Through
3. All fixed charges are on a month-to-month declining basis. The investment base from which fixed charges are developed shall be the CAPCO investment basis as defined in the Accounting and Procedure Manual under Procedures for Discharging Investment Responsibility. 4. The monthly finance charge rate applicable to all additions from the in-service date through the last month of the calendar year in which the construction job order is closed out shall be one-twelfth the specified annual rate. 5. The finance charge rate for ordinary additions in years subsequent to the calendar year in which the construction job order was closed out shall be the specified rate. 6. Amortization and other charges and adjustments shall be billed each month. Each month's additions to plant in-service shall constitute a vintage investment. However, in order to simplify the billing process, the monthly vintages of any particular calendar year may be combined into a composite vintage, either on an ongoing basis or at the end of the calendar year, providing the same billing results. Since finance charge rates are recalculated each year, vintages of different calendar years will not be composited. 118 BV-2 (Page 2 of 19) 7. The tax plant ratio to amortizable plant (CAPCO investment basis) shall be established from data for the total project as estimated at the in-service date, as described in Paragraph 5. This ratio will be used in developing fixed charge rates for the initial placements and all subsequent additions; except that in the case of major capital additions, at seller's option and with buyers' concurrence, a completely new vintage may be developed and the fixed charge factor recalculated using the new tax plant ratio and other pertinent data as appropriate. 8. When a production unit, or a major capital addition such as described in Paragraph 7, is placed in commercial service, the first fixed charge billing shall begin effective with the in-service date. For subsequent month-to-month additions, the billing shall begin with the first full calendar month after the addition is made. 9. Where sales are initiated out of an existing production facility to a new buyer, a single-vintage CAPCO investment basis may be calculated with an appropriate adjustment for depreciation incurred to date. The amortization component of the fixed charge factor will be calcu- lated on the basis of remaining life of the original amortization period or by mutual agreement. 10. The specific fixed charge rate for Beaver Valley Unit No. 2 is developed in Exhibit B. B. Operating and Maintenance Costs 1. The methods specified in the attached Exhibit A shall be used to allocate between the supplying Party and the receiving Party(s) or Purchaser(s) all costs, including overheads directly or indirectly applicable to the operation and maintenance of the supplying Party's participation in such unit. 2. The supplying Party will prepare, revise from time to time as appropriate and furnish to the Purchaser(s) an annual estimate of the amount to be billed by months (a) for the cost of energy during the term of the purchase from a unit, and (b) any other costs which shall accrue during this period. The supplying Party will furnish any reasonable request for estimates for longer periods if required by the Purchaser(s). 3. The supplying Party will maintain the records used in the deter- mination of the Purchaser(s) bill in order that the Purchaser(s) and their independent auditors shall have access at all reasonable times to such records and the supplying Party will furnish copies of such records as requested. The supplying Party shall preserve and maintain the originals of such records for at least such periods of time as the Purchaser(s) may request, having in mind the requirements of regulatory authorities having jurisdiction and the policies and practices of the parties with respect to the retention of records. 119 BV-2 (Page 3 of 19) 4. The cost of preparing, preserving and making copies of such budgets, records and accounts shall be borne by the companies in proportion to their respective capacity entitlements except that any costs incurred at the special request of the Purchaser(s) shall be borne by them. 5. The supplying Party shall have special audits conducted with respect to the matters provided for in this Appendix, either internally or by independent auditors, according to such programs and procedures as agreed to be necessary to conform to the auditing requirements of each company, and shall furnish copies of the reports of such audits to the Purchaser(s). The cost of making such audits, including any participation by the auditors of the Purchaser(s) agreed to be desirable and necessary, shall be shared by the companies in relation to the current capacity entitlement ratio. The Purchaser(s) may, at their own expense, make such further audits, using their internal or independent auditors or both, as it may be deemed desirable. 6. If requested by the Purchaser(s), the supplying Party will make such examinations, analyses or studies as needed to support the reason- ableness of the specific costs so allocated, or provide a basis for modification to achieve such reasonableness with respect to either the specific or the indirect cost allocations. Shareable costs which are incurred by the Purchaser(s) shall be accumulated and billed on a direct charge basis from specific records or reasonable estimates with applicable additives as agreed upon by the companies. 7. Except as otherwise provided herein, the accounting methods and practices normally in use at the time by each of the companies in determining and assigning operating and maintenance costs, generally, are to be used by such company for the purposes of this Appendix unless otherwise agreed, provided such methods and practices are consistent with sound accounting practices. 8. For the purpose of this Appendix, charges to Account 525, for rent or lease payments, will be considered fixed costs and will be charged to the Purchaser as described in Exhibit B. 9. The supplying Party will bill the Purchaser(s) for its share of property, franchise, business or other taxes applicable to its share of the unit, specifically identifying these items on the invoice when such taxes are payable by the supplying Party. To the extent that such taxes are charged to the operating expenses of the Unit because it is impractical or inequitable to segregate them, they will be billed as part of the normal operating expense of the Unit. 10. As soon as possible after the close of each calendar month, prefer- ably on or before the 8th working day of the following month, the supplying Party shall advise the Purchaser(s) of its proportionate share of estimated operating expenses, fixed charges, displacement training costs and working capital for the preceding month. Any costs payable will be paid pursuant to Section 12.02 of the CAPCO Basic Operating Agreement, as amended. 120 BV-2 (Page 4 of 19) C. Working Capital It is recognized that the operating company undertakes certain obligations to provide expenditures in advance of compensation by the purchasers of capacity and energy. These purchases include, but may not be limited to, payroll, fuel and material and supplies purchases, and material and supplies inventories. A reasonable allowance for this investment in working capital funds shall be considered a shareable cost to be compen- sated for as set out in detail in Exhibit C. D. Displacement Training Costs The CAPCO companies have agreed that the costs which an operating company will incur in training personnel at existing stations in order to be able to transfer experienced personnel to a new CAPCO generating unit should be shared by the joint owners. Purchasers of capacity and energy shall also share in these costs. 1. For each new CAPCO unit, the cost basis of $1/kW of the installed capacity is determined to be a reasonable estimate of the present-day cost which a company will incur within its existing plants as a result of assigning experienced company personnel to a new CAPCO generating unit. Installed capacity for this purpose is defined as the Net Demonstrated Capability of the CAPCO generating unit. 2. It is recognized that these costs will increase as labor costs increase. Therefore, this cost determination factor of $1/kW shall be subject to escalation for units planned to be in-service after Davis-Besse No. 1 based on an index of the composite labor costs of CAPCO companies as agreed to by the CAPCO Accounting and Finance Committee using 1972 as the base year equaling 100.0. The index to be applied shall be that calculated for the period two years prior to the actual in-service date for fossil-fired generating units and for the period three years prior to the actual in-service date for nuclear units. 3. The Purchasers of capacity and energy shall share in these costs for the periods they are involved. An amount of 1/420 of the cost basis for each kW of the purchasing company's capacity entitlement shall be included in the monthly billing. 4. The cost basis provided for herein shall be shown in Exhibit D. 121 BV-2 (Page 5 of 19) ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Beaver Valley Power Station Unit No. 2 EXHIBIT A Section I - Introduction This Exhibit pertains to all agreements related to the Sales of Capacity and Energy from the Participants of Beaver Valley Unit No. 2 to Purchasers. In the event any Purchaser does not schedule part or any of its generation entitlement share as stated in the applicable agreement, the balance of its entitlement shall remain as capacity available to the Purchaser, provided that, if the Unit is operated at minimum load required for safe operation of the Unit, the Purchaser shall be obligated to schedule an amount of energy equal to that Unit's minimum load for the hour, multiplied by a fraction of which the numerator is the Purchaser's entitlement under the applicable agreement and the denominator is the applicable Unit's Net Demonstrated Capability. The amount of energy determined above, subject to adjustment for proportionate use of all plant auxiliary power assignable to the operation of the Unit, shall constitute a scheduled (billing) MWH value (net) as of each Unit's generator transformer high voltage terminals. Each Participant shall schedule for delivery from the Unit, and each Purchaser shall schedule for receipt into its system, an amount of energy equal to such billing value less the increase, or plus the decrease, as the case may be, in electrical losses incurred on its system resulting from the transmission of such energy as determined by the Planning Committee under terms of the CAPCO Transmission Facilities Agreement. Section II - Accounting Concepts The basis for allocating the operation and maintenance costs of Beaver Valley Unit No. 2 between the joint Participants is set forth in Exhibit A of the Operating Agreement for this unit. This Exhibit prescribes the method of determining the portion of that cost of a Participant which will be billed to a Purchaser. The costs to be billed to a Purchaser will be segregated as to those that are directly identified with a Purchaser and to those that are allocated either on an investment responsibility or a fuel consumed basis. The codes for these segregations are defined at the end of Section III. In addition to the direct costs for operating and maintaining the Unit, a Participant shall bill a Purchaser for an appropriate portion of indirect overheads and taxes other than income taxes as defined in Section V. Section III - Allocation of Costs The operation and maintenance costs identified by FERC account number are assigned to a Purchaser either directly or on the basis of appropriate allocation codes as set forth in the following table. 122 BV-2 (Page 6 of 19) ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Beaver Valley Power Station Unit No. 2
Direct Participants' Costs to be Basis Allocated to the Purchaser Account to Allocation Codes Number Purchaser O(IR) HY(IR) OPERATION ACCOUNTS 517 Supervision and Engineering X 518 Nuclear Fuel Expense X 519 Coolants and Water X 520-2 Steam Expenses* X 520-3 Steam Expenses* X 523 Electric Expenses X 524 Misc. Nuclear Power Expenses X MAINTENANCE ACCOUNTS 528 Supervision and Engineering X 529 Structures X 530-2 Reactor Plant and Equipment* X 530-3 Reactor Plant and Equipment* X 531 Electric Plant X 532 Misc. Nuclear Plant X OTHER ACCOUNTS 562 Operation - Station Expenses X 570 Maintenance of Station Equipment X
*See Exhibit A of the Beaver Valley Operating Agreement for breakdown of these accounts. Direct charges will be made to a Purchaser for fuel consumed as determined in accordance with Section IV. Code Basis O(IR) The portion of a Participant's operation and maintenance costs for the Unit to be billed to a Purchaser for the current month shall be a fraction of which the numerator is a Purchaser's entitlement from the Unit as specified in the applicable agreement and the denominator is a Participant's interest in that Unit, both figures rounded to the nearest whole megawatt. A Participant's interest in the Unit shall be the product of the prevailing Net Demonstrated Capability (NDC) of the Unit multiplied by that Participant's net generation entitlement share in the Unit. 123 ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Beaver Valley Power Station Unit No. 2 Code Basis If the capacity of the Unit is reduced by operating problems, a Purchaser will be entitled to his O(IR) ratio multiplied by the Participant's entitlement of the output of the Unit on an hour- to-hour basis. HY(IR) The portion of a Participant's cost for the Unit to be billed to a Purchaser for the current month shall be a fraction of which the numerator is the portion of the BTU input to the main unit turbine used to produce the kilowatthours of energy taken from the Unit by the Purchaser during the preceding 12-month period and the denominator is the portion of the BTU input to the main turbine used to produce the kilowatthours of energy taken from the Unit by the Participant during that same preceding 12-month period. Prior to the time that this data is available on a 12-month basis, available data will be used to determine the allocation ratio. Section IV - Fuel In determining fuel costs, a Purchaser shall be treated in the same manner as a Participant. The following basic principles shall govern the calculation of depletion (amortization) of fuel assemblies installed in the reactor for heat production and the billing of fuel costs to Purchasers. 1. Nuclear fuel assemblies shall be considered to be producing heat only during periods of zero or positive net generation. 2. During periods of negative net generation, it will be considered that installed nuclear fuel assemblies are not producing heat and are not thus consumed. During periods of negative net generation, records of station service electric energy supplied by the system shall be maintained and the participants in the Unit shall be invoiced for such electric energy in proportion to their investment responsibilities in the Unit as the operating Participant's system average production cost (including net purchased power costs) during the current calendar month adjusted to exclude the output and cost during the current calendar month of the Unit to which such station service energy was supplied. 3. During periods of zero or positive net generation, the components of consumption of heat from nuclear fuel assemblies shall be considered to consist of a fixed heat consumption component and a variable heat consumption component. The components of heat consumption are illustrated by the current turbine-generator heat consumption curve for the Unit as agreed to by the Participants. The fixed portion of heat consumption consists of the heat produced by the reactor required to supply station service electric energy plus heat losses in the plant. 124 ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Beaver Valley Power Station Unit No. 2 4. During periods of zero or positive net generation, the fixed and variable portions of the total Unit heat consumption shall be calculated on an hour-by-hour basis. The fixed portion of the Unit heat consumption shall be the product of service hours accumulated during periods of zero or positive net generation times the fixed unit heat consumption as indicated on the current turbine-generator heat consumption curve for the Unit as agreed to by the Participants. The variable portion of the Unit heat consumption shall be the total net main unit generation in MWe hr/hr converted to BTU/hr excluding the fixed unit heat consumption utilizing the relationship between MWe hr/hr versus BTU/hr as represented on the current turbine-generator heat consumption curve for each Unit as agreed to by the Participants. The total unit heat consumption shall be the sum of fixed and variable portions of the unit heat consumption. 5. In calculations for determining the cost of nuclear fuel consumed, Duquesne Light Company shall take into account the original acquisition cost of the materials and services required to provide the fuel as originally installed, and predicted total heat output of the assemblies and the estimated net value of salvage materials. Duquesne shall calculate such cost of nuclear fuel consumed using methods and/or computer codes generally considered acceptable by the CAPCO Companies for this purpose. 6. For owned nuclear fuel, the total monthly nuclear fuel expense for the Purchaser shall be determined by the formula FCc = Ec (Ac - Sf) _________ Ef where: FCc = Nuclear Fuel expense during the current accounting month. Ec = The energy received by the Purchaser during the current accounting month. Ef = The energy expected to be produced from the fuel component. Fuel component can be a fuel assembly, sub-region, region or entire core. Ac = The Participant's current net costs. Sf = Anticipated salvage value of the fuel with related deductions including, but not limited to, shipping, reprocessing and waste disposal costs. When the Participant adjusts its Ac, Sf and Ef factors, these same factors will be adjusted in a similar manner for the Purchaser. 125 ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Beaver Valley Power Station Unit No. 2 7. For leased nuclear fuel, the total monthly nuclear fuel expense for the Purchaser is composed of a) a burnup expense related to energy resource consumption, b) amortization of accumulated deferred expenses not related to burnup pertaining to the period prior to the beginning of commercial operation of the leased nuclear fuel, and c) monthly payments not related to burnup made by the Participants to the Lessor pertaining to the period after the beginning of commercial operation of the leased nuclear fuel. A. The monthly burnup expense shall be calculated as follows: Bc = Ec (Cc - Sf) _________ Ef where: Bc = Burnup expense for the current accounting month. Ec = The energy received by the Purchaser during the current accounting month. Ef = The energy expected to be produced from the fuel component. Fuel component can be a fuel assembly, sub-region or entire core. Cc = The Lessor's current net costs. Sf = Anticipated salvage value of the fuel with related deductions including, but not limited to, shipping, reprocessing and waste disposal costs. B. The amortization of accumulated deferred expenses not related to burnup pertaining to the period prior to the beginning of commercial operation of the leased nuclear fuel shall be calculated as follows: PDAc = Ec (Dp) ____ Ef where: PDAc = The current month amortization of deferred expenses not related to burnup pertaining to the period prior to the beginning of commercial operation of the leased nuclear fuel. Ec = The energy received by the Purchaser during the current accounting month. Ef = The energy expected to be produced from the fuel component. 126 BV-2 (Page 10 of 19) ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Beaver Valley Power Station Unit No. 2 Dp = The unamortized portion at the beginning of the current accounting month of the deferred expense not related to burnup pertaining to the period prior to the beginning of commercial operation of the leased nuclear fuel. C. Monthly payments not related to burnup made by Participants to the Lessor pertaining to the period after the beginning of commercial operation of the leased nuclear fuel billable to the Purchaser shall be calculated as follows: MPLc = Rc (Cc) (O(IR)) where: MPLc = The current payments not related to burnup made by the Participant to the Lessor. Rc = The current lease rate as defined in the lease agreement expressed as the decimal equivalent of percent month. Cc = The Lessor's current net costs. O(IR) As defined in Section III. Section V - Other Expenses For billing costs to the Purchaser, labor and material additive costs at current rates prevailing in the industry as adjusted from time to time shall be added to the labor and material components of direct operation and maintenance costs of Beaver Valley Unit No. 2 to which such rates are applicable and shall be shared by Purchasers on the same bases on which the primary labor and material costs are shared. In addition, an allocation will be made of Account 556, System Control and Load Dispatching costs related to production, and Account 557, Other Production Expenses. These costs would be allocated to Beaver Valley Unit No. 2 on a direct basis where a direct relationship exists, or by using a net generating capability ratio (O(IR)) where a direct relationship does not exist. Account 556 will include only those load dispatching costs incurred by DL that are attributable to Beaver Valley Unit No. 2. Included in Account 557, Other Production Expenses, are such items as insurance premiums and recoveries and other production expenses not directly assignable to the other production accounts. The invoice will identify amounts billed that were included in Account 557. 127 BV-2 (Page 11 of 19) ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Beaver Valley Power Station Unit No. 2 For billing costs to Purchasers, labor fringe benefit additive costs shall be allocated to Beaver Valley Unit No. 2 on the basis of a rate representative of labor additive rates experienced by public utilities in the United States, as calculated from information contained in the U.S. Chamber of Commerce annual Employee Benefit Survey or in another mutually agreed upon source. The rate, expressed as a percent of total payroll cost, shall include the employer's share of employee benefit costs for legally required payments, retirement and savings plan payments, life insurance and death benefit payments, medical and medically related payments, and other miscellaneous benefit payments; but excluding benefits paid in the form of direct compensation to employees for time not worked such as paid rest periods, lunch or travel periods, holidays, vacations, sick time, parental leave and other similar payments. The rate produced in this manner is 31.3% for the billing year 1993 based on U.S. Chamber of Commerce survey data from benefit year 1991, and the rate for subsequent years will be computed annually based on the then most current U.S. Chamber of Commerce Survey data or other mutually agreed upon data available, and will become effective January 1 of each such subsequent year. The amount of labor additive costs to be allocated to each Purchaser during a given period shall be the product of the above rate multiplied by the direct labor expense allocated to the Purchaser for that period. For billing costs to Purchasers, administrative and general (A&G) expense shall be allocated to Beaver Valley Unit No. 2 on the basis of a rate representative of A&G rates in the utility industry as calculated from information contained in the Utility Data Institute (UDI) compilation of utilities' FERC Form 1 data or in another mutually agreed upon source. The rate shall be equal to the ratio of: A. the sum of the base year of all amounts for all data base companies in FERC Accounts 920, 921 and 922, divided by B. the sum for the base year for the same companies of all amounts in FERC Accounts 500 through 916, minus the amounts representing fuel and purchase power expenses in FERC Accounts 501, 518, 547, 555 and 557. The rate produced by this calculation is 12.70% for the billing year 1993 based on UDI data from 1991, and the rate for subsequent years will be computed annually based on the then most current UDI or other mutually agreed upon data available and will become effective January 1 of each such subse- quent year. The amount of Administrative and General Expenses to be allocated to each Purchaser during a given period shall be the product of the above ratio multiplied by the total operation and maintenance expenses and labor additives excluding Account 518 allocated to the Purchaser for that period. 128 BV-2 (Page 12 of 19) ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Beaver Valley Power Station Unit No. 2 In addition, a Purchaser shall pay to the Participant, at times payable by the Participant, amounts determined by multiplying (a) the property taxes and any other taxes except Federal Income Tax, payable by the Participant with respect to the Unit for the periods a Purchaser was involved by, (b) and O(IR) ratio for that period. 129 EXHIBIT B FIXED COSTS OF INVESTED CAPITAL I. As between Cleveland Electric Illuminating and Toledo Edison, the monthly fixed charge for vintage additions prior to 1988 shall be calculated as the algebraic sum of the following components: A. Lease Payment -- The Purchaser will reimburse the Seller's total monthly lease and/or rental payment for plant property under a sale/ leaseback agreement. This payment may be adjusted as the payment schedule on the underlying sale/leaseback agreement is amended. B. Decommissioning Costs -- The product of the allowed monthly charge for decommissioning in the Seller's rates multiplied by the ratio of Total Megawatt Capacity Purchased to the Seller's Total Megawatt Ownership in the Unit. [($142,400,000 : 480) * (150/166)] = $268,027/month. C. Refueling Outage Accrual -- The product of the allowed monthly charge for refueling outage accruals in the Seller's rates multi- plied by the ratio of Total Megawatt Capacity Purchased to the Seller's Total Megawatt Ownership in the Unit. II. The monthly fixed charge for a vintage addition made during 1987 or subsequent years shall be calculated as the algebraic sum of the following components: A. Amortization(1) -- The product of (XX) multiplied by the ratio in Note (5). B. Finance Charge(2) -- The product of (AA) multiplied by the Seller's net unamortized investment base as of the beginning of the month being billed times the ratio in Note (5). C. Gross Income Tax(3) (i) For billing months after 1987, the product of (BB) multiplied by the net unamortized investment base as of the beginning of the month being billed. If the incremental federal tax rate is different from 34% in any month of such period, the factor used as the multiplier shall be adjusted to reflect such difference from 34%. D. Income Tax Adjustment(4) For billing months after 1987, the product of (.34/1-34)) times the difference between the amortization (Item A) less the tax depreciation. If the incremental federal tax rate is different from 34% in any month of such period, the factor used as the multiplier shall be adjusted to reflect such difference from 34%. NOTE: This adjustment may be a negative or positive value during the period of the contract. 130 BV-2 (Page 14 of 19) EXHIBIT B FIXED COSTS OF INVESTED CAPITAL NOTES: (1) (XX) equals the sum of the Seller's investment base less land divided by 420 months plus the Seller's share of decommissioning costs divided by 480 months. The Seller's adjusted investment base equals his total investment for Beaver Valley Unit No. 2 and Common Facilities as of the beginning of the month for which service is being billed. (2) The Seller's net unamortized adjusted investment base equals the adjusted investment base, less the accumulated amortization previously reflected in rates, less investment tax credit attributed to the adjusted investment base, less the net tax deduction associated with capitalized overheads attributable to the adjusted investment base. (AA) is the monthly finance charge rate, which equals 1/12 of the Seller's weighted cost of capital as defined in the CAPCO Accounting and Procedures Manual under Procedures for Discharging Investment Responsibility. (3) (BB) is the monthly gross income tax charge rates applicable to 1987 and post-1987 billing periods. It is the product of 1/12 of the sum of the weighted costs of common equity, preferred equity and unamortized gain on the annual finance charge multiplied by the federal income tax rate divided by the complement of the income tax rate. The tax rate may be augmented to include state income taxes as defined in the CAPCO Accounting and Procedures Manual under Procedures for Discharging Investment Responsibility, i.e., 1/12 x (Seller's Equity Component of Capital) x (Tax Rate/(1-Tax Rate)) (4) The income tax adjustment results from the difference between book amortization and tax depreciation, and from the agreement between the parties of the extent to which such difference should be recognized in the price paid. (5) The ratio shall be the Ratio of Total Megawatt Capacity Purchased (or Shared) to the Total Megawatts of Seller's Plant Capacity. 131 BV-2 (Page 15 of 19) EXHIBIT B.1 DERIVATION OF WEIGHTED COST OF CAPITAL THE TOLEDO EDISON COMPANY The complete capital structure, including ratios, component costs and weighted component costs is provided below:
% of % Weighted Total % Cost Cost Long-Term Debt 50.53% 10.29% 5.20% Preferred Stock 10.13% 9.41% 0.95% Common Equity 39.34% 12.25% 4.82% 100.00% 10.97%
132 BV-2 (Page 16 of 19) EXHIBIT B.2 DERIVATION OF DECOMMISSIONING COST AND ACCRUAL THE TOLEDO EDISON COMPANY The derivation of the decommissioning cost estimate of $142.4 million for Beaver Valley Unit No. 2 was developed as follows: NRC Decommissioning Estimate (1984 Dollars) $100,000,000 Inflation Factor* 1.224 Decommissioning Estimate (10-87 Dollars) $122,400,000 Net Salvage on Non-Contaminated Portion 20,000,000 Total $142,400,000
*The inflation factor of 1.224 is twice the percentage increase in the CPI from the period June 1984 to October 1987. The annual accrual will simply be the $142.4 million estimate divided by 40 years or $3,560,000/year. Toledo Edison's share of this decommissioning cost is $28,352,000. Toledo Edison's share of the annual accrual is $708,800. The specific monthly amount Toledo Edison will charge The Cleveland Electric Illuminating Company for the 150 MW Unit Power Sale is $53,373, developed as shown below: Total Plant Estimated Decommissioning $142,400,000 Cost Toledo Edison Share at 19.91% 28,352,000 Toledo Edison Monthly Accrual 59,606 ($28,352,000 + 480) Toledo Edison Monthly Charge to CEI 53,373 for 150 MW Sale ($59,066 x 150 MW) ( 166 MW)
133 REIMBURSEMENT OF WORKING CAPITAL COSTS I. Accumulated Deferred Fuel Expense - Working Capital Costs Applicable to a Purchaser of Capacity and Energy Reimbursement by Monthly Carrying Charge in Lieu of Deposit The charge for a given month per megawatt of capacity purchased shall be based on the supplying Party's unamortized accumulated deferred expenses (not related to burnup) pertaining to the period prior to the the beginning of commercial operation of the leased nuclear fuel per megawatt of capacity, to include the unamortized deferred depletion balance, if any, at the end of the month in which service was rendered and shall be calculated as follows: The Product of (a) (b) (c) (a) The Unamortized Accumulated Deferred Expenses (Not Related to Burnup) pertaining to the period prior to the beginning of Commercial Operation of the leased Nuclear Fuel to include the unamortized deferred depletion balance, if any. (b) The Ratio of Total Megawatt Capacity Purchased to the Supplying Party's Total Megawatt Capacity in Service. (c) One-Twelfth* of the Supplying Party's Current Annual Capital Cost Rate, plus the Supplying Party's income tax liability on the Equity Component. II. Materials and Supplies Inventory - Working capital cost applicable to a purchaser. Reimbursement by Monthly Carrying Charge in Lieu of Deposit The charge for a given month per megawatt of capacity purchased (or shared) shall be based on the supplying Party's total dollar balance in M&S inventory at the end of the month in which service was rendered, and shall be calculated as follows: Beaver Valley Unit No. 2 - The Product Of: (a) Total Dollars in Supplying Party's M&S Inventory at the Entire Plant. (b) The Ratio of Total Megawatt Capacity Purchased (or Shared) to the Total Megawatts of Supplying Party's Plant Capacity. (c) One-Twelfth* of the Supplying Party's Current Annual Capital Cost Rate, augmented to Include Supplying Party's Income Tax Liability on the Equity Component. *Fraction used to calculate working capital for purposes of this Exhibit. 134 BV-2 (Page 18 of 19) EXHIBIT C REIMBURSEMENT OF WORKING CAPITAL COSTS III. Monthly Operation & Maintenance Expenses - Working capital cost appli- cable to a purchaser or to a participant. The monthly charge shall be calculated each month for the Unit as the product of (a) and (b) for capacity owned and as the product of (a), (b) and (c) for capacity purchased. (a) The current month's direct operating expenses (Accounts 500-554, 556, 557, 562 and 570) for each Participant for the Unit, including overheads, less fuel and lease payments, and any other inappropriate items. (b) One-Twelfth* of the Operating Company's Current Annual Capital Cost Rate plus the Operating Company's income tax liability on the equity component. (c) The Purchaser's entitlement share of megawatt capacity in the Unit. *Fraction used to calculate working capital for purposes of this Exhibit. 135 BV-2 (Page 19 of 19) EXHIBIT D DISPLACEMENT TRAINING COSTS Installed Capacity at Beaver Valley Power Station No. 2 833,000 kW Generation Entitlement Share Cleveland Electric Illuminating Company 24.47% Duquesne Light Company 13.74% Ohio Edison Company 41.88% Toledo Edison Company 19.91% 100.00% The participants' respective shares of the displacement training costs, based on $2.011/kW, are: Cleveland Electric Illuminating Company $409,912 Duquesne Light Company $230,167 Ohio Edison Company $701,558 Toledo Edison Company $333,525
Therefore, under the terms of this Agreement, each purchaser will share in these costs, based on its entitlement at the rate of 1/420 of the cost basis, for each billing month beginning with the effective purchase date. 136 CAPCO BASIC OPERATING AGREEMENT SCHEDULE F OUT-OF-POCKET COST Where referred to in this Agreement, the Out-of-Pocket Cost of supplying Power in each hour shall be the cost incurred in the supply of the highest cost power available on the supplying Party's system during that hour, including power purchased from non-CAPCO party systems as well as Power generated by a Party's own generation resources, after all sales with a lower pricing priority (higher cost) have been accounted for. The components of Out-of-Pocket Costs shall include but shall not be limited to the following: Capacity Costs Start-up and shutdown costs (boiler and turbine) No load cost (boiler and turbine) Maintenance cost (boiler and turbine) Charge (or credit) for increased (or decreased) cost of energy generated by the Party associated with the transaction Incremental labor costs Applicable incremental taxes Miscellaneous incremental operating costs 137 Energy Costs Incremental fuel cost Incremental transmission losses Incremental labor cost Incremental maintenance cost Applicable incremental taxes Miscellaneous incremental operating costs Purchased Power All costs, excluding demand charges, paid to a non-CAPCO party system for Power purchased plus applicable or allocable fees imposed by any regulatory body. 138 CAPCO BASIC OPERATING AGREEMENT SCHEDULE G EMERGENCY POWER Section 1 - Services to be Rendered 1.1 In the event of a breakdown or other emergency in or on the system of any Party involving either sources of power or transmission facilities, or both, impairing or jeopardizing the ability of a Party to meet the Load of its system, upon request, each Party shall deliver to such Party Emergency Power, during a period not exceeding 48 consecutive hours, in amounts up to 100 MW per hour and such additional amounts as in its sole judgment it can deliver without interposing a hazard to its operations or without impairing or jeopardizing its Load. Such Emergency Power shall be provided (1) from unloaded generating facilities, either on or off line, to the fullest extent necessary from each supplying Party's system, or (2) from non-CAPCO party systems to which the supplying Parties are interconnected. No Party is obligated to terminate any delivery of Power (excluding economy transactions) to any other system in order to provide Emergency Power, but a Party is obligated to terminate economy transactions and supply any excess Power from its own system and to purchase Power, if available, from any other system with which it is interconnected in order to provide Emergency Power. Every request hereunder shall identify the emergency that gave rise to it. Emergency Power shall not be requested or supplied in lieu of CAPCO Back-Up Power. 139 1.2 If at any time the record over a reasonable prior period shows clearly that any Party has failed to deliver Emergency Power, or has regularly requested delivery of Emergency Power, any Party, by written notice given to the other Parties, may call for a joint study by the Parties to determine the burden, if any, that such Party may be placing upon any other. If it should be found that such Party is placing an unreasonable burden upon the others, the Party causing the burden shall take such measures as are necessary to remove the burden, or the Parties shall enter into such arrangements as shall provide for equitable compensation to the Party(s) being burdened. Section 2 - Compensation 2.1 Capacity Charge Capacity supplied from a supplying Party's system shall be compensated for at the option of the supplying Party by return-in-kind or by the payment of the greater of (1) $100 per MW-hr or (2) 100% Out-of-Pocket Cost plus a charge of $2.40 per MW-hr for operating capacity from a supplying Party's system. Capacity supplied from a non-CAPCO party system shall be compensated for at the option of the supplying Party by return-in-kind or by the payment of the greater of (1) $100 per MW-hr or (2) 100% Out-of-Pocket Cost plus any demand charge of a non-CAPCO party system for providing operating capacity plus a demand charge not to exceed $5.59 per MW-hr shall apply, provided this demand charge in any one day shall not exceed $89.40 times the maximum MW(s) reserved in any one hour in that day plus $1.00 per MW-hr. 140 2.2 Capacity and Energy or Energy Only Charge Emergency Power supplied from a supplying Party's system shall be compensated for at the option of the supplying Party by return-in-kind or by the payment of the greater of (1) $100 per MWh or (2) 100% Out-of-Pocket Cost plus a charge of $2.40 per MWh for operating capacity and or energy or energy only from a supplying Party's system. Emergency Power supplied from a non-CAPCO party shall be compen- sated for at the option of the supplying Party by return-in-kind or by the payment of the greater of (1) $100 per MWh or (2) 100% Out-of-Pocket Cost plus any demand charge of a non-CAPCO party system for operating capacity and energy plus for such transactions a demand charge not to exceed $5.59 per MWh shall apply, provided this demand charge in any one day shall not exceed $89.40 times the maximum MW(s) reserved in any one hour in that day plus $1.00 per MWh. 141 CAPCO BASIC OPERATING AGREEMENT SCHEDULE H TRANSMISSION OF NON-CAPCO POWER Section 1 - Services to be Rendered 1.1 Any Party ("supplying Party") may arrange to reserve Non-CAPCO Power for periods of one day or more from or through an interconnected non-CAPCO party system to be delivered to another Party ("receiving Party") for delivery to or through another interconnected non-CAPCO party system. All Parties shall be advised of such transactions in advance. This Schedule shall not apply to Economy and Emergency transactions. Section 2 - Compensation 2.1 For such transactions the associated demand, capacity and energy charge payments for transmission service upon the transmission systems of the CAPCO Parties (i.e., the difference between the amounts paid to the receiving Party and by the supplying Party) shall be shared among all Parties with 2/3 of such payments allocated equally between the supplying Party and the receiv- ing Party and 1/3 of such payments allocated equally between the other two Parties. 142 CAPCO BASIC OPERATING AGREEMENT SCHEDULE I REPLACEMENT POWER Section 1 - Applicability The Parties recognize the possibility that the start-up of a nuclear CAPCO Unit may be delayed and such CAPCO Unit may be out of service due to the failure of a Party having an ownership interest in such CAPCO Unit to supply its required share of natural uranium in the form of U3O8 or UF6 ("Uranium") for such CAPCO Unit for delivery in a timely manner and in a tenant-in-common form of ownership to the United States Department of Energy or other enrich- ment contractor for enrichment. This Schedule I is applicable to the provi- sion of replacement Power in any such limited circumstances where a Party having an ownership interest in a CAPCO Unit fails to so supply its share of Uranium for enrichment. Section 2 - Services to be Rendered 2.1 In the event that any Party(s) ("supplying Party") fails to supply its required share of Uranium for a CAPCO Unit, then any Party(s) ("receiving Party"), which is unable to receive its entitlement of operating capacity and associated energy from such CAPCO Unit as the direct result of such supplying Party's failure to supply the required Uranium, may during the period that the start-up of such CAPCO Unit is delayed and such Unit is out of service, at such receiving Party's sole option, either (1) arrange for replacement 143 capacity ("Replacement Capacity") and replacement energy ("Replacement Energy") or (2) permit the supplying Party which failed to supply the Uranium to provide such Replacement Capacity and Replacement Energy. The amount of such Replacement Capacity on an hourly basis will be up to, at the option of each such receiving Party, an amount equal to such receiving Party's ownership interest in such CAPCO Unit times the effective average capacity factor achieved by such CAPCO Unit during the last fuel cycle (excluding refueling) prior to such CAPCO Unit being out of service. Any amount of Replacement Energy may be scheduled by such receiving Party out of such Replacement Capacity. If such CAPCO Unit has not yet attained sufficient operating experience to establish such effective average capacity factor, then such effective average capacity factor shall be deemed to be the same as the most recent comparable experience of any like CAPCO Unit at such CAPCO Unit site. Such transactions shall be arranged weekly in advance between the receiving Party and supplying Party and shall specify the amount of Replacement Capacity and Replacement Energy to be provided, if any, and the hours it is to be provided. 2.2 Replacement Capacity and Replacement Energy provided under this Schedule I will be made available to receiving Parties in proportion to their entitlements and from supplying Parties in proportion to their obligations. Replacement Capacity and Replacement Energy obligations not reserved by the receiving Party shall be deemed released by the receiving Party for that week. 144 Section 3 - Compensation 3.1 If the supplying Party supplies such Replacement Capacity and Replacement Energy hereunder from its system, the supplying Party shall be compensated at a rate equal to the receiving Party's average actual fuel cost of generation from the subject CAPCO Unit (in dollars per net MWh) during the last fuel cycle prior to such CAPCO Unit being out of service calculated in accordance with the operating agreement for such CAPCO Unit. If such CAPCO Unit has not yet attained sufficient operating experience to establish such average actual fuel cost of generation, then such average actual fuel cost of generation shall be deemed to be the same as the most recent fuel cycle experienced at any like CAPCO Unit at such CAPCO Unit site. It is understood that no additional operating capacity payments are to be made other than as included in the fuel cost (per net MWh) stated above. 3.2 If the receiving Party arranges such Replacement Capacity and Replacement Energy from other than the supplying Party, the supplying Party shall compensate the receiving Party an amount for any demand charge and Out-of-Pocket Costs incurred by such receiving Party in the purchase of such Replacement Capacity or Replacement Capacity and Replacement Energy in excess of the average actual fuel cost provided for under Section 3.1 above. EX-10.B.4 4 EXHIBIT FOR CENTERIOR 1 Exhibit 10b(4) AGREEMENT FOR THE TERMINATION OR CONSTRUCTION OF CERTAIN AGREEMENTS BY AND AMONG THE CLEVELAND ELECTRIC ILLUMINATING COMPANY, DUQUESNE LIGHT COMPANY, OHIO EDISON COMPANY, PENNSYLVANIA POWER COMPANY AND THE TOLEDO EDISON COMPANY THIS AGREEMENT, effective as of the 1st day of September 1980, by and among The Cleveland Electric Illuminating Company, an Ohio corporation; Duquesne Light Company, a Pennsylvania corporation; Ohio Edison Company, an Ohio corporation, and its wholly-owned subsidiary, Pennsylvania Power Company, a Pennsylvania corporation, which two companies are considered as a single party for purposes of this Agreement; and The Toledo Edison Company, an Ohio corporation, all of which are referred to collectively as the Parties or the CAPCO Group. WITNESSETH: WHEREAS, each of the Parties is desirous of terminating or construing, effective as of September 1, 1980, certain agreements by and among the Parties. NOW THEREFORE, in consideration of the premises and of the mutual covenants herein set forth, the Parties agree as follows: 1. The CAPCO Memorandum of Understanding dated September 14, 1967, the Agreement of Chief Executives dated July 6, 1973, and the Memorandum of Agree- ment with an effective date of March 1, 1977, and captioned "Purchase and Sale Agreements Under Schedules E and H of the CAPCO Basic Operating Agreement for 2 the period March 1, 1977 through December 31, 1977 and for 1978, and Tentative Purchase and Sale Agreements for 1979 and Beyond" are terminated and have no further force or effect. 2. The CAPCO Transmission Facilities Agreement with an effective date of September 14, 1967 (hereinafter referred to as the "Transmission Facilities Agreement") is to be construed so as to allow all of the services and trans- actions contemplated by the CAPCO Basic Operating Agreement as amended September 1, 1980 and as subsequently amended (hereinafter referred to as the "Basic Operating Agreement"), to be performed, accomplished or effected, as the case may be, under said Transmission Facilities Agreement. 3. This Agreement and the Basic Operating Agreement supersede any and all other agreements by and among the Parties involving the CAPCO Group which are not terminated in Paragraph 1, above, to the extent such other agreements conflict or are inconsistent therewith. All such conflicts or inconsistencies shall be removed by appropriate written amendments to these other agreements or by other appropriate action. 4. The Parties hereby reaffirm and agree to implement the pool restructuring principles heretofore described in the minutes of the meetings of the CAPCO Executive Committee on and after November 1, 1979, and shall use their best efforts to prepare and execute as soon as reasonably possible any and all written amendments to agreements by and among the Parties involving the CAPCO Group and to take other appropriate action required by this Agree- ment, the Basic Operating Agreement, and the aforesaid minutes of the Executive Committee. 3 IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be executed by their duly authorized officers this 23rd day of December, 1993. THE CLEVELAND ELECTRIC ILLUMINATING COMPANY By: TERRENCE G. LINNERT Title: Vice President DUQUESNE LIGHT COMPANY By: G. R. BRANDENBERGER Title: Vice President OHIO EDISON By: ARTHUR P. GARFIELD Title: Vice President PENNSYLVANIA POWER COMPANY By: J. R. EDGERLY Title: Vice President THE TOLEDO EDISON COMPANY By: TERRENCE G. LINNERT Title: Vice President EX-10.E.1 5 EXHIBIT FOR CENTERIOR 1 Exhibit 10e(1) May 25, 1993 Mr. Donald C. Shelton Davis-Besse Nuclear Power Station 300 Madison Avenue Toledo, Ohio 43652 Re: Employment Agreement Dear Mr. Shelton: This will confirm the agreement between you and Centerior Service Company (the "Company"), effective June 4, 1993, with respect to the terms of your employment by the Company, as follows: 1. The Company agrees to employ you, and you agree to serve, in a full-time senior executive capacity, until June 30, 1995, at which time you agree that your employment with the Company and its affiliates will terminate. Effective as of June 7, 1993 and during this period your annual base salary will be $225,000, payable bi-weekly. 2. Your duties will be those as Senior Vice President - Nuclear of the Company effective as of June 7, 1993; however, these may be changed to other duties of a senior executive nature as may be determined by the Chief Executive Officer and/or the Board of Directors of the Company. 3. Your employment, pursuant to this Agreement, will terminate upon June 30, 1995 or upon your earlier death or if, in the opinion of the Board of Directors, you are disabled or have failed to perform your duties as a senior executive of the Company. Upon your written request, the Board of Directors may, but is not obligated to, consent to your termination of employment at any time prior to June 30, 1995. 4. As an inducement to and in consideration of your employment commitment pursuant to this Agreement, the Company agrees to provide you (or if you are deceased, your spouse) with certain pension and other employee benefits, namely: (a) As a full-time employee of the Company and throughout your employment under this Agreement, you will be entitled to participate, in accordance with the terms thereof, in each of the Company's employee benefit plans as are available to other senior executive officers of the Company except for incentive compensation benefits and pension benefits which shall be payable as provided in paragraphs 4(b) and 4(c) below. In addition, upon termination of this agreement in accordance with the terms hereof, you will be entitled to normal retiree welfare benefits. 2 Mr. Donald C. Shelton May 25, 1993 Page 2 (b) You shall be entitled to participate in the Company's existing incentive compensation plan on the same terms and conditions as other vice presidents of the Company. In addition, you shall have the opportunity to receive, pursuant to this agreement, an additional incentive compensation award of up to 30% of your annual base salary contingent upon achievement of certain nuclear generation goals to be approved by the Company. The additional incentive compensation award provided pursuant to this paragraph 4(b) shall not be included in the calculation of pension benefits as provided in paragraph 4(c). (c) If you continue in the employ of the Company and continue the full performance of your duties hereunder through June 30, 1995, or such earlier date as may be approved by the Board of Directors, the Company will provide through the Pension Plan of the Company and by direct payments to you (or if you are deceased, your spouse) of the full amount of benefits to which you or she would otherwise be entitled to receive under the Pension Plan of the Company and at the time or times provided in such Plan, all as if the design features of the Company's 1993 Voluntary Transition Program were applied to your pension benefit calculation effective as of June 30, 1995, or such earlier date as may be approved by the Board of Directors, and as if the commuted benefit payment option were based on the interest rate under the Pension Plan in effect on July 1, 1993 or July 1, 1995 (or the actual date at retirement if earlier), whichever results in a higher commuted benefit amount; provided, however, that the Company's obligation to provide such benefits will be reduced by the amounts payable to you or on your behalf under such Pension Plan. In addition, you will be credited with 1.75 additional years of service for purposes of the foregoing normal pension benefit calculation. If your employment under this Agreement is terminated by the Board of Directors prior to June 30, 1995 by reason of your failure to perform your obligations and duties under this Agreement, the Company's only obligation to you will be the payment of the pension benefit described in this paragraph 4(c). If you voluntarily terminate employment from the Company prior to June 30, 1995 without Board of Directors' consent, the Company will have no obligation to provide the pension benefits described in this paragraph 4(c) or any other payment or benefit described in this agreement. 3 Mr. Donald C. Shelton May 25, 1993 Page 3 5. Your rights under this Agreement will not be transferable or subject to encumbrance of any nature except that upon your death, such rights will inure to the benefit of your executors, administrators, personal representatives or assigns. 6. You agree that during the term of this agreement you will provide no similar services to any corporation, partnership, association, business or activity which, in the Company's reasonable opinion, is then competitive with any business or type of enterprise conducted or engaged in by the Company, except with the written consent of the Company. Any violation of this provision of the agreement will cause the agreement to be null and void and any right you may have to future payments hereunder shall be cancelled. Otherwise you will be free to engage in other professional and/or business activities which do not impair your ability to perform this agreement. 7. All information disclosed by the Company to you which is not or does not become available to the public shall be treated by you as confidential information and shall not be disclosed to third parties. You agree not to publish either as author or co-author, without prior written approval by the Company, any information that may be developed by you in performance of your services for the Company. 8. Unless otherwise instructed, in the performance of your services under this agreement, approvals and requests on behalf of the Company shall be given by Robert J. Farling, Chief Executive Officer of the Company, or his designee or, in the event that Robert J. Farling shall cease to serve as Chief Executive Officer of the Company, the then Chief Executive Officer of the Company, or such person as the Board of Directors of Centerior may designate for such purposes. 9. This Agreement will be governed by and construed according to the laws of the State of Ohio. If the foregoing correctly sets forth the agreement between you and the Company, please sign and return to me the enclosed copy of this letter. Very truly yours, ROBERT J. FARLING Robert J. Farling Chairman and Chief Executive Officer AGREED: D. C. SHELTON Donald C. Shelton EX-10.E.2 6 EXHIBIT FOR CENTERIOR 1 Exhibit 10e(2) February 2, 1994 Mr. Al R. Temple 920 Whispering Hills Drive Naperville, IL 60540 Dear Al: This letter confirms our verbal offer for the Vice President, Marketing at Centerior. The Board of Directors and I are delighted with this opportunity, confirming our belief that you can play an important, high impact role in moving our company forward. The starting base salary is $170,000 per year plus a two-tier incentive compensation plan: participation in the existing company Executive Payroll (EPR) plan, a summary of which is attached; plus a personal cash incentive plan, up to 20% of base pay. The specific objectives for the personal cash incentive plan will be mutually established between you and I during the first month of your employment. The total compensation package includes the flexible benefit plan and the standard relocation plan, outlined in material sent to you earlier. In addition to the standard supplemental benefits for EPR employees, this offer includes an additional week of vacation (four weeks total), company car with phone, a $10,000 cash relocation allowance, and tax gross-up for reimbursed relocation expenses. A severance agreement, payable only for an involuntary separation for reasons other than non-performance, will be six months' base salary. This agreement is in effect through December, 1996. This offer remains open until February 9, 1994. It is further contingent upon successful completion of a physical examination, drug screen and the completion of a background check. Al, the Board and I are very much looking forward to your affirmative response and we hope to hear from you soon. We are confident that you and Barbara will enjoy your return to the Cleveland area. Upon acceptance, please sign and return a copy of this document. Very truly yours, ROBERT J. FARLING Accepted by: AL R. TEMPLE Date: 2/8/94 EX-10.A 7 EXHIBIT FOR CEC 1 Exhibit 10(a)(CEC) CENTERIOR ENERGY CORPORATION Each of the following current Directors and Officers of Centerior Energy Corporation ("Company") has entered into the attached Indemnity Agreement with the Company, which Agreement is currently in effect. Richard P. Anderson Director Albert C. Bersticker Director Leigh Carter Director Thomas A. Commes Director Wayne R. Embry Director Robert J. Farling Director, Chairman of the Board and President George H. Kaull Director Richard A. Miller Director Frank E. Mosier Director Sister Mary Marthe Reinhard Director Robert C. Savage Director William J. Williams Director Murray R. Edelman Executive Vice President Fred J. Lange, Jr. Senior Vice President Gary R. Leidich Vice President
March 29, 1994 2 CENTERIOR ENERGY CORPORATION DIRECTOR OR OFFICER INDEMNITY AGREEMENT This Agreement made as of the date stated at the end hereof, between Centerior Energy Corporation, an Ohio corporation (the "Company") and the Indemnitee whose name appears above his signature at the end hereof, a director or officer of the Company (the "Indemnitee"); Whereas, the Company and Indemnitee are each aware of the exposure to litiga- tion of directors and officers of the Company as such persons exercise their duties to the Company; Whereas, the Company and Indemnitee also are aware of conditions in the insurance industry that have affected and may continue to affect the Company's ability to obtain appropriate directors' and officers' liability insurance on an economically acceptable basis; Whereas, the Company desires to continue to benefit from the services of highly qualified, experienced and otherwise competent persons such as Indemnitee; Whereas, Indemnitee desires to serve or to continue to serve the Company as a director or officer or as a director, officer, employee, agent or trustee of another corporation, partnership, joint venture, trust or other enterprise in which the Company has a direct or indirect ownership interest for so long as the Company continues to provide on an acceptable basis adequate and reliable indemnification against certain liabilities and expenses which may be incurred by Indemnitee. Now, Therefore, in consideration of the foregoing premises and the mutual convenants herein contained, the parties hereto agree as follows: 1. Indemnification Subject to the terms of this Agreement, the Company shall indemnify Indemnitee with respect to his activities as a director or officer of the Company and/or as a person who is serving or has served on behalf of the Company as a director, officer, employee, agent or trustee of another corporation, partner- ship, joint venture, trust or other enterprise, domestic or foreign, in which the Company has a direct or indirect ownership interest (an "affiliated entity") against expenses and liabilities (including, but not limited to, attorneys' fees, judgments, fines and amounts paid in settlement) actually and reasonably incurred by him ("Expenses") in connection with any claim against Indemnitee which is the subject of any threatened, asserted, pending or com- pleted action, suit or proceeding, whether civil, criminal, administrative, investigative or otherwise and whether formal or informal (a "Proceeding"), to which Indemnitee was, is or is threatened to be made a party by reason of facts which include Indemnitee's being or having been such a director, - 1 - 3 officer, employee, agent or representative, to the extent of the highest and most advantageous to Indemnitee, as determined by Indemnitee, of one or any combination of the following: (a) The benefits provided by the Company's Regulations in effect on the date hereof (or as adopted by the share owners of the Company at the 1987 annual meeting of share owners); (b) The benefits provided by the Articles of Incorporation, Regulations, By-laws or their equivalent of the Company in effect at the time Expenses are incurred by Indemnitee; (c) The benefits allowable under Ohio law in effect at the date hereof; (d) The benefits allowable under the law of the jurisdiction under which the Company exists at the time Expenses are incurred by Indemnitee; (e) The benefits available under directors' and officers' liability insurance obtained by the Company and in effect for directors or officers of the Company at the time a claim for Expenses is made against Indemnitee or the Company; (f) The benefits which would be available to Indemnitee if the Directors' and Officers' Liability Insurance and Reimbursement for Directors and Officers Liability Policy issued to The Cleveland Electric Illuminating Company by Harbor Insurance Company and other insurers which expired on April 29, 1985 and which was designated as policy number HI 165461 were in effect for directors and officers of the Company at the time a claim for Expenses is made against Indemnitee or the Company; and (g) Such other benefits as are or may be otherwise available to Indemnitee. Any combination of two or more of the benefits provided by (a) through (g) shall be available to the extent that the Applicable Document, as hereafter defined, does not require that the benefits provided therein be exclusive of other benefits. The document or law providing for the benefits listed in items (a) through (g) above for an item of Expense is called the "Applicable Document" in this Agreement with respect to that item of Expense. The Company hereby undertakes to use its best efforts to assist Indemnitee, in all proper and legal ways, to obtain the benefits to which Indemnitee is entitled under this Section 2. For purposes of this Agreement, references to "other enterprise" shall include any employee benefit plan for employees of the Company or of any affiliated entity without regard to ownership of such plan; references to "fines" shall include any excise taxes assessed against Indemnitee with respect to any employee benefit plan; references to "is serving or has served on behalf of the Company" shall include any service as a director, officer, employee or agent of the Company which imposes duties on, or involves services by, Indemnitee with respect to any employee benefit plan, its participants or beneficiaries; references to "Proceeding" shall include any threatened, asserted, pending or completed Proceeding; references to the masculine shall - 2 - 4 include the feminine; references to the singular shall include the plural and vice versa; and if Indemnitee acted in good faith and in a manner he reason- ably believed to be in the interest of the participants and beneficiaries of an employee benefit plan, he shall be deemed to have acted in a manner con- sistent with the standards required for indemnification by the Company under the Applicable Documents. 2. Insurance The Company shall maintain directors' and officers' liability insurance covering Indemnitee for so long as Indemnitee's services are covered here- under, provided and only to the extent that such insurance is available in amounts and on terms and conditions determined by the Company to be acceptable. However, the Company agrees that the provisions hereof shall remain in effect regardless of whether liability or other insurance coverage is at any time obtained or retained by the Company; except that any payments made to Indemnitee for an Expense under an insurance policy obtained or retained by the Company shall reduce the obligation of the Company to make payments for such Expense hereunder by the amount of the payments made under any such insurance policy. 3. Payment of Expenses At Indemnitee's request, the Company shall pay the Expenses as and when incurred by Indemnitee, after receipt of written notice pursuant to Section 6 hereof and an undertaking, in the form attached hereto, by or on behalf of Indemnitee (i) to repay such amounts so paid on Indemnitee's behalf if it shall ultimately be determined under the Applicable Document that Indemnitee is required to repay such amounts and (ii) to reasonably cooperate with the Company concerning such Proceeding. That portion of Expenses which represents attorneys' fees and other costs incurred in defending any Proceeding shall be paid by the Company within 30 days of its receipt of such request, together with reasonable documentation (consistent, in the case of attorney's fees, with Company practice in payment of legal fees for outside counsel generally) evidencing the amount and nature of such Expenses, subject to its also having received such a notice and undertaking. 4. Trust Fund The Company shall irrevocably deposit into a trust fund (the "Trust") assets having an aggregate value of $600,000 as collateral security for the initial funding of its obligations hereunder and under similar agreements with other directors or officers. The Company shall promptly provide Indemnitee with a true and complete copy of the agreement relating to the establishment and operation of the Trust, together with such additional documentation or information with respect to the Trust as Indemnitee may from time to time reasonably request. The Company shall promptly deliver an executed copy of this Agreement to the trustee of the Trust to evidence to the trustee that Indemnitee is a beneficiary of the Trust and shall deliver to Indemnitee the trustee's signed receipt evidencing that delivery. The Company shall have the right, but no obligation, to replenish the Trust for amounts distributed from time to time to the beneficiaries thereof. - 3 - 5 5. Additional Rights The indemnification provided in this Agreement shall not be exclusive of any other indemnification or right to which Indemnitee may be entitled and shall continue after Indemnitee has ceased to occupy a position as an officer, director, employee, agent or trustee as described in Section 1 above with respect to Proceedings relating to or arising out of Indemnitee's acts or omissions during his service in such position. 6. Notice to Company Indemnitee shall provide to the Company prompt written notice of any Proceeding threatened, asserted or commenced against Indemnitee with respect to which Indemnitee may assert a right to indemnification hereunder; provided that failure to provide such notice shall not in any way limit Indemnitee's rights under this Agreement. 7. Cooperation in Defense and Settlement Indemnitee shall not make any admission or effect any settlement of any Proceeding without the Company's written consent unless Indemnitee shall have determined to undertake his own defense in such matter and has waived the benefits of this Agreement. The Company shall not settle any Proceeding to which Indemnitee is a party in any manner which would impose any Expense on Indemnitee without his written consent. Neither Indemnitee nor the Company shall unreasonably withhold consent to any proposed settlement. Indemnitee and the Company shall cooperate to the extent reasonably possible with each other and with the Company's insurers, in attempts to defend and/or settle any Proceeding. 8. Assumption of Defense Except as otherwise provided below, to the extent that it may wish, the Company jointly with any other indemnifying party similarly notified will be entitled to assume Indemnitee's defense in any Proceeding, with counsel mutually satisfactory to Indemnitee and the Company. After notice from the Company to Indemnitee of the Company's election so to assume such defense, the Company shall not be liable to Indemnitee under this Agreement for Expenses subsequently incurred by Indemnitee in connection with the defense thereof other than reasonable costs of investigation or as otherwise provided below. Indemnitee shall have the right to employ counsel in such Proceeding, but the fees and expenses of such counsel incurred after notice from the Company of its assumption of the defense thereof shall be at Indemnitee's expense unless: (a) The employment of counsel by Indemnitee has been authorized by the Company; (b) Counsel employed by the Company initially is unacceptable or later becomes unacceptable to Indemnitee and such unacceptability is reasonable under then existing circumstances; (c) Indemnitee shall have reasonably concluded that there may be a conflict of interest between Indemnitee and the Company in the conduct of the defense of such Proceeding; or - 4 - 6 (d) The Company shall not have employed counsel promptly to assume the defense of such Proceeding; In each of which cases the fees and expenses of counsel employed by Indemnitee shall be at the expense of the Company and subject to payment pursuant to this Agreement. The Company shall not be entitled to assume the defense of Indemnitee in any Proceeding brought by or on behalf of the Company or as to which Indemnitee shall have made either of the conclusions provided for in clauses (b) or (c) above. 9. Enforcement In the event any dispute or controversy shall arise under this Agreement between Indemnitee and the Company with respect to whether the Indemnitee is entitled to indemnification in connection with any Proceeding or with respect to any amount of Expenses incurred, then Indemnitee may seek to enforce the Agreement with respect to such dispute or controversy through legal action or, at Indemnitee's sole option and written request, through arbitration. If arbitration is requested, such dispute or controversy shall be submitted by the parties to binding arbitration in the City of Cleveland, State of Ohio, before a single arbitrator agreeable to both parties. If the parties cannot agree on a designated arbitrator within 15 days after arbitration is requested in writing by Indemnitee, the arbitration shall proceed in the City of Cleveland, State of Ohio, before an arbitrator appointed by the American Arbitration Association. In either case, the arbitration proceeding shall commence promptly under the rules then in effect of that Association and the arbitrator agreed to by the parties or appointed by that Association shall be an attorney other than an attorney who has, or is associated with a firm having associated with it an attorney which has been retained by or performed services for the Company or Indemnitee at any time during the five years preceding the commencement of the arbitration. The award shall be rendered in such form that judgment may be entered thereon in any court having jurisdic- tion thereof. The prevailing party shall be entitled to prompt reimbursement of any costs and expenses (including, without limitation, reasonable attorneys' fees) incurred in connection with such legal action or arbitration; provided that Indemnitee shall not be obligated to reimburse the Company unless the court or arbitrator which resolves the dispute determines that Indemnitee acted in bad faith in bringing such action or arbitration. 10. Exclusions Notwithstanding the scope of indemnification which may be available to Indemnitee from time to time under any Applicable Document, no indemnifica- tion, reimbursement or payment shall be required of the Company hereunder with respect to: (a) Any claim or any part thereof as to which Indemnitee shall have been determined by a court of competent jurisdiction from which no appeal is or can be taken, by clear and convincing evidence, to have acted or failed to act with deliberate intent to cause injury to the Company or with reckless disregard for the best interest of the Company. - 5 - 7 (b) Any claim or any part thereof arising under Section 16(b) of the Securities Exchange Act of 1934 pursuant to which Indemnitee shall be obligated to pay any penalty, fine, settlement or judgment; (c) Any obligation of Indemnitee based upon or attributable to the Indemnitee gaining any personal gain, profit or advantage to which he was not entitled; or (d) Any Proceeding initiated by Indemnitee without the consent or authorization of the Board of Directors of the Company, provided that this exclusion shall not apply with respect to any claims brought by Indemnitee (i) to enforce his rights under this Agreement or (ii) in any Proceeding initiated by another person or entity whether or not such claims were brought by Indemnitee against a person or entity who was otherwise a party to such Proceeding. Nothing in this Section 10 shall eliminate or diminish the Company's obligations to advance that portion of Indemnitee's Expenses which represent attorneys' fees and other costs incurred in defending any Proceeding pursuant to Section 3 of this Agreement. 11. Extraordinary Transactions The Company agrees that, in the event of any merger, consolidation or reorganization in which the Company is not the surviving entity, any sale of all or substantially all of the assets of the Company or any liquidation of the Company (each such event is hereinafter referred to as an "extraordinary transaction"), the Company shall: (a) Have the obligations of the Company under this Agreement expressly assumed by the survivor, purchaser or successor, as the case may be, in such extraordinary transaction; or (b) Otherwise adequately provide for the satisfaction of the Company's obligations under this Agreement in a manner acceptable to Indemnitee. 12. No Personal Liability Indemnitee agrees that no director, officer, employee, representative or agent of the Company shall be personally liable for the satisfaction of the Company's obligations under this Agreement, and Indemnitee shall look solely to the assets of the Company, any insurance referred to in Section 2 hereof and the assets of the Trust for satisfaction of any claims hereunder. 13. Severability If any provision, phrase or other portion of this Agreement shall be deter- mined by any court of competent jurisdiction to be invalid, illegal or unenforceable, in whole or in part, and such determination shall become final, then such provision, phrase or other portion shall be deemed to be severed or limited, but only to the extent required to render the remaining provisions and portions of the Agreement enforceable, and the Agreement as so modified shall be enforced to give effect to the intention of the parties insofar as that is possible. - 6 - 8 14. Subrogation In the event of any payment under this Agreement, the Company shall be subrogated to the extent thereof to all rights to indemnification or reimbursement against any insurer or other entity or person vested in Indemnitee, who shall execute all instruments and take all other actions as shall be reasonably necessary for the Company to enforce such rights. 15. Governing Law This Agreement shall be construed and enforced in accordance with and governed by the laws of the State of Ohio. 16. Notices All notices, requests, demands and other communications hereunder shall be in writing and shall be considered to have been duly given if delivered by hand and receipted for by the party to whom the notice, request, demand or other communication shall have been directed, or mailed by certified mail, return receipt requested, with postage prepaid: (a) If to the Company, to: CENTERIOR ENERGY CORPORATION 6200 Oak Tree Boulevard Post Office Box 94661 Independence, Ohio 44101-4661; and (b) If to Indemnitee, at the address stated below the name of Indemnitee at the end of this Agreement. or to such other or further address as shall be designated from time to time by the Company or Indemnitee to the other. 17. Termination This Agreement may be terminated by either party upon not less than 60 days prior written notice delivered to the other party, but such termination shall not in any way diminish the obligations of Company hereunder (or Indemnitee's right under the Trust) with respect to Indemnitee's activities prior to the effective date of termination; provided, that if this Agreement has been entered into by the Company before it shall have been authorized by the share owners of the Company at its 1987 annual meeting, it shall terminate automatically and be void ab initio if the share owners of the Company shall not have ratified this Agreement at such annual meeting. 18. Amendments and Binding Effect This Agreement and the rights and duties of Indemnitee and the Company hereunder may not be amended, modified or terminated except by written instrument signed and delivered by the parties hereto. This Agreement is and shall be binding upon and shall inure to the benefit of the parties thereto and their respective heirs, executors, administrators, successors and assigns. - 7 - 9 In Witness Whereof, the undersigned have executed this Agreement in triplicate on the _____________ day of ___________________, ____, effective as of the _____________ day of ___________________, ____. INDEMNITEE: CENTERIOR ENERGY CORPORATION ____________________________________ Title: ____________________________ By: _________________________________ Signed: ___________________________ Title: ______________________________ Address: __________________________ Signed: _____________________________ ____________________________________ ____________________________________ - 8 - 10 CENTERIOR ENERGY CORPORATION DIRECTOR OR OFFICER INDEMNITY AGREEMENT UNDERTAKING TO REIMBURSE PAYMENT OF EXPENSES This Undertaking has been entered into by the Indemnitee whose name appears above his signature below (hereinafter "Indemnitee") pursuant to an Indemnity Agreement dated the date set forth below (the "Indemnity Agreement") between Centerior Energy Corporation (hereinafter "Company"), an Ohio corporation and Indemnitee. WITNESSETH: Whereas, pursuant to the Indemnity Agreement, Company agreed to pay Expenses (within the meaning of the Indemnity Agreement) as and when incurred by Indemnitee in connection with any claim against Indemnitee which is the subject of any threatened, asserted, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative, to which Indemnitee was, is or is threatened to be made a party by reason of facts which include Indemnitee's being or having been a director or officer of the Company and/or as a person who is serving or has served on behalf of the Company as a director, officer, employee, agent or trustee of another corporation, partnership, joint venture, trust or other enterprise, domestic or foreign, in which the Company has a direct or indirect ownership interest; and Whereas, such a claim has arisen against Indemnitee (hereinafter the "Proceeding"), Indemnitee has notified Company of the Proceeding in accordance with the terms of Section 6 of the Indemnity Agreement and a copy of the Proceeding and notice are attached hereto as Exhibits A and B, respectively. Now, Therefore, Indemnitee hereby agrees that in consideration of Company's advance payment of Indemnitee's Expenses incurred prior to a final disposition of the Proceeding, Indemnitee hereby undertakes to reimburse Company for any and all Expenses paid by Company on behalf of Indemnitee prior to a final disposition of the Proceeding in the event that Indemnitee is determined under the Applicable Document (within the meaning of the Indemnity Agreement) to be required to repay such amounts to the Company pursuant to the Indemnity Agreement and applicable law, provided that if Indemnitee is entitled under the Applicable Document to indemnification for some or a portion of such Expenses, Indemnitee's obligation to reimburse Company shall apply only to those Expenses which Indemnitee is so determined to be required to repay. Such reimbursement or arrangements for reimbursement by Indemnitee shall be consummated within 90 days after a determination that Indemnitee is so required to repay such amounts to the Company pursuant to the Indemnity Agreement and applicable law. The Indemnitee agrees to reasonably cooperate with the Company concerning such Proceeding. - 9 - 11 In Witness Whereof, the undersigned has set his hand this _____________ day of ______________________, 19__. Date of Indemnity Agreement: INDEMNITEE: ________________________________ ______________________________________ Signed: _____________________________ - 10 - EX-23.A 8 EXHIBIT FOR CEC 1 EXHIBIT 23a (CEC) CENTERIOR ENERGY CORPORATION CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report on the consolidated financial statements and schedules of Centerior Energy Corporation dated February 14, 1994, included in this Form 10-K, into Centerior Energy Corporation's previously filed Registration Statements, File Nos. 33-4788, 33-9736, 33-47231 and 33-49957. ARTHUR ANDERSEN & CO. Cleveland, Ohio March 28, 1994 EX-23.B 9 EXHIBIT FOR CEC 1 Exhibit 23b(CEC) CONSENT OF COUNSEL FOR CENTERIOR ENERGY CORPORATION The statements as to matters of law and legal conclusions under the headings "General Regulation", "Environmental Regulation" and "Electric Rates" in Item 1. and "Title to Property" in Item 2. and under Item 3. of the Centerior Energy Corporation Annual Report on Form 10-K for the year ended December 31, 1993 have been prepared under my supervision and reviewed by me and in my opinion such respective statements as to such matters are correct. I hereby consent to the use of my name in connection with the statements I have reviewed as stated in the preceding paragraph and to the incorporation by reference of those statements into the respective Prospectuses now and hereafter constituting parts of the Registration Statements previously filed by Centerior Energy Corporation under File Nos. 33-4788, 33-9736, 33-47231 and 33-49957 and to the reference to me under the heading "Experts" in such Prospectuses. TERRENCE G. LINNERT Terrence G. Linnert Vice President - Legal & Governmental Affairs of Centerior Service Company March 29, 1994 EX-24.B 10 EXHIBIT FOR CEC 1 Exhibit 24b(CEC) POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF ----------------------------------------------- CENTERIOR ENERGY CORPORATION ---------------------------- The undersigned, being a director or officer or both (as stated under his or her signature below) of Centerior Energy Corporation, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum, as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 16th day of March, 1994. PAUL G. BUSBY --------------------------- Paul G. Busby Controller RUTH A. HARNER Signed and acknowledged in the presence of: ----------------------- 2 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF ----------------------------------------------- CENTERIOR ENERGY CORPORATION ---------------------------- The undersigned, being a director or officer or both (as stated under his or her signature below) of Centerior Energy Corporation, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum, as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 24th day of March, 1994. RICHARD P. ANDERSON -------------------------- Richard P. Anderson Director JOANNE KAPNICK Signed and acknowledged in the presence of: --------------------- 3 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF ----------------------------------------------- CENTERIOR ENERGY CORPORATION ---------------------------- The undersigned, being a director or officer or both (as stated under his or her signature below) of Centerior Energy Corporation, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum, as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 21 day of March, 1994. A. C. BERSTICKER ----------------------------- Albert C. Bersticker Director CAROLYN T. SIEKANIEC Signed and acknowledged in the presence of: -------------------------- 4 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF ----------------------------------------------- CENTERIOR ENERGY CORPORATION ---------------------------- The undersigned, being a director or officer or both (as stated under his or her signature below) of Centerior Energy Corporation, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum, as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 21 day of March, 1994. LEIGH CARTER ----------------------------- Leigh Carter Director JEAN C. BROOKS Signed and acknowledged in the presence of: -------------------------- 5 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF ----------------------------------------------- CENTERIOR ENERGY CORPORATION ---------------------------- The undersigned, being a director or officer or both (as stated under his or her signature below) of Centerior Energy Corporation, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum, as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 21 day of March, 1994. THOMAS A. COMMES -------------------------- Thomas A. Commes Director KATHY SCHIEKE Signed and acknowledged in the presence of: -------------------------- 6 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF ----------------------------------------------- CENTERIOR ENERGY CORPORATION ---------------------------- The undersigned, being a director or officer or both (as stated under his or her signature below) of Centerior Energy Corporation, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum, as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 24th day of March, 1994. WAYNE R. EMBRY ------------------------------ Wayne R. Embry Director JUDITH A. BERGER Signed and acknowledged in the presence of: -------------------------- 7 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF ----------------------------------------------- CENTERIOR ENERGY CORPORATION ---------------------------- The undersigned, being a director or officer or both (as stated under his or her signature below) of Centerior Energy Corporation, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum, as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 22 day of March, 1994. GEORGE H. KAULL ------------------------------ George H. Kaull Director E. LYLE PEPIN Signed and acknowledged in the presence of: -------------------------- 8 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF ----------------------------------------------- CENTERIOR ENERGY CORPORATION ---------------------------- The undersigned, being a director or officer or both (as stated under his or her signature below) of Centerior Energy Corporation, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum, as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 18 day of March, 1994. RICHARD A. MILLER ----------------------------------- Richard A. Miller Director LAVERNE STOKOWSKI Signed and acknowledged in the presence of: -------------------------- 9 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF ----------------------------------------------- CENTERIOR ENERGY CORPORATION ---------------------------- The undersigned, being a director or officer or both (as stated under his or her signature below) of Centerior Energy Corporation, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum, as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 21 day of March, 1994. FRANK E. MOSIER --------------------------------- Frank E. Mosier Director E. LYLE PEPIN Signed and acknowledged in the presence of: -------------------------- 10 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF ----------------------------------------------- CENTERIOR ENERGY CORPORATION ---------------------------- The undersigned, being a director or officer or both (as stated under his or her signature below) of Centerior Energy Corporation, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum, as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 23 day of March, 1994. SISTER MARY MARTHE REINHARD, SND ---------------------------------------- Sister Mary Marthe Reinhard, SND Director PATRICIA TECKMAN Signed and acknowledged in the presence of: -------------------------- 11 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF ----------------------------------------------- CENTERIOR ENERGY CORPORATION ---------------------------- The undersigned, being a director or officer or both (as stated under his or her signature below) of Centerior Energy Corporation, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum, as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 29th day of March, 1994. ROBERT C. SAVAGE ------------------------------- Robert C. Savage Director E. LYLE PEPIN Signed and acknowledged in the presence of: -------------------------- 12 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF ----------------------------------------------- CENTERIOR ENERGY CORPORATION ---------------------------- The undersigned, being a director or officer or both (as stated under his or her signature below) of Centerior Energy Corporation, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum, as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 22nd day of March, 1994. WILLIAM J. WILLIAMS ----------------------------------- William J. Williams Director SARA J. WILLIAMS Signed and acknowledged in the presence of: -------------------------- 13 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF ----------------------------------------------- CENTERIOR ENERGY CORPORATION ---------------------------- The undersigned, being a director or officer or both (as stated under his or her signature below) of Centerior Energy Corporation, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum, as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 22nd day of March, 1994. ROBERT J. FARLING ----------------------------------- Robert J. Farling Chairman, President and Chief Executive Officer and Director PEGGY KELLY Signed and acknowledged in the presence of: -------------------------- 14 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF ----------------------------------------------- CENTERIOR ENERGY CORPORATION ---------------------------- The undersigned, being a director or officer or both (as stated under his or her signature below) of Centerior Energy Corporation, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum, as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 18th day of March, 1994. GARY R. LEIDICH -------------------------------- Gary R. Leidich Vice President and Chief Financial Officer J. T. PERCIO Signed and acknowledged in the presence of: -------------------------- EX-3.A 11 EXHIBIT FOR CEI 1 Exhibit 3a(CEI) THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AMENDED ARTICLES OF INCORPORATION EFFECTIVE MARCH 30, 1994 2 AMENDED ARTICLES OF INCORPORATION OF THE CLEVELAND ELECTRIC ILLUMINATING COMPANY Effective March 30, 1994 ARTICLE ONE. The name of the Corporation shall be The Cleveland Electric Illuminating Company. ARTICLE TWO. The place in the State of Ohio where the principal office of the Corporation shall be located is the City of Cleveland in the County of Cuyahoga. ARTICLE THREE. The purposes for which the Corporation is formed are as follows: A. To manufacture, generate, develop, create and produce from any source and by any means, and to purchase, otherwise acquire, use, transmit, transport, distribute, sell, exchange, lease as lessor or as lessee, otherwise dispose of, grant licenses with respect to, furnish any kind of service by means of and engage in research with respect to, any kind or form of electricity, energy, radiation, light, refrigera- tion, heat, water, steam, gas and fuel; B. To purchase, otherwise acquire, hold, use, improve, develop, build, manufacture, repair, sell, exchange, encumber, lease as lessor or as lessee, otherwise dispose of, grant licenses with respect to, furnish any kind of service by means of and engage in research with respect to, any kind or form of tangible and intangible personal property and any kind or form of real estate, interests therein, buildings and structures; C. To purchase, otherwise acquire, hold, sell, assign, exchange, encumber and otherwise dispose of shares of stock and other securities of whatever nature issued by other corporations, govern- ments, firms, trusts and individuals, both domestic and foreign; and D. To do any and all things and transact any and all business incidental to the foregoing. ARTICLE FOUR. The authorized number of shares of the Corporation is 112,000,000 consisting of 4,000,000 shares of Serial Preferred Stock without par value (hereinafter called "Serial Preferred Stock"), 3,000,000 shares of Preference Stock without par value (hereinafter called "Preference Stock") and 105,000,000 shares of Common Stock without par value (hereinafter called "Common Stock"). - 1 - 3 DIVISION A The Serial Preferred Stock shall have the following express terms: {Section 1. Series.} The Serial Preferred Stock may be issued from time to time in one or more series. All shares of Serial Preferred Stock shall be of equal rank and shall be identical, except in respect of the matters that may be fixed by the Board of Directors as hereinafter provided, and each share of a series shall be identical with all other shares of such series, except as to the date from which dividends are cumulative. Subject to the provisions of Sections 2 to 7, both inclusive, of this Division, which provisions shall apply to all Serial Preferred Stock, the Board of Directors hereby is authorized to cause such shares to be issued in one or more series and with respect to each such series to determine and fix prior to the issuance thereof (and thereafter, to the extent provided in clause (b) of this Section) the following: (a) The designation of the series, which may be by distinguishing number, letter or title; (b) The number of shares of the series, which number the Board of Directors may (except where otherwise provided in the creation of the series) increase or decrease from time to time before or after the issuance thereof (but not below the number of shares thereof then outstanding); (c) The annual dividend rate or rates of the series; (d) The dates on which and the period or periods for which dividends, if declared, shall be payable and the date or dates from which dividends shall accrue and be cumulative; (e) The redemption rights and price or prices, if any, for shares of the series; (f) The terms and amount of the sinking fund, if any, for the purchase or redemption of shares of the series; (g) The amounts payable on shares of the series in the event of any voluntary or involuntary liquidation, dissolution or winding up of the affairs of the Corporation; (h) Whether the shares of the series shall be convertible into Common Stock or shares of any other class and, if so, the conversion rate or rates or price or prices, any adjustments thereof and all other terms and conditions upon which such conversion may be made; and (i) Restrictions (in addition to those set forth in Sections 5(c) and 5(d) of this Division) on the issuance of shares of the same series or of any other class or series. - 2 - 4 The Board of Directors is authorized to adopt from time to time amendments to the Amended Articles of Incorporation fixing, with respect to each such series, the matters described in clauses (a) to (i), both inclusive, of this Section. {Section 2. Dividends.} (a) The holders of Serial Preferred Stock of each series, in preference to the holders of Common Stock and of any other class of shares ranking junior to the Serial Preferred Stock, shall be entitled to receive out of any funds legally available and when and as declared by the Board of Directors, dividends in cash at the rate or rates for such series fixed in accordance with the provisions of Section 1 of this Division and no more, payable on the dates fixed for such series. Such dividends shall be cumulative, in the case of shares of each particular series, from and after the date or dates fixed with respect to such series. No dividends shall be paid upon or declared or set apart for any series of the Serial Preferred Stock for any dividend period unless at the same time a like proportionate dividend for the dividend periods terminating on the same or any earlier date, ratably in proportion to the respective annual dividend rates fixed therefor, shall have been paid upon or declared or set apart for all Serial Preferred Stock of all series then issued and outstanding and entitled to receive such dividend. (b) So long as any Serial Preferred Stock shall be outstanding no dividend, except a dividend payable in Common Stock or other shares ranking junior to the Serial Preferred Stock, shall be paid or declared or any distribution be made, except as aforesaid, in re- spect of the Common Stock or any other shares ranking junior to the Serial Preferred Stock, nor shall any Common Stock or any other shares ranking junior to the Serial Preferred Stock be purchased, retired or otherwise acquired by the Corporation, except out of the proceeds of the sale of Common Stock or other shares of the Corporation ranking junior to the Serial Preferred Stock received by the Corporation subsequent to the date of first issuance of Serial Preferred Stock of any series, unless: (1) All accrued and unpaid dividends on Serial Preferred Stock, including the full dividends for all current dividend periods, shall have been declared and paid or a sum sufficient for payment thereof set apart; and (2) There shall be no arrearages with respect to the redemption of Serial Preferred Stock of any series from any sinking fund provided for shares of such series in accordance with the provisions of Section 1 of this Division. - 3 - 5 {Section 3. Redemption.} (a) Subject to the express terms of each series and to the provisions of Section 5(c)(3) of this Division, the Corporation: (1) May, from time to time at the option of the Board of Directors, redeem all or any part of any redeemable series of Serial Preferred Stock at the time outstanding at the applicable redemption price for such series fixed in accordance with the provisions of Section 1 of this Division; and (2) Shall, from time to time, make such redemptions of each series of Serial Preferred Stock as may be required to fulfill the requirements of any sinking fund provided for shares of such series at the applicable sinking fund redemption price fixed in accordance with the provisions of Section 1 of this Division; and shall in each case pay all accrued and unpaid dividends to the redemption date. (b) (1) Notice of every such redemption shall be mailed, postage pre- paid, to the holders of record of the Serial Preferred Stock to be redeemed at their respective addresses then appearing on the books of the Corporation, not less than 30 days nor more than 60 days prior to the date fixed for such redemption, or such other time prior thereto as the Board of Directors shall fix for any series pursuant to Section 1(e) of this Division prior to the issuance thereof. At any time after notice as provided above has been deposited in the mail, the Corporation may deposit the aggregate redemption price of the shares of Serial Preferred Stock to be redeemed, together with accrued and unpaid dividends thereon to the redemption date, with any bank or trust company in Cleveland, Ohio or New York, New York, having capital and surplus of not less than $25,000,000, named in such notice, directed to be paid to the respective holders of the shares of Serial Preferred Stock so to be redeemed, in amounts equal to the redemption price of all shares of Serial Preferred Stock so to be redeemed, on surrender of the stock certificate or certificates held by such holders; and upon the deposit of such notice in the mail and the making of such deposit of money with such bank or trust company, such holders shall cease to be shareholders with respect to such shares; and from and after the time such notice shall have been so deposited and such deposit of money shall have been so made, such holders shall have no interest or claim against the Corporation with respect to such shares, except only the right to receive such money from such bank or trust company without interest or to exercise, before the redemption date, any unex- pired privileges of conversion. In the event less than all of the outstanding shares of Serial Preferred Stock are to be redeemed, the Corporation shall select by lot the shares so to be redeemed in such manner as shall be prescribed by the Board of Directors. - 4 - 6 (2) If the holders of shares of Serial Preferred Stock which have been called for redemption shall not, within 6 years after such deposit, claim the amount deposited for the redemption thereof, any such bank or trust company shall, upon demand, pay over to the Corporation such unclaimed amounts and thereupon such bank or trust company and the Corporation shall be re- lieved of all responsibility in respect thereof and to such holders. (c) Any shares of Serial Preferred Stock which are (1) redeemed by the Corporation pursuant to the provisions of this Section, (2) pur- chased and delivered in satisfaction of any sinking fund require- ments provided for shares of such series, (3) converted in accordance with the express terms thereof, or (4) otherwise acquired by the Corporation, shall resume the status of authorized but unissued shares of Serial Preferred Stock without serial designation. {Section 4. Liquidation.} (a) (1) The holders of Serial Preferred Stock of any series shall, in the event of voluntary or involuntary liquidation, dissolution or winding up of the affairs of the Corporation, be entitled to receive in full out of the assets of the Corporation, including its capital, before any amount shall be paid or distributed among the holders of the Common Stock or any other shares rank- ing junior to the Serial Preferred Stock, the amounts fixed with respect to shares of such series in accordance with Section 1 of this Division, plus an amount equal to all dividends accrued and unpaid thereon to the date of payment of the amount due pursuant to such liquidation, dissolution or winding up of the affairs of the Corporation. In the event the net assets of the Corporation legally available therefor are insufficient to permit the payment upon all outstanding shares of Serial Preferred Stock of the full preferential amount to which they are respectively entitled, then such net assets shall be distributed ratably upon outstanding shares of Serial Preferred Stock in proportion to the full preferential amount to which each such share is entitled. (2) After payment to the holders of Serial Preferred Stock of the full preferential amounts as aforesaid, the holders of Serial Preferred Stock, as such, shall have no right or claim to any of the remaining assets of the Corporation. (b) The merger or consolidation of the Corporation into or with any other corporation, the merger of any other corporation into it, or the sale, lease or conveyance of all or substantially all the property or business of the Corporation, shall not be deemed to be a dissolution, liquidation or winding up for the purposes of this Section. - 5 - 7 {Section 5. Voting.} (a) The holders of Serial Preferred Stock shall have no voting rights, except as provided in this Section or required by law. (b) (1) If, and so often as, the Corporation shall be in default in the payment of the equivalent of the full dividends for a number of dividend payment periods (whether or not consecutive) which in the aggregate contain at least 540 days on any series of Serial Preferred Stock at the time outstanding, whether or not earned or declared, the holders of Serial Preferred Stock of all series, voting separately as a class, shall be entitled to elect, as herein provided, two members of the Board of Directors of the Corporation; provided, however, that the holders of shares of Serial Preferred Stock shall not have or exercise such special class voting rights except at meetings of such shareholders for the election of Directors at which the holders of not less than 50% of the outstanding shares of Serial Preferred Stock of all series then outstanding are present in person or by proxy; and provided further that the special class voting rights provided for in this paragraph when the same shall have become vested shall remain so vested until all accrued and unpaid dividends on the Serial Preferred Stock of all series then outstanding shall have been paid, whereupon the holders of Serial Preferred Stock shall be divested of their special class voting rights in respect of subsequent elections of Directors, subject to the revesting of such special class voting rights in the event hereinabove specified in this paragraph. (2) In the event of default entitling the holders of Serial Preferred Stock to elect two Directors as specified in Paragraph (1) of this Subsection, a special meeting of such holders for the purpose of electing such Directors shall be called by the Secretary of the Corporation upon written request of, or may be called by, the holders of record of at least 10% of the shares of Serial Preferred Stock of all series at the time outstanding, and notice thereof shall be given in the same manner as that required for the annual meeting of shareholders; provided, however, that the Corporation shall not be required to call such special meeting if the annual meeting of share- holders shall be held within 120 days after the date of receipt of the foregoing written request from the holders of Serial Preferred Stock. At any meeting at which the holders of Serial Preferred Stock shall be entitled to elect Directors, the holders of 50% of the then outstanding shares of Serial Preferred Stock of all series, present in person or by proxy, shall be sufficient to constitute a quorum, and the vote of the holders of a majority of such shares so present at any such meeting at which there shall be such a quorum shall be sufficient to elect the members of the Board of Directors which the holders of Serial Preferred Stock are entitled to elect as - 6 - 8 hereinabove provided. Notwithstanding any provision of these Amended Articles of Incorporation or the Regulations of the Corporation or any action taken by the holders of any class of shares fixing the number of Directors of the Corporation, the two Directors who may be elected by the holders of Serial Preferred Stock pursuant to this Subsection shall serve in addition to any other Directors then in office or proposed to be elected otherwise than pursuant to this Subsection. Nothing in this Subsection shall prevent any change otherwise permitted in the total number of Directors of the Corporation or require the resignation of any Director elected otherwise than pursuant to this Subsection. Notwithstanding any classification of the other Directors of the Corporation, the two Directors elected by the holders of Serial Preferred Stock shall be elected annually for the terms expiring at the next succeeding annual meeting of shareholders. (c) The affirmative vote or consent of the holders of at least two- thirds of the shares of Serial Preferred Stock at the time outstand- ing, voting or consenting separately as a class, given in person or by proxy either in writing or at a meeting called for the purpose, shall be necessary to effect any one or more of the following (but so far as the holders of Serial Preferred Stock are concerned, such action may be effected with such vote or consent): (1) Any amendment, alteration or repeal of any of the provisions of the Amended Articles of Incorporation or of the Regulations of the Corporation which affects adversely the preferences or vot- ing or other rights of the holders of Serial Preferred Stock; provided, however, that for the purpose of this paragraph only, neither the amendment of the Amended Articles of Incorporation so as to authorize, create or change the authorized or out- standing amount of Serial Preferred Stock or of any shares of any class ranking on a parity with or junior to the Serial Preferred Stock nor the amendment of the provisions of the Regulations so as to change the number of directors of the Corporation shall be deemed to affect adversely the preferences or voting or other rights of the holders of Serial Preferred Stock; and provided further, that if such amendment, alteration or repeal affects adversely the preferences or voting or other rights of one or more but not all series of Serial Preferred Stock at the time outstanding, only the affirmative vote or consent of the holders of at least two-thirds of the number of the shares at the time outstanding of the series so affected shall be required; (2) The authorization, creation or the increase in the authorized amount of any shares of any class or any security convertible into shares of any class, in either case ranking prior to the Serial Preferred Stock; or - 7 - 9 (3) The purchase or redemption (for sinking fund purposes or other- wise) of less than all of the Serial Preferred Stock then out- standing except in accordance with a stock purchase offer made to all holders of record of Serial Preferred Stock, unless all dividends on all Serial Preferred Stock then outstanding for all previous dividend periods shall have been declared and paid or funds therefor set apart and all accrued sinking fund obligations applicable thereto shall have been complied with. (d) The affirmative vote or consent of the holders of at least a majority of the shares of Serial Preferred Stock at the time outstanding, voting or consenting separately as a class, given in person or by proxy either in writing or at a meeting called for the purpose, shall be necessary to effect any one or more of the following (but so far as the holders of Serial Preferred Stock are concerned, such action may be effected with such vote or consent): (1) The sale, lease or conveyance by the Corporation of all or substantially all of its property or business; (2) The consolidation of the Corporation with or its merger into any other corporation, unless the corporation resulting from such consolidation or surviving such merger will not have after such consolidation or merger any class of shares either authorized or outstanding ranking prior to or on a parity with the Serial Preferred Stock except the same number of shares ranking prior to or on a parity with the Serial Preferred Stock and having the same rights and preferences as the shares of the Corporation authorized and outstanding immediately preceding such consolidation or merger (and each holder of Serial Preferred Stock immediately preceding such consolidation or merger shall receive the same number of shares with the same rights and preferences of the resulting or surviving corporation); or (3) The authorization of any shares ranking on a parity with the Serial Preferred Stock or an increase in the authorized number of shares of Serial Preferred Stock. (e) Neither the vote, consent nor any adjustment of the voting rights of holders of shares of Serial Preferred Stock shall be required for an increase in the number of shares of Common Stock authorized or issued or for stock splits of the Common Stock or for stock dividends on any class of stock payable solely in Common Stock; and none of the foregoing actions shall be deemed to affect adversely the preferences or voting or other rights of Serial Preferred Stock within the meaning and for the purpose of this Division. {Section 6. Pre-emptive Rights.} No holder of Serial Preferred Stock, as such, shall have any pre-emptive right to purchase, have offered to him for purchase or subscribe for any of the Corporation's shares or other securities of any class, whether now or hereafter authorized. - 8 - 10 {Section 7. Definitions.} For the purposes of this Division: (a) Whenever reference is made to shares "ranking prior to the Serial Preferred Stock", such reference shall mean and include all shares of the Corporation in respect of which the rights of the holders thereof as to the payment of dividends or as to distributions in the event of a voluntary or involuntary liquidation, dissolution or winding up of the affairs of the Corporation are given preference over the rights of the holders of Serial Preferred Stock; (b) Whenever reference is made to shares "on a parity with the Serial Preferred Stock", such reference shall mean and include all shares of the Corporation in respect of which the rights of the holders thereof as to the payment of dividends and as to distributions in the event of a voluntary or involuntary liquidation, dissolution or winding up of the affairs of the Corporation rank on an equality (except as to the amounts fixed therefor) with the rights of the holders of Serial Preferred Stock; and (c) Whenever reference is made to shares "ranking junior to the Serial Preferred Stock", such reference shall mean and include all shares of the Corporation other than those defined under Subsections (a) and (b) of this Section as shares "ranking prior to" or "on a parity with" the Serial Preferred Stock. {Section 8. Serial Preferred Stock, $7.40 Series A.} Of the 4,000,000 authorized shares of Serial Preferred Stock, 500,000 shares are designated as a series entitled "Serial Preferred Stock, $7.40 Series A" (hereinafter called "Series A Stock"). The Series A Stock shall have the express terms set forth in this Division as being applicable to all shares of Serial Preferred Stock as a class, and, in addition, the following express terms applicable to all shares of Series A Stock as a series of the Serial Preferred Stock: (a) The annual dividend rate of the Series A Stock shall be $7.40 per share. (b) Dividends on Series A Stock shall be payable, if declared, quarterly on the first day of March, June, September and December of each year, the first quarterly dividend being payable, if declared, on March 1, 1972. (c) Dividends on Series A Stock shall be cumulative as follows: (1) With respect to shares included in the initial issue of Series A Stock and shares issued any time thereafter up to and includ- ing the record date for the payment of the first dividend on the initial issue of Series A Stock, dividends shall be cumulative from the date of the initial issue of Series A Stock; and - 9 - 11 (2) With respect to shares issued any time after the aforesaid record date, dividends shall be cumulative from the dividend payment date next preceding the date of issue of such shares, except that if such shares are issued during the period com- mencing the day after the record date for the payment of a dividend on Series A Stock and ending on the payment date of that dividend, dividends with respect to such shares shall be cumulative from that dividend payment date. (d) Subject to the provisions of Section 5(c)(3) of this Division, Series A Stock shall be redeemable in the manner provided in Sections 3(b)(1) and (2) of this Division, at any time or from time to time, at the option of the Board of Directors, upon payment of $107.50 per share if redeemed on any date prior to December 1, 1976, $105.00 per share if redeemed on or after the date last stated and prior to December 1, 1981, $102.50 per share if redeemed on or after the date last stated and prior to December 1, 1986, and $101.00 per share if redeemed on or after the date last stated, plus in each case an amount equal to all dividends accrued and unpaid thereon to the date of redemption; provided, however, that Series A Stock may not be redeemed prior to December 1, 1976, directly or indirectly as a part of or in anticipation of any refunding of Series A Stock involving the incurring of indebtedness or the issuance of shares of Serial Preferred Stock or any other shares ranking prior to or on a parity with the Serial Preferred Stock if the interest on such indebtedness or the dividends on such shares result in an effective cost to the Corporation of less than 7.49% per year. (e) The amount payable per share on Series A Stock in the event of any voluntary liquidation, dissolution or winding up of the affairs of the Corporation shall be the redemption price then in effect as set forth in Subsection (d) of this Section and in the event of any in- voluntary liquidation, dissolution or winding up of the affairs of the Corporation shall be $100.00, plus in each case an amount equal to all dividends accrued and unpaid thereon to the date of payment of the amount due pursuant to this Subsection. {Section 9. Serial Preferred Stock, $7.56 Series B.} Of the 4,000,000 authorized shares of Serial Preferred Stock, 450,000 shares are designated as a series entitled "Serial Preferred Stock, $7.56 Series B" (hereinafter called "Series B Stock"). The Series B Stock shall have the express terms set forth in this Division as being applicable to all shares of Serial Preferred Stock as a class, and, in addition, the following express terms applicable to all shares of Series B Stock as a series of the Serial Preferred Stock: (a) The annual dividend rate of the Series B Stock shall be $7.56 per share. (b) Dividends on Series B Stock shall be payable, if declared, quarterly on the first day of January, April, July and October of each year, the first quarterly dividend being payable, if declared, on October 1, 1972. - 10 - 12 (c) Dividends on Series B Stock shall be cumulative as follows: (1) With respect to shares included in the initial issue of Series B Stock and shares issued any time thereafter up to and includ- ing the record date for the payment of the first dividend on the initial issue of Series B Stock, dividends shall be cumulative from the date of the initial issue of Series B Stock; and (2) With respect to shares issued any time after the aforesaid record date, dividends shall be cumulative from the dividend payment date next preceding the date of issue of such shares, except that if such shares are issued during the period com- mencing the day after the record date for the payment of a dividend on Series B Stock and ending on the payment date of that dividend, dividends with respect to such shares shall be cumulative from that dividend payment date. (d) Subject to the provisions of Section 5(c)(3) of this Division, Series B Stock shall be redeemable in the manner provided in Sections 3(b)(1) and (2) of this Division, at any time or from time to time, at the option of the Board of Directors, upon payment of $108.76 per share if redeemed on any date prior to August 1, 1977, $106.35 per share if redeemed on or after the date last stated and prior to August 1, 1982, $103.78 per share if redeemed on or after the date last stated and prior to August 1, 1987, and $102.26 per share if redeemed on or after the date last stated, plus in each case an amount per share equal to all dividends accrued and unpaid thereon to the date of redemption; provided, however, that Series B Stock may not be redeemed prior to August 1, 1977, directly or in- directly as a part of or in anticipation of any refunding of Series B Stock involving the incurring of indebtedness or the issuance of shares of Serial Preferred Stock or any other shares ranking prior to or on a parity with the Serial Preferred Stock if the interest on such indebtedness or the dividends on such shares result in an effective cost to the Corporation of less than 7.55% per year. (e) The amount payable per share on Series B Stock in the event of any voluntary liquidation, dissolution or winding up of the affairs of the Corporation shall be the redemption price then in effect as set forth in Subsection (d) of this Section and in the event of any involuntary liquidation, dissolution or winding up of the affairs of the Corporation shall be $100.00, plus in each case an amount equal to all dividends accrued and unpaid thereon to the date of payment of the amount due pursuant to this Subsection. - 11 - 13 {Section 10. Serial Preferred Stock, $7.35 Series C.} Of the 4,000,000 authorized shares of Serial Preferred Stock, 250,000 shares are designated as a series entitled "Serial Preferred Stock, $7.35 Series C" (hereinafter called "Series C Stock"). The Series C Stock shall have the express terms set forth in this Division as being applicable to all shares of Serial Preferred Stock as a class, and, in addition, the following express terms applicable to all shares of Series C Stock as a series of the Serial Preferred Stock: (a) The annual dividend rate of the Series C Stock shall be $7.35 per share. (b) Dividends on Series C Stock shall be payable, if declared, quarterly on the first day of February, May, August and November of each year, the first quarterly dividend being payable, if declared, on November 1, 1973, to the extent then accrued. (c) Dividends on Series C Stock shall be cumulative from the date of initial issue. (d) Subject in each case to the provisions of Section 5(c)(3) of this Division, Series C Stock shall be redeemable in the manner provided in Sections 3(b)(1) and (2) of this Division, and as follows: (1) The Series C Stock shall be redeemed in part from time to time for the Sinking Fund as hereinafter set forth at a redemption price of $100.00 per share, plus in each case an amount per share equal to all dividends accrued and unpaid thereon to the date of redemption (such price plus such amount being herein- after called the "Sinking Fund Redemption Price"). As and for a Sinking Fund for the Series C Stock, so long as and to the extent that any shares thereof are outstanding, the Corporation will redeem on each August 1 (hereinafter called "Sinking Fund Date") commencing with August 1, 1984, 10,000 shares of Series C Stock at the Sinking Fund Redemption Price (the Corporation's obligation to redeem such number of such shares on any Sinking Fund Date being hereinafter referred to as the "Sinking Fund Obligation"). Such redemption shall be mandatory, subject to any applicable restrictions of law, and not optional to the Corporation. If the Corporation shall for any reason fail to discharge its Sinking Fund Obligation on any Sinking Fund Date, such Sinking Fund Obligation to the extent not discharged shall, without prejudice to any other right or remedy, become an additional Sinking Fund Obligation for each succeeding Sinking Fund Date until fully discharged. (2) On each Sinking Fund Date so long as and to the extent that Series C Stock shall be outstanding, and provided that the Corporation has fulfilled its Sinking Fund Obligation on such date, the Corporation may at the option of the Board of Directors redeem up to but not in excess of 10,000 additional shares of Series C Stock at the redemption price of $100.00 per share plus in each case an amount per share equal to all - 12 - 14 dividends accrued and unpaid thereon to the date of redemption; provided, however, that no more than 83,000 shares of Series C Stock in the aggregate may be redeemed pursuant to this Subsection (d)(2). (3) The Corporation at the option of the Board of Directors may at any time and from time to time redeem all or any part of the outstanding Series C Stock upon payment of $110.00 per share if redeemed on any date prior to August 1, 1983, $103.00 per share if redeemed on or after the date last stated and prior to August 1, 1988, and $101.00 per share if redeemed on or after August 1, 1988, plus in each case an amount per share equal to all dividends accrued and unpaid thereon to the date of redemp- tion; provided, however, that Series C Stock may not be re- deemed prior to August 1, 1978, directly or indirectly (i) as a part of or in anticipation of any refunding of Series C Stock involving the borrowing of funds or the issuance of shares of Serial Preferred Stock or any other shares ranking prior to or on a parity with the Serial Preferred Stock if the interest on such borrowed funds or the dividends on such shares result in an effective cost to the Corporation of less than 7.35% per year, or (ii) from proceeds derived from the sale of equity securities junior to Series C Stock. (4) On August 1, 2008, the Corporation shall redeem all remaining shares of Series C Stock, if any, then outstanding at the redemption price of $100.00 per share plus in each case an amount per share equal to all dividends accrued and unpaid thereon to the date of redemption. (e) The amount payable per share on Series C Stock in the event of any voluntary liquidation, dissolution or winding up of the affairs of the Corporation shall be the redemption price then in effect as set forth in Subsection (d)(3) of this Section and in the event of any involuntary liquidation, dissolution or winding up of the affairs of the Corporation shall be $100.00, plus in each case an amount equal to all dividends accrued and unpaid thereon to the date of payment of the amount due pursuant to this Subsection. (f) The number of shares of Series C Stock shall not be increased above, and shall not exceed 250,000. Series C Stock once redeemed shall not be reissued as shares of Series C Stock, but, having been restored to the status of authorized but unissued shares of Serial Preferred Stock without serial designation, may, in whole or in part, be, or be included in, any subsequent series of Serial Preferred Stock of a new designation with such express terms as may be fixed by the Board of Directors of the Corporation. - 13 - 15 {Section 11. Serial Preferred Stock, $12.00 Series D.} Redeemed June 16, 1978. {Section 12. Serial Preferred Stock, $88.00 Series E.} Of the 4,000,000 authorized shares of Serial Preferred Stock, 60,000 shares are designated as a series entitled "Serial Preferred Stock, $88.00 Series E" (hereinafter called "Series E Stock"). The Series E Stock shall have the express terms set forth in this Division as being applicable to all shares of Serial Preferred Stock as a class and, in addition, the following express terms applicable to all shares of Series E Stock as a series of the Serial Preferred Stock: (a) The annual dividend rate of the Series E Stock shall be $88.00 per share. (b) Dividends on Series E Stock shall be payable, if declared, quarterly on the first day of March, June, September and December of each year, the first quarterly dividend being payable, if declared, on September 1, 1976, to the extent then accrued. (c) Dividends on Series E Stock shall be cumulative from the date of initial issue. (d) Subject in each case to the provisions of Section 5(c)(3) of this Division, Series E Stock shall be redeemable in the manner provided in Sections 3(b)(1) and (2) of this Division, and as follows: (1) The Series E Stock shall be redeemed in part from time to time for the Sinking Fund as hereinafter set forth at a redemption price of $1,000.00 per share, plus in each case an amount per share equal to all dividends accrued and unpaid thereon to the date of redemption (such price plus such amount being herein- after called the "Sinking Fund Redemption Price"). As and for a Sinking Fund for the Series E Stock, so long as and to the extent that any shares thereof are outstanding, the Corporation will redeem on each June 1 (hereinafter call "Sinking Fund Date") commencing with June 1, 1981, 3,000 shares of Series E Stock at the Sinking Fund Redemption Price (the Corporation's obligation to redeem such number of such shares on any Sinking Fund Date being hereinafter referred to as the "Sinking Fund Obligation"). Such redemption shall be mandatory, subject to any applicable restrictions of law, and not optional to the Corporation. If the Corporation shall for any reason fail to discharge its Sinking Fund Obligation on any Sinking Fund Date, such Sinking Fund Obligation to the extent not discharged shall, without prejudice to any other right or remedy, become an additional Sinking Fund Obligation for each succeeding Sinking Fund Date until fully discharged. - 14 - 16 (2) On each Sinking Fund Date so long as and to the extent that Series E Stock shall be outstanding, and provided that the Corporation has fulfilled its Sinking Fund Obligation on such date, the Corporation may at the option of the Board of Directors redeem up to but not in excess of 3,000 additional shares of Series E Stock at the redemption price of $1,000.00 per share plus in each case an amount per share equal to all dividends accrued and unpaid thereon to the date of redemption; provided, however, that no more than 20,000 shares of Series E Stock in the aggregate may be redeemed pursuant to this Subsection (d)(2). (3) The Corporation at the option of the Board of Directors may at any time and from time to time redeem all or any part of the outstanding Series E Stock upon payment of $1,088.00 per share if redeemed on any date prior to June 1, 1986, and as follows:
If redeemed in the 12 Upon payment months ending May 31 per share of 1987 ..................................... $1,049.74 1988 ..................................... 1,045.91 1989 ..................................... 1,042.09 1990 ..................................... 1,038.26 1991 ..................................... 1,034.43 1992 ..................................... 1,030.61 1993 ..................................... 1,026.78 1994 ..................................... 1,022.96 1995 ..................................... 1,019.13 1996 ..................................... 1,015.30 1997 ..................................... 1,011.48 1998 ..................................... 1,007.65 1999 ..................................... 1,003.83 2000 or in any year thereafter ........... 1,000.00
plus in each case an amount per share equal to all dividends accrued and unpaid thereon to the date of redemption; provided, however, that Series E Stock may not be redeemed prior to June 1, 1986, directly or indirectly (i) as a part of or in anticipation of any refunding of Series E Stock involving the borrowing of funds or the issuance of shares of Serial Preferred Stock or any other shares ranking prior to or on a parity with the Serial Preferred Stock if the interest on such borrowed funds or the dividends on such shares result in an effective cost to the Corporation of less than 8.80% per year, or (ii) from proceeds derived from the sale of equity securities junior to Series E Stock. - 15 - 17 (4) On June 1, 2001, the Corporation shall redeem all remaining shares of Series E Stock, if any, then outstanding at the redemption price of $1,000.00 per share plus in each case an amount per share equal to all dividends accrued and unpaid thereon to the date of redemption. (e) The amount payable per share on Series E Stock in the event of any voluntary liquidation, dissolution or winding up of the affairs of the Corporation shall be the redemption price then in effect as set forth in Subsection (d)(3) of this Section and in the event of any involuntary liquidation, dissolution or winding up of the affairs of the Corporation shall be $1,000.00, plus in each case an amount equal to all dividends accrued and unpaid thereon to the date of payment of the amount due pursuant to this Subsection. (f) The number of shares of Series E Stock shall not be increased above, and shall not exceed, 60,000. Series E Stock once redeemed shall not be reissued as shares of Series E Stock, but having been re- stored to the status of authorized but unissued shares of Serial Preferred Stock without serial designation, may, in whole or in part, be, or be included in, any subsequent series of Serial Preferred Stock of a new designation with such express terms as may be fixed by the Board of Directors of the Corporation. {Section 13. Serial Preferred Stock, $75.00 Series F.} Redeemed November 1, 1991. {Section 14. Serial Preferred Stock, $80.00 Series G.} Redeemed December 1, 1990. {Section 15. Serial Preferred Stock, $145.00 Series H.} Redeemed June 1, 1990. {Section 16. Serial Preferred Stock, $145.00 Series I.} Redeemed June 1, 1991. {Section 17. Serial Preferred Stock, $113.50 Series J.} Redeemed June 1, 1987. {Section 18. Serial Preferred Stock, $113.50 Series K.} Redeemed June 1, 1991. {Section 19. Serial Preferred Stock, Adjustable Rate Series L.} Of the 4,000,000 authorized shares of Serial Preferred Stock, 500,000 shares are designated as a series entitled "Serial Preferred Stock, Adjustable Rate Series L" (hereinafter called "Series L Stock"). The Series L Stock shall have the express terms set forth in this Division as being applicable to all shares of Serial Preferred Stock as a class, and, in addition, the following express terms applicable to all shares of Series L Stock as a series of the Serial Preferred Stock: (a) The dividend rate of the Series L Stock shall be as follows: (1) An annual rate of $11.36 per share for the dividend period from the date of initial issue of the Series L Stock to and includ- ing March 31, 1984, and an annual rate of .50 of 1% below the Applicable Rate [as defined in Subsection (a)(2)] from time to 18 time in effect for each subsequent three-month dividend period; provided, however, that the annual dividend rate shall in no event be less than 7.00% or more than 13.00% for any dividend period. (2) The applicable rate (hereinafter called the "Applicable Rate") for any dividend period shall be the highest of the Treasury Bill Rate, the Ten Year Constant Maturity Rate and the Twenty Year Constant Maturity Rate (each as hereinafter defined) for such dividend period, except that in the event the Corporation determines in good faith that for any reason one or more of such rates cannot be determined for any dividend period, then the Applicable Rate for such dividend shall be the higher of whichever of such rates can be so determined or in the event the Corporation determines in good faith that none of such rates can be determined for any dividend period, then the Applicable Rate in effect for the preceding dividend period shall be continued for such dividend period. (3) Except as provided below in this Subsection (a)(3), the "Treasury Bill Rate" for each dividend period shall be the arithmetic average of the two most recent weekly per annum market discount rates (or the one weekly per annum market discount rate, if only one such rate is published during the relevant Calendar Period (as hereinafter defined)) for three- month U.S. Treasury bills, as published weekly by the Federal Reserve Board during the Calendar Period immediately prior to the last 10 calendar days of March, June, September or December, as the case may be, prior to the dividend period for which the dividend rate on the Series L Stock is being deter- mined. In the event that the Federal Reserve Board does not publish such a weekly per annum market discount rate during any such Calendar Period, then the Treasury Bill Rate for the related dividend period shall be the arithmetic average of the two most recent weekly per annum market discount rates (or the one weekly per annum market discount rate, if only one such rate is published during the relevant Calendar Period) for three-month U.S. Treasury bills, as published weekly during such Calendar Period by any Federal Reserve Bank or by any U.S. Government department or agency selected by the Corporation. In the event that a per annum market discount rate for three- month U.S. Treasury bills is not published by the Federal Reserve Board or by any Federal Reserve Bank or by any U.S. Government department or agency during such Calendar Period, then the Treasury Bill Rate for such dividend period shall be the arithmetic average of the two most recent weekly per annum market discount rates (or the one weekly per annum market discount rate, if only one such rate is published during the relevant Calendar Period) for all of the U.S. Treasury bills then having maturities of not less than 80 nor more than 100 days, as published during such Calendar Period by the Federal Reserve Board or, if the Federal Reserve Board does not publish 19 such rates, by any Federal Reserve Bank or by any U.S. Government department or agency selected by the Corporation. In the event the Corporation determines in good faith that for any reason no such U.S. Treasury bill rates are published as provided above during such Calendar Period, then the Treasury Bill Rate for such dividend period shall be the arithmetic average of the per annum market discount rates based upon the closing bids during such Calendar Period for each of the issues of marketable non-interest bearing U.S. Treasury securities with a maturity of not less than 80 nor more than 100 days from the date of each such quotation, as quoted daily for each business day in New York City (or less frequently if daily quotations are not generally available) to the Corporation by at least three recognized U.S. Government securities dealers selected by the Corporation. In the event the Corporation determines in good faith that for any reason the Corporation cannot determine the Treasury Bill Rate for any dividend period as provided above in this Subsection (a)(3), the Treasury Bill Rate for such dividend period shall be the arithmetic average of the per annum market discount rates based upon the closing bids during the related Calendar Period for each of the issues of marketable interest bearing U.S. Treasury securities with a maturity of not less than 80 nor more than 100 days from the date of each such quotation, as quoted daily for each business day in New York City (or less frequently if daily quotations are not generally available) to the Corporation by at least three recognized U.S. Government securities dealers selected by the Corporation. (4) Except as provided below in this Subsection (a)(4), the "Ten Year Constant Maturity Rate" for each dividend period shall be the arithmetic average of the two most recent weekly per annum Ten Year Average Yields (or the one weekly per annum Ten Year Average Yield, if only one such yield is published during the relevant Calendar Period), as published weekly by the Federal Reserve Board during the Calendar Period immediately prior to the last 10 calendar days of March, June, September or December, as the case may be, prior to the dividend period for which the dividend rate on the Series L Stock is being deter- mined. In the event that the Federal Reserve Board does not publish such a weekly per annum Ten Year Average Yield during such Calendar Period, then the Ten Year Constant Maturity Rate for such dividend period shall be the arithmetic average of the two most recent weekly per annum Ten Year Average Yields (or the one weekly per annum Ten Year Average Yield, if only one such yield is published during the relevant Calendar Period), as published weekly during such Calendar Period by any Federal Reserve Bank or by any U.S. Government department or agency selected by the Corporation. In the event that a per annum Ten Year Average Yield is not published by the Federal Reserve Board or by any Federal Reserve Bank or by any U.S. Government department or agency during such Calendar Period, then the Ten 20 Year Constant Maturity Rate for such dividend period shall be the arithmetic average of the two most recent weekly per annum average yields to maturity (or the one weekly average yield to maturity, if only one such yield is published during the relevant Calendar Period) for all of the actively traded marketable U.S. Treasury fixed interest rate securities (other than Special Securities (as hereinafter defined)) then having maturities of not less than eight nor more than 12 years, as published during such Calendar Period by the Federal Reserve Board or, if the Federal Reserve Board does not publish such yields, by any Federal Reserve Bank or by any U.S. Government department or agency selected by the Corporation. In the event the Corporation determines in good faith that for any reason the Corporation cannot determine the Ten Year Constant Maturity Rate for any dividend period as provided above in this Subsection (a)(4), then the Ten Year Constant Maturity Rate for such dividend period shall be the arithmetic average of the per annum average yields to maturity based upon the closing bids during such Calendar Period for each of the issues of actively traded marketable U.S. Treasury fixed interest rate securities (other than Special Securities) with a final date not less than eight nor more than 12 years from the date of each such quota- tion, as quoted daily for each business day in New York City (or less frequently if daily quotations are not generally available) to the Corporation by at least three recognized U.S. Government securities dealers selected by the Corporation. (5) Except as provided below in this Subsection (a)(5), the "Twenty Year Constant Maturity Rate" for each dividend period shall be the arithmetic average of the two most recent weekly per annum Twenty Year Average Yields (or the one weekly per annum Twenty Year Average Yield, if only one such yield is published during the relevant Calendar Period), as published weekly by the Federal Reserve Board during the Calendar Period immediately prior to the last 10 calendar days of March, June, September or December, as the case may be, prior to the dividend period for which the dividend rate on the Series L Stock is being deter- mined. In the event the Federal Reserve Board does not publish such a weekly per annum Twenty Year Average Yield during such Calendar Period, then the Twenty Year Constant Maturity Rate for such dividend period shall be the arithmetic average of the two most recent weekly per annum Twenty Year Average Yields (or the one weekly per annum Twenty Year Average Yield, if only one such yield is published during the relevant Calendar Period), as published weekly during such Calendar Period by any Federal Reserve Bank or by any U.S. Government department or agency selected by the Corporation. In the event that a per annum Twenty Year Average Yield is not published by the Federal Reserve Board or by any Federal Reserve Bank or by any U.S. Government department or agency during such Calendar Period, then the Twenty Year Constant Maturity Rate for such dividend period shall be the arithmetic average of the two most recent 21 weekly per annum average yields to maturity (or the one weekly average yield to maturity, if only one such yield is published during the relevant Calendar Period) for all of the actively traded marketable U.S. Treasury fixed interest rate securities (other than Special Securities) then having maturities of not less than 18 nor more than 22 years, as published during such Calendar Period by the Federal Reserve Board or, if the Federal Reserve Board does not publish such yields, by any Federal Reserve Bank or by any U.S. Government department or agency selected by the Corporation. In the event that the Corporation determines in good faith that for any reason the Corporation cannot determine the Twenty Year Constant Maturity Rate for any dividend period as provided above in this Subsection (a)(5), then the Twenty Year Constant Maturity Rate for such dividend period shall be the arithmetic average of the per annum average yields to maturity based upon the closing bids during such Calendar Period for each of the issues of actively traded marketable U.S. Treasury fixed interest rate securities (other than Special Securities) with a final maturity date not less than 18 nor more than 22 years from the date of each quotation, as quoted daily for each business day in New York City (or less frequently if daily quotations are not generally available) to the Corporation by at least three recognized U.S. Government securities dealers selected by the Corporation. (6) The Treasury Bill Rate, the Ten Year Constant Maturity Rate and the Twenty Year Constant Maturity Rate each shall be rounded to the nearest one hundredth of a percentage point. (7) The fixed dividend rate per share for each dividend period shall be computed in dollars by dividing the dividend rate for such dividend period by four and, in the case of an Applicable Rate, converting such rate to a fraction and multiplying it by $100.00; provided that the dividend payable for the initial dividend period or any period longer or shorter than a full quarterly dividend period shall be computed on the basis of a 360-day year consisting of 30-day months. (8) The dividend rate with respect to each dividend period shall be calculated as promptly as practicable by the Corporation. The mathematical accuracy of each such calculation shall be con- firmed in writing by the Corporation's independent auditors. The Corporation shall cause each individual rate to be pub- lished in a newspaper of general circulation in New York City prior to the commencement of the dividend period to which it applies. 22 (9) As used in this Subsection (a), the term "Calendar Period" means a period of 14 calendar days; the term "Special Securities" mean securities which can, at the option of the holder, be surrendered at face value in payment of any Federal estate tax or which provide tax benefits to the holder and are priced to reflect such tax benefits or which were originally issued at a deep or substantial discount; the term "Ten Year Average Yield" means the average yield to maturity for actively traded marketable U.S. Treasury fixed interest rate securities (adjusted to constant maturities of 10 years); and the term "Twenty Year Average Yield" means the average yield to maturity for actively traded marketable U.S. Treasury fixed interest rate securities (adjusted to constant maturities of 20 years). (b) Dividends on Series L Stock shall be payable, if declared, quarterly on the first day of January, April, July and October of each year, the first quarterly dividend being payable, if declared, on April 1, 1984, to the extent accrued. (c) Dividends on Series L Stock shall be cumulative as follows: (1) With respect to shares included in the initial issue of Series L Stock and shares issued any time thereafter up to and includ- ing the record date for the payment of the first dividend on the initial issue of Series L Stock, dividends shall be cumulative from the date of the initial issue of Series L Stock; and (2) With respect to shares issued any time after the aforesaid record date, dividends shall be cumulative from the dividend payment date next preceding the date of issue of such shares, except that if such shares are issued during the period com- mencing the day after the record date for the payment of a dividend on Series L Stock and ending on the payment date of that dividend, dividends with respect to such shares shall be cumulative from that dividend payment date. (d) Subject to the provisions of Section 5(c)(3) of this Division, Series L Stock shall be redeemable in the manner provided in Sections 3(b)(1) and (2) of this Division, at any time or from time to time, at the option of the Board of Directors, upon payment of $111.36 per share if redeemed on any date prior to January 1, 1985, $109.69 per share if redeemed on or after the date last stated and prior to January 1, 1986, $108.02 per share if redeemed on or after the date last stated and prior to January 1, 1987, $106.34 per share if redeemed on or after the date last stated and prior to January 1, 1988, $104.67 per share if redeemed on or after the date last stated and prior to January 1, 1989, $103.00 if redeemed on or after the date last stated and prior to January 1, 1994, and $100.00 per share if redeemed on or after the date last stated, plus in each case an amount equal to all dividends accrued and unpaid thereon to the date of redemption; provided, however, that Series L Stock may not be 23 redeemed prior to January 1, 1989, directly or indirectly as a part of or in anticipation of any refunding of Series L Stock involving the incurring of indebtedness or the issuance of shares of Serial Preferred Stock or any other shares ranking prior to or on a parity with the Serial Preferred Stock if the interest on such indebtedness or the dividends on such shares results in an effective annual cost to the Corporation of less than the annual dividend rate of the Series L Stock. In the case of a refunding redemption of Series L Stock with borrowed funds or shares having a fixed interest or dividend rate, the annual rate of the Series L Stock is the dividend payable on the Series L Stock on or, if it is not payable on, then payable most recently before, the date the redemption notice is deposited in the mail. In the case of a refunding redemption of Series L Stock with borrowed funds or shares having an adjustable interest or dividend rate, the effective annual interest or dividend cost of such borrowed funds or shares shall be deemed to be lower than the annual dividend rate of the Series L Stock if either (i) the initial annual interest or dividend rate of such borrowed funds or shares is lower than the annual dividend rate of the Series L Stock payable on, or if it is not payable on, then payable most recently before, the date the redemption notice is deposited in the mail, or (ii) the adjusted annual interest or dividend rate of such borrowed funds or shares definitely would, under the applicable adjustment formula, be lower at any time while such borrowing or shares would be outstanding than the adjusted annual dividend rate of the Series L Stock would be at the corresponding time if it also were to remain outstanding. (e) The amount payable per share on Series L Stock in the event of any voluntary liquidation, dissolution or winding up of the affairs of the Corporation shall be the redemption price then in effect as set forth in Subsection (d) of this Section and in the event of any involuntary liquidation, dissolution or winding up of the affairs of the Corporation shall be $100.00, plus in each case an amount equal to all dividends accrued and unpaid thereon to the date of payment of the amount due pursuant to this Subsection. (f) The number of shares of Series L Stock shall not be increased above, and shall not exceed, 500,000. Series L Stock once purchased, acquired or otherwise redeemed by the Corporation shall not be reissued as shares of Series L Stock, but, having been restored to the status of authorized but unissued shares of Serial Preferred Stock without serial designation, may, in whole or in part, be, or be included in, any subsequent series of Serial Preferred Stock of a new designation with such express terms as may be fixed by the Board of Directors of the Corporation. 24 {Section 20. Serial Preferred Stock, Adjustable Rate Series M.} Of the 4,000,000 authorized shares of Serial Preferred Stock, 500,000 shares are designated as a series entitled "Serial Preferred Stock, Adjustable Rate Series M" (hereinafter called "Series M Stock"). The Series M Stock shall have the express terms set forth in this Division as being applicable to all shares of Serial Preferred Stock as a class and, in addition, the following express terms applicable to all shares of Series M Stock as a series of the Serial Preferred Stock: (a) The dividend rate of the Series M Stock shall be as follows: (1) An annual rate of $9.27 per share for the dividend period from the date of initial issue of the Series M Stock to and includ- ing January 31, 1986 and an annual rate 1.15 percentage points below the Applicable Rate (as defined in Subsection (a)(2)) from time to time in effect for each subsequent three-month dividend period; provided, however, that the annual dividend rate shall in no event be less than 7.00% or more than 13.50% for any dividend period. (2) The applicable rate (hereinafter called the "Applicable Rate") for any dividend period shall be the highest of the Treasury Bill Rate, the Ten Year Constant Maturity Rate and the Twenty Year Constant Maturity Rate (each as hereinafter defined) for such dividend period, except that in the event the Corporation determines in good faith that for any reason one or more of such rates cannot be determined for any dividend period, then the Applicable Rate for such dividend shall be the higher of whichever of such rates can be so determined or in the event the Corporation determines in good faith that none of such rates can be determined for any dividend period, then the Applicable Rate in effect for the preceding dividend period shall be continued for such dividend period. (3) Except as provided below in this Subsection (a)(3), the "Treasury Bill Rate" for each dividend period shall be the arithmetic average of the two most recent weekly per annum market discount rates (or the one weekly per annum market dis- count rate, if only one such rate is published during the relevant Calendar Period (as hereinafter defined)) for three- month U.S. Treasury bills, as published weekly by the Federal Reserve Board during the Calendar Period immediately prior to the last 10 calendar days of January, April, July or October, as the case may be, prior to the dividend period for which the dividend rate on the Series M Stock is being determined. In the event that the Federal Reserve Board does not publish such a weekly per annum market discount rate during such Calendar Period, then the Treasury Bill Rate for such dividend period shall be the arithmetic average of the two most recent weekly per annum market discount rates (or the one weekly per annum market discount rate, if only one such rate is published during such Calendar Period) for three-month U.S. Treasury bills, as 25 published weekly during such Calendar Period by any Federal Reserve Bank or by any U.S. Government department or agency selected by the Corporation. In the event that a per annum market discount rate for three-month U.S. Treasury bills is not published by the Federal Reserve Board or by any Federal Reserve Bank or by any U.S. Government department or agency during such Calendar Period, then the Treasury Bill Rate for such dividend period shall be the arithmetic average of the two most recent weekly per annum market discount rates (or the one weekly per annum market discount rate, if only one such rate is published during such Calendar Period) for all of the U.S. Treasury bills then having maturities of not less than 80 nor more than 100 days, as published during such Calendar Period by the Federal Reserve Board or, if the Federal Reserve Board does not publish such rates, by any Federal Reserve Bank or by any U.S. Government department or agency selected by the Corporation. In the event the Corporation determines in good faith that for any reason no such U.S. Treasury bill rates are published as provided above during such Calendar Period, then the Treasury Bill Rate for such dividend period shall be the arithmetic average of the per annum market discount rates based upon the closing bids during such Calendar Period for each of the issues of marketable non-interest bearing U.S. Treasury securities with a maturity of not less than 80 nor more than 100 days from the date of each such quotation, as quoted daily for each business day in New York City (or less frequently if daily quotations are not generally available) to the Corporation by at least three recognized U.S. Government securities dealers selected by the Corporation. In the event the Corporation determines in good faith that for any reason the Corporation cannot determine the Treasury Bill Rate for such dividend period as provided above in this Subsection (a)(3), the Treasury Bill Rate for such dividend period shall be the arithmetic average of the per annum market discount rates based upon the closing bids during such Calendar Period for each of the issues of marketable interest bearing U.S. Treasury securities with a maturity of not less than 80 nor more than 100 days from the date of each such quotation, as quoted daily for each business day in New York City (or less frequently if daily quotations are not generally available) to the Corporation by at least three recognized U.S. Government securities dealers selected by the Corporation. (4) Except as provided below in this Subsection (a)(4), the "Ten Year Constant Maturity Rate" for each dividend period shall be the arithmetic average of the two most recent weekly per annum Ten Year Average Yields (or the one weekly per annum Ten Year Average Yield, if only one such yield is published during the relevant Calendar Period), as published weekly by the Federal Reserve Board during the Calendar Period immediately prior to the last 10 calendar days of January, April, July or October, as the case may be, prior to the dividend period for which the 26 dividend rate on the Series M Stock is being determined. In the event that the Federal Reserve Board does not publish such a weekly per annum Ten Year Average Yield during such Calendar Period, then the Ten Year Constant Maturity Rate for such dividend period shall be the arithmetic average of the two most recent weekly per annum Ten Year Average Yields (or the one weekly per annum Ten Year Average Yield, if only one such yield is published during such Calendar Period), as published weekly during such Calendar Period by any Federal Reserve Bank or by any U.S. Government department or agency selected by the Corporation. In the event that a per annum Ten Year Average Yield is not published by the Federal Reserve Board or by any Federal Reserve Bank or by any U.S. Government department or agency during such Calendar Period, then the Ten Year Constant Maturity Rate for such dividend period shall be the arithmetic average of the two most recent weekly per annum average yields to maturity (or the one weekly average yield to maturity, if only one such yield is published during such Calendar Period) for all of the actively traded marketable U.S. Treasury fixed interest rate securities (other than Special Securities (as hereinafter defined)) then having maturities of not less than eight nor more than 12 years, as published during said Calendar Period by the Federal Reserve Board or, if the Federal Reserve Board does not publish such yields, by any Federal Reserve Bank or by any U.S. Government department or agency selected by the Corporation. In the event the Corporation determines in good faith that for any reason the Corporation cannot determine the Ten Year Constant Maturity Rate for such dividend period as provided above in this Subsection (a)(4), then the Ten Year Constant Maturity Rate for such dividend period shall be the arithmetic average of the per annum average yields to maturity based upon the closing bids during such Calendar Period for each of the issues of actively traded marketable U.S. Treasury fixed interest rate securities (other than Special Securities) with a final maturity date not less than eight nor more than 12 years from the date of each such quotation, as quoted daily for each business day in New York City (or less frequently if daily quotations are not generally available) to the Corporation by at least three recognized U.S. Government securities dealers selected by the Corporation. (5) Except as provided below in this Subsection (a)(5), the "Twenty Year Constant Maturity Rate" for each dividend period shall be the arithmetic average of the two most recent weekly per annum Twenty Year Average Yields (or the one weekly per annum Twenty Year Average Yield, if only one such yield is published during the relevant Calendar Period), as published weekly by the Federal Reserve Board during the Calendar Period immediately prior to the last 10 calendar days of January, April, July or October, as the case may be, prior to the dividend period for which the dividend rate on the Series M Stock is being determined. In the event the Federal Reserve Board does not 27 publish such a weekly per annum Twenty Year Average Yield during such Calendar Period, then the Twenty Year Constant Maturity Rate for such dividend period shall be the arithmetic average of the two most recent weekly per annum Twenty Year Average Yields (or the one weekly per annum Twenty Year Average Yield, if only one such yield is published during such Calendar Period), as published weekly during such Calendar Period by any Federal Reserve Bank or by any U.S. Government department or agency selected by the Corporation. In the event that a per annum Twenty Year Average Yield is not published by the Federal Reserve Board or by any Federal Reserve Bank or by any U.S. Government department or agency during such Calendar Period, then the Twenty Year Constant Maturity Rate for such dividend period shall be the arithmetic average of the two most recent weekly per annum average yields to maturity (or the one weekly average yield to maturity, if only one such yield is published during such Calendar Period) for all of the actively traded marketable U.S. Treasury fixed interest rate securities (other than Special Securities) then having maturities of not less than 18 nor more than 22 years, as published during such Calendar Period by the Federal Reserve Board or, if the Federal Reserve Board does not publish such yields, by any Federal Reserve Bank or by any U.S. Government department or agency selected by the Corporation. In the event that the Corporation determines in good faith that for any reason the Corporation cannot determine the Twenty Year Constant Maturity Rate for such dividend period as provided above in this Subsection (a)(5), then the Twenty Year Constant Maturity Rate for such dividend period shall be the arithmetic average of the per annum average yields to maturity based upon the closing bids during such Calendar Period for each of the issues of actively traded marketable U.S. Treasury fixed interest rate securities (other than Special Securities) with a final maturity date not less than 18 nor more than 22 years from the date of each quotation, as quoted daily for each business day in New York City (or less frequently if daily quotations are not generally available) to the Corporation by at least three recognized U.S. Government securities dealers selected by the Corporation. (6) The Treasury Bill Rate, the Ten Year Constant Maturity Rate and the Twenty Year Constant Maturity Rate each shall be rounded to the nearest one hundredth of a percentage point. (7) The fixed dividend rate per share for each dividend period shall be computed in dollars by dividing the dividend rate for such dividend period by four and, in the case of an Applicable Rate, converting such rate to a fraction and multiplying it by $100.00; provided that the dividend payable for the initial dividend period or any period longer or shorter than a full quarterly dividend period shall be computed on the basis of a 360-day year consisting of 30-day months. 28 (8) The dividend rate with respect to each dividend period shall be calculated as promptly as practicable by the Corporation. The mathematical accuracy of each such calculation shall be con- firmed in writing by the Corporation's independent auditors. The Corporation shall cause each individual rate to be pub- lished in a newspaper of general circulation in New York City prior to the commencement of the dividend period to which it applies. (9) As used in this Subsection (a), the term "Calendar Period" means a period of 14 calendar days; the term "Special Securities" means securities which can, at the option of the holder, be surrendered at face value in payment of any Federal estate tax or which provide tax benefits to the holder and are priced to reflect such tax benefits or which were originally issued at a deep or substantial discount; the term "Ten Year Average Yield" means the average yield to maturity for actively traded marketable U.S. Treasury fixed interest rate securities (adjusted to constant maturities of 10 years); and the term "Twenty Year Average Yield" means the average yield to maturity for actively traded marketable U.S. Treasury fixed interest rate securities (adjusted to constant maturities of 20 years). (b) Dividends on Series M Stock shall be payable, if declared, quarterly on the first day of February, May, August and November of each year, the first quarterly dividend being payable, if declared, on February 1, 1986, to the extent accrued. (c) Dividends on Series M Stock shall be cumulative as follows: (1) With respect to shares included in the initial issue of Series M Stock and shares issued any time thereafter up to and includ- ing the record date for the payment of the first dividend on the initial issue of Series M Stock, dividends shall be cumulative from the date of the initial issue of Series M Stock; and (2) With respect to shares issued any time after the aforesaid record date, dividends shall be cumulative from the dividend payment date next preceding the date of issue of such shares, except that if such shares are issued during the period com- mencing the day after the record date for the payment of a dividend on Series M Stock and ending on the payment date of that dividend, dividends with respect to such shares shall be cumulative from that dividend payment date. (d) Subject to the provisions of Section 5(c)(3) of this Division, the Series M Stock shall be redeemed in the manner provided in Sections 3(b)(1) and (2) of this Division as follows: 29 (1) The Corporation shall, on November 1, 1991 and on each November 1 thereafter, redeem 100,000 shares of Series M Stock, or the number of shares then outstanding, if less, at the re- demption price of $100.00 per share, plus an amount per share equal to all dividends accrued and unpaid thereon to the date of redemption. The Corporation's obligation to redeem such number of shares on any such date is hereinafter referred to as a "Mandatory Redemption Obligation". If the Corporation shall not have on such date sufficient funds legally available to effect such mandatory redemption, it shall set aside for such redemption on such date such funds, if any, as are then legally available, and shall do so as promptly as practicable there- after as the Corporation determines that it has funds then legally available, and shall apply such funds to the redemption of shares of Series M Stock as provided in the last sentence of this Subsection (d)(1) until it has redeemed all of the Series M Stock then required to be redeemed pursuant to the first sentence of this Subsection (d)(1). Notwithstanding the fore- going, if at any time the Corporation (i) shall be obligated to redeem Series M Stock or to set aside legally available funds for that purpose and to redeem other Serial Preferred Stock for its sinking fund or other mandatory redemption and (ii) shall not have sufficient funds legally available to do so in full, then such portion of such then legally available funds shall be set aside to redeem the Series M Stock as shall bear the same ratio to the total funds then legally available to effect such redemption and to meet the then unmet obligations of the sink- ing fund and other mandatory redemption terms of all outstand- ing Serial Preferred Stock as the then unmet obligation to redeem Series M Stock bears to the aggregate of such unmet obligations to redeem and the then unmet obligations of the sinking fund and other mandatory redemption terms of all out- standing Serial Preferred Stock. At any time following the setting aside of funds to redeem Series M Stock pursuant to this Subsection (d)(1) when the amount so set aside is suffi- cient to redeem at least 1,000 shares of the Series M Stock, the Corporation shall promptly call for redemption such number of whole shares of Series M Stock as may be redeemed with such amount at the redemption price of $100.00 per share, plus accrued but unpaid dividends on the Series M Stock then being redeemed to the date of redemption. (2) On each mandatory redemption date specified in Subsection (d)(1), so long as and to the extent that Series M Stock shall be outstanding, and provided that the Corporation has fulfilled all its Mandatory Redemption Obligations under Subsection (d)(1) on such date, the Corporation, at the option of the Board of Directors, may redeem not more than 100,000 additional shares of Series M Stock, or the number of shares then out- standing in excess of those then being redeemed pursuant to Subsection (d)(1), if less, at the mandatory redemption price specified in Subsection (d)(1). The option to redeem addi- tional Series M Stock pursuant to this Subsection (d)(2) shall not be cumulative. 30 (3) The Corporation, at the option of the Board of Directors, may redeem at any time and from time to time all or any part of the outstanding Series M Stock as follows:
Upon payment of If redeemed in the 12 the redemption months ending on October 31, price per share of 1986 ......................... $109.27 1987 ......................... 108.02 1988 ......................... 106.76 1989 ......................... 105.51 1990 ......................... 104.25 1991 ......................... 103.00 1992 ......................... 102.00 1993 ......................... 101.00 1994 ......................... 100.00 1995 ......................... 100.00
plus in each case an amount equal to all dividends accrued and unpaid thereon to the date of redemption; provided, however, that Series M Stock may not be redeemed prior to November 1, 1990, directly or indirectly as a part of or in anticipation of any refunding of Series M Stock involving the incurring of in- debtedness or the issuance of shares of Serial Preferred Stock or any other shares ranking prior to or on a parity with the Serial Preferred Stock if the interest on such indebtedness or the dividends on such shares results in an effective annual cost to the Corporation of less than the annual dividend rate of the Series M Stock. In the case of a refunding redemption of Series M Stock with borrowed funds or shares having a fixed interest or dividend rate, the annual rate of the Series M Stock is the dividend payable on the Series M Stock on or, if it is not payable on, then payable most recently before, the date the redemption notice is deposited in the mail. In the case of a refunding redemption of Series M Stock with borrowed funds or shares having an adjustable interest or dividend rate, the effective annual interest or dividend cost of such borrowed funds or shares shall be deemed to be lower than the annual dividend rate of the Series M Stock if either (i) the initial annual interest or dividend rate of such borrowed funds or shares is lower than the annual dividend rate of the Series M Stock payable on, or if it is not payable on, then payable most recently before, the date the redemption notice is deposited in the mail, or (ii) the adjusted annual interest or dividend rate of such borrowed funds or shares definitely would, under the applicable adjustment formula, be lower at any time while such borrowing or shares would be outstanding than the adjusted annual dividend rate of the Series M Stock would be at the corresponding time if it also were to remain outstanding. 31 (4) Any shares of Series M Stock acquired by the Corporation pur- suant to Subsection (d)(2) or (3) or by purchase or otherwise may, at the option of the Board of Directors, be credited on any mandatory redemption date specified in Subsection (d)(1), in whole or in part, to reduce all or part of any unsatisfied Mandatory Redemption Obligation of the Corporation under Subsection (d)(1) on such date, such reduction to be credited first to the oldest unsatisfied Mandatory Redemption Obligation and then sequentially to each subsequent unsatisfied Mandatory Redemption Obligation, if any, to the extent of the number of shares so acquired and determined by the Board of Directors to be so credited. Any shares so credited may not thereafter be again so credited. (e) The amount payable per share on Series M Stock in the event of any voluntary liquidation, dissolution or winding up of the affairs of the Corporation shall be the redemption price then in effect as set forth in Subsection (d)(3) of this Section and in the event of any involuntary liquidation, dissolution or winding up of the affairs of the Corporation shall be $100.00, plus in each case an amount equal to all dividends accrued and unpaid thereon to the date of payment of the amount due pursuant to this Subsection (e). (f) The number of shares of Series M Stock shall not be increased above, and shall not exceed 500,000. Series M Stock once redeemed, pur- or otherwise acquired by the Corporation shall not be re-issued as shares of Series M Stock, but, having been restored to the status of authorized but unissued shares of Serial Preferred Stock without serial designation, may, in whole or in part, be, or be included in, any subsequent series of Serial Preferred Stock of a new designation with such express terms as may be fixed by the Board of Directors of the Corporation. {Section 21. Serial Preferred Stock, $9.125 Series N.} Of the 4,000,000 authorized shares of Serial Preferred Stock, 750,000 shares are designated as a series entitled "Serial Preferred Stock, $9.125 Series N" (hereinafter called "Series N Stock"). The Series N Stock shall have the express terms set forth in this Division as being applicable to all shares of Serial Preferred Stock as a class and, in addition, the following express terms applicable to all shares of Series N Stock as a series of the Serial Preferred Stock: (a) The annual dividend rate of the Series N Stock shall be $9.125 per share. (b) Dividends on Series N Stock shall be payable, if declared, quarterly on the first day of February, May, August and November of each year, the first quarterly dividend being payable, if declared, on February 1, 1987, to the extent accrued. (c) Dividends on Series N Stock shall be cumulative as follows: 32 (1) With respect to shares included in the initial issue of Series N Stock and shares issued any time thereafter up to and includ- ing the record date for the payment of the first dividend on the initial issue of Series N Stock, dividends shall be cumulative from the date of the initial issue of Series N Stock; and (2) With respect to shares issued any time after the aforesaid record date, dividends shall be cumulative from the dividend payment date next preceding the date of issue of such shares, except that if such shares are issued during the period com- mencing the day after the record date for the payment of a dividend on Series N Stock and ending on the payment date of that dividend, dividends with respect to such shares shall be cumulative from that dividend payment date. (d) Subject to the provisions of Section 5(c)(3) of this Division, the Series N Stock shall be redeemable in the manner provided in Sections 3(b)(1) and (2) of this Division as follows: (1) The Corporation shall, on February 1, 1993 and on each February 1 thereafter, redeem 150,000 shares of Series N Stock, or the number of shares then outstanding, if less, at the re- demption price of $100.00 per share, plus an amount per share equal to all dividends accrued and unpaid thereon to the date of redemption. If the Corporation shall not have on any such date sufficient funds legally available to effect such manda- tory redemption, it shall set aside for such redemption on such date such funds, if any, as are then legally available, and shall do so as promptly as practicable thereafter as the Corporation determines that it has funds then legally available, and shall apply such funds to the redemption of shares of Series N Stock as provided in the last sentence of this Subsection (d)(1) until it has redeemed all of the Series N Stock then required to be redeemed pursuant to the first sentence of this Subsection (d)(1). Notwithstanding the foregoing, if at any time the Corporation (i) shall be obli- gated to redeem Series N Stock or to set aside legally available funds for that purpose and to redeem other Serial Preferred Stock for its sinking fund or other mandatory re- demption terms and (ii) shall not have sufficient funds legally available to do so in full, then such portion of such then legally available funds shall be set aside to redeem the Series N Stock as shall bear the same ratio to the total funds then legally available to effect such redemption and to meet the then unmet obligations of the sinking fund and other mandatory redemption terms of all outstanding Serial Preferred Stock as the then unmet obligation to redeem Series N Stock bears to the aggregate of such unmet obligations to redeem and the then unmet obligations of the sinking fund and other mandatory redemption terms of all outstanding Serial Preferred Stock. At any time following the setting aside of funds to redeem Series N Stock pursuant to this Subsection (d)(1) when 33 the amount so set aside is sufficient to redeem at least 1,000 shares of the Series N Stock, the Corporation shall promptly call for redemption such number of whole shares of Series N Stock as may be redeemed with such amount at the redemption price of $100.00 per share, plus accrued but unpaid dividends on the Series N Stock then being redeemed to the date of redemption. (2) The Corporation, at the option of the Board of Directors, may redeem at any time and from time to time all or any part of the outstanding Series N Stock as follows:
Upon payment of If redeemed in the 12 the redemption months ending on January 31, price per share of 1987 ......................... $109.13 1988 ......................... 109.13 1989 ......................... 108.11 1990 ......................... 107.10 1991 ......................... 106.08 1992 ......................... 105.07 1993 ......................... 104.06 1994 ......................... 103.04 1995 ......................... 102.03 1996 ......................... 101.01 1997 ......................... 100.00
plus in each case an amount equal to all dividends accrued and unpaid thereon to the date of redemption; provided, however, that Series N Stock may not be so redeemed prior to February 1, 1992, directly or indirectly as part of or in anticipation of any refunding of Series N Stock involving the incurring of indebtedness or the issuance of shares of Serial Preferred Stock or any other shares ranking prior to or on a parity with the Serial Preferred Stock if the interest on such indebtedness or the dividends on such shares results in an effective annual cost to the Corporation of less than the annual dividend rate of the Series N Stock. In the case of a refunding optional redemption of Series N Stock with borrowed funds or shares or proceeds of shares having an adjustable interest or dividend rate, the effective annual interest or dividend cost of such borrowed funds or shares shall be deemed to be less than the annual dividend rate of the Series N Stock if the initial annual interest or dividend rate of such borrowed funds or shares is less than the annual dividend rate of the Series N Stock. 34 (3) On February 1, 1997, the Corporation shall redeem all remaining shares of Series N Stock, if any, then outstanding at the re- demption price of $100.00 per share, plus an amount per share equal to all dividends accrued and unpaid thereon to the date of redemption. (e) The amount payable per share on Series N Stock in the event of any voluntary liquidation, dissolution or winding up of the affairs of the Corporation shall be the redemption price then in effect as set forth in Subsection (d)(2) of this Section and in the event of any involuntary liquidation, dissolution or winding up of the affairs of the Corporation shall be $100.00, plus in each case an amount equal to all dividends accrued and unpaid thereon to the date of payment of the amount due pursuant to this Subsection (e). (f) The number of shares of Series N Stock shall not be increased above, and shall not exceed, 750,000. Series N Stock once redeemed, pur- chased or otherwise acquired by the Corporation shall not be re- issued as shares of Series N Stock, but, having been restored to the status of authorized but unissued shares of Serial Preferred Stock without serial designation, may, in whole or in part, be, or be included in, any subsequent series of Serial Preferred Stock of a new designation with such express terms as may be fixed by the Board of Directors of the Corporation. {Section 22. Serial Preferred Stock, Remarketed Series P.} Redeemed August 31, 1993. {Section 23. Serial Preferred Stock, $91.50 Series Q.} Of the 4,000,000 authorized shares of Serial Preferred Stock, 75,000 shares are designated as a series entitled "Serial Preferred Stock, $91.50 Series Q" (hereinafter called "Series Q Stock"). The shares of Series Q Stock shall have the express terms set forth in this Division as being applicable to all shares of Serial Preferred Stock as a class and, in addition, the following express terms applicable to all shares of Series Q Stock as a series of the Serial Preferred Stock: (a) The annual dividend rate of the Series Q Stock shall be $91.50 per share. (b) Dividends on Series Q Stock shall be payable, if declared, quarterly on the first day of March, June, September and December of each year, the first quarterly dividend being payable, if declared, on September 1, 1991, to the extent accrued. (c) Dividends on Series Q Stock shall be cumulative as follows: (1) With respect to shares included in the initial issue of Series Q Stock and shares issued any time thereafter up to and includ- ing the record date for the payment of the first dividend on the initial issue of Series Q Stock, dividends shall be cumulative from the date of the initial issue of Series Q Stock; and 35 (2) With respect to shares issued any time after the aforesaid record date, dividends shall be cumulative from the dividend payment date next preceding the date of issue of such shares, except that if such shares are issued during the period com- mencing the day after the record date for the payment of a dividend on Series Q Stock and ending on the payment date of that dividend, dividends with respect to such shares shall be cumulative from that dividend payment date. (d) Subject in each case to the provisions of Section 5(c)(3) of this Division, Series Q Stock shall be redeemable in the manner provided in Sections 3(b)(1) and (2) of this Division, and as follows: (1) Series Q Stock shall be redeemed in part from time to time for the Sinking Fund as hereinafter set forth at a redemption price of $1,000.00 per share, plus in each case an amount per share equal to all dividends accrued and unpaid thereon to the date of redemption (such price plus such amount being hereinafter called the "Sinking Fund Redemption Price"). As and for a Sinking Fund for Series Q Stock, so long as and to the extent that any shares thereof are outstanding, the Corporation will redeem on each June 1 (hereinafter called "Sinking Fund Date") commencing with June 1, 1995 and ending on June 1, 2000, 10,714 shares of Series Q Stock, and on June 1, 2001, the re- maining 10,716 shares of Series Q Stock, or the number of shares then outstanding, if less, at the Sinking Fund Redemption Price (the Corporation's obligation to redeem such number of such shares on any Sinking Fund Date being herein- after referred to as the "Sinking Fund Obligation"). If the Corporation shall not have on any Sinking Fund Date sufficient funds legally available to effect such mandatory redemption, it shall set aside for such redemption on such date such funds, if any, as are then legally available, and shall do so as promptly as practicable thereafter as the Corporation determines that it has funds then legally available, and shall apply such funds to the redemption of shares of Series Q Stock as provided in the last sentence of this Subsection (d)(1) until it has redeemed all of the Series Q Stock then required to be redeemed pursuant to this Subsection (d)(1). Notwithstanding the foregoing, if at any time the Corporation (i) shall be obligated to redeem Series Q Stock or to set aside legally available funds for that purpose and to redeem other Serial Preferred Stock for its sinking fund or other mandatory redemption terms and (ii) shall not have sufficient funds legally available to do so in full, then such portion of such then legally available funds shall be set aside to redeem the Series Q Stock as shall bear the same ratio to the total funds then legally available to effect such redemption and to meet the then unmet obligations of the sinking fund and other mandatory redemption terms of all outstanding Serial Preferred Stock as the then unmet obligation to redeem Series Q Stock bears to the aggregate of such unmet obligations to redeem and the then unmet obligations of the 36 sinking fund and other mandatory redemption terms of all outstanding Serial Preferred Stock. At any time following the setting aside of funds to redeem Series Q Stock pursuant to this Subsection (d)(1) when the amount so set aside is sufficient to redeem at least 100 shares of Series Q Stock, the Corporation shall promptly call for redemption such number of whole shares of Series Q Stock as may be redeemed with such amount at the redemption price of $1,000.00 per share, plus accrued but unpaid dividends on Series Q Stock then being redeemed to the date of redemption. (2) On each Sinking Fund Date so long as and to the extent that Series Q Stock shall be outstanding, and provided that the Corporation has fulfilled its Sinking Fund Obligation on such date, the Corporation may at the option of the Board of Directors redeem additional shares of Series Q Stock (any redemption of less than all of the then outstanding Series Q Stock being applied in satisfaction of required Sinking Fund Obligations in inverse order of their scheduled Sinking Fund Dates) at the redemption price of $1,000.00 per share (the Redemption Amount"), plus in each case an amount per share equal to all dividends accrued and unpaid thereon to the date of redemption, plus in each case the Optional Redemption Amount, if any. For purposes of this Section 23(d)(2) (and Section 23(e) as provided therein), the following definitions shall apply: "OPTIONAL REDEMPTION AMOUNT" shall mean, with respect to each share of Series Q Stock, an amount equal to (A) the excess, if any, of the Discounted Value of the Called Amount over the sum of (i) such Called Amount plus (ii) accrued and unpaid dividends on the shares of Series Q Stock to be redeemed as of (including dividends payable on) the Settlement Date, divided by (B) the number of shares of Series Q Stock to be redeemed on such Settlement Date. The Optional Redemption Amount shall in no event be less than zero. "BUSINESS DAY" shall mean any day other than a Saturday, a Sunday or a day on which commercial banks in New York City or Ohio are required or authorized to be closed. "CALLED AMOUNT" shall mean, with respect to the Series Q Stock, the aggregate Redemption Amount of the shares of Series Q Stock that are to be redeemed pursuant to this Section 23(d)(2) or pursuant to the provisions of Section 23(e) regarding voluntary liquidation, dissolution, or winding up of the affairs of the Corporation. 37 "DISCOUNTED VALUE" shall mean, with respect to the Called Amount, the amount obtained by discounting all Remaining Scheduled Payments with respect to such Called Amount from their respective scheduled due dates to the Settlement Date, in accordance with accepted financial practice and at a discount factor (applied on a quarterly basis) equal to the Reinvestment Yield with respect to such Called Amount. "REINVESTMENT YIELD" shall mean, with respect to the Called Amount, the yield to maturity implied by (i) the yields re- ported, as of 10:00 A.M. (New York City time) on the Business Day next preceding the Settlement Date, on the display designated as "Page 678" on the Telerate Service (or such other display as may replace Page 678 on the Telerate Service) for actively traded U.S. Treasury securities having a maturity equal to the Remaining Average Life of such Called Amount as of such Settlement Date, or, if such yields shall not be reported as of such time or if the yields reported as of such time shall not be ascertainable, (ii) the Treasury Constant Maturity Series yields reported, for the latest day for which such yields shall have been so reported as of the Business Day next preceding the Settlement Date, in Federal Reserve Statistical Release H.15 (519) (or any comparable successor publication) for actively traded U.S. Treasury securities having a constant maturity equal to the Remaining Average Life of such Called Amount as of such Settlement Date. Such implied yield shall be determined, if necessary, by (a) converting U.S. Treasury bill quotations to bond-equivalent yields in accordance with accepted financial practice and (b) interpolating linearly between reported yields. "REMAINING AVERAGE LIFE" shall mean, with respect to the Called Amount, the number of years (calculated to the nearest one- twelfth year) obtained by dividing (i) such Called Amount into (ii) the sum of the products obtained by multiplying (a) each Remaining Scheduled Payment of such Called Amount (but not of dividends that would have been payable with respect to the shares of Series Q Stock to be redeemed between the Settlement Date and the respective Sinking Fund Dates) by (b) the number of years (calculated to the nearest one-twelfth year) which will elapse between the Settlement Date and the scheduled Sinking Fund Date of such Remaining Scheduled Payment. "REMAINING SCHEDULED PAYMENTS" shall mean, with respect to the Called Amount, all payments required by Section 23(d)(1) with respect to such Called Amount plus all dividends at the rate of $103.60 per annum on the shares of Series Q Stock to be re- deemed that would have been payable between the Settlement Date and the respective Sinking Fund Dates. 38 "SETTLEMENT DATE" shall mean, with respect to the Called Amount, the date on which such Called Amount is to be redeemed pursuant to this Section 23(d)(2) or becomes payable pursuant to the provisions of Section 23(e) regarding voluntary liquida- tion, dissolution or winding up of the affairs of the Corporation. (3) On June 1, 2001, the Corporation shall redeem all remaining shares of Series Q Stock, if any, then outstanding at the re- demption price of $1,000.00 per share plus in each case an amount per share equal to all dividends accrued and unpaid thereon to the date of redemption. (e) The amount payable per share on Series Q Stock in the event of any voluntary liquidation, dissolution or winding up of the affairs of the Corporation shall be the redemption price then in effect as set forth in Subsection (d)(2) of this Section and in the event of any involuntary liquidation, dissolution or winding up of the affairs of the Corporation shall be $1,000.00, plus in each case an amount equal to all dividends accrued and unpaid thereon to the date of payment of the amount due pursuant to this Subsection (e). (f) The number of shares of Series Q Stock shall not be increased above, and shall not exceed, 75,000. Series Q Stock once redeemed, pur- chased or otherwise acquired by the Corporation shall not be re- issued as shares of Series Q Stock, but, having been restored to the status of authorized but unissued shares of Serial Preferred Stock without serial designation, may, in whole or in part, be, or be included in, any subsequent series of Serial Preferred Stock of a new designation with such express terms as may be fixed by the Board of Directors of the Corporation. (g) In the event that there is for any reason a change in the Federal Tax Rate (other than a change increasing such rate to more than 34%), then, in that event, the dividend rate on the Series Q Stock shall be automatically adjusted (but not higher than a rate of $105.00 per annum), effective as of the effective date of change for each such change, to the rate per annum determined by multiplying the original dividend rate on such Series Q Stock by the Adjustment Fraction. For purposes of this Section 23(g), the following definitions shall apply: "ADJUSTMENT FRACTION" shall mean the following fraction resulting from the following formula: (1 - (Xo x Fo)) x (1 - Fn) (1 - (Xo x Fn)) x (1 - Fo) where 39 Xo = 30% (the Inclusion Rate, which is that portion of dividends received that are includable in taxable income for corporations as set forth in the Internal Revenue Code of 1986 as amended) Fo = 34% (the Federal Tax Rate in effect on the date the original dividend rate was determined) Fn = the new Federal Tax Rate The Adjustment Fraction will be rounded to three decimal places with rounding up if the fourth decimal place is .0005 or higher, and rounding down otherwise. "FEDERAL TAX RATE" shall mean the highest marginal income tax rate in effect for corporations as set forth in the Internal Revenue Code of 1986 as amended. {Section 24. Serial Preferred Stock, $88.00 Series R.} Of the 4,000,000 authorized shares of Serial Preferred Stock, 50,000 shares are designated as a series entitled "Serial Preferred Stock, $88.00 Series R" (hereinafter called "Series R Stock"). The shares of Series R Stock shall have the express terms set forth in this Division as being applicable to all shares of Serial Preferred Stock as a class and, in addition, the following express terms applicable to all shares of Series R Stock as a series of the Serial Preferred Stock: (a) The annual dividend rate of the Series R Stock shall be $88.00 per share. (b) Dividends on Series R Stock shall be payable, if declared, quarterly on the first day of March, June, September and December of each year, the first quarterly dividend being payable, if declared, on March 1, 1992, to the extent accrued. The amount of dividends pay- able on any share of Series R Stock for any period shorter than a full quarterly dividend period shall be calculated on the basis of a 360-day year and 30-day months and, with respect to any month in which such share of the Series R Stock is not outstanding for the entire month, the actual number of days that such share of Series R Stock is outstanding in such month. (c) Dividends on Series R Stock shall be cumulative as follows: (1) With respect to shares included in the initial issue of Series R Stock and shares issued any time thereafter up to and includ- ing the record date for the payment of the first dividend on the initial issue of Series R Stock, dividends shall be cumula- tive from the date of the initial issue of Series R Stock; and 40 (2) With respect to shares issued any time after the aforesaid record date, dividends shall be cumulative from the dividend payment date next preceding the date of issue of such shares, except that if such shares are issued during the period com- mencing the day after the record date for the payment of a dividend on Series R Stock and ending on the payment date of that dividend, dividends with respect to such shares shall be cumulative from that dividend payment date. (d) Subject to the provisions of Section 5(c)(3) of this Division and in the manner provided in Sections 3(b)(1) and (2) of this Division, the Corporation shall, on December 1, 2001, redeem all shares of Series R Stock then outstanding at the redemption price of $1,000.00 per share, plus an amount per share equal to all dividends accrued and unpaid thereon to the date of redemption. If the Corporation shall not have on such date sufficient funds legally available to effect such mandatory redemption, it shall set aside for such re- demption on such date such funds, if any, as are then legally available, and shall do so as promptly as practicable thereafter as the Corporation determines that it has funds then legally available, and shall apply such funds to the redemption of shares of Series R Stock as provided in this paragraph until it has redeemed all of the Series R Stock. Notwithstanding the foregoing, if at any time the Corporation (i) shall be obligated to redeem Series R Stock or to set aside legally available funds for that purpose and to redeem other Serial Preferred Stock and (ii) shall not have sufficient funds legally available to do so in full, then such portion of such then legally available funds shall be set aside to redeem the Series R Stock as shall bear the same ratio to the total funds then legally available to effect such redemption and to meet the then unmet obli- gations to redeem all outstanding Serial Preferred Stock as the then unmet obligation to redeem Series R Stock bears to the aggregate of such unmet obligations to redeem and the then unmet obligations to redeem all outstanding Serial Preferred Stock. At any time follow- ing the setting aside of funds to redeem Series R Stock pursuant to this paragraph when the amount so set aside is sufficient to redeem at least 100 shares of Series R Stock, the Corporation shall promptly call for redemption such number of whole shares of Series R Stock as may be redeemed with such amount at the redemption price of $1,000.00 per share, plus accrued but unpaid dividends on Series R Stock then being redeemed to the date of redemption. The shares of Series R Stock shall not be subject to redemption except pursuant to this paragraph. (e) The amount payable per share on Series R Stock in the event of any liquidation, dissolution or winding up of the affairs of the Corporation shall be $1,000.00, plus an amount equal to all dividends accrued and unpaid thereon to the date of payment of the amount due pursuant to this paragraph. 41 (f) The number of shares of Series R Stock shall not be increased above, and shall not exceed, 50,000. Series R Stock once redeemed, pur- chased or otherwise acquired by the Corporation shall not be re- issued as shares of Series R Stock, but, having been restored to the status of authorized but unissued shares of Serial Preferred Stock without serial designation, may, in whole or in part, be, or be in- cluded in, any subsequent series of Serial Preferred Stock of a new designation with such express terms as may be fixed by the Board of Directors of the Corporation. {Section 25. Serial Preferred Stock, $90.00 Series S.} Of the 4,000,000 authorized shares of Serial Preferred Stock, 75,000 shares are designated as a series entitled "Serial Preferred Stock, $90.00 Series S" (hereinafter called "Series S Stock"). The shares of Series S Stock shall have the express terms set forth in this Division as being applicable to all shares of Serial Preferred Stock as a class and, in addition, the following express terms applicable to all shares of Series S Stock as a series of the Serial Preferred Stock: (a) The annual dividend rate of the Series S Stock shall be $90.00 per share. (b) Dividends on Series S Stock shall be payable, if declared, quarterly on the first day of February, May, August and November of each year, the first quarterly dividend being payable, if declared, on February 1, 1993, to the extent accrued. The amount of dividends payable for the initial dividend period or any period shorter than a full quarterly dividend period shall be calculated on the basis of a 360-day year and 30-day months or, with respect to any month in which any share of the Series S Stock is not outstanding for the entire month, the actual number of days that such share of Series S Stock is outstanding in such month. (c) Dividends on Series S Stock shall be cumulative as follows: (1) With respect to shares included in the initial issue of Series S Stock and shares issued any time thereafter up to and includ- ing the record date for the payment of the first dividend on the initial issue of Series S Stock, dividends shall be cumula- tive from the date of the initial issue of Series S Stock; and (2) With respect to shares issued any time after the aforesaid record date, dividends shall be cumulative from the dividend payment date next preceding the date of issue of such shares, except that if such shares are issued during the period com- mencing the day after the record date for the payment of a dividend on Series S Stock and ending on the payment date of that dividend, dividends with respect to such shares shall be cumulative from that dividend payment date. 42 (d) Subject to the provisions of Section 5(c)(3) of this Division and in the manner provided in Sections 3(b)(1) and (2) of this Division, the Corporation shall, on November 1, 1999 and on each November 1 thereafter, redeem 18,750 shares of Series S Stock, or the number of shares then outstanding, if less, at the redemption price of $1,000.00 per share, plus an amount per share equal to all dividends accrued and unpaid thereon to the date of redemption. If the Corporation shall not have on any such date sufficient funds legally available to effect such mandatory redemption, it shall set aside for such redemption on such date such funds, if any, as are then legally available, and shall do so as promptly as practicable there- after as the Corporation determines that it has funds then legally available, and shall apply such funds to the redemption of shares of Series S Stock as provided in the last sentence of this paragraph until it has redeemed all of the Series S Stock then required to be redeemed pursuant to the first sentence of this paragraph. Notwith- standing the foregoing, if at any time the Corporation (i) shall be obligated to redeem Series S Stock or to set aside legally available funds for that purpose and to redeem other Serial Preferred Stock for its sinking fund or other mandatory redemption terms and (ii) shall not have sufficient funds legally available to do so in full, then such portion of such then legally available funds shall be set aside to redeem the Series S Stock as shall bear the same ratio to the total funds then legally available to effect such redemption and to meet the then unmet obligations of the sinking fund and other mandatory redemption terms of all outstanding Serial Preferred Stock as the then unmet obligation to redeem Series S Stock bears to the aggregate of such unmet obligations to redeem and the then unmet obligations of the sinking fund and other mandatory redemption terms of all outstanding Serial Preferred Stock. At any time following the setting aside of funds to redeem Series S Stock pursuant to this paragraph when the amount so set aside is sufficient to redeem at least 100 shares of Series S Stock, the Corporation shall promptly call for redemption such number of whole shares of Series S Stock as may be redeemed with such amount at the redemption price of $1,000.00 per share, plus accrued but unpaid dividends on Series S Stock then being redeemed to the date of redemption. The shares of Series S Stock shall not be subject to redemption except pursuant to this paragraph. (e) The amount payable per share on Series S Stock in the event of any liquidation, dissolution or winding up of the affairs of the Corporation shall be $1,000.00, plus an amount equal to all dividends accrued and unpaid thereon to the date of payment of the amount due pursuant to this paragraph. 43 (f) The number of shares of Series S Stock shall not be increased above, and shall not exceed, 75,000. Series S Stock once redeemed, pur- chased or otherwise acquired by the Corporation shall not be re- issued as shares of Series S Stock, but, having been restored to the status of authorized but unissued shares of Serial Preferred Stock without serial designation, may, in whole or in part, be, or be included in, any subsequent series of Serial Preferred Stock of a new designation with such express terms as may be fixed by the Board of Directors of the Corporation. {Section 26. Serial Preferred Stock, $42.40 Series T.} Of the 4,000,000 authorized shares of Serial Preferred Stock, 200,000 shares are designated as a series entitled "Serial Preferred Stock, $42.40 Series T" (hereinafter called "Series T Stock"). The shares of Series T Stock shall have the express terms set forth in this Division as being applicable to all shares of Serial Preferred Stock as a class and, in addition, the following express terms applicable to all shares of Series T Stock as a series of the Serial Preferred Stock: (a) The annual dividend rate of the Series T Stock shall be $42.40 per share. (b) Dividends on Series T Stock shall be payable, if declared, quarterly on the first day of February, May, August and November of each year, the first quarterly dividend being payable, if declared, on August 1, 1993, to the extent accrued. The amount of dividends pay- able for the initial dividend period or any period shorter than a full quarterly dividend period shall be calculated on the basis of a 360-day year and 30-day months or, with respect to any month in which any share of the Series T Stock is not outstanding for the entire month, the actual number of days that such share of Series T Stock is outstanding in such month. (c) Dividends on Series T Stock shall be cumulative as follows: (1) With respect to shares included in the initial issue of Series T Stock and shares issued any time thereafter up to and includ- ing the record date for the payment of the first dividend on the initial issue of Series T Stock, dividends shall be cumula- tive from the date of the initial issue of Series T Stock; and (2) With respect to shares issued any time after the aforesaid record date, dividends shall be cumulative from the dividend payment date next preceding the date of issue of such shares, except that if such shares are issued during the period com- mencing the day after the record date for the payment of a dividend on Series T Stock and ending on the payment date of that dividend, dividends with respect to such shares shall be cumulative from that dividend payment date. 44 (d) Series T Stock shall not be redeemable prior to June 1, 1998. Thereafter, subject to the provisions of Section 5(c)(3) of this Division and in the manner provided in Sections 3(b)(1) and (2) of this Division, Series T Stock shall be redeemable at any time or from time to time, at the option of the Board of Directors, upon payment of $500.00 per share, plus an amount per share equal to all dividends accrued and unpaid thereon to the date of redemption. (e) The amount payable per share on Series T Stock in the event of any liquidation, dissolution or winding up of the affairs of the Corporation shall be $500.00, plus an amount per share equal to all dividends accrued and unpaid thereon to the date of payment of the amount due pursuant to this paragraph. (f) The number of shares of Series T Stock shall not be increased above, and shall not exceed, 200,000. Series T Stock once redeemed, pur- chased or otherwise acquired by the Corporation shall not be re- issued as shares of Series T Stock, but, having been restored to the status of authorized but unissued shares of Serial Preferred Stock without serial designation, may, in whole or in part, be, or be included in, any subsequent series of Serial Preferred Stock of a new designation with such express terms as may be fixed by the Board of Directors of the Corporation. DIVISION B The Preference Stock shall have the following express terms: {Section 1. Preferences; Series.} The Preference Stock shall rank junior to the Serial Preferred Stock as to the payment of dividends and as to distribu- tions in the event of a voluntary or involuntary liquidation, dissolution or winding up of the affairs of the Corporation. The Preference Stock may be issued from time to time in one or more series. All shares of Preference Stock shall be of equal rank and shall be identical, except in respect of the matters that may be fixed by the Board of Directors as hereinafter provided, and each share of a series shall be identical with all other shares of such series, except as to the date from which dividends are cumulative. Subject to the provisions of Sections 2 to 7, inclusive, of this Division, which pro- visions shall apply to all Preference Stock, the Board of Directors hereby is authorized to cause such shares to be issued in one or more series and with respect to each such series to determine and fix prior to the issuance thereof (and thereafter, to the extent provided in clause (b) of this Section) the following: (a) The designation of the series, which may be by distinguishing number, letter or title; 45 (b) The number of shares of the series, which number the Board of Directors may (except where otherwise provided in the creation of the series) increase or decrease from time to time before or after the issuance thereof (but not below the number of shares thereof then outstanding); (c) The annual dividend rate or rates of the series; (d) The dates on which and the period or periods for which dividends, if declared, shall be payable and the date or dates from which dividends shall accrue and be cumulative; (e) The redemption rights and price or prices, if any, for shares of the series; (f) The terms and amount of the sinking fund, if any, for the purchase or redemption of shares of the series; (g) The amounts payable on shares of the series in the event of any voluntary or involuntary liquidation, dissolution or winding up of the affairs of the Corporation, which may be different for voluntary and involuntary liquidation, dissolution or winding up; (h) Whether the shares of the series shall be convertible into Common Stock or shares of any other class ranking junior to the Preference Stock or any series of the same class of stock of the Corporation and, if so, the conversion rate or rates or price or prices, any adjustments thereof and all other terms and conditions upon which such conversion may be made; and (i) Restrictions (in addition to those set forth in Sections 5(c) and 5(d) of this Division) on the issuance of shares of the same series or of any other class or series. The Board of Directors is authorized to adopt from time to time amendments to the Amended Articles or Incorporation fixing, with respect to each such series, the matters described in clauses (a) through (i), inclusive, of this Section. {Section 2. Dividends.} (a) The holders of Preference Stock of each series, subject to the prior preference with respect to dividends upon Serial Preferred Stock set forth in Section 2 of Division A and in preference to the holders of Common Stock and of any other class of shares ranking junior to the Preference Stock, shall be entitled to receive out of any funds legally available and when and as declared by the Board of Directors, dividends in cash at the rate or rates for such series fixed in accordance with the provisions of Section 1 of this Division and no more, payable on the dates fixed for such series. Such dividends shall be cumulative, in the case of shares of each particular series, from and after the date or dates fixed with 46 respect to such series. No dividends shall be paid upon or declared or set apart for any series of the Preference Stock for any dividend period unless at the same time a like proportionate dividend for the dividend periods terminating on the same or any earlier date, ratably in proportion to the respective annual dividend rates fixed therefor, shall have been paid upon or declared or set apart for all Preference Stock of all series then issued and outstanding and entitled to receive such dividend. (b) So long as any Preference Stock shall be outstanding no dividend, except a dividend payable in Common Stock or other shares ranking junior to the Preference Stock, shall be paid or declared or any distribution be made, except as aforesaid, in respect of the Common Stock or any other shares ranking junior to the Preference Stock, nor shall any Common Stock or any other shares ranking junior to the Preference Stock be purchased, retired or otherwise acquired by the Corporation, except out of the proceeds of the sale of Common Stock or other shares of the Corporation ranking junior to the Preference Stock received by the Corporation subsequent to the date of first issuance of Preference Stock of any series, unless: (1) All accrued and unpaid dividends on Preference Stock, including the full dividends for all current dividend periods, shall have been declared and paid or a sum sufficient for payment thereof set apart; and (2) There shall be no arrearages with respect to the redemption of Preference Stock of any series from any sinking fund provided for shares of such series in accordance with the provisions of Section 1 of this Division. {Section 3. Redemption.} (a) Subject to the express terms of each series and to the provisions of Section 5(c)(2) of this Division, the Corporation: (1) May, from time to time at the option of the Board of Directors, redeem all or any part of any redeemable series of Preference Stock at the time outstanding at the applicable redemption price for such series fixed in accordance with the provisions of Section 1 of this Division; and (2) Shall, from time to time, make such redemptions of each series of Preference Stock as may be required to fulfill the requirements of any sinking fund provided for shares of such series at the applicable sinking fund redemption price fixed in accordance with the provisions of Section 1 of this Division; 47 and shall in each case pay all accrued and unpaid dividends to the redemption date. (b) (1) Notice of every such redemption shall be mailed, postage pre- paid, to the holders of record of the Preference Stock to be redeemed at their respective addresses then appearing on the books of the Corporation, not less than 30 days nor more than 90 days prior to the date fixed for such redemption, or such other time prior thereto as the Board of Directors shall fix for any series pursuant to Section 1(e) of this Division prior to the issuance thereof. At any time after notice as provided above has been deposited in the mail, the Corporation may deposit the aggregate redemption price of the shares of Preference Stock to be redeemed, together with accrued and unpaid dividends thereon to the redemption date, with any bank or trust company in Ohio or New York, New York, having capital and surplus of not less than $25,000,000, named in such notice, directed to be paid to the respective holders of the shares of Preference Stock so to be redeemed, in amounts equal to the redemption price of all shares of Preference Stock so to be redeemed, on surrender of the stock certificate or certificates held by such holders; and upon the deposit of such notice in the mail and the making of such deposit of money with such bank or trust company, such holders shall cease to be shareholders with respect to such shares; and from and after the time such notice shall have been so deposited and such deposit of money shall have been so made, such holders shall have no interest in or claim against the Corporation with respect to such shares, except only the right to receive such money from such bank or trust company without interest or to exercise, before the re- demption date, any unexpired privileges of conversion. In the event less than all of the outstanding shares of Preference Stock are to be redeemed, the Corporation shall select by lot or pro rata the shares so to be redeemed in such manner as shall be prescribed by the Board of Directors. (2) If the holders of shares of Preference Stock which have been called for redemption shall not, within six years after such deposit, claim the amount deposited for the redemption thereof, any such bank or trust company shall, upon demand, pay over to the Corporation such unclaimed amounts and thereupon such bank or trust company shall be relieved of all responsibility in respect thereof and to such holders. (c) Except as otherwise provided in Section 5(d)(2) of this Division, the Corporation may also from time to time purchase or otherwise acquire, for a consideration, shares of its outstanding Preference Stock of any series. 48 (d) Any shares of Preference Stock which are (1) redeemed by the Corporation pursuant to the provisions of this Section, (2) pur- chased and delivered in satisfaction of any sinking fund require- ments provided for shares of such series, (3) converted in accordance with the express terms thereof, or (4) otherwise acquired by the Corporation, shall resume the status of authorized but unissued shares of Preference Stock without serial designation. {Section 4. Liquidation.} (a) Subject to the prior preference with respect to distributions to holders of Serial Preferred Stock in the event of a voluntary or in- voluntary liquidation, dissolution or winding up of the affairs of the Corporation: (1) The holders of Preference Stock of any series shall, in the event of a voluntary or involuntary liquidation, dissolution or winding up of the affairs of the Corporation, be entitled to receive in full out of the assets of the Corporation, including its capital, before any amount shall be paid or distributed among the holders of the Common Stock or any other shares rank- ing junior to the Preference Stock, the amounts fixed with re- spect to shares of such series in accordance with Section 1 of this Division, plus an amount equal to all dividends accrued and unpaid thereon to the date of payment of the amount due pursuant to such liquidation, dissolution or winding up of the affairs of the Corporation; and in the event the net assets of the Corporation legally available therefor are insufficient to permit the payment upon all outstanding shares of Preference Stock of the full preferential amount to which they are re- spectively entitled, then such net assets shall be distributed ratably upon outstanding shares of Preference Stock in propor- tion to the full preferential amount to which each such share is entitled; and (2) After payment to the holders of Preference Stock of the full preferential amounts as aforesaid, the holders of Preference Stock, as such, shall have no right or claim to any of the remaining assets of the Corporation. (b) The merger or consolidation of the Corporation into or with any other corporation, the merger of any other corporation into it, or the sale, lease or conveyance of all or substantially all the property or business of the Corporation, shall not be deemed to be a dissolution, liquidation or winding up for the purposes of this Section. (c) Nothing in this Section 4 of this Division shall be deemed to prevent the purchase, acquisition or other retirement by the Corporation of any shares of its outstanding stock as now or in the future authorized or permitted by the laws of the State of Ohio. 49 {Section 5. Voting.} (a) The holders of Preference Stock shall have no voting rights, except as provided in this Section or required by law. (b) (1) If, and so often as, the Corporation shall be in default in the payment of the equivalent of the full dividends for a number of dividend payment periods (whether or not consecutive) which in the aggregate contain at least 540 days on any series of Preference Stock at the time outstanding, whether or not earned or declared, the holders of Preference Stock of all series, voting separately as a class, shall be entitled to elect, as herein provided, two members of the Board of Directors of the Corporation, subject to the prior rights of the holders of Serial Preferred Stock as hereinbefore provided in Division A; provided, however, that the holders of shares of Preference Stock shall not have or exercise such special class voting rights except at meetings of such shareholders for the election of Directors at which the holders of not less than 50% of the outstanding shares of Preference Stock of all series then outstanding are present in person or by proxy; and provided further that the special class voting rights provided for in this paragraph when the same shall have become vested shall remain so vested until all accrued and unpaid dividends on the Preference Stock of all series then outstanding shall have been paid, where- upon the holders of Preference Stock shall be divested of their special class voting rights in respect of subsequent elections of Directors, subject to the revesting of such special class voting rights in the event hereinabove specified in this paragraph. (2) In the event of default entitling the holders of Preference Stock to elect two Directors as specified in Paragraph 1 of this Subsection, a special meeting of such holders for the purpose of electing such Directors shall be called by the Secretary of the Corporation upon written request of, or may be called by, the holders of record of at least 10% of the shares of Preference Stock of all series at the time outstanding, and notice thereof shall be given in the same manner as that re- quired for the annual meeting of shareholders; provided, how- ever, that the Corporation shall not be required to call such special meeting if the annual meeting of shareholders shall be held within 120 days after the date of receipt of the foregoing written request from the holders of Preference Stock. At any meeting at which the holders of Preference Stock shall be entitled to elect Directors, the holders of 50% of the then outstanding shares of Preference Stock of all series, present in person or by proxy, shall be sufficient to constitute a quorum, and the vote of the holders of a majority of such shares so present at any such meeting at which there shall be such a quorum shall be sufficient to elect the members of the Board of Directors which the holders of Preference Stock are 50 entitled to elect as hereinabove provided. Notwithstanding any provision of these Amended Articles of Incorporation or the Regulations of the Corporation or any action taken by the holders of any class of shares fixing the number of Directors of the Corporation, the two Directors who may be elected by the holders of Preference Stock pursuant to this Subsection shall serve in addition to any other Directors then in office or pro- posed to be elected otherwise than pursuant to this Subsection. Nothing in this Subsection shall prevent any change otherwise permitted in the total number of Directors of the Corporation or require the resignation of any Director elected otherwise than pursuant to this Subsection. Notwithstanding any classification of the other Directors of the Corporation, the two Directors elected by the holders of Preference Stock shall be elected annually for terms expiring at the next succeeding annual meeting of shareholders. (3) In case of any vacancy in the office of a Director occurring among the Directors elected by the holders of the Preference Stock, voting separately as a class, or of a vacancy in the office of his or her successor appointed as below provided, the remaining Director so elected may elect a successor to hold office for the unexpired term of the Director whose place shall be vacant. Likewise, in case of any vacancy in the office of a Director occurring among the Directors not elected by the holders of the Serial Preferred Stock or the Preference Stock, or of a vacancy in the office of his or her successor appointed as below provided, the remaining Directors not elected by the holders of the Serial Preferred Stock or the Preference Stock, by affirmative vote of a majority thereof, or the remaining such Director if there be but one, may elect a successor or successors to hold office for the unexpired term of the Director or Directors whose place or places shall be vacant. (c) The holders of the outstanding shares of any series of Preference Stock shall not have any right under the provisions set forth in this Section 5 to vote in respect of the authorization of issuance of any shares of any class of stock of the Corporation if, through the application of proceeds thereof or otherwise in connection therewith, provision is to be made for redemption or retirement of all of the shares of such series of Preference Stock at the time outstanding. (d) The affirmative vote or consent of the holders of at least two- thirds of the shares of Preference Stock at the time outstanding, voting or consenting separately as a class, given in person or by proxy either in writing or at a meeting called for the purpose, shall be necessary to effect any one or more of the following (but so far as the holders of Preference Stock are concerned, such action may be effected with such vote or consent): 51 (1) Any amendment, alteration or repeal of any of the provisions of the Amended Articles of Incorporation or of the Regulations of the Corporation which affects adversely the preferences or vot- ing or other rights of the holders of Preference Stock; pro- vided, however, that for the purpose of this paragraph only, neither the amendment of the Amended Articles of Incorporation so as to authorize, create or change the authorized or out- standing amount of Preference Stock or of any shares of any class ranking on a parity with or junior to the Preference Stock nor the amendment of the provisions of the Regulations so as to change the number of Directors of the Corporation shall be deemed to affect adversely the preferences or voting or other rights of the holders of Preference Stock; and provided further, that if such amendment, alteration or repeal affects adversely the preferences or voting or other rights of one or more but not all series of Preference Stock at the time out- standing, only the affirmative vote or consent of the holders of at least two-thirds of the number of the shares at the time outstanding of the series so affected shall be required; or (2) The purchase or redemption (for sinking fund purposes or other- wise) of less than all of the Preference Stock then outstanding except in accordance with a stock purchase offer made to all holders of record of Preference Stock, unless all dividends on all Preference Stock then outstanding for all previous dividend periods shall have been declared and paid or funds therefor set apart and all accrued sinking fund obligations applicable thereto shall have been complied with. (e) The affirmative vote or consent of the holders of at least a majority of the shares of Preference Stock at the time outstanding, voting or consenting separately as a class, given in person or by proxy either in writing or at a meeting called for the purpose, shall be necessary to effect any one or more of the following (but so far as the holders of Preference Stock are concerned, such action may be effected with such vote or consent): (1) The sale, lease or conveyance by the Corporation of all or substantially all of its property or business; (2) The consolidation of the Corporation with or its merger into any other corporation, unless the corporation resulting from such consolidation or surviving such merger will not have after such consolidation or merger any class of shares either author- ized or outstanding ranking prior to or on a parity with the Preference Stock except the same number of shares ranking prior to or on a parity with the Preference Stock and having the same rights and preferences as the shares of the Corporation author- ized and outstanding immediately preceding such consolidation or merger (and each holder of Preference Stock immediately preceding such consolidation or merger shall receive the same number of shares with the same rights and preferences of the 52 resulting or surviving corporation); provided, however, that no vote or consent of the holders of Preference Stock shall be necessary to effect the consolidation of the Corporation with or its merger into a company owning all or a majority of the Corporation's Common Stock, or any affiliate; (3) The authorization, creation or the increase in the authorized amount of any shares of any class or any security convertible into shares of any class, in either case ranking prior to the Preference Stock; or (4) The authorization of any shares ranking on a parity with or convertible into the Preference Stock, or convertible into a class of stock on a parity with the Preference Stock, or an increase in the authorized number of shares of Preference Stock. (f) Neither the vote, consent nor any adjustment of the voting rights of holders of shares of Preference Stock shall be required for an in- crease in the number of shares of Common Stock authorized or issued or for stock splits of the Common Stock or for stock dividends on any class of stock payable solely in Common Stock; and none of the foregoing actions shall be deemed to affect adversely the preferences or voting or other rights of Preference Stock within the meaning and for the purpose of this Division. {Section 6. Pre-emptive Rights.} No holder of Preference Stock as such, shall have any pre-emptive right to purchase, have offered to him for purchase or subscribe for any of the Corporation's shares or other securities of any class, whether now or hereafter authorized. {Section 7. Definitions.} For the purposes of this Division: (a) Whenever reference is made to shares "ranking prior to the Preference Stock", such reference shall mean and include all shares of the Corporation in respect of which the rights of the holders thereof as to the payment of dividends or as to distributions in the event of a voluntary or involuntary liquidation, dissolution or winding up of the affairs of the Corporation are given preference over the rights of the holders of Preference Stock; (b) Whenever reference is made to shares "on a parity with the Preference Stock", such reference shall mean and include all shares of the Corporation in respect of which the rights of the holders thereof as to the payment of dividends and as to distributions in the event of a voluntary or involuntary liquidation, dissolution or winding up of the affairs of the Corporation rank on an equality (except as to the amounts fixed therefor) with the rights of the holders of Preference Stock; and 53 (c) Whenever reference is made to shares "ranking junior to the Preference Stock", such reference shall mean and include all shares of the Corporation other than those defined under Subsections (a) and (b) of this Section as shares "ranking prior to" or "on a parity with" the Preference Stock. {Section 8. Preference Stock, $77.50 Series 1.} Redeemed August 1, 1989. DIVISION C The Common Stock shall have the following express terms: {Section 1. General.} The Common Stock shall be subject to the express terms of the Serial Preferred Stock and any series thereof and to the express terms of the Preference Stock and any series thereof. Each share of Common Stock shall be equal to every other share of Common Stock and the holders thereof shall be entitled to one vote for each share of Common Stock on all questions presented to the shareholders. {Section 2. Changes in Number of Authorized Shares.} The affirmative vote or consent of the holders of at least a majority of the shares of Common Stock at the time outstanding, voting or consenting separately as a class, given in person or by proxy either in writing or at a meeting called for the purpose, shall be necessary to effect a change in the authorized number of shares of the Corporation or of any class of such shares. {Section 3. Pre-emptive Rights.} No holder of Common Stock shall have any pre-emptive right to purchase, have offered to him for purchase or subscribe for any of the Corporation's shares or other securities of any class, whether now or hereafter authorized. ARTICLE FIVE. The Corporation, by action of the Board of Directors, may purchase shares of any class issued by the Corporation. ARTICLE SIX. These Amended Articles of Incorporation shall supersede and take the place of the heretofore existing Amended Articles of Incorporation of the Corporation and all amendments thereof prior to the date hereof. EX-24.B 12 EXHIBIT FOR CEI 1 Exhibit 24b(CEI) POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF THE CLEVELAND ELECTRIC ILLUMINATING COMPANY The undersigned, being a director or officer or both (as stated under his or her signature below) of The Cleveland Electric Illuminating Company, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 22nd day of March, 1994. ROBERT J. FARLING Robert J. Farling Chairman, Chief Executive Officer and Director PEGGY KELLY Signed and acknowledged in the presence of: 2 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF THE CLEVELAND ELECTRIC ILLUMINATING COMPANY The undersigned, being a director or officer or both (as stated under his or her signature below) of The Cleveland Electric Illuminating Company, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 18th day of March, 1994. GARY R. LEIDICH Gary R. Leidich Vice President and Chief Financial Officer J.T. PERCIO Signed and acknowledged in the presence of: 3 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF THE CLEVELAND ELECTRIC ILLUMINATING COMPANY The undersigned, being a director or officer or both (as stated under his or her signature below) of The Cleveland Electric Illuminating Company, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 17 day of March, 1994. MURRAY R. EDELMAN Murray R. Edelman President and Director M. E. G. JANSEN Signed and acknowledged in the presence of: --------------- 4 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF THE CLEVELAND ELECTRIC ILLUMINATING COMPANY The undersigned, being a director or officer or both (as stated under his or her signature below) of The Cleveland Electric Illuminating Company, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 18th day of March, 1994. FRED J. LANGE, JR. Fred J. Lange, Jr. Vice President and Director PEGGY KELLY Signed and acknowledged in the presence of: 5 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF THE CLEVELAND ELECTRIC ILLUMINATING COMPANY The undersigned, being a director or officer or both (as stated under his or her signature below) of The Cleveland Electric Illuminating Company, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 16th day of March, 1994. PAUL G. BUSBY Paul G. Busby Controller RUTH A. HARNER Signed and acknowledged in the presence of: EX-24.B 13 EXHIBIT FOR TE 1 Exhibit 24b(TE) POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF THE TOLDEO EDISON COMPANY The undersigned, being a director or officer or both (as stated under his or her signature below) of The Toledo Edison Company, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 22nd day of March, 1994. ROBERT J. FARLING Robert J. Farling Chairman, Chief Executive Officer and Director PEGGY KELLY Signed and acknowledged in the presence of: 2 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF THE TOLEDO EDISON COMPANY The undersigned, being a director or officer or both (as stated under his or her signature below) of The Toledo Edison Company, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 18th day of March, 1994. GARY R. LEIDICH Gary R. Leidich Vice President and Chief Financial Officer J. T. PERCIO Signed and acknowledged in the presence of: 3 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF THE TOLEDO EDISON COMPANY The undersigned, being a director or officer or both (as stated under his or her signature below) of The Toledo Edison Company, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 17 day of March, 1994. MURRAY R. EDELMAN Murray R. Edelman Vice Chairman and Director M. E. G. JANSEN Signed and acknowledged in the presence of: --------------- 4 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF THE TOLEDO EDISON COMPANY The undersigned, being a director or officer or both (as stated under his or her signature below) of The Toledo Edison Company, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 18th day of March, 1994. FRED J. LANGE, JR. Fred J. Lange, Jr. President and Director PEGGY KELLY Signed and acknowledged in the presence of: 5 POWER OF ATTORNEY OF DIRECTOR AND/OR OFFICER OF THE TOLEDO EDISON COMPANY The undersigned, being a director or officer or both (as stated under his or her signature below) of The Toledo Edison Company, an Ohio corporation (hereinafter called the "Company"), does hereby constitute and appoint each of Robert J. Farling, Murray R. Edelman, Fred J. Lange, Jr., Gary R. Leidich, Paul G. Busby, Gary M. Hawkinson, E. Lyle Pepin, Janis T. Percio, Ronald J. Studeny, Terrence G. Linnert, Mary E. O'Reilly, Kevin P. Murphy, Michael C. Regulinski and Bruce T. Rosenbaum as an attorney of the undersigned with power to act alone for and in the name, place and stead of the undersigned, with power of substitution and resubstitution, to sign and file, including electronic filing, on behalf of the undersigned acting in his or her capacity as such director or officer the Company's Form 10-K Annual Report for the year ended December 31, 1993, and any and all amendments, exhibits and supplementary information thereto, with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, with full power and authority to do and perform any and all acts and things whatsoever requisite and necessary to be done in the premises and the undersigned hereby ratifies and approves the acts of each such attorney and any such substitute or substitutes. IN WITNESS WHEREOF, the undersigned hereby has signed his or her name this 16th day of March, 1994. PAUL G. BUSBY Paul G. Busby Controller RUTH A. HARNER Signed and acknowledged in the presence of: -----END PRIVACY-ENHANCED MESSAGE-----