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Exhibit 10b(3)
CAPCO BASIC OPERATING AGREEMENT
As Amended January 1, 1993
* * *
The Cleveland Electric Illuminating Company
Duquesne Light Company
Ohio Edison Company
Pennsylvania Power Company
The Toledo Edison Company
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IN WITNESS WHEREOF, the Partis hereto have caused this Agreement to be
executed by their duly authorized officers this 23rd day of December, 1993.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
By: TERRENCE G. LINNERT
Title: Vice President
DUQUESNE LIGHT COMPANY
By: G. R. BRANDENBERGER
Title: Vice President
OHIO EDISON COMPANY
By: ARTHUR P. GARFIELD
Title: Vice President
PENNSYLVANIA POWER COMPANY
By: J. R. Edgerly
Title: Vice President
THE TOLEDO EDISON COMPANY
By: TERRENCE G. LINNERT
Title: Vice President
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TABLE OF CONTENTS
Page No.
Article 1 -- Purpose of Agreement 2
Article 2 -- Definitions 2
Article 3 -- Operating Committee 5
Article 4 -- Operating Conditions 7
4.01 Parallel Operation 7
4.02 Frequency 8
4.03 Megavars 8
4.04 Unscheduled Energy 9
4.05 Transmission Operation 9
4.06 Coordinated Maintenance 10
4.07 Unit Availability 10
4.08 Utilization of CAPCO Units 11
Article 5 -- Coordinated Maintenance and CAPCO Back-Up Power 11
5.01 Coordinated Maintenance 11
5.02 CAPCO Back-Up Power 11
5.03 Scheduling CAPCO Back-Up Power 12
5.04 Obligation to Provide CAPCO Back-Up Power 12
5.05 Proportional Supply of CAPCO Back-Up Power 13
Article 6 -- Communications 14
Article 7 -- Services 15
Article 8 -- Executive Committee 16
Article 9 -- Ohio Edison System 17
Article 10 -- Interconnection Metering 17
Article 11 -- Records 19
Article 12 -- Statements, Billings, Settlements and Payments 19
Article 13 -- Government Approvals 22
Article 14 -- Notices 22
Article 15 -- Non-Waiver 22
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TABLE OF CONTENTS
(Cont'd)
Page No.
Article 16 -- Arbitration 23
Article 17 -- Assignment 26
Article 18 -- Governing Law 26
Article 19 -- Other Agreements 27
Article 20 -- Term of Agreement 28
Article 21 -- Separate Identities 28
Article 22 -- Force Majeure 29
Article 23 -- Liability 29
Schedule A -- Back-Up Power 32
Schedule B -- Short Term Power 35
Schedule C -- Non-Displacement Power 39
Schedule D -- Economy Power 42
Schedule E -- Unit Power 47
Schedule F -- Out-of-Pocket Cost 52
Schedule G -- Emergency Power 54
Schedule H -- Transmission of Non-CAPCO Power 57
Schedule I -- Replacement Power 58
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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.
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ARTICLE 1
Purpose of Agreement
1.01 It is the purpose of this Agreement to provide for the
coordinated operation of the systems of the Parties, so as to (1) provide for
the utilization by each of the Parties of facilities heretofore provided for
by the Parties; (2) provide a degree of mutual support; (3) provide for
capacity and energy transactions by and among the Parties; (4) permit coordi-
nation of the operation of the systems of the Parties; and (5) achieve an
equitable sharing of the responsibilities, risks and expenses and of the
resulting benefits of coordinated operation of the systems of the Parties.
ARTICLE 2
Definitions
The definitions in this Article shall apply to this Agreement
and to the Schedules hereto, unless otherwise expressly provided in such
Schedules.
2.01 Actual Capacity of a Party shall mean the sum of the Net
Demonstrated Capability of its ownership shares in CAPCO Units, plus its
Individual Capacity (in all cases to the extent then in commercial operation)
adjusted in all cases for seasonal factors existing at the time pursuant to
the document entitled, "CAPCO Group Common Method of Rating Generating Equip-
ment," dated October 17, 1969, as amended from time to time, plus such Party's
individual purchases less such Party's individual sales (but shall exclude
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power scheduled to be received by a Party to provide for deliveries to
cooperative or municipal systems or other Parties or non-CAPCO parties'
systems).
2.02 CAPCO Unit shall mean any one of the following listed
Units: W. H. Sammis Generating Station Unit No. 7, Bruce Mansfield Unit No.
1, Bruce Mansfield Unit No. 2, Bruce Mansfield Unit No. 3, Davis-Besse Nuclear
Power Station Unit No. 1, Beaver Valley Power Station Unit No. 1, Beaver
Valley Power Station Unit No. 2, Eastlake Generating Station Unit No. 5, Perry
Nuclear Power Plant Unit No. 1 and Perry Nuclear Power Plant Unit No. 2.
2.03 Coordinated Maintenance Schedule means the schedule
established under the direction of the Operating Committee pursuant to Section
5.01.
2.04 Individual Capacity of a Party as of any date is the sum
of the following:
(a) The Net Demonstrated Capabilities of the generating
units or portions thereof owned or leased by such Party in commercial opera-
tion and not placed in cold reserve, but exclusive of ownership of CAPCO
Units.
(b) The equivalent Net Demonstrated Capability of such
Party's portion of the Ohio Valley Electric Corporation ("OVEC") capacity.
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2.05 Interruptible Load of a Party is the total of megawatt-
hours delivered during any clock hour to its retail customers or to municipal
or cooperative systems which the Party, in its sole discretion, is privileged
to curtail or completely interrupt in accordance with a rate schedule or
contractual arrangement with such customer or customers.
2.06 Load of a Party during any clock hour is the total
during any such clock hour (eliminating on an agreed basis any distortion
arising out of deliveries between systems where material) of megawatthours (a)
delivered by the Party to its retail customers and its municipal systems, but
excluding that portion of municipal system Load which is purchased from other
Parties or systems, (b) used by the Party on its own system, exclusive of use
for station auxiliary power, and (c) lost and unaccounted for on the system of
the Party; but shall exclude Interruptible Load.
2.07 Minimum Operating Reserve of a Party, unless otherwise
determined by the Operating Committee, shall mean a spinning reserve of not
less than 3% of the projected daily Peak Load of such Party.
2.08 Net Demonstrated Capability of a generating unit as of
any time means that most recently determined pursuant to the methods and
principles set forth in the document entitled, "CAPCO Group Common Method of
Rating Generating Equipment," dated October 17, 1969, as amended from time to
time.
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2.09 Operating Capacity of a Party during a particular day
shall mean that portion of a Party's Actual Capacity to the extent actually in
operation or expected to be in operation.
2.10 Operating Reserve of a Party means that component of
Operating Capacity which is unloaded, plus Quick Start Capacity and Inter-
ruptible Load to the extent they can be so included in accordance with rules
and procedures established by the Operating Committee.
2.11 Peak Load of a Party for any period of time is the
maximum Load of the Party for any clock hour of the period.
2.12 Power shall include electric capacity and energy
expressed in megawatts and megawatthours.
2.13 Quick Start Capacity means generating capacity which can
be started, synchronized to the system and loaded within a time period as
specified by the Operating Committee.
ARTICLE 3
Operating Committee
3.01 The Operating Committee shall be that established
pursuant to the CAPCO Administration Agreement dated as of September 14, 1967,
as the same may be amended from time to time.
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3.02 Each Party shall make available to the Operating
Committee all data and information reasonably required to enable it to perform
its duties.
3.03 The Operating Committee shall be responsible for
establishing, maintaining and revising as necessary the Coordinated
Maintenance Schedule.
3.04 The Operating Committee shall be responsible for the
establishment and administration of rules and procedures to coordinate the
operation of the systems of the Parties to effectuate the purpose of this
Agreement. Without limiting the generality of the foregoing, the Operating
Committee shall establish rules and procedures for:
(a) The determination of billing costs and other
factors used for scheduling and billing of transactions hereunder;
(b) The determination of the increase or decrease of
electrical losses incurred as the result of transactions hereunder;
(c) The establishment and periodic revision of the
Coordinated Maintenance Schedule which shall be reviewed at least annually;
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(d) The determination of the Minimum Operating Reserve
for each Party;
(e) The scheduling of CAPCO Back-Up Power as provided
in Article 5; and
(f) Accumulating and recording load, capacity and other
operating data needed to evaluate performance under the various CAPCO
agreements.
3.05 The Operating Committee shall conduct studies of the
coordinated operation of the systems of the Parties for the purposes of this
Agreement, and make recommendations with respect thereto, including recom-
mendations with respect to the development and coordination of an adequate
communication system. The Operating Committee is authorized to create task
forces for particular studies and to appoint the members thereof who need not
be members of the Operating Committee. Subject to such limitations as may be
imposed by the Executive Committee, the Operating Committee is authorized on
behalf of the Parties to hire consultants and computer time and to incur other
expenses in the making of any of its studies.
ARTICLE 4
Operating Conditions
4.01 Each party shall operate its system continuously in
parallel with each other Party with which it is interconnected. Unless
otherwise mutually agreed which agreement shall not be unreasonably withheld,
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all existing interconnections between the systems of the Parties operating at
nominal voltages of 138,000 volts and above shall normally be operated closed.
Each Party shall maintain and operate its system so as to minimize the
likelihood and effect of disturbances on its system which might impair the
service on the system of any other Party. Each Party shall be the sole judge
whether service on its system is being impaired by conditions on the system of
another Party and may itself take, or request such other Party to take,
appropriate corrective action to restore normal operating conditions as soon
as reasonably practicable.
Power which is supplied by one Party to another Party through
interconnections normally operated open or through a temporary interconnection
point shall be compensated for by the other Party delivering to the first
Party through other interconnections equivalent Power adjusted for losses. It
is the intent of the Parties that, whenever feasible, such compensation shall
be made simultaneously with the delivery of Power through such
interconnections.
4.02 Each Party shall use its best efforts to operate its
system so as to aid in maintaining the frequency on the systems of the Parties
at a nominal 60 Hz within the limits for normal operating deviations as
established from time to time by the Operating Committee.
4.03 Each Party shall, to the extent practicable, operate its
system so as to avoid the creation of objectionable operating conditions on
the system of another Party due to the transfer of megavars. Subject to the
foregoing, the Operating Committee shall (a) establish operating procedures
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for the coordination of megavar supply associated with flows of Power pursuant
to this Agreement, and (b) determine the circumstances under which a Party
shall compensate another for supplying megavars in connection with flows of
Power pursuant to this Agreement and recommend the amount of such
compensation.
4.04 Each Party shall exercise reasonable care to minimize,
to the extent practicable, unscheduled deliveries or receipts of electric
energy. The Parties recognize, however, that despite their best efforts such
unscheduled deliveries or receipts of electric energy may occur. Electric
energy delivered or received in such event shall be settled for by return of
equivalent energy. It shall be returned at times when the load conditions of
the returning Party are equivalent to the load conditions of such Party at the
time the energy for which it is returned was received, unless otherwise
agreed.
4.05 The Parties recognize that in the day-to-day operation
of their systems the transmission facilities of any Party may, as a natural
result of the physical and electrical characteristics of the interconnected
network of transmission lines of which the transmission lines of the Parties
are a part, carry Power from one portion of the system of one of the Parties
to another portion of that Party's system, or carry Power intended to be
transmitted to or from the system of one of the Parties from or to the system
of another Party or other systems. The Parties will use their best efforts to
resolve promptly any operating problems thereby created, including but not
limited to curtailing or interrupting Interruptible Load and Economy Power
transactions with other Parties and/or other systems.
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4.06 Each Party shall, to the fullest extent practicable:
(a) Maintain generating units in accordance with the
Coordinated Maintenance Schedule.
(b) Coordinate with the other Parties the scheduled
outages of transmission facilities operating at nominal voltages of 138,000
volts or above.
(c) Return generation and transmission facilities to
service in good operating condition with reasonable promptness.
(d) Advise the other Parties as to its maintenance
practices and policies and any changes therein, and cooperate in attempts to
accelerate or defer maintenance of generation and transmission facilities in
emergency situations.
4.07 Each Party shall be the sole judge as to whether, due to
physical conditions beyond its reasonable control, a generating unit operated
by such Party is unavailable for operation or unavailable for continued opera-
tion or must be derated or temporarily removed from service; provided,
however, that unavailability for operation or continued operation, or
derating, for reasons of limitations of fuel supply for a CAPCO unit, shall be
determined in accordance with rules and procedures established by the
Operating Committee.
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4.08 Each Party shall be entitled to the full utilization,
with respect to capacity and energy, when a CAPCO Unit is available and based
on and in proportion to the actual day-by-day operating capacity, of (a) its
ownership share of capacity in that Unit, plus (b) its entitlement to receive
capacity from another Party's ownership share in such Unit, and minus (c) its
obligation to provide capacity from such Unit. Scheduling of such capacity
and energy entitlements shall be adjusted appropriately for transmission line
losses.
ARTICLE 5
Coordinated Maintenance and CAPCO Back-Up Power
5.01 The Parties shall coordinate the outages for maintenance
of all CAPCO Units and such other units of the Parties as are identified by
the Operating Committee and for such purpose the Coordinated Maintenance
Schedule shall be developed and maintained in accordance with rules and
procedures established pursuant to Section 3.04.
5.02 In order to provide back-up for CAPCO Unit outages, each
Party shall have an entitlement to receive or an obligation to provide
operating capacity and associated energy in the form of CAPCO Back-Up Power.
CAPCO Back-Up Power shall be calculated as specified in the next paragraph in
this Section and shall be compensated for as specified in Schedule A of this
Agreement; provided, however, such CAPCO Back-Up Power shall not be available
for any nuclear CAPCO Unit during those periods in which such CAPCO Unit is
out of service for the reasons set forth in Schedule I.
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In the event of the forced or scheduled outage of any
CAPCO Unit in commercial operation (except those Units in cold reserve), each
Party agrees to provide or shall have the right to receive, as the case may
be, CAPCO Back-Up Power in an amount equal to the difference between such
Party's ownership share in the CAPCO Unit out of service, expressed in
megawatts, and a value determined by multiplying the Net Demonstrated
Capability of the CAPCO Unit out of service by the ratio of such Party's
ownership share of the Net Demonstrated Capability of all of the CAPCO Units
in commercial operation to the total Net Demonstrated Capability of all of the
CAPCO Units in commercial operation.
Each Party shall use its best efforts to operate its
system so as to provide the amounts of Minimum Operating Reserve determined
consistent with the rules and procedures established pursuant to Section
3.04.
5.03 Pursuant to rules and procedures established by the
Operating Committee, CAPCO Back-Up Power for the next succeeding day shall be
arranged on a net basis, initially at 1200 hours on the preceding day or such
other time mutually agreed upon by the Operating Committee, and shall be
scheduled as requested by the receiving Party. The receiving Party shall have
the right to receive all or any part of such Party's net entitlement to CAPCO
Back-Up Power.
5.04 Each Party is obligated to provide CAPCO Back-Up Power
after supplying its Load and meeting its Minimum Operating Reserve, except
when the delivery of such Power would, in the judgment of the supplying Party,
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have to be interrupted or reduced to preserve the integrity of or to prevent
or limit any instability on the supplying Party's system. If a Party having
an obligation to supply does not have sufficient capacity available on its own
system to meet the obligation, it is obligated to purchase capacity and
associated energy if available to provide CAPCO Back-Up Power.
For each day that a Party is unable to fulfill all or any part
of its obligation to provide CAPCO Back-Up Power because it is supplying Power
other than CAPCO Back-Up Power to another Party or to a non-CAPCO party,
except pursuant to obligations imposed by governmental authorities, agreements
referred to in Article 19, and any additional agreements excepted by the
Parties, such Party shall pay an amount equal to twice the maximum daily
demand charge for the CAPCO Back-Up Power not provided by such Party to the
other Parties to be shared in proportion to the entitlements which were not
fulfilled. In the event any Party is unable to provide CAPCO Back-Up Power in
any substantial amount over an extended period and reserves substantial CAPCO
Back-Up Power from others, the Parties shall develop corrective measures such
as, but not limited to, increasing the demand charge rate.
5.05 CAPCO Back-Up Power will be made available in proportion
to Party entitlements from supplying Parties in proportion to their obliga-
tions, and will be made available from the least-cost available Power. In the
event that a receiving Party or Parties reserve less than its or their
entitlement of CAPCO Back-Up Power, the remaining CAPCO Back-Up Power will be
made available from the supplying Parties in proportion to their obligations
to the other receiving Parties in proportion to their entitlements from such
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least-cost available Power. CAPCO Back-Up Power obligations not reserved by
the receiving Parties shall be deemed released to the supplying Parties.
ARTICLE 6
Communications
6.01 The Parties will establish communication facilities as
may be required to provide voice communication, telemetering, automatic
generation control, monitoring, tie-line control, and other functions as may
be determined from time to time by the Operating Committee, or as required by
other agreements among the Parties. Such communication facilities will
consist of existing communication links owned or leased by the Parties as well
as communication links to be built or leased by the Parties. It is understood
that extensive use of microwave links will be made pursuant to the CAPCO
Microwave Sharing Agreement, as amended January 1, 1993 and as it may be
amended from time to time, although carrier current and wire communication
facilities will be used as deemed appropriate by the Operating Committee.
Communication links other than microwave will be provided, operated and paid
for as determined by the Operating Committee following as closely as possible
the principles established in said sharing Agreement.
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ARTICLE 7
Services
7.01 The specific services and transactions among the Parties
pursuant to this Agreement shall be in conformance with the terms and condi-
tions of this Agreement and as set forth in Schedules arranged from time to
time among the Parties.
The following Schedules are agreed to and hereby made a part of
this Agreement:
Schedule A - CAPCO Back-Up Power
Schedule B - Short Term Power
Schedule C - Non-Displacement Power
Schedule D - Economy Power
Schedule E - Unit Power
Schedule F - Out-of-Pocket Cost
Schedule G - Emergency Power
Schedule H - Transmission of Non-CAPCO Power
Schedule I - Replacement Power
The Parties may, from time to time, agree on modifications to
or additional Schedules, and upon execution thereof by the Parties any such
modification or addition shall become a part of this Agreement.
7.02 Energy transactions (other than those arising under
Schedule E) shall be scheduled as if there were zero transmission losses. A
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Party receiving such energy from another Party (whether such Party is acting
as a supplying or transmitting Party arising under Schedule D of this Agree-
ment) shall be charged with any increase in transmission losses and/or shall
receive credit for any decrease in transmission losses associated with the
transmission of the energy through the systems of Parties other than that of
the supplying Party. Transmission losses will be accounted for by separate
calculation in a manner prescribed by the Operating Committee. Loss
imbalances shall be repaid through loss-payback schedules arranged among the
Parties.
7.03 If any transaction results in material interference with
the facilities or operation of the system of any other Party, the Parties to
the transaction promptly shall take appropriate actions which may include,
among other things, modification of the transaction to eliminate such
interferences and provide compensation to the Party affected for increased
operating costs or damage to facilities.
ARTICLE 8
Executive Committee
8.01 The Executive Committee shall be that established
pursuant to the CAPCO Administration Agreement, dated as of September 14,
1967, as the same may be amended from time to time.
8.02 The Executive Committee shall have the duties and powers
conferred on it by this Agreement, including the making of any decision or
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determination necessary under any provision of this Agreement and not
expressly specified to be decided or determined by any other person or
persons.
ARTICLE 9
Ohio Edison System
9.01 Ohio Edison Company and Pennsylvania Power Company shall
be considered to be separate Parties under this Agreement whenever and to the
extent that separate corporate action is required of such Companies in order
to accomplish the purpose of this Agreement, but their liability and respon-
sibility for the performance of any obligation of OE hereunder to the other
Parties shall be joint and several. The allocation between Ohio Edison
Company and Pennsylvania Power Company of their collective obligations here-
under as OE shall be the sole responsibility of said Companies, but they
undertake that they will, during the period that they shall be obligated under
this Agreement, have in force one or more arrangements for the allocation of
the whole of such collective obligations and will, upon the request of any of
the other Parties hereto, furnish the requesting Party or Parties satisfactory
evidence of the existence of their then effective arrangements relating to
such allocation.
ARTICLE 10
Interconnection Metering
10.01 Electricity flowing across an interconnection shall be
measured by suitable metering equipment at metering points agreed upon by the
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Parties to the interconnection. The equipment at such metering points shall
be provided, owned and maintained as agreed by the affected Parties.
10.02 Measurements of electric energy for the purpose of
effecting settlements shall be made by standard types of electric meters
installed and maintained by the owners at the metering points. The timing
devices of all meters having such devices shall be maintained in time
synchronism as closely as practicable. The meters shall be sealed and the
seals shall be broken only upon occasions when the meters are to be tested or
adjusted.
10.03 The aforesaid standard metering equipment shall be
tested by the owners at suitable intervals and its accuracy of registration
maintained in accordance with good practice. On request of any affected
Party, a special test may be made at the expense of the Party requesting such
special test. Representatives of all affected Parties shall be afforded
opportunity to be present at all routine or special tests and upon occasions
when any readings, for purposes of settlements, are taken from meters not
bearing an automatic record. For the purpose of checking the records of the
metering equipment installed by a Party as provided above, the other affected
Party shall have the right to install check metering equipment at its own
expense at the metering points referred to in Section 10.01.
10.04 If any test of metering equipment shall disclose an
inaccuracy greater than 2%, the accounts among the affected Parties for
service theretofore delivered shall, unless otherwise agreed by the affected
Parties, be adjusted to correct for the inaccuracy disclosed over the shorter
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of the following two periods: (1) from 30 days prior to the receipt of
written request of the test until the meter is corrected; or (2) for the
period that such inaccuracy may be determined to have existed. Should the
metering equipment at any time fail to register under load conditions, or
registers during times of zero flow, the electric energy delivered shall be
determined from the best available data.
ARTICLE 11
Records
11.01 Each Party shall keep such records as may be reasonably
required by the Executive Committee or the Operating Committee, and shall
furnish to such committees such records, reports and other information as they
may reasonably require.
ARTICLE 12
Statements, Billings, Settlements and Payments
12.01 As promptly as practicable within 10 days after the end
of each calendar month, the Parties shall prepare and furnish to every other
Party a statement showing the debits and credits to each Party for Power
transactions hereunder during such month and, to the extent appropriate,
offset or reduce said transactions to a net basis. From the Party balances so
determined, each billing Party shall prepare and send to each other Party, as
appropriate, a billing statement for all transactions which occurred during
the month and involve payment of money. The billing Party shall take all
reasonable measures to ensure that billing statements are mailed or otherwise
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transmitted on the billing statement date. Billing statements may be rendered
on an estimated basis subject to corrective adjustments in subsequent
statements. Other than as required by law or regulatory action or by billing
adjustments must be made for power purchases from non-CAPCO companies,
corrective adjustments for power purchases as defined in Schedules A, B, C, D,
G, H and I must be made within one (1) year of the rendering of the initial
billing statement and corrective adjustments for all other CAPCO billings must
be made within four (4) years of the rendering of the initial billing
statement.
12.02 Billing statements rendered pursuant to Section 12.01
shall be due and payable in good funds the fifteenth calendar day after the
billing statement date of any such statement except that, if the 15th calendar
day is not a business day, the amount billed will be payable the next business
day. Good funds shall consist of checks received at least one business day
prior to the due date and wire transfers received by noon on the due date.
Interest on unpaid billing statement amounts will be compounded monthly and
prorated for any partial month based on a 365-day year, and will accrue at a
rate equal to Chase Manhattan Bank's prime rate on the first day of the then
current calendar quarter plus two percentage points for a period of up to one
year and for any period thereafter at the higher of this rate or a rate equal
to the billing Party's cost of capital which shall consist of the weighted
average of the billing Party's long-term debt cost and preferred stock cost
rates determined for issues outstanding on December 31 of the prior year and a
common equity cost rate to be effective January 1 of each year equal to the
average return on common equity for at least 50 major electric utilities with
positive returns on common equity as reported in the prior year's December
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issue of the C.A. Turner Utility Reports or as reported in the prior year's
latest issue of another report mutually agreed to by the Parties. The
weighting for this calculation shall be the billing Party's capital structure
at December 31 of the prior year, consisting solely of long-term debt,
preferred stock and common equity, as reported in such Party's FERC Form 1 or
in another mutually agreed upon source. Billing adjustments which represent
amounts to be refunded by the billing Party shall accrue interest as noted
above, but billing adjustments payable to the billing Party for additional
amounts shall not accrue interest. Notwithstanding the foregoing, any billing
statement shall not be due and payable to the extent that (1) any non-CAPCO
party system fails to compensate a Party for amounts owed hereunder in which
event such Party shall exercise its best efforts to collect such compensation
from such non-CAPCO party system and will not compromise or settle any claim
for such compensation without prior consent of all other affected parties, or
(2) any non-CAPCO party system's payment date is later that the fifteen days
stated above in which case such billing statement shall be due and payable on
the same date as that of the non-CAPCO party system's payment date. To the
extent that any non-CAPCO party system compensates a Party in an amount less
than the amount the non-CAPCO party system owes the Parties under the Party's
billing statement for amounts owed hereunder, each Party shall be entitled to
be first compensated for Out-of-Pocket Costs associated with the transaction
hereunder and so much of the balance as will result in a sharing of the
remainder among the Parties in proportion to the amounts owed to such Parties
for their respective unpaid charges.
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ARTICLE 13
Government Approvals
13.01 The obligations of each of the Parties hereunder are
subject to the obtaining of any requisite orders, approvals, permits, certif-
icates or licenses from any government authorities having jurisdiction.
13.02 This Agreement is made subject to the jurisdiction of
any government authority or authorities having jurisdiction in the premises.
Nothing contained in this Agreement or any Schedule of this Agreement shall be
construed as affecting in any way the right of any Party to unilaterally make
application to the Federal Energy Regulatory Commission for a change in rates
under the Federal Power Act and pursuant to the Commission's Rules and
Regulations promulgated thereunder.
ARTICLE 14
Notices
14.01 Notices or requests, when required under this Agreement
to be in writing, shall be delivered in person or mailed to the addressee at
such Party's general office. Other notices or requests required under this
Agreement may be given orally and, if required by the other Party, shall
thereafter be confirmed in writing within three working days. Copies of
notices or requests, confirmations of oral notices or requests, and informa-
tion as to oral notices or requests shall be provided to the Office in
accordance with procedures established by the Operating Committee.
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ARTICLE 15
Non-Waiver
15.01 Any waiver at any time by any Party of its rights with
respect to any matter arising in connection with this Agreement shall not be
deemed a waiver with respect to any subsequent similar matter. Any delay,
short of the statutory period of limitation, in asserting or enforcing any
right under this Agreement, shall not be deemed a waiver of such right, except
as provided in Sections 12.01 and 12.02 and in Section 16.01.
ARTICLE 16
Arbitration
16.01 Any controversy or claim arising out of this Agreement,
including the refusal by any Party to perform the whole or any part hereof,
shall, upon demand of any Party aggrieved, be settled by an Arbitration Board,
which shall consist of three nonrepresentative members and such additional
representative members as hereinafter provided in this Section. No person
shall be eligible for appointment as a nonrepresentative member of the
Arbitration Board who is an officer, employee, shareholder of, or otherwise
interested in, any Party or any affiliate thereof or in the matter sought to
be arbitrated.
Unless otherwise agreed, no demand for arbitration shall be
made more than one year after the Parties have reached an impasse as to the
controversy or claim involved. The Party or Parties demanding arbitration
shall serve written notice upon the other Party or Parties to the controversy,
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setting forth in detail the matter or matters with respect to which
arbitration is demanded, and shall serve copies of such notice upon any other
Parties hereto. Within a period of 10 days from the date of receipt of the
aforesaid written notice, each Party to the controversy shall appoint a
representative to serve as a member of the Arbitration Board; and, within a
period of 30 days from such date of receipt of such written notice, such
representative members shall unanimously agree upon the persons who shall
serve as the three nonrepresentative members of the Arbitration Board.
If the representative members are not so appointed within the
specified 30-day period, or if the representative members shall fail to
unanimously agree under the appointment of any or all of the three non-
representative members of the Arbitration Board within the specified 30-day
period, any Party to the controversy may, upon written notice to the other
Parties to the controversy, request the American Arbitration Association to
submit to the Parties to the controversy a list from its panels of arbitrators
of the names of at least seven persons from which the nonrepresentative member
or members who have not been so appointed shall be selected in accordance with
the Commercial Arbitration Rules of such Association.
If any Party to the controversy shall fail to appoint its
representative member within the specified 10-day period, such Party shall be
deemed to have waived its right to appoint such representative member and
the Arbitration Board shall consist of the three nonrepresentative members and
such representative members, if any, as shall have been appointed in
accordance with the provisions of this Section 16.01.
29
The arbitration proceedings shall be conducted at a place, to
be designated by the Arbitration Board, within the service area of one of the
Parties to the controversy. The Arbitration Board shall afford adequate
opportunity to each Party to the controversy to present information with
respect to the controversy or claim submitted to arbitration and may request
further information from any such Party. Except as provided in the preceding
sentence, the Parties to the controversy may, by mutual agreement, specify the
rules which are to govern any proceeding before the Arbitration Board and
limit the matters to be considered by the Arbitration Board, in which event
the Arbitration Board shall be governed by the terms and conditions of such
agreement. To the extent of the absence of any such agreement specifying the
rules which are to govern any proceeding, the then current applicable rules of
the American Arbitration Association for the conduct of commercial arbitration
shall govern the proceedings.
The arbitration shall be limited to the matter or matters
specified in the initial notice demanding arbitration and the award of the
Board shall not affect or change any provision of this Agreement or any other
transaction between the Parties.
Procedural matters pertaining to the conduct of the arbitration
and the award of the Arbitration Board shall be determined by a majority of
the nonrepresentative members thereof; provided, however, that the representa-
tive members shall have full right and authority to participate in all
meetings and deliberations of the Arbitration Board leading to the award. The
findings and award of the Arbitration Board, so made upon a determination of a
30
majority of the nonrepresentative members thereof, shall be final and conclu-
sive with respect to the controversy or claim submitted for arbitration and
shall be binding upon the Parties to the controversy except as otherwise
provided by law. Such award of the Arbitration Board shall specify the manner
and extent of the division of the costs of the arbitration proceedings among
the Parties to the controversy. Judgment upon the award may be entered in any
court, State or Federal, having jurisdiction.
ARTICLE 17
Assignment
17.01 No Party may, without the prior written consent of the
others, assign this Agreement, except as the same may be assigned (a) volun-
tarily or otherwise under its first mortgage, or (b) to a successor to all or
substantially all of the assets of the Party by way of merger, consolidation,
sale or otherwise, where the successor assumes and becomes liable for all the
obligations of the Party hereunder.
ARTICLE 18
Governing Law
18.01 This Agreement is made under and shall be governed by
the laws of the State of Ohio insofar as applicable.
31
ARTICLE 19
Other Agreements
19.01 During the term of this Agreement, its terms, conditions
and Schedules shall be applicable to transactions among the Parties. This
Agreement is not to be interpreted as conflicting or interfering with the
performance of any agreement including modifications or amendments thereto
between any Party and any system not a Party to this Agreement, effective
prior to August 31, 1980.
The Parties hereto shall be free to enter into any new agree-
ments with other Parties or with other systems which do not impair operations
under this Agreement or the ability of a Party to perform its obligations
under this Agreement.
The following agreements identified by FERC rate schedule
numbers shown for each listed company are hereby terminated:
Company FERC Rate Schedule Number(s)
The Cleveland Electric Illuminating Company 25
Duquesne Light Company 21
Ohio Edison Company 157
Pennsylvania Power Company 44
The Toledo Edison Company 35
32
ARTICLE 20
Term of Agreement
20.01 Except as provided in Section 20.03, this Agreement
shall continue in effect until such time as all CAPCO Units are retired.
20.02 Any Party may withdraw from this Agreement by giving one
year's advance notice in writing to the members of the Executive Committee of
the other Parties, provided that in the event of such withdrawal, the provi-
sions of this Agreement relating to coordinated maintenance of CAPCO Units,
CAPCO Back-Up Power, and CAPCO Replacement Power shall continue in effect
until such time as all CAPCO Units are retired.
20.03 Notwithstanding the retirement of all CAPCO Units under
Section 20.01 and the withdrawal of any Party under Section 20.02, this
Agreement shall continue in effect for those Parties who do not withdraw from
this Agreement.
ARTICLE 21
Separate Identities
21.01 The duties, obligations and liabilities of the Parties
are intended to be several and not joint or collective, and nothing herein
contained shall ever be construed to create an association, joint venture,
trust or partnership or to impose a trust or partnership duty, obligation or
liability on or with regard to any Party. Each Party shall be individually
responsible for its own obligations as herein provided. No Party shall be
33
under the control of or shall be deemed to control another Party by virtue of
this Agreement. No Party shall have a right or power to bind another without
its or their express written consent, except as expressly provided in this
Agreement.
ARTICLE 22
Force Majeure
22.01 No Party shall be considered to be in default in the
performance of any of the obligations hereunder if failure of performance
shall be due to uncontrollable forces. The term "uncontrollable forces" shall
mean any cause beyond the control of the Party affected, including but not
limited to the failure of facilities, flood, earthquake, storm, fire,
lightning, epidemic, war, riot, civil disturbance, labor dispute, sabotage,
restraint by Court order or public authority or inability to obtain necessary
licenses or permits. Nothing herein shall be construed so as to require a
Party to settle any strike or labor dispute in which it may be involved. Any
Party which is unable to fulfill any obligations by reason of uncontrollable
forces shall exercise due diligence to remove such inability with all
reasonable dispatch.
ARTICLE 23
Liability
23.01 All claims arising out of any bodily injury, death or
damages to property or business of third persons (other than customers, as
such, of any of the Parties) arising because of operations under this
34
Agreement caused or sustained on the system of a Party (the Defending Party)
shall be defended or in its discretion settled by such Party. In the event
any action on any such claim is brought against any other Party, such other
Party shall promptly notify the Defending Party in writing, and the Defending
Party shall be entitled to and shall take over and direct the defense and
disposition of the case. Any amounts paid by way of settlement or in
satisfaction of any judgment and all expenses associated with such defense or
settlement shall be the responsibility of the Defending Party. The provisions
of this Section do not apply to claims of the employees of any Party under any
workers' compensation law, for which the employing Party shall be responsible.
23.02 Each Party hereby waives any and all claims it may have
against any other Party arising from negligence or other fault of another
Party in connection with operations under this Agreement, except as otherwise
provided in Section 7.03.
35
IN WITNESS WHEREOF, the Parties hereto have caused this
Agreement to be executed by their duly authorized officers this 23rd day of
December, 1993.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
By: TERRENCE G. LINNERT
Title: Vice President
DUQUESNE LIGHT COMPANY
By: G. R. BRANDENBERGER
Title: Vice President
OHIO EDISON COMPANY
By: ARTHUR P. GARFIELD
Title: Vice President
PENNSYLVANIA POWER COMPANY
By: J. R. EDGERLY
Title: Vice President
THE TOLEDO EDISON COMPANY
By: TERRENCE G. LINNERT
Title: Vice President
36
CAPCO BASIC OPERATING AGREEMENT
SCHEDULE A
CAPCO BACK-UP POWER
Section 1 - Applicability
1.1 This Schedule A is applicable to CAPCO Back-Up Power transactions
among the Parties pursuant to the provisions of Article 5 of the CAPCO Basic
Operating Agreement ("Agreement").
Section 2 - Compensation for CAPCO Back-Up Power
2.1 Demand Charge
Receiving Party shall pay the supplying Party a demand charge
calculated on a daily basis for the net amount of CAPCO Back-Up Power reserved
at a rate not to exceed $323 per MW per day, plus the excess demand charge, if
any, of the amount paid therefor by the supplying Party over such demand
charge for each megawatt of capacity that is purchased by a supplying Party
from a Party or a non-CAPCO party system to provide CAPCO Back-Up Power. If
at any time during a day a supplying Party is unable to provide all or any
portion of the capacity reserved, the demand charge for the capacity not
provided will be canceled for that day.
Supplying Parties will communicate to the Receiving Parties
significant changes in estimated energy costs occurring during the day. If
the supplying Party's estimated Out-of-Pocket Costs for energy increase beyond
37
limits established by the Operating Committee from the estimate which was used
as the basis for the reservation, a receiving Party shall have the right to
cancel all or any part of the balance of the daily reservation (other than any
specific reservation from third parties) which will include the cancellation
of the daily demand charge for the capacity canceled.
In the event the total energy cost of a supplying Party for a
particular day (other than the cost of the specific reservation from third
parties) exceeded the total energy cost quoted by such Party for that day
beyond limits established by the Operating Committee, such Party's demand
charge for that day shall not be payable.
2.2 Capacity Charge
Receiving Party shall pay the supplying Party a charge not to
exceed the supplying Party's Out-of-Pocket Cost of providing operating
capacity; plus a charge not to exceed $2.40 per MW-hr for operating capacity
provided from a supplying Party's system; or plus a charge not to exceed $1.00
per MW-hr for operating capacity purchased from a non-CAPCO party system.
2.3 Capacity and Energy
Receiving Party shall pay the supplying Party a charge not to
exceed the supplying Party's Out-of-Pocket Cost of providing operating
capacity and energy; plus a charge not to exceed $2.40 per MWh for operating
38
capacity and energy provided from the supplying Party's system; or plus a
charge not to exceed $1.00 per MWh for operating capacity and energy purchased
from a non-CAPCO party system.
2.4 Total Compensation
Notwithstanding the rates stated in Subsections 2.1, 2.2 and 2.3
above for any CAPCO Party generating CAPCO Back-Up Power, the sum of the
demand, capacity and the capacity and energy charges provided in such
subsections for each specific reservation made pursuant to this Schedule A
shall not be less than 100% of the total Out-of-Pocket Cost of supplying the
CAPCO Back-Up Power for such reservation; plus any demand charges paid to a
non-CAPCO party and provided additionally, however, that any incremental or
decremental transmission losses incurred on the system of any other Party
resulting from the transmission of such energy shall be treated in accordance
with Article 7.
39
CAPCO BASIC OPERATING AGREEMENT
SCHEDULE B
SHORT TERM POWER
Section 1 - Services to be Rendered
Any Party may arrange to reserve from another Party for periods of one or
more days or weeks Short Term Power whenever, in the sole judgment of the
Party requested to supply the same, such Short Term Power is available. As
used herein, the term "week" shall mean any seven consecutive days.
1.1 Prior to each reservation of Short Term Power, the number of mega-
watts to be reserved and the period of the reservation shall be determined by
the Parties to the transaction. Such determination shall be confirmed in
writing. If during such period conditions arise that could not have been
reasonably foreseen at the time of reservation and cause the reservation to be
burdensome to the supplying Party, such Party may by oral or written notice to
the receiving Party, reduce the number of megawatts to be reserved by such
amount and for such times as it shall specify in such notice.
1.2 During each period that Short Term Power has been reserved, the
supplying Party shall upon call provide Short Term Operating Capacity up to
and including the number of megawatts then reserved and deliver Short Term
Energy to the receiving Party, as scheduled by the receiving Party, in an
amount during each hour up to and including the number of megawatts of Short
Term Operating Capacity then being provided.
40
Section 2 - Compensation
2.1 Demand Charge
The receiving Party shall pay the supplying Party for any week that
Short Term Power is reserved, a demand charge in an amount not to exceed
$2,121 per MW reserved for that week, less one-sixth of such demand charge per
MW of reduction for each day (other than Sunday) during any part of which the
amount of such Short Term Power is reduced by the supplying Party; or for any
period less than a week but not less than a day that Short Term Power is
reserved, a demand charge in an amount not to exceed $424 per MW per day, less
such demand charge per MW of reduction for each day during any part of which
the amount of such Short Term Power is reduced by the supplying Party; plus
The receiving Party shall pay the supplying Party for each megawatt
of capacity reserved under this Schedule that is purchased by the supplying
Party from a non-CAPCO party system, the excess, if any, of the amount paid
therefor by the supplying Party over the demand charge therefor agreed to
under Paragraph 1 of Subsection 2.1 above (or, if such amount is less than
such agreed to demand charge, minus the deficiency); plus for such trans-
actions a demand charge not to exceed $447 per MW week or $89.40 per MW day
shall apply based on the agreed upon period. The supplying CAPCO Party will
determine the demand charge for each transaction; plus
41
2.2 Capacity Charge
Receiving Party shall pay the supplying Party a charge not to
exceed the supplying Party's Out-of-Pocket Cost of providing operating
capacity; plus a charge not to exceed $2.40 per MW-hr for operating capacity
provided from a supplying Party's system; or plus a charge not to exceed $1.00
per MW-hr for operating capacity purchased from a non-CAPCO party system.
2.3 Capacity and Energy
Receiving Party shall pay the supplying Party a charge not to
exceed the supplying Party's Out-of-Pocket Cost of providing operating
capacity and energy; plus a charge not to exceed $2.40 per MWh for operating
capacity and energy provided from the supplying Party's system; or plus a
charge not to exceed $1.00 per MWh for operating capacity and energy purchased
from a non-CAPCO party system.
2.4 Total Compensation
Notwithstanding the rates stated in Subsections 2.1, 2.2 and 2.3
above for any CAPCO Party generating Short Term Power, the sum of the demand,
capacity and the capacity and energy charges provided in such subsections for
each specific reservation made pursuant to this Schedule B shall not be less
than 100% of the total Out-of-Pocket Cost of supplying the Short Term Energy
for such reservation; plus any demand charges paid to a non-CAPCO party and
42
provided additionally, however, that any incremental or decremental
transmission losses incurred on the system of any other Party resulting from
the transmission of such energy shall be treated in accordance with
Article 7.
43
CAPCO BASIC OPERATING AGREEMENT
SCHEDULE C
NON-DISPLACEMENT POWER
Section 1 - Services to be Rendered
1.1 Transactions not specifically provided for under other Schedules
may be mutually advantageous and may be arranged between Parties when one
Party has operating capacity and/or energy it is willing to make available to
another Party as Non-Displacement Power. Such transactions shall be arranged
in advance and shall specify the amount of operating capacity to be provided,
if any, and the hours it is to be provided. Energy to be delivered under this
Schedule shall be as scheduled by the receiving Party.
Section 2 - Compensation
2.1 Demand Charge
Non-Displacement Power shall be compensated for at the option of
the supplying Party (1) by return-in-kind or (2) by payment of a demand charge
not to exceed $26.51 per MWh, the charge in any one day not to exceed $424
times the maximum MW(s) reserved in any one hour of that day and the charge in
that week not to exceed $2,121 times the maximum MW(s) reserved in any one
hour of that week when supplied from a CAPCO party system; plus
For each megawatt of capacity reserved under this Schedule that is
purchased by the supplying Party from a non-CAPCO party system, the excess, if
44
any, of the amount paid therefor by the supplying Party over the demand charge
therefor agreed to under Paragraph 1 of Subsection 2.1 above (or, if such
amount is less than such agreed to demand charge, minus the deficiency); plus
for such transactions a demand charge not to exceed $5.59 per MWh shall apply.
However, the charge in any one day is not to exceed $89.40 times the maximum
MW(s) reserved in any one hour in that day and the charge in that week not to
exceed $447 times the maximum MW(s) reserved in any one hour in that week.
The supplying CAPCO Party will determine the demand charge for each
transaction; plus
2.2 Capacity Charge
Receiving Party shall pay the supplying Party a charge not to
exceed the supplying Party's Out-of-Pocket Cost of providing operating
capacity; plus a charge not to exceed $2.40 per MW-hr for operating capacity
from a supplying Party's system; or plus a charge not to exceed $1.00 per
MW-hr for operating capacity or purchased from a non-CAPCO party system.
2.3 Capacity and Energy Charge or Energy Only Charge
Receiving Party shall pay the supplying Party a charge not to
exceed the supplying Party's Out-of-Pocket Cost of providing operating
capacity and energy; plus a charge not to exceed $2.40 per MWh for operating
capacity and energy provided from the supplying Party's system; or plus a
charge not to exceed $1.00 per MWh for operating capacity and energy purchased
from a non-CAPCO party system.
45
2.4 Total Compensation
Notwithstanding the rates stated in Subsections 2.1, 2.2 and 2.3
above for any CAPCO Party generating Non-Displacement Power, the sum of the
demand, capacity and energy charges provided in such subsections for each
reservation made pursuant to this Schedule C shall not be less than 100% of
the total Out-of-Pocket Cost of supplying the Non-Displacement Energy for such
reservation; plus any demand charges paid to a non-CAPCO party and provided
additionally, however, that incremental or decremental transmission losses
incurred on the system of any other Party resulting from the transmission of
such energy shall be treated in accordance with Article 7.
46
CAPCO BASIC OPERATING AGREEMENT
SCHEDULE D
ECONOMY POWER
Section 1 - Services to be Rendered
1.1 Economy Capacity
Any Party may arrange to purchase from any other Party Economy
Capacity whenever, in the sole judgment of the Party requested to provide the
same, such Economy Capacity can be made available. Prior to its being made
available, the amount of Economy Capacity to be provided, the period during
which it is to be provided, and the charge therefor shall be determined by the
Parties to the transaction. The charge agreed to shall not be subject to
later review or adjustment. Economy Capacity may also be arranged to be
obtained from or delivered to non-CAPCO party systems interconnected with a
Party.
1.2 Economy Energy or Power
Any Party may arrange to purchase from any other Party Economy
Energy or Power whenever it is possible to effect a saving thereby and, in the
sole judgment of the Party requested to supply the same, such Economy Energy
or Power is available. Prior to each delivery of Economy Energy or Power, the
amount and time of delivery and the charge therefor shall be determined by the
Parties to the transaction. The charge agreed to shall not be subject to
later review or adjustment. Economy Energy or Power may also be arranged to
be obtained from or delivered to non-CAPCO party systems interconnected with a
Party.
47
Section 2 - Discontinuance of Services
2.1 Service being provided under this Schedule may be discontinued at
any time provided, however, that a Party making available Economy Capacity
shall allow the other Party a reasonable opportunity to restore its own
operating capacity or make other arrangements before discontinuing such
Economy Capacity; and provided further that the receiving Party shall be
obligated to pay to the supplying Party an amount not less than the Out-of-
Pocket Cost of the supplying Party.
Section 3 - Compensation
3.1 Economy Capacity
The charge for Economy Capacity shall be based on the principle
that the Party purchasing it shall pay the Out-of-Pocket Cost of providing it,
and that the resulting savings to such Party shall be shared by the supplying
and receiving Parties as determined by the supplying Party. When Economy
Capacity is obtained from or delivered to non-CAPCO party systems inter-
connected with a Party, payments shall be based on the Out-of-Pocket Cost of
supplying the Economy Capacity and an allocation of the gross savings which
are defined as the difference between (1) what the Out-of-Pocket Costs of the
receiving Party or system would have been to supply such Economy Capacity, and
(2) the Out-of-Pocket Cost of the supplying Party or system providing the
Economy Capacity. Such allocation shall be made as provided in Subsections
3.11 and 3.12.
48
3.11 Each Party or system participating in the transaction other than
the supplying and receiving Parties or systems, shall be paid (a) its cost of
purchasing the Economy Operating Capacity supplied, plus an amount not to
exceed (b) the greater of (i) 15% of the gross savings or (ii) the sum of a
demand charge of $5.59 (however, the charge in any one day is not to exceed
$89.40 times the maximum MW(s) reserved in any one hour of that day and the
charge in that week not not to exceed $447 times the maximum MW(s) reserved in
any one hour in that week) per MW reserved per hour plus $1.00 per MWh from a
third party, plus any incremental costs or taxes incurred that would not
otherwise have been incurred. In the event a Party or system participating in
the transaction (other than the supplying and receiving Parties or systems) is
to be compensated at a different amount of gross savings or demand charge
under the terms and conditions of that Party's or system's interconnection
agreement with a non-CAPCO party receiving the Power, then that Party or
system shall be compensated at the rate specified in the interconnection
agreement with the non-CAPCO party system receiving the Power.
3.12 The supplying Party or system shall be paid its Out-of-Pocket Cost
of providing the Economy Capacity, plus a portion of the gross savings as
determined by the supplying Party remaining after deducting payments made
under Subsection 3.11 (b). The receiving Party or system shall be entitled to
the remaining gross savings.
49
3.2 Economy Energy or Power
The charge for Economy Energy or Power shall be based on the prin-
ciple that the Party purchasing it shall pay the Out-of-Pocket Cost of pro-
viding it and that the resulting savings to such Party shall be shared by the
supplying and receiving Parties as determined by the supplying Party. When
Economy Energy or Power is obtained from or delivered to non-CAPCO party
systems interconnected with a Party, payments shall be based on the Out-of-
Pocket Cost of supplying the Economy Energy or Power and an allocation of the
gross savings which are defined as the difference between (1) what the
Out-of-Pocket Costs of the receiving Party or system would have been to
generate such Economy Energy or Power, and (2) the Out-of-Pocket Cost of the
supplying Party or system providing the Economy Energy or Power. Such
allocation shall be made as provided in Subsections 3.21 and 3.22.
3.21 Each Party or system participating in the transaction other than
the supplying and receiving Parties or systems, shall be paid (a) its cost of
purchasing the Economy Energy or Power supplied, plus (b) its cost of addi-
tional transmission losses incurred, plus (c) an amount not to exceed the
greater of (i) 15% of the gross savings remaining after deducting all such
payments for transmission losses, if any or (ii) the sum of a demand charge of
$5.59 (however, the charge in any one day is not to exceed $89.40 times the
maximum MW(s) reserved in any one hour of that day and the charge in that week
not not to exceed $447 times the maximum MW(s) reserved in any one hour in
that week) per MW reserved per hour plus $1.00 per MWh from a third party,
plus any incremental costs or taxes incurred that would not otherwise have
been incurred. In the event a Party or system participating in the
50
transaction (other than the supplying and receiving Parties or systems) is to
be compensated at a different amount of gross savings or demand charges under
the terms and conditions of that Party's or system's interconnection agreement
with a non-CAPCO party receiving the Power in the transaction, then that Party
or system shall be compensated at the rate specified in the interconnection
agreement with the non-CAPCO party system receiving the Power and provided
additionally, however, that any incremental or decremental transmission losses
incurred on the system of any other Party resulting from the transmission of
such energy shall be treated in accordance with Article 7.
3.22 The supplying Party or system shall be paid its Out-of-Pocket Cost
of providing the Economy Energy or Power, plus a portion of the gross savings
remaining as determined by the supplying Party after deducting all payments
made under Subsections 3.21 (b) and (c). The receiving Party or system shall
be entitled to the remaining gross savings and provided additionally, however,
that any incremental or decremental transmission losses incurred on the system
of any other Party resulting from the transmission of such energy shall be
treated in accordance with Article 7.
51
CAPCO BASIC OPERATING AGREEMENT
SCHEDULE E
UNIT POWER
Availability
This Schedule is available to a Party ("receiving Party") which has
agreed with another Party ("supplying Party") to purchase for a specified
period of time a specified amount of capacity out of the portion of a
particular CAPCO Unit owned by the supplying Party.
Section 1 - Services to be Rendered
1.1 The amount of capacity purchased by a receiving Party shall be
expressed as a fraction of the Unit's Net Demonstrated Capability of which the
numerator is the receiving Party's entitlement in MW as purchased and the
denominator is the Unit's Net Demonstrated Capability in MW at the time of the
purchase. Unless otherwise agreed by the Parties to the transaction, such
fraction shall remain the same notwithstanding any redetermination of the
Unit's Net Demonstrated Capability. The supplying Party shall be obligated to
provide and the receiving Party shall be entitled to receive in any hour upon
request by the receiving Party up to an amount of capacity and energy equal to
the Unit's expected capability for that hour multiplied by such fraction.
1.2 In the event the receiving Party schedules less than its full
entitlement, the balance of its entitlement shall remain as unloaded capacity
available to it.
52
1.3 At any time when the Unit is operated at minimum net generation re-
quired for safe operation of the Unit, each receiving Party shall be obligated
to schedule an amount of energy equal to the Unit's minimum net safe genera-
tion for the hour multiplied by the fraction determined in Subsection 1.1;
provided that, if any Party having an entitlement shall schedule more than its
percentage entitlement of such minimum net safe generation, the other Party or
Parties shall be obligated to schedule an amount of energy not less than the
balance of such minimum net safe generation in proportion to its percentage
entitlement in the Unit.
1.4 The amount of capacity and energy scheduled under Subsections 1.1,
1.2 and 1.3 above, subject to adjustment for proportionate use of all plant
auxiliary Power assignable to the operation of the Unit, and adjusted for a
proportionate share of the generation step-up transformer losses if the
metering is located at the low voltage terminals, shall constitute scheduled
billing values (net) as of the Unit's generator transformer high voltage
terminals. The supplying Party shall schedule for delivery from its system,
an amount of energy equal to the energy billing value less the increase, or
plus the decrease, as the case may be, in electrical losses, incurred on the
system of the supplying Party resulting from the transmission of such energy.
The receiving Party shall schedule for receipt into its system an equivalent
amount of energy to that scheduled for delivery by the supplying Party. The
losses incurred on the system of any Party other than the supplying or
receiving Parties resulting from the transmission of such energy shall be
banked. Any such other Party so affected shall schedule for delivery from its
system the decrease in losses it incurred or shall schedule for receipt into
its system the increase in losses it incurred in accordance with rules and
53
procedures established by the Operating Committee. Electrical losses shall be
determined in accordance with rules and procedures established by the
Operating Committee.
Section 2 - Adjustments
2.1 If the supplying Party's records indicate that the receiving Party
was entitled to schedule (or was obligated to schedule) values less than, or
more than those determined pursuant to Section 1 above for any extended period
of time, adjustments in future scheduling will be made by agreement of the
Parties to the transactions to compensate for such differences.
Section 3 - Auxiliary Power for Maintenance
3.1 During the period of the transaction, the receiving Party shall be
obligated to the supplying Party for maintenance auxiliary energy.
3.2 The amount of maintenance auxiliary energy obligation shall be a
figure in MWh equal to the total auxiliary Power used by the Unit's auxiliary
equipment when the Unit is off for maintenance multiplied by the fraction
determined pursuant to Subsection 1.1.
3.3 Such obligation for maintenance auxiliary energy shall be dis-
charged by reimbursement to the operating Owner at the operating Owner's
system average cost (including net purchase Power costs) for supplying net
energy for load during the current calendar month, adjusted to exclude the
output and cost during the current calendar month of the Unit to which such
54
maintenance auxiliary energy was supplied. In the event actual costs are not
available, estimated costs will be used for the current month's calculations
and an adjustment, based upon the deviation of estimated actual costs will be
made in the next succeeding month.
Section 4 - Compensation
4.1 The receiving Party shall compensate the supplying Party for Opera-
tion and Maintenance costs, monthly, on a basis consistent with the method
used to compensate the operating Owner by nonoperating Owners.
4.2 Additionally, the receiving Party shall pay the supplying Party,
monthly, Fixed Charges which shall cover Return on Investment, Depreciation
and Income Tax.
In the event that a CAPCO Unit is placed in commercial operation at a
capability which is not within a reasonable range of the expected Net Demon-
strated Capability, a proportional amount of the capital costs of such Unit
will be retained in FERC Account 107, Construction Work in Progress, and will
continue to accrue allowance for funds used during construction. Such portion
shall be excluded from the determination of Fixed Charges payable by the
receiving Party.
In the event that the final Net Demonstrated Capability of a Unit proves
to be different from the original expected Net Demonstrated Capability, the
remaining portion of the capital costs shall be transferred to FERC Account
101, Electric Plant In-Service, and all of the capital costs shall then be
55
included in the determination of Fixed Charges payable by the receiving Party.
The operating Owner shall have the responsibility for determining the timing
and level of the final Net Demonstrated Capability.
In any event, the amount of investment in FERC Account 101, Electric
Plant In-Service, shall be the basis for determining Fixed Charges to be paid.
4.3 The supplying Party shall also bill the receiving Party for its
share of property, franchise, business or other taxes and insurance applicable
to its share of the Unit, based on the fraction determined pursuant to
Subsection 1.1 specifically identifying these items on the invoice. To the
extent that such taxes and insurance are charged to the operating expenses of
the Unit, because it is impractical or inequitable to segregate them, they
will be billed as part of the normal operating expense of the Unit.
4.4 Specific charges applicable to each transaction under this Schedule
from a particular Unit supplying the capacity and energy shall be set forth in
appropriate Appendices to this Schedule, or in separate agreements to be
attached to or referred to in appropriate Appendices to this Schedule.
56
APPENDICES TO SCHEDULE E
TO THE CAPCO BASIC OPERATING AGREEMENT
As Amended January 1, 1993
(1) APPENDIX 1 TO SCHEDULE E, which was filed as part of Exhibit
10b(3), 1992 Form 10-K, File Nos. 1-9130, 1-2323 and 1-3583,
filed by Centerior Energy, Cleveland Electric and Toledo Edison,
remains in full force and effect, except for SM-7 Pages 16-22,
19-22, 20-22 and 21-22, revised copies of which are filed
herewith.
(2) APPENDIX 2 TO SCHEDULE E has been revised from previous filings
and is filed in full herewith.
(3) APPENDIX 3 TO SCHEDULE E, which was filed as part of Exhibit
10.24, 1980 Form 10-K, File No. 1-956, filed by Duquesne,
remains in full force and effect, except for MF-1 Pages 17-21,
18-21, 19-21 and 20-21, revised copies of which are filed
herewith.
(4) APPENDIX 4 TO SCHEDULE E, which was filed as part of Exhibit
10.24, 1980 Form 10-K, File No. 1-956, filed by Duquesne,
remains in full force and effect, except for BV-1 Pages 20-25,
21-25, 22-25, 23-25 and 24-25, revised copies of which are filed
herewith.
(5) APPENDIX 5 TO SCHEDULE E, which was filed as part of Exhibit
10.24, 1980 Form 10-K, File No. 1-956, filed by Duquesne,
remains in full force and effect, except for MF-2 Pages 17-21,
18-21, 19-21 and 20-21, revised copies of which are filed
herewith.
(6) APPENDIX 6 TO SCHEDULE E has been revised from previous filings
and is filed in full herewith.
(7) APPENDIX 7 TO SCHEDULE E, which was filed as part of Exhibit
10b(3), 1992 Form 10-K, File Nos. 1-9130, 1-2323 and 1-3583,
filed by Centerior Energy, Cleveland Electric and Toledo Edison,
remains in full force and effect, except for PY-1 Pages 11-18,
12-18, 13-18, 16-18 and 17-18, revised copies of which are filed
herewith.
(8) APPENDIX 8 TO SCHEDULE E has been revised from previous filings
and is filed in full herewith.
57
APPENDIX 1 TO SCHEDULE E, which was filed as part of Exhibit 10b(3),
1992 Form 10-K, File Nos. 1-9130, 1-2323 and 1-3583, filed by
Centerior Energy, Cleveland Electric and Toledo Edison, remains in
full force and effect, except for SM-7 Pages 16-22, 19-22, 20-22 and
21-22, revised copies of which are filed herewith.
58
SM-7 (Page 16 of 22)
CODE BASIS - (Cont'd)
SY(IR) Coal Allocation Ratio
The portion of the cost to charge to a Purchaser(s) during the
current month shall be (a) the total tons of coal allocated to the
Purchaser(s) for the preceding 12-month period determined as set
forth in Section IV divided by (b) the tons of coal charged to OE
for the Sammis Unit No. 7 for the same 12-month period.
Section IV - Fuel
In determining fuel costs the Purchaser(s) shall be treated in the same
manner as an owner. The tons of coal and the costs thereof shall be
allocated in proportion to the Btu's consumed to produce the kilowatt hours
taken by each of those sharing in the output of the unit, taking into account
the Btu's consumed during start-ups of the unit. OE's share of Btu's used
during a start-up (including Btu's which may be supplied by transfers of
steam from steam sources other than that unit's own steam source) and Btu's
computed to have been used during periods of synchronized on-line operation
of the unit to maintain zero load on the unit (the "Y" intercept, or no load
input, of the standard Input/Output equation for the unit) shall be allocated
among those sharing in the OE's share of the output of the unit in proportion
to their investment responsibilities in the unit during the month for which
allocation is being made. Btu's consumed during periods of synchronized
on-line operation in excess of those used to maintain zero load on the unit
(see preceding statement) shall be allocated each hour in proportion to the
net kilowatt hours determined to have been taken from the unit by each of
those sharing in the output of the unit.
Section V - Other Expenses
For billing costs to the Purchaser, labor and material additive costs at
current rates prevailing in the industry as adjusted from time to time shall
be added to the labor and material components of direct operation and
maintenance costs of W. H. Sammis Unit No. 7 to which such rates are
applicable and shall be shared by Purchasers on the same bases on which the
primary labor and material costs are shared.
In addition, an allocation will be made of Account 556, System Control and
Load Dispatching costs related to production, and Account 557, Other
Production Expenses. These costs would be allocated to W. H. Sammis Unit No.
7 on a direct basis where a direct relationship exists, or by using a net
generating capability ratio (O(IR)) where a direct relationship does not
exist. Account 556 will include only those load dispatching costs incurred
by OE that are attributable to W. H. Sammis Unit No. 7. Included in Account
557, Other Production Expenses, are such items as insurance premiums and
recoveries and other production expenses not directly assignable to the other
production accounts. The invoice will identify amounts billed that were
included in Account 557.
59
SM-7 (Page 19-22)
Sales of Capacity and Energy from Base Load Units
to Purchasers: W. H. Sammis Unit No. 7
Exhibit C - Reimbursement of Working Capital Costs
I. Fuel (Coal and Oil) Inventory - Working capital cost applicable to
a purchaser.
Reimbursement by Monthly Carrying Charge in Lieu of Deposit
The charge for a given month per megawatt of capacity purchased (or
shared) shall be based on the Supplying Party's total dollar balance
in Fuel (Coal and Oil) inventory at the end of the month in which
service was rendered, and shall be calculated as follows:
W. J. Sammis Unit No. 7 - The Product Of:
(a) Total Dollars in Supplying Party's Fuel (Coal and Oil)
Inventory at the Entire Plant
(b) The Ratio of Total Megawatt Capacity Purchased (or Shared)
to the Total Megawatts of Supplying Party's Plant Capacity.
(c) One-Twelfth* of the Supplying Party's Current Annual Capital
Cost Rate, augmented to Include Supplying Party's Income
Tax Liability on the Equity Component.
II. Monthly Operation & Maintenance Expenses - Working capital cost
applicable to a purchaser or to a participant.
Reimbursement by Monthly Carrying Charge in Lieu of Deposit
The monthly charge shall be calculated each month for the Unit as the
product of (a) and (b) for capacity owned and as the product of (a),
(b) and (c) for capacity purchased.
(a) The current month's direct operating expenses (Accounts
500-554, 556, 557, 562 and 570) for each Participant for the
Unit, including overheads, less fuel and lease payments, and
any other inappropriate items.
(b) One-Twelfth* of the Operating Company's Current Annual Capital
Cost Rate plus the Operating Company's income tax liability
on the equity component.
(c) The Purchaser's entitlement share of megawatt capacity in
the Unit.
*Fraction used to calculate working capital for purposes of this Exhibit
60
SM-7 (Page 20-22)
III. Monthly Working Capital on M&S Inventory (Excluding Coal and Oil) -
Working capital cost applicable to a purchaser or to a participant.
Reimbursement by Monthly Carrying Charge in Lieu of Deposit
The monthly charge shall be calculated each month for the Unit as
a product of (a), (b), (c) and (d) for capacity purchased.
(a) The Operating Company's balance in M&S Inventory
(excluding coal and oil) at the plant.
(b) The ratio of megawatt capacity owned is required for
units in which the plant materials and operating supplies
inventory is not owned by the CAPCO partners and shall be
calculated as follows:
A = C
B
Where:
A= An owning Company's megawatt share in the unit.
B= Total megawatt capacity of all units on site
excluding short lead time capacity units.
C= Ratio of an owning Company's portion of megawatt
capacity owned.
c) One-Twelfth* of the Operating Company's Current Annual
Capital Cost Rate plus the Operating Company's income tax
liability on the equity component.
d) The Purchaser's entitlement share of megawatt capacity in
the Unit.
*Fraction used to calculate working capital for purposes of this Exhibit
61
SM-7 (Page 21 of 22)
(BLANK)
62
APPENDIX 2 TO SCHEDULE E has been revised from previous filings
and is filed in full herewith.
63
EL-5 (Page 1 of 13)
APPENDIX 2 TO SCHEDULE E
Charges Applicable to Transactions from Eastlake Unit No. 5
Pursuant to Schedule E
This Appendix provides for specific charges applicable to transactions made
from Eastlake Unit No. 5 pursuant to Schedule E.
Costs will be shared on a basis equivalent to that of the joint owners with
certain modifications specified herein.
The following are the components of the costs to be included.
A. Fixed Costs of Invested Capital
1. It is expected that sales out of production units will occur pre-
dominantly over a relative short time period in the early part of the
unit's life. However, this Appendix develops a consistent basis
which is applicable throughout the life cycle.
2. Amortization and tax calculations are based on the following:
Amortization Period - 35 Years (420 Months)
DDB Tax Life 28 Years (336 Months)
Estimated Salvage Rate -5%
Accounting Treatment Flow-Through
3. DDB tax depreciation is assumed, with switch to straight line method
effective the first month in which the straight line remaining life
depreciation exceeds DDB depreciation, with remaining life stretched
out in the straight line calculations to extend to the end of the
book amortization period. The switch occurs at the end of the 221st
month.
4. All fixed charges are on a month-to-month declining basis. The
investment base from which fixed charges are developed shall be the
CAPCO investment basis as defined in the Accounting and Procedure
Manual under Procedures for Discharging Investment Responsibility.
5. The monthly finance charge rate applicable to all additions from the
in-service date through the last month of the calendar year in which
the construction job order is closed out shall be one-twelfth the
specified annual rate.
6. The finance charge rate for ordinary additions in years subsequent to
the calendar year in which the construction job order was closed out
shall be the specified rate.
64
EL-5 (Page 2 of 13)
7. Amortization and other charges and adjustments shall be billed each
month. Each month's additions to plant in-service shall constitute a
vintage investment. However, in order to simplify the billing
process, the monthly vintages of any particular calendar year may be
combined into a composite vintage, either on an ongoing basis or at
the end of the calendar year, providing the same billing results.
Since finance charge rates are recalculated each year, vintages of
different calendar years will not be composited.
8. The tax plant ratio to amortizable plant (CAPCO investment basis)
shall be established from data for the total project as estimated at
the in-service date, as described in Paragraph 5. This ratio will be
used in developing fixed charge rates for the initial placements and
all subsequent additions; except that in the case of major capital
additions, at seller's option and with buyers' concurrence, a
completely new vintage may be developed and the fixed charge factor
recalculated using the new tax plant ratio and other pertinent data
as appropriate.
9. When a production unit, or a major capital addition such as described
in Paragraph 7, is placed in commercial service, the first fixed
charge billing shall begin effective with the in-service date. For
subsequent month-to-month additions, the billing shall begin with the
first full calendar month after the addition is made.
10. Where sales are initiated out of an existing production facility to a
new buyer, a single-vintage CAPCO investment basis may be calculated
with an appropriate adjustment for depreciation incurred to date.
The amortization component of the fixed charge factor will be calcu-
lated on the basis of remaining life of the original amortization
period or by mutual agreement.
11. The specific fixed charge rate for Eastlake Unit No. 5 is developed
in Exhibit B.
B. Operating and Maintenance Costs
1. The methods specified in the attached Exhibit A shall be used to
allocate between the supplying Party and the receiving Party(s) or
Purchaser(s) all costs, including overheads directly or indirectly
applicable to the operation and maintenance of the supplying Party's
participation in such unit.
2. The supplying Party will prepare, revise from time to time as
appropriate and furnish to the Purchaser(s) an annual estimate of the
amount to be billed by months (a) for the cost of energy during the
term of the purchase from a unit, and (b) any other costs which shall
accrue during this period. The supplying Party will furnish any
reasonable request for estimates for longer periods if required by
the Purchaser(s).
65
EL-5 (Page 3 of 13)
3. The supplying Party will maintain the records used in the deter-
mination of the Purchaser(s) bill in order that the Purchaser(s) and
their independent auditors shall have access at all reasonable times
to such records and the supplying Party will furnish copies of such
records as requested. The supplying Party shall preserve and
maintain the originals of such records for at least such periods of
time as the Purchaser(s) may request, having in mind the requirements
of regulatory authorities having jurisdiction and the policies and
practices of the parties with respect to the retention of records.
4. The cost of preparing, preserving and making copies of such budgets,
records and accounts shall be borne by the companies in proportion to
their respective capacity entitlements except that any costs incurred
at the special request of the Purchaser(s) shall be borne by them.
5. The supplying Party shall have special audits conducted with respect
to the matters provided for in this Appendix, either internally or by
independent auditors, according to such programs and procedures as
agreed to be necessary to conform to the auditing requirements of
each company, and shall furnish copies of the reports of such audits
to the Purchaser(s). The cost of making such audits, including any
participation by the auditors of the Purchaser(s) agreed to be
desirable and necessary, shall be shared by the companies in relation
to the current capacity entitlement ratio. The Purchaser(s) may, at
their own expense, make such further audits, using their internal or
independent auditors or both, as it may be deemed desirable.
6. If requested by the Purchaser(s), the supplying Party will make such
examinations, analyses or studies as needed to support the reason-
ableness of the specific costs so allocated, or provide a basis for
modification to achieve such reasonableness with respect to either
the specific or the indirect cost allocations. Shareable costs which
are incurred by the Purchaser(s) shall be accumulated and billed on a
direct charge basis from specific records or reasonable estimates
with applicable additives as agreed upon by the companies.
7. Except as otherwise provided herein, the accounting methods and
practices normally in use at the time by each of the companies in
determining and assigning operating and maintenance costs, generally,
are to be used by such company for the purposes of this Appendix
unless otherwise agreed, provided such methods and practices are
consistent with sound accounting practices.
8. The supplying Party will bill the Purchaser(s) for its share of
property, franchise, business or other taxes applicable to its share
of the unit, specifically identifying these items on the invoice when
such taxes are payable by the supplying Party. To the extent that
such taxes are charged to the operating expenses of the Unit because
it is impractical or inequitable to segregate them, they will be
billed as part of the normal operating expense of the Unit.
66
EL-5 (Page 4 of 13)
9. As soon as possible after the close of each calendar month, prefer-
ably on or before the 8th working day of the following month, the
supplying Party shall advise the Purchaser(s) of its proportionate
share of estimated operating expenses, fixed charges, displacement
training costs and working capital for the preceding month. Any
costs payable will be paid pursuant to Section 12.02 of the CAPCO
Basic Operating Agreement, as amended.
C. Working Capital
It is recognized that the operating company undertakes certain obligations
to provide expenditures in advance of compensation by the purchasers of
capacity and energy. These purchases include, but may not be limited to,
payroll, fuel and material and supplies purchases, and coal and material
and supplies inventories. A reasonable allowance for this investment in
working capital funds shall be considered a shareable cost to be compen-
sated for as set out in detail in Exhibit C.
D. Displacement Training Costs
The CAPCO companies have agreed that the costs which an operating company
will incur in training personnel at existing stations in order to be able
to transfer experienced personnel to a new CAPCO generating unit should be
shared by the joint owners.
Purchasers of capacity and energy shall also share in these costs.
1. For each new CAPCO unit, the cost basis of $1/kW of the installed
capacity is determined to be a reasonable estimate of the present-day
cost which a company will incur within its existing plants as a
result of assigning experienced company personnel to a new CAPCO
generating unit. Installed capacity for this purpose is defined as
the Net Demonstrated Capability of the CAPCO generating unit.
2. It is recognized that these costs will increase as labor costs
increase. Therefore, this cost determination factor of $1/kW shall
be subject to escalation for units planned to be in-service after
Davis-Besse No. 1 based on an index of the composite labor costs of
CAPCO companies as agreed to by the CAPCO Accounting and Finance
Committee using 1972 as the base year equaling 100.0. The index to
be applied shall be that calculated for the period two years prior to
the actual in-service date for fossil-fired generating units and for
the period three years prior to the actual in-service date for
nuclear units.
3. The Purchasers of capacity and energy shall share in these costs for
the periods they are involved. An amount of 1/420 of the cost basis
for each kW of the purchasing company's capacity entitlement shall be
included in the monthly billing.
4. The cost basis provided for herein shall be shown in Exhibit D.
67
EL-5 (Page 5 of 13)
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Eastlake Unit No. 5
EXHIBIT A
Section I - Introduction
This Exhibit pertains to all agreements related to the Sales of Capacity and
Energy from the Owners of Eastlake Unit No. 5 to Purchasers. In the event any
Purchaser does not schedule part or any of its generation entitlement share as
stated in the applicable agreement, the balance of its entitlement shall
remain as capacity available to the Purchaser, provided that, if the Unit is
operated at minimum load required for safe operation of the Unit, the
Purchaser shall be obligated to schedule an amount of energy equal to that
Unit's minimum load for the hour, multiplied by a fraction of which the
numerator is the Purchaser's entitlement under the applicable agreement and
the denominator is the applicable Unit's Net Demonstrated Capability. The
amount of energy determined above, subject to adjustment for proportionate use
of all plant auxiliary power assignable to the operation of the Unit, shall
constitute a scheduled (billing) MWH value (net) as of each Unit's generator
transformer high voltage terminals. Each Participant shall schedule for
delivery from the Unit, and each Purchaser shall schedule for receipt into its
system, an amount of energy equal to such billing value less the increase, or
plus the decrease, as the case may be, in electrical losses incurred on its
system resulting from the transmission of such energy as determined by the
Planning Committee under terms of the CAPCO Transmission Facilities Agreement.
Section II - Accounting Concepts
The basis for allocating the operation and maintenance costs of Eastlake Unit
No. 5 between the joint Owners is set forth in Exhibit A of the Operating
Agreement for this unit. This Exhibit prescribes the method of determining
the portion of that cost of an Owner which will be billed to a Purchaser.
The costs to be billed to a Purchaser will be segregated as to those that are
directly identified with a Purchaser and to those that are allocated either on
an investment responsibility or a fuel consumed basis. The codes for these
segregations are defined at the end of Section III.
In addition to the direct costs for operating and maintaining the Unit, an
Owner shall bill a Purchaser for an appropriate portion of indirect overheads
and taxes other than income taxes as defined in Section V.
Section III - Allocation of Costs
The operation and maintenance costs identified by FERC account number are
assigned to a Purchaser either directly or on the basis of appropriate
allocation codes as set forth in the following table.
68
EL-5 (Page 6 of 13)
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Eastlake Unit No. 5
Direct Owner's Costs to be
Basis Allocated to the Purchaser
Account to Allocation Codes
Number Purchaser O(IR) SY(IR)
OPERATION ACCOUNTS
500 Supervision and Engineering* X
501 Fuel: Cost of Fuel Consumed X
501 Fuel* X
501 Fuel: Other Costs X
502 Steam Expenses* X
505 Electric Expenses X
506 Misc. Steam Power Expenses* X
MAINTENANCE ACCOUNTS
510 Supervision and Engineering* X
511 Structures* X
512 Boiler Plant X
512 Boiler Plant: Feedwater and X
Accessory Steam Plant
Equipment*
513 Electric Plant* X
514 Misc. Steam Plant X
OTHER ACCOUNTS
556 System Control and Load X
Dispatching (Power Supply)
557 Other Expenses (Power Supply) X
562 Transmission Station Expenses X
(Step-Up Transformer and
Connection to Switch Yard
Only)
570 Maintenance of Station Equipment X
(Step-Up Transformer and
Connection to Switch Yard
Only)
*Charges made to primary accounts (500, 501, 502, etc.) will include distribu-
tions from clearing accounts for such costs as non-productive time and plant
stores handling costs.
Direct charges will be made to a Purchaser for fuel consumed as determined in
accordance with Section IV.
69
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Eastlake Unit No. 5
Code Basis
O(IR) Investment Responsibility Ratio
The portion of an Owner's operation and maintenance costs for the
Unit to be billed to a Purchaser for the current month shall be a
fraction of which the numerator is a Purchaser's entitlement from
the Unit as specified in the applicable agreement and the denomi-
nator is an Owner's interest in that Unit, both figures rounded to
the nearest whole megawatt. An Owner's interest in the Unit shall
be the product of the prevailing Net Demonstrated Capability (NDC)
of the Unit multiplied by that Owner's net generation entitlement
share in the Unit.
If the capacity of the Unit is reduced by operating problems, a
Purchaser will be entitled to his O(IR) ratio multiplied by the
Owner's entitlement of the output of the Unit on an hour-to-hour
basis.
SY(IR) Coal Allocation Ratio
The portion of an Owner's cost for the Unit to be billed to a
Purchaser for the current month shall be a fraction of which the
numerator is the total tons of coal allocated to the Purchaser for
the preceding 12-month period, and the denominator is the tons of
coal charged to the Owner during that same preceding 12-month
period. Prior to the time that this data is available on a
12-month basis, available data will be used to determine the
allocation ratio.
Section IV - Fuel
In determining fuel costs, a Purchaser shall be treated in the same manner as
an Owner.
The fuel cost shall be allocated in proportion to the Btu's consumed to
produce the kilowatt-hours taken by each of those sharing in the output of the
unit, taking into account the Btu's consumed during start-ups of the unit.
Btu used during a start-up (including Btu which may be supplied by transfers
of steam from steam sources other than that unit's own steam source) and Btu
computed to have been used during periods of synchronized on-line operation of
the unit to maintain zero load on the unit (the "Y" intercept, or no load
input, of the standard Input/Output equation for the unit) shall be allocated
among those sharing in the output of the unit in proportion to their
investment responsibilities in the unit during the month for which the
allocation is being made. Btu consumed during periods of synchronized on-line
operation in excess of those used to maintain zero load on the unit (see
preceding statement) shall be allocated each hour in proportion to the net
kilowatt-hours determined to have been taken from the unit by each of those
sharing in the output of the unit.
70
EL-5 (Page 8 of 13)
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Eastlake Unit No. 5
Section V - Other Expenses
For billing costs to the Purchaser, labor and material additive costs at
current rates prevailing in the industry as adjusted from time to time shall
be added to the labor and material components of direct operation and
maintenance costs of Eastlake Unit No. 5 to which such rates are applicable
and shall be shared by Purchasers on the same bases on which the primary labor
and material costs are shared.
In addition, an allocation will be made of Account 556, System Control and
Load Dispatching costs related to production, and Account 557, Other
Production Expenses. These costs would be allocated to Eastlake Unit No. 5 on
a direct basis where a direct relationship exists, or by using a net
generating capability ratio (O(IR)) where a direct relationship does not
exist. Account 556 will include only those load dispatching costs incurred by
CEI that are attributable to Eastlake Unit No. 5. Included in Account 557,
Other Production Expenses, are such items as insurance premiums and recoveries
and other production expenses not directly assignable to the other production
accounts. The invoice will identify amounts billed that were included in
Account 557.
For billing costs to Purchasers, labor fringe benefit additive costs shall be
allocated to Eastlake Unit No. 5 on the basis of a rate representative of
labor additive rates experienced by public utilities in the United States, as
calculated from information contained in the U.S. Chamber of Commerce annual
Employee Benefit Survey or in another mutually agreed upon source. The rate,
expressed as a percent of total payroll cost, shall include the employer's
share of employee benefit costs for legally required payments, retirement and
savings plan payments, life insurance and death benefit payments, medical and
medically related payments, and other miscellaneous benefit payments; but
excluding benefits paid in the form of direct compensation to employees for
time not worked such as paid rest periods, lunch or travel periods, holidays,
vacations, sick time, parental leave and other similar payments.
The rate produced in this manner is 31.3% for the billing year 1993 based on
U.S. Chamber of Commerce survey data from benefit year 1991, and the rate for
subsequent years will be computed annually based on the then most current U.S.
Chamber of Commerce Survey data or other mutually agreed upon data available,
and will become effective January 1 of each such subsequent year.
The amount of labor additive costs to be allocated to each Purchaser during a
given period shall be the product of the above rate multiplied by the direct
labor expense allocated to the Purchaser for that period.
71
EL-5 (Page 9 of 13)
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Eastlake Unit No. 5
For billing costs to Purchasers, administrative and general (A&G) expense
shall be allocated to Eastlake Unit No. 5 on the basis of a rate
representative of A&G rates in the utility industry as calculated from
information contained in the Utility Data Institute (UDI) compilation of
utilities' FERC Form 1 data or in another mutually agreed upon source. The
rate shall be equal to the ratio of:
A. the sum of the base year of all amounts for all data base companies in
FERC Accounts 920, 921 and 922, divided by
B. the sum for the base year for the same companies of all amounts in FERC
Accounts 500 through 916, minus the amounts representing fuel and purchase
power expenses in FERC Accounts 501, 518, 547, 555 and 557.
The rate produced by this calculation is 12.70% for the billing year 1993
based on UDI data from 1991, and the rate for subsequent years will be
computed annually based on the then most current UDI or other mutually agreed
upon data available and will become effective January 1 of each such subse-
quent year.
The amount of Administrative and General Expenses to be allocated to each
Purchaser during a given period shall be the product of the above ratio
multiplied by the total operation and maintenance expenses and labor additives
excluding Account 501 allocated to the Purchaser for that period.
In addition, a Purchaser shall pay to the Owner, at times payable by the
Owner, amounts determined by multiplying (a) the property taxes and any other
taxes except Federal Income Tax, payable by the Owner with respect to the Unit
for the periods a Purchaser was involved by, (b) and O(IR) ratio for that
period.
72
EL-5 (Page 10 of 13)
EXHIBIT B
FIXED COSTS OF INVESTED CAPITAL
The monthly fixed charge for a vintage addition shall be calculated as the
algebraic sum of the following components:
A. Amortization(1) -- The product of (XX) multiplied by the ratio in
Note (5).
B. Finance Charge(2) -- The product of (AA) multiplied by the Seller's net
unamortized investment base as of the beginning of the month being billed
times the ratio in Note (5).
C. Gross Income Tax(3)
The product of (BB) multiplied by the net unamortized investment base as
of the beginning of the month being billed.
D. Income Tax Adjustment(4)
The product of (.34/1-34)) times the difference between the amortization
(Item A) less the tax depreciation. If the incremental federal tax rate
is different from 34% in any month of such period, the factor used as the
multiplier shall be adjusted to reflect such difference from 34%.
NOTE: This adjustment may be a negative or positive value during the
period of the contract.
NOTES:
(1) (XX) equals the sum of the Seller's investment base less land divided by
420 months.
The Seller's adjusted investment base equals his total investment for
Eastlake Unit No. 5 and Common Facilities as of the beginning of the
month for which service is being billed.
(2) The Seller's net unamortized adjusted investment base equals the adjusted
investment base, less the accumulated amortization previously reflected
in rates, less investment tax credit attributed to the adjusted
investment base, less the net tax deduction associated with capitalized
overheads attributable to the adjusted investment base.
(AA) is the monthly finance charge rate, which equals 1/12 of the
Seller's weighted cost of capital as defined in the CAPCO Accounting and
Procedures Manual under Procedures for Discharging Investment
Responsibility.
73
EL-5 (Page 11 of 13)
EXHIBIT B
FIXED COSTS OF INVESTED CAPITAL
NOTES: (Cont'd)
(3) (BB) is the monthly gross income tax charge rates applicable to 1987 and
post-1987 billing periods. It is the product of 1/12 of the sum of the
weighted costs of common equity, preferred equity and unamortized gain on
the annual finance charge multiplied by the federal income tax rate
divided by the complement of the income tax rate. The tax rate may be
augmented to include state income taxes as defined in the CAPCO
Accounting and Procedures Manual under Procedures for Discharging Invest-
ment Responsibility, i.e.,
1/12 x (Seller's Equity Component of Capital) x (Tax Rate/(1-Tax Rate))
(4) The income tax adjustment results from the difference between book
amortization and tax depreciation, and from the agreement between the
parties of the extent to which such difference should be recognized in
the price paid.
(5) The ratio shall be the Ratio of Total Megawatt Capacity Purchased (or
Shared) to the Total Megawatts of Seller's Plant Capacity.
74
EL-5 (Page 12 of 13)
EXHIBIT C
REIMBURSEMENT OF WORKING CAPITAL COSTS
I. Materials and Supplies Inventory - Working capital cost applicable to a
purchaser.
Reimbursement by Monthly Carrying Charge in Lieu of Deposit
The charge for a given month per megawatt of capacity purchased (or
shared) shall be based on the supplying Party's total dollar balance
in M&S inventory at the end of the month in which service was
rendered, and shall be calculated as follows:
(a) Total Dollars in supplying Party's M&S Inventory at the Entire
Plant
(b) The Ratio of Total Megawatt Capacity Purchased (or Shared) to
the Total Megawatts of supplying Party's Plant Capacity.
(c) One-Twelfth* of the supplying Party's Current Annual Capital
Cost Rate, augmented to Include supplying Party's Income Tax
Liability on the Equity Component.
*Fraction used to calculate working capital for purposes of this Exhibit.
II. Monthly Operation & Maintenance Expenses - Working capital cost appli-
cable to a purchaser or to an Owner.
The monthly charge shall be calculated each month for the Unit as the
product of (a) and (b) for capacity owned and as the product of (a), (b)
and (c) for capacity purchased.
(a) The current month's direct operating expenses (Accounts 500-554,
556, 557, 562 and 570) for each Owner for the Unit, including
overheads, less fuel and lease payments, and any other inappropriate
items.
(b) One-Twelfth* of the Operating Company's Current Annual Capital Cost
Rate plus the Operating Company's income tax liability on the equity
component.
(c) The Purchaser's entitlement share of megawatt capacity in the Unit.
*Fraction used to calculate working capital for purposes of this Exhibit.
75
EL-5 (Page 13 of 13)
EXHIBIT D
DISPLACEMENT TRAINING COSTS
Installed Capacity at Eastlake Unit No. 5 650,000 kW
Generation Entitlement Share
Cleveland Electric Illuminating Company 447,000 kW
Duquesne Light Company 203,000 kW
650,000 kW
The participants' respective shares of the displacement training costs, based
on $1.00/kW, are:
Cleveland Electric Illuminating Company $447,000
Duquesne Light Company $203,000
Therefore, under the terms of this Agreement, each purchaser will share in
these costs, based on its entitlement at the rate of 1/420 of the cost basis,
for each billing month beginning with the effective purchase date.
76
APPENDIX 3 TO SCHEDULE E, which was filed as part of Exhibit
10.24, 1980 Form 10-K, File No. 1-956, filed by Duquesne,
remains in full force and effect, except for MF-1 Pages 17-21,
18-21, 19-21 and 20-21, revised copies of which are filed
herewith.
77
MF-1 (Page 17 of 21)
Section V - Other Expenses
For billing costs to the Purchaser, labor and material additive costs at
current rates prevailing in the industry as adjusted from time to time shall
be added to the labor and material components of direct operation and
maintenance costs of Bruce Mansfield Unit No. 1 to which such rates are
applicable and shall be shared by Purchasers on the same bases on which the
primary labor and material costs are shared.
In addition, an allocation will be made of Account 556, System Control and
Load Dispatching costs related to production, and Account 557, Other
Production Expenses. These costs would be allocated to Bruce Mansfield Unit
No. 1 on a direct basis where a direct relationship exists, or by using a net
generating capacity ratio (O(IR)) where a direct relationship does not exist.
Account 556 will include only those load dispatching costs incurred by PP
that a reattributable to Bruce Mansfield Unit No. 1. Included in Account
557, Other Production Expenses, are such items as insurance premiums and
recoveries and other production expenses not directly assignable to the other
production accounts. The invoice will identify amounts billed that were
included in Account 557.
For billing costs to Purchasers, labor fringe benefit additive costs shall be
allocated to Bruce Mansfield Unit No. 1 on the basis of a rate representative
of labor additive rates experienced by public utilities in the United States,
as calculated from information contained in the U.S. Chamber of Commerce
annual Employee Benefit Survey or in another mutually agreed upon source.
The rate, expressed as a percent of total payroll cost, shall include the
employer's share of employee benefit costs for legally required payments,
retirement and savings plan payments, life insurance and death benefit
payments, medical and medically related payments, and other miscellaneous
benefit payments; but excluding benefits paid in the form of direct
compensation to employees for time not worked such as paid rest periods,
lunch or travel periods, holidays, vacations, sick time, parental leave and
other similar payments.
The rate produced in this manner is 31.3% for the billing year 1993 based on
U.S. Chamber of Commerce survey data from benefit year 1991, and the rate for
subsequent years will be computed annually based on the then most current
U.S. Chamber of Commerce Survey data or other mutually agreed upon data
available, and will become effective January 1 of each such subsequent year.
The amount of labor additive costs to be allocated to each Purchaser during a
given period shall be the product of the above rate multiplied by the direct
labor expense allocated to the Purchaser for that period.
For billing costs to Purchasers, administrative and general (A&G) expense
shall be allocated to Bruce Mansfield Unit No. 1 on the basis of a rate
representative of A&G rates in the utility industry as calculated from
information contained in the Utility Data Institute (UDI) compilation of
utilities' FERC Form 1 data or in another mutually agreed upon source. The
rate shall be equal to the ratio of:
78
MF-1 (Page 18 of 21)
A. the sum of the base year of all amounts for all data base companies in
FERC Accounts 920, 921 and 922, divided by
B. the sum for the base year for the same companies of all amounts in FERC
Accounts 500 through 916, minus the amounts representing fuel and purchase
power expenses in FERC Accounts 501, 518, 547, 555 and 557.
The rate produced by this calculation is 12.70% for the billing year 1993
based on UDI data from 1991, and the rate for subsequent years will be
computed annually based on the then most current UDI or other mutually agreed
upon data available and will become effective January 1 to each such
subsequent year.
The amount of Administrative and General expenses to be allocated to each
Purchaser during a given period shall be the product of the above ratio
multiplied by the total operation and maintenance expenses and labor additive
excluding Account 501 allocated to the Purchaser for that period.
In addition, a Purchaser shall pay to the Participant, at times payable by
the Participant, amounts determined by multiplying (a) the property taxes and
any other taxes except Federal Income Tax, payable by the Participant with
respect to the Unit for the periods a Purchaser was involved by, (b) and
O(IR) ratio for that period.
79
MF-1 (Page 19-21)
Sales of Capacity and Energy from Base Load Units
to Purchasers: B. Mansfield Unit No. 1
Exhibit C - Reimbursement of Working Capital Costs
I. Fuel (Coal and Oil) and Material and Supplies Inventory - Working capital
cost applicable to a purchaser.
Reimbursement by Monthly Carrying Charge in Lieu of Deposit
The charge for a given month per megawatt of capacity purchased (or
shared) shall be based on the Supplying Party's total dollar balance
in Fuel (Coal and Oil) and Material and Supplies Inventory at the end
of the month in which service was rendered, and shall be calculated
as follows:
B. Mansfield Unit No. 1 - The Product Of:
(a) Total Dollars in Supplying Party's Fuel (Coal and Oil) and
Material and Supplies Inventory at the Entire Plant
(b) The Ratio of Total Megawatt Capacity Purchased (or Shared)
to the Total Megawatts of Supplying Party's Plant Capacity.
(c) One-Twelfth* of the Supplying Party's Current Annual Capital
Cost Rate, augmented to Include Supplying Party's Income Tax
Liability on the Equity Component.
II. Monthly Operation & Maintenance Expenses - Working capital cost appli-
cable to a purchaser or to a participant.
Reimbursement by Monthly Carrying Charge in Lieu of Deposit
The monthly charge shall be calculated each month for the Unit as the
product of (a) and (b) for capacity owned and as the product of (a),
(b) and (c) for capacity purchased.
(a) The current month's direct operating expenses (Accounts
500-554, 556, 57, 562 and 570) for each Participant for
the Unit, including overheads, less fuel and lease pay-
ments, and any other inappropriate items.
(b) One-Twelfth* of the Operating Company's Current Annual
Capital Cost Rate plus the Operating Company's income
tax liability on the equity component.
(c) The Purchaser's entitlement share of megawatt capacity
in the Unit.
*Fraction used to calculate working capital for purposes of this Exhibit
80
MF-1 (Page 20-21)
(BLANK)
81
APPENDIX 4 TO SCHEDULE E, which was filed as part of Exhibit
10.24, 1980 Form 10-K, File No. 1-956, filed by Duquesne,
remains in full force and effect, except for BV-1 Pages 20-25,
21-25, 22-25, 23-25 and 24-25, revised copies of which are filed
herewith.
82
BV-1 (Page 20-25)
C. Monthly payments not related to burnup made by Owners to the Lessor
pertaining to the period after the beginning of commercial operation
of the leased nuclear fuel shall be calculated as follows:
MPLc = Rc (Cc)
Where:
MPLc = The current payments not related to burnup made by
the Owners to the Lessor.
Rc = The current lease rate as defined in the lease
agreement expressed as the decimal equivalent of
percent per month.
Cc = The lessor's net investment (acquisition cost as
defined in the lease agreement less burnup expenses
prior to the current accounting month) at the
beginning of the current accounting month.
Section V - Other Expenses
For billing costs to the Purchaser, labor and material additive costs at
current rates prevailing in the industry as adjusted from time to time shall
be added to the labor and material components of direct operation and
maintenance costs of Beaver Valley Unit No. 1 to which such rates are
applicable and shall be shared by Purchasers on the same bases on which the
primary labor and material costs are shared.
In addition, an allocation will be made of Account 556, System Control and
Load Dispatching costs related to production, and Account 557, Other
Production Expenses. These costs would be allocated to Beaver Valley Unit
No. 1 on a direct basis where a direct relationship exists, or by using a net
generating capacity ratio (O(IR)) where a direct relationship does not exist.
Account 556 will include only those load dispatching costs incurred by DL
that are attributable to Beaver Valley Unit No. 1. Included in Account 557,
Other Production Expenses, are such items as insurance premiums and
recoveries and other production expenses not directly assignable to the other
production accounts. The invoice will identify amounts billed that were
included in Account 557.
For billing costs to Purchasers, labor fringe benefit additive costs shall be
allocated to Beaver Valley Unit No. 1 on the basis of a rate representative
of labor additive rates experienced by public utilities in the United States,
as calculated from information contained in the U.S. Chamber of Commerce
annual Employee Benefit Survey or in another mutually agreed upon source.
The rate, expressed as a percent of total payroll cost, shall include the
employer's share of employee benefit costs for legally required payments,
retirement and savings plan payments, life insurance and death benefit
payments, medical and medically related payments, and other miscellaneous
benefit payments; but excluding
83
BV-1 (Page 21 of 25)
benefits paid in the form of direct compensation to employees for time not
worked such as paid rest periods, lunch or travel periods, holidays,
vacations, sick time, parental leave and other similar payments.
The rate produced in this manner is 31.3% for the billing year 1993 based on
U.S. Chamber of Commerce survey data from benefit year 1991, and the rate for
subsequent years will be computed annually based on the then most current
U.S. Chamber of Commerce Survey data or other mutually agreed upon data
available, and will become effective January 1 of each such subsequent year.
The amount of labor additive costs to be allocated to each Purchaser during a
given period shall be the product of the above rate multiplied by the direct
labor expense allocated to the Purchaser for that period.
For billing costs to Purchasers, administrative and general (A&G) expense
shall be allocated to Beaver Valley Unit No. 1 on the basis of a rate
representative of A&G rates in the utility industry as calculated from
information contained in the Utility Data Institute (UDI) compilation of
utilities' FERC Form 1 data or in another mutually agreed upon source. The
rate shall be equal to the ratio of:
A. the sum of the base year of all amounts for all data base companies
in FERC Accounts 920, 921 and 922, divided by
B. the sum for the base year for the same companies of all amounts in
FERC Accounts 500 through 916, minus the amounts representing fuel
and purchase power expenses in FERC Accounts 501, 518, 547, 555 and
557.
The rate produced by this calculation is 12.70% for the billing year 1993
based on UDI data from 1991, and the rate for subsequent years will be
computed annually based on the then most current UDI or other mutually agreed
upon data available and will become effective January 1 of each such
subsequent year.
The amount of Administrative and General Expenses to be allocated to each
Purchaser during a given period shall be the product of the above ratio
multiplied by the total operation and maintenance expenses and labor additive
excluding Account 501 allocated to the Purchaser for that period.
In addition, a Purchaser shall pay to the Participant, at times payable by
the Participant, amounts determined by multiplying (a) the property taxes and
any other taxes except Federal Income Tax, payable by the Participant with
respect to the Unit for the periods a Purchaser was involved by, (b) and
O(IR) ratio for that period.
84
BV-1 (Page 22-25)
(BLANK)
85
BV-1 (Page 23-25)
EXHIBIT C
REIMBURSEMENT OF WORKING CAPITAL COSTS
I. Accumulated Deferred Fuel Expense - Working Capital Costs Applicable to
a Purchaser of Capacity and Energy
Reimbursement by Monthly Carrying Charge in Lieu of Deposit
The charge for a given month per megawatt of capacity purchased shall be
based on the Supplying Party's unamortized accumulated deferred expenses
(not related to burnup) pertaining to the period prior to the beginning
of commercial operation of the leased nuclear fuel per megawatt of
capacity, to include the unamortized deferred depletion balance, if any,
at the end of the month in which service was rendered and shall be
calculated as follows:
The Product of (a) (b) (c)
(a) The Unamortized Accumulated Deferred Expenses (Not Related to
Burnup) pertaining to the period prior to the beginning of
Commercial Operation of the leased Nuclear Fuel to include
the unamortized deferred depletion balance, if any.
(b) The Ratio of Total Megawatt Capacity Purchased to the Supplying
Party's Total Megawatt Capacity in Service.
(c) One-Twelfth* of the Supplying Party's Current Annual Capital
Cost Rate, plus the Supplying Party's income tax liability on
the Equity Component.
II. Materials and Supplies Inventory - Working capital cost applicable to a
purchaser.
Reimbursement by Monthly Carrying Charge in Lieu of Deposit
The charge for a given month per megawatt of capacity purchased
(or shared) shall be based on the Supplying Party's total dollar
balance in M&S inventory at the end of the month in which service
was rendered, and shall be calculated as follows:
Beaver Valley Unit No. 1 - The Product Of:
(a) Total Dollars in Supplying Party's M&S Inventory
at the Entire Plant
(b) The Ration of Total Megawatt Capacity Purchased
(or Shared) to the Total Megawatts of Supplying
Party's Plant Capacity.
*FRACTION USED TO CALCULATE WORKING CAPITAL FOR PURPOSES OF THIS EXHIBIT.
86
BV-1 (Page 24-25)
(c) One-twelfth* of the Supplying Party's Current Annual
Capital Cost Rate, augmented to include Supplying
Party's Income Tax Liability on the Equity Component.
III. Monthly Operation & Maintenance Expenses - Working capital cost
applicable to a purchaser or to a participant.
The monthly charge shall be calculated each month for the Unit as the
product of (a) and (b) for capacity owned and as the product of (a),
(b) and (c) for capacity purchased.
(a) The current monthly's direct operating expenses (Accounts 500-
554, 556, 557, 562 and 570) for each Participant for the Unit,
including overheads, less fuel and lease payments, and any
other inappropriate items.
(b) One-Twelfth& of the Operating Company's Current Annual Capital
Cost Rate plus the Operating Company's income tax liability on
the equity component.
(c) The Purchaser's entitlement share of megawatt capacity in the
Unit.
87
APPENDIX 5 TO SCHEDULE E, which was filed as part of Exhibit
10.24, 1980 Form 10-K, File No. 1-956, filed by Duquesne,
remains in full force and effect, except for MF-2 Pages 17-21,
18-21, 19-21 and 20-21, revised copies of which are filed
herewith.
88
MF-2 (Page 17 of 21)
Section V - Other Expenses
For billing costs to the Purchaser, labor and material additive costs at
current rates prevailing in the industry as adjusted from time to time shall
be added to the labor and material components of direct operation and
maintenance costs of Bruce Mansfield Unit No. 2 to which such rates are
applicable and shall be shared by Purchasers on the same bases on which the
primary labor and material costs are shared.
In addition, an allocation will be made of Account 556, System Control and
Load Dispatching costs related to production, and Account 557, Other
Production Expenses. These costs would be allocated to Bruce Mansfield Unit
No. 2 on a direct basis where a direct relationship exists, or by using a net
generating capacity ratio (O(IR)) where a direct relationship does not exist.
Account 556 will include only those load dispatching costs incurred by PP
that a reattributable to Bruce Mansfield Unit No. 2. Included in Account
557, Other Production Expenses, are such items as insurance premiums and
recoveries and other production expenses not directly assignable to the other
production accounts. The invoice will identify amounts billed that were
included in Account 557.
For billing costs to Purchasers, labor fringe benefit additive costs shall be
allocated to Bruce Mansfield Unit No. 2 on the basis of a rate representative
of labor additive rates experienced by public utilities in the United States,
as calculated from information contained in the U.S. Chamber of Commerce
annual Employee Benefit Survey or in another mutually agreed upon source.
The rate, expressed as a percent of total payroll cost, shall include the
employer's share of employee benefit costs for legally required payments,
retirement and savings plan payments, life insurance and death benefit
payments, medical and medically related payments, and other miscellaneous
benefit payments; but excluding benefits paid in the form of direct
compensation to employees for time not worked such as paid rest periods,
lunch or travel periods, holidays, vacations, sick time, parental leave and
other similar payments.
The rate produced in this manner is 31.3% for the billing year 1993 based on
U.S. Chamber of Commerce survey data from benefit year 1991, and the rate for
subsequent years will be computed annually based on the then most current
U.S. Chamber of Commerce Survey data or other mutually agreed upon data
available, and will become effective January 1 of each such subsequent year.
The amount of labor additive costs to be allocated to each Purchaser during a
given period shall be the product of the above rate multiplied by the direct
labor expense allocated to the Purchaser for that period.
For billing costs to Purchasers, administrative and general (A&G) expense
shall be allocated to Bruce Mansfield Unit No. 2 on the basis of a rate
representative of A&G rates in the utility industry as calculated from
information contained in the Utility Data Institute (UDI) compilation of
utilities' FERC Form 1 data or in another mutually agreed upon source. The
rate shall be equal to the ratio of:
89
MF-2 (Page 18 of 21)
A. the sum of the base year of all amounts for all data base companies in
FERC Accounts 920, 921 and 922, divided by
B. the sum for the base year for the same companies of all amounts in
FERC Accounts 500 through 916, minus the amounts representing fuel
and purchase power expenses in FERC Account 501, 518, 547, 555 and 557.
The rate produced by this calculation is 12.70% for the billing year 1993
based on UDI data from 1991, and the rate for subsequent years will be
computed annually based on the then most current UDI or other mutually agreed
upon data available and will become effective January 1 of each such
subsequent year.
The amount of Administrative and General expenses to be allocated to each
Purchaser during a given period shall be the product of the above ratio
multiplied by the total operation and maintenance expenses and labor
additives excluding Account 501 allocated to the Purchaser for that period.
In addition, a Purchaser shall pay to the Participant, at times payable by
the Participant, amounts determined by multiplying (a) the property taxes and
any other taxes except Federal Income Tax, payable by the Participant with
respect to the Unit for the periods a Purchaser was involved by, (b) and
O(IR) ratio for that period.
90
MF-2 (Page 19-21)
Sales of Capacity and Energy from Base Load Units
to Purchasers: B. Mansfield Unit No. 2
Exhibit C - Reimbursement of Working Capital Costs
I. Fuel (Coal and Oil) Inventory - Working capital cost applicable to
a purchaser.
Reimbursement by Monthly Carrying Charge in Lieu of Deposit
The charge for a given month per megawatt of capacity purchased (or
shared) shall be based on the Supplying Party's total dollar balance
in Fuel (Coal and Oil) and Material and Supplies Inventory at the end
of the month in which service was rendered, and shall be calculated
as follows:
B. Mansfield Unit No. 2 - The Product Of:
(a) Total Dollars in Supplying Party's Fuel (Coal and Oil)
and Material and Supplies Inventory at the Entire Plant
(b) The Ratio of Total Megawatt Capacity Purchased (or Shared)
to the Total Megawatts of Supplying Party's Plant Capacity.
(c) One-Twelfth* of the Supplying Party's Current Annual Capital
Cost Rate, augmented to Include Supplying Party's Income
Tax Liability on the Equity Component.
II. Monthly Operation & Maintenance Expenses - Working capital cost
applicable to a purchaser or to a participant.
Reimbursement by Monthly Carrying Charge in Lieu of Deposit
The monthly charge shall be calculated each month for the Unit as the
product of (a) and (b) for capacity owned and as the product of (a),
(b) and (c) for capacity purchased.
(a) The current month's direct operating expenses (Accounts
500-554, 556, 557, 562 and 570) for each Participant for the
Unit, including overheads, less fuel and lease payments, and
any other inappropriate items.
(b) One-Twelfth* of the Operating Company's Current Annual Capital
Cost Rate plus the Operating Company's income tax liability
on the equity component.
(c) The Purchaser's entitlement share of megawatt capacity in
the Unit.
*Fraction used to calculate working capital for purposes of this Exhibit
91
MF-2 (Page 20-21)
(BLANK)
92
APPENDIX 6 TO SCHEDULE E has been revised from previous filings
and is filed in full herewith.
93
DB-1 (Page 1 of 17)
APPENDIX 6 TO SCHEDULE E
Charges Applicable to Transactions from Davis-Besse Unit No. 1
Pursuant to Schedule E
This Appendix provides for specific charges applicable to transactions made
from Davis-Besse Unit No. 1 pursuant to Schedule E.
Costs will be shared on a basis equivalent to that of the joint owners with
certain modifications specified herein.
The following are the components of the costs to be included.
A. Fixed Costs of Invested Capital
1. It is expected that sales out of production units will occur pre-
dominantly over a relative short time period in the early part of the
unit's life. However, this Appendix develops a consistent basis
which is applicable throughout the life cycle.
2. Amortization and tax calculations are based on the following:
Amortization Period - 35 Years (420 Months)
Plant
DDB Tax Life 28 Years (336 Months)
Estimated Salvage Rate -10%
Accounting Treatment Flow-Through
3. DDB tax depreciation is assumed, with switch to straight line method
effective the first month in which the straight line remaining life
depreciation exceeds DDB depreciation, with remaining life stretched
out in the straight line calculations to extend to the end of the
book amortization period. The switch occurs at the end of the 221st
month.
4. All fixed charges are on a month-to-month declining basis. The
investment base from which fixed charges are developed shall be the
CAPCO investment basis as defined in the Accounting and Procedure
Manual under Procedures for Discharging Investment Responsibility.
5. The monthly finance charge rate applicable to all additions from the
in-service date through the last month of the calendar year in which
the construction job order is closed out shall be one-twelfth the
specified annual rate.
6. The finance charge rate for ordinary additions in years subsequent to
the calendar year in which the construction job order was closed out
shall be the specified rate.
94
DB-1 (Page 2 of 17)
7. Amortization and other charges and adjustments shall be billed each
month. Each month's additions to plant in-service shall constitute a
vintage investment. However, in order to simplify the billing
process, the monthly vintages of any particular calendar year may be
combined into a composite vintage, either on an ongoing basis or at
the end of the calendar year, providing the same billing results.
Since finance charge rates are recalculated each year, vintages of
different calendar years will not be composited.
8. The tax plant ratio to amortizable plant (CAPCO investment basis)
shall be established from data for the total project as estimated at
the in-service date, as described in Paragraph 5. This ratio will be
used in developing fixed charge rates for the initial placements and
all subsequent additions; except that in the case of major capital
additions, at seller's option and with buyers' concurrence, a
completely new vintage may be developed and the fixed charge factor
recalculated using the new tax plant ratio and other pertinent data
as appropriate.
9. When a production unit, or a major capital addition such as described
in Paragraph 7, is placed in commercial service, the first fixed
charge billing shall begin effective with the in-service date. For
subsequent month-to-month additions, the billing shall begin with the
first full calendar month after the addition is made.
10. Where sales are initiated out of an existing production facility to a
new buyer, a single-vintage CAPCO investment basis may be calculated
with an appropriate adjustment for depreciation incurred to date.
The amortization component of the fixed charge factor will be calcu-
lated on the basis of remaining life of the original amortization
period or by mutual agreement.
11. The specific fixed charge rate for Davis-Besse Unit No. 1 is
developed in Exhibit B.
B. Operating and Maintenance Costs
1. The methods specified in the attached Exhibit A shall be used to
allocate between the supplying Party and the receiving Party(s) or
Purchaser(s) all costs, including overheads directly or indirectly
applicable to the operation and maintenance of the supplying Party's
participation in such unit.
2. The supplying Party will prepare, revise from time to time as
appropriate and furnish to the Purchaser(s) an annual estimate of the
amount to be billed by months (a) for the cost of energy during the
term of the purchase from a unit, and (b) any other costs which shall
accrue during this period. The supplying Party will furnish any
reasonable request for estimates for longer periods if required by
the Purchaser(s).
95
DB-1 (Page 3 of 17)
3. The supplying Party will maintain the records used in the deter-
mination of the Purchaser(s) bill in order that the Purchaser(s) and
their independent auditors shall have access at all reasonable times
to such records and the supplying Party will furnish copies of such
records as requested. The supplying Party shall preserve and
maintain the originals of such records for at least such periods of
time as the Purchaser(s) may request, having in mind the requirements
of regulatory authorities having jurisdiction and the policies and
practices of the parties with respect to the retention of records.
4. The cost of preparing, preserving and making copies of such budgets,
records and accounts shall be borne by the companies in proportion to
their respective capacity entitlements except that any costs incurred
at the special request of the Purchaser(s) shall be borne by them.
5. The supplying Party shall have special audits conducted with respect
to the matters provided for in this Appendix, either internally or by
independent auditors, according to such programs and procedures as
agreed to be necessary to conform to the auditing requirements of
each company, and shall furnish copies of the reports of such audits
to the Purchaser(s). The cost of making such audits, including any
participation by the auditors of the Purchaser(s) agreed to be
desirable and necessary, shall be shared by the companies in relation
to the current capacity entitlement ratio. The Purchaser(s) may, at
their own expense, make such further audits, using their internal or
independent auditors or both, as it may be deemed desirable.
6. If requested by the Purchaser(s), the supplying Party will make such
examinations, analyses or studies as needed to support the reason-
ableness of the specific costs so allocated, or provide a basis for
modification to achieve such reasonableness with respect to either
the specific or the indirect cost allocations. Shareable costs which
are incurred by the Purchaser(s) shall be accumulated and billed on a
direct charge basis from specific records or reasonable estimates
with applicable additives as agreed upon by the companies.
7. Except as otherwise provided herein, the accounting methods and
practices normally in use at the time by each of the companies in
determining and assigning operating and maintenance costs, generally,
are to be used by such company for the purposes of this Appendix
unless otherwise agreed, provided such methods and practices are
consistent with sound accounting practices.
8. The supplying Party will bill the Purchaser(s) for its share of
property, franchise, business or other taxes applicable to its share
of the unit, specifically identifying these items on the invoice when
such taxes are payable by the supplying Party. To the extent that
such taxes are charged to the operating expenses of the Unit because
it is impractical or inequitable to segregate them, they will be
billed as part of the normal operating expense of the Unit.
96
DB-1 (Page 4 of 17)
9. As soon as possible after the close of each calendar month, prefer-
ably on or before the 8th working day of the following month, the
supplying Party shall advise the Purchaser(s) of its proportionate
share of estimated operating expenses, fixed charges, displacement
training costs and working capital for the preceding month. Any
costs payable will be paid pursuant to Section 12.02 of the CAPCO
Basic Operating Agreement, as amended.
C. Working Capital
It is recognized that the operating company undertakes certain obligations
to provide expenditures in advance of compensation by the purchasers of
capacity and energy. These purchases include, but may not be limited to,
payroll, fuel and material and supplies purchases, and material and
supplies inventories. A reasonable allowance for this investment in
working capital funds shall be considered a shareable cost to be compen-
sated for as set out in detail in Exhibit C.
D. Displacement Training Costs
The CAPCO companies have agreed that the costs which an operating company
will incur in training personnel at existing stations in order to be able
to transfer experienced personnel to a new CAPCO generating unit should be
shared by the joint owners.
Purchasers of capacity and energy shall also share in these costs.
1. For each new CAPCO unit, the cost basis of $1/kW of the installed
capacity is determined to be a reasonable estimate of the present-day
cost which a company will incur within its existing plants as a
result of assigning experienced company personnel to a new CAPCO
generating unit. Installed capacity for this purpose is defined as
the Net Demonstrated Capability of the CAPCO generating unit.
2. It is recognized that these costs will increase as labor costs
increase. Therefore, this cost determination factor of $1/kW shall
be subject to escalation for units planned to be in-service after
Davis-Besse No. 1 based on an index of the composite labor costs of
CAPCO companies as agreed to by the CAPCO Accounting and Finance
Committee using 1972 as the base year equaling 100.0. The index to
be applied shall be that calculated for the period two years prior to
the actual in-service date for fossil-fired generating units and for
the period three years prior to the actual in-service date for
nuclear units.
3. The Purchasers of capacity and energy shall share in these costs for
the periods they are involved. An amount of 1/420 of the cost basis
for each kW of the purchasing company's capacity entitlement shall be
included in the monthly billing.
4. The cost basis provided for herein shall be shown in Exhibit D.
97
DB-1 (Page 5 of 17)
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Davis-Besse Station Unit No. 1
EXHIBIT A
Section I - Introduction
This Exhibit pertains to all agreements related to the Sales of Capacity and
Energy from the Owners of Davis-Besse Unit No. 1 to Purchasers. In the event
any Purchaser does not schedule part or any of its generation entitlement
share as stated in the applicable agreement, the balance of its entitlement
shall remain as capacity available to the Purchaser, provided that, if the
Unit is operated at minimum load required for safe operation of the Unit, the
Purchaser shall be obligated to schedule an amount of energy equal to that
Unit's minimum load for the hour, multiplied by a fraction of which the
numerator is the Purchaser's entitlement under the applicable agreement and
the denominator is the applicable Unit's Net Demonstrated Capability. The
amount of energy determined above, subject to adjustment for proportionate use
of all plant auxiliary power assignable to the operation of the Unit, shall
constitute a scheduled (billing) MWH value (net) as of each Unit's generator
transformer high voltage terminals. Each Participant shall schedule for
delivery from the Unit, and each Purchaser shall schedule for receipt into its
system, an amount of energy equal to such billing value less the increase, or
plus the decrease, as the case may be, in electrical losses incurred on its
system resulting from the transmission of such energy as determined by the
Planning Committee under terms of the CAPCO Transmission Facilities Agreement.
Section II - Accounting Concepts
The basis for allocating the operation and maintenance costs of Davis-Besse
Unit No. 1 between the joint Owners is set forth in Exhibit A of the Operating
Agreement for this unit. This Exhibit prescribes the method of determining
the portion of that cost of an Owner which will be billed to a Purchaser.
The costs to be billed to a Purchaser will be segregated as to those that are
directly identified with a Purchaser and to those that are allocated either on
an investment responsibility or a fuel consumed basis. The codes for these
segregations are defined at the end of Section III.
In addition to the direct costs for operating and maintaining the Unit, an
Owner shall bill a Purchaser for an appropriate portion of indirect overheads
and taxes other than income taxes as defined in Section V.
Section III - Allocation of Costs
The operation and maintenance costs identified by FERC account number are
assigned to a Purchaser either directly or on the basis of appropriate
allocation codes as set forth in the following table.
98
DB-1 (Page 6 of 17)
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Davis-Besse Station Unit No. 1
Direct Participants' Costs to be
Basis Allocated to the Purchaser
Account to Allocation Codes
Number Purchaser O(IR) HY(IR)
OPERATION ACCOUNTS
517 Supervision and Engineering X
518 Nuclear Fuel Expense X
519 Coolants and Water* X
519 Coolants and Water* X
520 Steam Expenses* X
520 Steam Expenses* X
523 Electric Expenses X
524 Misc. Nuclear Power Expenses X
525 Rents X
MAINTENANCE ACCOUNTS
528 Supervision and Engineering X
529 Structures X
530 Reactor Plant and Equipment* X
530 Reactor Plant and Equipment* X
531 Electric Plant X
532 Misc. Nuclear Plant X
OTHER ACCOUNTS
562 Operation - Station Expenses X
570 Maintenance of Station Equipment X
*See Exhibit A of the Davis-Besse Station Operating Agreement for breakdown of
these accounts.
Direct charges will be made to a Purchaser for fuel consumed as determined in
accordance with Section IV.
Code Basis
O(IR) The portion of an Owner's operation and maintenance costs for the
Unit to be billed to a Purchaser for the current month shall be a
fraction of which the numerator is a Purchaser's entitlement from
the Unit as specified in the applicable agreement and the denomi-
nator is an Owner's interest in that Unit, both figures rounded to
the nearest whole megawatt. An Owner's interest in the Unit shall
be the product of the prevailing Net Demonstrated Capability (NDC)
of the Unit multiplied by that Owner's net generation entitlement
share in the Unit.
99
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Davis-Besse Station Unit No. 1
Code Basis
If the capacity of the Unit is reduced by operating problems, a
Purchaser will be entitled to his O(IR) ratio multiplied by the
Owner's entitlement of the output of the Unit on an hour-to-hour
basis.
HY(IR) The portion of an Owner's cost for the Unit to be billed to a
Purchaser for the current month shall be a fraction of which the
numerator is the portion of the BTU input to the main unit turbine
used to produce the kilowatthours of energy taken from the Unit by
the Purchaser during the preceding 12-month period and the denomi-
nator is the portion of the BTU input to the main turbine used to
produce the kilowatthours of energy taken from the Unit by the
Owner during that same preceding 12-month period. Prior to the
time that this data is available on a 12-month basis, available
data will be used to determine the allocation ratio.
Section IV - Fuel
In determining fuel costs, a Purchaser shall be treated in the same manner as
an Owner.
The following basic principles shall govern the calculation of depletion
(amortization) of fuel assemblies installed in the reactor for heat production
and the billing of fuel costs to Purchasers.
1. Nuclear fuel assemblies shall be considered to be producing heat only
during periods of zero or positive net generation.
2. During periods of negative net generation, it will be considered that
installed nuclear fuel assemblies are not producing heat and are not thus
consumed. During periods of negative net generation, records of station
service electric energy supplied by the system shall be maintained and the
participants in the Unit shall be invoiced for such electric energy in
proportion to their investment responsibilities in the Unit as the
operating Owner's system average production cost (including net purchased
power costs) during the current calendar month adjusted to exclude the
output and cost during the current calendar month of the Unit to which
such station service energy was supplied.
3. During periods of zero or positive net generation, the components of
consumption of heat from nuclear fuel assemblies shall be considered to
consist of a fixed heat consumption component and a variable heat
consumption component. The components of heat consumption are illustrated
by the current turbine-generator heat consumption curve for the Unit as
agreed to by the Owners. The fixed portion of heat consumption consists
of the heat produced by the reactor required to supply station service
electric energy plus heat losses in the plant.
100
DB-1 (Page 8 of 17)
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Davis-Besse Station Unit No. 1
4. During periods of zero or positive net generation, the fixed and variable
portions of the total Unit heat consumption shall be calculated on an
hour-by-hour basis. The fixed portion of the Unit heat consumption shall
be the product of service hours accumulated during periods of zero or
positive net generation times the fixed unit heat consumption as indicated
on the current turbine-generator heat consumption curve for the Unit as
agreed to by the Owners. The variable portion of the Unit heat
consumption shall be the total net main unit generation in MWe hr/hr
converted to BTU/hr excluding the fixed unit heat consumption utilizing
the relationship between MWe hr/hr versus BTU/hr as represented on the
current turbine-generator heat consumption curve for each Unit as agreed
to by the Owners. The total unit heat consumption shall be the sum of
fixed and variable portions of the unit heat consumption.
5. In calculations for determining the cost of nuclear fuel consumed, Toledo
Edison Company shall take into account the original acquisition cost of
the materials and services required to provide the fuel as originally
installed, and predicted total heat output of the assemblies and the
estimated net value of salvage materials. TE shall calculate such cost of
nuclear fuel consumed using methods and/or computer codes generally
considered acceptable by the CAPCO Companies for this purpose.
6. For owned nuclear fuel, the total monthly nuclear fuel expense for the
Purchaser shall be determined by the formula
FCc = Ec (Ac - Sf)
---------
Ef
where:
FCc = Nuclear Fuel expense during the current accounting month.
Ec = The energy received by the Purchaser during the current accounting
month.
Ef = The energy expected to be produced from the fuel component. Fuel
component can be a fuel assembly, sub-region, region or entire
core.
Ac = The Owner's current net costs.
Sf = Anticipated salvage value of the fuel with related deductions
including, but not limited to, shipping, reprocessing and waste
disposal costs.
When the Owner adjusts its Ac, Sf and Ef factors, these same factors will be
adjusted in a similar manner for the Purchaser.
101
DB-1 (Page 9 of 17)
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Davis-Besse Station Unit No. 1
7. For leased nuclear fuel, the total monthly nuclear fuel expense for the
Purchaser is composed of a) a burnup expense related to energy resource
consumption, b) amortization of accumulated deferred expenses not related
to burnup pertaining to the period prior to the beginning of commercial
operation of the leased nuclear fuel, and c) monthly payments not related
to burnup made by the Owners to the Lessor pertaining to the period after
the beginning of commercial operation of the leased nuclear fuel.
A. The monthly burnup expense shall be calculated as follows:
Bc = Ec (Cc - Sf)
---------
Ef
where:
Bc = Burnup expense for the current accounting month.
Ec = The energy received by the Purchaser during the current
accounting month.
Ef = The energy expected to be produced from the fuel component.
Fuel component can be a fuel assembly, sub-region or entire
core.
Cc = The Lessor's current net costs.
Sf = Anticipated salvage value of the fuel with related deductions
including, but not limited to, shipping, reprocessing and waste
disposal costs.
B. The amortization of accumulated deferred expenses not related to
burnup pertaining to the period prior to the beginning of commercial
operation of the leased nuclear fuel shall be calculated as follows:
PDAc = Ec (Dp)
----
Ef
where:
PDAc = The current month amortization of deferred expenses not
related to burnup pertaining to the period prior to the
beginning of commercial operation of the leased nuclear fuel.
Ec = The energy received by the Purchaser during the current
accounting month.
Ef = The energy expected to be produced from the fuel component.
102
DB-1 (Page 10 of 17)
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Davis-Besse Unit No. 1
Dp = The unamortized portion at the beginning of the current
accounting month of the deferred expense not related to
burnup pertaining to the period prior to the beginning of
commercial operation of the leased nuclear fuel.
C. Monthly payments not related to burnup made by Owners to the Lessor
pertaining to the period after the beginning of commercial operation
of the leased nuclear fuel billable to the Purchaser shall be
calculated as follows:
MPLc = Rc (Cc) (O(IR))
where:
MPLc = The current payments not related to burnup made by the Owner
to the Lessor.
Rc = The current lease rate as defined in the lease agreement
expressed as the decimal equivalent of percent month.
Cc = The Lessor's current net costs.
O(IR) As defined in Section III.
Section V - Other Expenses
For billing costs to the Purchaser, labor and material additive costs at
current rates prevailing in the industry as adjusted from time to time shall
be added to the labor and material components of direct operation and
maintenance costs of Davis-Besse Unit No. 1 to which such rates are applicable
and shall be shared by Purchasers on the same bases on which the primary labor
and material costs are shared.
In addition, an allocation will be made of Account 556, System Control and
Load Dispatching costs related to production, and Account 557, Other
Production Expenses. These costs would be allocated to Davis-Besse Unit No. 1
on a direct basis where a direct relationship exists, or by using a net
generating capability ratio (O(IR)) where a direct relationship does not
exist. Account 556 will include only those load dispatching costs incurred by
TE that are attributable to Davis-Besse Unit No. 1. Included in Account 557,
Other Production Expenses, are such items as insurance premiums and recoveries
and other production expenses not directly assignable to the other production
accounts. The invoice will identify amounts billed that were included in
Account 557.
103
DB-1 (Page 11 of 17)
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Davis-Besse Station Unit No. 1
For billing costs to Purchasers, labor fringe benefit additive costs shall be
allocated to Davis-Besse Unit No. 1 on the basis of a rate representative of
labor additive rates experienced by public utilities in the United States, as
calculated from information contained in the U.S. Chamber of Commerce annual
Employee Benefit Survey or in another mutually agreed upon source. The rate,
expressed as a percent of total payroll cost, shall include the employer's
share of employee benefit costs for legally required payments, retirement and
savings plan payments, life insurance and death benefit payments, medical and
medically related payments, and other miscellaneous benefit payments; but
excluding benefits paid in the form of direct compensation to employees for
time not worked such as paid rest periods, lunch or travel periods, holidays,
vacations, sick time, parental leave and other similar payments.
The rate produced in this manner is 31.3% for the billing year 1993 based on
U.S. Chamber of Commerce survey data from benefit year 1991, and the rate for
subsequent years will be computed annually based on the then most current U.S.
Chamber of Commerce Survey data or other mutually agreed upon data available,
and will become effective January 1 of each such subsequent year.
The amount of labor additive costs to be allocated to each Purchaser during a
given period shall be the product of the above rate multiplied by the direct
labor expense allocated to the Purchaser for that period.
For billing costs to Purchasers, administrative and general (A&G) expense
shall be allocated to Davis-Besse Unit No. 1 on the basis of a rate
representative of A&G rates in the utility industry as calculated from
information contained in the Utility Data Institute (UDI) compilation of
utilities' FERC Form 1 data or in another mutually agreed upon source. The
rate shall be equal to the ratio of:
A. the sum of the base year of all amounts for all data base companies in
FERC Accounts 920, 921 and 922, divided by
B. the sum for the base year for the same companies of all amounts in FERC
Accounts 500 through 916, minus the amounts representing fuel and purchase
power expenses in FERC Accounts 501, 518, 547, 555 and 557.
The rate produced by this calculation is 12.70% for the billing year 1993
based on UDI data from 1991, and the rate for subsequent years will be
computed annually based on the then most current UDI or other mutually agreed
upon data available and will become effective January 1 of each such subse-
quent year.
The amount of Administrative and General Expenses to be allocated to each
Purchaser during a given period shall be the product of the above ratio
multiplied by the total operation and maintenance expenses and labor additives
excluding Account 518 allocated to the Purchaser for that period.
104
DB-1 (Page 12 of 17)
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Davis-Besse Station Unit No. 1
In addition, a Purchaser shall pay to the Owner, at times payable by the
Owner, amounts determined by multiplying (a) the property taxes and any other
taxes except Federal Income Tax, payable by the Owner with respect to the Unit
for the periods a Purchaser was involved by, (b) and O(IR) ratio for that
period.
105
EXHIBIT B
FIXED COSTS OF INVESTED CAPITAL
The monthly fixed charge for a vintage addition shall be calculated as the
algebraic sum of the following components:
A. Amortization(1) -- The product of (XX) multiplied by the ratio in
Note (5).
B. Finance Charge(2) -- The product of (AA) multiplied by the Seller's net
unamortized investment base as of the beginning of the month being billed
times the ratio in Note (5).
C. Gross Income Tax(3)
(i) For billing months after 1987, the product of (BB) multiplied by the
net unamortized investment base as of the beginning of the month
being billed. If the incremental federal tax rate is different from
34% in any month of such period, the factor used as the multiplier
shall be adjusted to reflect such difference from 34%.
D. Income Tax Adjustment(4)
For billing months after 1987, the product of (.34/1-34)) times the
difference between the amortization (Item A) less the tax depreciation.
If the incremental federal tax rate is different from 34% in any month of
such period, the factor used as the multiplier shall be adjusted to
reflect such difference from 34%.
NOTE: This adjustment may be a negative or positive value during the
period of the contract.
NOTES:
(1) (XX) equals the sum of the Seller's investment base less land divided by
420 months.
The Seller's adjusted investment base equals his total investment for
Beaver Valley Unit No. 2 and Common Facilities as of the beginning of the
month for which service is being billed.
(2) The Seller's net unamortized adjusted investment base equals the adjusted
investment base, less the accumulated amortization previously reflected
in rates, less investment tax credit attributed to the adjusted
investment base, less the net tax deduction associated with capitalized
overheads attributable to the adjusted investment base.
(AA) is the monthly finance charge rate, which equals 1/12 of the
Seller's weighted cost of capital as defined in the CAPCO Accounting and
Procedures Manual under Procedures for Discharging Investment
Responsibility.
106
DB-1 (Page 14 of 17)
EXHIBIT B
FIXED COSTS OF INVESTED CAPITAL
NOTES: (Cont'd)
(3) (BB) is the monthly gross income tax charge rates applicable to 1987 and
post-1987 billing periods. It is the product of 1/12 of the sum of the
weighted costs of common equity, preferred equity and unamortized gain on
the annual finance charge multiplied by the federal income tax rate
divided by the complement of the income tax rate. The tax rate may be
augmented to include state income taxes as defined in the CAPCO
Accounting and Procedures Manual under Procedures for Discharging Invest-
ment Responsibility, i.e.,
1/12 x (Seller's Equity Component of Capital) x (Tax Rate/(1-Tax Rate))
(4) The income tax adjustment results from the difference between book
amortization and tax depreciation, and from the agreement between the
parties of the extent to which such difference should be recognized in
the price paid.
(5) The ratio shall be the Ratio of Total Megawatt Capacity Purchased (or
Shared) to the Total Megawatts of Seller's Plant Capacity.
107
EXHIBIT C
REIMBURSEMENT OF WORKING CAPITAL COSTS
I. Accumulated Deferred Fuel Expense - Working Capital Costs Applicable to
a Purchaser of Capacity and Energy
Reimbursement by Monthly Carrying Charge in Lieu of Deposit
The charge for a given month per megawatt of capacity purchased
shall be based on the supplying Party's unamortized accumulated
deferred expenses (not related to burnup) pertaining to the period
prior to the the beginning of commercial operation of the leased
nuclear fuel per megawatt of capacity, to include the unamortized
deferred depletion balance, if any, at the end of the month in which
service was rendered and shall be calculated as follows:
The Product of (a) (b) (c)
(a) The Unamortized Accumulated Deferred Expenses (Not Related
to Burnup) pertaining to the period prior to the beginning
of Commercial Operation of the leased Nuclear Fuel to
include the unamortized deferred depletion balance, if any.
(b) The Ratio of Total Megawatt Capacity Purchased to the
supplying Party's Total Megawatt Capacity in Service.
(c) One-Twelfth* of the supplying Party's Current Annual
Capital Cost Rate, plus the supplying Party's income tax
liability on the Equity Component.
II. Materials and Supplies Inventory - Working capital cost applicable to a
purchaser.
Reimbursement by Monthly Carrying Charge in Lieu of Deposit
The charge for a given month per megawatt of capacity purchased (or
shared) shall be based on the supplying Party's total dollar balance
in M&S inventory at the end of the month in which service was
rendered, and shall be calculated as follows:
(a) Total Dollars in supplying Party's M&S Inventory at the Entire
Plant
(b) The Ratio of Total Megawatt Capacity Purchased (or Shared) to
the Total Megawatts of supplying Party's Plant Capacity.
(c) One-Twelfth* of the supplying Party's Current Annual Capital
Cost Rate, augmented to Include supplying Party's Income Tax
Liability on the Equity Component.
*Fraction used to calculate working capital for purposes of this
Exhibit.
108
DB-1 (Page 16 of 17)
EXHIBIT C
REIMBURSEMENT OF WORKING CAPITAL COSTS
III. Monthly Operation & Maintenance Expenses - Working capital cost appli-
cable to a purchaser or to an Owner.
The monthly charge shall be calculated each month for the Unit as the
product of (a) and (b) for capacity owned and as the product of (a), (b)
and (c) for capacity purchased.
(a) The current month's direct operating expenses (Accounts 500-554,
556, 557, 562 and 570) for each Owner for the Unit, including
overheads, less fuel and lease payments, and any other
inappropriate items.
(b) One-Twelfth* of the Operating Company's Current Annual Capital Cost
Rate plus the Operating Company's income tax liability on the
equity component.
(c) The Purchaser's entitlement share of megawatt capacity in the Unit.
*Fraction used to calculate working capital for purposes of this
Exhibit.
109
DB-1 (Page 17 of 17)
EXHIBIT D
DISPLACEMENT TRAINING COSTS
Installed Capacity at Davis-Besse Station No. 1 906,000 kW
Generation Entitlement Share
Cleveland Electric Illuminating Company 51.38%
Toledo Edison Company 48.62%
100.00%
The participants' respective shares of the displacement training costs, based
on $1.00/kW, are:
Cleveland Electric Illuminating Company $465,500
Toledo Edison Company $440,500
Therefore, under the terms of this Agreement, each purchaser will share in
these costs, based on its entitlement at the rate of 1/420 of the cost basis,
for each billing month beginning with the effective purchase date.
110
APPENDIX 7 TO SCHEDULE E, which was filed as part of Exhibit
10b(3), 1992 Form 10-K, File Nos. 1-9130, 1-2323 and 1-3583,
filed by Centerior Energy, Cleveland Electric and Toledo Edison,
remains in full force and effect, except for PY-1 Pages 11-18,
12-18, 13-18, 16-18 and 17-18, revised copies of which are filed
herewith.
111
PY-1 (Page 11-18)
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Perry Plant Unit No. 1
Dp = The unamortized portion at the beginning of the current accounting
month of the deferred expense not related to burnup pertaining to
the period prior to the beginning of commercial operation of the
leased nuclear fuel.
C. Monthly payments not related to burnup made by Participants to the
Lessor pertaining to the period after the beginning of commercial
operation of the leased nuclear fuel billable to the Purchaser shall be
calculated as follows:
MPLc = Rc(Cc)(O(IR))
Where:
MPLc = The current payments not related to burnup made by the
Participant to the Lessor.
Rc = The current lease rate as defined in the lease agreement
expressed as the decimal equivalent of percent per month.
Cc = The Lessor's current net costs.
O(IR) As defined in Section III.
Section V - Other Expenses
For billing costs to the Purchaser, labor and material additive costs at
current rates prevailing in the industry as adjusted from time to time shall
be added to the labor and material components of direct operation and
maintenance costs of Perry Unit No. 1 to which such rates are applicable and
shall be shared by Purchasers on the same bases on which the primary labor
and material costs are shared.
In addition, an allocation will be made of Account 556, System Control and
Load Dispatching costs related to production, and Account 557, Other
Production Expenses. These costs would be allocated to Perry Unit No. 1 on a
direct basis where a direct relationship exists, or by using a net generating
capability ratio (O(IR)) where a direct relationship does not exist. Account
556 will include only those load dispatching costs incurred by CEI that are
attributable to Perry Unit No. 1. Included in Account 557, Other Production
Expenses, are such items as insurance premiums and recoveries and other
production expenses not directly assignable to the other production accounts.
The invoice will identify amounts billed that were included in Account 557.
For billing costs to Purchasers, labor fringe benefit additive costs shall be
allocated to Perry Unit No. 1 on the basis of a rate representative of labor
additive rates experienced by public utilities in the United States, as
calculated from information contained in the U.S. Chamber of Commerce annual
Employee Benefit Survey or in another mutually agreed upon source.
112
PY-1 (Page 12 of 18)
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Perry Plant Unit No. 1
The rate, expressed as a percent of total payroll cost, shall include the
employer's share of employee benefit costs for legally required payments,
retirement and savings plan payments, life insurance and death benefit
payments, medical and medically related payments, and other miscellaneous
benefit payments; but excluding
benefits paid in the form of direct compensation to employees for time not
worked such as paid rest periods, lunch or travel periods, holidays,
vacations, sick time, parental leave and other similar payments.
The rate produced in this manner is 31.3% for the billing year 1993 based on
U.S. Chamber of Commerce survey data from benefit year 1991, and the rate for
subsequent years will be computed annually based on the then most current
U.S. Chamber of Commerce Survey data or other mutually agreed upon data
available, and will become effective January 1 of each such subsequent year.
The amount of labor additive costs to be allocated to each Purchaser during a
given period shall be the product of the above rate multiplied by the direct
labor expense allocated to the Purchaser for that period.
For billing costs to Purchasers, administrative and general (A&G) expense
shall be allocated to Perry Unit No. 1 on the basis of a rate representative
of A&G rates in the utility industry as calculated from information contained
in the Utility Data Institute (UDI) compilation of utilities' FERC Form 1
data or in another mutually agreed upon source. The rate shall be equal to
the ratio of:
A. the sum of the base year of all amounts for all data base companies in
FERC Accounts 920, 921 and 922, divided by
B. the sum for the base year for the same companies of all amounts in FERC
Accounts 500 through 916, minus the amounts representing fuel and
purchase power expenses in FERC Accounts 501, 518, 547, 555 and 557.
The rate produced by this calculation is 12.70% for the billing year 1993
based on UDI data from 1991, and the rate for subsequent years will be
computed annually based on the then most current UDI or other mutually agreed
upon data available and will become effective January 1 of each such
subsequent year.
The amount of Administrative and General Expenses to be allocated to each
Purchaser during a given period shall be the product of the above ratio
multiplied by the total operation and maintenance expenses and labor
additives excluding Account 501 allocated to the Purchaser for that period.
In addition, a Purchaser shall pay to the Participant, at times payable by
the Participant, amounts determined by multiplying (a) the property taxes and
any other taxes except Federal Income Tax, payable by the Participant with
respect to the Unit for the periods a Purchaser was involved by, (b) and
O(IR) ratio for that period.
113
PY-1 (Page 13 of 18)
(BLANK)
114
PY-1 (Page 16-18)
EXHIBIT C
REIMBURSEMENT OF WORKING CAPITAL COSTS
I. Accumulated Deferred Fuel Expense - Working Capital Costs Applicable to
a Purchaser of Capacity and Energy
Reimbursement by Monthly Carrying Charge in Lieu of Deposit
The charge for a given month per megawatt of capacity purchased shall be
based on the Supplying Party's unamortized accumulated deferred expenses
(not related to burnup) pertaining to the period prior to the beginning
of commercial operation of the leased nuclear fuel per megawatt of
capacity, to include the unamortized deferred depletion balance, if any,
at the end of the month in which service was rendered and shall be
calculated as follows:
The Product of (a) (b) (c)
(a) The Unamortized Accumulated Deferred Expenses (Not Related to
Burnup) pertaining to the period prior to the beginning of
Commercial Operation of the leased Nuclear Fuel to include
the unamortized deferred depletion balance, if any.
(b) The Ratio of Total Megawatt Capacity Purchased to the Supplying
Party's Total Megawatt Capacity in Service.
(c) One-Twelfth* of the Supplying Party's Current Annual Capital
Cost Rate, plus the Supplying Party's income tax liability
on the Equity Component.
II. Materials and Supplies Inventory - Working capital cost applicable to a
purchaser.
Reimbursement by Monthly Carrying Charge in Lieu of Deposit
The charge for a given month per megawatt of capacity purchased
(or shared) shall be based on the Supplying Party's total dollar
balance in M&S inventory at the end of the month in which service
was rendered, and shall be calculated as follows:
Perry Unit No. 1 - The Product Of:
(a) Total Dollars in Supplying Party's M&S Inventory at
the Entire Plant
(b) The Ratio of Total Megawatt Capacity Purchased (or
Shared) to the Total Megawatts of Supplying Party's
Plant Capacity.
*FRACTION USED TO CALCULATE WORKING CAPITAL FOR PURPOSES OF THIS EXHIBIT.
115
PY-1 (Page 17-18)
(c) One-twelfth* of the Supplying Party's current Annual
Capital Cost Rate, augmented to include Supplying
Party's Income Tax Liability on the Equity Component.
III. Monthly Operation & Maintenance Expenses - Working capital cost
applicable to a purchaser or to a participant.
The monthly charge shall be calculated each month for the Unit as the
product of (a) and (b) for capacity owned and as the product of (a),
(b) and (c) for capacity purchased.
(a) The current monthly's direct operating expenses (Accounts 500-
554, 556, 557, 562 and 570) for each Participant for the Unit,
including overheads, less fuel and lease payments, and any
other inappropriate items.
(b) One-Twelfth* of the Operating Company's Current Annual Capital
Cost Rate plus the Operating Company's income tax liability on
the equity component.
(c) The Purchaser's entitlement share of megawatt capacity in the
Unit.
*FRACTION USED TO CALCULATE WORKING CAPITAL FOR PURPOSES OF THIS EXHIBIT.
116
APPENDIX 8 TO SCHEDULE E has been revised from previous filings
and is filed in full herewith.
117
APPENDIX 8 TO SCHEDULE E
Charges Applicable to Transactions from Beaver Valley Power Station Unit No. 2
Pursuant to Schedule E
This Appendix provides for specific charges applicable to transactions made
from Beaver Valley Power Station Unit No. 2 pursuant to Schedule E.
Costs will be shared on a basis equivalent to that of the joint participants
with certain modifications specified herein.
The following are the components of the costs to be included.
A. Fixed Costs of Invested Capital
1. It is expected that sales out of production units will occur pre-
dominantly over a relative short time period in the early part of the
unit's life. However, this Appendix develops a consistent basis
which is applicable throughout the life cycle.
2. Amortization and tax calculations are based on the following:
Amortization Period - 35 Years (420 Months)
Plant
Amortization Period - 40 Years (480 Months)
Decommissioning
ACRS Tax Life 10 Years (120 Months)
Estimated Salvage Rate $142.4 Million Decommissioning Cost
Accounting Treatment Flow-Through
3. All fixed charges are on a month-to-month declining basis. The
investment base from which fixed charges are developed shall be the
CAPCO investment basis as defined in the Accounting and Procedure
Manual under Procedures for Discharging Investment Responsibility.
4. The monthly finance charge rate applicable to all additions from the
in-service date through the last month of the calendar year in which
the construction job order is closed out shall be one-twelfth the
specified annual rate.
5. The finance charge rate for ordinary additions in years subsequent to
the calendar year in which the construction job order was closed out
shall be the specified rate.
6. Amortization and other charges and adjustments shall be billed each
month. Each month's additions to plant in-service shall constitute a
vintage investment. However, in order to simplify the billing
process, the monthly vintages of any particular calendar year may be
combined into a composite vintage, either on an ongoing basis or at
the end of the calendar year, providing the same billing results.
Since finance charge rates are recalculated each year, vintages of
different calendar years will not be composited.
118
BV-2 (Page 2 of 19)
7. The tax plant ratio to amortizable plant (CAPCO investment basis)
shall be established from data for the total project as estimated at
the in-service date, as described in Paragraph 5. This ratio will be
used in developing fixed charge rates for the initial placements and
all subsequent additions; except that in the case of major capital
additions, at seller's option and with buyers' concurrence, a
completely new vintage may be developed and the fixed charge factor
recalculated using the new tax plant ratio and other pertinent data
as appropriate.
8. When a production unit, or a major capital addition such as described
in Paragraph 7, is placed in commercial service, the first fixed
charge billing shall begin effective with the in-service date. For
subsequent month-to-month additions, the billing shall begin with the
first full calendar month after the addition is made.
9. Where sales are initiated out of an existing production facility to a
new buyer, a single-vintage CAPCO investment basis may be calculated
with an appropriate adjustment for depreciation incurred to date.
The amortization component of the fixed charge factor will be calcu-
lated on the basis of remaining life of the original amortization
period or by mutual agreement.
10. The specific fixed charge rate for Beaver Valley Unit No. 2 is
developed in Exhibit B.
B. Operating and Maintenance Costs
1. The methods specified in the attached Exhibit A shall be used to
allocate between the supplying Party and the receiving Party(s) or
Purchaser(s) all costs, including overheads directly or indirectly
applicable to the operation and maintenance of the supplying Party's
participation in such unit.
2. The supplying Party will prepare, revise from time to time as
appropriate and furnish to the Purchaser(s) an annual estimate of the
amount to be billed by months (a) for the cost of energy during the
term of the purchase from a unit, and (b) any other costs which shall
accrue during this period. The supplying Party will furnish any
reasonable request for estimates for longer periods if required by
the Purchaser(s).
3. The supplying Party will maintain the records used in the deter-
mination of the Purchaser(s) bill in order that the Purchaser(s) and
their independent auditors shall have access at all reasonable times
to such records and the supplying Party will furnish copies of such
records as requested. The supplying Party shall preserve and
maintain the originals of such records for at least such periods of
time as the Purchaser(s) may request, having in mind the requirements
of regulatory authorities having jurisdiction and the policies and
practices of the parties with respect to the retention of records.
119
BV-2 (Page 3 of 19)
4. The cost of preparing, preserving and making copies of such budgets,
records and accounts shall be borne by the companies in proportion to
their respective capacity entitlements except that any costs incurred
at the special request of the Purchaser(s) shall be borne by them.
5. The supplying Party shall have special audits conducted with respect
to the matters provided for in this Appendix, either internally or by
independent auditors, according to such programs and procedures as
agreed to be necessary to conform to the auditing requirements of
each company, and shall furnish copies of the reports of such audits
to the Purchaser(s). The cost of making such audits, including any
participation by the auditors of the Purchaser(s) agreed to be
desirable and necessary, shall be shared by the companies in relation
to the current capacity entitlement ratio. The Purchaser(s) may, at
their own expense, make such further audits, using their internal or
independent auditors or both, as it may be deemed desirable.
6. If requested by the Purchaser(s), the supplying Party will make such
examinations, analyses or studies as needed to support the reason-
ableness of the specific costs so allocated, or provide a basis for
modification to achieve such reasonableness with respect to either
the specific or the indirect cost allocations. Shareable costs which
are incurred by the Purchaser(s) shall be accumulated and billed on a
direct charge basis from specific records or reasonable estimates
with applicable additives as agreed upon by the companies.
7. Except as otherwise provided herein, the accounting methods and
practices normally in use at the time by each of the companies in
determining and assigning operating and maintenance costs, generally,
are to be used by such company for the purposes of this Appendix
unless otherwise agreed, provided such methods and practices are
consistent with sound accounting practices.
8. For the purpose of this Appendix, charges to Account 525, for rent or
lease payments, will be considered fixed costs and will be charged to
the Purchaser as described in Exhibit B.
9. The supplying Party will bill the Purchaser(s) for its share of
property, franchise, business or other taxes applicable to its share
of the unit, specifically identifying these items on the invoice when
such taxes are payable by the supplying Party. To the extent that
such taxes are charged to the operating expenses of the Unit because
it is impractical or inequitable to segregate them, they will be
billed as part of the normal operating expense of the Unit.
10. As soon as possible after the close of each calendar month, prefer-
ably on or before the 8th working day of the following month, the
supplying Party shall advise the Purchaser(s) of its proportionate
share of estimated operating expenses, fixed charges, displacement
training costs and working capital for the preceding month. Any
costs payable will be paid pursuant to Section 12.02 of the CAPCO
Basic Operating Agreement, as amended.
120
BV-2 (Page 4 of 19)
C. Working Capital
It is recognized that the operating company undertakes certain obligations
to provide expenditures in advance of compensation by the purchasers of
capacity and energy. These purchases include, but may not be limited to,
payroll, fuel and material and supplies purchases, and material and
supplies inventories. A reasonable allowance for this investment in
working capital funds shall be considered a shareable cost to be compen-
sated for as set out in detail in Exhibit C.
D. Displacement Training Costs
The CAPCO companies have agreed that the costs which an operating company
will incur in training personnel at existing stations in order to be able
to transfer experienced personnel to a new CAPCO generating unit should be
shared by the joint owners.
Purchasers of capacity and energy shall also share in these costs.
1. For each new CAPCO unit, the cost basis of $1/kW of the installed
capacity is determined to be a reasonable estimate of the present-day
cost which a company will incur within its existing plants as a
result of assigning experienced company personnel to a new CAPCO
generating unit. Installed capacity for this purpose is defined as
the Net Demonstrated Capability of the CAPCO generating unit.
2. It is recognized that these costs will increase as labor costs
increase. Therefore, this cost determination factor of $1/kW shall
be subject to escalation for units planned to be in-service after
Davis-Besse No. 1 based on an index of the composite labor costs of
CAPCO companies as agreed to by the CAPCO Accounting and Finance
Committee using 1972 as the base year equaling 100.0. The index to
be applied shall be that calculated for the period two years prior to
the actual in-service date for fossil-fired generating units and for
the period three years prior to the actual in-service date for
nuclear units.
3. The Purchasers of capacity and energy shall share in these costs for
the periods they are involved. An amount of 1/420 of the cost basis
for each kW of the purchasing company's capacity entitlement shall be
included in the monthly billing.
4. The cost basis provided for herein shall be shown in Exhibit D.
121
BV-2 (Page 5 of 19)
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Beaver Valley Power Station Unit No. 2
EXHIBIT A
Section I - Introduction
This Exhibit pertains to all agreements related to the Sales of Capacity and
Energy from the Participants of Beaver Valley Unit No. 2 to Purchasers. In
the event any Purchaser does not schedule part or any of its generation
entitlement share as stated in the applicable agreement, the balance of its
entitlement shall remain as capacity available to the Purchaser, provided
that, if the Unit is operated at minimum load required for safe operation of
the Unit, the Purchaser shall be obligated to schedule an amount of energy
equal to that Unit's minimum load for the hour, multiplied by a fraction of
which the numerator is the Purchaser's entitlement under the applicable
agreement and the denominator is the applicable Unit's Net Demonstrated
Capability. The amount of energy determined above, subject to adjustment for
proportionate use of all plant auxiliary power assignable to the operation of
the Unit, shall constitute a scheduled (billing) MWH value (net) as of each
Unit's generator transformer high voltage terminals. Each Participant shall
schedule for delivery from the Unit, and each Purchaser shall schedule for
receipt into its system, an amount of energy equal to such billing value less
the increase, or plus the decrease, as the case may be, in electrical losses
incurred on its system resulting from the transmission of such energy as
determined by the Planning Committee under terms of the CAPCO Transmission
Facilities Agreement.
Section II - Accounting Concepts
The basis for allocating the operation and maintenance costs of Beaver Valley
Unit No. 2 between the joint Participants is set forth in Exhibit A of the
Operating Agreement for this unit. This Exhibit prescribes the method of
determining the portion of that cost of a Participant which will be billed to
a Purchaser.
The costs to be billed to a Purchaser will be segregated as to those that are
directly identified with a Purchaser and to those that are allocated either on
an investment responsibility or a fuel consumed basis. The codes for these
segregations are defined at the end of Section III.
In addition to the direct costs for operating and maintaining the Unit, a
Participant shall bill a Purchaser for an appropriate portion of indirect
overheads and taxes other than income taxes as defined in Section V.
Section III - Allocation of Costs
The operation and maintenance costs identified by FERC account number are
assigned to a Purchaser either directly or on the basis of appropriate
allocation codes as set forth in the following table.
122
BV-2 (Page 6 of 19)
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Beaver Valley Power Station Unit No. 2
Direct Participants' Costs to be
Basis Allocated to the Purchaser
Account to Allocation Codes
Number Purchaser O(IR) HY(IR)
OPERATION ACCOUNTS
517 Supervision and Engineering X
518 Nuclear Fuel Expense X
519 Coolants and Water X
520-2 Steam Expenses* X
520-3 Steam Expenses* X
523 Electric Expenses X
524 Misc. Nuclear Power Expenses X
MAINTENANCE ACCOUNTS
528 Supervision and Engineering X
529 Structures X
530-2 Reactor Plant and Equipment* X
530-3 Reactor Plant and Equipment* X
531 Electric Plant X
532 Misc. Nuclear Plant X
OTHER ACCOUNTS
562 Operation - Station Expenses X
570 Maintenance of Station Equipment X
*See Exhibit A of the Beaver Valley Operating Agreement for breakdown of these
accounts.
Direct charges will be made to a Purchaser for fuel consumed as determined in
accordance with Section IV.
Code Basis
O(IR) The portion of a Participant's operation and maintenance costs for
the Unit to be billed to a Purchaser for the current month shall be
a fraction of which the numerator is a Purchaser's entitlement from
the Unit as specified in the applicable agreement and the
denominator is a Participant's interest in that Unit, both figures
rounded to the nearest whole megawatt. A Participant's interest in
the Unit shall be the product of the prevailing Net Demonstrated
Capability (NDC) of the Unit multiplied by that Participant's net
generation entitlement share in the Unit.
123
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Beaver Valley Power Station Unit No. 2
Code Basis
If the capacity of the Unit is reduced by operating problems, a
Purchaser will be entitled to his O(IR) ratio multiplied by the
Participant's entitlement of the output of the Unit on an hour-
to-hour basis.
HY(IR) The portion of a Participant's cost for the Unit to be billed to a
Purchaser for the current month shall be a fraction of which the
numerator is the portion of the BTU input to the main unit turbine
used to produce the kilowatthours of energy taken from the Unit by
the Purchaser during the preceding 12-month period and the
denominator is the portion of the BTU input to the main turbine
used to produce the kilowatthours of energy taken from the Unit by
the Participant during that same preceding 12-month period. Prior
to the time that this data is available on a 12-month basis,
available data will be used to determine the allocation ratio.
Section IV - Fuel
In determining fuel costs, a Purchaser shall be treated in the same manner as
a Participant.
The following basic principles shall govern the calculation of depletion
(amortization) of fuel assemblies installed in the reactor for heat production
and the billing of fuel costs to Purchasers.
1. Nuclear fuel assemblies shall be considered to be producing heat only
during periods of zero or positive net generation.
2. During periods of negative net generation, it will be considered that
installed nuclear fuel assemblies are not producing heat and are not thus
consumed. During periods of negative net generation, records of station
service electric energy supplied by the system shall be maintained and the
participants in the Unit shall be invoiced for such electric energy in
proportion to their investment responsibilities in the Unit as the
operating Participant's system average production cost (including net
purchased power costs) during the current calendar month adjusted to
exclude the output and cost during the current calendar month of the Unit
to which such station service energy was supplied.
3. During periods of zero or positive net generation, the components of
consumption of heat from nuclear fuel assemblies shall be considered to
consist of a fixed heat consumption component and a variable heat
consumption component. The components of heat consumption are illustrated
by the current turbine-generator heat consumption curve for the Unit as
agreed to by the Participants. The fixed portion of heat consumption
consists of the heat produced by the reactor required to supply station
service electric energy plus heat losses in the plant.
124
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Beaver Valley Power Station Unit No. 2
4. During periods of zero or positive net generation, the fixed and variable
portions of the total Unit heat consumption shall be calculated on an
hour-by-hour basis. The fixed portion of the Unit heat consumption shall
be the product of service hours accumulated during periods of zero or
positive net generation times the fixed unit heat consumption as indicated
on the current turbine-generator heat consumption curve for the Unit as
agreed to by the Participants. The variable portion of the Unit heat
consumption shall be the total net main unit generation in MWe hr/hr
converted to BTU/hr excluding the fixed unit heat consumption utilizing
the relationship between MWe hr/hr versus BTU/hr as represented on the
current turbine-generator heat consumption curve for each Unit as agreed
to by the Participants. The total unit heat consumption shall be the sum
of fixed and variable portions of the unit heat consumption.
5. In calculations for determining the cost of nuclear fuel consumed,
Duquesne Light Company shall take into account the original acquisition
cost of the materials and services required to provide the fuel as
originally installed, and predicted total heat output of the assemblies
and the estimated net value of salvage materials. Duquesne shall
calculate such cost of nuclear fuel consumed using methods and/or computer
codes generally considered acceptable by the CAPCO Companies for this
purpose.
6. For owned nuclear fuel, the total monthly nuclear fuel expense for the
Purchaser shall be determined by the formula
FCc = Ec (Ac - Sf)
_________
Ef
where:
FCc = Nuclear Fuel expense during the current accounting month.
Ec = The energy received by the Purchaser during the current accounting
month.
Ef = The energy expected to be produced from the fuel component. Fuel
component can be a fuel assembly, sub-region, region or entire
core.
Ac = The Participant's current net costs.
Sf = Anticipated salvage value of the fuel with related deductions
including, but not limited to, shipping, reprocessing and waste
disposal costs.
When the Participant adjusts its Ac, Sf and Ef factors, these same factors
will be adjusted in a similar manner for the Purchaser.
125
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Beaver Valley Power Station Unit No. 2
7. For leased nuclear fuel, the total monthly nuclear fuel expense for the
Purchaser is composed of a) a burnup expense related to energy resource
consumption, b) amortization of accumulated deferred expenses not related
to burnup pertaining to the period prior to the beginning of commercial
operation of the leased nuclear fuel, and c) monthly payments not related
to burnup made by the Participants to the Lessor pertaining to the period
after the beginning of commercial operation of the leased nuclear fuel.
A. The monthly burnup expense shall be calculated as follows:
Bc = Ec (Cc - Sf)
_________
Ef
where:
Bc = Burnup expense for the current accounting month.
Ec = The energy received by the Purchaser during the current
accounting month.
Ef = The energy expected to be produced from the fuel component.
Fuel component can be a fuel assembly, sub-region or entire
core.
Cc = The Lessor's current net costs.
Sf = Anticipated salvage value of the fuel with related deductions
including, but not limited to, shipping, reprocessing and waste
disposal costs.
B. The amortization of accumulated deferred expenses not related to
burnup pertaining to the period prior to the beginning of commercial
operation of the leased nuclear fuel shall be calculated as follows:
PDAc = Ec (Dp)
____
Ef
where:
PDAc = The current month amortization of deferred expenses not
related to burnup pertaining to the period prior to the
beginning of commercial operation of the leased nuclear fuel.
Ec = The energy received by the Purchaser during the current
accounting month.
Ef = The energy expected to be produced from the fuel component.
126
BV-2 (Page 10 of 19)
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Beaver Valley Power Station Unit No. 2
Dp = The unamortized portion at the beginning of the current
accounting month of the deferred expense not related to
burnup pertaining to the period prior to the beginning of
commercial operation of the leased nuclear fuel.
C. Monthly payments not related to burnup made by Participants to the
Lessor pertaining to the period after the beginning of commercial
operation of the leased nuclear fuel billable to the Purchaser shall
be calculated as follows:
MPLc = Rc (Cc) (O(IR))
where:
MPLc = The current payments not related to burnup made by the
Participant to the Lessor.
Rc = The current lease rate as defined in the lease agreement
expressed as the decimal equivalent of percent month.
Cc = The Lessor's current net costs.
O(IR) As defined in Section III.
Section V - Other Expenses
For billing costs to the Purchaser, labor and material additive costs at
current rates prevailing in the industry as adjusted from time to time shall
be added to the labor and material components of direct operation and
maintenance costs of Beaver Valley Unit No. 2 to which such rates are
applicable and shall be shared by Purchasers on the same bases on which the
primary labor and material costs are shared.
In addition, an allocation will be made of Account 556, System Control and
Load Dispatching costs related to production, and Account 557, Other
Production Expenses. These costs would be allocated to Beaver Valley Unit
No. 2 on a direct basis where a direct relationship exists, or by using a net
generating capability ratio (O(IR)) where a direct relationship does not
exist. Account 556 will include only those load dispatching costs incurred by
DL that are attributable to Beaver Valley Unit No. 2. Included in
Account 557, Other Production Expenses, are such items as insurance premiums
and recoveries and other production expenses not directly assignable to the
other production accounts. The invoice will identify amounts billed that were
included in Account 557.
127
BV-2 (Page 11 of 19)
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Beaver Valley Power Station Unit No. 2
For billing costs to Purchasers, labor fringe benefit additive costs shall be
allocated to Beaver Valley Unit No. 2 on the basis of a rate representative of
labor additive rates experienced by public utilities in the United States, as
calculated from information contained in the U.S. Chamber of Commerce annual
Employee Benefit Survey or in another mutually agreed upon source. The rate,
expressed as a percent of total payroll cost, shall include the employer's
share of employee benefit costs for legally required payments, retirement and
savings plan payments, life insurance and death benefit payments, medical and
medically related payments, and other miscellaneous benefit payments; but
excluding benefits paid in the form of direct compensation to employees for
time not worked such as paid rest periods, lunch or travel periods, holidays,
vacations, sick time, parental leave and other similar payments.
The rate produced in this manner is 31.3% for the billing year 1993 based on
U.S. Chamber of Commerce survey data from benefit year 1991, and the rate for
subsequent years will be computed annually based on the then most current U.S.
Chamber of Commerce Survey data or other mutually agreed upon data available,
and will become effective January 1 of each such subsequent year.
The amount of labor additive costs to be allocated to each Purchaser during a
given period shall be the product of the above rate multiplied by the direct
labor expense allocated to the Purchaser for that period.
For billing costs to Purchasers, administrative and general (A&G) expense
shall be allocated to Beaver Valley Unit No. 2 on the basis of a rate
representative of A&G rates in the utility industry as calculated from
information contained in the Utility Data Institute (UDI) compilation of
utilities' FERC Form 1 data or in another mutually agreed upon source. The
rate shall be equal to the ratio of:
A. the sum of the base year of all amounts for all data base companies in
FERC Accounts 920, 921 and 922, divided by
B. the sum for the base year for the same companies of all amounts in FERC
Accounts 500 through 916, minus the amounts representing fuel and purchase
power expenses in FERC Accounts 501, 518, 547, 555 and 557.
The rate produced by this calculation is 12.70% for the billing year 1993
based on UDI data from 1991, and the rate for subsequent years will be
computed annually based on the then most current UDI or other mutually agreed
upon data available and will become effective January 1 of each such subse-
quent year.
The amount of Administrative and General Expenses to be allocated to each
Purchaser during a given period shall be the product of the above ratio
multiplied by the total operation and maintenance expenses and labor additives
excluding Account 518 allocated to the Purchaser for that period.
128
BV-2 (Page 12 of 19)
ASSIGNMENT OF PRODUCTION COSTS
Sales of Capacity and Energy from Base Load Units
to Purchasers: Beaver Valley Power Station Unit No. 2
In addition, a Purchaser shall pay to the Participant, at times payable by the
Participant, amounts determined by multiplying (a) the property taxes and any
other taxes except Federal Income Tax, payable by the Participant with respect
to the Unit for the periods a Purchaser was involved by, (b) and O(IR) ratio
for that period.
129
EXHIBIT B
FIXED COSTS OF INVESTED CAPITAL
I. As between Cleveland Electric Illuminating and Toledo Edison, the
monthly fixed charge for vintage additions prior to 1988 shall be
calculated as the algebraic sum of the following components:
A. Lease Payment -- The Purchaser will reimburse the Seller's total
monthly lease and/or rental payment for plant property under a sale/
leaseback agreement. This payment may be adjusted as the payment
schedule on the underlying sale/leaseback agreement is amended.
B. Decommissioning Costs -- The product of the allowed monthly charge
for decommissioning in the Seller's rates multiplied by the ratio of
Total Megawatt Capacity Purchased to the Seller's Total Megawatt
Ownership in the Unit. [($142,400,000 : 480) * (150/166)] =
$268,027/month.
C. Refueling Outage Accrual -- The product of the allowed monthly
charge for refueling outage accruals in the Seller's rates multi-
plied by the ratio of Total Megawatt Capacity Purchased to the
Seller's Total Megawatt Ownership in the Unit.
II. The monthly fixed charge for a vintage addition made during 1987 or
subsequent years shall be calculated as the algebraic sum of the
following components:
A. Amortization(1) -- The product of (XX) multiplied by the ratio in
Note (5).
B. Finance Charge(2) -- The product of (AA) multiplied by the Seller's
net unamortized investment base as of the beginning of the month
being billed times the ratio in Note (5).
C. Gross Income Tax(3)
(i) For billing months after 1987, the product of (BB) multiplied
by the net unamortized investment base as of the beginning of
the month being billed. If the incremental federal tax rate is
different from 34% in any month of such period, the factor used
as the multiplier shall be adjusted to reflect such difference
from 34%.
D. Income Tax Adjustment(4)
For billing months after 1987, the product of (.34/1-34)) times the
difference between the amortization (Item A) less the tax
depreciation. If the incremental federal tax rate is different from
34% in any month of such period, the factor used as the multiplier
shall be adjusted to reflect such difference from 34%.
NOTE: This adjustment may be a negative or positive value during
the period of the contract.
130
BV-2 (Page 14 of 19)
EXHIBIT B
FIXED COSTS OF INVESTED CAPITAL
NOTES:
(1) (XX) equals the sum of the Seller's investment base less land divided by
420 months plus the Seller's share of decommissioning costs divided by
480 months.
The Seller's adjusted investment base equals his total investment for
Beaver Valley Unit No. 2 and Common Facilities as of the beginning of
the month for which service is being billed.
(2) The Seller's net unamortized adjusted investment base equals the
adjusted investment base, less the accumulated amortization previously
reflected in rates, less investment tax credit attributed to the
adjusted investment base, less the net tax deduction associated with
capitalized overheads attributable to the adjusted investment base.
(AA) is the monthly finance charge rate, which equals 1/12 of the
Seller's weighted cost of capital as defined in the CAPCO Accounting and
Procedures Manual under Procedures for Discharging Investment
Responsibility.
(3) (BB) is the monthly gross income tax charge rates applicable to 1987 and
post-1987 billing periods. It is the product of 1/12 of the sum of the
weighted costs of common equity, preferred equity and unamortized gain
on the annual finance charge multiplied by the federal income tax rate
divided by the complement of the income tax rate. The tax rate may be
augmented to include state income taxes as defined in the CAPCO
Accounting and Procedures Manual under Procedures for Discharging
Investment Responsibility, i.e.,
1/12 x (Seller's Equity Component of Capital) x (Tax Rate/(1-Tax Rate))
(4) The income tax adjustment results from the difference between book
amortization and tax depreciation, and from the agreement between the
parties of the extent to which such difference should be recognized in
the price paid.
(5) The ratio shall be the Ratio of Total Megawatt Capacity Purchased (or
Shared) to the Total Megawatts of Seller's Plant Capacity.
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BV-2 (Page 15 of 19)
EXHIBIT B.1
DERIVATION OF WEIGHTED COST OF CAPITAL
THE TOLEDO EDISON COMPANY
The complete capital structure, including ratios, component costs and weighted
component costs is provided below:
% of % Weighted
Total % Cost Cost
Long-Term Debt 50.53% 10.29% 5.20%
Preferred Stock 10.13% 9.41% 0.95%
Common Equity 39.34% 12.25% 4.82%
100.00% 10.97%
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BV-2 (Page 16 of 19)
EXHIBIT B.2
DERIVATION OF DECOMMISSIONING COST AND ACCRUAL
THE TOLEDO EDISON COMPANY
The derivation of the decommissioning cost estimate of $142.4 million for
Beaver Valley Unit No. 2 was developed as follows:
NRC Decommissioning Estimate (1984 Dollars) $100,000,000
Inflation Factor* 1.224
Decommissioning Estimate (10-87 Dollars) $122,400,000
Net Salvage on Non-Contaminated Portion 20,000,000
Total $142,400,000
*The inflation factor of 1.224 is twice the percentage increase in the CPI
from the period June 1984 to October 1987.
The annual accrual will simply be the $142.4 million estimate divided by
40 years or $3,560,000/year. Toledo Edison's share of this decommissioning
cost is $28,352,000. Toledo Edison's share of the annual accrual is $708,800.
The specific monthly amount Toledo Edison will charge The Cleveland Electric
Illuminating Company for the 150 MW Unit Power Sale is $53,373, developed as
shown below:
Total Plant Estimated Decommissioning $142,400,000
Cost
Toledo Edison Share at 19.91% 28,352,000
Toledo Edison Monthly Accrual 59,606
($28,352,000 + 480)
Toledo Edison Monthly Charge to CEI 53,373
for 150 MW Sale
($59,066 x 150 MW)
( 166 MW)
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REIMBURSEMENT OF WORKING CAPITAL COSTS
I. Accumulated Deferred Fuel Expense - Working Capital Costs Applicable to
a Purchaser of Capacity and Energy
Reimbursement by Monthly Carrying Charge in Lieu of Deposit
The charge for a given month per megawatt of capacity purchased
shall be based on the supplying Party's unamortized accumulated
deferred expenses (not related to burnup) pertaining to the period
prior to the the beginning of commercial operation of the leased
nuclear fuel per megawatt of capacity, to include the unamortized
deferred depletion balance, if any, at the end of the month in which
service was rendered and shall be calculated as follows:
The Product of (a) (b) (c)
(a) The Unamortized Accumulated Deferred Expenses (Not Related
to Burnup) pertaining to the period prior to the beginning
of Commercial Operation of the leased Nuclear Fuel to
include the unamortized deferred depletion balance, if any.
(b) The Ratio of Total Megawatt Capacity Purchased to the
Supplying Party's Total Megawatt Capacity in Service.
(c) One-Twelfth* of the Supplying Party's Current Annual
Capital Cost Rate, plus the Supplying Party's income tax
liability on the Equity Component.
II. Materials and Supplies Inventory - Working capital cost applicable to a
purchaser.
Reimbursement by Monthly Carrying Charge in Lieu of Deposit
The charge for a given month per megawatt of capacity purchased (or
shared) shall be based on the supplying Party's total dollar balance
in M&S inventory at the end of the month in which service was
rendered, and shall be calculated as follows:
Beaver Valley Unit No. 2 - The Product Of:
(a) Total Dollars in Supplying Party's M&S Inventory at the
Entire Plant.
(b) The Ratio of Total Megawatt Capacity Purchased (or Shared)
to the Total Megawatts of Supplying Party's Plant Capacity.
(c) One-Twelfth* of the Supplying Party's Current Annual
Capital Cost Rate, augmented to Include Supplying Party's
Income Tax Liability on the Equity Component.
*Fraction used to calculate working capital for purposes of this
Exhibit.
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BV-2 (Page 18 of 19)
EXHIBIT C
REIMBURSEMENT OF WORKING CAPITAL COSTS
III. Monthly Operation & Maintenance Expenses - Working capital cost appli-
cable to a purchaser or to a participant.
The monthly charge shall be calculated each month for the Unit as the
product of (a) and (b) for capacity owned and as the product of (a), (b)
and (c) for capacity purchased.
(a) The current month's direct operating expenses (Accounts 500-554,
556, 557, 562 and 570) for each Participant for the Unit, including
overheads, less fuel and lease payments, and any other
inappropriate items.
(b) One-Twelfth* of the Operating Company's Current Annual Capital Cost
Rate plus the Operating Company's income tax liability on the
equity component.
(c) The Purchaser's entitlement share of megawatt capacity in the Unit.
*Fraction used to calculate working capital for purposes of this
Exhibit.
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BV-2 (Page 19 of 19)
EXHIBIT D
DISPLACEMENT TRAINING COSTS
Installed Capacity at Beaver Valley Power Station No. 2 833,000 kW
Generation Entitlement Share
Cleveland Electric Illuminating Company 24.47%
Duquesne Light Company 13.74%
Ohio Edison Company 41.88%
Toledo Edison Company 19.91%
100.00%
The participants' respective shares of the displacement training costs, based
on $2.011/kW, are:
Cleveland Electric Illuminating Company $409,912
Duquesne Light Company $230,167
Ohio Edison Company $701,558
Toledo Edison Company $333,525
Therefore, under the terms of this Agreement, each purchaser will share in
these costs, based on its entitlement at the rate of 1/420 of the cost basis,
for each billing month beginning with the effective purchase date.
136
CAPCO BASIC OPERATING AGREEMENT
SCHEDULE F
OUT-OF-POCKET COST
Where referred to in this Agreement, the Out-of-Pocket Cost of supplying Power
in each hour shall be the cost incurred in the supply of the highest cost
power available on the supplying Party's system during that hour, including
power purchased from non-CAPCO party systems as well as Power generated by a
Party's own generation resources, after all sales with a lower pricing
priority (higher cost) have been accounted for. The components of
Out-of-Pocket Costs shall include but shall not be limited to the following:
Capacity Costs
Start-up and shutdown costs (boiler and turbine)
No load cost (boiler and turbine)
Maintenance cost (boiler and turbine)
Charge (or credit) for increased (or decreased) cost of energy generated
by the Party associated with the transaction
Incremental labor costs
Applicable incremental taxes
Miscellaneous incremental operating costs
137
Energy Costs
Incremental fuel cost
Incremental transmission losses
Incremental labor cost
Incremental maintenance cost
Applicable incremental taxes
Miscellaneous incremental operating costs
Purchased Power
All costs, excluding demand charges, paid to a non-CAPCO party system for
Power purchased plus applicable or allocable fees imposed by any
regulatory body.
138
CAPCO BASIC OPERATING AGREEMENT
SCHEDULE G
EMERGENCY POWER
Section 1 - Services to be Rendered
1.1 In the event of a breakdown or other emergency in or on the system
of any Party involving either sources of power or transmission facilities, or
both, impairing or jeopardizing the ability of a Party to meet the Load of its
system, upon request, each Party shall deliver to such Party Emergency Power,
during a period not exceeding 48 consecutive hours, in amounts up to 100 MW
per hour and such additional amounts as in its sole judgment it can deliver
without interposing a hazard to its operations or without impairing or
jeopardizing its Load. Such Emergency Power shall be provided (1) from
unloaded generating facilities, either on or off line, to the fullest extent
necessary from each supplying Party's system, or (2) from non-CAPCO party
systems to which the supplying Parties are interconnected. No Party is
obligated to terminate any delivery of Power (excluding economy transactions)
to any other system in order to provide Emergency Power, but a Party is
obligated to terminate economy transactions and supply any excess Power from
its own system and to purchase Power, if available, from any other system with
which it is interconnected in order to provide Emergency Power. Every request
hereunder shall identify the emergency that gave rise to it. Emergency Power
shall not be requested or supplied in lieu of CAPCO Back-Up Power.
139
1.2 If at any time the record over a reasonable prior period shows
clearly that any Party has failed to deliver Emergency Power, or has regularly
requested delivery of Emergency Power, any Party, by written notice given to
the other Parties, may call for a joint study by the Parties to determine the
burden, if any, that such Party may be placing upon any other. If it should
be found that such Party is placing an unreasonable burden upon the others,
the Party causing the burden shall take such measures as are necessary to
remove the burden, or the Parties shall enter into such arrangements as shall
provide for equitable compensation to the Party(s) being burdened.
Section 2 - Compensation
2.1 Capacity Charge
Capacity supplied from a supplying Party's system shall be
compensated for at the option of the supplying Party by return-in-kind or by
the payment of the greater of (1) $100 per MW-hr or (2) 100% Out-of-Pocket
Cost plus a charge of $2.40 per MW-hr for operating capacity from a supplying
Party's system.
Capacity supplied from a non-CAPCO party system shall be
compensated for at the option of the supplying Party by return-in-kind or by
the payment of the greater of (1) $100 per MW-hr or (2) 100% Out-of-Pocket
Cost plus any demand charge of a non-CAPCO party system for providing
operating capacity plus a demand charge not to exceed $5.59 per MW-hr shall
apply, provided this demand charge in any one day shall not exceed $89.40
times the maximum MW(s) reserved in any one hour in that day plus $1.00 per
MW-hr.
140
2.2 Capacity and Energy or Energy Only Charge
Emergency Power supplied from a supplying Party's system shall be
compensated for at the option of the supplying Party by return-in-kind or by
the payment of the greater of (1) $100 per MWh or (2) 100% Out-of-Pocket Cost
plus a charge of $2.40 per MWh for operating capacity and or energy or energy
only from a supplying Party's system.
Emergency Power supplied from a non-CAPCO party shall be compen-
sated for at the option of the supplying Party by return-in-kind or by the
payment of the greater of (1) $100 per MWh or (2) 100% Out-of-Pocket Cost plus
any demand charge of a non-CAPCO party system for operating capacity and
energy plus for such transactions a demand charge not to exceed $5.59 per MWh
shall apply, provided this demand charge in any one day shall not exceed
$89.40 times the maximum MW(s) reserved in any one hour in that day plus $1.00
per MWh.
141
CAPCO BASIC OPERATING AGREEMENT
SCHEDULE H
TRANSMISSION OF NON-CAPCO POWER
Section 1 - Services to be Rendered
1.1 Any Party ("supplying Party") may arrange to reserve Non-CAPCO
Power for periods of one day or more from or through an interconnected
non-CAPCO party system to be delivered to another Party ("receiving Party")
for delivery to or through another interconnected non-CAPCO party system. All
Parties shall be advised of such transactions in advance. This Schedule shall
not apply to Economy and Emergency transactions.
Section 2 - Compensation
2.1 For such transactions the associated demand, capacity and energy
charge payments for transmission service upon the transmission systems of the
CAPCO Parties (i.e., the difference between the amounts paid to the receiving
Party and by the supplying Party) shall be shared among all Parties with 2/3
of such payments allocated equally between the supplying Party and the receiv-
ing Party and 1/3 of such payments allocated equally between the other two
Parties.
142
CAPCO BASIC OPERATING AGREEMENT
SCHEDULE I
REPLACEMENT POWER
Section 1 - Applicability
The Parties recognize the possibility that the start-up of a nuclear
CAPCO Unit may be delayed and such CAPCO Unit may be out of service due to the
failure of a Party having an ownership interest in such CAPCO Unit to supply
its required share of natural uranium in the form of U3O8 or UF6 ("Uranium")
for such CAPCO Unit for delivery in a timely manner and in a tenant-in-common
form of ownership to the United States Department of Energy or other enrich-
ment contractor for enrichment. This Schedule I is applicable to the provi-
sion of replacement Power in any such limited circumstances where a Party
having an ownership interest in a CAPCO Unit fails to so supply its share of
Uranium for enrichment.
Section 2 - Services to be Rendered
2.1 In the event that any Party(s) ("supplying Party") fails to supply
its required share of Uranium for a CAPCO Unit, then any Party(s) ("receiving
Party"), which is unable to receive its entitlement of operating capacity and
associated energy from such CAPCO Unit as the direct result of such supplying
Party's failure to supply the required Uranium, may during the period that the
start-up of such CAPCO Unit is delayed and such Unit is out of service, at
such receiving Party's sole option, either (1) arrange for replacement
143
capacity ("Replacement Capacity") and replacement energy ("Replacement
Energy") or (2) permit the supplying Party which failed to supply the Uranium
to provide such Replacement Capacity and Replacement Energy. The amount of
such Replacement Capacity on an hourly basis will be up to, at the option of
each such receiving Party, an amount equal to such receiving Party's ownership
interest in such CAPCO Unit times the effective average capacity factor
achieved by such CAPCO Unit during the last fuel cycle (excluding refueling)
prior to such CAPCO Unit being out of service. Any amount of Replacement
Energy may be scheduled by such receiving Party out of such Replacement
Capacity. If such CAPCO Unit has not yet attained sufficient operating
experience to establish such effective average capacity factor, then such
effective average capacity factor shall be deemed to be the same as the most
recent comparable experience of any like CAPCO Unit at such CAPCO Unit site.
Such transactions shall be arranged weekly in advance between the receiving
Party and supplying Party and shall specify the amount of Replacement Capacity
and Replacement Energy to be provided, if any, and the hours it is to be
provided.
2.2 Replacement Capacity and Replacement Energy provided under this
Schedule I will be made available to receiving Parties in proportion to their
entitlements and from supplying Parties in proportion to their obligations.
Replacement Capacity and Replacement Energy obligations not reserved by the
receiving Party shall be deemed released by the receiving Party for that week.
144
Section 3 - Compensation
3.1 If the supplying Party supplies such Replacement Capacity and
Replacement Energy hereunder from its system, the supplying Party shall be
compensated at a rate equal to the receiving Party's average actual fuel cost
of generation from the subject CAPCO Unit (in dollars per net MWh) during the
last fuel cycle prior to such CAPCO Unit being out of service calculated in
accordance with the operating agreement for such CAPCO Unit. If such CAPCO
Unit has not yet attained sufficient operating experience to establish such
average actual fuel cost of generation, then such average actual fuel cost of
generation shall be deemed to be the same as the most recent fuel cycle
experienced at any like CAPCO Unit at such CAPCO Unit site. It is understood
that no additional operating capacity payments are to be made other than as
included in the fuel cost (per net MWh) stated above.
3.2 If the receiving Party arranges such Replacement Capacity and
Replacement Energy from other than the supplying Party, the supplying Party
shall compensate the receiving Party an amount for any demand charge and
Out-of-Pocket Costs incurred by such receiving Party in the purchase of such
Replacement Capacity or Replacement Capacity and Replacement Energy in excess
of the average actual fuel cost provided for under Section 3.1 above.