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
<PAGE>
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
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
<TABLE>
SCHEDULE V
Page 1
OHIO EDISON COMPANY
CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1993
<CAPTION>
Beginning Additions Retirements Other Ending
Classification Balance at Cost or Sales Changes(a) Balance
-------------- --------- --------- ------------- --------- -------
<S> <C> <C> <C> <C> <C>
(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
=========== ======== ======== ========= ==========
- --------------------
<FN>
(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.
</TABLE>
-36-
<PAGE>
<TABLE>
SCHEDULE V
Page 2
OHIO EDISON COMPANY
CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1992
<CAPTION>
Beginning Additions Retirements Other Ending
Classification Balance at Cost or Sales Changes(a) Balance
-------------- --------- --------- ------------ ----------- -------
<S> <C> <C> <C> <C> <C>
(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
========== ======== ========== ======= ==========
- --------------------------------
<FN>
(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.
</TABLE>
-37-
<PAGE>
<TABLE>
SCHEDULE V
Page 3
OHIO EDISON COMPANY
CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1991
<CAPTION>
Beginning Additions Retirements Other Ending
Classification Balance at Cost or Sales Changes(a) Balance
-------------- --------- ---------- ------------ ---------- -------
<S> <C> <C> <C> <C> <C>
(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
========== ======== ========== ======== ==========
- ------------------------------------------
<FN>
(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-
</TABLE>
<PAGE>
<TABLE>
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
<CAPTION>
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)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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
========== ======== ======= ======= ======== ======= ======== ==========
- -------------------
<FN>
(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-
</TABLE>
<PAGE>
<TABLE>
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
<CAPTION>
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)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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
========== ======== ======= ======= ======== ======= ===== ==========
- -------------------
<FN>
(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
<PAGE>
<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
<CAPTION>
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)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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
========== ======== ======= ====== ======== ======= ======== ==========
- -------------------
<FN>
(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-
</TABLE>
<PAGE>
<TABLE>
SCHEDULE VIII
OHIO EDISON COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
<CAPTION>
Additions
--------------------------
Charged Charged
(Credited) (Credited)
Beginning to to Other Ending
Description Balance Income Accounts Deductions Balance
----------- --------- ---------- ---------- ---------- -------
(In Thousands)
<S> <C> <C> <C> <C> <C>
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
====== ======= ====== ======= ======
- ---------------------
<FN>
(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-
</TABLE>
<PAGE>
<TABLE>
SCHEDULE IX
OHIO EDISON COMPANY
CONSOLIDATED SHORT-TERM BORROWINGS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
<CAPTION>
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
<S> <C> <C> <C> <C> <C> <C>
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%
- ------------------
<FN>
(a) Based on the daily amounts outstanding.
(b) Excludes the effect of commitment fees.
-43-
</TABLE>
<PAGE>
<TABLE>
SCHEDULE X
OHIO EDISON COMPANY
SUPPLEMENTARY CONSOLIDATED INCOME STATEMENT INFORMATION
FOR THE THREE YEARS ENDED DECEMBER 31, 1993
<CAPTION>
Item Charged to Expense
- ----------------------- ------------------------------------------
1993 1992 1991
---- ---- ----
<S> <C> <C> <C>
Maintenance and repairs $189,806,000 $188,009,000 $187,431,000
<FN>
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.
</TABLE>
-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
<PAGE>
_____________________________________________
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
<PAGE>
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-
<PAGE>
(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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
(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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
(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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
(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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
Party resulting from the transmission of such energy shall be
treated in accordance with Article 7.
Doc. 17723
-37-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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
<PAGE>
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
<PAGE>
SM-7 (Page 21 of 22)
(BLANK)
Doc. 17727
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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
<PAGE>
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.
<PAGE>
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.
<PAGE>
(BLANK)
Doc. 17729
<PAGE>
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.
<PAGE>
(BLANK)
<PAGE>
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.<PAGE>
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
<PAGE>
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.
<PAGE>
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
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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
<PAGE>
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.
<PAGE>
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)
<PAGE>
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
<PAGE>
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
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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
<PAGE>
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.
<PAGE>
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:
<PAGE>
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
<PAGE>
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.
<PAGE>
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
<PAGE>
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.
<PAGE>
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%
<PAGE>
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)
<PAGE>
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
<PAGE>
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.
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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.
<PAGE>
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.
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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.
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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-
<PAGE>
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-
<PAGE>
(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-
<PAGE>
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-
<PAGE>
(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-
<PAGE>
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-
<PAGE>
(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-
<PAGE>
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-
<PAGE>
(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-
<PAGE>
(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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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
<PAGE>
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.
<PAGE>
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
<PAGE>
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.
<PAGE>
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
<PAGE>
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.
<PAGE>
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-
<PAGE>
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
<PAGE>
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.
<TABLE>
EXHIBIT 12
OHIO EDISON COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
<CAPTION>
Year Ended December 31,
--------------------------------------------
1989 1990 1991 1992 1993
-------- -------- -------- -------- --------
(Dollars in Thousands)
<S> <C> <C> <C> <C> <C>
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
==== ==== ==== ==== ====
- -------------
<FN>
(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-
</TABLE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
<TABLE>
OHIO EDISON COMPANY
SELECTED FINANCIAL DATA
<CAPTION>
1993 1992 1991 1990 1989
---- ---- ---- ---- ----
(In thousands, except per share amounts)
<S> <C> <C> <C> <C> <C>
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
- --------------------------- ---- ----
<S> <C> <C> <C> <C>
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 %
------- ------ ---------- -----
<S> <C> <C> <C> <C>
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
-----------------------------------------------
<FN>
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.
</TABLE>
-6-
<PAGE>
<TABLE>
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
<CAPTION>
For the Years Ended December 31, 1993 1992 1991
---- ---- ----
(In thousands, except per share amounts)
<S> <C> <C> <C>
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
========== ========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</TABLE>
-7-
<PAGE>
<TABLE>
OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
<CAPTION>
At December 31, 1993 1992
---- ----
(In thousands)
ASSETS
<S> <C> <C>
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
========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
</TABLE>
-8-
<PAGE>
<TABLE>
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
<CAPTION>
At December 31, 1993 1992
---- ----
(In thousands, except per share amounts)
<S> <C> <C>
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
---- ---- ---------- ---------
<S> <C> <C> <C> <C> <C> <C>
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
========= ========= ======== ------- -------
</TABLE>
-9-
<PAGE>
<TABLE>
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont.)
<CAPTION>
At December 31, 1993 1992 1993 1992 1993 1992
---- ---- ---- ---- ---- ----
(In thousands)
<S> <C> <C> <C> <C> <C> <C>
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
========================================================================================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</TABLE>
-10-
<PAGE>
<TABLE>
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<CAPTION>
For the Years Ended December 31, 1993 1992 1991
---- ---- ----
(In thousands)
<S> <C> <C> <C>
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)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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
=============================================================================================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</TABLE>
-11-
<PAGE>
<TABLE>
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
For the Years Ended December 31, 1993 1992 1991
---- ---- ----
(In thousands)
<S> <C> <C> <C>
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
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</TABLE>
-12-
<PAGE>
<TABLE>
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF TAXES
<CAPTION>
For the Years Ended December 31, 1993 1992 1991
---- ---- ----
(In thousands)
<S> <C> <C> <C>
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
==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these
statements.
</TABLE>
-13-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
(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
<PAGE>
(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-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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.
<TABLE>
8. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
<CAPTION>
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)
<S> <C> <C> <C> <C>
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-
<PAGE>
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-
<PAGE>
</TABLE>
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.<PAGE>
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.
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
