-----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, puU7XK3HpE/2aVbYkf3E9INmZc4LuWvAdJWCI+Zu0b2dqZbNbhfCVBD97TRblZl9 5s8ut0UYKf7vLpmLrsQMNA== 0000073960-94-000004.txt : 19940325 0000073960-94-000004.hdr.sgml : 19940325 ACCESSION NUMBER: 0000073960-94-000004 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 12 CONFORMED PERIOD OF REPORT: 19931231 FILED AS OF DATE: 19940324 FILER: COMPANY DATA: COMPANY CONFORMED NAME: OHIO EDISON CO CENTRAL INDEX KEY: 0000073960 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 340437786 STATE OF INCORPORATION: OH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 001-02578 FILM NUMBER: 94517615 BUSINESS ADDRESS: STREET 1: 76 S MAIN ST CITY: AKRON STATE: OH ZIP: 44308 BUSINESS PHONE: 2163845100 10-K 1 OE10K 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 File Number 1-2578 OHIO EDISON COMPANY (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) OHIO 34-0437786 (STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.) 76 SOUTH MAIN STREET, AKRON, OHIO 44308 (ADDRESS OF PRINCIPAL EXECUTIVE OFFICE) (ZIP CODE) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (216) 384-5100 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ------------------- --------------------- Each registered on Common Stock, $9 par value New York Stock Exchange Rights to Purchase Common Stock and Chicago Stock Exchange Cumulative Preferred Stock, $100 par value 3.90% Series 7.24% Series 4.40% Series 7.36% Series All series registered on 4.44% Series 8.20% Series New York Stock Exchange 4.56% Series and Chicago Stock Exchange Cumulative Preferred Stock, $25 par value Registered on 7.75% Series New York Stock Exchange and Chicago Stock Exchange SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None 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 registrant's 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 --- Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: Yes X No --- --- State the aggregate market value of the voting stock held by non-affiliates of the registrant: $3,087,968,771 as of March 7, 1994 Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date: CLASS OUTSTANDING AT MARCH 23, 1994 ----- ----------------------------- Common Stock, $9 par value 152,569,437 Documents incorporated by reference (to the extent indicated herein): PART OF FORM 10-K INTO WHICH DOCUMENT DOCUMENT IS INCORPORATED -------- ---------------------------- Annual Report to Stockholders for the fiscal year ended December 31, 1993 (Pages 16-33) Part II Proxy Statement for 1994 Annual Meeting of Stockholders to be held April 28, 1994 Part III TABLE OF CONTENTS Page ---- Part I Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . . . 1 The Company . . . . . . . . . . . . . . . . . . . . . . . 1 Central Area Power Coordination Group . . . . . . . . . . 1 Arrangements Among the CAPCO Companies. . . . . . . . . . 1 Reliance on the CAPCO Companies . . . . . . . . . . . . . 2 Perry Unit 2. . . . . . . . . . . . . . . . . . . . . . . 2 Financing and Construction. . . . . . . . . . . . . . . . 2 Future Financing. . . . . . . . . . . . . . . . . . . . . 2 Coverage Requirements . . . . . . . . . . . . . . . . . . 3 Utility Regulation. . . . . . . . . . . . . . . . . . . . 4 PUCO Rate Matters . . . . . . . . . . . . . . . . . . . . 5 FERC Rate Matters . . . . . . . . . . . . . . . . . . . . 5 Fuel Adjustment Clauses . . . . . . . . . . . . . . . . . 5 Nuclear Regulation. . . . . . . . . . . . . . . . . . . . 5 Nuclear Insurance . . . . . . . . . . . . . . . . . . . . 6 Environmental Matters . . . . . . . . . . . . . . . . . . 8 Air Regulation. . . . . . . . . . . . . . . . . . . . . . 8 Water Regulation. . . . . . . . . . . . . . . . . . . . . 9 Waste Disposal. . . . . . . . . . . . . . . . . . . . . . 9 Summary . . . . . . . . . . . . . . . . . . . . . . . . . 9 Fuel Supply . . . . . . . . . . . . . . . . . . . . . . . 10 Nuclear Fuel. . . . . . . . . . . . . . . . . . . . . . . 10 System Capacity and Reserves. . . . . . . . . . . . . . . 11 Regional Reliability. . . . . . . . . . . . . . . . . . . 11 Competition . . . . . . . . . . . . . . . . . . . . . . . 11 Research and Development. . . . . . . . . . . . . . . . . 12 Executive Officers. . . . . . . . . . . . . . . . . . . . 12 Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . . . 13 Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . 15 Item 4. Submission of Matters to a Vote of Security Holders . . . . 15 Part II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters . . . . . . . . . . . . . . . . . . . . 15 Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . 15 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . 15 Item 8. Financial Statements and Supplementary Data . . . . . . . . 15 Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . . . . 15 Part III Item 10. Directors and Executive Officers of the Registrant. . . . . 16 Item 11. Executive Compensation. . . . . . . . . . . . . . . . . . . 16 Item 12. Security Ownership of Certain Beneficial Owners and Management. . . . . . . . . . . . . . . . . . . . . . . . . 16 Item 13. Certain Relationships and Related Transactions. . . . . . . 16 Part IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K. . . . . . . . . . . . . . . . . . . . . . . . . . 16 PART I ITEM 1. BUSINESS The Company Ohio Edison Company (Company) was organized under the laws of the State of Ohio in 1930 and owns property and does business as an electric public utility in that state. The Company also has ownership interests in certain generating facilities located in the Commonwealth of Pennsylvania. The Company furnishes electric service to communities in a 7,500 square mile area of central and northeastern Ohio. It also provides transmission services and electric energy for resale to certain municipalities in the Company's service area and transmission services to certain rural cooperatives. The Company also engages in the sale, purchase and interchange of electric energy with other electric companies. The area it serves has a population of approximately 2,400,000. The Company owns all of the outstanding common stock of Pennsylvania Power Company (Penn Power), a Pennsylvania corporation, which furnishes electric service to communities in a 1,500 square mile area of western Pennsylvania. Penn Power also provides transmission services and electric energy for resale to certain municipalities in Pennsylvania. The area served by Penn Power has a population of approximately 360,000. Central Area Power Coordination Group (CAPCO) In September 1967, the CAPCO companies, consisting of the Company, Penn Power, The Cleveland Electric Illuminating Company (CEI), Duquesne Light Company (Duquesne) and The Toledo Edison Company (Toledo), announced a program for joint development of power generation and transmission facilities. Included in the program are Unit 7 at the W. H. Sammis Plant, Units 1, 2 and 3 at the Bruce Mansfield Plant, Units 1 and 2 at the Beaver Valley Power Station and Unit 1 at the Perry Nuclear Power Plant, each now in service. Perry Unit 2, a CAPCO nuclear generating unit whose construction had been previously suspended, has been abandoned by the CAPCO companies (see "Perry Unit 2"). Arrangements Among the CAPCO Companies The present CAPCO Basic Operating Agreement provides, among other things, for coordinated maintenance responsibilities among the CAPCO companies, a limited and qualified mutual backup arrangement in the event of outage of CAPCO units and certain capacity and energy transactions among the CAPCO companies. The agreements among the CAPCO companies generally treat the Company and Penn Power (Companies) as a single system as between them and the other three CAPCO companies, but, in agreements between the CAPCO companies and others, all five companies are treated as separate entities. Subject to any rights that might arise among the CAPCO companies as such, each member company, severally and not jointly, is obligated to pay only its proportionate share of the costs associated with the facilities and the cost of required fuel. The CAPCO companies have agreed that any modification of their arrangements or of their agreed-upon programs requires their unanimous consent. Should any member become unable to continue to pay its share of the costs associated with a CAPCO facility, -1- each of the other CAPCO companies could be adversely affected in varying degrees because it may become necessary for the remaining members to assume such costs for the account of the defaulting member. Reliance on the CAPCO Companies Under the agreements governing the construction and operation of CAPCO generating units, the responsibility is assigned to a specific CAPCO company. CEI has such responsibilities for Perry Unit 1 and Duquesne is responsible for Beaver Valley Units 1 and 2. The Company monitors activities in connection with these units but must rely to a significant degree on the operating company for necessary information. The Company in its oversight role as a practical matter cannot be privy to every detail; it is the operating company that must directly supervise activities and then exercise its reporting responsibilities to the co-owners. The Company critically reviews the information given to it by the operating company, but it cannot be absolutely certain that things that it would have considered significant have been reported or that it would always have reached exactly the same conclusion about matters that are reported. In addition, the time that is necessarily part of the compiling and analyzing process creates a lag between the occurrence of events and the time the Company becomes aware of their significance. The Companies have similar responsibilities to the other CAPCO companies with respect to W.H. Sammis Unit 7 and Bruce Mansfield Units 1, 2 and 3. Perry Unit 2 In December 1993, the Companies announced that they will not participate in further construction of Perry Unit 2 and have abandoned Perry Unit 2 as a possible electric generating plant. The Company determined that recovery from customers of its Perry Unit 2 investment is not probable, resulting in a $366,377,000 write-off of its investment in 1993. Penn Power expects its Perry Unit 2 investment to be recoverable from its customers. However, due to the anticipated delay in commencement of recovery and taking into account the expected rate treatment, Penn Power recognized an impairment to its Perry Unit 2 investment of $24,458,000 in 1993. As a result, net income for the year ended December 31, 1993, was reduced by $248,743,000 ($1.63 per share of common stock). Financing and Construction The Companies access the capital markets from time to time to provide funds for their construction programs and to refinance existing securities. Future Financing The Companies' total construction costs, excluding nuclear fuel, amounted to approximately $239,000,000 in 1993. Such costs included expenditures for the betterment of existing facilities and for the construction of transmission lines, distribution lines, substations and other additions. For the years 1994-1998, such construction costs are estimated to be approximately $1,000,000,000, of which approximately $235,000,000 is applicable to 1994. See "Environmental Matters" below with regard to possible environment-related expenditures not included in this estimate. During the 1994-1998 period, maturities of, and sinking fund requirements for, long-term debt and preferred stock will require expenditures by the Companies of approximately $1,389,000,000, of which approximately $444,000,000 is applicable to 1994 (including $50,000,000 -2- of preferred stock optionally redeemed in the first quarter of 1994). All or a major portion of maturing debt is expected to be refunded at or prior to maturity. Nuclear fuel purchases are financed through OES Fuel, Incorporated (a wholly owned subsidiary of the Company) commercial paper and loans, both of which are supported by a $325,000,000 long-term bank credit agreement. Investments for additional nuclear fuel during the 1994-1998 period are estimated to be approximately $204,000,000, of which approximately $45,000,000 applies to 1994. During the same periods, the Companies' nuclear fuel investments are expected to be reduced by approximately $261,000,000 and $64,000,000, respectively, as the nuclear fuel is consumed. Also, the Companies have operating lease commitments of approximately $547,000,000 for the 1994-1998 period, of which approximately $102,000,000 relates to 1994. The Companies recover the cost of nuclear fuel consumed and operating leases through their electric rates. Short-term borrowings of $104,126,000 at December 31, 1993 represented OES Capital, Incorporated (a wholly owned subsidiary of the Company) debt, which is secured by customer accounts receivable. OES Capital can borrow up to $120,000,000 under a receivables financing agreement at rates based on certain bank commercial paper. The Companies also had $85,000,000 of unused short-term bank lines of credit as of December 31, 1993. In addition, $132,000,000 of bank facilities that provide for borrowings on a short-term basis at the banks' discretion were available. OES Fuel had approximately $193,000,000 of unused borrowing capability at the end of 1993 which was available for reloan to the Company. Based on their present plans, the Companies may provide for their cash requirements in 1994 from: funds to be received from operations; available cash and temporary cash investments (approximately $160,000,000 as of December 31, 1993); the issuance of long-term debt and funds available under short-term bank credit arrangements. The Companies currently expect that, for the period 1994-1998, external financings may be necessary to provide a portion of their cash requirements. The extent and type of future financings will depend on the need for external funds as well as market conditions, the maintenance of an appropriate capital structure and the ability of the Companies to comply with coverage requirements in order to issue first mortgage bonds and preferred stock. The Companies will continue to monitor financial market conditions and, where appropriate, may take advantage of opportunities to refund outstanding high cost debt and preferred stock to the extent that their financial resources permit. Except as otherwise indicated, the foregoing statements with respect to construction expenditures are based on estimates made in February 1994 and are subject to change based upon the progress of and changes required in the construction program, including periodic reviews of costs, changing customer requirements for electric energy, the level of earnings and resulting changes in applicable coverage requirements, conditions in capital markets, changes in regulatory requirements and other relevant factors. Coverage Requirements The coverage requirements contained in the first mortgage indentures under which the Companies issue first mortgage bonds provide that, except for certain refunding purposes, the Companies may not issue first mortgage bonds unless applicable net earnings (before income taxes), calculated as provided in the indentures, for any period of twelve consecutive months within the fifteen calendar months preceding the month in which such additional bonds are issued, are at least twice annual -3- interest requirements on outstanding first mortgage bonds, including those being issued. The Companies' respective articles of incorporation prohibit the sale of preferred stock unless applicable gross income, calculated as provided in the articles of incorporation, is equal to at least 1-1/2 times the aggregate of the annual interest requirements on indebtedness outstanding immediately thereafter plus the annual dividend requirements on all preferred stock which will be outstanding at that time. With respect to the issuance of first mortgage bonds under the Company's first mortgage indenture, the availability of property additions is more restrictive than the earnings test at the present time and would limit the amount of first mortgage bonds issuable against property additions to $404,000,000. The Company is currently able to issue $868,000,000 principal amount of first mortgage bonds against previously retired bonds without the need to meet the above restrictions. The Company could issue in excess of $1,000,000,000 of additional preferred stock before the end of the first quarter of 1994. For the remainder of 1994, however, the earnings coverage test contained in the Company's charter would preclude the issuance of additional preferred stock due to inclusion of the Perry Unit 2 write-off in the earnings test. Additional preferred stock capability is expected to be restored in January 1995. If the Company were to issue additional debt at or prior to the time it issued preferred stock, the amount of preferred stock which would be issuable would be reduced. To the extent that coverage requirements or market conditions restrict the Companies' abilities to issue desired amounts of first mortgage bonds or preferred stock, the Companies may seek other methods of financing. Such financings could include the sale of common stock and preference stock in amounts greater than otherwise planned, or of such other types of securities as might be authorized by applicable regulatory authorities which would not otherwise be sold and could result in annual interest charges and/or dividend requirements in excess of those that would otherwise be incurred. In addition, the Companies might, to the extent possible, reduce their expenditures for construction and other purposes. Utility Regulation The Companies are subject to broad regulation as to rates and other matters by the Public Utilities Commission of Ohio (PUCO) and the Pennsylvania Public Utility Commission (PPUC). With respect to their wholesale and interstate electric operations and rates, the Companies are subject to regulation, including regulation of their accounting policies and practices, by the Federal Energy Regulatory Commission (FERC). Under Ohio law, municipalities may regulate rates, subject to appeal to the PUCO if not acceptable to the utility. In 1986, a law was passed which extended the jurisdiction of the PUCO to nonutility affiliates of holding companies exempt under Section 3(a)(1) and 3(a)(2) of the Public Utility Holding Company Act of 1935 (1935 Act) to the extent that the activities of such affiliates affect or relate to the cost of providing electric utility service in Ohio. The law, among other things, requires PUCO approval of investments in, or the transfer of assets to, nonutility affiliates. Investments in such affiliates are limited to 15% of the aggregate capitalization of the holding company on a consolidated basis. The Company is an exempt holding company under Section 3(a)(2) of the 1935 Act, but the law has not had any effect on its operations as they are currently conducted. The Energy Policy Act of 1992 (1992 Act) amends portions of the 1935 Act, providing independent power producers and other nonregulated generating facilities easier entry into the electric generation markets. The 1992 Act also amends portions of the Federal Power Act, authorizing -4- the FERC, under certain circumstances, to mandate access to utility-owned transmission facilities. The Companies are currently unable to predict the ultimate effects on their operations resulting from this legislation. In February 1994, a bill was introduced in the Ohio legislature which would amend Ohio law to require utilities to provide transmission access to enable others to serve retail customers located in the service territory of the transmitting utility. Access would not be required however, if the transmission access requested would impair the ability of the transmitting utility to provide physically adequate service to its existing customers unless the requesting party is willing to pay the cost of eliminating the problem in instances where such elimination is possible. The sponsor of the bill has indicated that he expects its introduction will encourage comments and debate in the months ahead on the policy considerations involved. The Company is unable to predict whether this legislation will be adopted and, if adopted, what form it will actually take. PUCO Rate Matters The Company's Rate Stabilization and Service Area Development Program provides for base electric rates to remain at 1990 levels until at least 1997, absent any significant changes in regulatory, environmental or tax requirements. Among other things, the program also provides for the adoption of demand side management programs and a tariff option for customer retention and service area stabilization. FERC Rate Matters Rates for the Companies' respective wholesale customers are regulated by the FERC. The Company's tariff for its customers was approved by the FERC in 1989. Penn Power sells power to its wholesale customers under agreements which were accepted by the FERC in 1984. These agreements provide that Penn Power's wholesale customers will be charged the applicable prevailing retail electric rates through August 1994, and that they will remain full requirements customers of Penn Power at least through that date. Negotiations are currently underway to extend these agreements. Fuel Adjustment Clauses Under the laws of the State of Ohio, an electric utility is required to have semiannual hearings before the PUCO with respect to its fuel and net purchased power policies and practices. At these hearings a utility is required to show that its electric fuel component (EFC) charges are "fair, just and reasonable". The law also requires additional auditing of, and additional reporting by, the utility with respect to its fuel costs and fuel procurement policies and practices. The law provides for the recovery of fuel costs, including any over or under collection of fuel costs applicable to a prior six month period, by adjusting an electric utility's EFC rate every six months. Penn Power uses a "levelized" energy cost rate (ECR) for the recovery of fuel and net purchased power costs from its customers. The ECR, which includes adjustment for any over or under collection from customers, is recalculated each year. Nuclear Regulation The construction and operation of nuclear generating units are subject to the regulatory jurisdiction of the Nuclear Regulatory Commission (NRC) including the issuance by it of construction permits and -5- operating licenses. The NRC's procedures with respect to application for construction permits and operating licenses afford opportunities for interested parties to request public hearings on health, safety, environmental and antitrust issues. In this connection, the NRC may require substantial changes in operation or the installation of additional equipment to meet safety or environmental standards with resulting delay and added costs. The possibility also exists for modification, denial or revocation of licenses or permits. Full power operating licenses were issued for Beaver Valley Unit 1, Perry Unit 1 and Beaver Valley Unit 2 on July 1, 1976, November 13, 1986 and August 14, 1987, respectively. The construction permit and operating license issued by the NRC applicable to Perry Unit 1 is conditioned to require, among other things: (i) maintenance, emergency, economy and wholesale power and reserve sharing to be made available to, (ii) interconnections to be made with, and (iii) wheeling to be provided for, electric generating and/or distribution systems (or municipalities or cooperatives with the right to engage in such functions) if such entities so request and to permit such entities to become members of CAPCO (subject to certain prerequisites with respect to size), or to acquire a share of the capacity of Perry Unit 1 or any other future nuclear units, if they so desire. In September 1987, the Company asked the NRC to suspend these license conditions. In April 1991, the NRC Staff denied the Company's application; accordingly, the Company petitioned the NRC for a hearing. Pursuant to this request the matter was referred to the Atomic Safety and Licensing Board (ASLB). The ASLB ruled against the Company in November 1992. The Company petitioned the NRC to review the ASLB decision in December 1992. On August 3, 1993, the NRC ruled that the license conditions will not be suspended. On October 1, 1993, the Company appealed the NRC decision in the United States Court of Appeals for the District of Columbia Circuit. If these license conditions are not suspended, they could have a materially adverse but presently undeterminable effect on the Companies' future business operations. The NRC has promulgated and continues to promulgate additional regulations related to the safe operation of nuclear power plants. The Companies cannot predict what additional regulations will be promulgated or design changes required or the effect that any such regulations or design changes, or the consideration thereof, may have upon the Beaver Valley and Perry plants. Although the Companies have no reason to anticipate an accident at any nuclear plant in which they have an interest, if such an accident did happen, it could have a material but presently undeterminable adverse effect on the Company's consolidated financial position. In addition, such an accident at any operating nuclear plant, whether or not owned by the Companies, could result in regulations or requirements that could affect the operation or licensing of plants that the Companies do own with a consequent but presently undeterminable adverse impact, and could affect the Companies' abilities to raise funds in the capital markets. Nuclear Insurance The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $9,396,000,000 (assuming 116 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $200,000,000; and (ii) $9,196,000,000 provided by an industry retrospective rating plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $75,500,000 (but not more than $10,000,000 per unit per year in the event of more than one incident) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on their present ownership and leasehold interests in Beaver Valley Units 1 and 2 and Perry Unit 1, the Companies' maximum potential assessment under these provisions (assuming the other CAPCO -6- companies were to contribute their proportionate share of any assessments under the retrospective rating plan) would be $102,800,000 per incident but not more than $13,000,000 in any one year for each incident. In addition to the public liability insurance provided pursuant to the Price-Anderson Act, the Companies have also obtained insurance coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. The Companies are members of Nuclear Electric Insurance Limited (NEIL) which provides coverage (NEIL I) for the extra expense of replacement power incurred due to prolonged accidental outages of nuclear units. Under NEIL I, the Companies have policies, renewable yearly, corresponding to their respective interests in Beaver Valley Units 1 and 2 and Perry Unit 1, which provide an aggregate indemnity of up to approximately $313,000,000 for replacement power costs incurred during an outage after an initial 21-week waiting period. Members of NEIL I pay annual premiums and are subject to assessments if losses exceed the accumulated funds available to the insurer. The Companies' present maximum aggregate assessment for incidents at any covered nuclear facility occurring during a policy year would be approximately $3,300,000. The Companies are insured as to their respective interests in the Beaver Valley Station and Perry Plant under property damage insurance provided by American Nuclear Insurers (ANI) and Mutual Atomic Energy Liability Underwriters (MAELU) to the operating company for each plant. Under the ANI/MAELU arrangements, $500,000,000 of primary coverage and $850,000,000 of excess coverage for decontamination costs, debris removal and repair and/or replacement of property is provided for the Beaver Valley Station and the Perry Plant. The Companies pay annual premiums for this coverage and are not liable for retrospective assessments. A secondary level of coverage for the Beaver Valley Station and Perry Plant over and above the ANI/MAELU policy is provided by a decontamination liability, excess property and decommissioning liability insurance policy issued to each operating company by NEIL (NEIL II). Under NEIL II a minimum of $1,400,000,000 of coverage is available to pay costs required for decontamination operations in excess of the $1,350,000,000 provided by the primary ANI/MAELU policy. Additionally, a maximum of $250,000,000, as provided by NEIL II, would cover decommissioning costs in excess of funds already collected for decommissioning. Any remaining portion of the NEIL II proceeds after payment of decontamination costs will be available to pay excess property damage losses. Members of NEIL II pay annual premiums and are subject to assessments if losses exceed the accumulated funds available to the insurer. The Companies' present maximum assessment for NEIL II coverage for accidents at any covered nuclear facility occurring during a policy year would be approximately $12,100,000. The NEIL II policy is renewable yearly. The Companies intend to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of the Companies' plants exceed the policy limits of the insurance from time to time in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Companies' insurance policies, or to the extent such insurance becomes unavailable in the future, the Companies would remain at risk for such costs. The NRC requires nuclear power plant licensees to obtain minimum property insurance coverage of $1,060,000,000 or the amount generally available from private sources, whichever is less. The proceeds of this insurance are required to be used first to ensure that the licensed reactor is in a safe and stable condition and can be maintained in that condition so as to prevent any significant risk to the public health and -7- safety. Within 30 days of stabilization, the licensee is required to prepare and submit to the NRC a cleanup plan for approval. The plan is required to identify all cleanup operations necessary to decontaminate the reactor sufficiently to permit the resumption of operations or to commence decommissioning. Any property insurance proceeds not already expended to place the reactor in a safe and stable condition must be used first to complete those decontamination operations that are ordered by the NRC. The Companies are unable to predict what effect these requirements may have on the availability of insurance proceeds to the Companies for the Companies' bondholders. Environmental Matters Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. The Companies have estimated capital expenditures for environmental compliance of approximately $175,000,000, which is included in the construction estimate given under "Financing and Construction - Future Financing" for 1994 through 1998. Air Regulation Under the provisions of the Clean Air Act of 1970, both the State of Ohio and the Commonwealth of Pennsylvania adopted ambient air quality standards, and related emission limits, including limits for sulfur dioxide (SO2) and particulates. In addition, the U.S. Environmental Protection Agency (EPA) promulgated an SO2 regulatory plan for Ohio which became effective for the Company's plants in 1977. Generating plants to be constructed in the future and some future modifications of existing facilities will be covered not only by the applicable state standards but also by EPA emission performance standards for new sources. In both Ohio and Pennsylvania the construction or modification of emission sources requires approval from appropriate environmental authorities, and the facilities involved may not be operated unless a permit or variance to do so has been issued by those same authorities. The Clean Air Act Amendments of 1990 require significant reductions of SO2 and oxides of nitrogen from the Companies' coal-fired generating units by 1995 and additional emission reductions by 2000. Compliance options include, but are not limited to, installing additional pollution control equipment, burning less polluting fuel, purchasing emission allowances from others, operating existing facilities in a manner which minimizes pollution and retiring facilities. In compliance plans submitted to the PUCO and to the EPA, the Company stated that reductions for the years 1995 through 1999 are likely to be achieved by burning lower sulfur fuel, generating more electricity at its lower emitting plants and/or purchasing emission allowances. The Company continues to evaluate its compliance plans and other compliance options as they arise. Plans for complying with the year 2000 reductions are less certain at this time. The Companies are required to meet federally approved SO2 regulations, and the violations of such regulations can result in injunctive relief, including shutdown of the generating unit involved, and/or civil or criminal penalties of up to $25,000 per day of violation. The EPA has an interim enforcement policy for the SO2 regulations in Ohio which allows for compliance with the regulations based on a 30-day averaging period. The EPA has proposed regulations which could cause changes in the interim enforcement policy including a revision of methods of determining compliance with emission limits. The Companies cannot predict what action the EPA may take in the future with respect to the proposed regulations or the interim enforcement policy. -8- Water Regulation Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to the Companies' plants. In addition, Ohio and Pennsylvania have water quality standards applicable to the Companies' operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System (NPDES) water discharge permits can be assumed by a state. Ohio and Pennsylvania have assumed such authority. The Ohio Environmental Protection Agency (Ohio EPA) has issued NPDES Permits for the R.E. Burger, Edgewater, Niles, W.H. Sammis and West Lorain plants and has proposed a water discharge permit for the Mad River Plant. The West Lorain Plant is in compliance with all permit conditions. The other plants are in compliance with chemical limitations of the permits. The permit conditions would have required the addition of cooling towers at all of the above plants except West Lorain. However, the EPA and Ohio EPA have approved variance requests for the W.H. Sammis, R.E. Burger, Edgewater and Niles plants, eliminating the current need for cooling towers at those plants. Waste Disposal As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. These regulations may result in significantly increased costs to dispose of waste materials. The ultimate effect of these requirements cannot presently be determined. The Pennsylvania Department of Environmental Resources has issued regulations dealing with the storage, treatment, transportation and disposal of residual waste such as coal ash and scrubber sludge. These regulations impose additional requirements relating to permitting, ground water monitoring, leachate collection systems, closure, liability insurance and operating matters. The Companies are developing and analyzing various compliance options and are currently unable to determine the ultimate increase in capital and operating costs at existing sites. Summary Environmental controls are still in the process of development and require, in many instances, balancing the needs for additional quantities of energy in future years and the need to protect the environment. As a result, the Companies cannot now estimate the precise effect of existing and potential regulations and legislation upon any of their existing and proposed facilities and operations or upon their ability to issue additional first mortgage bonds under their respective mortgages. These mortgages contain covenants by the Companies to observe and conform to all valid governmental requirements at the time applicable unless in course of contest, and provisions which, in effect, prevent the issuance of additional bonds if there is a completed default under the mortgage. The provisions of each of the mortgages, in effect, also require, in the opinion of counsel for the respective Companies, that certification of property additions as the basis for the issuance of bonds or other action under the mortgages be accompanied by an opinion of counsel that the company certifying such property additions has all governmental permissions at the time necessary for its then current ownership and operation of such property additions. The Companies intend to contest any requirements they deem unreasonable or impossible for compliance or otherwise contrary to the public interest. Developments in these and other areas of regulation may require the Companies to modify, supplement or replace equipment and facilities, and may delay or impede the -9- construction and operation of new facilities, at costs which could be substantial. The Companies expect that the impact of any such costs would eventually be reflected in their rate schedules. Fuel Supply The Companies' sources of generation during 1993 were 81.9% coal and 18.1% nuclear. Over two-thirds of the Company's annual coal purchase requirements are supplied under long-term contracts. These contracts have minimum annual tonnage levels of approximately 5,900,000 tons (including the Company's portion of the coal purchase contract relating to the Bruce Mansfield Plant discussed below). This contract coal is produced primarily from mines located in Ohio, Pennsylvania, Kentucky and West Virginia; the contracts expire at various times through February 28, 2003. With the 1993 expiration of the long-term coal contract for the New Castle Plant, Penn Power's coal, other than that related to its interest in the Bruce Mansfield Plant and W. H. Sammis Unit 7, is currently supplied entirely through spot purchases of coal produced from nearby reserves. The Company and Penn Power estimate their 1994 coal requirements to be approximately 8,600,000 and 1,200,000 tons, respectively (including their respective shares of the coal requirements of CAPCO's W. H. Sammis Unit 7 and the Bruce Mansfield Plant). See "Environmental Matters" for factors pertaining to meeting environmental regulations affecting coal- fired generating units. The Companies, together with the other CAPCO companies, have each severally guaranteed (the Company's and Penn Power's composite percentages being approximately 46.7% and 6.7%, respectively) certain debt and lease obligations in connection with a coal supply contract for the Bruce Mansfield Plant (see Note 7 of Notes to Consolidated Financial Statements). As of December 31, 1993, the Companies' shares of the guarantees were $101,217,000. The price under the coal supply contract, which includes certain minimum payments, has been determined to be sufficient to satisfy the debt and lease obligations. This contract extends to December 31, 1999. The Companies' fuel costs (excluding disposal costs) for each of the five years ended December 31, 1993, were as follows: 1993 1992 1991 1990 1989 ---- ---- ---- ---- ---- Cost of fuel consumed per million BTU's: Coal . . . . . . . . . . . . . . . . . . $1.37 $1.40 $1.40 $1.39 $1.34 Nuclear . . . . . . . . . . . . . . . . $ .76 $ .83 $ .87 $ .84 $ .90 Average fuel cost per kilowatt-hour generated (cents). . . . . . . . . . . . 1.31 1.31 1.34 1.34 1.34 Nuclear Fuel OES Fuel is the sole lessor for the Companies' nuclear fuel requirements (see "Financing and Construction - Future Financing" and Note 5E of Notes to Consolidated Financial Statements). The Companies and OES Fuel have contracts for the supply of uranium sufficient to meet projected needs through 2000 and conversion services sufficient to meet projected needs through 2001. Fabrication services for fuel assemblies have been contracted by the CAPCO companies for the next two reloads for Beaver Valley Unit 1, one reload for Beaver Valley Unit 2 (through approximately 1996 and 1995, respectively), and the next seven -10- reloads for Perry Unit 1 (through approximately 2003). The CAPCO companies have a contract with the U.S. Enrichment Corporation for enrichment services for all CAPCO nuclear units through 2014. Prior to the expiration of existing commitments, the Companies intend to make additional arrangements for the supply of uranium and for the subsequent conversion, enrichment, fabrication, reprocessing and/or waste disposal services, the specific prices and availability of which are not known at this time. Due to the present lack of availability of domestic reprocessing services, to the continuing absence of any program to begin development of such reprocessing capability and questions as to the economics of reprocessing, the Companies are calculating nuclear fuel costs based on the assumption that spent fuel will not be reprocessed. On- site spent fuel storage facilities for the Perry Plant are expected to be adequate through 2010; facilities at Beaver Valley Units 1 and 2 are expected to be adequate through 2011 and 2005, respectively. After on-site storage capacity is exhausted, additional storage capacity will have to be obtained which could result in significant additional costs unless reprocessing services or permanent waste disposal facilities become available. The Federal Nuclear Waste Policy Act of 1982 provides for the construction of facilities for the disposal of high-level nuclear wastes, including spent fuel from nuclear power plants operated by electric utilities; however, the selection of a suitable site has become embroiled in the political process. Duquesne and CEI have each previously entered into contracts with the U.S. Department of Energy for the disposal of spent fuel from the Beaver Valley Power Station and the Perry Plant, respectively. System Capacity and Reserves The 1993 net maximum hourly demand on the Companies of 5,729,000 kW (including 450,000 kW of firm power sales which extend through 2005 as discussed under "Competition") occurred on July 28, 1993. The seasonal capability of the Companies on that day was 6,141,000 kW. Of that system capability, 6.6% was available to serve additional load, after giving effect to net firm purchases at that hour of 521,000 kW and term power sales to other utilities. Based on existing capacity, the load forecast made in November 1993 and anticipated term power sales to other utilities, the capacity margins during the 1994-1998 period are expected to range from about 5% to 9%. Regional Reliability The Company participates with 26 other electric companies operating in nine states in the East Central Area Reliability Coordination Agreement (ECAR), which was organized for the purpose of furthering the reliability of bulk power supply in the area through coordination of the planning and operation by the ECAR members of their bulk power supply facilities. The ECAR members have established principles and procedures regarding matters affecting the reliability of the bulk power supply within the ECAR region. Procedures have been adopted regarding: i) the evaluation and simulated testing of systems' performance; ii) the establishment of minimum levels of daily operating reserves; iii) the development of a program regarding emergency procedures during conditions of declining system frequency; and iv) the basis for uniform rating of generating equipment. Competition The Companies compete with other utilities for intersystem bulk power sales and for sales to municipalities and cooperatives. The Companies compete with suppliers of natural gas and other forms of energy in connection with their industrial and commercial sales and in the home -11- climate control market, both with respect to new customers and conversions, and with all other suppliers of electricity. To date, there has been no substantial cogeneration by the Companies' customers. In an effort to more fully utilize their facilities and hold down rates to their other customers, the Companies have entered into a long- term power sales agreement with another utility. Currently, the Companies are selling 450,000 kW annually under this contract through December 31, 2005. The Companies have the option to reduce this commitment by 150,000 kW beginning June 1, 1996. Research and Development The Company participates in funding the Electric Power Research Institute (EPRI), which was formed for the purpose of expanding electric research and development under the voluntary sponsorship of the nation's utility industry - public, private and cooperative. Its goal is to mutually benefit utilities and their customers by promoting the development of new and improved technologies to help the utility industry meet present and future electric energy needs in environmentally and economically acceptable ways. EPRI conducts research on all aspects of electric power production and use, including fuels, generating, delivery, energy management and conservation, environmental effects and energy analysis. The major portion of EPRI research and development projects is directed toward practical solutions and their applications to problems currently facing the electric utility industry. In 1993, approximately 93% of the Company's research and development expenditures were related to EPRI. The Company also participates in various research and development efforts by sponsoring clean coal technology demonstration projects at Company-owned coal-fired units. These projects are designed to derive alternate ways of using coal that would otherwise be environmentally unacceptable. In addition to researching environmentally acceptable ways of burning coal, the Company is also researching technology which will produce ash waste with properties and characteristics different from present fly ash and bottom ash, with the initial goal of producing marketable products for use in agronomy applications. Executive Officers The executive officers are elected at the annual organization meeting of the Board of Directors, held immediately after the annual meeting of stockholders, and hold office until the next such organization meeting, unless the Board of Directors shall otherwise determine, or unless a resignation is submitted. Position Held During Name Age Past Five Years Dates ---- --- -------------------- ----- W. R. Holland 57 President and Chief Executive Officer 1993-present President and Chief Operating Officer 1991-1993 Senior Vice President of Detroit Edison Company *-1991 A. J. Alexander 42 Senior Vice President and General Counsel 1991-present Vice President and General Counsel 1989-1991 Associate General Counsel *-1989 -12- Position Held During Name Age Past Five Years Dates ---- --- -------------------- ----- H. P. Burg 47 Senior Vice President and Chief Financial Officer 1989-present Vice President-Treasury and Budget *-1989 R. J. McWhorter 61 Senior Vice President- Generating Plant and Transmission Operations *-present A. R. Garfield 55 Vice President-System Operations 1991-present Manager, System Operations *-1991 J. A. Gill 56 Vice President- Administration *-present A. N. Gorant 63 Vice President-Division Operations and Customer Service *-present B. M. Miller 61 Vice President-Engineering and Construction *-present D. L. Yeager 59 Vice President-Special Projects *-present D. P. Zeno 63 Vice President-Governmental Affairs 1991-present Manager, Governmental Affairs *-1991 G. F. LaFlame 45 Secretary *-present R. H. Marsh 43 Treasurer 1991-present Manager, Assets Administration 1989-1991 Director, Benefits Investment Administration *-1989 H. L. Wagner 41 Comptroller 1990-present Assistant Comptroller *-1990 *Indicates position held at least since January 1, 1989. At December 31, 1993, the Company had 4,623 employees and Penn Power had 1,355 employees for a total of 5,978 employees for the Companies. ITEM 2. PROPERTIES The Companies' respective first mortgage indentures constitute, in the opinion of the Companies' counsel, direct first liens on substantially all of the respective Companies' physical property, subject only to excepted encumbrances, as defined in the Indentures. See Notes 4 and 5 to the Consolidated Financial Statements for information concerning leases and financing encumbrances affecting certain of the Companies' properties. -13- The Companies own, individually or, together with one or more of the other CAPCO companies as tenants in common, and/or lease, the generating units in service shown on the table below. Net Demonstrated Interest Capacity (kW) ----------------------- --------------------------- Penn Companies' Ohio Edison Power -------------- Plant-Location Unit Total Entitlement Owned Leased Owned - ---------------- ---- -------- ----------- ------ ------ ----- Coal-Fired Units R.E. Burger- 1-5 518,000 518,000 100.00% - - Shadyside, OH B. Mansfield- 1 780,000 501,000 60.00% - 4.20% Shippingport, PA 2 780,000 360,000 39.30% - 6.80% 3 800,000 335,000 35.60% - 6.28% New Castle- 3-5 333,000 333,000 - - 100.00% W. Pittsburg, PA Niles-Niles, OH 1-2 216,000 216,000 100.00% - - W.H. Sammis- 1-6 1,620,000 1,620,000 100.00% - - Stratton, OH 7 600,000 413,000 48.00% - 20.80% Nuclear Units Beaver Valley- 1 810,000 425,000 35.00% - 17.50% Shippingport, PA 2 820,000 343,000 20.22% 21.66% - Perry- 1 1,194,000 421,000 17.42% 12.58% 5.24% North Perry Village, OH Oil-Fired Units Various 164,000 164,000 84.82% - 15.18% --------- Total 5,649,000 ========= Prolonged outages of existing generating units might make it necessary for the Companies, depending upon the state of demand from time to time for electric service upon their system, to use to a greater extent than otherwise, less efficient and less economic generating units, or purchased power, and in some cases may require the reduction of load during peak periods under the Companies' interruptible programs, all to an extent not presently determinable. The Companies' generating plants and load centers are connected by a transmission system consisting of elements having various voltage ratings ranging from 23 kilovolts (kV) to 345 kV. The Companies' transmission lines aggregate 4,547 miles. The Companies' electric distribution systems include 25,173 miles of pole line carrying primary, secondary and street lighting circuits. They own, individually or, together with one or more of the other CAPCO companies as tenants in common, 436 substations with a total installed transformer capacity of 23,394,654 kilovolt-amperes, of which 64 are transmission substations, including 8 located at generating plants. -14- The Company's transmission lines also interconnect with those of CEI, Columbus Southern Power Company, The Dayton Power and Light Company, Duquesne, Monongahela Power Company, Ohio Power Company and Toledo; Penn Power's interconnect with those of Duquesne and West Penn Power Company. These interconnections make possible utilization by the Company and Penn Power of generating capacity constructed as a part of the CAPCO program, as well as providing opportunities for the sale of power to other utilities. ITEM 3. LEGAL PROCEEDINGS See "Item 1 - Business - Nuclear Regulation" for information with respect to legal proceedings. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS ITEM 6. SELECTED FINANCIAL DATA ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information called for by Items 5 through 8 is incorporated herein by reference to the Common Stock Data, Classification of Holders of Common Stock as of December 31, 1993, Selected Financial Data, Management's Discussion and Analysis of Results of Operations and Financial Condition, and Consolidated Financial Statements included on pages 16 through 33 in the Company's 1993 Annual Report to Stockholders. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. -15- PART III ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by Item 10, with respect to Identification of Directors and with respect to reports required to be filed under Section 16 of the Securities Exchange Act of 1934, is incorporated herein by reference to the Company's 1994 Proxy Statement filed with the Securities and Exchange Commission (SEC) pursuant to Regulation 14A and, with respect to Identification of Executive Officers, to "Part I, Item 1. Business- Executive Officers" herein. ITEM 11.EXECUTIVE COMPENSATION ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by Items 11, 12 and 13 is incorporated herein by reference to the Company's 1994 Proxy Statement filed with the SEC pursuant to Regulation 14A. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) 1. Financial Statements Included in Part II of this report and incorporated herein by reference to the Company's 1993 Annual Report to Stockholders (Exhibit 13 below) at the pages indicated. Page No. -------- Consolidated Statements of Income-Three Years Ended December 31, 1993 . . . . . . . . . . . . . . . . . . . . 20 Consolidated Balance Sheets-December 31, 1993 and 1992. . . . . 21 Consolidated Statements of Capitalization- December 31, 1993 and 1992. . . . . . . . . . . . . . . . . 22-23 Consolidated Statements of Retained Earnings-Three Years Ended December 31, 1993 . . . . . . . . . . . . . . . . . . 24 Consolidated Statements of Capital Stock and Other Paid-In Capital-Three Years Ended December 31, 1993 . . . . 24 Consolidated Statements of Cash Flows-Three Years Ended December 31, 1993 . . . . . . . . . . . . . . . . . . 25 Consolidated Statements of Taxes-Three Years Ended December 31, 1993 . . . . . . . . . . . . . . . . . . 26 Notes to Consolidated Financial Statements. . . . . . . . . . . 27-33 Report of Independent Public Accountants. . . . . . . . . . . . 33 -16- 2. Financial Statement Schedules Included in Part IV of this report: Page No. -------- Report of Independent Public Accountants on Schedules . . . . 35 Schedules - Three Years Ended December 31, 1993: V - Consolidated Property, Plant and Equipment. . . . 36-38 VI - Consolidated Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment . . . . . . . . . . . . . . 39-41 VIII - Consolidated Valuation and Qualifying Accounts and Reserves . . . . . . . . . . . . . 42 IX - Consolidated Short-Term Borrowings. . . . . . . . 43 X - Supplementary Consolidated Income Statement Information . . . . . . . . . . . . . . . . . . . 44 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. 3. Exhibits Exhibit Number - ------- 3-1- Amended Articles of Incorporation, Effective August 5, 1993, constituting the Company's Articles of Incorporation. (Registration No. 33-51139, Exhibit (3)(b).) 3-2- Code of Regulations of the Company as amended April 24, 1986. (Registration No. 33-5081, Exhibit (4)(d).) (B)4-1- Indenture dated as of August 1, 1930 between the Company and Bankers Trust Company, as Trustee, as amended and supplemented by Supplemental Indentures: Dated as of File Reference Exhibit No. ----------- -------------- ----------- March 3, 1931 2-1725 B-1,B-1(a),B-1(b) November 1, 1935 2-2721 B-4 January 1, 1937 2-3402 B-5 September 1, 1937 Form 8-A B-6 June 13, 1939 2-5462 7(a)-7 August 1, 1974 Form 8-A, August 28, 1974 2(b) July 1, 1976 Form 8-A, July 28, 1976 2(b) December 1, 1976 Form 8-A, December 15, 1976 2(b) June 15, 1977 Form 8-A, June 27, 1977 2(b) -17- Supplemental Indentures: Dated as of File Reference Exhibit No. ----------- -------------- ----------- September 1, 1944 2-61146 2(b)(2) April 1, 1945 2-61146 2(b)(2) September 1, 1948 2-61146 2(b)(2) May 1, 1950 2-61146 2(b)(2) January 1, 1954 2-61146 2(b)(2) May 1, 1955 2-61146 2(b)(2) August 1, 1956 2-61146 2(b)(2) March 1, 1958 2-61146 2(b)(2) April 1, 1959 2-61146 2(b)(2) June 1, 1961 2-61146 2(b)(2) September 1, 1969 2-34351 2(b)(2) May 1, 1970 2-37146 2(b)(2) September 1, 1970 2-38172 2(b)(2) June 1, 1971 2-40379 2(b)(2) August 1, 1972 2-44803 2(b)(2) September 1, 1973 2-48867 2(b)(2) May 15, 1978 2-66957 2(b)(4) February 1, 1980 2-66957 2(b)(5) April 15, 1980 2-66957 2(b)(6) June 15, 1980 2-68023 (b)(4)(b)(5) October 1, 1981 2-74059 (4)(d) October 15, 1981 2-75917 (4)(e) February 15, 1982 2-75917 (4)(e) July 1, 1982 2-89360 (4)(d) March 1, 1983 2-89360 (4)(e) March 1, 1984 2-89360 (4)(f) September 15, 1984 2-92918 (4)(d) September 27, 1984 33-2576 (4)(d) November 8, 1984 33-2576 (4)(d) December 1, 1984 33-2576 (4)(d) December 5, 1984 33-2576 (4)(e) January 30, 1985 33-2576 (4)(e) February 25, 1985 33-2576 (4)(e) July 1, 1985 33-2576 (4)(e) October 1, 1985 33-2576 (4)(e) January 15, 1986 33-8791 (4)(d) May 20, 1986 33-8791 (4)(d) June 3, 1986 33-8791 (4)(e) October 1, 1986 33-29827 (4)(d) July 15, 1989 33-34663 (4)(d) August 25, 1989 33-34663 (4)(d) February 15, 1991 33-39713 (4)(d) May 1, 1991 33-45751 (4)(d) May 15, 1991 33-45751 (4)(d) -18- Exhibit Number Supplemental Indentures: (Cont'd) - ------- Dated as of File Reference Exhibit No. ----------- -------------- ----------- September 15, 1991 33-45751 (4)(d) April 1, 1992 33-48931 (4)(d) June 15, 1992 33-48931 (4)(d) September 15, 1992 33-48931 (4)(e) April 1, 1993 33-51139 (4)(d) June 15, 1993 33-51139 (4)(d) September 15, 1993 33-51139 (4)(d) November 15, 1993 (A) 4-2 10-1- Administration Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-43102, Exhibit 5(c)(2).) 10-2- Amendment No. 1 dated January 4, 1974 to Administration Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-68906, Exhibit 5(c)(3).) 10-3- Transmission Facilities Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-43102, Exhibit 5(c)(3).) (A)10-4- Amendment No. 1 dated as of January 1, 1993 to Transmission Facilities Agreement between the CAPCO Group dated as of September 14, 1967. 10-5- Agreement for the Termination or Construction of Certain Agreements effective September 1, 1980 among the CAPCO Group. (Registration No. 2-68906, Exhibit 10-4.) (A)10-6- Amendment dated as of December 23, 1993 to Agreement for the Termination or Construction of Certain Agreements effective September 1, 1980 among the CAPCO Group. 10-7- CAPCO Basic Operating Agreement, as amended September 1, 1980. (Registration No. 2-68906, Exhibit 10-5.) 10-8- Amendment No. 1 dated August 1, 1981, and Amendment No. 2 dated September 1, 1982 to CAPCO Basic Operating Agreement, as amended September 1, 1980. (September 30, 1981 Form 10-Q, Exhibit 20-1 and 1982 Form 10-K, Exhibit 19-3, respectively.) 10-9- Amendment No. 3 dated July 1, 1984 to CAPCO Basic Operating Agreement, as amended September 1, 1980. (1985 Form 10-K, Exhibit 10-7.) 10-10- Basic Operating Agreement between the CAPCO Companies as amended October 1, 1991. (1991 Form 10-K, Exhibit 10-8.) -19- Exhibit Number - ------- (A)10-11- Basic Operating Agreement between the CAPCO Companies as amended January 1, 1993. 10-12- Memorandum of Agreement effective as of September 1, 1980 among the CAPCO Group. (1982 Form 10-K, Exhibit 19-2.) 10-13- Operating Agreement for Beaver Valley Power Station Units Nos. 1 and 2 as Amended and Restated September 15, 1987, by and between the CAPCO Companies. (1987 Form 10-K, Exhibit 10-15.) 10-14- Construction Agreement with respect to Perry Plant between the CAPCO Group dated as of July 22, 1974. (Registration No. 2- 52251 of Toledo Edison Company, Exhibit 5(yy).) 10-15- Participation Agreement No. 1 relating to the financing of the development of certain coal mines, dated as of October 1, 1973, among Quarto Mining Company, the CAPCO Group, Energy Properties, Inc., General Electric Credit Corporation, the Loan Participants listed in Schedules A and B thereto, Central National Bank of Cleveland, as Owner Trustee, National City Bank, as Loan Trustee, and Owner Trustee, National City Bank, as Loan Trustee, and National City Bank, as Bond Trustee. (Registration No. 2-61146, Exhibit 5(e)(1).) 10-16- Amendment No. 1 dated as of September 15, 1978 to Participation Agreement No. 1 dated as of October 1, 1973 among Quarto Mining Company, the CAPCO Group, Energy Properties, Inc., General Electric Credit Corporation, the Loan Participants listed in Schedules A and B thereto, Central National Bank of Cleveland as Owner Trustee, National City Bank as Loan Trustee and National City Bank as Bond Trustee. (Registration No. 2-68906 of Pennsylvania Power Company, Exhibit 5(e)(2).) 10-17- Participation Agreement No. 2 relating to the financing of the development of certain coal mines, dated as of August 1, 1974, among Quarto Mining Company, the CAPCO Group, Energy Properties, Inc., General Electric Credit Corporation, the Loan Participants listed in Schedules A and B thereto, Central National Bank of Cleveland, as Owner Trustee, National City Bank, as Loan Trustee, and National City Bank, as Bond Trustee. (Registration No. 2-53059, Exhibit 5(h)(2).) 10-18- Amendment No. 1 dated as of September 15, 1978 to Participation Agreement No. 2 dated as of August 1, 1974 among Quarto Mining Company, the CAPCO Group, Energy Properties, Inc., General Electric Credit Corporation, the Loan Participants listed in Schedules A and B thereto, Central National Bank of Cleveland as Owner Trustee, National City Bank as Loan Trustee and National City Bank as Bond Trustee. (Registration No. 2-68906 of Pennsylvania Power Company, Exhibit 5(e)(4).) 10-19- Participation Agreement No. 3 dated as of September 15, 1978 among Quarto Mining Company, the CAPCO Companies, Energy Properties, Inc., General Electric Credit Corporation, the Loan Participants listed in Schedules A and B thereto, Central National Bank of Cleveland as Owner Trustee, and National City Bank as Loan Trustee and Bond Trustee. (Registration No. 2-68906 of Pennsylvania Power Company, Exhibit 5(e)(5).) -20- Exhibit Number - ------- 10-20- Participation Agreement No. 4 dated as of October 31, 1980 among Quarto Mining Company, the CAPCO Group, the Loan Participants listed in Schedule A thereto and National City Bank as Bond Trustee. (Registration No. 2- 68906 of Pennsylvania Power Company, Exhibit 10-16.) 10-21- Participation Agreement dated as of May 1, 1986, among Quarto Mining Company, the CAPCO Companies, the Loan Participants thereto, and National City Bank as Bond Trustee. (1986 Form 10-K, Exhibit 10-22.) 10-22- Participation Agreement No. 6 dated as of December 1, 1991 among Quarto Mining Company, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, the Toledo Edison Company, the Loan Participants listed in Schedule A thereto, National City Bank, as Mortgage Bond Trustee and National City Bank, as Refunding Bond Trustee. (1991 Form 10-K, Exhibit 10- 19.) 10-23- Agreement entered into as of October 20, 1981 among the CAPCO Companies regarding the use of Quarto coal at Mansfield Units 1, 2 and 3. (1981 Form 10-K, Exhibit 20-1.) 10-24- Restated Option Agreement dated as of May 1, 1983 by and between the North American Coal Corporation and the CAPCO Companies. (1983 Form 10-K, Exhibit 19-1.) 10-25- Trust Indenture and Mortgage dated as of October 1, 1973 between Quarto Mining Company and National City Bank, as Bond Trustee, together with Guaranty dated as of October 1, 1973 with respect thereto by the CAPCO Group. (Registration No. 2- 61146, Exhibit 5(e)(5).) 10-26- Amendment No. 1 dated August 1, 1974 to Trust Indenture and Mortgage dated as of October 1, 1973 between Quarto Mining Company and National City Bank, as Bond Trustee, together with Amendment No. 1 dated August 1, 1974 to Guaranty dated as of October 1, 1973 with respect thereto by the CAPCO Group. (Registration No. 2-53059, Exhibit 5(h)(2).) 10-27- Amendment No. 2 dated as of September 15, 1978 to the Trust Indenture and Mortgage dated as of October 1, 1973, as amended, between Quarto Mining Company and National City Bank, as Bond Trustee, together with Amendment No. 2 dated as of September 15, 1978 to Guaranty dated as of October 1, 1973 with respect to the CAPCO Group. (Registration No. 2-68906 of Pennsylvania Power Company, Exhibits 5(e)(11) and 5(e)(12).) 10-28- Amendment No. 3 dated as of October 31, 1980, to Trust Indenture and Mortgage dated as of October 1, 1973, as amended between Quarto Mining Company and National City Bank as Bond Trustee. (Registration No. 2-68906 of Pennsylvania Power Company, Exhibit 10-16.) -21- Exhibit Number - ------- 10-29- Amendment No. 4 dated as of July 1, 1985 to the Trust Indenture and Mortgage dated as of October 1, 1973, as amended between Quarto Mining Company and National City Bank as Bond Trustee. (1985 Form 10-K, Exhibit 10-28.) 10-30- Amendment No. 5 dated as of May 1, 1986, to the Trust Indenture and Mortgage between Quarto and National City Bank as Bond Trustee. (1986 Form 10-K, Exhibit 10-30.) 10-31- Amendment No. 6 dated as of December 1, 1991, to the Trust Indenture and Mortgage dated as of October 1, 1973, between Quarto Mining Company and National City Bank, as Bond Trustee. (1991 Form 10-K, Exhibit 10-28.) 10-32- Trust Indenture dated as of December 1, 1991, between Quarto Mining Company and National City Bank, as Bond Trustee. (1991 Form 10-K, Exhibit 10-29.) 10-33- Amendment No. 3 dated as of October 31, 1980 to the Bond Guaranty dated as of October 1, 1973, as amended, with respect to the CAPCO Group. (Registration No. 2- 68906 of Pennsylvania Power Company, Exhibit 10-16.) 10-34- Amendment No. 4 dated as of July 1, 1985 to the Bond Guaranty dated as of October 1, 1973, as amended, by the CAPCO Companies to National City Bank as Bond Trustee. (1985 Form 10-K, Exhibit 10-30.) 10-35- Amendment No. 5 dated as of May 1, 1986, to the Bond Guaranty by the CAPCO Companies to National City Bank as Bond Trustee. (1986 Form 10-K, Exhibit 10-33.) 10-36- Amendment No. 6A dated as of December 1, 1991, to the Bond Guaranty dated as of October 1, 1973, by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, the Toledo Edison Company to National City Bank, as Bond Trustee. (1991 Form 10- K, Exhibit 10-33.) 10-37- Amendment No. 6B dated as of December 30, 1991, to the Bond Guaranty dated as of October 1, 1973 by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, the Toledo Edison Company to National City Bank, as Bond Trustee. (1991 Form 10-K, Exhibit 10-34.) 10-38- Bond Guaranty dated as of December 1, 1991, by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, the Toledo Edison Company to National City Bank, as Bond Trustee. (1991 Form 10- K, Exhibit 10-35.) -22- Exhibit Number - ------- 10-39- Open end Mortgage dated as of October 1, 1973 between Quarto Mining Company and the CAPCO Companies and Amendment No. 1 thereto, dated as of September 15, 1978. (Registration No. 2- 68906 of Pennsylvania Power Company, Exhibit 10-23.) 10-40- Repayment and Security Agreement and Assignment of Lease dated as of October 1, 1973 between Quarto Mining Company and Ohio Edison Company as Agent for the CAPCO Companies and Amendment No. 1 thereto, dated as of September 15, 1978. (1980 Form 10- K, Exhibit 20-2.) 10-41- Restructuring Agreement dated as of April 1, 1985 among Quarto Mining Company, the Company and the other CAPCO Companies, Energy Properties, Inc., General Electric Credit Corporation, the Loan Participants signatories thereto, Central National Bank of Cleveland, as Owner Trustee and National City Bank as Loan Trustee and Bond Trustee. (1985 Form 10-K, Exhibit 10- 33.) 10-42- Unsecured Note Guaranty dated as of July 1, 1985 by the CAPCO Companies to General Electric Credit Corporation. (1985 Form 10-K, Exhibit 10-34.) 10-43- Memorandum of Understanding dated March 31, 1985 among the CAPCO Companies. (1985 Form 10-K, Exhibit 10-35.) (C)10-44- Ohio Edison Company Executive Incentive Compensation Plan. (1984 Form 10-K, Exhibit 19-2.) (C)10-45- Ohio Edison Company Executive Incentive Compensation Plan as amended February 16, 1987. (1986 Form 10-K, Exhibit 10-40.) (C)10-46- Restated and Amended Executive Deferred Compensation Plan. (1989 Form 10-K, Exhibit 10-36.) (C)10-47- Restated and Amended Supplemental Executive Retirement Plan. (1989 Form 10-K, Exhibit 10-37). (D)10-48- Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 Hereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1986 Form 10-K, Exhibit 28- 1.) (D)10-49- Amendment No. 1 dated as of September 1, 1987 to Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 thereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company (now The Bank of New York), as Indenture Trustee, and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-46.) -23- Exhibit Number - ------- (D)10-50- Amendment No. 3 dated as of May 16, 1988 to Participation Agreement dated as of March 16, 1987, as amended among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10- 47.) (D)10-51- Amendment No. 4 dated as of November 1, 1991 to Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-47.) (D)10-52- Amendment No. 5 dated as of November 24, 1992 to Participation Agreement dated as of March 16, 1987, as amended, among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPPII Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company as Lessee. (1992 Form 10-K, Exhibit 10-49.) (D)10-53- Amendment No. 6 dated as of January 12, 1993 to Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-50.) (D)10-54- Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, Lessor, and Ohio Edison Company, Lessee. (1986 Form 10-K, Exhibit 28-2.) (D)10-55- Amendment No. 1 dated as of September 1, 1987 to Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (1991 Form 10-K, Exhibit 10-49.) (D)10-56- Amendment No. 2 dated as of November 1, 1991, to Facility Lease dated as of March 16, 1987, between The First National Bank of Boston, as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (1991 Form 10-K, Exhibit 10-50.) (D)10-57- Amendment No. 3 dated as of November 24, 1992 to Facility Lease dated as of March 16, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, as Owner Participant and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-54.) -24- Exhibit Number - ------- (D)10-58- Letter Agreement dated as of March 19, 1987 between Ohio Edison Company, Lessee, and The First National Bank of Boston, as Owner Trustee under a Trust dated March 16, 1987 with Chase Manhattan Realty Leasing Corporation, required by Section 3(d) of the Facility Lease. (1986 Form 10-K, Exhibit 28-3.) (D)10-59- Ground Lease dated as of March 16, 1987 between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with the Owner Participant, Tenant. (1986 Form 10-K, Exhibit 28-4.) (D)10-60- Trust Agreement dated as of March 16, 1987 between Perry One Alpha Limited Partnership, as Owner Participant, and The First National Bank of Boston. (1986 Form 10-K, Exhibit 28-5.) (D)10-61- Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of March 16, 1987 with Perry One Alpha Limited Partnership, and Irving Trust Company, as Indenture Trustee. (1986 Form 10-K, Exhibit 28-6.) (D)10-62- Supplemental Indenture No. 1 dated as of September 1, 1987 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston as Owner Trustee and Irving Trust Company (now The Bank of New York), as Indenture Trustee. (1991 Form 10-K, Exhibit 10-55.) (D)10-63- Supplemental Indenture No. 2 dated as of November 1, 1991 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee and The Bank of New York, as Indenture Trustee. (1991 Form 10-K, Exhibit 10-56.) (D)10-64- Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (1986 Form 10-K, Exhibit 28-7.) (D)10-65- Amendment No. 1 dated as of November 1, 1991 to Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and Parock Limited Partnership and Ohio Edison Company. (1991 Form 10-K, Exhibit 10-58.) (D)10-66- Partial Mortgage Release dated as of March 19, 1987 under the Indenture between Ohio Edison Company and Bankers Trust Company, as Trustee, dated as of the 1st day of August, 1930. (1986 Form 10-K, Exhibit 28-8.) (D)10-67- Assignment, Assumption and Further Agreement dated as of March 16, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison Company. (1986 Form 10-K, Exhibit 28-9.) -25- Exhibit Number - ------- (D)10-68- Additional Support Agreement dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, and Ohio Edison Company. (1986 Form 10-K, Exhibit 28-10.) (D)10-69- Bill of Sale, Instrument of Transfer and Severance Agreement dated as of March 19, 1987 between Ohio Edison Company, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership. (1986 Form 10-K, Exhibit 28- 11.) (D)10-70- Easement dated as of March 16, 1987 from Ohio Edison Company, Grantor, to The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, Grantee. (1986 Form 10-K, File Exhibit 28-12.) 10-71- Participation Agreement dated as of March 16, 1987 among Security Pacific Capital Leasing Corporation, as Owner Participant, the Original Loan Participants listed in Schedule 1 Hereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1986 Form 10-K, as Exhibit 28-13.) 10-72- Amendment No. 1 dated as of September 1, 1987 to Participation Agreement dated as of March 16, 1987 among Security Pacific Capital Leasing Corporation, as Owner Participant, The Original Loan Participants Listed in Schedule 1 thereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10- 65.) 10-73- Amendment No. 4 dated as of November 1, 1991, to Participation Agreement dated as of March 16, 1987 among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-66.) 10-74- Amendment No. 5 dated as of November 24, 1992 to Participation Agreement dated as of March 16, 1987 as amended among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-71.) -26- Exhibit Number - ------- 10-75- Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, Lessor, and Ohio Edison Company, as Lessee. (1986 Form 10-K, Exhibit 28-14.) 10-76- Amendment No. 1 dated as of September 1, 1987 to Facility Lease dated as of March 16, 1987 between The First National Bank of Boston as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (1991 Form 10-K, Exhibit 10-68.) 10-77- Amendment No. 2 dated as of November 1, 1991 to Facility Lease dated as of March 16, 1987 between The First National Bank of Boston as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (1991 Form 10-K, Exhibit 10-69.) 10-78- Amendment No. 3 dated as of November 24, 1992 to Facility Lease dated as of March 16, 1987, as amended, between, The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, as Owner Participant and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10- 75.) 10-79- Amendment No. 4 dated as of January 12, 1993 to Facility Lease dated as of March 16, 1987 as amended between, The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10- 76.) 10-80- Letter Agreement dated as of March 19, 1987 between Ohio Edison Company, as Lessee, and The First National Bank of Boston, as Owner Trustee under a Trust, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, required by Section 3(d) of the Facility Lease. (1986 Form 10- K, Exhibit 28-15.) 10-81- Ground Lease dated as of March 16, 1987 between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, Tenant. (1986 Form 10-K, Exhibit 28-16.) 10-82- Trust Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation, as Owner Participant, and The First National Bank of Boston. (1986 Form 10-K, Exhibit 28-17.) 10-83- Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, and Irving Trust Company, as Indenture Trustee. (1986 Form 10-K, Exhibit 28-18.) 10-84- Supplemental Indenture No. 1 dated as of September 1, 1987 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee and Irving Trust Company (now The Bank of New York), as Indenture Trustee. (1991 Form 10-K, Exhibit 10-74.) -27- Exhibit Number - ------- 10-85- Supplemental Indenture No. 2 dated as of November 1, 1991 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee and The Bank of New York, as Indenture Trustee. (1991 Form 10-K, Exhibit 10-75.) 10-86- Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1986 Form 10-K, Exhibit 28-19.) 10-87- Amendment No. 1 dated as of November 1, 1991 to Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation and Ohio Edison Company. (1991 Form 10-K, Exhibit 10-77.) 10-88- Assignment, Assumption and Further Agreement dated as of March 16, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison Company. (1986 Form 10-K, Exhibit 28-20.) 10-89- Additional Support Agreement dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, and Ohio Edison Company. (1986 Form 10-K, Exhibit 28-21.) 10-90- Bill of Sale, Instrument of Transfer and Severance Agreement dated as of March 19, 1987 between Ohio Edison Company, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, Buyer. (1986 Form 10-K, Exhibit 28-22.) 10-91- Easement dated as of March 16, 1987 from Ohio Edison Company, Grantor, to The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, Grantee. (1986 Form 10-K, Exhibit 28-23.) 10-92- Refinancing Agreement dated as of November 1, 1991 among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, 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 Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-82.) -28- Exhibit Number - ------- 10-93- Refinancing Agreement dated as of November 1, 1991 among Security Pacific Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, 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 Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-83.) (A)10-94- Ohio Edison Company Master Decommissioning Trust Agreement for Perry Nuclear Power Plant Unit One, Perry Nuclear Power Plant Unit Two, Beaver Valley Power Station Unit One and Beaver Valley Power Station Unit Two dated July 1, 1993. 10-95- Nuclear Fuel Lease dated as of March 31, 1989, between OES Fuel, Incorporated, as Lessor, and Ohio Edison Company, as Lessee. (1989 Form 10-K, Exhibit 10-62.) 10-96- Receivables Purchase Agreement dated as of November 28, 1989 between Ohio Edison Company and OES Capital, Incorporated. (1989 Form 10-K, Exhibit 10-63.) 10-97- Guarantee Agreement entered into by Ohio Edison Company dated as of January 17, 1991. (1990 Form 10-K, Exhibit 10-64). 10-98- Transfer and Assignment Agreement among Ohio Edison Company and Chemical Bank, as trustee under the OE Power Contract Trust. (1990 Form 10-K, Exhibit 10-65). 10-99- Renunciation of Payments and Assignment among Ohio Edison Company, Monongahela Power Company, West Penn Power Company, and the Potomac Edison Company dated as of January 4, 1991. (1990 Form 10-K, Exhibit 10-66). (E)10-100- Participation Agreement dated as of September 15, 1987, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-1.) (E)10-101- Amendment No. 1 dated as of February 1, 1988, to Participation Agreement dated as of September 15, 1987, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-2.) (E)10-102- Amendment No. 3 dated as of March 16, 1988 to Participation Agreement dated as ofSeptember 15, 1987, as amended, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-99.) -29- Exhibit Number - ------- (E)10-103- Amendment No. 4 dated as of November 5, 1992 to Participation Agreement dated as of September 15, 1987, as amended, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-100.) (E)10-104- Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, Lessor, and Ohio Edison Company, Lessee. (1987 Form 10-K, Exhibit 28-3.) (E)10-105- Amendment No. 1 dated as of February 1, 1988, to Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, Lessor, and Ohio Edison Company, Lessee. (1987 Form 10-K, Exhibit 28-4.) (E)10-106- Amendment No. 2 dated as of November 5, 1992 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-103.) (E)10-107- Ground Lease and Easement Agreement dated as of September 15, 1987, between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, Tenant. (1987 Form 10-K, Exhibit 28- 5.) (E)10-108- Trust Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Limited Partnership, as Owner Participant, and The First National Bank of Boston. (1987 Form 10-K, Exhibit 28-6.) (E)10-109- Trust Indenture, Mortgage, Security Agreement and Assignment 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 Beaver Valley Two Pi Limited Partnership, and Irving Trust Company, as Indenture Trustee. (1987 Form 10-K, Exhibit 28-7.) (E)10-110- Supplemental Indenture No. 1 dated as of February 1, 1988 to Trust Indenture, Mortgage, Security Agreement and Assignment 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 Beaver Valley Two Pi Limited Partnership and Irving Trust Company, as Indenture Trustee. (1987 Form 10-K, Exhibit 28-8.) (E)10-111- Tax Indemnification Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-9.) -30- Exhibit Number - ------- (E)10-112- Tax Indemnification Agreement dated as of September 15, 1987, between HG Power Plant, Inc., as Limited Partner and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-10.) (E)10-113- 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 Beaver Valley Two Pi Limited Partnership, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison Company. (1987 Form 10-K, Exhibit 28-11.) (E)10-114- 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 Beaver Valley Two Pi Limited Partnership, and Ohio Edison Company. (1987 Form 10-K, Exhibit 28-12.) (F)10-115- Participation Agreement dated as of September 15, 1987, among Chrysler Consortium Corporation, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28- 13.) (F)10-116- Amendment No. 1 dated as of February 1, 1988, to Participation Agreement dated as of September 15, 1987, among Chrysler Consortium Corporation, as Owner Participant, the Original Loan Participants listed in Schedule I Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-14.) (F)10-117- Amendment No. 3 dated as of March 16, 1988 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10- 114.) (F)10-118- Amendment No. 4 dated as of November 5, 1992 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-115.) (F)10-119- Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, Lessor, and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-15.) -31- Exhibit Number - ------- (F)10-120- Amendment No. 1 dated as of February 1, 1988, to Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, Lessor, and Ohio Edison Company, Lessee. (1987 Form 10-K, Exhibit 28-16.) (F)10-121- Amendment No. 2 dated as of November 5, 1992 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner Participant and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 118.) (F)10-122- Amendment No. 3 dated as of January 12, 1993 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-119.) (F)10-123- Ground Lease and Easement Agreement dated as of September 15, 1987, between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation, Tenant. (1987 Form 10-K, Exhibit 28- 17.) (F)10-124- Trust Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and The First National Bank of Boston. (1987 Form 10-K, Exhibit 28-18.) (F)10-125- Trust Indenture, Mortgage, Security Agreement and Assignment 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 Chrysler Consortium Corporation and Irving Trust Company, as Indenture Trustee. (1987 Form 10-K, Exhibit 28-19.) (F)10-126- Supplemental Indenture No. 1 dated as of February 1, 1988 to Trust Indenture, Mortgage, Security Agreement and Assignment 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 Chrysler Consortium Corporation and Irving Trust Company, as Indenture Trustee. (1987 Form 10-K, Exhibit 28-20.) (F)10-127- Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-21.) (F)10-128- 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 Chrysler Consortium Corporation, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, and Toledo Edison Company. (1987 Form 10-K, Exhibit 28-22.) -32- Exhibit Number - ------- (F)10-129- 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 Chrysler Consortium Corporation, and Ohio Edison Company. (1987 Form 10-K, Exhibit 28-23.) 10-130- Operating Agreement dated March 10, 1987 with respect to Perry Unit No. 1 between the CAPCO Companies. (1987 Form 10-K, Exhibit 28-24.) 10-131- Operating Agreement for Bruce Mansfield Units Nos. 1, 2 and 3 dated as of June 1, 1976, and executed on September 15, 1987, by and between the CAPCO Companies. (1987 Form 10-K, Exhibit 28-25.) 10-132- Operating Agreement for W. H. Sammis Unit No. 7 dated as of September 1, 1971 by and between the CAPCO Companies. (1987 Form 10-K, Exhibit 28-26.) 10-133- OE-APS Power Interchange Agreement dated March 18, 1987, by and among Ohio Edison Company and Pennsylvania Power Company, and Monongahela Power Company and West Penn Power Company and The Potomac Edison Company. (1987 Form 10-K, Exhibit 28-27.) 10-134- OE-PEPCO Power Supply Agreement dated March 18, 1987, by and among Ohio Edison Company and Pennsylvania Power Company and Potomac Electric Power Company. (1987 Form 10-K, Exhibit 28- 28.) 10-135- Supplement No. 1 dated as of April 28, 1987, to the OE-PEPCO Power Supply Agreement dated March 18, 1987, by and among Ohio Edison Company, Pennsylvania Power Company, and Potomac Electric Power Company. (1987 Form 10-K, Exhibit 28-29.) 10-136- APS-PEPCO Power Resale Agreement dated March 18, 1987, by and among Monongahela Power Company, West Penn Power Company, and The Potomac Edison Company and Potomac Electric Power Company. (1987 Form 10-K, Exhibit 28-30.) 11- Calculation of fully diluted earnings per common share. 12- Consolidated fixed charge ratios. (A) 13- 1993 Annual Report to Stockholders. (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed "filed" with the SEC.) 18- Letter from Independent Public Accountants regarding a change in accounting. 21- List of Subsidiaries of the Registrant at December 31, 1993. 23- Consent of Independent Public Accountants. -33- Exhibit Number - ------- (A) Provided herein in electronic format as an exhibit. (B) Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S- K, the Company has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis, but hereby agrees to furnish to the SEC on request any such instruments. (C) Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K. (D) Substantially similar documents have been entered into relating to three additional Owner Participants. (E) Substantially similar documents have been entered into relating to five additional Owner Participants. (F) Substantially similar documents have been entered into relating to two additional Owner Participants. Note: Reports of the Company on Forms 10-Q and 10-K are on file with the SEC under number 1-2578. Pursuant to Rule 14a - 3 (10) of the Securities Exchange Act of 1934, the Company will furnish any exhibit in this Report upon the payment of the Company's expenses in furnishing such exhibit. (b) Reports on Form 8-K The Company filed one report on Form 8-K since September 30, 1993. A report dated December 13, 1993, reported the abandonment of Perry Unit 2 as a possible electric generating plant. -34- REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of Ohio Edison Company: We have audited, in accordance with generally accepted auditing standards, the consolidated financial statements included in Ohio Edison Company's annual report to stockholders incorporated by reference in this Form 10-K and have issued our report thereon dated February 1, 1994. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed in Item 14 are the responsibility of the Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic consolidated financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic consolidated 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 consolidated financial statements taken as a whole. ARTHUR ANDERSEN & CO. New York, N.Y. February 1, 1994 -35- SCHEDULE V Page 1 OHIO EDISON COMPANY CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31, 1993
Beginning Additions Retirements Other Ending Classification Balance at Cost or Sales Changes(a) Balance -------------- --------- --------- ------------- --------- ------- (In Thousands) UTILITY PLANT AT ORIGINAL COST: ELECTRIC: Intangibles- Organization expense . . . . . . . . . . $ 113 $ - $ - $ - $ 113 Franchises and consents. . . . . . . . . 64 - - - 64 Production- Steam. . . . . . . . . . . . . . . . . . 2,150,979 46,475 16,297 (81,829) 2,099,328 Nuclear. . . . . . . . . . . . . . . . . 3,076,797 28,257 4,011 314,171 3,415,214 Other. . . . . . . . . . . . . . . . . . 23,214 50 100 34 23,198 Transmission. . . . . . . . . . . . . . . 814,917 30,306 4,353 55,613 896,483 Distribution. . . . . . . . . . . . . . . 1,281,413 73,141 15,073 (45,109) 1,294,372 General . . . . . . . . . . . . . . . . . 215,009 13,760 12,635 1,423 217,557 Construction work in progress . . . . . . 479,289 46,109 - (342,504)(b) 182,894 Plant held for future use . . . . . . . . 80,288 17 25,942 111,553 165,916 ----------- -------- -------- --------- ---------- Total electric . . . . . . . . . . . . 8,122,083 238,115 78,411 13,352 8,295,139 NUCLEAR FUEL. . . . . . . . . . . . . . . . 366,727 24,140 75,803 - 315,064 ----------- -------- -------- --------- ---------- Total utility plant at original cost. . . . . . . . . . . . . 8,488,810 262,255 154,214 13,352 8,610,203 NONUTILITY PROPERTY AT ORIGINAL COST. . . . . 8,523 924 1,599 115 7,963 ----------- -------- -------- --------- ---------- Total property, plant and equipment. . . . . . . . . . . . . $8,497,333 $263,179 $155,813 $ 13,467 $8,618,166 =========== ======== ======== ========= ========== - -------------------- (a) Represents increases of approximately $354,135,000 and $32,656,000 to plant in-service and construction work in progress, respectively, as a result of adopting Statement of Financial Accounting Standards No. 109, transfers and adjustments within property, plant and equipment and amortization of ACRS depreciation deductions sold under the Economic Recovery Tax Act of 1981, except as otherwise noted. (b) Includes the write-off of Perry Unit 2 construction costs of approximately $375,160,000.
-36- SCHEDULE V Page 2 OHIO EDISON COMPANY CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31, 1992
Beginning Additions Retirements Other Ending Classification Balance at Cost or Sales Changes(a) Balance -------------- --------- --------- ------------ ----------- ------- (In Thousands) UTILITY PLANT AT ORIGINAL COST: ELECTRIC: Intangibles- Organization expense . . . . . . . . . $ 113 $ - $ - $ - $ 113 Franchises and consents. . . . . . . . 64 - - - 64 Production- Steam. . . . . . . . . . . . . . . . . 2,097,035 74,333 21,057 668 2,150,979 Nuclear. . . . . . . . . . . . . . . . 3,043,302 45,882 7,002 (5,385) 3,076,797 Other. . . . . . . . . . . . . . . . . 22,778 484 48 - 23,214 Transmission . . . . . . . . . . . . . . 792,770 21,674 5,043 5,516 814,917 Distribution . . . . . . . . . . . . . . 1,206,043 89,956 14,846 260 1,281,413 General. . . . . . . . . . . . . . . . . 208,555 19,276 12,802 (20) 215,009 Construction work in progress. . . . . . 503,956 (24,667) - - 479,289 Plant held for future use. . . . . . . . 80,297 157 - (166) 80,288 ---------- -------- -------- ------ ---------- Total electric . . . . . . . . . . . . 7,954,913 227,095 60,798 873 8,122,083 NUCLEAR FUEL . . . . . . . . . . . . . . . 391,116 24,098 48,487 - 366,727 ---------- -------- -------- ------ ---------- Total utility plant at original cost . 8,346,029 251,193 109,285 873 8,488,810 NONUTILITY PROPERTY AT ORIGINAL COST. . . . . 8,657 1,399 1,589 56 8,523 ---------- -------- -------- ------ ---------- Total property, plant and equipment. . . . . . . . . . . . . $8,354,686 $252,592 $ 110,874 $ 929 $8,497,333 ========== ======== ========== ======= ========== - -------------------------------- (a) Represents transfers and adjustments within property, plant and equipment and amortization of ACRS depreciation deductions sold under the Economic Recovery Tax Act of 1981.
-37- SCHEDULE V Page 3 OHIO EDISON COMPANY CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31, 1991
Beginning Additions Retirements Other Ending Classification Balance at Cost or Sales Changes(a) Balance -------------- --------- ---------- ------------ ---------- ------- (In Thousands) UTILITY PLANT AT ORIGINAL COST: ELECTRIC: Intangibles- Organization expense . . . . . . . . . . $ 113 $ - $ - $ - $ 113 Franchises and consents . . . . . . . . 64 - - - 64 Production- Steam. . . . . . . . . . . . . . . . . . 2,072,650 51,726 12,526 (14,815) 2,097,035 Nuclear . . . . . . . . . . . . . . . . 3,004,217 54,035 14,961 11 3,043,302 Other. . . . . . . . . . . . . . . . . . 22,583 273 78 - 22,778 Transmission. . . . . . . . . . . . . . . 764,051 30,482 2,828 1,065 (b) 792,770 Distribution. . . . . . . . . . . . . . . 1,141,469 77,947 13,590 217 1,206,043 General . . . . . . . . . . . . . . . . . 206,569 21,157 19,636 465 (b) 208,555 Construction work in progress . . . . . . 526,219 (22,263) - - 503,956 Plant held for future use . . . . . . . . 64,851 33 5 15,418 80,297 --------- ------- -------- ------ --------- Total electric . . . . . . . . . . . . 7,802,786 213,390 63,624 2,361 7,954,913 NUCLEAR FUEL. . . . . . . . . . . . . . . . 436,269 20,104 65,257 - 391,116 --------- ------- -------- ------ --------- Total utility plant at original cost. . . . . . . . . . . . . 8,239,055 233,494 128,881 2,361 8,346,029 NONUTILITY PROPERTY AT ORIGINAL COST. . . . . 7,343 2,128 838 24 8,657 --------- ------- -------- ------ --------- Total property, plant and equipment. . . . . . . . . . . . . $8,246,398 $235,622 $ 129,719 $ 2,385 $8,354,686 ========== ======== ========== ======== ========== - ------------------------------------------ (a) Represents transfers and adjustments within property, plant and equipment and amortization of ACRS depreciation deductions sold under the Economic Recovery Tax Act of 1981, except as otherwise noted. (b) Includes a $1,422,000 adjustment to previously capitalized leases. -38-
SCHEDULE VI Page 1 OHIO EDISON COMPANY CONSOLIDATED ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31, 1993
Additions --------------------------------- Provisions Deductions Charged to --------------------- ---------------------- Retirements, Beginning Other Salvage Renewals and Removal Other Ending Description Balance Income Accounts(a) Recoveries Replacements Cost Changes(b) Balance ----------- --------- ------ ----------- ---------- ------------ ------- ---------- --------- (In Thousands) UTILITY PLANT: ELECTRIC: Production- Steam . . . . . . . . . $ 889,298 $ 58,649 $ 157 $ 452 $ 16,297 $ 2,713 $(97,931) $ 831,615 Nuclear . . . . . . . . 578,052 102,108 - 2,175 4,011 89 46,783 725,018 Other . . . . . . . . . 13,924 898 - - 100 1 12 14,733 Transmission. . . . . . . 294,781 17,429 741 2,054 4,353 2,058 27,729 336,323 Distribution. . . . . . . 492,168 35,530 39 4,847 15,051 6,696 (24,760) 486,077 General . . . . . . . . . 70,010 4,161 10,160 696 12,281 301 103 72,548 Plant held for future use 33,514 - - - 25,942 - 107,164 114,736 ---------- -------- ------ ------ ------- ------ ------- -------- Total electric. . . . . 2,371,747 218,775 11,097 10,224 78,035 11,858 59,100 2,581,050 NUCLEAR FUEL . . . . . . . 178,653 - 48,627 - 75,803 - - 151,477 ---------- -------- ------ ------ ------- ------ ------- --------- Total utility plant . . 2,550,400 218,775 59,724 10,224 153,838 11,858 59,100 2,732,527 NONUTILITY PROPERTY . . . . 2,176 70 64 560 - 1,169 - 1,701 ---------- -------- ------ ------ ------- ------ ------- --------- Total property, plant and equipment. . . . . $2,552,576 $218,845 $59,788 $10,784 $153,838 $13,027 $ 59,100 $2,734,228 ========== ======== ======= ======= ======== ======= ======== ========== - ------------------- (a) Represents amortization of capital leases and nuclear fuel, and depreciation charged to clearing accounts. (b) Represents interest earned on external decommissioning trust funds, transfers of provisions for depreciation within property, plant and equipment and approximately $58,459,000 resulting from the adoption of Statement of Financial Accounting Standards No. 109. -39-
SCHEDULE VI Page 2 OHIO EDISON COMPANY CONSOLIDATED ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31, 1992
Additions ------------------------------- Deductions Provisions ---------------------- Charged to -------------------- Retirements, Beginning Other Salvage Renewals and Removal Other Ending Description Balance Income Accounts(a) Recoveries Replacements Cost Changes(b) Balance ----------- --------- ------ ----------- ---------- ------------ ------- ---------- ------- (In Thousands) UTILITY PLANT: ELECTRIC: Production- Steam . . . . . . . . . $ 851,556 $ 63,218 $ 158 $ 362 $ 21,057 $ 4,939 $ - $ 889,298 Nuclear . . . . . . . . 497,918 89,491 - - 7,002 2,655 300 578,052 Other . . . . . . . . . 13,014 958 - - 48 - - 13,924 Transmission. . . . . . . 281,101 18,193 744 1,420 4,701 1,935 (41) 294,781 Distribution. . . . . . . 462,193 48,367 37 3,733 14,846 7,357 41 492,168 General . . . . . . . . . 68,759 3,881 9,771 848 12,581 668 - 70,010 Plant held for future use 33,514 - - - - - - 33,514 --------- ------- ------ ------ ------- ------ ---- --------- Total electric. . . . . 2,208,055 224,108 10,710 6,363 60,235 17,554 300 2,371,747 NUCLEAR FUEL . . . . . . . 152,559 - 74,581 - 48,487 - - 178,653 --------- ------- ------ ------ ------- ------ ---- --------- Total utility plant . . 2,360,614 224,108 85,291 6,363 108,722 17,554 300 2,550,400 NONUTILITY PROPERTY . . . . 1,747 72 57 1,337 109 928 - 2,176 --------- ------- ------ ------ ------- ------ ---- --------- Total property, plant and equipment. . . . . $2,362,361 $224,180 $85,348 $7,700 $108,831 $18,482 $ 300 $2,552,576 ========== ======== ======= ======= ======== ======= ===== ========== - ------------------- (a) Represents amortization of capital leases and nuclear fuel, and depreciation charged to clearing accounts. (b) Represents interest earned on external decommissioning trust funds and transfers of provisions for depreciation within property, plant and equipment. -40- /TABLE SCHEDULE VI Page 3 OHIO EDISON COMPANY CONSOLIDATED ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31, 1991
Additions ------------------------------ Provisions Deductions Charged to --------------------- ------------------- Retirements, Beginning Other Salvage Renewals and Removal Other Ending Description Balance Income Accounts(a) Recoveries Replacements Cost Changes(b) Balance ----------- --------- ------ ----------- ---------- ------------ ------- ---------- ------- (In Thousands) UTILITY PLANT: ELECTRIC: Production- Steam . . . . . . . . . $ 817,501 $ 66,788 $ 142 $ 336 $ 12,526 $ 7,417 $(13,268) $ 851,556 Nuclear . . . . . . . . 422,220 91,087 - 226 14,961 1,362 708 497,918 Other . . . . . . . . . 12,089 999 - - 78 - 4 13,014 Transmission. . . . . . . 264,153 19,520 732 1,468 2,828 1,929 (15) 281,101 Distribution. . . . . . . 437,206 41,932 36 2,829 13,590 6,325 105 462,193 General . . . . . . . . . 75,052 3,814 8,910 883 19,591 307 (2) 68,759 Plant held for future use 20,343 - - - 5 - 13,176 33,514 --------- ------- ------ ----- ------- ------ ------- --------- Total electric. . . . . 2,048,564 224,140 9,820 5,742 63,579 17,340 708 2,208,055 NUCLEAR FUEL . . . . . . . 141,272 - 76,544 - 65,257 - - 152,559 --------- ------- ------ ----- ------- ------ ------- --------- Total utility plant . . 2,189,836 224,140 86,364 5,742 128,836 17,340 708 2,360,614 NONUTILITY PROPERTY . . . . 1,121 62 52 558 - 46 - 1,747 --------- ------- ------ ----- ------- ------ ------- --------- Total property, plant and equipment. . . . . $2,190,957 $224,202 $86,416 $6,300 $128,836 $17,386 $ 708 $2,362,361 ========== ======== ======= ====== ======== ======= ======== ========== - ------------------- (a) Represents amortization of capital leases and nuclear fuel, and depreciation charged to clearing accounts. (b) Represents interest earned on external decommissioning trust funds and transfers of provisions for depreciation within property, plant and equipment. -41-
SCHEDULE VIII OHIO EDISON COMPANY CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
Additions -------------------------- Charged Charged (Credited) (Credited) Beginning to to Other Ending Description Balance Income Accounts Deductions Balance ----------- --------- ---------- ---------- ---------- ------- (In Thousands) Year Ended December 31, 1993: Accumulated provision for uncollectible accounts . . . . . . . . $6,432 $ 8,002 $1,751(a) $ 9,278(b) $6,907 ====== ======= ====== ======= ====== Reserve for injuries and damages . . . . $4,934 $ 588 $ (44)(c) $ 300(d) $5,178 ====== ======= ====== ======= ====== Year Ended December 31, 1992: Accumulated provision for uncollectible accounts . . . . . . . . $5,312 $20,034 $1,875(a) $20,789(b) $6,432 ====== ======= ====== ======= ====== Reserve for injuries and damages . . . . $5,306 $ 222 $ (6)(c) $ 588(d) $4,934 ====== ======= ====== ======= ====== Year Ended December 31, 1991: Accumulated provision for uncollectible accounts . . . . . . . . $5,210 $ 6,879 $1,741(a) $ 8,518(b) $5,312 ====== ======= ====== ======= ====== Reserve for injuries and damages . . . . $5,714 $ 750 $ (11)(c) $ 1,147(d) $5,306 ====== ======= ====== ======= ====== - --------------------- (a) Represents recoveries and reinstatements of accounts previously written off. (b) Represents the write-off of accounts considered to be uncollectible. (c) Represents net provisions charged to property, plant and equipment on the basis of direct costs of construction of certain classes of property. (d) Represents payments for claims and other related expenses. -42-
SCHEDULE IX OHIO EDISON COMPANY CONSOLIDATED SHORT-TERM BORROWINGS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
1993 1992 1991 ------------------------- ------------------------- -------------------------- Advances From Notes Advances From Notes Advances From Notes Financial Payable Financial Payable Financial Payable Institutions To Banks Institutions To Banks Institutions To Banks Balance at End of Period $104,126,000 $ - $100,871,000 $ 50,700,000 $ 94,855,000 $ - Weighted Average Interest Rate at End of Period 3.23% - 3.56% 4.12% 5.26% - Maximum Amount Outstanding During the Period $110,994,000 $ 146,000,000 $102,887,000 $157,500,000 $ 107,307,000 $248,000,000 Average Amount Outstanding During the Period (a) $ 84,550,000 $ 33,982,000 $ 81,641,000 $ 25,027,000 $ 86,894,000 $ 70,046,000 Weighted Average Interest Rate During the Period (a)(b) 3.24% 3.69% 4.03% 4.10% 6.31% 7.04% - ------------------ (a) Based on the daily amounts outstanding. (b) Excludes the effect of commitment fees. -43-
SCHEDULE X OHIO EDISON COMPANY SUPPLEMENTARY CONSOLIDATED INCOME STATEMENT INFORMATION FOR THE THREE YEARS ENDED DECEMBER 31, 1993
Item Charged to Expense - ----------------------- ------------------------------------------ 1993 1992 1991 ---- ---- ---- Maintenance and repairs $189,806,000 $188,009,000 $187,431,000 Other items required by this schedule are omitted due to the required information being shown in the financial statements or being less than 1% of total sales.
-44- 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. OHIO EDISON COMPANY BY /s/W. R. Holland ------------------------------------------- W. R. Holland President and Chief Executive Officer Date: March 23, 1994 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated: /s/W. R. Holland /s/H. P. Burg - --------------------------------- --------------------------------------------- W. R. Holland H. P. Burg President and Chief Senior Vice President and Director Executive Officer and Director (Principal Financial Officer and Principal (Principal Executive Officer) Accounting Officer) /s/Donald C. Blasius /s/Paul J. Powers - --------------------------------- -------------------------------------------- Donald C. Blasius Paul J. Powers Director Director /s/Robert H. Carlson /s/Charles W. Rainger - --------------------------------- -------------------------------------------- Robert H. Carlson Charles W. Rainger Director Director /s/Robert M. Carter - --------------------------------- -------------------------------------------- Robert M. Carter George M. Smart Director Director /s Carol A. Cartwright /s/Frank C. Watson - --------------------------------- -------------------------------------------- Carol A. Cartwright Frank C. Watson Director Director /s/R. L. Loughhead /s/Jesse T. Williams, Sr. - --------------------------------- -------------------------------------------- R. L. Loughhead Jesse T. Williams, Sr. Director Director /s/Glenn H. Meadows - --------------------------------- Glenn H. Meadows Director Date: March 23, 1994 EX-4 2 OE10K _____________________________________________ OHIO EDISON COMPANY with BANKERS TRUST COMPANY, As Trustee _______________ SIXTY-FOURTH SUPPLEMENTAL INDENTURE Providing among other things for First Mortgage Bonds Guarantee Series B of 1993 due 2029 Guarantee Series C of 1993 due 2029 and Guarantee Series D of 1993 due 2029 _______________ Dated as of November 15, 1993 ----------------------------------------------- SUPPLEMENTAL INDENTURE, dated as of November 15, 1993 between Ohio Edison Company, a corporation organized and existing under the laws of the State of Ohio (hereinafter called the "Company"), party of the first part, and Bankers Trust Company, a corporation organized and existing under the laws of the State of New York, as Trustee under the Indenture hereinafter referred to, party of the second part. Whereas, the Company has heretofore executed and delivered to Bankers Trust Company, as Trustee (hereinafter called the "Trustee"), a certain Indenture of Mortgage and Deed of Trust, dated as of August 1, 1930, to secure an issue of bonds of the Company, issued and to be issued in series, from time to time, in the manner and subject to the conditions set forth in the said Indenture; and the said Indenture has been supplemented by supplemental indentures, dated as of August 1, 1930, March 3, 1931, as of November 1, 1935, as of January 1, 1937, as of September 1, 1937, as of June 13, 1939, as of September 1, 1944, as of April 1, 1945, as of September 1, 1948, as of May 1, 1950, as of January 1, 1954, as of May 1, 1955, as of August 1, 1956, as of March 1, 1958, as of April 1, 1959, as of June 1, 1961, as of September 1, 1969, as of May 1, 1970, as of September 1, 1970, as of June 1, 1971, as of August 1, 1972, as of September 1, 1973, as of August 1, 1974, as of July 1, 1976, as of December 1, 1976, as of June 15, 1977, as of May 15, 1978, as of February 1, 1980, as of April 15, 1980, as of June 15, 1980, as of October 1, 1981, as of October 15, 1981, as of February 15, 1982, as of July 1, 1982, as of March 1, 1983, as of March 1, 1984, as of September 15, 1984, as of September 27, 1984, as of November 8, 1984, as of December 1, 1984, as of December 5, 1984, as of January 1, 1985, as of January 30, 1985, as of February 25, 1985, as of July 1, 1985, as of October 1, 1985, as of January 15, 1986, as of May 20, 1986, as of June 3, 1986, as of October 1, 1986, as of July 15, 1989, as of August 25, 1989, as of February 15, 1991, as of May 1, 1991, as of May 15, 1991, as of September 15, 1991, as of April 1, 1992, as of June 15, 1992, as of September 15, 1992, as of April 1, 1993, as of June 15, 1993 and as of September 15, 1993 respectively, which Indenture as so supplemented and to be hereby supplemented is hereinafter referred to as the "Indenture"; and Whereas, the Indenture provides for the issuance of bonds thereunder in one or more series, the form of each series of bonds and of the coupons to be attached to the coupon bonds, if any, to be substantially in the forms set forth therein with such insertions, omissions and variations as the Board of Directors of the Company may determine; and Whereas, the Company, by appropriate corporate action in conformity with the terms of the Indenture, has duly determined to create three new series of bonds under the Indenture, consisting of $50,000,000 in principal amount, to be designated as "First Mortgage Bonds Guarantee Series B of 1993 due 2029" (hereinafter sometimes referred to as the "bonds of Guarantee Series B"), $50,000,000 in principal amount, to be designated as "First Mortgage Bonds Guarantee Series C of 1993 due 2029" (hereinafter sometimes referred to as the "bonds of Guarantee Series C"), and $6,450,000 aggregate principal amount, to be designated as "First Mortgage Bonds Guarantee Series D of 1993 due 2029" (hereinafter sometimes referred to as the "bonds of Guarantee Series D"), the bonds of each such series are to bear interest at the rates of 5.95%, 5 5/8% and 5.95% per annum, respectively, are to mature May 15, 2029, November 15, 2029, and May 15, 2029, respectively, and are to be substantially in the following forms: (form of bond of Guarantee Series B) This Bond is not transferable except to a successor trustee under the Indenture, dated as of November 15, 1993, between the OHIO AIR QUALITY DEVELOPMENT AUTHORITY and SOCIETY NATIONAL BANK, as Trustee, or in connection with the exercise of the rights and remedies of the holder hereof consequent upon a "default" as defined in the Mortgage referred to herein. OHIO EDISON COMPANY First Mortgage Bond Guarantee Series B of 1993 Due 2029 Due May 15, 2029 $ No. Ohio Edison Company, a corporation of the State of Ohio (hereinafter called the Company), for value received, hereby promises to pay to or registered assigns, dollars at an office or agency of the Company in the Borough of Manhattan, The City of New York, N.Y. or in the City of Akron, Ohio, on May 15, 2029 in any coin or currency of the United States of America which at the time of payment is legal tender for public and private debts, and to pay at said offices or agencies to the registered owner hereof, in like coin or currency, interest thereon from the Initial Interest Accrual Date (hereinbelow defined) at the rate of five and ninety-five one hundredths per centum per annum. Payments of principal of and interest on this bond shall be made at an office or agency of the Company in the Borough of Manhattan, The City of New York, N. Y. or in the City of Akron, Ohio. The provisions of this bond are continued on the reverse hereof and such continued provisions shall for all purposes have the same effect as though fully set forth at this place. This bond shall not become obligatory until Bankers Trust Company, the Trustee under the Mortgage referred to on the reverse hereof, or its successor thereunder, shall have authenticated the form of certificate endorsed thereon. -2- In witness whereof, Ohio Edison Company has caused this bond to be signed in its name by its President or Vice President, by his signature or a facsimile thereof, and its corporate seal to be printed hereon, attested by its Secretary or an Assistant Secretary, by his signature or a facsimile thereof. Dated, , 1993 Ohio Edison Company, By____________________ Title: Attest: _________________________ Title: (form of trustee's authentication certificate) Trustee's Authentication Certificate This bond is one of the bonds of the series designated therein, described in the within-mentioned Mortgage. Bankers Trust Company, as Trustee, By_____________________ Authorized Officer -3- (form of bond of Guarantee Series B) (Reverse) OHIO EDISON COMPANY First Mortgage Bond Guarantee Series B of 1993 Due 2029 This bond is one of an issue of bonds of the Company, issuable in series, and is one of a series known as its First Mortgage Bonds of the series designated in its title, all issued and to be issued under and equally secured (except as to any sinking fund established in accordance with the provisions of the Mortgage hereinafter mentioned for the bonds of any particular series) by an Indenture of Mortgage and Deed of Trust, dated as of August 1, 1930, executed by the Company to Bankers Trust Company, as Trustee, as amended and supplemented by indentures supplemental thereto, to which Indenture as so amended and supplemented (herein referred to as the "Mortgage") reference is made for a description of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders of the bonds in respect thereof and the terms and conditions upon which the bonds are secured. The bonds of this series shall be redeemed in whole, by payment of the principal amount thereof plus accrued interest thereon, if any, to the date fixed for redemption, upon receipt by the Trustee of a written advice from the trustee under the Trust Indenture (the "Revenue Bond Indenture") dated as of November 15, 1993, between Ohio Air Quality Development Authority and Society National Bank, as trustee (such trustee and any successor trustee being hereinafter referred to as the "Revenue Bond Trustee"), securing $50,000,000 of Ohio Air Quality Development Authority State of Ohio Pollution Control Revenue Refunding Bonds, 1993 Series A (Ohio Edison Company Project), stating that the principal amount of all the pollution control revenue bonds then outstanding under the Revenue Bond Indenture has been declared due and payable pursuant to the provisions of Section 8.02 of the Revenue Bond Indenture, specifying the date of the accelerated maturity of such pollution control revenue bonds and the date from which interest on the pollution control revenue bonds issued under the Revenue Bond Indenture has then accrued, stating such declaration of maturity has not been annulled and demanding payment of the principal amount hereof plus accrued interest hereon to the date fixed for such redemption. As provided in the supplemental indenture establishing the terms and provisions of the bonds of this series, the date fixed for such redemption shall be not earlier than the date specified in the aforesaid written advice as the date of the accelerated maturity of the pollution control revenue bonds then outstanding under the Revenue Bond Indenture and not later than the 45th day after receipt by the Trustee of such advice, unless such 45th day is earlier than such date of accelerated maturity. The date fixed for such redemption shall be specified in a notice of redemption to be given not less than 30 days prior to the date so fixed for such redemption. Upon mailing of such notice of redemption, the date from which unpaid interest on the aforesaid pollution control revenue bonds has then accrued (as specified by the Revenue Bond Trustee) shall become the initial interest accrual date (the "Initial Interest Accrual Date") with respect to the bonds of this series, and the -4- date which is six months after the Initial Interest Accrual Date shall be the first interest payment date for the bonds of this series, provided, however, on any demand for payment of the principal amount hereof at maturity as a result of the principal of the aforesaid pollution control revenue bonds becoming due and payable on the maturity date of the bonds of this series, the date from which unpaid interest on the aforesaid pollution control revenue bonds has then accrued shall become the Initial Interest Accrual Date with respect to the bonds of this series, such date to be as stated in a written notice from the Revenue Bond Trustee to the Trustee. As provided in said supplemental indenture, the aforementioned notice of redemption shall become null and void for all purposes under said supplemental indenture and the Mortgage (including the fixing of the Initial Interest Accrual Date with respect to the bonds of this series) upon receipt by the Trustee of written notice from the Revenue Bond Trustee of the annulment of the acceleration of the maturity of the pollution control revenue bonds then outstanding under the Revenue Bond Indenture and of the rescission of the aforesaid written advice prior to the redemption date specified in such notice of redemption, and thereupon no redemption of the bonds of this series and no payment in respect thereof as specified in such notice of redemption shall be effected or required. But no such rescission shall extend to any subsequent written advice from the Revenue Bond Trustee or impair any right consequent on such subsequent written advice. Bonds of this series are not otherwise redeemable prior to their maturity. As more fully described in the supplemental indenture establishing the terms and provisions of the bonds of this series, the Company reserves the right, without any consent or other action by holders of the bonds of this series, to amend the Mortgage to provide (a) that the Mortgage, the rights and obligations of the Company and the rights of the bondholders may be modified with the consent of the holders of not less than 60% in principal amount of the bonds adversely affected; provided, however, that no modification shall (1) extend the time, or reduce the amount, of any payment on any bond, without the consent of the holder of each bond so affected, (2) permit the creation of any lien, not otherwise permitted, prior to or on a parity with the lien of the Mortgage, without the consent of the holders of all bonds then outstanding, or (3) reduce the above percentage of the principal amount of bonds the holders of which are required to approve any such modification without the consent of the holders of all bonds then outstanding and (b) that (i) additional bonds may be issued against 70% of the value of the property which forms the basis for such issuance and (ii) the charge against property subject to a prior lien which is used to effectuate the release of property under the Mortgage be similarly based. The principal hereof may be declared or may become due on the conditions, in the manner and at the time set forth in the Mortgage, upon the occurrence of a completed default as in the Mortgage provided. No recourse shall be had for the payment of the principal of or interest on this bond against any incorporator or any past, present or future subscriber to the capital stock, stockholder, officer or director of the Company or any predecessor or successor corporation, either directly or through the Company or any predecessor or successor corporation, under any rule of law, statute or constitution or by the enforcement of any assessment or otherwise, all such liability of incorporators, -5- subscribers, stockholders, officers and directors being released by the registered owner hereof by the acceptance of this bond and being likewise waived and released by the terms of the Mortgage. The bonds of this series are issuable only as registered bonds without coupons in denominations of $5,000 and authorized multiples thereof. Subject only to the restrictions contained in the Pledge Agreement dated as of November 15, 1993 between the Company and the Revenue Bond Trustee relating to bonds of this series, this bond is transferable as prescribed in the Mortgage by the registered owner hereof, in person or by attorney duly authorized, at an office or agency of the Company, in the Borough of Manhattan, The City of New York, N.Y. or in the City of Akron, Ohio, upon surrender and cancellation of this bond and thereupon a new registered bond or bonds of the same series for a like principal amount, in authorized denominations, will be issued to the transferee in exchange therefor, as provided in the Mortgage, and upon payment, if the Company shall require it, of the transfer charges therein prescribed. The Company and the Trustee may deem and treat the person in whose name this bond is registered as the absolute owner for the purpose of receiving payment of or on account of the principal and interest due hereon and for all other purposes. Registered bonds of this series shall be exchangeable at said offices or agencies of the Company for registered bonds of other authorized denominations having the same aggregate principal amount, in the manner and upon the conditions prescribed in the Mortgage. Notwithstanding any provision of the Mortgage, (a) neither the Company nor the Trustee shall be required to make transfers or exchanges of bonds of this series during the period between any interest payment date for such series and the record date next preceding such interest payment date, and (b) no charge shall be made upon any transfer or exchange of bonds of this series other than for any tax or taxes or other governmental charge required to be paid by the Company. (end of form of bond of Guarantee Series B) (form of bond of Guarantee Series C) This Bond is not transferable except to a successor trustee under the Indenture, dated as of November 15, 1993, between the OHIO AIR QUALITY DEVELOPMENT AUTHORITY and SOCIETY NATIONAL BANK, as Trustee, or in connection with the exercise of the rights and remedies of the holder hereof consequent upon a "default" as defined in the Mortgage referred to herein. OHIO EDISON COMPANY First Mortgage Bond Guarantee Series C of 1993 Due 2029 Due November 15, 2029 $ No. Ohio Edison Company, a corporation of the State of Ohio (hereinafter called the Company), for value received, hereby promises to pay to or registered assigns, -6- dollars at an office or agency of the Company in the Borough of Manhattan, The City of New York, N.Y. or in the City of Akron, Ohio, on November 15, 2029 in any coin or currency of the United States of America which at the time of payment is legal tender for public and private debts, and to pay at said offices or agencies to the registered owner hereof, in like coin or currency, interest thereon from the Initial Interest Accrual Date (hereinbelow defined) at the rate of five and five-eighths per centum per annum. Payments of principal of and interest on this bond shall be made at an office or agency of the Company in the Borough of Manhattan, The City of New York, N. Y. or in the City of Akron, Ohio. The provisions of this bond are continued on the reverse hereof and such continued provisions shall for all purposes have the same effect as though fully set forth at this place. This bond shall not become obligatory until Bankers Trust Company, the Trustee under the Mortgage referred to on the reverse hereof, or its successor thereunder, shall have authenticated the form of certificate endorsed thereon. In witness whereof, Ohio Edison Company has caused this bond to be signed in its name by its President or Vice President, by his signature or a facsimile thereof, and its corporate seal to be printed hereon, attested by its Secretary or an Assistant Secretary, by his signature or a facsimile thereof. Dated, , 1993 Ohio Edison Company, By____________________ Title: Attest: _________________________ Title: (form of trustee's authentication certificate) Trustee's Authentication Certificate This bond is one of the bonds of the series designated therein, described in the within-mentioned Mortgage. Bankers Trust Company, as Trustee, By___________________ Authorized Officer -7- (form of bond of Guarantee Series C) (Reverse) OHIO EDISON COMPANY First Mortgage Bond Guarantee Series C of 1993 Due 2029 This bond is one of an issue of bonds of the Company, issuable in series, and is one of a series known as its First Mortgage Bonds of the series designated in its title, all issued and to be issued under and equally secured (except as to any sinking fund established in accordance with the provisions of the Mortgage hereinafter mentioned for the bonds of any particular series) by an Indenture of Mortgage and Deed of Trust, dated as of August 1, 1930, executed by the Company to Bankers Trust Company, as Trustee, as amended and supplemented by indentures supplemental thereto, to which Indenture as so amended and supplemented (herein referred to as the "Mortgage") reference is made for a description of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders of the bonds in respect thereof and the terms and conditions upon which the bonds are secured. The bonds of this series shall be redeemed in whole, by payment of the principal amount thereof plus accrued interest thereon, if any, to the date fixed for redemption, upon receipt by the Trustee of a written advice from the trustee under the Trust Indenture (the "Revenue Bond Indenture") dated as of November 15, 1993, between Ohio Air Quality Development Authority and Society National Bank, as trustee (such trustee and any successor trustee being hereinafter referred to as the "Revenue Bond Trustee"), securing $50,000,000 of Ohio Air Quality Development Authority State of Ohio Pollution Control Revenue Refunding Bonds, 1993 Series B (Ohio Edison Company Project), stating that the principal amount of all the pollution control revenue bonds then outstanding under the Revenue Bond Indenture has been declared due and payable pursuant to the provisions of Section 8.02 of the Revenue Bond Indenture, specifying the date of the accelerated maturity of such pollution control revenue bonds and the date from which interest on the pollution control revenue bonds issued under the Revenue Bond Indenture has then accrued, stating such declaration of maturity has not been annulled and demanding payment of the principal amount hereof plus accrued interest hereon to the date fixed for such redemption. As provided in the supplemental indenture establishing the terms and provisions of the bonds of this series, the date fixed for such redemption shall be not earlier than the date specified in the aforesaid written advice as the date of the accelerated maturity of the pollution control revenue bonds then outstanding under the Revenue Bond Indenture and not later than the 45th day after receipt by the Trustee of such advice, unless such 45th day is earlier than such date of accelerated maturity. The date fixed for such redemption shall be specified in a notice of redemption to be given not less than 30 days prior to the date so fixed for such redemption. Upon mailing of such notice of redemption, the date from which unpaid interest on the aforesaid pollution control revenue bonds has then accrued (as specified by the Revenue Bond Trustee) shall become the initial interest accrual date (the "Initial Interest Accrual Date") with respect to the bonds of this series, and the -8- date which is six months after the Initial Interest Accrual Date shall be the first interest payment date for the bonds of this series, provided, however, on any demand for payment of the principal amount hereof at maturity as a result of the principal of the aforesaid pollution control revenue bonds becoming due and payable on the maturity date of the bonds of this series, the date from which unpaid interest on the aforesaid pollution control revenue bonds has then accrued shall become the Initial Interest Accrual Date with respect to the bonds of this series, such date to be as stated in a written notice from the Revenue Bond Trustee to the Trustee. As provided in said supplemental indenture, the aforementioned notice of redemption shall become null and void for all purposes under said supplemental indenture and the Mortgage (including the fixing of the Initial Interest Accrual Date with respect to the bonds of this series) upon receipt by the Trustee of written notice from the Revenue Bond Trustee of the annulment of the acceleration of the maturity of the pollution control revenue bonds then outstanding under the Revenue Bond Indenture and of the rescission of the aforesaid written advice prior to the redemption date specified in such notice of redemption, and thereupon no redemption of the bonds of this series and no payment in respect thereof as specified in such notice of redemption shall be effected or required. But no such rescission shall extend to any subsequent written advice from the Revenue Bond Trustee or impair any right consequent on such subsequent written advice. Bonds of this series are not otherwise redeemable prior to their maturity. As more fully described in the supplemental indenture establishing the terms and provisions of the bonds of this series, the Company reserves the right, without any consent or other action by holders of the bonds of this series, to amend the Mortgage to provide (a) that the Mortgage, the rights and obligations of the Company and the rights of the bondholders may be modified with the consent of the holders of not less than 60% in principal amount of the bonds adversely affected; provided, however, that no modification shall (1) extend the time, or reduce the amount, of any payment on any bond, without the consent of the holder of each bond so affected, (2) permit the creation of any lien, not otherwise permitted, prior to or on a parity with the lien of the Mortgage, without the consent of the holders of all bonds then outstanding, or (3) reduce the above percentage of the principal amount of bonds the holders of which are required to approve any such modification without the consent of the holders of all bonds then outstanding and (b) that (i) additional bonds may be issued against 70% of the value of the property which forms the basis for such issuance and (ii) the charge against property subject to a prior lien which is used to effectuate the release of property under the Mortgage be similarly based. The principal hereof may be declared or may become due on the conditions, in the manner and at the time set forth in the Mortgage, upon the occurrence of a completed default as in the Mortgage provided. No recourse shall be had for the payment of the principal of or interest on this bond against any incorporator or any past, present or future subscriber to the capital stock, stockholder, officer or director of the Company or any predecessor or successor corporation, either directly or through the Company or any predecessor or successor corporation, under any rule of law, statute or constitution or by the enforcement of any assessment or otherwise, all such liability of incorporators, subscribers, stockholders, officers and directors being released -9- by the registered owner hereof by the acceptance of this bond and being likewise waived and released by the terms of the Mortgage. The bonds of this series are issuable only as registered bonds without coupons in denominations of $5,000 and authorized multiples thereof. Subject only to the restrictions contained in the Pledge Agreement dated as of November 15, 1993 between the Company and the Revenue Bond Trustee relating to bonds of this series, this bond is transferable as prescribed in the Mortgage by the registered owner hereof, in person or by attorney duly authorized, at an office or agency of the Company, in the Borough of Manhattan, The City of New York, N.Y. or in the City of Akron, Ohio, upon surrender and cancellation of this bond and thereupon a new registered bond or bonds of the same series for a like principal amount, in authorized denominations, will be issued to the transferee in exchange therefor, as provided in the Mortgage, and upon payment, if the Company shall require it, of the transfer charges therein prescribed. The Company and the Trustee may deem and treat the person in whose name this bond is registered as the absolute owner for the purpose of receiving payment of or on account of the principal and interest due hereon and for all other purposes. Registered bonds of this series shall be exchangeable at said offices or agencies of the Company for registered bonds of other authorized denominations having the same aggregate principal amount, in the manner and upon the conditions prescribed in the Mortgage. Notwithstanding any provision of the Mortgage, (a) neither the Company nor the Trustee shall be required to make transfers or exchanges of bonds of this series during the period between any interest payment date for such series and the record date next preceding such interest payment date, and (b) no charge shall be made upon any transfer or exchange of bonds of this series other than for any tax or taxes or other governmental charge required to be paid by the Company. (end of form of bond of Guarantee Series C) (form of bond of Guarantee Series D) This Bond is not transferable except to a successor trustee under the Indenture, dated as of November 15, 1993, between the OHIO WATER DEVELOPMENT AUTHORITY and SOCIETY NATIONAL BANK, as Trustee, or in connection with the exercise of the rights and remedies of the holder hereof consequent upon a "default" as defined in the Mortgage referred to herein. OHIO EDISON COMPANY First Mortgage Bond Guarantee Series D of 1993 Due 2029 Due May 15, 2029 $ No. Ohio Edison Company, a corporation of the State of Ohio (hereinafter called the Company), for value received, hereby promises to pay to or registered assigns, dollars at an office or -10- agency of the Company in the Borough of Manhattan, The City of New York, N.Y. or in the City of Akron, Ohio, on May 15, 2029 in any coin or currency of the United States of America which at the time of payment is legal tender for public and private debts, and to pay at said offices or agencies to the registered owner hereof, in like coin or currency, interest thereon from the Initial Interest Accrual Date (hereinbelow defined) at the rate of five and ninety-five one hundredths per centum per annum. Payments of principal of and interest on this bond shall be made at an office or agency of the Company in the Borough of Manhattan, The City of New York, N. Y. or in the City of Akron, Ohio. The provisions of this bond are continued on the reverse hereof and such continued provisions shall for all purposes have the same effect as though fully set forth at this place. This bond shall not become obligatory until Bankers Trust Company, the Trustee under the Mortgage referred to on the reverse hereof, or its successor thereunder, shall have authenticated the form of certificate endorsed thereon. In witness whereof, Ohio Edison Company has caused this bond to be signed in its name by its President or Vice President, by his signature or a facsimile thereof, and its corporate seal to be printed hereon, attested by its Secretary or an Assistant Secretary, by his signature or a facsimile thereof. Dated, , 1993 Ohio Edison Company, By____________________ Title: Attest: _________________________ Title: (form of trustee's authentication certificate) Trustee's Authentication Certificate This bond is one of the bonds of the series designated therein, described in the within-mentioned Mortgage. Bankers Trust Company, as Trustee, By_____________________ Authorized Officer -11- (form of bond of Guarantee Series D) (Reverse) OHIO EDISON COMPANY First Mortgage Bond Guarantee Series D of 1993 Due 2029 This bond is one of an issue of bonds of the Company, issuable in series, and is one of a series known as its First Mortgage Bonds of the series designated in its title, all issued and to be issued under and equally secured (except as to any sinking fund established in accordance with the provisions of the Mortgage hereinafter mentioned for the bonds of any particular series) by an Indenture of Mortgage and Deed of Trust, dated as of August 1, 1930, executed by the Company to Bankers Trust Company, as Trustee, as amended and supplemented by indentures supplemental thereto, to which Indenture as so amended and supplemented (herein referred to as the "Mortgage") reference is made for a description of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders of the bonds in respect thereof and the terms and conditions upon which the bonds are secured. The bonds of this series shall be redeemed in whole, by payment of the principal amount thereof plus accrued interest thereon, if any, to the date fixed for redemption, upon receipt by the Trustee of a written advice from the trustee under the Trust Indenture (the "Revenue Bond Indenture") dated as of November 15, 1993, between Ohio Water Development Authority and Society National Bank, as trustee (such trustee and any successor trustee being hereinafter referred to as the "Revenue Bond Trustee"), securing $6,450,000 of Ohio Water Development Authority State of Ohio Pollution Control Revenue Refunding Bonds, 1993 Series (Ohio Edison Company Project), stating that the principal amount of all the pollution control revenue bonds then outstanding under the Revenue Bond Indenture has been declared due and payable pursuant to the provisions of Section 8.02 of the Revenue Bond Indenture, specifying the date of the accelerated maturity of such pollution control revenue bonds and the date from which interest on the pollution control revenue bonds issued under the Revenue Bond Indenture has then accrued, stating such declaration of maturity has not been annulled and demanding payment of the principal amount hereof plus accrued interest hereon to the date fixed for such redemption. As provided in the supplemental indenture establishing the terms and provisions of the bonds of this series, the date fixed for such redemption shall be not earlier than the date specified in the aforesaid written advice as the date of the accelerated maturity of the pollution control revenue bonds then outstanding under the Revenue Bond Indenture and not later than the 45th day after receipt by the Trustee of such advice, unless such 45th day is earlier than such date of accelerated maturity. The date fixed for such redemption shall be specified in a notice of redemption to be given not less than 30 days prior to the date so fixed for such redemption. Upon mailing of such notice of redemption, the date from which unpaid interest on the aforesaid pollution control revenue bonds has then accrued (as specified by the Revenue Bond Trustee) shall become the initial interest accrual date (the "Initial Interest Accrual Date") with respect to the bonds of this series, and the date which is six months after the -12- Initial Interest Accrual Date shall be the first interest payment date for the bonds of this series, provided, however, on any demand for payment of the principal amount hereof at maturity as a result of the principal of the aforesaid pollution control revenue bonds becoming due and payable on the maturity date of the bonds of this series, the date from which unpaid interest on the aforesaid pollution control revenue bonds has then accrued shall become the Initial Interest Accrual Date with respect to the bonds of this series, such date to be as stated in a written notice from the Revenue Bond Trustee to the Trustee. As provided in said supplemental indenture, the aforementioned notice of redemption shall become null and void for all purposes under said supplemental indenture and the Mortgage (including the fixing of the Initial Interest Accrual Date with respect to the bonds of this series) upon receipt by the Trustee of written notice from the Revenue Bond Trustee of the annulment of the acceleration of the maturity of the pollution control revenue bonds then outstanding under the Revenue Bond Indenture and of the rescission of the aforesaid written advice prior to the redemption date specified in such notice of redemption, and thereupon no redemption of the bonds of this series and no payment in respect thereof as specified in such notice of redemption shall be effected or required. But no such rescission shall extend to any subsequent written advice from the Revenue Bond Trustee or impair any right consequent on such subsequent written advice. Bonds of this series are not otherwise redeemable prior to their maturity. As more fully described in the supplemental indenture establishing the terms and provisions of the bonds of this series, the Company reserves the right, without any consent or other action by holders of the bonds of this series, to amend the Mortgage to provide (a) that the Mortgage, the rights and obligations of the Company and the rights of the bondholders may be modified with the consent of the holders of not less than 60% in principal amount of the bonds adversely affected; provided, however, that no modification shall (1) extend the time, or reduce the amount, of any payment on any bond, without the consent of the holder of each bond so affected, (2) permit the creation of any lien, not otherwise permitted, prior to or on a parity with the lien of the Mortgage, without the consent of the holders of all bonds then outstanding, or (3) reduce the above percentage of the principal amount of bonds the holders of which are required to approve any such modification without the consent of the holders of all bonds then outstanding and (b) that (i) additional bonds may be issued against 70% of the value of the property which forms the basis for such issuance and (ii) the charge against property subject to a prior lien which is used to effectuate the release of property under the Mortgage be similarly based. The principal hereof may be declared or may become due on the conditions, in the manner and at the time set forth in the Mortgage, upon the occurrence of a completed default as in the Mortgage provided. No recourse shall be had for the payment of the principal of or interest on this bond against any incorporator or any past, present or future subscriber to the capital stock, stockholder, officer or director of the Company or any predecessor or successor corporation, either directly or through the Company or any predecessor or successor corporation, under any rule of law, statute or constitution or by the enforcement of any assessment or otherwise, all such liability of incorporators, -13- subscribers, stockholders, officers and directors being released by the registered owner hereof by the acceptance of this bond and being likewise waived and released by the terms of the Mortgage. The bonds of this series are issuable only as registered bonds without coupons in denominations of $5,000 and authorized multiples thereof. Subject only to the restrictions contained in the Pledge Agreement dated as of November 15, 1993 between the Company and the Revenue Bond Trustee relating to bonds of this series, this bond is transferable as prescribed in the Mortgage by the registered owner hereof, in person or by attorney duly authorized, at an office or agency of the Company, in the Borough of Manhattan, The City of New York, N.Y. or in the City of Akron, Ohio, upon surrender and cancellation of this bond and thereupon a new registered bond or bonds of the same series for a like principal amount, in authorized denominations, will be issued to the transferee in exchange therefor, as provided in the Mortgage, and upon payment, if the Company shall require it, of the transfer charges therein prescribed. The Company and the Trustee may deem and treat the person in whose name this bond is registered as the absolute owner for the purpose of receiving payment of or on account of the principal and interest due hereon and for all other purposes. Registered bonds of this series shall be exchangeable at said offices or agencies of the Company for registered bonds of other authorized denominations having the same aggregate principal amount, in the manner and upon the conditions prescribed in the Mortgage. Notwithstanding any provision of the Mortgage, (a) neither the Company nor the Trustee shall be required to make transfers or exchanges of bonds of this series during the period between any interest payment date for such series and the record date next preceding such interest payment date, and (b) no charge shall be made upon any transfer or exchange of bonds of this series other than for any tax or taxes or other governmental charge required to be paid by the Company. (end of form of bond Guarantee Series D) and Whereas, Section 115 of the Indenture provides that the Company and the Trustee may, from time to time and at any time, enter into such indentures supplemental thereto as shall be deemed necessary or desirable for one or more purposes, including, among others, to describe and set forth the particular terms and the form of additional series of bonds to be issued under the Indenture, to add other limitations on the issue of bonds, withdrawal of cash or release of property, to add to the covenants and agreements of the Company for the protection of the holders of the bonds and of the mortgaged and pledged property, to supplement defective or inconsistent provisions contained in the Indenture, and for any other purpose not inconsistent with the terms of the Indenture; and Whereas, all things necessary to make the bonds of Guarantee Series B, the bonds of Guarantee Series C and the bonds of Guarantee Series D (collectively, hereinafter sometimes referred to as the "bonds of the Guarantee Series") when authenticated by the Trustee and issued as in the Indenture provided, the valid, binding and legal obligations of the Company, entitled in all respects to the security of the Indenture, have been done and performed, and the creation, execution and delivery of this Supplemental Indenture have in all respects been duly authorized; and -14- Whereas, the Company and Trustee deem it advisable to enter into this Supplemental Indenture for the purposes of describing the bonds of the Guarantee Series and of establishing the terms and provisions thereof, confirming the mortgaging under the Indenture of additional property for the equal and proportionate benefit and security of the holders of all bonds at any time issued thereunder, amplifying the description of the property mortgaged, adding other limitations to the Indenture on the issue of bonds, withdrawal of cash or release of property, and adding to the covenants and agreements of the Company for the protection of the holders of bonds and of mortgaged and pledged property; Now, therefore, this supplemental indenture witnesseth: That Ohio Edison Company, in consideration of the premises and of one dollar to it duly paid by the Trustee at or before the ensealing and delivery of these presents, the receipt whereof is hereby acknowledged, and of the purchase and acceptance of the bonds issued or to be issued hereunder by the holders thereof, and in order to secure the payment both of the principal and interest of all bonds at any time issued and outstanding under the Indenture, according to their tenor and effect, and the performance of all the provisions of the Indenture and of said bonds, hath granted, bargained, sold, released, conveyed, assigned, transferred, pledged, set over and confirmed and by these presents doth grant, bargain, sell, release, convey, assign, transfer, pledge, set over and confirm unto Bankers Trust Company, as Trustee, and to its successor or successors in said trust, and to its and their assigns forever, all the properties of the Company described in Schedule A (which is identified by the signature of an officer of each party hereto at the end thereof) hereto annexed and hereby made a part hereof; Together with all and singular the tenements, hereditaments and appurtenances belonging or in any wise appertaining to the aforesaid property or any part thereof, with the reversion and reversions, remainder and remainders and (subject to the provisions of Article XI of the Indenture) the tolls, rents, revenues, issues, earnings, income, product and profits thereof, and all the estate, right, title and interest and claim whatsoever, at law as well as in equity, which the Company now has or may hereafter acquire in and to the aforesaid property and franchises and every part and parcel thereof. The Company does hereby agree and does hereby confirm and reaffirm the agreement made by it in the Indenture, dated as of August 1, 1930, that all the property, rights and franchises acquired by the Company after the date of the Indenture, dated as of August 1, 1930 (except any hereinafter expressly excepted), shall be as fully embraced within the lien of the Indenture as if such property had been owned by the Company on the date of the Indenture, dated as of August 1, 1930 and was specifically described therein and conveyed thereby and does hereby confirm that the Company will not cause or consent to a partition, whether voluntary or through legal proceedings, of property, whether herein described or heretofore or hereafter acquired, in which its ownership shall be as a tenant in common except as permitted by and in conformity with the provisions of the Indenture and particularly of Article XI thereof. Provided that the following are not and are not intended to be now or hereafter granted, bargained, sold, released, conveyed, assigned, transferred, mortgaged, pledged, set over or confirmed hereunder and are hereby expressly excepted from the lien and operation of the Indenture, viz.: cash, shares -15- of stock and obligations (including bonds, notes and other securities) not heretofore or hereafter specifically pledged, paid or deposited or delivered under the Indenture or covenanted so to be. To have and to hold all such properties, real, personal and mixed, mortgaged, pledged or conveyed by the Company as aforesaid, or intended so to be, unto the Trustee and its successors and assigns forever. In trust, nevertheless, upon the terms and trusts of the Indenture for those who shall hold the bonds and coupons issued and to be issued thereunder, or any of them, without preference, priority or distinction as to lien of any of said bonds and coupons over any others thereof by reason of priority in the time of the issue or negotiations thereof, or otherwise howsoever, subject, however, to the provisions in reference to extended, transferred or pledged coupons and claims for interest set forth in the Indenture (and subject to any sinking funds that may be hereafter created for the benefit of any particular series). Provided, however, and these presents are upon the condition that if the Company, its successors or assigns, shall pay or cause to be paid, the principal of and interest on said bonds, at the times and in the manner stipulated therein and herein, and shall keep, perform and observe all and singular the covenants and promises in said bonds and in the Indenture expressed to be kept, performed and observed by or on the part of the Company, then this Supplemental Indenture and the estate and rights hereby granted shall cease, determine and be void, otherwise to be and remain in full force and effect. It is hereby covenanted, declared and agreed, by the Company, that all such bonds and coupons are to be issued, authenticated and delivered, and that all property subject or to become subject hereto is to be held, subject to the further covenants, conditions, uses and trusts in the Indenture set forth, and the parties hereto mutually agree as follows: Section 1. Bonds of Guarantee Series B shall mature on May 15, 2029, bonds of Guarantee Series C shall mature on November 15, 2029, and bonds of Guarantee Series D shall mature on May 15, 2029, and shall be designated as the Company's "First Mortgage Bonds Guarantee Series B of 1993 due 2029," "First Mortgage Bonds Guarantee Series C of 1993 due 2029," and "First Mortgage Bonds Guarantee Series D of 1993 due 2029," respectively. The bonds of Guarantee Series B, Guarantee Series C and Guarantee Series D shall bear interest from their respective Initial Interest Accrual Dates (as defined in the forms of the bonds of the Guarantee Series hereinabove set forth) at the rates of five and ninety-five one hundredths per centum per annum, five and five-eighths per centum per annum and five and ninety-five one hundredths per centum per annum, respectively. Principal or redemption price of and interest on the bonds of the Guarantee Series shall be payable in any coin or currency of the United States of America which at the time of payment is legal tender for public and private debts, at an office or agency of the Company in the Borough of Manhattan, The City of New York, N.Y. or in the City of Akron, Ohio. Definitive bonds of the Guarantee Series may be issued, originally or otherwise, only as registered bonds, substantially in the respective forms of bond hereinbefore recited, and in the denominations of $5,000 and authorized multiples thereof. -16- Delivery of a bond of the Guarantee Series to the Trustee for authentication shall be conclusive evidence that its serial number has been duly approved by the Company. The bonds of the respective Guarantee Series shall be redeemable pursuant to the requirements of this Sixty-fourth Supplemental Indenture in whole, prior to maturity, upon notice given by mailing the same, postage pre-paid, at least thirty days and not more than forty-five days prior to the date fixed for redemption to each registered holder of a bond to be redeemed at the last address of such holder appearing on the registry books. The Trustee shall within five business days of receiving the written advice specified in the applicable form of bond of the Guarantee Series provided for herein mail a copy thereof to the Company stamped or otherwise marked to indicate the date of receipt by the Trustee. The Company shall fix a redemption date for the redemption so demanded and shall mail to the Trustee notice of such date at least 35 days prior thereto. Subject to the foregoing sentence, the redemption date so fixed may be any day not earlier than the date specified in the aforesaid written advice as the date of the accelerated maturity of the pollution control revenue bonds then outstanding under the related Revenue Bond Indenture and not later than the 45th day after receipt by the Trustee of such advice, unless such 45th day is earlier than such date of accelerated maturity. If the Trustee does not receive such notice from the Company within 13 days after receipt by the Trustee of the aforesaid written advice, the redemption date shall be deemed fixed as the 45th day after such receipt. The Trustee shall mail notice of the redemption date to the Revenue Bond Trustee not less than 30 days prior to such redemption date, provided, however, that the Trustee shall mail no such notice (and no redemption shall be made) if prior to the mailing of such notice the Trustee shall have received written notice from the Revenue Bond Trustee of the annulment of the acceleration of the maturity of the pollution control revenue bonds then outstanding under the related Revenue Bond Indenture and of the rescission of the aforesaid written advice. The terms "Revenue Bond Trustee" and "Revenue Bond Indenture" shall have the meanings specified in the forms of bonds of the Guarantee Series provided for herein. Redemption of the bonds of the Guarantee Series shall be at the principal amount thereof, plus accrued interest thereon to the date fixed for redemption and such amount shall become due and payable on the date fixed for such redemption. Anything in this paragraph contained to the contrary notwithstanding, if, after mailing notice of the date fixed for redemption but prior to such date, the Trustee shall have been advised in writing by the Revenue Bond Trustee that the acceleration of the maturity of the pollution control revenue bonds then outstanding under the related Revenue Bond Indenture has been annulled and that the aforesaid written advice has been rescinded, the aforesaid written advice shall thereupon, without further act of the Trustee or the Company, be rescinded and become null and void for all purposes hereunder (including the fixing of the Initial Interest Accrual Dates as provided in the forms of the bonds of the Guarantee Series provided for herein) and no redemption of the bonds of the Guarantee Series and no payments in respect thereof as specified in the aforesaid written notice shall be effected or required. But no such rescission shall extend to any subsequent written advice from the related Revenue Bond Trustee or impair any right consequent on such subsequent written advice. Section 2. Bonds of the Guarantee Series shall be deemed to be paid and no longer outstanding under the Indenture to the extent that pollution control revenue bonds which are -17- outstanding from time to time under the related Revenue Bond Indenture are paid or deemed to be paid and are no longer outstanding and the Trustee has been notified to such effect by the Company. Section 3. Subject to the terms of the respective Pledge Agreements each dated as of November 15, 1993 between the Company and the respective Revenue Bond Trustee relating to the bonds of the Guarantee Series, bonds of the respective Guarantee Series may be transferred by the registered owners thereof, in person or by attorney duly authorized, at an office or agency of the Company in the Borough of Manhattan, The City of New York, N. Y. or in the City of Akron, Ohio but only in the manner and upon the conditions prescribed in the Indenture and in the respective form of the bonds of such series hereinbefore recited. Bonds of the respective Guarantee Series shall be exchangeable for other registered bonds of the same series, in the manner and upon the conditions prescribed in the Indenture, and in the forms of bonds of such series hereinbefore recited, upon the surrender of such bonds at said offices or agencies of the Company. However, notwithstanding the provisions of Section 14 or 15 of the Indenture, no charge shall be made upon any transfer or exchange of bonds of said series other than for any tax or taxes or other governmental charge required to be paid by the Company. Section 4. The Company reserves the right, without any consent or other action by holders of the bonds of the Guarantee Series, or any subsequent series of bonds, to amend the Indenture by inserting the following language as Section 115A immediately following current Section 115 of the Indenture: With the consent of the holders of not less than sixty per centum (60%) in principal amount of the bonds at the time outstanding or their attorneys-in-fact duly authorized, or, if the rights of the holders of one or more, but not all, series then outstanding are affected, the consent of the holders of not less than sixty per centum (60%) in aggregate principal amount of the bonds at the time outstanding of all affected series, taken together, and not any other series, the Company, when authorized by a resolution, and the Trustee may from time to time and at any time enter into an indenture or indentures supplemental hereto for the purpose of adding any provisions to or changing in any manner or eliminating any of the provisions of this Indenture or of any supplemental indenture or modifying the rights and obligations of the Company and the rights of the holders of any of the bonds and coupons; provided, however, that no such supplemental indenture shall (1) extend the maturity of any of the bonds or reduce the rate or extend the time of payment of interest thereon, or reduce the amount of the principal thereof, or reduce any premium, payable on the redemption thereof or change the coin or currency in which any bond or interest thereon is payable, without the consent of the holder of each bond so affected, or (2) permit the creation of any lien, not otherwise permitted, prior to or on a parity with the lien of this Indenture, without the consent of the holders of all of the bonds then outstanding, or (3) reduce the aforesaid percentage of the principal amount of bonds the holders of which are required to approve any such supplemental indenture, without the consent of the holders of all the bonds then outstanding. For the purposes of this Section, -18- bonds shall be deemed to be affected by a supplemental indenture if such supplemental indenture adversely affects or diminishes the right of holders thereof against the Company or against its property. Upon the written request of the Company, accompanied by a resolution authorizing the execution of any such supplemental indenture, and upon the filing with the Trustee of evidence of the consent of bondholders as aforesaid (the instrument or instruments evidencing such consent to be dated within one year of such request), the Trustee shall join with the Company in the execution of such supplemental indenture unless such supplemental indenture affects the Trustee's own rights, duties or immunities under this Indenture or otherwise, in which case the Trustee may in its discretion but shall not be obligated to enter into such supplemental indenture. The Trustee shall be entitled to receive and, subject to Section 102 of the Indenture and Article Five of the Seventh Supplemental Indenture, may rely upon an opinion of counsel as conclusive evidence that any such supplemental indenture is authorized or permitted by the provisions of this Section. It shall not be necessary for the consent of the bondholders under this Section to approve the particular form of any proposed supplemental indenture, but it shall be sufficient if such consent shall approve the substance thereof. The Company and the Trustee, if they so elect, and either before or after such 60% or greater consent has been obtained, may require the holder of any bond consenting to the execution of any such supplemental indenture to submit his bond to the Trustee or to such bank, banker or trust company as may be designated by the Trustee for the purpose, for the notation thereon of the fact that the holder of such bond has consented to the execution of such supplemental indenture, and in such case such notation, in form satisfactory to the Trustee, shall be made upon all bonds so submitted, and such bonds bearing such notation shall forthwith be returned to the persons entitled thereto. All subsequent holders of bonds bearing such notation shall be deemed to have consented to the execution of such supplemental indenture, and consent, once given or deemed to be given, may not be withdrawn. Prior to the execution by the Company and the Trustee of any supplemental indenture pursuant to the provisions of this Section, the Company shall publish a notice, setting forth in general terms the substance of such supplemental indenture, at least once in one daily newspaper of general circulation in each city in which the principal of any of the bonds shall be payable, or, if all bonds outstanding shall be registered bonds without coupons or coupon bonds registered as to principal, such notice shall be sufficiently given if mailed, first class, postage prepaid, and registered if the Company so elects, to each registered holder of bonds at the last address of such holder appearing on the registry books, such publication or mailing, as the case may be, to be made not less than thirty days prior to such execution. Any failure of the Company to give such notice, or any defect therein, shall not, however, in any way impair or affect the validity of any such supplemental indenture. -19- Section 5. The Company reserves the right, without any consent or other action by the holders of the bonds of the Guarantee Series, or any subsequent series of bonds, to amend the Indenture by deleting the phrase "sixty per centum (60%)" in Section 28 of the Indenture and substituting therefor the phrase "seventy per centum (70%)" and by deleting the phrase "One hundred sixty-six and two-thirds per cent. (166 2/3%)" in Sections 65 and 67 of the Indenture and substituting therefor the phrase "One hundred and forty-two and eighty-six hundredths per cent. (142.86%)". Section 6. Except as herein otherwise expressly provided, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this Supplemental Indenture; the Trustee shall not be responsible for the recitals herein or in the bonds (except the Trustee's authentication certificate), all of which are made by the Company solely; and this Supplemental Indenture is executed and accepted by the Trustee, subject to all the terms and conditions set forth in the Indenture, as fully to all intents and purposes as if the terms and conditions of the Indenture were herein set forth at length. Section 7. As supplemented by this Supplemental Indenture, the Indenture is in all respects ratified and confirmed, and the Indenture as herein defined, and this Supplemental Indenture, shall be read, taken and construed as one and the same instrument. Section 8. Nothing in this Supplemental Indenture contained shall or shall be construed to confer upon any person other than a holder of bonds issued under the Indenture, the Company and the Trustee any right or interest to avail himself of any benefit under any provision of the Indenture or of this Supplemental Indenture. Section 9. This Supplemental Indenture may be simultaneously executed in several counterparts and all such counterparts executed and delivered, each as an original, shall constitute but one and the same instrument. In witness whereof, Ohio Edison Company, party of the first part hereto, and Bankers Trust Company, party of the second part hereto, have caused these presents to be executed in their respective names by their respective Presidents or one of their Vice Presidents or Assistant Vice Presidents and their respective seals to be hereunto affixed and attested by their respective Secretaries or one of their Assistant Secretaries or Assistant Treasurers, all as of the day and year first above written. -20- Ohio Edison Company (Seal) By: D. L. Yeager ---------------------- Title: Vice President Attest: Nancy C. Brink --------------------------- Title: Assistant Secretary Signed, Sealed and Acknowledged on behalf of Ohio Edison Company in the presence of: Cynthia A. Kippes - ----------------------------------------------- Carol L. Daniels - ----------------------------------------------- Bankers Trust Company (Seal) By: Robert Caporale ---------------------- Title: Vice President Attest: M. Lisa Morrone ---------------------------- Title: Assistant Treasurer Signed, Sealed and Acknowledged on behalf of Bankers Trust Company in the presence of: Daniel M. Weber, Jr. - ----------------------------------------------- Scott Thiel - ----------------------------------------------- -21- State of Ohio) : ss.: County of Summit ) On the 23 day of November, 1993, personally appeared before me, a Notary Public in and for the said County and State aforesaid, D. L. Yeager and Nancy C. Brink, to me known and known to me to be a Vice President and an Assistant Secretary, respectively, of Ohio Edison Company, the corporation which executed the foregoing instrument, and who severally acknowledged that they did sign and seal such instrument as such Vice President and Assistant Secretary, respectively, of Ohio Edison Company, the same is their free act and deed and the free and corporate act and deed of said corporation. In witness whereof, I have hereunto set my hand and seal the 23 day of November, 1993. Tracy A. Bendel ----------------------------------- Tracy A. Bendel, Notary Public State of Ohio My Commission Expires June 26, 1997 (Seal) State of Ohio) : ss.: County of Summit ) On the 23 day of November, 1993, before me personally came D. L. Yeager, to me known, who, being by me duly sworn, did depose and say that he resides at 2878 Lakeland Parkway, Silver Lake, Ohio 44224; that he is a Vice President of Ohio Edison Company, one of the corporations described in and which executed the above instrument; that he knows the seal of said corporation; that the seal affixed to said instrument is such corporate seal; that it was so affixed by order of the Board of Directors of said corporation, and that he signed his name thereto by like order. Tracy A. Bendel ----------------------------------- Tracy A. Bendel, Notary Public State of Ohio My Commission Expires June 26, 1997 (Seal) -22- State of New York) : ss.: County of New York) On the 22nd day of November, 1993, personally appeared before me, a Notary Public in and for the said County and State aforesaid, Robert Caporale and M. Lisa Morrone, to me known and known to me to be a Vice President and Assistant Treasurer, respectively, of Bankers Trust Company, the corporation which executed the foregoing instrument, and who severally acknowledged that they did sign and seal such instrument as such Vice President and Assistant Treasurer for and on behalf of said corporation and that the same is their free act and deed and the free and corporate act and deed of said corporation. In witness whereof, I have hereunto set my hand and seal the 22nd day of November, 1993. Sharon V. Alston ---------------------------------- SHARON V. ALSTON Notary Public, State of New York No. 31-4966275 Qualified in New York County My Commission Expires May 7, 1994 (Seal) State of New York) : ss.: County of New York) On the 22nd day of November, 1993, before me personally came Robert Caporale, to me known, who, being by me duly sworn, did depose and say that he resides at 25 Lake Street, White Plains, New York 10603; that he is a Vice President of Bankers Trust Company, one of the parties described in and which executed the above instrument; that she knows the seal of said corporation; that the seal affixed to said instrument is such corporate seal; that it was so affixed by order of the Board of Directors of said corporation, and that she signed her name thereto by like authority. Sharon V. Alston ----------------------------------- SHARON V. ALSTON Notary Public, State of New York No. 31-4966275 Qualified in New York County My Commission Expires May 7, 1994 (Seal) -23- Bankers Trust Company hereby certifies that its precise name and address as Trustee hereunder are: Bankers Trust Company Four Albany Street Borough of Manhattan City, County and State of New York 10015 Bankers Trust Company By: Robert Caporale ---------------------- Title: Vice President -24- SCHEDULE A Detailed Description of Additional Properties A. ELECTRIC TRANSMISSION LINES The following electric transmission lines of the Company, including the towers, poles, pole lines, wire, switch racks, insulators and other appurtenances, and equipment owned by the Company, and all other property of the Company, with all the Company's rights of way, easements, permits, privileges and consents, licenses and rights over or relating to the construction, maintenance or operation thereof, through, over, under or upon any public streets or highways or other lands, public or private: Bay Division 1. A. Schulman Inc. Tap: Single circuit wood pole construction extending from Structure #14 on the existing Bellevue-Carriage line southerly, easterly, southerly, and westerly to A. Schulman Inc. Substation, a distance of 0.39 mile, all being located in the City of Bellevue, Huron County, Ohio. Nancy C. Brink ----------------------------------- Nancy C. Brink, Assistant Secretary Ohio Edison Company Robert Caporale ------------------------------- Robert Caporale, Vice President Bankers Trust Company A-1 EX-10 3 OE10K 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 TABLE OF CONTENTS Page No. -------- Article 1 -- Purpose of Agreement 1 Article 2 -- Definitions 2 Article 3 -- Operating Committee 5 Article 4 -- Operating Conditions 7 4.01 Parallel Operation 7 4.02 Frequency 7 4.03 Megavars 8 4.04 Unscheduled Energy 8 4.05 Transmission Operation 8 4.06 Coordinated Maintenance 9 4.07 Unit Availability 9 4.08 Utilization of CAPCO Units 10 Article 5 -- Coordinated Maintenance and CAPCO Back-Up Power 10 5.01 Coordinated Maintenance 10 5.02 CAPCO Back-Up Power 10 5.03 Scheduling CAPCO Back-Up Power 11 5.04 Obligation to Provide CAPCO Back-Up Power 12 5.05 Proportional Supply of CAPCO Back-Up Power 13 Article 6 -- Communications 13 Article 7 -- Services 14 Article 8 -- Executive Committee 15 Article 9 -- Ohio Edison System 16 Article 10 -- Interconnection Metering 17 Article 11 -- Records 18 Article 12 -- Statements, Billings, Settlements and Payments 18 Article 13 -- Government Approvals 21 Article 14 -- Notices 22 Article 15 -- Non-Waiver 22 TABLE OF CONTENTS (Cont'd) Page No. -------- Article 16 -- Arbitration 22 Article 17 -- Assignment 26 Article 18 -- Governing Law 26 Article 19 -- Other Agreements 26 Article 20 -- Term of Agreement 27 Article 21 -- Separate Identities 28 Article 22 -- Force Majeure 28 Article 23 -- Liability 29 Schedule A -- Back-Up Power 31 Schedule B -- Short Term Power 34 Schedule C -- Non-Displacement Power 38 Schedule D -- Economy Power 41 Schedule E -- Unit Power 46 Schedule F -- Out-of-Pocket Cost 51 Schedule G -- Emergency Power 53 Schedule H -- Transmission of Mon-CAPCO Power 56 Schedule I -- Replacement Power 57 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. ARTICLE 1 - --------- Purpose of Agreement - -------------------- 1.01 It is the purpose of this Agreement to provide for -1- 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 coordination 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 Equipment," 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 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- 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 operation 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. 2.05 Interruptible Load of a Party is the total of ------------------ megawatthours 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. -3- 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. 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 Interruptible Load to the extent they can be so included in accordance with rules and procedures established by the Operating Committee. -4- 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. 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; -5- (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; (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 recommendations 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. -6- 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, 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 -7- 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 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 -8- 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. 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 -9- or unavailable for continued operation 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. 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 -10- 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. 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 -11- 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, 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 -12- 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 obligations, 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 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, -13- 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. 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 conditions 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 -14- 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 Party receiving such energy from another Party (whether such Party is acting as a supplying or transmitting Party arising under Schedule D of this Agreement) 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. -15- 8.02 The Executive Committee shall have the duties and powers conferred on it by this Agreement, including the making of any decision or 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 responsibility 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 hereunder 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. -16- 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 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 -17- 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 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 -18- 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 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 -19- 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 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, -20- 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. 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, certificates 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. -21- 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 information as to oral notices or requests shall be provided to the Office in accordance with procedures established by the Operating Committee. 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 -22- 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, 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 nonrepresentative 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 -23- 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. 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 -24- 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 representative 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 majority of the nonrepresentative members thereof, shall be final and conclusive 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. -25- 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) voluntarily 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. 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 agreements 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. -26- 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 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 provisions 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. -27- 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 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 -28- 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 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. -29- 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 ------------------------- Doc. 17707 -30- 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 KW 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 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 -31- 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 NW-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. -32- 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. Doc. 17722 -33- 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 megawatts 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 -34- to and including the number of megawatts of Short Term Operating Capacity then being provided. 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 transactions 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 -35- 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 that 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 provided additionally, however, that any incremental or decremental transmission losses incurred on the system of any other -36- Party resulting from the transmission of such energy shall be treated in accordance with Article 7. Doc. 17723 -37- CAPCO BASIC OPERATING AGREEMENT ------------------------------- SCHEDULE C ---------- NON-DISPIACEMENT 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 any, of the amount paid therefor by the supplying Party over the demand charge therefor agreed to under -38- 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 MW-hr 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 Non-Displacement Power, -39- 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. Doc. 17724 -40- 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 -41- arranged to be obtained from or delivered to non-CAPCO party systems interconnected with a Party. 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 interconnected 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 -42- Economy Capacity. Such allocation shall be made as provided in Subsections 3.11 and 3.12. 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 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 -43- receiving Party or system shall be entitled to the remaining gross savings. 3.2 Economy Energy or Power ----------------------- The charge for Economy Energy or Power 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 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 additional 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 -44- and the charge in that week 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 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. Doc. 17725 -45- 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. -46- 1.3 At any time when the Unit is operated at minimum net generation required 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 generation 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 -47- 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 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 discharged 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 -48- month, adjusted to exclude the output and cost during the current calendar month of the Unit to which such 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 Operation 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 Not Demonstrated 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- -49- service, and all of the capital costs shall then be 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. Doc. 17726 -50- 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. 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 Charges 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. H. 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 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 SM-7 (Page 21 of 22) (BLANK) Doc. 17727 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 predominantly 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. 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 calculated 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). 3. The supplying Party will maintain the records used in the determination 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 home 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 reasonableness 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. 9. As soon as possible after the close of each calendar month, preferably 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 compensated 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. 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. Owner's Costs to Direct be Allocated to Basis 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 Accessory Steam Plant Equipment* X 513 Electric Plant* X 514 Misc. Steam Plant X OTHER ACCOUNTS - -------------- 556 System Control and Load Dispatching (Power Supply) X 557 Other Expenses (Power Supply) X 562 Transmission Station Expenses (Step-Up Transformer and Connection to Switch Yard Only) X 570 Maintenance of Station Equipment (Step-Up Transformer and Connection to Switch Yard Only) X * Charges made to primary accounts (500, 501, 502, etc.) will include distributions 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. 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 denominator 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. 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. 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 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 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. 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. 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 Investment Responsibility, i.e., 1/12 x (Seller's Equity Component of Capital) x (Tax Rate/(l- 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. 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 H&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 H&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 applicable 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, 5572 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. EXHIBIT D --------- DISPLACEMENT TRAINING COSTS Installed Capacity at Eastlake Unit No. 5 650,000 kV Generation Entitlement Share ---------------------------- Cleveland Electric Illuminating Company 447,000 kV Duquesne Light Company 203,000 kV ------- 650,000 kV 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. Doc. 17728 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 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 capability ratio (O(IR)) where a direct relationship does not exist. Account 556 will include only those load dispatching costs incurred by PP that are attributable 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: 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 f or 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. 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 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. (BLANK) Doc. 17729 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 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. 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 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 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. (BLANK) 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: * Fraction used to calculate working capital for purposes of this Exhibit. Beaver Valley 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. (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. Doc. 17730 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 capability ratio (O(IR)) where a direct relationship does not exist. Account 556 will include only those load dispatching costs incurred by PP that are attributable 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 Mansf ield 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 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. 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) 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. 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. (BLANK) Doc. 17731 APPENDIX 6 TO SCHEDULE E Charges Applicable to Transactions ---------------------------------- from Davis-Besse Unit No. 1 --------------------------- Pursuant to Schedule B ---------------------- 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 predominantly 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. 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 calculated 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). 3. The supplying Party will maintain the records used in the determination 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 reasonableness 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. 9. As soon as possible after the close of each calendar month, preferably 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 compensated 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. ASSIGNMENT OF PRODUCTION COSTS Sales of Capacity and Energy from Base Load Units to Purchasers: Davis-Besse Station Unit No. I 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 at set forth in the following table. Participants' Costs Direct to be Allocated to Basis 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 denominator 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. 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 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 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. 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. 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: where: Bc = Ec (Cc - Sf) ______ Ef 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. 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. 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 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 518 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. 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. 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 Investment Responsibility, i.e., 1/12 x (Seller's Equity Component of Capital) x (Tax Rate/(l- 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. EXHIBIT C --------- REIMBURSEMENT OF WORKING CAPITAL COSTS I. Accumulated Deferred Fuel Expense - Working Capital Costs --------------------------------- Applicable to 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 H&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 * Fraction used to calculate working capital for purposes of this Exhibit. (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. III. Monthly Operation & Maintenance Expenses - Working capital ---------------------------------------- cost applicable 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. 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. Doc. 17737 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: Where: MPLc = The current payments not related to burnup made by the Participant Rc = The current lease rate as defined in the lease agreement expressed as 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 experience 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. 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. (BLANK) 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. (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. Doc. 17739 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 predominantly 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. 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 calculated 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 determination 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 reasonableness 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, preferably 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 compensated 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 kg 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. 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. Participants' Costs Direct to be Allocated to Basis the Purchaser to Allocation Codes Account ------------------- 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. Code Basis - ---- ----- O(IR) 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. 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. 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. 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. 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 I 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 518 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. 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 multiplied 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(') -- 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 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/(l-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. 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% 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) EXHIBIT C REIMBURSEMENT OF WORKING CAPITAL COSTS I. Accumulated Deferred Fuel Expense - Working Capital Costs --------------------------------- Applicable to 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. * Fraction used to calculate working capital for purposes of this Exhibit. 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 H&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. 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 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. 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. Doc. 17740 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 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. Doc. 17741 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. 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 MS-hr. 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 compensated for at the option of the supplying Party by return-in-kind or by the payment of the greater of (1) $100 pe 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. Doc. 17772 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 receiving Party and 1/3 of such payments allocated equally between the other two Parties. Doc. 17773 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 enrichment contractor for enrichment. This Schedule I is applicable to the provision 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 "arty") fails to supply its required share of Uranium for a CAPCO Unit, they 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 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. Section 3 - Compensation ------------------------ 3.1 If the supplying Party supplies such Replacement Capacity and Replacement Energy u=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. Doc. 17774 EX-10 4 OE10K OHIO EDISON COMPANY MASTER DECOMMISSIONING TRUST AGREEMENT FOR PERRY NUCLEAR POWER PLANT UNIT ONE, PERRY NUCLEAR POWER PLANT UNIT TWO, BEAVER VALLEY POWER STATION UNIT ONE AND BEAVER VALLEY POWER STATION UNIT TWO Dated: July 1, 1993 TABLE OF CONTENTS Page ---- I. DEFINITIONS 1.01 Definitions . . . . . . . . . . . . . . . . . . . . 3 II. MASTER TRUST PURPOSE, NAME AND FUNDS 2.01 Master Trust Purpose. . . . . . . . . . . . . . . 11 2.02 Establishment of Master Trust . . . . . . . . . . 11 2.03 Acceptance of Appointment . . . . . . . . . . . . 11 2.04 Name of Master Trust. . . . . . . . . . . . . . . 12 2.05 Division of Master Trust. . . . . . . . . . . . . 12 2.06 Designation of Funds. . . . . . . . . . . . . . . 13 2.07 Duties of Authorized Representatives. . . . . . . 13 2.08 No Authority to Conduct Business. . . . . . . . . 14 2.09 No Transferability of Master Trust. . . . . . . . 14 III. BENEFICIARIES OF MASTER TRUST 3.01 Company and Others to be Beneficiaries. . . . . . 14 IV. CONTRIBUTIONS AND INCOME 4.01 Contributions . . . . . . . . . . . . . . . . . . 15 4.02 Allocation of Net Income. . . . . . . . . . . . . 16 4.03 Subsequent Transfers. . . . . . . . . . . . . . . 16 V. DISTRIBUTIONS 5.01 Payment of Decommissioning Costs and Administrative Costs. . . . . . . . . . . . . . . 17 5.02 Payment of Administrative Expenses. . . . . . . . 18 5.03 Fees. . . . . . . . . . . . . . . . . . . . . . . 19 5.04 Liquidation of Investments. . . . . . . . . . . . 20 VI. TERMINATION 6.01 Termination of Funds and Master Trust in General . . . . . . . . . . . . . . . . . . . . . 20 6.02 Distribution of Master Trust and Funds Upon Termination . . . . . . . . . . . . . . . . . . . 21 VII. TRUSTEES 7.01 Designation and Qualification of Successor Trustee(s). . . . . . . . . . . . . . . . . . . . 21 7.02 Exoneration from Bond . . . . . . . . . . . . . . 23 7.03 Resignation . . . . . . . . . . . . . . . . . . . 23 7.04 Transactions With Third Parties . . . . . . . . . 23 7.05 Accounts and Reports. . . . . . . . . . . . . . . 24 7.06 Tax Returns and Other Reports . . . . . . . . . . 26 7.07 Liability . . . . . . . . . . . . . . . . . . . . 27 VIII. INVESTMENTS 8.01 Appointment of Investment Manager(s). . . . . . . 28 8.02 Direction by Investment Manager(s). . . . . . . . 29 IX. TRUSTEE'S GENERAL POWER 9.01 Registration of Securities. . . . . . . . . . . . 32 9.02 Borrowing . . . . . . . . . . . . . . . . . . . . 32 9.03 Retention and Removal of Professional and Employee Services . . . . . . . . . . . . . . . . 33 9.04 Delegation of Ministerial Powers. . . . . . . . . 33 9.05 Powers of Trustee to Continue Until Final Distribution. . . . . . . . . . . . . . . . . . . 33 9.06 Discretion in Exercise of Powers. . . . . . . . . 33 9.07 Deposition of Funds . . . . . . . . . . . . . . . 34 9.08 Market Inventory Funds. . . . . . . . . . . . . . 34 9.09 Loaning of Securities . . . . . . . . . . . . . . 34 9.10 Retention of Uninvested Cash. . . . . . . . . . . 35 X. TRUSTEE'S INVESTMENT POWERS 10.01 General Investment Powers. . . . . . . . . . . . 35 XI. MISCELLANEOUS 11.01 Headings . . . . . . . . . . . . . . . . . . . . 36 11.02 Particular Words . . . . . . . . . . . . . . . . 36 11.03 Severability of Provisions . . . . . . . . . . . 36 11.04 Delivery of Notices Under Agreement. . . . . . . 37 11.05 Alterations and Amendments . . . . . . . . . . . 37 11.06 Successors and Assigns . . . . . . . . . . . . . 39 11.07 Governing Law; Jurisdiction; Certain Waivers . . 39 11.08 Accounting Year. . . . . . . . . . . . . . . . . 39 11.09 Counterparts . . . . . . . . . . . . . . . . . . 39 11.10 Decommissioning Liability. . . . . . . . . . . . 40 SCHEDULE A PERMITTED INVESTMENTS SCHEDULE B OWNER TRUSTEE AND OWNER PARTICIPANTS EXHIBIT A CERTIFICATE MASTER DECOMMISSIONING TRUST AGREEMENT -------------------------------------- AGREEMENT made as of this 1st day of July 1993, between OHIO EDISON COMPANY, an Ohio corporation (the "Company"), and MELLON BANK, N.A., as Trustee (the "Trustee"), a national banking association duly organized and validly existing under the laws of the United States of America. WHEREAS, the Company has ownership interests as a tenant in common of undivided interests in Perry No. 1, Perry No. 2, Beaver Valley No. 1 and Beaver Valley No. 2, as well as leasehold interests in additional undivided interests in Perry No. 1 and Beaver Valley No. 2; and WHEREAS, Perry No. 1, Perry No. 2, Beaver Valley No. 1 and Beaver Valley No. 2 are, or are designed to be, nuclear fueled electric generating units which will require Decommissioning at the end of their useful life; and WHEREAS, pursuant to the requirements of the Sale/Leaseback Transactions, the Company is required to establish trust funds to provide for payment of Decommissioning Costs associated with its ownership and leasehold interests in Perry No. 1 and Beaver Valley No. 2, and, pursuant to the requirements of The Public Utilities Commission of Ohio ("PUCO") and the Nuclear Regulatory Commission ("NRC"), is generally required to create an external source of funding to provide for the costs associated with the Decommissioning of its proportionate share of nuclear fueled electric generating units in which it has an interest; and WHEREAS, pursuant to Section 468A of the Internal Revenue Code of 1986, as amended, certain federal income tax benefits are available to the Company as a result of creating and making contributions to certain nuclear decommissioning reserve funds; and WHEREAS, the Company, in order to comply with the requirements of the Sale/Leaseback Transactions and the requirements of the PUCO and NRC, and in order to be in a position to take advantage of the federal income tax benefits available under the aforementioned Section 468A, established as of June 1, 1988 both Qualified Funds and Nonqualified Funds to hold amounts in trust for the future Decommissioning of each of the Units wherein each of the Funds constituted a separate trust under a Master Trust (the "Master Trust"); and WHEREAS, National City Bank, Akron, which served as Trustee under the Master Trust from its inception, has been replaced as Trustee by Mellon Bank, N.A.; and WHEREAS, the Company and Mellon Bank, N.A. (acting as Trustee) wish to amend the agreement dated as of June 1, 1988 -2- which established the Master Trust and to restate such agreement in its entirety. NOW, THEREFORE, in consideration of the mutual promises herein contained and other good and valuable consideration, receipt and sufficiency of which is hereby acknowledged, the Trustee hereby acknowledges that it has accepted appointment as successor Trustee under the Master Trust and agrees (a) to serve as such on the terms and conditions herein set forth and (b) to accept, from and after the date first above written, Contributions to the Master Trust delivered to it from time to time by or on behalf of the Company; TO HAVE AND TO HOLD such assets, together with the assets of the Master Trust which it received upon becoming successor Trustee thereunder; and TO INVEST AND REINVEST the same as provided herein; IN TRUST NEVERTHELESS, for the uses and purposes and upon the terms and conditions, as hereinafter set forth; and TO PAY OR DISTRIBUTE from the Master Trust as provided herein. I. DEFINITIONS ----------- 1.01 Definitions. As used in this Master Decommissioning Trust Agreement, the following terms shall have the following meanings: -3- (1) "Agreement" shall mean this Master Decommissioning Trust Agreement as the same may be amended, modified, or supplemented from time to time. (2) "Applicable Law" shall mean all applicable laws, statutes, treaties, rules, codes, ordinances, regulations, certificates, orders, interpretations, licenses and permits of any Governmental Authority and judgments, decrees, injunctions, writs, orders or like action of any court, arbitrator or other judicial or quasi judicial tribunal of competent jurisdiction (including those pertaining to health, safety, the environment or otherwise). (3) "Applicable Tax Law" shall mean Section 468A of the Code (or comparable subsequent provision of the Code) and the regulations thereunder, and any other provision of the Code relating to the Federal taxation of the Funds or credits or deductions based on Contributions. (4) "Authorized Representative" shall mean the persons designated as such pursuant to Section 2.07 hereof, except that after a Default any Designated Beneficiary shall be deemed to be an Authorized Representative for purposes of completing, executing and delivering a Certificate to the Trustee relating to a particular Unit but only with respect to the Unit specified in the Supplement pursuant to which such Designated Beneficiary is designated as such and its Beneficial Interest therein. (5) "Beaver Valley No. 1" shall mean the nuclear generating unit located at the Beaver Valley Power Station and -4- known as Unit 1, together with its associated facilities and equipment. (6) "Beaver Valley No. 2" shall mean the nuclear generating unit located at the Beaver Valley Power Station and known as Unit 2, together with its associated facilities and equipment. (7) "Beaver Valley Power Station" shall mean the electric generating station located on the south bank of the Ohio River in Beaver County, Pennsylvania, approximately 25 miles northwest of Pittsburgh. (8) "Beneficial Interest" shall mean the undivided interest in a Unit that is owned by a Designated Beneficiary in its capacity as Owner Trustee in the Sale/Leaseback Transaction involving the Unit and the Equity Participant specified in the Supplement by which such Owner Trustee became a Designated Beneficiary. (9) "Business Day" shall mean a day that is not a Saturday or Sunday or a legal holiday in the State of Ohio or the Commonwealth of Pennsylvania. (10) "Certificate" shall mean a document properly completed and executed by an Authorized Representative of the Company, or by a Designated Beneficiary when it is deemed to be an Authorized Representative under Paragraph (4) of this Section 1.10, and substantially in the form of Exhibit A hereto as it may from time to time be amended. (11) "Code" shall mean the Internal Revenue Code of 1986, as the same may be amended from time to time. -5- (12) "Company" shall have the meaning set forth in the opening paragraph of this Agreement. (13) "Contribution" shall mean any contribution, cash or otherwise, made to the Trustee for deposit in one or more of the Funds and in such subaccount thereunder as provided in this Agreement. No contribution which consists of real property shall be permitted. (14) "Decommissioning" shall mean the decommissioning and retiring of a nuclear generating unit from commercial service under Applicable Law and, to the extent a method of decommissioning is not prescribed by Applicable Law, by the method of decommissioning determined as provided in the operating agreement relating to such unit, and shall consist of the removal (as a facility) of such unit safely from service, the dismantling, shipping, long-term storage and disposal of all radioactive parts and components of such unit and the reduction of residual radioactivity at the site of such unit to a level that permits, and the removal of non-contaminated structures and components and such restoration as shall be necessary or desirable to permit, the release of the property for unrestricted use and termination of the NRC license relating to the unit. This process shall include, but not be limited to (a) the removal of both radioactively contaminated and radioactively uncontaminated portions of the unit, and shipping, long-term storage and disposal of the same, in each case, in accordance with Applicable Law at the end of the useful life of such unit or if there shall be no Applicable Law at that time, in accordance -6- with the operating agreement with respect to such unit (b) work done to the site of the unit and its associated equipment and facilities and to adjacent areas, whether or not such areas are contiguous to such site, in order to decontaminate such site and such areas and (c) work done by or on behalf of the Company (or for which the Company is charged) to the site where any portion of the unit and its associated equipment and facilities are to be stored or disposed of in order to prepare and maintain such site as a storage or disposal site. (15) "Decommissioning Costs" shall mean all costs and expenses relating or allocable to, or incurred in connection with Decommissioning, including but not limited to the removal of the equipment, structures and portions of a nuclear generating unit and its site containing radioactive contaminants or the decontamination of the same to a level that permits the property to be released for unrestrictive use as promptly as practicable after cessation of the operation of the unit, plus, in the case of decontamination, the cost of removal, shipping and long-term storage or disposal of such equipment structures and portions; provided, however, that if Applicable Law prohibits the foregoing or imposes requirements that are more costly to implement than the removal, shipping, storage, disposal or decontamination referred to above in this definition, the term "Decommissioning Costs" shall mean all costs and expenses relating or allocable to, or incurred in connection with, the most costly requirements imposed by Applicable Law with respect to radioactive contaminants after a nuclear generating unit ceases operation. -7- (16) "Default" shall have the meaning ascribed thereto in Section 6.1 of the form of Supplement set forth in Exhibit B hereto. (17) "Designated Beneficiary" shall mean a party designated as such in a Supplement. (18) "Funds" shall mean the Qualified Funds and the Nonqualified Funds, collectively. (19) "Governmental Authority" shall mean any Federal, state, county, municipal, foreign, international, regional or other governmental authority, agency, board, body, instrumentality or court, including, without limitation, the NRC and the PUCO. (20) "Investment Account" shall mean an account established by the Trustee pursuant to Section 8.01 hereof which consists of those assets in each Fund under the Master Trust designated by the Company for management by an Investment Manager. (21) "Investment Manager(s)" shall mean the person(s) appointed by the Company pursuant to Section 8.01 hereof, including any employees of the Company or its affiliated companies. (22) "Investment Manager Agreement(s)" shall mean an agreement(s) between the Company and an Investment Manager(s) appointed by the Company which agreement governs the management of all or a portion of the Funds. (23) "March 1987 Sale/Leaseback Transaction" shall mean the transactions consummated in March 1987 in which the -8- Company sold and leased back portions of its undivided ownership interest in Perry No. 1. (24) "Minimum Amount" shall mean the amount required to be in a Designated Beneficiary's subaccount or subaccounts as of a particular date under Section 10(b)(3)(viii) of the Participation Agreement relating to such Designated Beneficiary. (25) "Nonqualified Funds" shall mean, collectively, the Funds not constituting Qualified Funds established under, and in accordance with, Section 2.02(b) or Section 2.05 of the Master Trust with respect to any of the Units. Each Nonqualified Fund shall have such subaccount as are provided for herein or as the Company may otherwise specify. (26) "NRC" shall have the meaning ascribed thereto in the third WHEREAS clause of this Agreement or any successor agency. (27) "Order" shall mean any order relating to Decommissioning issued by a Governmental Authority and applicable to one or more of the Units. (28) "Participation Agreements" shall mean the Participation Agreements referred to in the documentation for the Sale/Leaseback Transactions. (29) "Permitted Investment" shall mean, at any particular time, each investment shown on Schedule A hereto to be permissible at such time. (30) "Perry No. 1" shall mean the nuclear generating unit located at the Perry Nuclear Power Plant and known as Unit 1, together with its associated facilities and equipment. -9- (31) "Perry No. 2" shall mean the nuclear generating unit located at the Perry Nuclear Power Plant and known as Unit 2, together with its associated facilities and equipment, at such time as such unit is completed and is placed in service. (32) "Perry Nuclear Power Plant" shall mean the electric generating station located on the shore of Lake Erie in Lake County, Ohio, approximately 35 miles northeast of Cleveland. (33) "PUCO" shall have the meaning ascribed thereto in the third WHEREAS clause of this Agreement or any successor agency. (34) "Qualified Funds" shall mean, collectively, the accounts established under, and in accordance with, Section 2.02(b) of the Master Trust for purposes of Section 468A of the Code which are designated as such in the records of the Trustee. Each Qualified Fund shall have such subaccounts as are specified herein or as the Company may otherwise specify. Contributions, if any, made with respect to each such Fund in any year shall not exceed the amount permitted to be made to such Fund with respect to the year in question in order for the Company to be allowed to take the deduction afforded by Section 468A of the Code. (35) "Sale/Leaseback Transactions" shall mean the March 1987 Sale/Leaseback Transaction and the September 1987 Sale/Leaseback Transaction, collectively. (36) "September 1987 Sale/Leaseback Transaction" shall mean the transactions consummated in September 1987 in which the Company sold and leased back portions of its undivided ownership interest in Beaver Valley No. 2. -10- (37) "Service" shall mean the Internal Revenue Service. (38) "Supplement" shall mean a Supplement substantially in the form of Exhibit B hereto as it may from time to time be amended. (39) "Trustee" shall have the meaning ascribed thereto in the opening paragraph of this Agreement or any successor appointed pursuant to Section 7.01 hereof. (40) "Units" shall mean Beaver Valley No. 1, Beaver Valley No. 2, Perry No. 1 and Perry No. 2, collectively. II. MASTER TRUST PURPOSE, NAME AND FUNDS ------------------------------------ 2.01 Master Trust Purpose. The exclusive purpose of -------------------- this Master Trust is to accumulate and hold funds for the contemplated Decommissioning of the Units and to expend funds for that purpose. 2.02 Establishment of Master Trust. By execution of ----------------------------- this Agreement, the Company: (a) reaffirms the establishment of the Master Trust for the retention and investment of the assets of the Funds, effective June 1, 1988 on the date first above written; (b) reaffirms the establishment of a Qualified Fund and a Nonqualified Fund for each Unit; and (c) reaffirms the appointment of Mellon Bank, N.A., as successor to National City Bank, Akron, as Trustee of the Master Trust. 2.03 Acceptance of Appointment. Upon the terms and ------------------------- conditions herein set forth, Mellon Bank, N.A. reaffirms -11- acceptance of its appointment as Trustee of this Master Trust. The Trustee declares that it will hold all estate, right, title and interest it may acquire hereunder exclusively for the purposes set forth in this Article II. The Trustee shall receive any Contributions deposited with it by the Company in trust for the benefit of the Company (subject to the rights of other parties as contemplated by Section 3.01 hereof) and shall deposit such Contributions in one or more of the Funds, and in such subaccounts thereunder, as provided in Section 2.05 hereof and otherwise as the Company shall specify. The Trustee shall hold, manage, invest and administer such Contributions, together with earnings and appreciation thereon, in accordance with this Agreement. 2.04 Name of Master Trust. The Contributions received -------------------- by the Trustee (or by any predecessor or successor trustee) from the Company together with the proceeds, reinvestment and appreciation thereof shall constitute the "Ohio Edison Company Master Decommissioning Trust." 2.05 Division of Master Trust. The Master Trust shall ------------------------ be divided by the Trustee into a Qualified Fund and a Nonqualified Fund for each of the Units and into such other Nonqualified Funds as the Company from time to time shall establish. Each Fund shall constitute a separate trust under the Master Trust and shall be designated as relating to a particular Unit. Each Fund shall have a subaccount relating to each Designated Beneficiary, clearly identified as such, and such other subaccounts as the Company from time to time shall specify. -12- The Trustee shall maintain such records as are necessary to reflect each Fund and each subaccount thereunder separately on its books from each other Fund and subaccount. 2.06 Designation of Funds. Upon (i) any Contribution -------------------- to the Master Trust; or (ii) any withdrawal from the Master Trust; or (iii) any transfer between the Funds or sub-accounts thereunder, the Company shall designate (in writing), in accordance with Article IV or V, as applicable, the Fund(s), and the subaccount(s) thereunder, which is to be credited or debited for the amount of such Contribution, withdrawal or transfer, and the Trustee shall credit or debit the Fund(s), and the subaccount(s) thereunder, in accordance with such designation. 2.07 Duties of Authorized Representatives. The ------------------------------------ Company has empowered the Authorized Representatives and their delegates to act for the Company in all respects hereunder. The Authorized Representatives may act as a group or may designate one or more Authorized Representative(s) or delegate(s) to perform the duties described in the foregoing sentence. The Company shall provide the Trustee with a written statement setting forth the names and specimen signatures of the Authorized Representatives. The Authorized Representatives shall provide the Trustee with a written statement setting forth the names and specimen signatures of, and specific authority delegated to, any delegate of the Authorized Representatives. Until otherwise notified in writing by the Company, the Trustee may rely upon any written notice, instruction, direction, certificate or other communication believed by it to be genuine and to be signed or -13- certified by any one or more Authorized Representatives or their designated delegate(s), and the Trustee shall be under no duty to make any investigation or inquiry as to the truth or accuracy of any statement contained therein. 2.08 No Authority to Conduct Business. The purpose of -------------------------------- this Master Trust is limited specifically to the matters set forth in Section 2.01 hereof, and there is no objective to carry on any business unrelated to the Master Trust purpose set forth in Section 2.01 hereof, or divide the gains there from. 2.09 No Transferability of Master Trust. Except as ---------------------------------- expressly provided in Article III hereof or in a Supplement, the interest of the Company in the Master Trust is neither transferable, whether voluntarily or involuntarily, by the Company nor subject to the payment of the claims of creditors of the Company; provided, however, that any creditor of the Company as to which a Certificate has been properly completed and submitted to the Trustee may assert a claim directly against the Master Trust in an amount not to exceed the amount specified in such Certificate. III. BENEFICIARIES OF MASTER TRUST ----------------------------- 3.01 Company and Others to be Beneficiaries. The -------------------------------------- beneficial ownership of the Funds shall, subject to the to the purpose of the Master Trust and the security interests granted to each Designated Beneficiary pursuant to one or more Supplements, be at all times in the Company and in any Designated Beneficiary named as such in a Supplement, provided, however, that the beneficial ownership of the Funds in any such Designated -14- Beneficiary shall be limited to a right to have, and an interest in having, the Funds applied to pay Decommissioning Costs as contemplated hereunder and under Section 10(b)(3)(viii) of the Participation Agreement(s), relating to the Sale/Leaseback Transaction(s) to which it is a party; and for the recognition and enforcement of such right and interest, each such Designated Beneficiary shall have the remedies set forth in the Supplement naming it as a Designated Beneficiary. IV. CONTRIBUTIONS AND INCOME ------------------------ 4.01 Contributions. On or before March 16, 1992, with ------------- respect to Perry No. 1, and on or before September 29, 1992, with respect to Beaver Valley No. 2, and thereafter annually on or before the anniversary of such dates, respectively, or quarterly (based on such respective dates as applicable) as to the subaccounts for any Designated Beneficiary who is a party to a Participation Agreement relating to a Sale/Leaseback Transaction which requires quarterly funding of such subaccounts, the Company shall make a Contribution or otherwise transfer funds so that the amounts in the subaccounts for each Designated Beneficiary are maintained at the level required by the Participation Agreement(s) relating to the Sale/Leaseback Transactions to which it is a party. The Company may also make such other Contributions to any Fund from time to time as it shall deem necessary or appropriate. The Trustee shall have the ability, subject to the prior written consent of the affected Designated Beneficiary if the funds to be returned are derived from amounts in any subaccount relating to such Designated Beneficiary, to -15- return Contributions to the Company if such Contributions are excessive in light of Applicable Law, Applicable Tax Law and the requirements of the Sale/Leaseback Transactions. 4.02 Allocation of Net Income. So long as no Default ------------------------ (as such term is defined in any Supplement) has occurred and is continuing, the Trustee may pool the assets of the Funds or of any subaccount thereunder for investment purposes in accordance with the written instructions of the Company, subject to the limitations on investments contained in Schedule A hereto, and, upon so doing, shall treat each Fund or subaccount so pooled as having received or accrued a pro rata portion (based on the principal balances of the Funds or subaccount so pooled) of the net income of the Master Trust (including appreciation) related to such pooled assets in any accounting period of the Master Trust. Without limiting the requirements of Section 7.05 hereof, the Trustee shall maintain such separate records of each of the Funds and the subaccounts thereunder as are necessary to reflect the assets thereof and the allocation of income and losses among the Funds and subaccounts thereunder. The Trustee may rely upon the written opinion of legal counsel of the Company, who may be an employee of the Company, with respect to any question arising under this Section 4.02. 4.03 Subsequent Transfers. Upon receipt of a written -------------------- directive of the Company signed by an Authorized Representative which sets forth an amount to be transferred from one of the Funds or subaccount thereunder and states that such amount should be transferred to one or more other Funds or subaccount as -16- specified, the Trustee shall transfer such amount to the Fund(s) or subaccount specified by the Company in the written directive; provided, however, that no transfer shall be made from a Designated Beneficiary's subaccount except to another subaccount of such Designated Beneficiary without such Designated Beneficiary's prior written consent. No transfer to or from a Qualified Fund shall be made which would violate the provisions of Section 468A of the Code. V. DISTRIBUTIONS ------------- 5.01 Payment of Decommissioning Costs and ------------------------------------ Administrative Costs. In addition to payments otherwise - -------------------- authorized by this Agreement, the Trustee shall make payments out of the Funds or any subaccount thereunder upon presentation to the Trustee of a Certificate by the Company, or by any Designated Beneficiary if such Designated Beneficiary shall certify that it is acting pursuant to the provisions of Section 6.2 of the Supplement to which it is a party, instructing the Trustee to disburse amounts in the Funds or any subaccount thereunder in a manner designated in such Certificate for purposes of paying costs, liabilities and expenses of Decommissioning or, if so specified, administrative costs related to services authorized by the Company pursuant to Section 9.03. If the Funds relate to either Perry No. 1 or Beaver Valley No. 2, the amount to be withdrawn from any Designated Beneficiary's subaccount with respect to any particular disbursement shall be equal to the percentage of such Designated Beneficiary's Beneficial Interest in the Unit to which the relevant Fund is related times the -17- aggregate amount of the costs, liabilities or expenses of Decommissioning to which such disbursement is to be applied. If the balance in any Designated Beneficiary's subaccount from which payment is to be made is insufficient for any payment, the Company shall, at the time it delivers the Certificate to the Trustee, pay or transfer the amount of such deficiency into the applicable Nonqualified Fund for credit to such subaccount or subaccounts, and any such payment shall then be withdrawn as provided above. If the assets of any Fund or subaccount thereof are insufficient to permit the payment in full of amounts to be paid pursuant to a Certificate, the Trustee shall have no liability with respect to such insufficiency and no obligation to use its own funds to pay the same, except as it might otherwise be liable under this Agreement because of its negligence or wilful misconduct. 5.02 Payment of Administrative Expenses. In addition ---------------------------------- to the payment of administrative costs paid pursuant to Section 5.01 hereof, from time to time, the Trustee shall make payments of all reasonable administrative expenses (including, reasonable out-of-pocket expenses and Trustee's fees as specified in the agreement referred to in Section 5.03 hereof and taxes, other than taxes payable on the income of the Trustee) in connection with the operation of the Master Trust pursuant to this Agreement. All such administrative expenses and incidental expenses of the Master Trust shall require prior written authorization of the Company and shall be allocated proportionately among the Funds (based on the fair market value -18- of each Fund immediately prior to any such payment) and within each Fund among the subaccounts in the proportion that the balance in each subaccount bears to the aggregate balance of all subaccounts in such Fund; provided, that the amount allocated to any Designated Beneficiary's subaccount or subaccounts shall in no event exceed the lesser of (a) an amount equal to the percentage of the Designated Beneficiary's Beneficial Interest in the Unit to which the relevant fund is related times the aggregate amount of such administrative and incidental expenses allocated to such Fund and (b) an amount which would cause the balance in such subaccount or subaccounts to be less the Minimum Amount as of such date; and provided further that income taxes shall be allocated among the Qualified Funds and Nonqualified Funds in accordance with the income tax actually imposed on each such Fund. The Trustee shall maintain such records as are necessary to reflect the allocation of administrative expenses and incidental expenses among the Funds and subaccounts in accordance with this Section 5.02. If the assets of any Fund or subaccount thereof are insufficient to permit the payment in full of amounts payable under this Section 5.02, the Trustee shall have no liability with respect to such insufficiency and no obligation to use its own funds to pay the same, except as it might otherwise be liable under this Agreement because of its negligence or wilful misconduct. 5.03 Fees. The Trustee shall receive as exclusive ---- compensation for its services such reasonable amounts as may from time to time be agreed to by the Trustee and the Company. -19- 5.04 Liquidation of Investments. At the direction of -------------------------- the Company or any Investment Manager (with respect to Funds or portions thereof specified to be under the control of such Investment Manager as to investment in an Investment Manager Agreement), the Trustee shall sell or liquidate such investments of the Funds as may be specified. The proceeds of any such sale or liquidation shall be credited pro rata to the Fund or Funds and within each Fund to the subaccount or subaccounts thereunder to which such investments were credited prior to such sale or liquidation. Notwithstanding the foregoing, at any time during the continuance of a Default, a Designated Beneficiary may direct the Trustee in writing to sell or liquidate such investments of any subaccount or subaccounts identified with such Designated Beneficiary as such Designated Beneficiary may specify and the proceeds of any such sale or liquidation shall be credited proportionately to the subaccount or subaccounts to which such investments were credited prior to such sale or liquidation. VI. TERMINATION ----------- 6.01 Termination of Funds and Master Trust in General. ------------------------------------------------ Each Fund established hereunder shall terminate only upon the earlier of (i) the completion of the Decommissioning of the Unit to which it relates (as evidenced by written notification of that fact to the Trustee by the Authorized Representative accompanied -20- by evidence of the concurrence of the NRC with respect thereto, which written notification in the case of Perry No. 1 and Beaver Valley No. 2 (and in those cases only) shall also be accompanied by the written approval of each lessor, partnership and corporation identified in Schedule B hereto (as amended by the Company from time to time) as being connected with the Unit in question or (ii) twenty-one (21) years after the death of the last survivor of each Person who was an officer or director of the Company on May 31, 1988 and each of their descendants born on or prior to May 31, 1988. This Master Trust shall terminate upon the termination of all of the Funds. Prior to its termination this Master Trust shall be irrevocable. 6.02 Distribution of Master Trust and Funds Upon ------------------------------------------- Termination. Upon termination of this Master Trust or of the - ----------- Funds with respect to a particular Unit, the Trustee shall assist the Company or the Investment Manager(s) in liquidating the assets of the Master Trust or such Funds, as the case may be, and distributing the then existing assets thereof (including accrued, accumulated and undistributed net income), less all reasonable final administrative costs and expenses agreed to by the Company (including accrued taxes), to the Company; provided, however, that no such distribution shall be made unless Decommissioning shall have been completed and the conditions set forth in Section 6.01 shall have been satisfied. VII. TRUSTEES -------- 7.01 Designation and Qualification of Successor ------------------------------------------ Trustee(s). At any time during the term of this Master Trust, - ---------- the Company shall have the right to remove the Trustee (at the Company's sole discretion) acting hereunder and appoint another qualified entity as a successor Trustee upon thirty (30) days' -21- notice in writing to the Trustee, or upon such shorter notice as may be acceptable to the Trustee. In the event that the bank or trust company serving as Trustee or successor Trustee shall: (a) become insolvent or admit in writing its insolvency; (b) be unable or admit in writing its inability to pay its debts as such debts mature; (c) make a general assignment for the benefit of creditors; (d) have an involuntary petition in bankruptcy filed against it; (e) commence a case under or otherwise seek to take advantage of any bankruptcy, reorganization, insolvency, readjustment of debt, dissolution or liquidation law, statute, or proceeding or (f) resign, the Company shall appoint a successor Trustee as soon as practicable. In the event of any such removal or resignation, the Trustee or successor Trustee shall have the right to have its accounts finalized as provided in Section 7.05 hereof. Any successor to the Company, as provided herein, shall have the same right to remove and to appoint any Trustee or successor Trustee. Any successor Trustee shall be a bank or trust company incorporated and doing business within the United States of America and having a combined capital and surplus of at least $250,000,000 (in 1988 dollars), if there be such an institution willing, able and legally qualified to perform the duties of Trustee hereunder upon reasonable or customary terms. Any successor Trustee shall qualify by a duly acknowledged acceptance of this Master Trust, delivered to the Company. Upon acceptance of such appointment by the successor Trustee, the Trustee shall assign, transfer and pay over to such -22- successor Trustee the assets then constituting the Master Trust. Any successor Trustee shall have all the rights, powers, duties and obligations herein granted to the original Trustee. 7.02 Exoneration from Bond. No bond or other security --------------------- shall be exacted or required of any Trustee or successor Trustee appointed pursuant to this Agreement. 7.03 Resignation. The Trustee or any successor ----------- Trustee may resign and be relieved as Trustee at any time without prior application to or approval by or order of any court, by a duly acknowledged instrument, which shall have been delivered to the Company by the Trustee no less than sixty (60) days prior to the effective date of such Trustee's resignation or upon such shorter notice as may be acceptable to the Company. A copy of each such instrument shall be sent forthwith to each lessor, partnership and corporation identified in Schedule B hereto (as amended by the Company from time to time). If for any reason the Company cannot or does not act in the event of the resignation of the Trustee, the Trustee may apply to a court of competent jurisdiction for the appointment of a successor Trustee and the cost of making such application shall be an administrative expense. 7.04 Transactions With Third Parties. No person or ------------------------------- organization dealing with the Trustee hereunder shall be required to inquire into or to investigate its authority for entering into any transaction or to see to the application of the proceeds of any such transaction. -23- 7.05 Accounts and Reports. The Trustee shall keep -------------------- accurate and detailed accounts of all investments, receipts and disbursements and other transactions hereunder with respect to each Fund and each subaccount thereunder in accordance with specifications of the Company and generally accepted accounting principles, and all accounts, books and records relating thereto as to a particular Unit shall be open to inspection and audit at all reasonable times by each lessor, partnership and corporation identified in Schedule B hereto (as amended by the Company from time to time) as being connected with that Unit, and as to a particular Unit and generally by any other person designated by the Company. Within 5 Business Days following the close of each month, the Trustee shall provide a written report of the estimated market value of each Fund and each subaccount thereunder, prepared on an accrual basis. Within 15 days following the close of each month, the Trustee shall file with the Company a final written report setting forth all investments, receipts and disbursements and other transactions effected by it during the month and containing an exact description of all cash and securities contributed, purchased, sold or distributed and the cost or net proceeds of sale, and showing all cash, and securities and other investments held at the end of such month and the cost and fair market value of each item thereof as carried on the books of the Trustee. A copy of so much of each report provided to the Company by the Trustee pursuant to the two immediately preceding sentences as relates to the Funds and subaccounts associated with a particular Unit shall be sent by -24- the Company to each lessor, partnership and corporation identified in Schedule B hereto (as amended by the Company from time to time) as being connected with that Unit. The Company may for the sake of expediency include information relating to other Funds and subaccounts not related to that Unit in the copies of reports it sends pursuant to the immediately preceding sentence. Such accounts and reports shall be based on the accrual method of reporting net income and expenses and shall show the portion of the assets applicable to each Fund and subaccount thereunder and shall also identify all disbursements from each Fund and subaccount thereunder. In addition to the foregoing, on or before January 31 in each calendar year, the Trustee shall submit such reports to the PUCO and any other Governmental Authority as may be required under any applicable regulation and shall promptly deliver a copy of each such report to each lessor, partnership and corporation identified in Schedule B hereto (as amended by the Company from time to time). All records and accounts maintained by the Trustee with respect to the Master Trust and the Funds shall be preserved at least until one year after the termination of the Master Trust and thereafter for such additional period as may be required under any applicable law. Upon the expiration of any such required retention period, the Trustee shall have the right to destroy such records and accounts after first notifying the Company in writing of its intention and transferring to the Company any records and accounts requested by the Company. -25- 7.06 Tax Returns and Other Reports. The Trustee shall ----------------------------- prepare, execute and timely file all federal, state and local income or franchise tax returns or other reports (including estimated tax returns and information returns) as may be required from time to time with respect to the Qualified Funds, and the Company agrees to provide the Trustee in a timely manner with any information within its possession, and to cause the Investment Manager(s) to provide the Trustee with any information in its possession, which is necessary to such filings. The Trustee shall prepare and submit to the Company in a timely manner all information requested by the Company regarding the Funds required to be included in the Company's federal, state and local income tax returns or other reports (including estimated tax returns and information returns). Subject to the limitations contained in Section 9.03 hereof, the Trustee may employ independent certified public accountants or other tax counsel to prepare or review such returns and reports and the cost thereof shall be an administrative cost. The Trustee agrees to remit from the Master Trust appropriate payments or deposits of federal, state and local income or franchise taxes directly to the taxing agencies or authorized depositaries in a timely manner. Notwithstanding Section 7.07 hereof, any interest or penalty charges assessed against the Master Trust pursuant to Chapters 67 or 68 of the Code, or pursuant to any similar state or local tax provisions, as a result of the Trustee's failure to comply with this Section 7.06 (other than as a result of the Company's failure to provide or cause to be provided the information that it has agreed to -26- provide or cause to be provided in this Section 7.06) shall be borne by the Trustee and not the Master Trust. The Trustee agrees to notify immediately the Company in writing of the commencement of the audit of any Qualified Fund's federal, state, or local tax returns, and to participate with the Company on behalf of the Qualified Funds in such audits and related inquiries. The Trustee further agrees to provide the Company with any additional information in its possession regarding the Master Trust which may be requested by the Company to be furnished in an audit of the Company's federal, state, or local tax returns within 30 days of receipt of notice of audit but in no event less than 15 days prior to the commencement of any audit. In addition, the Trustee shall file with the PUCO, within thirty days of the filing thereof with a State or Federal agency, copies of all documents that the Master Trust is required to file with any State or Federal agency (other than the PUCO), including without limitation tax returns. 7.07 Liability. (a) The Trustee shall be liable only --------- for such Trustee's own acts or omissions (and those of its officers and employees) occasioned by the willful misconduct or negligence of such Trustee (or that of its officers and employees). (b) Notwithstanding anything contained in this Agreement to the contrary, the Trustee agrees to refrain from authorizing or carrying out transactions that would constitute "self-dealing" under Code Section 468A(e) (5) or Code Section -27- 4951 (or any applicable successor provisions). If the Trustee authorizes or carries out any transaction in violation of the provisions of this clause (b), the Trustee (and not the Master Trust or any Qualified Fund) shall be liable for any tax imposed on the Master Trust, any Qualified Fund, or the Trustee pursuant to Code Section 4951 (or any applicable successor provision) and for any loss or damage sustained by the Master Trust, any Qualified Fund, or the Company; provided, however, that the Trustee shall have no such liability with respect to transactions authorized or carried out pursuant to specific written instructions of the Company. (c) The Company shall indemnify the Trustee and hold it harmless against any and all claims, losses, liabilities, excise taxes, damages or expenses (including reasonable attorneys' fees and expenses) howsoever arising from or in connection with this Agreement or the responsible performance of its duties hereunder, together with any income taxes imposed on the Trustee as a result of any indemnity paid to it hereunder, provided that nothing contained herein shall require that the Trustee be indemnified for any liability imposed pursuant to clauses (a) or (b) of this Section 7.07. Nothing contained herein shall limit or in any way impair the right of the Trustee to indemnification under any other provision of this Agreement. VIII. INVESTMENTS ----------- 8.01 Appointment of Investment Manager(s). The ------------------------------------ Company may appoint one or more Investment Managers to direct the investment of all or part of the Funds under the Master Trust. -28- The Company shall also have the right to remove any such Investment Manager (s). Whenever such appointment is made, the Company shall provide written notice of such appointment to the Trustee, shall specify the portion of the Funds under the Master Trust with respect to which an Investment Manager has been designated, and shall instruct the Trustee to segregate into an Investment Account for each Fund those assets designated for management by the Investment Manager. Each Investment Account shall be divided into a separate subaccounts relating to each Designated Beneficiary and such other subaccounts as the Company from time to time shall specify. To the extent that assets are segregated into an Investment Account, the Trustee shall be released and relieved of all investment responsibilities with respect to the assets in the Investment Account, and as to such Investment Account the Trustee shall act as custodian. An Investment Manager shall certify in writing to the Trustee the identity of the person or persons authorized to give instructions or directions to the Trustee on its behalf, including specimen signatures. The Trustee may continue to rely upon all such certifications unless otherwise notified in writing by the Company or an Investment Manager, as the case may be. 8.02 Direction by Investment Manager(s). An ---------------------------------- Investment Manager appointed by the Company to manage an Investment Account shall have authority, subject to the limitations set forth in Schedule A hereto, to manage and to direct the acquisition and disposition of the assets of the Funds under the Master Trust, or a portion thereof, as the case may be, -29- and, after notification of such appointment, the Trustee shall exercise the powers set forth in Article X hereof with respect to those assets only when, if, and in the manner directed by the Company (or, during the continuance of a Default, by one or more Designated Beneficiaries) in writing, and shall not be under any obligation to invest or otherwise manage any assets in the Investment Account. An Investment Manager shall have the power and authority, exercisable in its sole discretion at any time, and from time to time, to issue and place orders for the purchase or sale of portfolio securities directly with qualified brokers or dealers. The Trustee, upon proper notification from an Investment Manager, shall settle the transactions in accordance with the appropriate trading authorizations. Written notification of the issuance of each such authorization shall be given promptly to the Trustee by an Investment Manager, and such Investment Manager shall cause the settlement of such transaction to be confirmed in writing to the Trustee, and to the Company, by the broker or dealer. Such notification shall be proper authority for the Trustee to pay for portfolio securities purchased against receipt thereof and to deliver portfolio securities sold against payment therefor, as the case may be. All directions to the Trustee by an Investment Manager shall be in writing and shall be signed by a person who has been certified by such Investment Manager pursuant to Section 8.01 hereof as authorized to give instructions or directions to the Trustee. Should an Investment Manager at any time elect to place security transactions directly with a broker or dealer, the -30- Trustee shall not recognize such transaction unless and until it has received instructions or confirmation of such fact from an Investment Manager. Should an Investment Manager direct the Trustee to utilize the services of any person with regard to the assets under its management or control, such instructions shall be in writing and shall specifically set forth the actions to be taken by the Trustee as to such services. In the event that an Investment Manager places security transactions directly or directs the utilization of a service, such Investment Manager shall be solely responsible for the acts of such persons. The sole duty of the Trustee as to such transactions shall be incident to its duties as custodian. The authority of an Investment Manager and the terms and conditions of the appointment and retention of an Investment Manager(s) shall be the responsibility solely of the Company, and the Trustee shall not be deemed to be a party to, or to have any obligations under, any agreement with an Investment Manager. Any duty of supervision or review of the acts, omissions or overall performance of the Investment Manager(s) shall be the exclusive responsibility of the Company, and the Trustee shall have no duty to review any securities or other assets purchased by an Investment Manager, or to make suggestions to an Investment Manager or to the Company with respect to the exercise or nonexercise of any power by an Investment Manager; provided, however, that the Trustee shall keep complete records of all transactions in accordance with Section 7.05 hereof (whether conducted by the Trustee or an Investment Manager) and shall not -31- carry out any instruction from an Investment Manager which would violate the investment standards set forth in Schedule A hereto. Nothing contained in this Section 8.02 shall be deemed to authorize any Investment Manager as such to direct or otherwise cause assets to be transferred between Funds or subaccounts. Any investment authorization shall at all times be subject to the investment standards set forth in Schedule A hereto. IX. TRUSTEE'S GENERAL POWER ----------------------- The Trustee shall have, with respect to the Master Trust, the following powers, all of which powers are fiduciary powers to be exercised in a fiduciary capacity and in the best interests of this Master Trust and the purposes hereof, namely: 9.01 Registration of Securities. To hold any stocks, -------------------------- bonds, securities, and/or other property in the name of a nominee, in a street name, or by other titleholding device, without indication of trust and generally to exercise the powers of an owner, including without limitation the power to vote in accordance with instructions provided by the Company, with respect to any such property whether so held or held in its own name, as Trustee. 9.02 Borrowing. To borrow money in such amounts and --------- upon such terms as the Company may authorize in writing as necessary to carry out the purposes of this Master Trust, and to pledge any securities or other property for the repayment of any such loan as the Company may direct. -32- 9.03 Retention and Removal of Professional and ----------------------------------------- Employee Services. To employ (upon authorization by the Company) - ----------------- attorneys, accountants, custodians, engineers, contractors, clerks and agents to carry out the purposes of this Master Trust. The cost of any such employment shall be an administrative cost. 9.04 Delegation of Ministerial Powers. To delegate to -------------------------------- other persons, as agents of the Trustee, such ministerial powers and duties as the Trustee may deem to be advisable. 9.05 Powers of Trustee to Continue Until Final ----------------------------------------- Distribution. To exercise any of such powers after the date on - ------------ which the principal and income of the Funds under the Master Trust shall have become distributable and until such time as the entire principal of, and income from, the Master Trust shall have been actually distributed by the Trustee. It is intended that distribution of one or more of the Funds under the Master Trust will occur as soon as possible after termination of the Master Trust or any Fund, subject, however, to the limitations contained in Article V hereof. 9.06 Discretion in Exercise of Powers. To do any and -------------------------------- all other acts which the Trustee shall deem proper to effectuate the powers specifically conferred upon it by this Agreement, provided, however, that the Trustee may not do any act or participate in any transaction which would: (1) Contravene any provision of this Agreement or any Supplement hereto; (2) Violate the terms and conditions of any instructions provided in a written statement of the Company or, if -33- applicable, of any Designated Beneficiary, provided such instructions are not inconsistent with this Agreement or any Supplement; (3) Eliminate or disqualify the status of the Qualified Funds (or any of them) as Qualified Decommissioning Reserve Funds under Section 468A (or any applicable successor provision) of the Code; or (4) Constitute an investment of the Funds (i) in the Company or an affiliate of the Company, (ii) in securities issued by any owner of the Perry Nuclear Power Plant or the Beaver Valley Power Station or (iii) in the securities issued in connection with the Sale/Leaseback Transactions. 9.07 Deposition of Funds. To the extent it shall ------------------- constitute a Permitted Investment or shall be temporary pending further investment, to invest in common trust funds maintained by the Trustee or its affiliate and to deposit funds in interest bearing account deposits maintained by or savings certificates issued by Mellon Bank, N.A. in its separate corporate capacity, or in any other banking institution affiliated with Mellon Bank, N.A.; provided, however, that the assets of a Qualified Fund may only be so deposited if the requirements of Applicable Tax Law are met. 9.08 Market Inventory Funds. To maintain and operate ---------------------- one or more market inventory funds as a vehicle to exchange securities among Funds without alienating the property from the Trust. -34- 9.09 Loaning of Securities. To the extent it shall --------------------- constitute a Permitted Investment, to loan securities (including securities held in a common trust fund maintained by the Trustee or an affiliate) to brokers or dealers or other borrowers under such terms and conditions as the Trustee, in its absolute discretion, deems advisable, to secure the same in any manner permitted by law and the provisions of this Agreement, and during the term of any such loan, to permit the loaned securities to be transferred into the name of and voted by the borrowers or others, and, in connection with the exercise of the powers hereinabove granted, to hold any property deposited as collateral by the borrower pursuant to any master loan agreement in bulk or otherwise, together with the unallocated interests of other lenders, and to liquidate and retain any such property upon the default of the borrower, and to receive compensation therefor out of any amount paid by or charged to the account of the borrower. 9.10 Retention of Uninvested Cash. To hold uninvested ---------------------------- cash awaiting investment and such additional cash balances as it shall deem reasonable or necessary, without incurring any liability for the payment of interest thereon. X. TRUSTEE'S INVESTMENT POWERS --------------------------- 10.01 General Investment Powers. The Trustee ------------------------- recognizes the authority of an Investment Manager to manage, invest, and reinvest the assets in an Investment Account pursuant to an Investment Manager Agreement and as provided in Article VIII of this Agreement, and the Trustee agrees to cooperate with any Investment Manager as deemed necessary to accomplish these -35- tasks. Notwithstanding the foregoing, to the extent that the assets of the Funds under the Master Trust have not been segregated into an Investment Account to be invested by an Investment Manager, the Trustee, subject to the limitations contained in Schedule A hereto, shall have the power to invest such assets in accordance with the written directions of the Company (or during the continuance of a Default, of one or more Designated Beneficiaries) and, as to Qualified Funds, in conformity with the limitations set forth in Section 468A of the Code and the regulations thereunder. XI. MISCELLANEOUS ------------- 11.01 Headings. The section headings set forth in -------- this Agreement and the Table of Contents are inserted for convenience of reference only and shall be disregarded in the construction or interpretation of any of the provisions of this Agreement. 11.02 Particular Words. Any word contained in the ---------------- text of this Agreement shall be read as the singular or plural and as the masculine, feminine, or neuter as may be applicable or permissible in the particular context. Unless otherwise specifically stated, the word "person" shall be taken to mean and include an individual, partnership, association, trust, company, or corporation. 11.03 Severability of Provisions. If any provision of -------------------------- this Agreement or its application to any person or entity or in any circumstances shall be invalid and unenforceable, the application of such provision to persons and in circumstances -36- other than those as to which it is invalid or unenforceable, and the other provisions of this Agreement, shall not be affected by such invalidity or unenforceability. 11.04 Delivery of Notices Under Agreement. Any ----------------------------------- notice, direction or instruction required by this Agreement to be given to the Company or the Trustee shall be deemed to have been properly given when mailed, postage prepaid, by registered or certified mail, to the person to be notified as set forth below: If to the Company: OHIO EDISON COMPANY 76 South Main Street Akron, Ohio 44308 Attention: Treasurer If to the Trustee: Mellon Bank, N.A. One Mellon Bank Center Pittsburgh, Pennsylvania 15258 Attention: Corporate Trust Department The Company or the Trustee may change the above address by delivering notice thereof in writing to the other party. 11.05 Alterations and Amendments. The Trustee and the -------------------------- Company understand and agree that modifications or amendments may be required to this Agreement, and to the exhibits and schedules hereto, from time to time to effectuate the purpose of the Master Trust and to comply with Applicable Law, Applicable Tax Law, any Order, any changes in tax laws, regulations or rulings (whether published or private) of the Service and any similar state taxing authority, and any other changes in the laws applicable to the Company or the Units. This Agreement, and the exhibits and schedules hereto, may be altered or amended to the extent -37- necessary or advisable to effectuate such purposes or to comply with such Applicable Law, Applicable Tax Law, Order or changes; provided, however, no such alteration or amendment may be made which adversely affects a Designated Beneficiary or any other person named in a Supplement in any material way without their prior written approval unless the failure to make such alteration or amendment could subject the Master Trust, the Trustee or the Company to fines, penalties or sanctions. If the only consequence of a failure to make such alteration or amendment would be the loss of a financial benefit that would accrue to the Master Trust or the Company if such change or alteration were made, such result shall not be construed as subjecting the Master Trust, the Trustee or the Company to fines, penalties or sanctions for purposes of the foregoing proviso. Otherwise, this Agreement, and the exhibits and schedules hereto, subject to and in conformity with Section 15 of any applicable Supplement, may be amended, modified, or altered for any purpose requested by the Company so long as such amendment, modification, or alteration does not affect the use of the assets of any Fund or subaccount to pay the costs of Decommissioning to which they are dedicated. Any alteration or amendment to, or modification of, this Agreement or an exhibit hereto must be in writing and signed by the Company and the Trustee. Schedules to this Agreement may be amended, modified or altered by delivery of such amended, modified or altered schedule to the Trustee together with notice that such amended, modified or altered schedule shall be -38- effective forthwith or at such later date as specified in the notice. The Trustee shall execute any such alteration, modification or amendment required to be executed by it and shall accept and be governed by any amended, modified or altered schedule delivered to it but shall have no duty to inquire or make any investigation as to whether any amendment, modification or alteration is consistent with this Section 11.05. Notwithstanding the foregoing, no alteration, modification or amendment to this Agreement or any exhibit or schedule hereto shall have any effect whatsoever if it shall fail to comply with the terms and conditions set forth in the proviso to the second sentence of the first paragraph of this Section 11.05 and those of Section 5.1 of each Supplement then in effect. 11.06 Successors and Assigns. Subject to the ---------------------- provisions of Sections 2.09 and 7.01, this Agreement shall be binding upon and inure to the benefit of the Company, the Trustee and their respective successors, assigns, personal representatives, executors and heirs. 11.07 Governing Law; Jurisdiction; Certain Waivers. -------------------------------------------- The Master Trust and all questions pertaining to its validity, construction, and administration shall be determined in accordance with the laws of the State of Ohio to the extent not superseded by Federal law. 11.08 Accounting Year. The Master Trust shall operate --------------- on an accounting year which coincides with the calendar year, January 1 through December 31. -39- 11.09 Counterparts. This Agreement may be executed in ------------ any number of counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument. 11.10 Decommissioning Liability. Nothing in this ------------------------- Agreement or in any Supplement is intended to impose any responsibility on the Trustee, on any Designated Beneficiary or any other person named in a Supplement for overseeing or paying the cost of the Decommissioning of the Units or any of them other than, in the case of the Trustee, the disbursement of funds in accordance with Article V hereof. 11.11 Aggregate Balance of the Fund. Notwithstanding ----------------------------- any other provision of this Agreement, the aggregate balance of the subaccounts with respect to each Designated Beneficiary at any time shall not be reduced to an amount less than the aggregate sum of the Minimum Amount in effect at such time with respect to such Designated Beneficiary. -40- IN WITNESS WHEREOF, the Company and the Trustee have set their hands and seals to this Agreement as of the day and year first above written. OHIO EDISON COMPANY By: R. H. Marsh ------------------------ Attest: G. F. LaFlame -------------------- MELLON BANK, N.A. By: E. Kleckner ---------------------- Attest: Phyllis K. Kokkila ------------------ -41- COMMONWEALTH OF PENNSYLVANIA ) ) ss: COUNTY OF ALLEGHENY ) I, Denise A. Fuhrer a Notary Public in and for the aforesaid jurisdiction, do hereby certify that Earl Kleckner and Phyllis Kokkila, who are personally known to me to be the persons who executed the foregoing Master Decommissioning Trust Agreement, personally appeared before me in the aforesaid jurisdiction, and as Vice President and Vice President of Mellon Bank, N.A., and by virtue of the power and authority vested in them, acknowledged the same to be the act and deed of Mellon Bank, N.A., and they executed the same as such. Given under my hand and seal this 19th day of January 1994. (NOTARIAL SEAL) Denise A. Fuhrer, Notary Public Pittsburgh, Alleheny County My Commission Expires Dec. 3, 1994 Member, Pennsylvania Association of Notaries -42- SCHEDULE A Perry No. 1: - ------------ Qualified Fund: Investments permitted from time to time under Section 468A of the Code and Regulations thereunder, unless, with respect to a particular Qualified Fund subaccount, the investments permitted with respect to the related Perry No. 1 Nonqualified Fund subaccount are more restrictive, in which case, the investments permitted with respect to the related Perry No. 1 Nonqualified Fund subaccount shall control as to such Qualified Fund subaccount. Nonqualified Funds: For each subaccount for a Designated Beneficiary, investments permitted by the Participation Agreement for the March 1987 Sale/Leaseback Transaction to which such Designated Beneficiary is a party as evidenced from time to time by a written schedule approved by such Designated Beneficiary. For each subaccount for which there is no Designated Beneficiary, there is no restriction on permitted investments other than as imposed by Applicable Law. Perry No. 2: - ------------ Qualified Fund: Investments permitted from time to time under Section 468A of the Code and Regulations thereunder, unless the investments permitted with respect to Perry No. 2 Nonqualified Funds are more restrictive, in which case, the investments permitted with respect to the Perry No. 2 Nonqualified Funds shall control. Nonqualified Funds: No restrictions on permitted investments other than as imposed by Applicable Law. Beaver Valley No. 1 - ------------------- Qualified Fund: Investments permitted from time to time under Section 468A of the Code and Regulations thereunder, unless the investments permitted with respect to the Beaver Valley No. 1 -1- Nonqualified Funds are more restrictive, in which case, the investments permitted with respect to the Beaver Valley No. 2 Nonqualified Funds shall control. Nonqualified Fund: No restrictions on permitted investments other than as imposed by Applicable Law. Beaver Valley No. 2 - ------------------- Qualified Fund: Investments permitted from time to time under Section 468A of the Code and Regulations thereunder, unless, with respect to a particular Qualified Fund subaccount, the investments permitted with respect to the related Beaver Valley No. 2 Nonqualified Fund subaccount are more restrictive, in which case, the investments permitted with respect to the related Beaver Valley No. 2 Nonqualified Fund subaccount shall control as to such Qualified Fund subaccount. Nonqualified Fund: For each subaccount for a Designated Beneficiary, investments permitted by the Participation Agreement for the September 1987 Sale/Leaseback Transaction to which such Designated Beneficiary is a party as evidenced from time to time by a written schedule approved by such Designated Beneficiary. For each subaccount for which there is no Designated Beneficiary, there is no restriction on permitted investments other than as imposed by Applicable Law. -2- SCHEDULE B Perry No. 1: (Names of Owner Trustee and Owner Participants to be inserted) Perry No. 2: None. Beaver Valley No. 1: None: Beaver Valley No. 2: (Names of Owner Trustee and Owner Participants to be inserted) -1- EXHIBIT A CERTIFICATE NO. ------------------------- The undersigned [Authorized Representative of Ohio Edison Company (Company), an Ohio corporation, or Designated Beneficiary*] being duly authorized and empowered to execute and deliver this Certificate, hereby certifies that payments in the amounts and to the payees listed below are for obligations duly incurred for the Decommissioning of [insert name of Unit] and hereby directs the Trustee of the Ohio Edison Company Master Decommissioning Trust (Master Trust), pursuant to Article V of the Master Trust Agreement to pay to each payee listed, including the Company if so listed, (Payees) in Exhibit 1 hereto, the amounts set forth therein, and certifies that the payments requested are proper expenditures of the Master Trust. Accordingly, request is hereby made that the Trustee provide for the withdrawal of $____________ from the [insert name of Unit and Fund and Subaccount (s)] in order to permit payment of such sum to be made to the Payees. You are further requested to disburse such sum, once withdrawn, directly to such Payees in the following -1- manner: (CHECK/WIRE TRANSFER/ ) on or before _________, 19__. WITNESS MY HAND THIS ____ day of ________, 19 (OHIO EDISON COMPANY or Designated Beneficiary*) By__________________________ Authorized Representative * A Designated Beneficiary may execute and deliver a Certificate during the continuance of a Default but only as to Funds and subaccounts related to the Designated Beneficiary's Beneficial Interest in the Unit in Question. -2- EX-10 5 OE10K AMENDMENT NO. 1 TO ------------------ CAPCO TRANSMISSION FACILITIES AGREEMENT --------------------------------------- THIS AGREEMENT, effective as of the lst 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 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 amendments 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 -2- least one business day prior to the due 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 -3- 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. 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. -4- 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 ------------------------------ Doc. 17781 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. 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: (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. 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 corresponding 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. 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. Doc. 17783 EX-10 6 OE10K 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 Agreement 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 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 transactions 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 Agreement, the Basic Operating Agreement, and the aforesaid minutes of the Executive Committee. -2- 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 By: Terrence G. Linnert ------------------------- Title: Vice President ------------------------- Doc. 17784 EX-11 7 OE10K EXHIBIT 11 OHIO EDISON COMPANY CALCULATION OF FULLY DILUTED EARNINGS PER COMMON SHARE Year Ended December 31, ----------------------------- 1991 1992 1993 -------- -------- -------- (In thousands, except per share amounts) EARNINGS - -------- Income before cumulative effect ..... $264,823 $276,986 $ 24,523 Add: Tax benefit from employee stock ownership plan dividends ...... 3,404 5,592 - Less: Preferred and preference stock dividend requirements ......... 24,754 23,926 23,707 -------- -------- -------- Earnings before cumulative effect ... 243,473 258,652 816 Cumulative effect of a change in accounting ..................... - - 58,201 -------- -------- -------- Earnings after cumulative effect .... $243,473 $258,652 $ 59,017 ======== ======== ======== SHARES - ------ Weighted average number of common shares outstanding ......... 152,569 152,569 152,569 ======== ======== ======== Earnings per share of Common Stock: Before cumulative effect of a change in accounting ..................... $1.60 $1.70 $ .01 Cumulative effect of a change in accounting ..................... - - .38 ----- ----- ----- Earnings per share of Common Stock .. $1.60 $1.70 $ .39 ===== ===== ===== NOTE: These calculations are submitted in accordance with Securities Exchange Act of 1934 Release No. 9083 although not required by footnote 2 to paragraph 14 of APB Opinion No. 15 because they result in dilution of less than 3%. Statement of Differences ------------------------ Exhibit Number 11, Calculation of fully diluted earnings per common share, is not included in the printed document. EX-12 8 OE10K EXHIBIT 12 OHIO EDISON COMPANY CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
Year Ended December 31, -------------------------------------------- 1989 1990 1991 1992 1993 -------- -------- -------- -------- -------- (Dollars in Thousands) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items $361,026 $281,676 $264,823 $276,986 $ 24,523 Interest and other charges, before reduction for amounts capitalized 351,506 329,520 324,017 296,292 285,169 Provision for income taxes 151,056 170,804 173,725 147,407 32,431 Interest element of rentals charged to income (a) 132,744 126,804 125,777 117,224 104,700 -------- -------- -------- -------- -------- Earnings as defined $996,332 $908,804 $888,342 $837,909 $446,823 ======== ======== ======== ======== ======== FIXED CHARGES AS DEFINED IN REGULATION S-K: Interest on long-term debt $332,023 $293,993 $288,599 $275,835 $262,861 Other interest expense 8,810 25,545 27,696 13,958 16,445 Subsidiary's preferred stock dividend requirements 10,673 9,982 7,722 6,499 5,863 Adjustment to subsidiary's preferred stock dividends to state on a pre-income tax basis 6,408 6,009 5,018 3,420 7,659 Interest element of rentals charged to income (a) 132,744 126,804 125,777 117,224 104,700 -------- -------- -------- -------- -------- Fixed charges as defined $490,658 $462,333 $454,812 $416,936 $397,528 ======== ======== ======== ======== ======== CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES (b) 2.03 1.97 1.95 2.01 1.12 ==== ==== ==== ==== ==== - ------------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined. (b) These ratios exclude fixed charges applicable to the guarantee of the debt of a coal supplier aggregating $18,124,000, $16,922,000, $13,298,000, $9,762,000 and $8,565,000 for each of the five years ended December 31, 1993, respectively. -46-
EX-13 9 OE10K MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION RESULTS OF OPERATIONS Retail sales were at an all-time high for the Companies during 1993, increasing 4.1% over last year and 3.2% over the previous record set in 1991. During the year, the Companies' residential customers set a record for average kilowatt-hour usage at 8,660 kilowatt-hours. The increased sales pushed operating revenues to a new high--up 1.6% compared to 1992. Earnings per share of $.39 for 1993 were adversely affected by net nonrecurring charges amounting to $1.43 per share. Before giving effect to the nonrecurring charges, earnings were $1.82 per share compared to $1.70 in 1992. The nonrecurring charges reflect a $276,578,000 after-tax write-off in the fourth quarter due to the termination of Perry Unit 2, expected resolution of fuel cost recovery issues in Pennsylvania and costs associated with the Company's performance initiative. The effect on 1993 net income from these items was partially offset by a $58,201,000 credit from the cumulative effect of a change in accounting to accrue metered but unbilled revenue (see Note 2). As discussed in Note 3, the Companies will not participate in further construction of Perry Unit 2 and have abandoned it as a possible electric generating plant. The unit was approximately 50% complete when construction was suspended in 1985. The termination resulted in a $366,377,000 write-off of the Company's investment since the Company has determined that recovery from its customers is not likely. Penn Power expects to recover its investment in Perry Unit 2 from its customers. However, due to the anticipated delay in commencement of recovery and taking into account the expected rate treatment, Penn Power recognized an impairment to its Perry Unit 2 investment of $24,458,000. As a result, net income for the year ended December 31, 1993, was reduced by $248,743,000 ($1.63 per share of common stock). The Companies' continuing cost reduction efforts have resulted in steadily decreasing operating costs. Excluding applicable nonrecurring charges discussed above, total operation and maintenance expenses are lower than they were five years ago. The Companies closed six old coal-fired generating units in 1993 which will reduce operating costs and, more significantly, will decrease capital requirements over the next five years by approximately $100,000,000. Also, qualifying production group employees were offered an early retirement opportunity that, in combination with other work force reductions, is expected to produce annual savings of nearly $15,000,000. The following summarizes the sources of changes in operating revenues during 1993 and 1992 as compared to the previous year: 1993 1992 ---- ---- (In millions) Change in retail kilowatt-hour sales $ 95.9 $(26.3) Change in average retail electric price (37.8) (1.5) Sales to utilities (17.0) 5.0 Other (3.5) (3.8) ------ ------ Net Increase (Decrease) $ 37.6 $(26.6) ====== ====== -1- Total kilowatt-hour sales in 1993 increased slightly over 1992 due to the record retail sales mentioned above, which were offset by an 11.7% decrease in sales to other utilities. Kilowatt-hour sales to residential and commercial customers increased 7.2% and 4.7%, respectively, with sales to industrial customers showing a 1.3% gain. Increased sales to residential and commercial customers in 1993 reflect more extreme weather conditions compared to conditions during 1992 along with the addition of approximately 14,500 new customers. Excluding the effect of Sharon Steel, which shut down in November 1992, industrial sales increased 6.4% during 1993, which is indicative of an improving economy in the Companies' service area. The decrease in sales to other utilities reflects reduced demand for bulk power in the spot market coupled with reduced capacity available for sale intermittently due to outages at nuclear generating units in which the Companies share ownership. Total kilowatt-hour sales were up 1.5% in 1992 compared with 1991 primarily due to a 10.1% increase in sales to other utilities. The increase in nuclear operating costs over last year was primarily due to increased expenses resulting from forced and scheduled outages. Contributing to the increase were expenses associated with performance results at Perry Unit 1 during the year. As a result of mechanical failures, Perry produced electricity for less than half the year. The operating company is undertaking significant corrective actions, including additional maintenance work to be performed during the refueling outage currently in process and for the refueling outage scheduled for 1995. Work done during the outages is expected to enhance systems and improve Perry's performance. The 1993 increase in other operating costs was due to the performance initiative charges mentioned above ($39,000,000) and increased costs associated with the January 1, 1993, adoption of Statement of Financial Accounting Standards (SFAS) No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" ($18,000,000). These comparative increases were partially offset by last year's additional provision for uncollectible accounts. The 1992 increase compared to 1991 was due principally to a charge for an early retirement program offered to qualifying employees in that year and to the increase in the provision for uncollectible accounts. Lower depreciation charges in 1993 reflect a full year's effect of reduced depreciation rates approved as part of the Company's Rate Stabilization and Service Area Development Program, which was effective in July 1992. Penn Power's depreciation rates were reduced in 1993 as a result of an updated depreciation study filed with the Pennsylvania Public Utility Commission, which takes into consideration extended useful lives of certain generation and distribution facilities. General taxes were 7.1% higher in 1993 than in 1992 due primarily to higher property and gross receipts taxes. The change in net amortization of regulatory assets in 1993 compared with 1992 is due to the deferral of incremental costs resulting from the adoption of SFAS No. 106 and the amortization of regulatory liabilities. Both of these items were also part of the Company's rate stabilization program. Other income decreased in 1993 compared to 1992, due to last year's amortization of investment tax credits associated with disallowed Perry Unit 1 and Beaver Valley Unit 2 construction costs, as described in Note 1. Interest on long-term debt decreased in 1993 and 1992 compared to 1992 and 1991, respectively, as a result of long-term debt refinancings at lower rates. During 1993, the Companies issued approximately $609,000,000 principal amount of new debt at a weighted average cost of 6.77% and redeemed approximately $552,000,000 principal amount of debt with a weighted average cost of 8.59%. The 1993 increase in other interest expense compared to last year is due primarily to costs associated with the debt refinancings. The 1992 reduction in other interest expense, compared with 1991, reflects reduced short-term borrowing in 1992. -2- The electric utility industry is subject to the same inflationary pressures as those experienced by other industries. To the extent that the Companies incur additional costs or receive benefits resulting from the effects of inflation, those effects are generally reflected in the Companies' electric rates through the traditional rate making process. CAPITAL RESOURCES AND LIQUIDITY As indicated above, the Companies have taken aggressive action to reduce their capital costs by taking advantage of opportunities to optionally redeem high-cost debt and preferred stock. The embedded cost of debt outstanding, 8.27% at the end of 1993, was at its lowest level since 1979. The cost of preferred stock outstanding was 6.86% at the end of 1993, which was its lowest since 1974. As a result of these actions and excluding the nonrecurring charges mentioned above, the Companies' fixed charge coverage is at its highest level since 1987. Cash generated from operations reached a record level in 1993. It surpassed the previous record, achieved in 1991, by 6.8% and was 22.5% higher than 1992. Internally generated cash as a percentage of capital expenditures increased to 157.8% in 1993 from 37.7% in 1988. All cash requirements for 1993 were met internally, with cash and cash equivalents increasing by $145,000,000 during the year. All financing activities during the year were for refunding purposes, as discussed above. The Companies had approximately $160,000,000 of cash and temporary investments and $104,000,000 of short-term indebtedness at December 31, 1993. OES Fuel had approximately $193,000,000 of unused borrowing capability at the end of 1993 that was available for reloan to the Company. The Companies also had available $85,000,000 of unused short-term bank lines of credit. In addition, $132,000,000 of bank facilities that provide for borrowings on a short-term basis at the banks' discretion was available. OES Capital had approximately $16,000,000 of unused, short-term borrowing capability at December 31, 1993. During the last five years, the Companies spent approximately $1,100,000,000 in connection with their construction programs (excluding nuclear fuel). During that period, the Employee Stock Ownership Plan Trust was also funded with $200,000,000. The Companies' construction programs and capital lease requirements for the period 1994-1998 are currently estimated to be approximately $1,000,000,000 (excluding nuclear fuel), of which approximately $235,000,000 applies to 1994. The Companies have additional cash requirements of approximately $1,389,000,000 for the 1994-1998 period to meet maturities of, and sinking fund requirements for, long-term debt and preferred stock; of that amount, approximately $444,000,000 applies to 1994. Investments for additional nuclear fuel during the 1994-1998 period are estimated to be approximately $204,000,000, of which approximately $45,000,000 applies to 1994. During the same periods, the Companies' nuclear fuel investments are expected to be reduced by approximately $261,000,000 and $64,000,000, respectively, as the nuclear fuel is consumed. Also, the Companies have operating lease commitments of approximately $547,000,000 for the 1994-1998 period, of which approximately $102,000,000 relates to 1994. The Companies recover the cost of nuclear fuel consumed and operating leases through their electric rates. Sales by the Company of first mortgage bonds against property additions and of preferred stock require that applicable earnings coverage tests be met. With respect to the issuance of first mortgage bonds under the Company's first mortgage indenture, the availability of property additions is more restrictive than the earnings test at the present time and would limit the amount of first mortgage bonds issuable against property additions to $404,000,000. The Company is currently able to issue $868,000,000 -3- principal amount of first mortgage bonds against previously retired bonds without the need to meet the above restrictions. The Company could issue in excess of $1,000,000,000 of additional preferred stock before the end of the first quarter of 1994. For the remainder of 1994, however, the earnings coverage test contained in the Company's charter would preclude the issuance of additional preferred stock due to inclusion of the 1993 nonrecurring charges in the earnings test. Additional preferred stock capability is expected to be restored in January 1995. Reference is made to Note 1 for a discussion of the Companies' regulatory assets. Although the amounts recoverable from customers are significant, about 90% of these deferred costs are already reflected in the Companies' rates and are being recovered from customers over approximately 30 years. The remainder, which is deferred for recovery in future rate proceedings, would increase revenues by about 1% on an annual basis once they are included in customers' electric rates. In January 1994, the Central Area Power Coordination Group (CAPCO) companies reached a settlement in connection with a 1991 lawsuit against General Electric Company regarding the Perry Plant. The settlement provides for cash payments to the CAPCO companies and discounts on future purchases from General Electric. This settlement will not materially affect the Company's results of operations in future years. The CAPCO companies filed suit against Westinghouse Electric Corporation in 1991 alleging that six steam generators supplied by Westinghouse for the Beaver Valley Plant are defective and that replacement could be required earlier than their 40-year design life. The operating company has no current plans to replace the steam generators and is evaluating the feasibility of applying new technologies to repair the generators. If the generators would need to be replaced the capital costs to the CAPCO companies could range from $100,000,000 to $150,000,000 per unit based upon the costs other utilities have experienced. The Companies have a 52.5% interest in Beaver Valley Unit 1 and a 41.88% interest in Unit 2. The Clean Air Act Amendments of 1990 require significant reductions of sulfur dioxide (SO2) and oxides of nitrogen from the Companies' coal-fired generating units by 1995 and additional emission reductions by 2000. Compliance options include, but are not limited to, installing additional pollution control equipment, burning lower-emitting fuel, purchasing emission allowances from others, operating existing facilities in a manner which minimizes pollution and retiring facilities. In compliance plans submitted to the PUCO and to the Environmental Protection Agency (EPA), the Company stated that reductions for the years 1995 through 1999 are likely to be achieved by burning lower-sulfur fuel, generating electricity at its lower-emitting plants and/or purchasing emission allowances. The Company continues to evaluate its compliance plans and other compliance options as they arise. Plans for complying with the year 2000 reductions are less certain at this time. OUTLOOK The Company's Rate Stabilization and Service Area Development Program provides for base electric rates to remain at 1990 levels until at least 1997, absent any significant changes in regulatory, environmental or tax requirements. In addition, the Company has a goal not to increase base rates prior to the year 2000. The changing environment in the utility industry is posing competitive challenges for the Companies. Many of these challenges are a result of the passage of the Energy Policy Act of 1992. Others result from attempts by large users of electricity to choose their supplier. In order to meet competitive challenges that may lie ahead, the Companies are aggressively pursuing opportunities to reduce costs, increase revenues, and improve operating efficiencies, which, if successful, will enhance the Companies' competitive -4- position. The Companies are currently in the process of a comprehensive review of their business operations as part of a performance initiative, to further identify opportunities for improvement. The Companies are serving more customers than ever before with a work force that is at its lowest level since 1972. The Companies' operating results should continue to improve as a result of these activities. -5- OHIO EDISON COMPANY SELECTED FINANCIAL DATA
1993 1992 1991 1990 1989 ---- ---- ---- ---- ---- (In thousands, except per share amounts) Operating Revenues $2,369,940 $2,332,378 $2,358,946 $2,240,646 $2,162,720 ---------------------------------------------------------- Operating Income $525,330 $522,115 $550,452 $510,279 $543,659 ---------------------------------------------------------- Net Income $82,724 $276,986 $264,823 $281,676 $361,026 ---------------------------------------------------------- Earnings on Common Stock $59,017 $253,060 $240,069 $254,048 $332,932 ---------------------------------------------------------- Earnings per Share of Common Stock $0.39 $1.70 $1.60 $1.67 $2.18 Dividends Declared per Share of Common Stock $1.50 $1.50 $1.50 $1.73 $1.96 ---------------------------------------------------------- Total Assets $8,918,267 $7,830,026 $7,812,345 $7,841,621 $7,722,896 ---------------------------------------------------------- Preferred and Preference Stock Subject to Mandatory Redemption $ 45,500 $ 59,862 $ 65,582 $ 62,822 $ 89,562 ---------------------------------------------------------- Long-Term Debt $3,039,263 $3,121,647 $3,243,167 $3,105,248 $3,073,796 ---------------------------------------------------------- COMMON STOCK DATA The Company's Common Stock is listed on the New York and Chicago stock exchanges and is traded on other registered exchanges. PRICE RANGE OF COMMON STOCK 1993 1992 - --------------------------- ---- ---- First Quarter High-Low 25-3/8 22-1/8 20-7/8 18-3/4 ----------------------------------- Second Quarter High-Low 26 22-3/4 21 19 ----------------------------------- Third Quarter High-Low 25-7/8 24-3/8 22-3/4 20-3/4 ----------------------------------- Fourth Quarter High-Low 25-1/4 21 24 21-1/4 ----------------------------------- Yearly High-Low 26 21 24 18-3/4 Prices are based on reports published in The Wall Street Journal for New York Stock Exchange Composite Transactions. ----------------------- CLASSIFICATION OF HOLDERS OF COMMON STOCK AS OF DECEMBER 31, 1993 Holders of Record Shares Held ----------------- ------------------ Number % Number % ------- ------ ---------- ----- Individuals 128,005 83.48 55,241,397 36.21 Fiduciaries 23,260 15.17 9,054,076 5.93 Nominees 83 0.05 86,450,346 56.66 All Others 1,991 1.30 1,823,618 1.20 ----------------------------------------------- Total 153,339 100.00 152,569,437 100.00 ----------------------------------------------- As of January 31, 1994, there were 152,566 holders of 152,569,437 shares of the Company's Common Stock. Quarterly dividends of 37.5 cents per share were paid on the Company's Common Stock during 1993 and 1992. Information regarding retained earnings available for payment of cash dividends is given in Note 5A.
-6- OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 1993 1992 1991 ---- ---- ---- (In thousands, except per share amounts) OPERATING REVENUES $2,369,940 $2,332,378 $2,358,946 ---------- ---------- ---------- OPERATING EXPENSES AND TAXES: Fuel and purchased power 456,494 463,599 467,657 Nuclear operating costs 290,321 274,719 291,551 Other operating costs 474,241 440,425 412,476 ---------- ---------- ---------- Total operation and maintenance expenses 1,221,056 1,178,743 1,171,684 Provision for depreciation 217,980 223,497 238,853 General taxes 245,554 229,332 217,758 Amortization (deferral) of net regulatory assets (6,753) 18,333 13,515 Income taxes 166,773 160,358 166,684 ---------- ---------- ---------- Total operating expenses and taxes 1,844,610 1,810,263 1,808,494 ---------- ---------- ---------- OPERATING INCOME 525,330 522,115 550,452 ---------- ---------- ---------- OTHER INCOME AND EXPENSE: Perry Unit 2 termination (Note 3) (390,835) -- -- Income tax benefit from Perry Unit 2 termination 142,092 -- -- Other 19,921 36,283 18,725 ---------- ---------- ---------- Total other income (expense) (228,822) 36,283 18,725 ---------- ---------- ---------- TOTAL INCOME 296,508 558,398 569,177 ---------- ---------- ---------- NET INTEREST AND OTHER CHARGES: Interest on long-term debt 262,861 275,835 288,599 Deferred nuclear unit interest (8,518) (8,392) (8,387) Allowance for borrowed funds used during construction and capitalized interest (4,666) (6,488) (11,276) Other interest expense 16,445 13,958 27,696 Subsidiary's preferred stock dividend requirements 5,863 6,499 7,722 ---------- ---------- ---------- Net interest and other charges 271,985 281,412 304,354 ---------- ---------- ---------- INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING 24,523 276,986 264,823 Cumulative effect to January 1, 1993 of a change in accounting for unbilled revenues (net of income taxes of $33,632,000) (Note 2) 58,201 -- -- ---------- ---------- ---------- NET INCOME 82,724 276,986 264,823 PREFERRED AND PREFERENCE STOCK DIVIDEND REQUIREMENTS 23,707 23,926 24,754 ---------- ---------- ---------- EARNINGS ON COMMON STOCK $ 59,017 $ 253,060 $ 240,069 ========== ========== ========== EARNINGS PER SHARE OF COMMON STOCK: Before cumulative effect of a change in accounting $ .01 $1.70 $1.60 Cumulative effect to January 1, 1993 of a change in accounting for unbilled revenues (Note 2) .38 -- -- ---------- ---------- ---------- EARNINGS PER SHARE OF COMMON STOCK $ .39 $1.70 $1.60 ========== ========== ========== DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $1.50 $1.50 $1.50 ========== ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
-7- OHIO EDISON COMPANY CONSOLIDATED BALANCE SHEETS
At December 31, 1993 1992 ---- ---- (In thousands) ASSETS UTILITY PLANT: In service, at original cost $8,380,430 $7,931,403 Less--Accumulated provision for depreciation 2,732,527 2,550,400 ---------- ---------- 5,647,903 5,381,003 ---------- ---------- Construction work in progress-- Electric plant (Note 3) 182,894 479,289 Nuclear fuel 46,879 78,118 ---------- ---------- 229,773 557,407 ---------- ---------- 5,877,676 5,938,410 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 181,815 152,118 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents 159,690 14,212 Receivables-- Customers (less accumulated provisions of $6,907,000 and $6,432,000, respectively, for uncollectible accounts) (Note 2) 298,913 203,929 Other 42,428 39,074 Materials and supplies, at average cost-- Fuel 41,513 70,127 Other 87,689 100,542 Prepayments 72,889 86,040 ---------- ---------- 703,122 513,924 ---------- ---------- DEFERRED CHARGES: Regulatory assets 1,993,795 1,079,102 Unamortized sale and leaseback costs 110,656 105,350 Other 51,203 41,122 ---------- ---------- 2,155,654 1,225,574 ---------- ---------- $8,918,267 $7,830,026 ========== ========== CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Consolidated Statements of Capitalization): Common stockholders' equity $2,243,292 $2,408,164 Preferred stock-- Not subject to mandatory redemption 277,335 312,335 Subject to mandatory redemption 25,000 25,000 Preference stock subject to mandatory redemption. -- 4,500 Preferred stock of consolidated subsidiary-- Not subject to mandatory redemption 50,905 41,905 Subject to mandatory redemption 20,500 30,362 Long-term debt 3,039,263 3,121,647 ---------- ---------- 5,656,295 5,943,913 ---------- ---------- CURRENT LIABILITIES: Currently payable preferred and preference stock and long-term debt 444,170 305,465 Short-term borrowings (Note 6) 104,126 151,571 Accounts payable 127,895 112,128 Accrued taxes 107,687 126,414 Accrued interest 72,667 72,563 Other 141,251 97,917 ---------- ---------- 997,796 866,058 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes 1,798,551 603,123 Accumulated deferred investment tax credits 231,863 240,208 Property taxes 101,182 109,621 Other 132,580 67,103 ---------- ---------- 2,264,176 1,020,055 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 4 and 7) ---------- ---------- $8,918,267 $7,830,026 ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
-8- OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 1993 1992 ---- ---- (In thousands, except per share amounts) COMMON STOCKHOLDERS' EQUITY: Common stock, $9 par value, authorized 175,000,000 shares- l52,569,437 shares outstanding $1,373,125 $1,373,125 Other paid-in capital 727,865 731,793 Retained earnings (Note 5A) 322,821 490,564 Unallocated employee stock ownership plan common stock- 9,608,739 and 9,978,695 shares, respectively (Note 5B) (180,519) (187,318) ---------- ---------- Total common stockholders' equity 2,243,292 2,408,164 ---------- ---------- Number of Shares Optional Outstanding Redemption Price ---------------- ---------------------- 1993 1992 Per Share Aggregate ---- ---- ---------- --------- PREFERRED STOCK (Note 5C): Cumulative, $100 par value- Authorized 6,000,000 shares Not Subject to Mandatory Redemption: 3.85% 500,000 500,000 $100.00 $ 50,000 50,000 50,000 3.90% 152,510 152,510 103.63 15,804 15,251 15,251 4.40% 176,280 176,280 108.00 19,038 17,628 17,628 4.44% 136,560 136,560 103.50 14,134 13,656 13,656 4.56% 144,300 144,300 103.38 14,917 14,430 14,430 7.24% 363,700 363,700 101.98 37,090 36,370 36,370 7.36% 350,000 350,000 101.74 35,609 35,000 35,000 8.20% 450,000 450,000 103.30 46,485 45,000 45,000 8.64% -- 400,000 -- -- -- 40,000 9.12% -- 450,000 -- -- -- 45,000 Optional Redemption - February 1994 (50,000) -- --------- --------- -------- -------- ------- 2,273,350 3,123,350 233,077 177,335 312,335 Cumulative, $25 par value- Authorized 8,000,000 shares Not Subject to Mandatory Redemption: 7.75% 4,000,000 -- $ 25.00 100,000 100,000 -- --------- --------- -------- -------- ------- Total not subject to mandatory redemption 6,273,350 3,123,350 $333,077 277,335 312,335 ========= ========= ======== -------- ------- Cumulative, $100 par value- Subject to Mandatory Redemption (Note 5D): 8.45% 250,000 250,000 25,000 25,000 ========= ========= -------- ------- PREFERENCE STOCK: Cumulative, no par value- Authorized 8,000,000 shares Subject to Mandatory Redemption: 10.25% -- 5,400 -- 5,400 Redemption within one year -- (900) --------- --------- -------- ------- Total subject to mandatory redemption -- 5,400 -- 4,500 ========= ========= -------- ------- PREFERRED STOCK OF CONSOLIDATED SUBSIDIARY (Note 5C): Cumulative, $100 par value- Authorized 1,200,000 shares Not Subject to Mandatory Redemption: 4.24% 40,000 40,000 $103.13 $ 4,125 4,000 4,000 4.25% 41,049 41,049 105.00 4,310 4,105 4,105 4.64% 60,000 60,000 102.98 6,179 6,000 6,000 7.64% 60,000 60,000 101.42 6,085 6,000 6,000 7.75% 250,000 -- 100.00 25,000 25,000 -- 8.00% 58,000 58,000 102.07 5,920 5,800 5,800 8.48% -- 80,000 -- -- -- 8,000 9.16% -- 80,000 -- -- -- 8,000 --------- --------- -------- ------- ------- Total not subject to mandatory redemption 509,049 419,049 $ 51,619 50,905 41,905 ========= ========= ======== ------- ------- Subject to Mandatory Redemption (Note 5D): 7.625% 150,000 150,000 $107.63 $ 16,144 15,000 15,000 8.24% -- 45,000 -- -- -- 4,500 11.00% 3,616 11,616 102.75 372 362 1,162 11.50% -- 60,000 -- -- -- 6,000 13.00% 60,000 70,000 107.15 6,429 6,000 7,000 Redemption within one year (862) (3,300) --------- --------- -------- ------- ------- Total subject to mandatory redemption 213,616 336,616 $ 22,945 20,500 30,362 ========= ========= ======== ------- -------
-9- OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont.)
At December 31, 1993 1992 1993 1992 1993 1992 ---- ---- ---- ---- ---- ---- (In thousands) LONG-TERM DEBT (Note 5E): First mortgage bonds: Ohio Edison Company- Pennsylvania Power Company- 8.800% due 1993-96 27,600 36,800 4.375% due 1993 -- 9,000 12.750% due 1993-96 -- 12,250 9.000% due 1996 50,000 50,000 13.430% due 1994 30,000 30,000 8.000% due 1999 -- 12,000 12.740% due 1995 30,000 30,000 9.740% due 1999-2019 20,000 20,000 8.500% due 1996 150,000 150,000 7.875% due 2001 -- 12,000 8.750% due 1998 150,000 150,000 8.000% due 2001 -- 10,000 6.875% due 1999 150,000 150,000 7.625% due 2002 -- 12,000 8.250% due 1999 -- 37,630 7.500% due 2003 40,000 40,000 6.375% due 2000 80,000 -- 6.375% due 2004 50,000 -- 8.375% due 2001 -- 50,470 6.625% due 2004 20,000 -- 7.375% due 2002 120,000 120,000 8.750% due 2006 -- 15,000 7.500% due 2002 34,265 34,265 8.500% due 2022 50,000 50,000 8.250% due 2002 125,000 125,000 7.625% due 2023 40,000 -- ------- -------- 8.125% due 2003 -- 61,608 8.625% due 2003 150,000 150,000 6.875% due 2005 80,000 -- 8.500% due 2006 -- 47,595 8.375% due 2007 -- 56,865 9.750% due 2019 150,000 150,000 8.750% due 2022 100,000 100,000 7.625% due 2023 75,000 -- 7.875% due 2023 100,000 -- ---------- --------- Total first mortgage bonds 1,551,865 1,492,483 270,000 230,000 1,821,865 1,722,483 ---------- --------- ------- ------- --------- --------- Secured notes and obligations: Ohio Edison Company- Pennsylvania Power Company- 8.250% due 1993 -- 44,000 7.900% due 1993-2001 -- 950 7.300% due 1993-2003 -- 6,212 5.750% due 1993-2003 -- 2,850 9.345% due 1994 50,000 50,000 7.300% due 1993-2003 -- 238 8.380% due 1996 87,987 119,510 11.080% due 1995 -- 20,000 8.980% due 2003 -- 1,000 12.450% due 1995 -- 20,000 8.800% due 2013 -- 50,000 4.750% due 1998 850 -- 8.980% due 2013 -- 13,800 6.750% due 1998-2007 -- 10,600 9.200% due 2014 50,000 50,000 6.080% due 2000 23,000 -- 10.500% due 2015 60,000 60,000 5.400% due 2013 1,000 -- 10.625% due 2015 40,000 40,000 8.980% due 2013 -- 4,200 7.450% due 2016 47,725 47,725 9.000% due 2013 -- 1,000 7.100% due 2018 26,000 26,000 12.000% due 2014 12,700 12,700 7.000% due 2021 69,500 69,500 8.125% due 2015 14,250 14,250 7.150% due 2021 443 443 5.400% due 2017 10,600 -- 7.625% due 2023 50,000 50,000 7.150% due 2017 17,925 17,925 8.100% due 2023 30,000 30,000 5.900% due 2018 16,800 16,800 7.750% due 2024 108,000 108,000 8.100% due 2018 10,300 10,300 5.625% due 2029 50,000 -- 8.100% due 2020 5,200 5,200 5.950% due 2029 56,212 -- 7.150% due 2021 14,482 14,482 5.450% due 2033 14,800 -- 6.450% due 2027 14,500 14,500 -------- -------- 5.450% due 2028 6,950 -- 5.950% due 2029 238 -- ------- ------- 740,667 766,190 148,795 165,995 889,462 932,185 -------- -------- ------- ------- OES Fuel- 3.46% weighted average interest rate 131,611 169,416 --------- --------- Total secured notes and obligations 1,021,073 1,101,601 --------- --------- Unsecured notes: Ohio Edison Company- 9.440% due 1995 75,000 75,000 7.380% due 1997 100,000 100,000 8.585% due 1997 50,000 50,000 5.650% due 2012 50,000 50,000 4.250% due 2014 50,000 50,000 2.850% due 2015 50,000 50,000 3.125% due 2018 56,000 56,000 4.650% due 2018 57,100 57,100 3.450% due 2032 53,400 53,400 ------- ------- Total unsecured notes 541,500 541,500 541,500 541,500 ------- ------- --------- --------- Capital lease obligations (Note 4) 59,312 65,274 --------- --------- Net unamortized discount on debt (11,179) (7,946) --------- --------- Long-term debt due within one year (393,308) (301,265) --------- --------- Total long-term debt 3,039,263 3,121,647 --------- --------- TOTAL CAPITALIZATION $5,656,295 $5,943,913 ======================================================================================================================== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
-10- OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1993 1992 1991 ---- ---- ---- (In thousands) Balance at beginning of year. . . . . . $490,564 $462,087 $449,810 Net income. . . . . . . . . . . . . . . 82,724 276,986 264,823 Tax benefit from ESOP dividends . . . . 5,256 5,592 3,404 -------- -------- -------- 578,544 744,665 718,037 _________________________________________________________________________ Cash dividends on preferred and preference stock . . . . . . . . . . . 23,275 23,874 24,338 Cash dividends on common stock. . . . . 228,855 228,855 228,855 Premium on redemption of preferred stock 3,593 1,372 2,757 -------- -------- -------- 255,723 254,101 255,950 -------- -------- -------- Balance at end of year (Note 5A) $322,821 $490,564 $462,087 _________________________________________________________________________ CONSOLIDATED STATEMENTS OF CAPITAL STOCK AND OTHER PAID-IN CAPITAL Preferred and Preference Stock ------------------------------------------- Not Subject to Subject to Common Stock Unallocated Mandatory Redemption Mandatory Redemption --------------------------------- --------------------- -------------------- of Shares Value Capital Stock of Shares Value of Shares Value ----------- ---------- -------- ----------- ---------- --------- --------- --------- (Dollars in thousands) Balance, January 1, 1991 152,569,437 $1,373,125 $733,081 $ (10,857) 5,042,399 $354,240 782,416 $ 86,342 ESOP Purchase Transactions (189,143) Allocation of ESOP Shares 4,941 Sale of Market Auction Preferred Stock (1,140) 500,000 50,000 Sale of 8.45% Preferred Stock 250,000 25,000 Redemptions-- Series B (2,000,000) (50,000) $102.50 Series (1,800) (1,800) 8.24% Series (5,000) (500) 11.00% Series (8,000) (800) 11.50% Series (148) (165,000) (16,500) 13.00% Series (10,000) (1,000) 13.50% Series (200,000) (20,000) 15.00% Series (6,400) (640) ______________________________________________________________________________________________________________________________ Balance, December 31, 1991 152,569,437 1,373,125 731,793 (195,059) 3,542,399 354,240 636,216 70,102 Allocation of ESOP Shares 7,741 Sale of 7.625% Preferred Stock 150,000 15,000 Redemptions-- $102.50 Series (1,800) (1,800) 8.24% Series (5,000) (500) 11.00% Series (8,000) (800) 15.00% Series (54,400) (5,440) 10.50% Series (100,000) (10,000) 11.50% Series (15,000) (1,500) 13.00% Series (10,000) (1,000) ______________________________________________________________________________________________________________________________ Balance, December 31, 1992 152,569,437 1,373,125 731,793 (187,318) 3,542,399 354,240 592,016 64,062 Allocation of ESOP Shares 6,799 Sale of 7.75% Class A Preferred Stock (3,361) 4,000,000 100,000 Sale of 7.75% Preferred Stock (345) 250,000 25,000 Redemptions-- $102.50 Series (216) (5,400) (5,400) 8.24% Series (45,000) (4,500) 8.48% Series (6) (80,000) (8,000) 8.64% Series (400,000) (40,000) 9.12% Series (450,000) (45,000) 9.16% Series (80,000) (8,000) 11.00% Series (8,000) (800) 11.50% Series (60,000) (6,000) 13.00% Series (10,000) (1,000) _____________________________________________________________________________________________________________________________ Balance, December 31, 1993 152,569,437 $1,373,125 $727,865 $(180,519) 6,782,399 $378,240 463,616 $46,362 ============================================================================================================================= The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
-11- OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1993 1992 1991 ---- ---- ---- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income $ 82,724 $ 276,986 $ 264,823 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation 217,980 223,497 238,853 Nuclear fuel and lease amortization 59,858 85,419 85,754 Deferred income taxes, net (26,233) 18,221 58,964 Investment tax credits, net (8,345) (17,857) (2,776) Deferred revenue - 19,517 37,757 Allowance for equity funds used during construction (4,257) (3,025) (3,050) Deferred fuel costs, net (1,078) 5,130 1,411 Perry Unit 2 termination 390,835 - - Cumulative effect of a change in accounting for unbilled revenues (58,201) - - Other amortization, net 1,184 9,941 5,128 --------- ---------- -------- Internal cash before dividends 654,467 617,829 686,864 Receivables (1,962) 2,278 (21,231) Materials and supplies 41,467 (14,889) (2,874) Accounts payable 9,823 (19,986) (4,042) Other 19,088 4,727 18,359 --------- ---------- -------- Net cash provided from operating activities 722,883 589,959 677,076 --------- ---------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing-- Preferred stock 121,294 15,000 73,863 Long-term debt 765,358 937,797 1,034,801 Short-term borrowings, net - 56,716 - Redemptions and Repayments-- Preferred and preference stock 122,502 22,412 94,063 Long-term debt 773,128 1,065,377 756,520 Short-term borrowings, net 47,445 - 227,184 Dividend Payments-- Common stock 224,943 234,188 229,686 Preferred and preference stock 20,926 23,786 23,899 --------- --------- --------- Net cash used for financing activities 302,292 336,250 222,688 --------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions 256,746 241,508 226,153 Investment in employee stock ownership plan - - 160,000 Sale and leaseback restructuring fees 10,417 37,654 23,723 Other 7,950 14,133 15,062 --------- --------- --------- Net cash used for investing activities 275,113 293,295 424,938 --------- --------- --------- Net increase (decrease) in cash and cash equivalents 145,478 (39,586) 29,450 Cash and cash equivalents at beginning of year 14,212 53,798 24,348 --------- --------- --------- Cash and cash equivalents at end of year $ 159,690 $ 14,212 $ 53,798 ========= ========= ========= SUPPLEMENTAL CASH FLOWS INFORMATION: Cash Paid During the Year-- Interest (net of amounts capitalized) $ 262,410 $ 290,420 $ 286,005 Income taxes 94,272 134,768 113,712 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
-12- OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31, 1993 1992 1991 ---- ---- ---- (In thousands) GENERAL TAXES: Real and personal property $124,709 $111,533 $103,298 State gross receipts 97,348 94,415 90,961 Social security and unemployment 15,626 15,166 14,494 Other 7,871 8,218 9,005 -------- -------- -------- Total general taxes $245,554 $229,332 $217,758 ======== ======== ======== PROVISION FOR INCOME TAXES: Currently payable- Federal $ 61,920 $132,712 $102,017 State 5,544 14,331 15,520 -------- -------- -------- 67,464 147,043 117,537 -------- -------- -------- Deferred, net- Federal 489 17,586 62,480 State 6,455 635 (3,516) -------- -------- -------- 6,944 18,221 58,964 -------- -------- -------- Investment tax credits, net of amortization (8,345) (17,857) (2,776) -------- -------- -------- Total provision for income taxes $ 66,063 $147,407 $173,725 ======== ======== ======== INCOME STATEMENT CLASSIFICATION OF PROVISION FOR INCOME TAXES: Operating income $166,773 $160,358 $166,684 Other income (134,342) (12,951) 7,041 Cumulative effect of a change in accounting 33,632 -- -- -------- -------- -------- Total provision for income taxes $ 66,063 $147,407 $173,725 ======== ======== ======== RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES: Book income before provision for income taxes $148,787 $424,393 $438,548 ======== ======== ======== Federal income tax expense at statutory rate $ 52,075 $144,294 $149,106 Increases (reductions) in taxes resulting from- Excess of book over tax depreciation -- 19,741 20,043 Amortization of investment tax credits (8,345) (32,092) (8,284) State income taxes net of federal income tax benefit 7,799 9,878 7,923 Amortization of tax regulatory assets 15,412 -- -- Other, net (878) 5,586 4,937 -------- -------- -------- Total provision for income taxes $ 66,063 $147,407 $173,725 ======== ======== ======== SOURCES OF DEFERRED TAX EXPENSE: Excess of tax over book depreciation, net $ 27,627 $ 58,306 Difference between tax and book revenue, net (9,084) (18,292) Alternative minimum tax credits utilized 12,467 29,749 Other, net (12,789) (10,799 -------- -------- Net deferred tax expense $ 18,221 $ 58,964 ======== ======== ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31, 1993: Property basis differences $ 983,603 Allowance for equity funds used during construction 282,040 Deferred nuclear expense 275,832 Customer receivables for future income taxes 244,304 Deferred sale and leaseback costs 90,955 Unamortized investment tax credits (85,459) Other 7,276 ---------- Net deferred income tax liability $1,798,551 ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
-13- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: The consolidated financial statements include Ohio Edison Company (Company) and its wholly owned subsidiaries, Pennsylvania Power Company (Penn Power), OES Capital, Incorporated (OES Capital) and OES Fuel, Incorporated (OES Fuel). All significant intercompany transactions have been eliminated. The Company and Penn Power (Companies) follow the accounting policies and practices prescribed by the Public Utilities Commission of Ohio (PUCO), the Pennsylvania Public Utility Commission (PPUC) and the Federal Energy Regulatory Commission (FERC). REVENUES- The Companies' retail customers are metered on a cycle basis. Revenue was recognized for electric service based on meters read through the end of the year for years prior to 1993. Beginning in 1993, revenue is recognized to include unbilled sales through the end of the year (see Note 2). Accounts receivable from customers include approximately $105,234,000 relating to metered but unbilled revenues through December 31, 1993. Receivables from customers include sales to residential, commercial and industrial customers located in the Companies' service area and sales to wholesale customers. There was no material concentration of receivables at December 31, 1993 or 1992, with respect to any particular segment of the Companies' customers. FUEL COSTS- The Companies recover fuel-related costs not otherwise included in base rates from retail customers through separate energy rates. Any over or under collection resulting from the operation of these rates are included as adjustments to subsequent energy rates. Accordingly, the Companies defer the difference between actual fuel- related costs incurred and the amounts currently recovered from their customers. UTILITY PLANT AND DEPRECIATION- Utility plant reflects the original cost of construction, including payroll and related costs such as taxes, pensions and other fringe benefits, administrative and general costs and allowance for funds used during construction (AFUDC). The Companies provide for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annual composite straight-line rate for electric plant was approximately 3.0% in 1993, 1992 and 1991. The Companies recognize approximately $5,000,000 annually (as depreciation expense) for future decommissioning costs applicable to their ownership and leasehold interests in nuclear generating units. The Companies' share of the future obligation to decommission these units in current dollars is estimated to be approximately $382,000,000. The Companies have recovered approximately $43,000,000 from customers through December 31, 1993; such amounts are reflected in the reserve for depreciation on the Consolidated Balance Sheet. If the actual costs of decommissioning the units -14- exceed the accumulated amounts recovered from customers, the Companies expect that difference to be recoverable from their customers. The Companies have approximately $29,700,000 invested in external decommissioning trust funds as of December 31, 1993. Earnings on these funds are recorded as an addition to the trust investment with a corresponding increase to the depreciation reserve. The Companies have also recognized an estimated liability of $19,275,000 related to decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy (DOE), as required by the Energy Policy Act of 1992. The Companies recover these costs through their respective energy rates. COMMON OWNERSHIP OF GENERATING FACILITIES- The Companies and other Central Area Power Coordination Group (CAPCO) companies own, as tenants in common, various power generating facilities. Each of the companies is obligated to pay a share of the costs associated with any jointly owned facility in the same proportion as its interest. The Companies' portions of operating expenses associated with any jointly owned facilities are included in the corresponding operating expenses on the Consolidated Statements of Income. The amounts reflected on the Consolidated Balance Sheet under utility plant at December 31, 1993, include the following: Companies' Utility Accumulated Construction Ownership/ Plant Provision for Work in Leasehold Generating Units in Service Depreciation Progress Interest ---------- ------------- ------------ ---------- (In thousands) W.H. Sammis #7 $ 304,900 $ 80,300 $5,000 68.80% Bruce Mansfield #1, #2 and #3 744,000 330,600 11,800 50.68% Beaver Valley #1 and #2 1,839,500 490,200 18,500 47.11% Perry #1 1,604,300 240,600 15,900 35.24% - --------------------------------------------------------------------- Total $4,492,700 $1,141,700 $51,200 - --------------------------------------------------------------------- NUCLEAR FUEL- Nuclear fuel is recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. The Companies amortize the cost of nuclear fuel based on the rate of consumption. The Companies' electric rates include amounts for the future disposal of spent nuclear fuel based upon the formula used to compute payments to the DOE. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION- AFUDC represents financing costs capitalized to construction work in progress (CWIP) during the construction period. The borrowed funds portion reflects capitalized interest payments, and the equity funds portion represents the noncash capitalization of imputed equity costs. AFUDC varies according to changes in the level of CWIP and in the sources and costs of capital. The composite AFUDC rates (excluding nuclear fuel interest) were 8.8%, 9.4% and 9.5% in 1993, 1992 and 1991, respectively. Capitalization rates for interest on nuclear fuel were 3.4%, 4.5% and 6.6% in 1993, 1992 and 1991, respectively. -15- INCOME TAXES- Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. The deferred income taxes in 1992 and 1991 resulted from timing differences in the recognition of revenues and expenses for tax and accounting purposes. Investment tax credits (ITC), which were deferred when utilized, are being amortized over the estimated life of the related property. ITC amortization in 1992 included $21,300,000 associated with portions of the Company's investments in Perry Unit 1 and Beaver Valley Unit 2 which are not recoverable from retail customers. The Companies adopted Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes," on January 1, 1993, which requires the liability method to be used to account for deferred income taxes. Under this standard, deferred income tax liabilities related to tax and accounting basis differences must be recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. The components of accumulated deferred income taxes as of December 31, 1993 are disclosed on the Consolidated Statements of Taxes. RETIREMENT BENEFITS- The Companies' trusteed, noncontributory defined benefit pension plans cover almost all full-time employees. Upon retirement, employees receive a monthly pension based on length of service and compensation. The Companies use the projected unit credit method for funding purposes and were not required to make pension contributions during the three years ended December 31, 1993. The following sets forth the funded status of the plans and amounts recognized on the Consolidated Balance Sheets as of December 31: 1993 1992 ---- ---- (In thousands) Actuarial present value of benefit obligations: Vested benefits $471,205 $385,187 Nonvested benefits 28,180 21,740 - -------------------------------------------------------------------- Accumulated benefit obligation $499,385 $406,927 ==================================================================== Plan assets at fair value $770,240 $710,370 Actuarial present value of projected benefit obligation 605,848 489,985 - -------------------------------------------------------------------- Plan assets in excess of projected benefit obligation 164,392 220,385 Unrecognized net gain (6,743) (77,333) Unrecognized prior service cost 14,074 15,629 Unrecognized net transition asset (57,719) (65,664) - -------------------------------------------------------------------- Net pension asset $114,004 $ 93,017 ==================================================================== -16- The assets of the plans consist primarily of common stocks, United States government bonds and corporate bonds. Net pension costs for the three years ended December 31, 1993, were computed as follows: 1993 1992 1991 ---- ---- ---- (In thousands) Service cost-benefits earned during the period $ 13,171 $ 13,278 $ 13,321 Interest on projected benefit obligation 42,723 40,291 38,076 Return on plan assets (97,849) (59,297) (124,509) Net deferral (amortization) 14,954 (22,378) 53,398 Voluntary early retirement program expense 6,014 7,289 - - --------------------------------------------------------------- Net pension cost $(20,987) $(20,817) $(19,714) =============================================================== The assumed discount rate used in determining the actuarial present value of the projected benefit obligation was 7.5% in 1993 and 9% in 1992. The assumed rate of increase in future compensation levels used to measure this obligation was 4.5% in each year. Expected long-term rates of return on plan assets were assumed to be 11% in each year. The Companies provide a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. The Companies pay insurance premiums to cover a portion of these benefits in excess of set limits; all amounts up to the limits are paid by the Companies. Expenses associated with health care and life insurance benefits for retirees were charged to income during the applicable payment periods in 1992 and 1991, and amounted to $9,689,000 and $8,280,000, respectively. In 1993 the Companies adopted SFAS No. 106 "Employers' Accounting for Postretirement Benefits Other Than Pensions," which requires companies to recognize the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. The Companies do not currently fund these future benefits. The following sets forth the accrued postretirement benefit cost on the Consolidated Balance Sheet as of December 31, 1993: Accumulated postretirement benefit obligation $240,712,000 Unrecognized transition obligation (193,374,000) Unrecognized net loss (25,048,000) ------------ Accrued postretirement benefit cost $ 22,290,000 The accumulated postretirement benefit obligation is allocated to: retirees - $136,288,000, fully eligible active plan participants - - $36,827,000, and other active plan participants - $67,597,000. -17- Net periodic postretirement benefit cost for 1993 included the following components: - ----------------------------------------------------------------- Service cost $ 3,929,000 Interest cost 18,039,000 Amortization of transition obligation 10,178,000 Voluntary early retirement program expense 1,533,000 ----------- Net periodic postretirement benefit cost 33,679,000 Benefits paid 11,389,000 ----------- Increase in accrued postretirement benefit cost $22,290,000 ================================================================== The health care trend rate assumption is 8.25% in the first year gradually decreasing to 3.5% for the year 2008 and later. The discount rate used to compute the accumulated postretirement benefit obligation at December 31, 1993 was 7.5%. An increase in the health care trend rate assumption by one percentage point in all years would increase the accumulated postretirement benefit obligation by approximately $40,100,000 and the aggregate annual service and interest costs by approximately $4,200,000. The PUCO and PPUC have authorized the Companies to defer the incremental costs resulting from adopting SFAS No. 106 (compared to costs computed under the former accounting basis) for future recovery from their retail customers. EARNINGS PER SHARE OF COMMON STOCK- Earnings per share of common stock shown on the Consolidated Statements of Income for the three years ended December 31, 1993, were computed as follows: 1993 1992 1991 - ------------------------------------------------------------------ (In thousands, except per share amounts) Earnings: Income before cumulative effect $ 24,523 $276,986 $264,823 Preferred and preference stock dividend requirements (23,707) (23,926) (24,754) Tax benefit from employee stock ownership plan dividends - 5,592 3,404 - ------------------------------------------------------------------ Earnings before cumulative effect 816 258,652 243,473 Cumulative effect of a change in accounting 58,201 - - - ------------------------------------------------------------------ Earnings after cumulative effect $ 59,017 $258,652 $243,473 - ------------------------------------------------------------------ Shares: Weighted average number of common shares outstanding 152,569 152,569 152,569 - ------------------------------------------------------------------ Earnings per share of Common Stock: Before cumulative effect of a change in accounting $.01 $1.70 $1.60 Cumulative effect of a change in accounting .38 - - - ------------------------------------------------------------------ Earnings per share of Common Stock $.39 $1.70 $1.60 ================================================================== -18- SUPPLEMENTAL CASH FLOWS INFORMATION- All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets. The Companies record temporary cash investments at cost, which approximates their market value. Noncash financing and investing activities included capital lease transactions amounting to $1,487,000, $5,831,000 and $10,467,000 for the years 1993, 1992 and 1991, respectively. OES Fuel commercial paper transactions, which are reflected as long-term debt on the Consolidated Balance Sheets (see Note 5E) but have initial maturity periods of three months or less, are reported net within financing activities under long-term debt. All borrowings with initial maturities of less than one year and $36,554,000 and $30,072,000 of investments other than cash and cash equivalents at December 31, 1993 and 1992, respectively, which are defined as financial instruments, are reflected at their approximate fair market value. The approximate fair market value of all other long-term debt and of preferred and preference stock subject to mandatory redemption exceeded the carrying cost of those financial instruments by approximately $198,000,000 and $1,800,000 as of December 31, 1993 and approximately $130,000,000 and $2,500,000 as of December 31, 1992, respectively. The fair value of these instruments reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by a corporation with credit ratings similar to the Companies' ratings. REGULATORY ASSETS - The Companies recognize, as regulatory assets, costs which the FERC, PUCO and PPUC have authorized for recovery from customers in future periods. Without such authorization, the costs would have been charged to income as incurred. Amounts shown below as being recovered currently have a composite remaining recovery period of approximately 30 years. The remaining assets, which are deferred for recovery in future rate proceedings, would increase revenues by about 1% on an annual basis once they are included in customers' electric rates. Regulatory assets on the Consolidated Balance Sheets were comprised of the following: 1993 1992 - -------------------------------------------------------------------- (In thousands) Currently being recovered through rates: Nuclear Unit Expenses $ 580,482 $ 596,275 Customer Receivables for Future Income Taxes 658,115 - Sale and Leaseback Costs 252,625 43,496 Property Taxes 101,182 109,621 Loss on Reacquired Debt 103,158 94,254 DOE Decommissioning and Decontamination Costs 19,275 20,500 Uncollectible Customer Accounts 13,425 11,154 Other 12,987 13,867 - ------------------------------------------------------------------- 1,741,249 889,167 - ------------------------------------------------------------------- Not currently recovered through rates: Nuclear Unit Interest Expense 198,453 189,935 Employee Postretirement Benefit Costs 16,456 - Perry Unit 2 Termination 37,637 - - ------------------------------------------------------------------- 252,546 189,935 - ------------------------------------------------------------------- Total $1,993,795 $1,079,102 =================================================================== -19- 2. CHANGE IN ACCOUNTING FOR UNBILLED REVENUES: On January 1, 1993, the Companies changed their accounting policies to recognize revenue relating to metered sales which remain unbilled at the end of the accounting period. This change was made to more closely match the Companies' revenues with the costs of services provided. The effect of this change increased net income for the year ended December 31, 1993 (before the cumulative effect from periods prior to 1993) by approximately $4,600,000 ($.03 per share of common stock). The cumulative effect to January 1, 1993 was $58,201,000 (net of $33,632,000 of income taxes) or $.38 per share. The reported results of operations for the years ended December 31, 1992 and 1991, would not have been materially different if this new accounting policy had been in effect during those years. 3. PERRY UNIT 2 TERMINATION: In December 1993, the Companies announced that they will not participate in further construction of Perry Unit 2 and have abandoned Perry Unit 2 as a possible electric generating plant. The Company determined that recovery from customers of its Perry Unit 2 investment is not probable, resulting in a $366,377,000 write-off of its investment in 1993. Penn Power expects its Perry Unit 2 investment to be recoverable from its customers. However, due to the anticipated delay in commencement of recovery and taking into account the expected rate treatment, Penn Power recognized an impairment to its Perry Unit 2 investment of $24,458,000 in 1993. As a result, net income for the year ended December 31, 1993, was reduced by $248,743,000 ($1.63 per share of common stock). 4. LEASES: The Companies lease a portion of their nuclear generating facilities, certain transmission facilities, computer equipment, office space and other property and equipment under cancelable and noncancelable leases. In 1987, the Company sold a portion of its ownership interest in Perry Unit 1 and Beaver Valley Unit 2 and simultaneously entered into operating leases on the portions sold for basic lease terms of approximately 29 years. During the terms of the leases the Company continues to be responsible, to the extent of its combined ownership and leasehold interest, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. The leases provide for adjustments to the basic rental payments for possible future federal tax law changes. The Company has the right, at the end of the respective basic lease terms, to renew the leases for up to two years. The Company also has the right to purchase the facilities at the expiration of the basic lease term or renewal term (if elected) at a price equal to the fair market value of the facilities. -20- Consistent with the regulatory treatment, the rental payments for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs reflected on the Consolidated Statements of Income for the three years ended December 31, 1993, are summarized as follows: 1993 1992 1991 - ------------------------------------------------------------------- (In thousands) Operating Leases Interest element $ 96,804 $108,870 $117,627 Other 15,418 13,308 11,866 Capital Leases Interest element 7,896 8,354 8,150 Other 6,843 6,985 6,788 - ------------------------------------------------------------------- Total rental payments $126,961 $137,517 $144,431 =================================================================== The future minimum lease payments as of December 31, 1993, are: Capital Operating Leases Leases - ---------------------------------------------------------------- (In thousands) 1994 $ 17,299 $ 101,744 1995 16,165 105,526 1996 14,484 108,743 1997 13,193 113,047 1998 12,278 118,128 Years thereafter 112,761 2,479,443 - ---------------------------------------------------------------- Total minimum lease payments 186,180 $3,026,631 Executory costs 46,375 ========== - -------------------------------------------------- Net minimum lease payments 139,805 Interest portion 80,493 - -------------------------------------------------- Present value of net minimum lease payments 59,312 Less current portion 6,739 - -------------------------------------------------- Noncurrent portion $ 52,573 ================================================== 5. CAPITALIZATION: (A) RETAINED EARNINGS- Under the Company's first mortgage indenture, the Company's consolidated retained earnings unrestricted for payment of cash dividends on the Company's common stock were $256,002,000 at December 31, 1993. -21- (B) EMPLOYEE STOCK OWNERSHIP PLAN- The Employee Stock Ownership Plan Trust (ESOP) was established in October 1990 to fund the matching contribution to the Companies' existing 401(k) savings plan. All full-time employees eligible for participation in the 401(k) savings plan are covered by the ESOP. The ESOP borrowed $200,000,000 from the Company and acquired 10,654,114 shares of the Company's common stock on the open market. In 1993, 1992 and 1991, 369,956 shares, 412,167 shares and 263,252 shares, respectively, were allocated to employees with the corresponding expense recognized based on the shares allocated method. Total ESOP related compensation expense was calculated as follows: - ----------------------------------------------------------------- 1993 1992 1991 - ----------------------------------------------------------------- (In thousands) Base compensation $ 6,799 $ 7,741 $ 4,941 Interest on ESOP debt 19,985 19,985 12,706 Dividends on common stock held by the ESOP and used to service debt (15,944) (15,970) (9,735) Interest earned by the ESOP (275) (317) (1,708) - ------------------------------------------------------------------ $ 10,565 $ 11,439 $ 6,204 ================================================================== (C) PREFERRED STOCK- Penn Power's 7.625% and 7.75% series of preferred stock have restrictions which prevent early redemption prior to October 1997 and July 2003, respectively. The Company's 8.45% series of preferred stock has no early redemption provision and its 7.75% series is not redeemable before April 1998. All other preferred stock may be redeemed by the Companies in whole, or in part, with 30-60 days' notice. The optional redemption prices shown on the Consolidated Statements of Capitalization will decline to eventual minimums per share according to the Charter provisions that establish each series. (D) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION- The Company's 8.45% series of preferred stock has an annual sinking fund requirement for 50,000 shares beginning on September 16, 1997. Penn Power's 13.00% series of preferred stock has an annual sinking fund requirement for 5,000 shares in each year on July 1; its 7.625% series has an annual sinking fund requirement for 7,500 shares beginning on October 1, 2002. Preferred shares are retired at $100 per share plus accrued dividends. Sinking fund requirements (including an optional redemption in 1994) for the next five years are: - ------------------------------------------------------------------- 1994 $50,862,000 1995 500,000 1996 500,000 1997 5,500,000 1998 5,500,000 - ------------------------------------------------------------------- -22 (E) LONG-TERM DEBT- The first mortgage indentures and their supplements, which secure all of the Companies' first mortgage bonds, serve as direct first mortgage liens on substantially all property and franchises, other than specifically excepted property, owned by the Companies. Based on the amount of bonds authenticated by the Trustee through December 31, 1993, the Company's annual sinking and improvement fund requirement for all bonds issued under the mortgage amounts to $30,056,000. The Company expects to deposit funds in 1994 which will be withdrawn upon the surrender for cancellation of a like principal amount of bonds, which are specifically authenticated for such purposes against unfunded property additions or against previously retired bonds. This method can result in minor increases in the amount of the annual sinking fund requirement. Sinking fund requirements (including an optional redemption in 1994) for first mortgage bonds and maturing long-term debt (excluding capital leases) for the next five years are: - ------------------------------------------------------------------ 1994 $386,569,000 1995 204,854,000 1996 407,275,000 1997 150,000,000 1998 150,850,000 - ------------------------------------------------------------------ The Companies' obligations to repay certain pollution control revenue bonds are secured by several series of first mortgage bonds and, in some cases, by subordinate liens on the related pollution control facilities. A portion of the unsecured notes outstanding are entitled to the benefit of irrevocable bank letters of credit of $338,831,000. To the extent that drawings are made under those letters of credit to pay principal of, or interest on, the pollution control revenue bonds, the Company is entitled to a credit on the notes. The Company pays an annual fee of 0.625% to 0.925% of the amounts of the letters of credit to the issuing banks and is obligated to reimburse the banks for any drawings thereunder. Nuclear fuel purchases are financed through the issuance of OES Fuel commercial paper and loans, both of which are supported by a $325,000,000 long-term bank credit agreement which expires March 31, 1996. Accordingly, the commercial paper and loans are reflected as long-term debt on the Consolidated Balance Sheets. OES Fuel must pay a facility fee of 0.1875% on the total line of credit and a commitment fee of 0.0625% on any unused amount. 6. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT: Short-term borrowings outstanding at December 31, 1993 represent OES Capital debt which is secured by customer accounts receivable. OES Capital can borrow up to $120,000,000 under a receivables financing agreement at rates based on certain bank commercial paper. OES Capital is required to pay a fee of 0.5% on the amount of the entire finance limit. The receivables financing agreement expires April 23, 1996. -23- The Companies have lines of credit with domestic banks that provide for borrowings of up to $85,000,000 under various interest rate options. Short-term borrowings may be made under these lines of credit on the Companies' unsecured notes. To assure the availability of these lines, the Companies are required to pay commitment fees that vary from 0.15% to 0.5%. These lines expire at various times during 1994. 7. COMMITMENTS, GUARANTEES AND CONTINGENCIES: CONSTRUCTION PROGRAM- The Companies' current forecasts reflect expenditures of approximately $1,000,000,000 for property additions and improvements from 1994-1998, of which approximately $235,000,000 is applicable to 1994. Investments for additional nuclear fuel during the 1994-1998 period are estimated to be approximately $204,000,000, of which approximately $45,000,000 applies to 1994. During the same periods, the Companies' nuclear fuel investments are expected to be reduced by approximately $261,000,000 and $64,000,000, respectively, as the nuclear fuel is consumed. NUCLEAR INSURANCE- The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $9,396,000,000. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on their present ownership and leasehold interests in Beaver Valley Units 1 and 2 and Perry Unit 1, the Companies' maximum potential assessment under the industry retrospective rating plan (assuming the other CAPCO companies were to contribute their proportionate share of any assessments under the retrospective rating plan) would be $102,800,000 per incident but not more than $13,000,000 in any one year for each incident. The Companies are also insured as to their respective interests in the Beaver Valley Station and the Perry Plant under policies issued to the operating company for each plant. Under these policies, up to $2,750,000,000 is provided for property damage and decontamination and decommissioning costs. The Companies have also obtained approximately $313,000,000 of insurance coverage for replacement power costs for their respective interests in Beaver Valley Units 1 and 2 and Perry Unit 1. Under these policies, the Companies can be assessed a maximum of approximately $15,400,000 for accidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses. The Companies intend to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of the Companies' plants exceed the policy limits of the insurance from time to time in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Companies' insurance policies, or to the extent such insurance becomes unavailable in the future, the Companies would remain at risk for such costs. -24- GUARANTEES- The Companies, together with the other CAPCO companies, have each severally guaranteed certain debt and lease obligations in connection with a coal supply contract for the Bruce Mansfield Plant. As of December 31, 1993, the Companies' shares of the guarantees (which approximate fair market value) were $101,217,000. The price under the coal supply contract, which includes certain minimum payments, has been determined to be sufficient to satisfy the debt and lease obligations. The Companies' total payments under the coal supply contract were $114,572,000, $103,657,000 and $107,069,000 during 1993, 1992 and 1991, respectively. Under the coal supply contract, the Companies' minimum payments in each year during the period 1994 through 1999 are approximately $35,000,000. ENVIRONMENTAL MATTERS- Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. The Companies have estimated additional capital expenditures for environmental compliance of approximately $175,000,000, which is included in the construction forecast given above under "Construction Program" for 1994 through 1998. The Clean Air Act Amendments of 1990 require significant reductions of sulfur dioxide (SO2) and oxides of nitrogen from the Companies' coal-fired generating units by 1995 and additional emission reductions by 2000. Compliance options include, but are not limited to, installing additional pollution control equipment, burning less polluting fuel, purchasing emission allowances from others, operating existing facilities in a manner which minimizes pollution and retiring facilities. In compliance plans submitted to the PUCO and to the Environmental Protection Agency (EPA), the Company stated that reductions for the years 1995 through 1999 are likely to be achieved by burning lower sulfur fuel, generating more electricity at its lower emitting plants and/or purchasing emission allowances. The Company continues to evaluate its compliance plans and other compliance options as they arise. Plans for complying with the year 2000 reductions are less certain at this time. The Companies are presently required to meet federally approved SO2 regulations, and the violations of such regulations can result in injunctive relief, including shutdown of the generating unit involved, and/or civil or criminal penalties of up to $25,000 per day of violation. The EPA has an interim enforcement policy for the SO2 regulations in Ohio which allows for compliance with the regulations based on a 30-day averaging period. The EPA has proposed regulations which could cause changes in the interim enforcement policy, including revisions of the methods of determining compliance with emission limits. The Companies cannot predict what action the EPA may take in the future with respect to the proposed regulations or the interim enforcement policy. The Pennsylvania Department of Environmental Resources has issued regulations dealing with the storage, treatment, transportation and disposal of residual waste such as coal ash and scrubber sludge. These regulations impose additional requirements relating to permitting, ground water monitoring, leachate collection systems, closure, liability insurance and operating matters. The Companies are developing and analyzing various compliance options and are presently unable to determine the ultimate increase in capital and operating costs at existing sites. Legislative and administrative action and the effect of court decisions can be expected in the future (as they have in the past) to change the way that the Companies must operate in order to comply -25- with environmental laws and regulations. With respect to any such changes and to the environmental matters described above, the Companies expect that any resulting additional capital costs which may be required, as well as any required increase in operating costs, would ultimately be recovered from their customers. 8. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results by quarter for 1993 and 1992. March 31, June 30, September 30, December 31, Three Months Ended 1993 1993 1993 1993 - ----------------------------------------------------------------------------------- (In thousands, except per share amounts) Operating Revenues $593,214 $563,349 $624,524 $588,853 Operating Expenses and Taxes 461,719 425,354 472,341 485,196 - ----------------------------------------------------------------------------------- Operating Income 131,495 137,995 152,183 103,657 Other Income (Expense) 4,016 4,988 4,079 (241,905) Net Interest and Other Charges 68,287 68,438 68,041 67,219 - ----------------------------------------------------------------------------------- Income (Loss) Before Cumulative Effect of a Change in Accounting 67,224 74,545 88,221 (205,467) Cumulative Effect of a Change in Accounting 58,201 - - - - ----------------------------------------------------------------------------------- Net Income (Loss) $125,425 $ 74,545 $ 88,221 $(205,467) - ----------------------------------------------------------------------------------- Earnings (Loss) Applicable to Common Stock $119,520 $ 68,310 $ 82,462 $(211,275) - ----------------------------------------------------------------------------------- Earnings (Loss) per Share of Common Stock Before Cumulative Effect of a Change in Accounting $.40 $.45 $.54 $(1.38) Cumulative Effect of a Change in Accounting .38 - - - - ----------------------------------------------------------------------------------- Earnings (Loss) per Share of Common Stock $.78 $.45 $.54 $(1.38) - ----------------------------------------------------------------------------------- March 31, June 30, September 30, December 31, Three Months Ended 1992 1992 1992 1992 - ----------------------------------------------------------------------------------- (In thousands, except per share amounts) Operating Revenues $587,787 $565,621 $601,533 $577,437 Operating Expenses and Taxes 453,220 445,036 459,430 452,577 - ----------------------------------------------------------------------------------- Operating Income 134,567 120,585 142,103 124,860 Other Income 9,585 9,198 8,290 9,210 Net Interest and Other Charges 71,014 70,002 71,255 69,141 - ----------------------------------------------------------------------------------- Net Income $ 73,138 $ 59,781 $ 79,138 $ 64,929 - ----------------------------------------------------------------------------------- Earnings on Common Stock $ 67,052 $ 53,776 $ 73,240 $ 58,992 - ----------------------------------------------------------------------------------- Earnings per Share of Common Stock $.45 $.36 $.49 $.40 - ----------------------------------------------------------------------------------- Results of operations for the first three quarters of 1993 were restated to reflect the change in accounting for unbilled revenues as described in Note 2. Restated net income for the first quarter includes $58,201,000 or $.38 per share for the cumulative effect of the change. The effect on income from continuing operations was as follows: $(5,797,000) or $(.04) per share in the first quarter, $4,539,000 or $.03 per share in the second quarter, and $(4,459,000) or $(.03) in the third quarter. -26- Report of Independent Public Accountants To the Stockholders and Board of Directors of Ohio Edison Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Ohio Edison Company (an Ohio corporation) and subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of income, retained earnings, capital stock and other paid-in capital, cash flows and taxes for each of the three years in the period ended December 31, 1993. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements 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 Ohio Edison 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 in Notes 1 and 2 to the consolidated financial statements, effective January 1, 1993, the Company changed its method of accounting for unbilled revenues, income taxes and postretirement benefits other than pensions. ARTHUR ANDERSEN & CO. New York, N.Y. February 1, 1994 -27-
EX-18 10 OE10K EXHIBIT 18 February 1, 1994 Ohio Edison Company 76 South Main Street Akron, Ohio 44308 RE: Form 10-K Report for the Year Ended December 31, 1993 Gentlemen: This letter is written to meet the requirements of Regulation S-K calling for a letter from a registrant's independent public accountants whenever there has been a change in accounting principle or practice. As of January 1, 1993, for certain customers, the Company changed from recording sales when billed to these customers based on a monthly meter reading schedule to estimating and accruing the amount of sales associated with service provided after billing through the end of the accounting period. According to management of the Company, this change was made to more closely match the Company's revenues with the services provided to customers. This change in accounting will result in the Company accruing unbilled revenues for all customers at the end of each accounting period. We are of the opinion that the Company's change in method of accounting is an acceptable alternative method of accounting, which, based upon the reason stated for the change and our discussions with you, is also preferable under the circumstances in this particular case. In arriving at this opinion, we have relied on the business judgment and business planning of your management. Very truly yours, ARTHUR ANDERSEN & CO. New York, N.Y. EX-21 11 OE10K EXHIBIT 21 LIST OF SUBSIDIARIES OF THE REGISTRANT AT DECEMBER 31, 1993 Pennsylvania Power Company - Incorporated in Pennsylvania OES Fuel, Incorporated - Incorporated in Ohio OES Capital, Incorporated - Incorporated in Ohio Statement of Differences ------------------------ Exhibit Number 21, List of Subsidiaries of the Registrant at December 31, 1993, is not included in the printed document. EX-23 12 OE10K EXHIBIT 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our reports included or incorporated by reference in this Form 10-K, into the Company's previously filed Registration Statements, File No. 33-49135, No. 33-49259, 33-49413 and 33-51139. ARTHUR ANDERSEN & CO. New York, N.Y. March 23, 1994 -----END PRIVACY-ENHANCED MESSAGE-----