HomeMy WebLinkAbout4.5 Original ContractI
STATE OF WASHINGTON
ss
County of Clallam
I, the undersigned City Clerk of the City of Port Angeles, Washington,
do hereby certify that the hereto attached
Minutes of the City Council Meeting of April 5, 1988.
is a true and correct copy of the document (s) indicated above.
WITNESS my hand and official seal this 20th day of April 1988
Aeitd&A Aecii
City Clerk of the City of Port Angeles,
Washington
Mr. Stuart Clarke
Assistant Area Power Manager
Bonneville Power Administration
Puget Sound Area Office
201 Queen Anne Avenue North
Seattle, WA 98109
Dear Stuart:
Please find enclosed three signed copies of Revision No. 1 to Exhibit H of
the City's power sales contract with the Bonneville Power Administration
(Contract No. DE- MS79- 81BP90450)
This revision adds a metering point to the Port Angeles Point of Delivery
at the City's Morse Creek Hydroelectric Project.
Thank you for your prompt attention.
Sincerely yours,
v h'
Robert E. Orton
Director
Enclosures
CITY OF PORT ANGELES
240 WEST FRONT ST P 0 BOX 1150 PORT ANGELES, WASHINGTON 98362
PHONE (206) 457 -0411
April 8, 1988
DAISHOWA 69 KV POINT OF DELIVERY:
power flows;
Exceptions:
POINTS OF DELIVERY
Revision No. 2
Exhibit I1, Page 1 of 3
Contract No. DE- MS79- 81BP90450
The City of Port Angeles
Effective at 2400 hours on the date of
execution of this Revision
This revision deletes the Crown Zellerbach 69 kV Point of Delivery and adds the Daishowa 69 kV Point of
Delivery effective at 2400 hours on February 15, 1988, to reflect the change in ownership of the paper
plant.
Location: the point in the Government's Port Angeles Substation where the 69 kV facilities of the
parties hereto are connected;
Voltage: 69 kV;
Metering: in the Government's Port Angeles Substation, in the .69 kVcircuit over which such electric
(a) the Purchaser and Bonneville agree and hereby ratify that the Daishowa 69 kV Point of
Delivery has been included as a point of delivery under this Agreement since 2400 hours on
February 15, 1988;
(b) charges for electric power and energy shall be computed by combining deliveries at the
Daishowa 69 kV, Port Angeles, and Rayonier Points of Delivery coincidentally pursuant to the
Combining Deliveries Coincidentally section of Exhibit B. The charge for diversity in
demands for electric energy at such points shall be $2,323 per month This charge shall be
subject to review and change not more often than once every three years.
2. PORT ANGELES POINT OF DELIVERY.
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Location: the point in Government's Port Angeles Substation where the 69 kV facilities of the parties
hereto are connected;
Voltaae: 69 kV;
Metering.
(a) in the Government's Port Angeles Substation, m the 69 kV circuit over which such electric
power flows;
(b) in the Purchaser's Morse Creek Hydroelectric Generation Plant, in the 0.48 kV circuit over
which such electric power flows;
Exceptions:
(a) the period of service for metering point (b) shall only be in effect when the Purchaser has a
contract for the transmission of the output from the Morse Creek Hydroelectric Generation
Plant;
(b) there shall be an adjustment for losses between the Point of Delivery and metering point (b),
and such adjustment shall be specified in correspondence transmitted between Bonneville and
the Purchaser;
(c) after adjustment for losses to metering point (b) as specified above, amount of electric power
delivered at the Port Angeles Point of Delivery shall be determined by subtracting amounts
measured at metering point (b) from Coincidental amounts measured at ineterittg point. (a);
(d) charges for electric power and energy shall be computed by combining deliveries at the
Daishowa 69 kV, Port Angeles, and Rayonier Points of Delivery coincidentally pursuant to the
Combining Deliveries Coincidentally section of Exhibit B. The charge for diversity in
demands for electric energy at such points shall be $2,323 per month. This charge shall be
subject to review and change not more often than once every three years;
(e)
the revenue meters at metering point (b) are owned by the Purchaser.
Revision No. 2
Exhibit H, Page 2 of 3
Contract No. DE- MS79 -81 BP90450
The City of Port Angeles
Effective at 2400 hours on the date of
execution of this Revision
3 RAYONIER POINT OF DELIVERY:
Location: the point in the Government's Port Angeles Substation where the 69 kV facilities of the
parties hereto are connected;
Voltage: 69 kV;
Metering: in the Government's Port Angeles Substation, in the 69 kV circuit over which such electric
power flows;
Exceptions charges for electric power and energy shall be computed by combining deliveries at the
Daishowa 69 kV, Port Angeles, and Rayomer Points of Delivery coincidentally pursuant to the
Combining Deliveries Coincidentally section of Exhibit B. The charge for diversity in demands for
electric energy at such points shall be $2,323 per month. This charge shall be subject to review and
change not more often than once every three years.
THE CITY OF PORT ANGELES
By &ied
Name P r J J. 7TTt1S
(Print/Type)
Title DIRECro'R OF CITY LIGHT
Date 4- //8
G:\MPSS \CLT\Contract\Exh H\TCPAE018 DOC
Revision No. 2
Exhibit H, Page 3 of 3
Contract No. DE- MS79 -81 BP90450
The City of Port Angeles
Effective at 2400 hours on the date of
execution of this Revision
UNITED STATES OF AMERICA
DEPARTMENT OF ENERGY
Bonneville Power Administration
Customer Account Executive
Name Tc r" 1 7SCe
A li Execution Date U`�oi- -`7 /y 77";.s
NONFIRM ENERGY SALES AGREEMENT
executed by the
UNITED STATES OF AMERICA
DEPARTMENT OF ENERGY
acting by and through the
BONNEVILLE POWER ADMINISTRATION
and
THE CITY OF PORT ANGELES. WASHINGTON
(Service to Consumer Alternate Fuel Loads)
Index to Sections
Contract No. DE- MS79- 85BP92138
6/11/85
Section Page
1. Term 3
2. Definitions 3
3. Exhibits 5
4. Level of Nonfirm Energy Service 5
5. Availability and Purchase of Nonfirm Energy and Surplus
Firm Energy 6
6. Notification 8
7. Metering 9
8. Payment 10
9. Firm Service 11
10. Mid -Term Review of Agreement 12
Section Page
11. Disclaimer 12
12. Right to Inspect and Access to Information 12
13. Termination of Prior Agreement 13
Exhibit A (Nonfirm Energy Rate Schedules) 5
Exhibit B (Surplus Firm Energy Rate Schedule) 5
Exhibit C (General Rate Schedule Provisions) 5
Exhibit D (General Contract Provisions) 5
Exhibit E (Alternate Fuel Loads to be Served, Point of Delivery,
Firm Power Service Levels, Maximum Nonfirm Service Levels,
and Transition Periods)
This AGREEMENT, executed 19, by the UNITED
STATES OF AMERICA, Department of Energy, acting by and through the BONNEVILLE
POWER ADMINISTRATION (Bonneville), and THE CITY OF PORT ANGELES, WASHINGTON
(Purchaser), a municipal corporation of the State of Washington,
W I T N E S S E T H:
WHEREAS the Purchaser has a firm requirements contract with Bonneville,
Bonneville Contract No. DE- MS79- 81BP90450 (Power Sales Contract); and
WHEREAS the Purchaser has certain consumer loads which can be served by
electric energy when electric energy is available at a rate which is
competitive with the cost of an alternate fuel, or by an alternate fuel; and
WHEREAS Bonneville may have nonfirm energy available from time to time
which can be used by Consumers for loads which are capable of being served by
electric energy and an alternate fuel; and
WHEREAS Bonneville desires to make more efficient use of electric energy
produced by the Federal Columbia River Power System (FCRPS); and
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WHEREAS Bonneville may determine that it has surplus firm energy available
to serve such Consumers' Alternate Fuel Loads for a limited Transition Period
while the consumer brings its Alternate Fuel Facility on line at the end of a
period of nonfirm energy availability; and
WHEREAS Bonneville may determine that it has surplus firm energy available
to serve a consumer's load during scheduled maintenance of or forced outage of
the Alternate Fuel Facili_ty;I
WHEREAS Bonneville is authorized by law to market electric power and energy
generated at various Federal hydroelectric projects in the Region or acquired
from other resources, to construct and operate transmission facilities, to
provide transmission and other services, and to enter into agreements to carry
out such authority; and
NOW, THEREFORE, the parties hereto mutually agree as follows:
1. Term.
(a) Upon execution by both parties, this Agreement shall be effective as
of 2400 hours on June 30, 1985, and shall expire at 2400 hours on June 30, 1989.
(b) Upon expiration or termination of this Agreement, all liabilities
accrued hereunder shall be preserved until satisifed.
2. Definitions.
(a) "Alternate Fuel Capability" means the electric demand and energy
levels required to serve the Alternate Fuel Load at a level equivalent to the
capability of the load's Alternate Fuel Facilities.
(b) "Alternate Fuel Facility" means an on —site energy source(s) capable of
serving and available to serve the Alternate Fuel Load.
(c) "Alternate Fuel Load(s)" means each electric load listed in Exhibit E
which constitutes that portion of each Consumer's load which is eligible for
service with electric energy pursuant to this Agreement.
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(d) "Consumer(s)" means the consumer(s) listed in Exhibit E who will
receive nonfirm energy service which Bonneville makes available to the
Purchaser as a result of this Agreement.
(e) "Firm Power Service Levels" means that portion of an Alternate Fuel
Load, if any, which is served by firm power. The Firm Power Service Level is
comprised of a demand and an energy component, referred to respectively in
this Agreement as "Firm Power Demand Level" and a "Firm Power Energy Level."
These levels shall be specified in Exhibit E for each Alternate Fuel Load.
(f) "Maximum Nonfirm Service Level" means the maximum amount of nonfirm
energy which Bonneville will make available to the Purchaser for service to an
Alternate Fuel Load. The Maximum Nonfirm Service Level includes a demand and
an energy component which are referred to respectively as the Maximum Nonfirm
Demand Level and a Maximum Nonfirm Energy Level. The Maximum Nonfirm Energy
Level and Maximum Nonfirm Demand Level for each Alternate Fuel Load shall be
the energy and demand levels for the Consumer's)' electrical facilities that
are equivalent to the historical operation during a representative month and
maximum capability, respectively, of the Alternate Fuel Facilities and which
are in excess of the Firm Power Service Levels. These levels shall be
specified in Exhibit E for each Alternate Fuel Load.
(g) "Point of Delivery" means the point(s) of delivery specified in
Exhibit E to which nonfirm energy will be delivered to the Purchaser by
Bonneville to serve an Alternate Fuel Load.
(h) "Point of Metering" means the metering point at the Alternate Fuel
Load.
(i) "Transition Period" means the period required to bring the Consumer's
Alternate Fuel Facility up to a level sufficient to carry the load when
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nonfirm electric energy is restricted. This period shall be defined for each
Consumer in Exhibit E and shall in no case exceed 72 hours.
3. Exhibits. Exhibit A (Bonneville's Wholesale Nonfirm Energy Rate
Schedule), Exhibit B (Bonneville's Surplus Firm Energy Rate Schedule),
Exhibit C (General Rate Schedule Provisions), Exhibit D (General Contract
Provisions [GCP Form PSC -1, as amended]), and Exhibit E (Alternate Fuel
Load(s) to be Served, and associated Point of Delivery, Firm Power Service
Levels, Maximum Nonfirm Service Levels, and Transition Period), are by this
reference incorporated and made a part of this Agreement.
4. Level of Nonfirm Energy Service.
(a) Nonfirm energy service shall be made available in accordance with
section 5 for each Alternate Fuel Load in amounts up to the Maximum Nonfirm
Service Levels.
(b) Bonneville shall issue a revised Exhibit E to reflect a change in the
Maximum Nonfirm Service Level to an Alternate Fuel Load if:
(1) the Purchaser requests an increase in such level and Bonneville
determines that the Alternate Fuel Capability has increased, or
(2) Bonneville determines that the Alternate Fuel Capability has
decreased, or
(3) the Purchaser requests a decrease in such level and a
corresponding increase in the Firm Power Service Level, and Bonneville
agrees to such an increase.
5. Availability and Purchase of Nonfirm Energy and Surplus Firm Energy.
(a) If Bonneville determines that it has nonfirm energy available for
service to Alternate Fuel Loads subject to subsection (e) below, Bonneville
shall notify the Purchaser pursuant to section 6, Notification. Bonneville
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will then make nonfirm energy available for delivery to the Purchaser at the
Purchaser's request for service to Alternate Fuel Load(s).
(b) The Purchaser shall pay for such nonfirm energy which Bonneville has
delivered for service to the Alternate Fuel Load in accordance with section 8,
Payment.
(c) When a Purchaser is notified by Bonneville that nonfirm energy will
be restricted, a Purchaser may request surplus firm energy for service to the
Alternate Fuel Load during the Transition Period. If Bonneville determines
that it has surplus firm energy available, Bonneville shall inform the
Purchaser of the duration and amount of available surplus firm energy. If the
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Purchaser then agrees to purchase the surplus firm energy which Bonneville has
offered, Bonneville shal,.l make such surplus firm energy available to the
Purchaser for service to the Alternate Fuel Load during. _the _Transition Period
and the Purchaser shall purchase such surplus firm energy./
(d) When one of the following occurs, the Purchaser shall use its best
efforts to insure that the Consumer interrupts electric energy service to
Alternate Fuel Load. provided by Bonneville through the Purchaser as soon as is
practicable:
(1) nonfirm energy is no longer available and surplus firm energy is
not available for the Transition Period; or
(2) the termination of a Transition Period during which Bonneville
has provided the Purchaser with surplus firm energy; or
(3) Bonneville is not brokering or ends a period of brokering energy
from other suppliers, and does not have availability of nonfirm energy or
surplus firm energy; or
(4) the Purchaser is not serving the Alternate Fuel Load with its
own nonfirm energy.
At such time, the Purchaser shall allow the Consumer(s) to switch to
another energy source and shall inform Bonneville as soon as is practicable
that the Consumer(s) is no longer taking electric energy provided by
Bonneville to serve the Alternate Fuel Load(s).
(e) The Purchaser acknowledges that Bonneville does not guarantee that
Bonneville has or will have nonfirm energy for delivery to the Purchaser at
any time for service to the Alternate Fuel Load(s), or surplus firm energy
available for service during the Transition Period. The determination made by
Bonneville at any time of the amount of nonfirm energy or surplus firm energy
available for delivery on each hour and at each rate shall be final and
conclusive.
(f) A Purchaser may request, in advance of need, surplus firm energy_for
service to an Alternate Fuel Load during scheduled maintenance of an Alternate
Fuel Facility. If Bonneville determines that it has surplus firm energy
available and that it has sufficient generating capability to meet such load,
Bonneville shall inform the Purchaser as soon as is practicable of the
availability of such energy. If the Purchaser then agrees to the amount and
duration of surplus firm energy offered by Bonneville, Bonneville shall make
such amount available to the Purchaser for service to the Alternate Fuel Load
during the scheduled maintenance of the Alternate Fuel Facility and Purchaser
shall purchase such energy.
(g) A Purchaser may request surplus firm energy for service to the
Alternate Fuel Load during a temporary forced outage of the Alternate Fuel
Facility. If Bonneville determines that it has or had surplus firm energy
available and that it has or had sufficient generating capability to serve
such load, Bonneville shall make or deem to have made surplus firm energy
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available to the Purchaser for service to the Alternate Fuel Load during a
forced outage of the Alternate Fuel Facility.
(h) At the end of any period when Bonneville makes surplus firm energy
available for scheduled maintenance or forced outages, the Purchaser shall use
its best efforts to insure that the Consumer interruptselectric energy
service to the Alternate Fuel Load(s) which is provided by Bonneville through
the Purchaser._ The Purchaser shall allow the Consumer to switch to another
energy source and shall inform Bonneville as soon as is practicable that the
Consumer(s) is no longer taking electric energy provided by Bonneville to
serve the Alternate Fuel Load(s).
6. Notification.
(a) Bonneville shall notify the Purchaser of the projected availability
of nonfirm energy, including projected price, projected amount, and of
projected duration. Bonneville shall make maximum practicable efforts to give
the Purchaser notice of any change in price, amount, or duration of
availability of nonfirm energy, but expressly reserves the right to change the
price, amount, or duration of availability, or to terminate availability, at
the end of any hour.
(b) Bonneville shall notify the Purchaser of availability of surplus firm
energy at the end of any period of availability of nonfirm energy.
(c) For Purchasers without automatic generation control, unless otherwise
agreed, during any period of availability of nonfirm energy, the Purchaser
shall notify Bonneville by 1200 hours of each workday of the estimated usage
of nonfirm energy or surplus firm energy for the following day(s) through the
next workday, and of the actual use for the previous day(s).
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For Purchasers with automatic generation control, during any such period
of availability, the Purchaser shall schedule nonfirm energy or surplus firm
energy pursuant to the applicable provisions of its Power Sales Contract.
(d) Prior to implementation by Bonneville of the system described in
subsection (e) below, Bonneville shall provide notifications required above by
telephoning the Purchaser at (206) 457 -0411, extension 183 (day) or
(206) 452 -4545 (alternate or night).
(e) Bonneville intends to implement a computer- initiated dial -up system
for transmitting notification to the Purchaser required by this Agreement.
Upon 4 months' written notice from Bonneville, the Purchaser shall provide, at
no expense to Bonneville, a hard copy terminal equipped with an auto answer
modem (300 baud, Bell 103 compatible) connected to a dedicated telephone
line. The Consumer(s) may install similar equipment, at no expense to
Bonneville.
(f) Notification procedures for sale of surplus firm energy used during
scheduled maintenance and forced outage shall be in accordance with
section 5(f) and 5(g) respectively.
7. Metering.
(a) The Purchaser shall insure that a kilowatthour meter and an hourly
recording demand meter are provided at the Alternate Fuel Load without expense
to Bonneville. (Bonneville may require the Purchaser to install, at no
expense to Bonneville, a varhour meter at the Point of Metering when operating
or planning conditions necessitate such a meter in Bonneville's
determination.) Such meters, design of meter installation, and meter
installations must be approved by Bonneville for billing accuracy and
compatibility with Bonneville's remote reading equipment.
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(b) Demand and energy loss factors between the Point of Metering and the
Point of Delivery sha as agreed to by the parties in writing.
(c) The Purchaser shall read meters at each Point of Metering each month
when meters are read at the Point of Delivery and shall immediately furnish
Bonneville with the reading, until such time as remote metering equipment is
installed at the Point of Delivery and the corresponding Point of Metering.
(d) The Purchaser shall insure that a Bonneville approved remote metering
device is installed at the Point of Metering when remote metering devices are
installed at the Point of Delivery, without expense to Bonneville, unless
otherwise agreed to by the parties.
8. Payment.
(a) (1) The amount of nonfirm energy delivered to the Purchaser for an
Alternate Fuel Load during a billing month shall be the difference
(adjusted for losses between the Point of Delivery and the Point of
Metering) between the Firm Power Energy Level specified in Exhibit E and
the total energy recorded at the Point of Metering up to the Maximum
Nonfirm Service Levels, excluding any surplus firm energy delivered by
Bonneville, any energy brokered by Bonneville from other suppliers, and
any of the Purchaser's own nonfirm energy served to the Alternate Fuel
Load. The applicable rate specified in Exhibit A (Bonneville's Nonfirm
Energy Rate Schedule) shall apply to the purchase of the amounts of
nonfirm energy described above.
(2) Any energy taken by the Purchaser for the Alternate Fuel Load in
excess of amounts of nonfirm energy determined above, surplus firm energy
made available by Bonneville, energy brokered by Bonneville from other
suppliers, and the Purchaser's own nonfirm energy served to the Alternate
Fuel Load shall be considered an unauthorized increase and subject to
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vyl4 .4
unauthorized increase charges. Energy associated with demand taken in
excess of the Maximum Nonfirm Demand Level shall be considered an
unauthorized increase and subject to an unauthorized increase charge.
(3) For purposes of Bonneville's firm demand billing to the
Purchaser, Bonneville shall subtract from the Purchaser's measured demand
at the Point of Delivery the difference (adjusted for losses between the
Point of Delivery and the Point of Metering) between the Firm Power Demand
Level specified in Exhibit E and the integrated hourly demand associated
with deliveries of nonfirm energy, surplus firm energy, energy brokered by
Bonneville from other suppliers, and the Purchaser's own nonfirm energy
served to the Alternate Fuel Load at the Point of Metering measured
coincidentally with the Purchaser's hour of peak firm power billing demand.
(b) The Purchaser shall pay for the amount of surplus firm energy_ z.--
requested by the Purchaser and made_available by__Bonneville regardless of
actual metered amounts The Surplus Firm Energy Rate Schedule, attached as
Exhibit B, shall apply to any such amounts.
9. Firm Service.
(a) The Purchaser shall not provide firm service during the term of this
Agreement to the Alternate Fuel Loads in excess of the Firm Power Service
Levels specified in Exhibit E without written approval from Bonneville.
Availability of firm service to Alternate Fuel Loads on the expiration of this
Agreement shall be in accordance with sections 8 and 9 of the Power Sales
Contract; provided, however, that such service shall be on not less than
2 years' written notice Bonneville, unless otherwise agreed.
(b) Bonneville agrees that no Purchaser or Consumer receiving nonfirm
service pursuant to this Agreement shall, by receiving such service, forfeit
any rights it may have under sections 3(13) and 7(b) of Public Law 96 -501;
11 7 1`«`16
provided, however, that firm service to any load specified in Exhibit E shall
be subject to subsection (a) above.
10. Mid -Term Review of Agreement. At the end of the second and third
years of this Agreement, Bonneville and the Purchaser shall review their
expectations regarding their ability and intent to negotiate future agreements
for nonfirm energy service to Alternate Fuel Loads.
11. Disclaimer.
(a) Except as specifically provided herein, nothing in this Agreement
shall constitute a waiver, modification of, amendment to, or otherwise affect
any rights or obligations of the parties to the Power Sales Contract.
(b) The Purchaser covenants that all loads being served under this
Agreement are truly nonfirm in nature; that is, discontinuance of nonfirm
energy deliveries as provided in sections 5 and 6 of this Agreement will not
cause undue hardship for the Purchaser, Consumer(s), or otherwise in the
Purchaser's service area. The Purchaser also accepts full responsibility for
any hardship that may occur.
12. Right to Inspect and Access to Information.
(a) The Purchaser shall obtain in its contract with its Consumer(s) the
right for Bonneville (1) to inspect the electric facilities and Alternate Fuel
Facilities of the Consumer(s), (2) to obtain reasonable information related to
current and historical operation of each Alternate Fuel Load, and (3) to
obtain information documenting the decremental cost of the Alternate Fuel
Facility. The Purchaser's contract with its Consumers shall also require such
consumers to notify the Purchaser and Bonneville of any reduction in Alternate
Fuel Capability.
(b) The Purchaser shall obtain and supply to Bonneville up -to -date
information concerning the decremental cost of each Alternate Fuel Load from
time to time or at the request of Bonneville.
13. Termination of Prior Agreement. Upon execution of this Agreement,
the prior agreement with the Purchaser for sale of nonfirm energy for service
to its Consumers Alternate Fuel Loads, Contract No. DE- MS79- 84BP91683, is
hereby terminated. All liabilities accrued under such prior agreement shall
be preserved until satisfied.
IN WITNESS WHEREOF, the parties hereto have executed this Agreement.
UNITED STATES OF AMERICA
Department of Energy
ATTEST:
By All; a_
Title e;i71,1 eiae,)-4
Date
S7/ /,?`5
(WP- PKL- 2739c)
By
Bonneville Powef Administrator
THE CITY OF PORT ANGELES, WASHINGTON
By
13
Title C' 6LA./
Date Ci At u41 A9 I q R5
l
consumer
1/ The points of delivery are described in Exhibit H of the Power Sales Contract.
2/ ThePurchaser is billed on a coincidental basis.
(WP— PKL- 2739c)
NONFIRM LOADS TO BE SERVED
Exhibit E
Contract No. DE— MS79- 85BP92138
The City of Port Angeles
Firm Service Maximum Nonfirm
Alternate Point of Level Service Level Transition
Fuel Loa,_ Delivery 1/ Demand Average Eneray Demand Averaae Energy Period
MW MW MW MW (Hours)
Crown The 7 MW electric Crown 0 0 7.2 7.2 72
Zellerbach boiler at the paper Zellerbach 2/
Corporation processing plant
SECTION I. AVAILABILITY
This schedule is available for the purchase of nonfirm energy to be used both
inside and outside the United States. This schedule also applies to energy
delivered for emergency use under the conditions set forth in section V.A. of
the General Rate Schedule Provisions (GRSPs). This rate schedule is not
available (1) for the purchase of energy that BPA has a firm obligation to
supply, except to the extent that short -term guarantees are agreed to, or (2)
for the purchase of energy under contracts for which rates have been
negotiated pursuant to section 7(1) of the Pacific Northwest Electric Power
Planning and Conservation Act (Northwest Power Act). For purchasers who have
executed a contract with BPA specifying the SS -85 Share the Savings Schedule,
the NF -85 Rate Schedule is not available to displace resources and alternate
purchases with Decremental Cost greater than or equal to 13.0 mills per
kilowatthour, or to displace alternate fuel sources with Decremental Cost
greater than or equal to 15.0 mills per kilowatthour. The offer of Nonfirm
Energy under this rate schedule shall be determined by BPA. This rate
schedule supersedes Schedule NF -83 which went into effect on an interim basis
on November 1, 1983.
SECTION II. RATES
A. Standard Rate
The Standard rate is 22.2 mills per kilowatthour of billing energy.
B. High Cost Displacement Rate
The High Cost Displacement rate is 12.8 mills per kilowatthour of
billing energy.
C. Low Cost Displacement Rate
SCHEDULE NF -85
NONFIRM ENERGY RATE
EXHIBIT A
The Low Cost Displacement rate depends upon the type of resource
being displaced and is:
1. 7.0 mills per kilowatthour of billing energy for displacement of
coal -fired resources, resources that may be displaced
indirectly, and end -user alternate fuel sources; and
2. 3.0 mills per kilowatthour of billing energy for displacement of
nuclear resources.
D. Incremental Rate
The Incremental rate is the Incremental Cost of energy plus 2.0 mills
per kilowatthour, where the Incremental Cost is defined as all
SECTION I. AVAILABILITY
SCHEDULE NF -85
NONFIRM ENERGY RATE
This schedule is available for the purchase of nonfirm energy to be used both
inside and outside the United States. This schedule also applies to energy
delivered for emergency use under the conditions set forth in section V.A. of
the General Rate Schedule Provisions (GRSPs). This rate schedule is not
available (1) for the purchase of energy that BPA has a firm obligation to
supply, except to the extent that short -term guarantees are agreed to, or (2)
for the purchase of energy under contracts for which rates have been
negotiated pursuant to section 7(1) of the Pacific Northwest Electric Power
Planning and Conservation Act (Northwest Power Act). For purchasers who have
executed a contract with BPA specifying the SS -85 Share the Savings Schedule,
the NF -85 Rate Schedule is not available to displace resources and alternate
purchases with Decremental Cost greater than or equal to 13.0 mills per
kilowatthour, or to displace alternate fuel sources with Decremental Cost
greater than or equal to 15.0 mills per kilowatthour. The offer of Nonfirm
Energy under this rate schedule shall be determined by BPA. This rate
schedule supersedes Schedule NF -83 which went into effect on an interim basis
on November 1, 1983.
SECTION II. RATES
A. Standard Rate
The Standard rate is 22.2 mills per kilowatthour of billing energy.
B. High Cost Displacement Rate
The High Cost Displacement rate is 12.8 mills per kilowatthour of
billing energy.
C. Low Cost Displacement Rate
The Low Cost Displacement rate depends upon the type of resource
being displaced and is:
1. 7.0 mills per kilowatthour of billing energy for displacement of
coal -fired resources, resources that may be displaced
indirectly, and end -user alternate fuel sources; and
2. 3.0 mills per kilowatthour of billing energy for displacement of
nuclear resources.
D. Incremental Rate
The Incremental rate is the Incremental Cost of energy plus 2.0 mills
per kilowatthour, where the Incremental Cost is defined as all
identifiable costs (expressed in mills per kilowatthour) that BPA
would have avoided had it not produced or purchased the energy being
sold under this rate.
E. Contract Rate
The Contract rate is 18.1 mills per kilowatthour of billing energy.
SECTION III. ADJUSTMENTS TO RATES
A. Guaranteed Delivery Surcharge
1. A surcharge of 2.0 mills per kilowatthour of billing energy is
applied to guaranteed delivery of Nonfirm Energy under the
Standard Rate, the High Cost Displacement Rate, and the Low Cost
Displacement Rate as specified in section II.C.1. of this rate
schedule.
2. No surcharge shall be applied to guaranteed delivery of Nonfirm
Energy at the Low Cost Displacement Rate as specified in section
II.C.2. of this rate schedule.
B. Intertie Service
All rates specified shall be increased by 1.2 mills per kilowatthour
for Nonfirm Energy scheduled for delivery over the Pacific
Northwest- Pacific Southwest Intertie.
SECTION IV. BILLING FACTORS
The billing energy for Nonfirm Energy purchased under this rate schedule shall
be the Measured Energy unless otherwise specified by contract.
SECTION V. APPLICATION AND ELIGIBILITY
Any time that BPA has Nonfirm Energy for sale, the Standard Rate, the High
Cost Displacement Rate, the Low Cost Displacement Rate, the Incremental Rate,
the Contract Rate, or a combination of these rates may be in effect. BPA is
not obligated to offer nonfirm energy at any of these rates in a manner that
displaces purchases under BPA firm power contracts.
A. Standard Rate
The Standard rate is:
1. available for all purchases of Nonfirm Energy; and
2. applies to Nonfirm Energy purchased pursuant to the Relief from
Overrun Exhibit to the power sales contract.
B. High Cost Displacement Rate
1. The High Cost Displacement Rate applies:
a. when all markets at the Standard Rate have been satisfied
and BPA offers additional energy; or
b. when BPA, in order to clear its market for Nonfirm Energy,
offers the High Cost Displacement Rate in lieu of the
Standard Rate.
2. When both the Standard Rate and the High Cost Displacement Rate
are in effect, in order to be eligible for the High Cost
Displacement Rate, purchasers must identify:
a. a displaceable resource, displaceable purchase of
electricity, or a resource that may be displaced indirectly
with Decremental Costs lower than 24.2 (25.4 in the Pacific
Southwest) mills per kilowatthour; or
b. an end -user load having an alternate fuel source with
Decremental Costs lower than 26.2 mills per kilowatthour.
Such alternate fuel source may not be a displaceable
purchase of electricity.
3. When both the Standard Rate and the High Cost Displacement Rate
are in effect, in order to be eligible to purchase energy under
the High Cost Displacement Rate, in addition to the eligibility
criteria specified in V.B.Z., purchasers must demonstrate one of
the following:
a. shut down or reduction of the output of the displaceable
resource in an amount equal to the amount of High Cost
Displacement Rate energy purchased; or
b. reduction of a displaceable purchase and the resource
associated with that purchase, in an amount equal to the
amount of High Cost Displacement Rate energy purchased; or
c. shut down or reduction of the identified resource(s)
indirectly in an amount equal to the amount of High Cost
Displacement Rate energy purchased. For example, the
purchase may be used to run a pumped storage unit; or
d. that an end -user alternate fuel source is reduced in an
amount equivalent to the amount of High Cost Displacement
Rate energy purchased.
C. Low Cost Displacement Rate
1. The Low Cost Displacement rate applies:
a. if both the Standard Rate and the High Cost Displacement
Rates are in effect, when all markets at those two rates
have been satisfied; or
b. if only the High Cost Displacement Rate is in effect, when
all markets at that rate are satisfied.
2. In order to be eligible for the Low Cost Displacement Rate,
purchasers must:
a. identify either:
(1) a displaceable resource, displaceable purchase of
electricity, or a resource that may be displaced
indirectly with Decremental Costs lower than 14.8
(16.0 in the Pacific Southwest) mills per
kilowatthour; or
(2) an end —user load having an alternate fuel source with
Decremental Costs lower than 16.8 mills per
kilowatthour. Such alternate fuel source may not be a
displaceable purchase of electricity; and
b. demonstrate one of the following:
D. Incremental Rate
(1) shut down or reduction of the output of the
displaceable resource in an amount equal to the amount
of Low Cost Displacement Rate energy purchased; or
(2) reduction of a displaceable purchase and the resource
associated with that purchase in an amount equal to
the amount of Low Cost Displacement Rate energy
purchased; or
(3) reduction of the identified resource(s) indirectly in
an amount equal to the amount of Low Cost Displacement
Rate energy purchased. For example, the purchase may
be used to run a pumped storage unit; or
(4) that an end —user alternate fuel source is reduced in
an amount equivalent to the amount of Low Cost
Displacement Rate energy purchased.
The Incremental rate applies to sales of energy:
1. that is produced or purchased by BPA concurrently with the
nonfirm energy sale;
2. that BPA may at its option not produce or purchase; and
3. that has an Incremental Cost greater than the Standard Rate
(plus the Intertie Adder, if applicable) less 2.0 mills per
kilowatthour.
E Contract Rate
The Contract Rate applies to contracts (except power sales contracts
offered pursuant to sections 5(b), 5(c), and 5(g) of the Northwest
Power Act power) that refer to the Contract Rate:
1. for the sale of Nonfirm Energy; or
2. for determining the value of energy.
SECTION VI. DELIVERY
A. Rate of Delivery
BPA shall determine the amount of Nonfirm Energy to be made available
for each hour. Such determination shall be made for each applicable
Nonfirm Energy rate.
B. Guaranteed Delivery
1. Availability
BPA will indicate on Tuesday the amounts of Nonfirm Energy
available for delivery on a guaranteed basis for the following
Thursday through Saturday, on Thursday for the following Sunday
through Wednesday, or on other days if BPA determines that such
offers are appropriate. Such daily or hourly amounts may be as
small as zero or as much as all the nonfirm energy that BPA
plans to offer for sale on such days.
2. Conditions
Scheduled amounts of guaranteed Nonfirm Energy may not be
changed except:
a. when BPA and the purchaser mutually agree to increase or
decrease the scheduled amounts; or
b. when BPA must reduce Nonfirm Energy deliveries in order to
serve firm loads because of unexpected generation loss, or
because of unexpected transmission loss.
SECTION VII. RESOURCE COST CONTRIBUTION
Pursuant to section 7(j) of the Northwest Power Act, BPA has made the
following determinations:
A. The approximate cost contribution of different resource categories to
the NF -85 Standard rate is 57.6 percent FBS, 0.2 percent New
Resources, and 42.2 percent Exchange.
B. The forecasted average cost of resources available to BPA under
average water conditions is 17.6 mills per kilowatthour.
C. The forecasted cost of resources to meet load growth is 33.0 mills
per kilowatthour.
SECTION VIII. GENERAL PROVISIONS
Sales of energy under this schedule shall be subject to the General Rate
Schedule Provisions and the following Acts, as amended: Bonneville Project
Act, the Flood Control Act of 1944, the Regional Preference Act
(Pub. L. 88 -552), the Federal Columbia River Transmission System Act, and the
Northwest Power Planning Act.
SECTION I. AVAILABILITY
SCHEDULE SE -85
SURPLUS FIRM ENERGY RATE
This schedule is available for the purchase of Surplus Firm Energy to be used
either for resale or direct consumption. Surplus Firm Energy may be sold to
entities inside and outside the Pacific Northwest as well as outside the
United States. This rate schedule shall not apply to contracts for which
rates have been negotiated pursuant to section 7(1) of the Northwest Power
Act. In addition, this schedule is not available to any DSI purchaser who
buys power either under Schedule IP -85 or Schedule SI -85. Schedule SE -85
supersedes Schedule SE -83 which went into effect on an interim basis on
November 1, 1983.
SECTION II. RATE
A. 28.7 mills per kilowatthour of billing energy. The contract may
specify a lower charge.
B. Intertie Service
The SE rate shall be increased by 1.2 mills per kilowatthour of
billing energy for delivery of surplus firm energy over the Pacific
Northwest- Pacific Southwest Intertie.
SECTION III. BILLING FACTORS
The billing energy shall be the Measured Energy, unless otherwise specified in
the contract.
SECTION IV. ADJUSTMENTS AND SPECIAL PROVISIONS
A. Escalation Factor
Schedule SE -85 shall be subject to change each October 1, beginning
October 1, 1987, for all contracts that extend beyond September 30,
1987. The change in the SE -85 rate shall be determined according to
one of the two formulas below. The applicable formula shall be
contractually specified.
1. Rate Rate (1 INCn_i)
where:
,XHIBIT B
Rate the rate in the fiscal year (October 1 through
September 30) for which the SE -85 rate is being
calculated;
Rate
INCn_i
2. Rate Rate 1.076
where:
the SE -85 rate in the previous year (year n -1);
the weighted average increase in the cost of
exchange resources in year n -1 as calculated on
October 1 in year n. The average cost of
exchange resources shall be based on the average
system costs of exchanging investor -owned
utilities (IOUs). If any of the IOUs equalizes
rates in year n -1 pursuant to section 10 of the
Residential Purchase and Sale Agreement, the
calculation of INC shall not reflect the average
system cost of such utility.
Rate the rate in the fiscal year (October 1
September 30) for which the SE -85 rate is being
calculated; and
Rate the SE -85 rate in the previous year (year n -1).
B. Power Factor Adjustment
The adjustment for power factor for BPA customers that are billed for
surplus firm power on metered amounts, when specified in this rate
schedule or in the power sales contract, shall be made in accordance
with the provisions of both this section and section III.C.1 of the
GRSPs. The adjustment shall be made if the average leading power
factor or average lagging power factor at which energy is supplied
during the billing month is less than 95 percent.
To make the power factor adjustment, BPA shall increase the billing
energy by one percentage point for each percentage point or major
fraction thereof (0.5 or greater) by which the average leading power
factor or average lagging power factor is below 95 percent. BPA may
elect to waive the adjustment for power factor in whole or in part.
SECTION V. RESOURCE COST CONTRIBUTION:
In compliance with section 7(j) of the Northwest Power Act, BPA has made the
following determinations:
A. The approximate cost contribution of different resource categories to
the SE -85 rate is 99.2 percent Exchange and 0.8 percent New Resources.
-r
B. The forecasted average cost of resources available to BPA under
average water conditions is 17.6 mills per kilowatthour.
C. The forecasted cost of resources to meet load growth is 33.0 mills
per kilowatthour.
SECTION VI. GENERAL PROVISIONS
Sales of power under this schedule shall be subject to the GRSPs and the
following acts, as amended: the Bonneville Project Act, the Regional
Preference Act (Pub. L. 88 -552), the Federal Columbia River Transmission
System Act, and the Northwest Power Act.
A. Approval of Rates
B. General Provisions
GENERAL RATE SCHEDULE PROVISIONS
SECTION I. ADOPTION OF REVISED RATE SCHEDULES AND GENERAL RATE SCHEDULE
PROVISIONS
These rate schedules and General Rate Schedule Provisions (GRSPs)
shall become effective following confirmation and approval by the
Federal Energy Regulatory Commission (FERC). If the rates and GRSPs
are first approved on an interim basis, they shall not be considered
final until the FERC has issued an order confirming and approving
them on a final basis. BPA is requesting FERC approval for these
rates to be effective from July 1 1985 through June 30 1990.
BPA's Wholesale Power Rate Schedules and associated GRSPs that are
effective July 1, 1985, supersede in their entirety BPA's Wholesale
Power Rate Schedules and GRSPs effective November 1, 1983. The
revised schedules and provisions shall be applicable to every BPA
contract, including contracts executed prior to and subsequent to
enactment of the Pacific Northwest Electric Power Planning and
Conservation Act (Northwest Power Act).
C. Reorganization of the Wholesale Power Rate Schedules and General
Rate Schedule Provisions (GRSPs)
1. Reorganization of the Wholesale Power Rate Schedules
All references in the industrial power sales contract to
section 4 of the rate schedules for Industrial Firm Power shall
be deemed to refer to the section in such schedules entitled
"Billing Factors."
2. Reorganization of the General Rate Schedule Provisions (GRSPs)
A major restructuring of the GRSPs took place effective with
BPA's 1983 wholesale power rates. Contractual and other
references to sections in GRSPs associated with earlier BPA
rates were deemed to be changed to the new organization and
numbering system as of November 1, 1983, when the 1983 rates
were adopted. Those changes are not reiterated herein. Only
those changes effective with these new GRSPs are indicated in
the table below.
References to sections in those GRSPs that were in effect
between November 1, 1983, and July 1, 1985, are deemed to refer
to the section in these revised GRSPs indicated in the listing
below.
Title
Old GRSPs
Section
New GRSPs
Section
Priority Firm Power II.A II.A
New Resource Firm Power II.B II.B
Industrial Firm Power II.0 II.0
Special Industrial Power N/A II.D
Auxiliary Power II.D II.E
Firm Capacity II.E II.F
Surplus Firm Power II.F II.G
Surplus Firm Energy II.G II.H
Nonfirm Energy II.H II.I
Share the Savings Energy N/A II.J
Energy Broker Energy II.I II.K
Reserve Power II.J II.L
Measured Demand III.A.1 III.A.1
Ratchet Demand N/A III.A.2
Contract Demand III.A.2 III.A.3
Computed Peak Requirement III.A.3 III.A.4
Computed Average Energy Requirement III.A.4 III.A.5
Operating Demand III.A.6 III.A.6
Curtailed Demand III.A.7 III.A.7
Restricted Demand III.A.8 III.A.8
Auxiliary Demand III.A.9 III.A.9
BPA Operating Level N/A III.A.10
Committed Demand III.A.10 III.A.11
Measured Energy III.B.1 III.B.1
Computed Energy Maximum III.B.2 III.B.2
Committed Energy III.8.3 III.B.3
Contract Energy N/A III.8.4
Power Factor Adjustment III.C.1 III.C.1
Outage Adjustment N/A III.C.2
Low Density Discount N/A III.C.3
Irrigation Discount N/A III.C.4
Coincidental Billing Adjustment VI.A III.C.5
Exchange Adjustment Clause III.C.2 III.C.6
Supply System Adjustment Clause III.C.3 III.C.7
Conservation Charge III.C.4 N/A
Peak Period N/A III.D.1
Offpeak Period N/A III.D.2
Computed Requirements Purchasers IV.B IV.B
Definitions Relating to the Nonfirm Energy Rate(NF -85) N/A IV.C.
Application of Rates Under Special Circumstances V. V.
Changes in a DSI's BPA Operating Level N/A V.D
Application of the Industrial Incentive Rate V.D V.E
Restriction of Deliveries IV.A. V.F.
Determination of Estimated Billing Data VI.B VI.A
Load Shift and Outage Reports N/A VI.B
Billing for New Large Single Loads N/A VI.0
Determination of Measured Demand N/A VI.D
Determination of Measured Energy N/A VI.E
Title
Billing Month VI.0 VI.F
Payment of Bills VI.D VI.G
Computation of Bills VI.D VI.G.1
Estimated Bills VI.D VI.G.2
Due Date VI.D VI.G.3
Late Payment VI.D VI.G.4
Disputed Billings VI.D VI.G.5
Revised Bills N/A VI.G.6
SECTION II. TYPES OF BPA SERVICE
A. Priority Firm Power
Old GRSPs New GRSPs
Section Section
Priority Firm Power is electric power (capacity, or capacity and
energy) that BPA will make continuously available for resale to
ultimate consumers, direct consumption, construction, test and
start -up, and station service by public bodies, cooperatives, and
Federal agencies. (Construction, test and start -up, and station
service are defined in section V.B of these GRSPs.)
Utilities participating in the exchange under section 5(c) of the
Pacific Northwest Electric Power Planning and Conservation Act
(Northwest Power Act) may purchase Priority Firm Power pursuant to
their Residential Purchase and Sale Agreements.
In addition, BPA may make Priority Firm Power available to those
parties participating in exchange agreements specifying use of the
Priority Firm rate for determining the amount or value of power to be
exchanged.
Power purchased under the Priority Firm Power Rate Schedule is to be
used to meet the purchaser's actual firm load within the Pacific
Northwest. Such power may be restricted in accordance with the
Restriction of Deliveries section of these GRSPs (section IV.A).
However, BPA shall not restrict Priority Firm Power until Industrial
Firm Power has been restricted in accordance with the provisions of
section II.0 of these GRSPs.
Any increase in energy consumption of a load as defined in:
1. section 3.(13) of the Northwest Power Act, or
2. section 8 of any BPA utility power sales contract executed after
December 5, 1980,
shall be considered New Resource Firm Power and shall be served under
the New Resource Firm Power Rate.
B. New Resource Firm Power
New Resource Firm Power is electric power (capacity, or capacity and
energy) that BPA will make continuously available:
1. for any new large single load as defined in section 3.(13) of
the Northwest Power Act and as described in section 8 of any BPA
utility power sales contract executed after December 5, 1980,
2. for firm power purchased by investor -owned utilities pursuant to
power sales contracts with BPA, and /or
3. for construction, test and start -up, and station service for
facilities owned and /or operated by investor -owned utilities.
New Resource Firm Power is to be used to meet the purchaser's actual
firm load within the Pacific Northwest. Such power may be restricted
in accordance with the Restriction of Deliveries section of these
GRSPs (section V.F.). However, BPA shall not restrict New Resource
Firm Power until Industrial Firm Power has been restricted in
accordance with the provisions of section II.0 of these GRSPs.
C. Industrial Firm Power
Industrial Firm Power is electric power that BPA will make
continuously available to a direct service industrial purchaser (DSI)
pursuant to the DSI's power sales contract and subject to:
1. the restriction applicable to deliveries of all firm power
pursuant to the Uncontrollable Forces and Continuity of Service
provisions of the General Contract Provisions of the power sales
contract, and
2. the restrictions given in the Restriction of Deliveries section
of the power sales contract.
D. Special Industrial Power
Special Industrial Power is electric power which BPA will make
continuously available to any DSI that qualifies for the Special
Industrial Power rate pursuant to section 7(d)(2) of the Northwest
Power Act. This power is similar in nature to Industrial Firm Power,
but is subject to greater restriction by BPA. Special Industrial
Power is made available to the qualifying DSI upon adoption of, and
subject to, an amendment modifying its power sales contract.
E. Auxiliary Power
Auxiliary Power is that power which a DSI requests and which BPA
agrees to make available to serve that portion of the DSI's load
which is in excess of the DSI's Operating Demand for Industrial Firm
Power or Special Industrial Power.
F. Firm Capacity
Firm Capacity is capacity that BPA assures a purchaser will be
available in the amount(s) and during the period(s) specified in the
power sales contract. The energy associated with this capacity must
be returned to BPA. Firm Capacity may be restricted pursuant to the
Restriction of Deliveries section of these GRSPs (section V.F.).
G. Surplus Firm Power
Surplus Firm Power is firm power (capacity, or capacity and energy)
that BPA assures a purchaser will be available in the amount(s) and
during the period(s) specified in the power sales contract. BPA will
make Surplus Firm Power available only to the extent that BPA
determines that it has firm power in excess of the amount required to
meet BPA's existing contractual obligations to provide firm service.
Surplus Firm Power may be used either for resale or direct
consumption by purchasers both inside and outside the United States.
Such power may, however, be restricted pursuant to the Restriction of
Deliveries section of these GRSPs (section V.F.).
H. Surplus Firm Energy
Surplus Firm Energy is firm energy that BPA assures a purchaser will
be available in the amount(s) and during the period(s) specified in
the power sales contract. BPA will make Surplus Firm Energy
available only to the extent that BPA determines that it has firm
energy in excess of the amount required to meet BPA's existing
contractual obligations to provide firm service. Surplus Firm Energy
may be used either for resale or direct consumption by purchasers
both inside and outside the United States. Such energy may, however,
be restricted pursuant to the Restriction of Deliveries section of
these GRSPs (section V.F.).
I. Nonfirm Energy
Nonfirm Energy is nonfirm energy that BPA supplies or makes available
to a purchaser under an arrangement that does not have the guaranteed
continuous availability feature of firm power. However,
Energy that has been purchased under a guarantee provision in the
Nonfirm Energy Rate Schedule shall be provided to the purchaser in
accordance with the provisions of that schedule and the applicable
power sales contract. BPA may make Nonfirm Energy available to
purchasers both inside and outside the United States.
J. Share the Savings Energy
Share the Savings Energy is Nonfirm Energy that BPA supplies or makes
available for contract purchase, under an arrangement that does not
have the guaranteed continuous availability feature of firm
power. The Share -the- Savings Rate is an experimental rate.
Requirements for purchase at the Share the Savings Rate beyond those
contained in the rate schedule will be specified in the contract.
BPA may make Share the Savings Energy available to purchasers both
inside and outside the United States.
K. Energy Broker Energy
Energy Broker Energy, as used in BPA's EB -85 rate schedule, is
Nonfirm Energy that BPA makes available for sale to WSCC members
participating in the Energy Broker System. Power that BPA sells to
such WSCC participants is subject to the Restriction of Deliveries
section of these GRSPs (section V.F.).
L. Reserve Power
Reserve Power is firm power sold to a purchaser:
1. in cases where the purchaser's power sales contract states that
the rate for Reserve Power shall be applied;
2. to provide service when no other type of power is deemed
applicable; and /or
3. to serve the purchaser's firm power loads under circumstances
where BPA does not have a power sales contract in force with
the purchaser.
Sales of Reserve Power are subject to the Restriction of Deliveries
section of these GRSPs (section V.F.).
SECTION III. BILLING FACTORS AND BILLING ADJUSTMENTS
A. Billing Factors for Demand
1. Measured Demand
The purchaser's Measured Demand shall be determined in the
manner described in this section unless the terms of a power
sales contract executed after December 5 ,1980, provide
otherwise. Measured Demand shall be that portion of the
metered and /or scheduled demand that is purchased from BPA
under the applicable rate schedule. For those contracts to
which BPA is a party and that provide for delivery of more than
one class of electric power to the purchaser at any point of
delivery, the portion of each 60- minute clock -hour integrated
demand assigned to any class of power shall be determined
pursuant to the power sales contract. The portion of the total
Measured Demand so assigned shall constitute the Measured
Demand for each such class of power.
The Measured Demand shall be determined from the metered demand
and /or the scheduled demand, as hereinafter defined. The
Measured Demand shall be determined either on a coincidental or
a noncoincidental basis, as provided in the purchaser's power
sales contract.
a. Metered Demand
The metered demand in kilowatts shall be the largest of the
60- minute clock -hour integrated demands, adjusted as
specified in the power sales contract, at which electric
energy is delivered to a purchaser:
(1) at each point of delivery for which the metered demand
is the basis for determination of the Measured Demand,
(2) during each time period specified in the applicable
rate schedule, and
(3) during any billing period.
Such largest integrated demand shall be determined from
measurements made either in the manner specified in the
power sales contract or as provided in section VI.A
herein. In determining the metered demand, BPA shall
exclude any abnormal integrated demands due to or resulting
from:
(1) emergencies or breakdowns on, or maintenance of, the
Federal system facilities, and /or
(2) emergencies on the purchaser's facilities, provided
that such facilities have been adequately maintained
and prudently operated, as determined by BPA.
b. Scheduled Demand
The scheduled demand in kilowatts shall be the largest of
the hourly demands at which electric energy is scheduled
for delivery to a purchaser:
(1) to each system for which scheduled demand is the basis
for determination of the Measured Demand,
(2) during each time period specified in the applicable
rate schedule, and
(3) during any billing period.
Scheduled amounts are deemed delivered for the purpose of
determining billing demand.
2. Ratchet Demand
The Ratchet Demand in kilowatts shall be the maximum demand
established during a specified period of time either during or
prior to the current billing period. The demand on which the
ratchet is based is specified in the relevant rate schedule or
in these GRSPs. For utilities purchasing under the PF or NR
rate schedules, the Ratchet Demand is based on the highest
demand during prior billing months. When the Ratchet Demand is
used as a billing factor, BPA shall have specified in the
appropriate schedules and /or GRSPs:
a. the period of time over which the ratchet shall be
calculated,
b. the type of demand (Measured Demand, Computed Peak
Requirement, etc.) to be used in the calculation, and
c. the percentage (if any) of that demand which will be used
to calculate the Ratchet Demand.
3. Contract Demand
The Contract Demand shall be the maximum number of kilowatts
that the purchaser agrees to purchase and BPA agrees to make
available, subject to any limitations included in the power
sales contract. BPA may agree to make deliveries at a rate in
excess of the Contract Demand at the request of the purchaser,
but shall not be obligated to continue such excess deliveries.
Any contractual or other reference to Contract Demand as
expressed in kilowatthours shall be deemed, for the purpose of
these GRSPs, to refer to the term "Contract Energy."
4. Computed Peak Requirement
For purchasers designated to purchase on the basis of computed
requirements under power sales contracts executed after
December 5, 1980, the Computed Peak Requirement shall be
determined as specified in the purchaser's power sales
contract. That specification is provided in:
a. sections 16, 17(c), and 17(f), as adjusted by other
sections of the contract, for actual computed requirements
purchasers,
b. sections 16, 17(a), and 17(f), as adjusted by other
sections of the contract, for planned computed requirements
purchasers, and
c. sections 16 and 17(b), as adjusted by other sections of the
contract, for contracted computed requirements purchasers.
For computed requirements purchasers with power sales contracts
executed prior to December 5, 1980, the purchaser's Computed
Peak Requirement for each billing month shall be the largest
amount during such month by which the purchaser's actual hourly
system demand, excluding any loads otherwise provided for in
the contract, exceeds its assured peaking capability for such
month, as determined pursuant to section IV.B.3 of these GRSPs.
5. Computed Average Energy Requirement
For computed requirements purchasers with power sales contracts
executed after December 5, 1980, the Computed Average Energy
Requirement shall be determined as specified in the purchaser's
power sales contract. That specification is provided in:
a. sections 16, 17(c), and 17(f), as adjusted by other
sections of the contract, for actual computed requirements
purchasers,
b. sections 16, 17(a), and 17(f), as adjusted by other
sections of the contract, for planned computed requirements
purchasers, and
c. sections 16 and 17(b), as adjusted by other sections of the
contract, for contracted computed requirements purchasers.
For computed requirements purchasers with power sales contracts
executed prior to December 5, 1980, the purchaser's Computed
Average Energy Requirement for each billing month shall be the
amount during such month by which the purchaser's actual system
average load exceeds its assured average energy capability, as
determined pursuant to section IV.A.3 of these GRSPs.
6. Operating Demand
The Operating Demand is that demand which is established by the
DSI in accordance with section 5(b) of the DSI's power sales
contract. Unless the DSI has requested, and BPA has granted,
an Auxiliary Demand, the Operating Demand establishes a limit
with respect to:
a. the demand which the purchaser may impose on BPA; and
b. the total amount of energy during a billing month which the
DSI is entitled to purchase from BPA.
7. Curtailed Demand
A Curtailed Demand is the number of kilowatts of industrial
power (Industrial Firm Power or Special Industrial Power)
during the billing month which results from the DSIs request
for such power in amounts less than the Operating Demand
therefor. Each purchaser of industrial power may curtail its
demand according to the terms of its power sales contract
(which permits up to 3 levels of Curtailed Demand each month).
8. Restricted Demand
Restricted Demand is the number of kilowatts of industrial
power (either Industrial Firm Power or Special Industrial
Power) that results when BPA has restricted delivery of such
power for one (1) clock -hour or more. BPA shall make such
restrictions according to the terms of the DSIs' power sales
contract. In a given billing month, there are as many possible
levels of Restricted Demand for a DSI as there are number of
restrictions.
9. Auxiliary Demand
Auxiliary Demand is the number of kilowatts of Auxiliary Power
that a DSI requests and that BPA agrees to make available to
serve a portion of the DSI's load during the period specified
in the DSI's request. The DSI may request up to three levels
of Auxiliary Demand during a billing month.
If BPA agrees to a request for Auxiliary Power but later
becomes unable to supply such demand, the Restricted Demand for
Auxiliary Power is deemed to be the Auxiliary Demand for such
period of restriction. Auxiliary Power may be curtailed by the
DSI according to the provisions of section 9(a) of the DSI's
power sales contract.
BPA shall make Auxiliary Power available to Industrial Firm
Power purchasers at the Standard Industrial Rate, except that
the Industrial Incentive Rate shall apply if the DSI is making
its purchases under the IP -85 Industrial Incentive Rate.
Auxiliary Power sales to DSIs purchasing under the Special
Industrial Rate will be made only at the Standard Special
Industrial Power Rate.
10. BPA Operating Level
The BPA Operating Level is, for the purpose of these rate
schedules and GRSPs, an hourly amount of industrial power
(Industrial Firm Power or Special Industrial Power) for a DSI
that is equal to the lowest of the following demands during
that hour:
a. Operating Demand plus Auxiliary Demand, if any;
b. Curtailed Demand; or
c. Restricted Demand.
The weighted average BPA Operating Level for the DSI can be
determined by summing the hourly BPA Operating Levels and
dividing by the number of hours in the billing month.
Each DSI must request service from BPA for each billing month
in accordance with the terms of the power sales contract. The
requested level of service will be the BPA Operating Level,
provided BPA does not need to restrict the DSI and provided BPA
agrees to supply any requested Auxiliary Demand. Each
requested level of service may include a designation for both
the Peak Period and the Offpeak Period. A DSI may request and
BPA may agree to a level of service for the Offpeak Periods
other than that in the Peak Period. If a DSI does not
separately designate a requested level of service for the Peak
and Offpeak Periods, the BPA Operating Level will be the same
for both periods. The BPA Operating Level is the basis for
determining if a DSI has incurred an unauthorized increase.
Any DSI whose Measured Demand, before adjustment for power
factor, during any one hour exceeds the BPA Operating Level for
that hour shall be subject to unauthorized increase charges for
each kilowatthour of unauthorized increase associated with each
overrun.
Only the BPA Operating Level applicable during the Peak Period
will be used in determining the Billing Demand for power
purchased under the Industrial Firm Power Rate Schedule, and
the Standard Rate under the Special Industrial Rate Schedule.
During the Peak Period the BPA Operating Level may be no
greater than the Operating Demand for the billing month unless
the customer has requested, and BPA has agreed to supply, the
Auxiliary Demand.
11. Committed Demand
Committed Demand is the number of kilowatts of Industrial Firm
Power that BPA agrees to supply and a DSI agrees to purchase on
a take -or -pay basis under the Industrial Incentive Rate. The
Committed Demand shall be established by written agreement with
each DSI electing to purchase on this basis. A purchaser may
specify up to three levels of Committed Demand for each billing
month for the Peak Period.
B. Billing Factors for Energy
1. Measured Energy
The purchaser's Measured Energy shall be determined in the
manner described in this section unless the terms of a power
sales contract executed after December 5, 1980, provide
otherwise. Measured Energy shall be that portion of the
metered and /or scheduled energy that is purchased from BPA
under the applicable rate schedule. For those contracts to
which BPA is a party and that provide for delivery of more than
one class of electric power to the purchaser at any point of
delivery, the portion of each 60- minute clock -hour integrated
demand assigned to any class of power shall be determined
pursuant to the power sales contract. The sum of the portions
of the demands so assigned shall constitute the Measured Energy
for each such class of power.
The Measured Energy shall be determined from the metered energy
and /or the scheduled energy, as hereinafter defined.
a. Metered Energy
The metered energy for a purchaser shall be the number of
kilowatthours that are recorded on the appropriate metering
equipment, adjusted as specified in the power sales
contract, and delivered to a purchaser:
(1) at all points of delivery for which metered energy is
the basis for determination of the Measured Energy, and
(2) during any billing period.
The metered energy shall be determined from measurements
made either in the manner specified in the power sales
contract or as provided in section VI.A herein.
b. Scheduled Energy
The scheduled energy in kilowatthours shall be the sum of
the hourly demands at which electric energy is scheduled
for delivery to a purchaser:
(1) for each system for which scheduled energy is the
basis for determination of the Measured Energy, and
(2) during any billing period.
Scheduled amounts are deemed delivered for the purpose of
determining billing energy.
2. Computed Energy Maximum
The Computed Energy Maximum equals the product of the number of
hours in the billing month and the Computed Average Energy
Requirement.
3. Committed Energy
Committed Energy is the number of kilowatthours of Industrial
Firm Power that BPA agrees to supply and that a DSI agrees to
purchase on a take -or -pay basis under the Industrial Incentive
Rate. The Committed Energy shall be established by written
agreement with each DSI electing to purchase on this basis. In
lieu of providing a kilowatthour figure, BPA may permit a
customer to contractually specify the load factor at which the
Committed Demand will be purchased.
4. Contract Energy
The Contract Energy shall be the maximum number of
kilowatthours that the purchaser agrees to purchase and BPA
agrees to make available, subject to any limitations included
in the power sales contract.
C. Billing Adiustments
1. Power Factor Ad.iustment
The formula for determining average power factor is as follows:
Kilowatthours
Average Power
Factor Kilowatthours) 4- (Reactive kilovoltamperehours)
The data used in the above formula shall be obtained from
meters that are ratcheted to prevent reverse registration.
This data shall then be adjusted for losses, if applicable,
before determination of the average power factor.
When deliveries to a purchaser at any point of delivery either:
a. include more than one class of power, or
b. are provided under more than one rate schedule
and it is impracticable to meter the kilowatthours and
reactive kilovoltamperehours for each class or rate schedule
separately, the average power factor of the total deliveries
for the r�oonth will be used, where applicable, as the power
factor for all power delivered to such point of delivery.
To maintain acceptable operating conditions on the Federal
system, BPA may, unless specifically otherwise agreed,
restrict deliveries of power to a purchaser with a poor power
factor. Such restriction may be made to a point of delivery
or to a purchaser's system at any time that the average
leading power factor or average lagging power factor for all
classes of power delivered to such point or to such system is
below 75 percent.
2. Outage Adjustment
To the extent that BPA is unable to provide full service to a
purchaser during the billing month as a result of
interruptions in service due to reasons cited in the General
Contract Provisions, BPA shall adjust the charges for billing
demand for such purchaser to reflect BPA's inability to
provide full service, provided such adjustment is mandated by
the purchaser's power sales contract. The adjustment is
provided on a point of delivery basis. To compute the
adjustment for noncoincidentally billed systems, BPA shall
determine the monthly demand charge(s) for the point(s) of
delivery where the outage(s) occurred, multiply by the number
of hours of outage, and divide by the total number of hours in
the billing month. For coincidentally billed points of
delivery, the adjustment shall apply only to those points of
delivery at which BPA was unable to provide full service. For
partial outages (such as an outage on one feeder in a
substation with several feeders), BPA shall determine an
equivalent interruption in order to arrive at the number of
hours to be used in the calculation of the credit.
3. Low Density Discount (LDD)
a. Basic LDD Principles
A predetermined discount shall be applied each billing
month to the charges for all power purchased under the
Priority Firm Power Rate Schedule by eligible purchasers
as defined in section b, below. The discount shall be
calculated on an annual basis and shall become effective
with the first billing period in the calendar year. The
level of the discount shall be determined from the
following ratios:
(1) the purchaser's total electric energy requirements
during the previous calendar year (the purchaser's
firm sales, nonfirm sales, sales for resale, and
associated losses) divided by the value of the
purchaser's depreciated electric plant (excluding
generation plant) at the end of such year, and
(2) the average number of residential consumers during
the previous calendar year divided by the number of
pole miles of distribution line at the end of such
year.
These calculations shall be based on data provided in the
purchaser's annual financial and operating report.
"Residential consumers" shall include both annual and
seasonal consumers, but nonresidential consumers (such as
barns, sheds, and pumps) reported in the residential
category for accounting purposes may be excluded,
providing the purchaser submits a listing of all
nonresidential account numbers to BPA at the time that
the annual submission is first made.
In calculating these ratios, BPA shall use data
pertaining to the purchaser's entire electric utility
system within the region. Results of the calculations
shall not be rounded.
Customers who have not provided BPA with all four
requisite pieces of annual data see a.(1) and a.(2)
above) by June 30 of each year shall be assumed to be
ineligible for the LDD effective with their first
complete billing period following June 1 of that year.
BPA shall continue to use LDD data from the previous year
up to June 30 and shall make any necessary retroactive
adjustments once the new data have been processed. If no
data have been received by December 31 for the previous
calendar year, BPA shall assume that the utility did not
qualify for an LDD for that year. LDD discounts that
were issued from January 1 to June 30 shall be assumed to
have been in error, and the utility shall be billed for
any such discounts issued.
Revisions to the data used to calculate the amount of the
LDD may be made by the purchaser for a period of up to
2 years from the first day to which the data applies.
However, such revisions shall not apply to periods when
the customer was ineligible for a discount due to late
data submission.
b. Eligibility Criteria
To qualify for a discount, the purchaser must meet all
five of the following eligibility criteria:
(1) the purchaser must serve as an electric utility
offering power for resale;
(2) the purchaser must agree to pass the benefits of the
discount through to the purchaser's consumers within
the region served by BPA;
(3) the purchaser's kilowatthour to investment ratio
(Ratio 3.a.(1)) must be less than 100;
(4) the purchaser's consumers per mile ratio
(Ratio 3.a.(2)) must be less than 10; and
(5) the purchaser must qualify for a discount based on
the criteria in section c, below.
c. Discounts
The purchaser shall be awarded the greatest discount for
which that purchaser qualifies. The discounts and the
qualifying criteria for those discounts are listed below.
(1) Three percent, for any purchaser for whom:
(a) the kilowatthour to investment ratio is equal
to or greater than 25 but less than 35; or
(b) the consumers per mile ratio is equal to or
greater than 4 but less than 6.
(2) Five percent, for any purchaser for whom:
4. Irrigation Discount
(a) the kilowatthour to investment ratio is equal
to or greater than 15 but less than 25; or
(b) the consumers per mile ratio is equal to or
greater than 2 but less than 4.
(3) Seven percent, for any purchaser for whom:
(a) the kilowatthour to investment ratio is less
than 15; or
(b) the consumers per mile ratio is less than 2.
a. Basic Irrigation Discount Principles
A discount of 3.7 mills per kilowatthour shall be applied
to the charges for qualifying energy purchased under the
Priority Firm Power and New Resource Firm Power rate
schedules, during the billing months of April through
August. This discount shall be applied subsequent to
calculation of the Low Density Discount, if applicable.
Any energy on which the discount is claimed shall be
metered separately by the purchaser.
b. Oualifvinq Energy Purchases
The qualifying irrigation load "irrigation energy
shall be determined as follows:
(1) All irrigation energy must be used exclusively for
the purpose of irrigation and drainage pumping on
agricultural land and be measured at the point of
use.
(2) Energy subject to the discount must be purchased
during the billing months of April through August.
(3) Purchasers of exchange energy under the Residential
Purchase and Sale Agreement (RPSA) are eligible for
the irrigation discount for the portion of their
irrigation load qualifying for the exchange under
the RPSA contracts.
(4) General requirements customers with their own
resources are eligible for an irrigation discount
for a portion of their irrigation load equal to the
share of their total load served by BPA (i.e., total
irrigation load multiplied by BPA billing energy
divided by total utility system requirements for the
billing month).
c. Reporting Requirements
Request for the Irrigation Discount
(1) To receive an irrigation discount, a purchaser must
file a request for the discount with their local
Area or District office by July 1, 1985, for the
1985 irrigation season and by April 1 each year
thereafter for subsequent irrigation seasons.
(2) In the request, the purchaser must certify that the
irrigation energy is sold exclusively for use in
irrigation and drainage pumping and that the
discount is passed, in its entirety, to the
irrigation consumer. BPA retains the right to
verify, in a manner satisfactory to the
Administrator, that the discounted energy is used
for the sole benefit of the purchaser's irrigation
load.
(3) The purchaser shall also list each irrigation
account number in its request. If the purchaser is
an exchanging utility, the purchaser shall also
identify the size (in horsepower) of the connected
load for each account. That account list shall be
updated on a monthly basis if accounts are added,
deleted, or changed. In addition, the utility shall
state how its irrigation consumers are
billed: monthly, bimonthly, or seasonally.
Irrigation Report
(1) Purchasers shall submit an irrigation report to
their local Area or District office in order to
receive the irrigation discount. Purchasers are
required to report information related to irrigation
energy on the same basis as they bill their
irrigation consumers. In order to qualify for the
discount, the purchaser must submit all data to BPA
by December 31 of the calendar year in which the
load occurred.
(2) Irrigation reports to BPA shall include the
following information for the reporting period
(monthly, bimonthly, or seasonally):
(a) utility name;
(b) period for which the report is being made;
(c) total irrigation load;
(d) total irrigation load under 400 hp, for
exchanging utilities;
(e) total utility system requirements (in
kilowatthours).
5. Coincidental Billing Adlustment
Purchasers of Priority Firm Power and New Resource Firm Power
shall be billed on a noncoincidental demand basis for power
purchased at each point of delivery under the applicable rate
schedule(s) unless the power sales contract specifically
provides for coincidental demand billing among particular
points of delivery. For the purpose of these rate schedules
and GRSPs, the purchaser's noncoincidental demand is the sum
of the highest hourly peak demands during the billing month
for each of the purchaser's points of delivery. The
purchaser's coincidental demand is the highest demand for the
billing month calculated by summing, for each hour of every
day, the purchaser's demands for power purchased under the
applicable rate schedule at all coincidentally billed points
of delivery. Computed requirements customers for whom power
is "scheduled" from BPA are not subject to a diversity charge
for scheduled power.
When the purchaser's contract provides for billing on a
coincidental demand basis, a charge shall be assessed for the
diversity among the purchaser's coincidentally billed points
of delivery unless BPA elects to waive such charge in whole or
in part. The purpose of charging the customer for diversity
is to compensate BPA for lost revenue due to coincidentally
combining demands from multiple points of delivery. BPA may
calculate the charge by applying an existing methodology or by
specifying a diversity factor or charge in the power sales
contract. If a diversity charge is specified in a purchaser's
power sales contract, that charge shall be applied.
Diversity factors will be specified in the power sales
contract for coincidentally billed points of delivery of
customers who are not currently assessed a diversity charge
and who, by BPA's criteria, should be assessed the charge. Any
changes to existing diversity factors or charges shall be
likewise reflected in the power sales contract. The diversity
factor(s) specified in the power sales contract shall be
multiplied by the respective coincidental demands for the
coincidentally billed points of delivery in order to determine
the diversity demand for those points of delivery. Diversity
demand will be billed at the same demand charge that is
applied to the customer's other purchases.
The diversity factor(s) specified in the power sales contract
shall be no greater than:
Noncoincidental Demand Coincidental Demand
Coincidental Demand
where the Noncoincidental and Coincidental Demands used in the
calculation are the sum of the monthly demands for 12 months
prior to the computation of the diversity factor for each of
the purchaser's coincidentally billed points of delivery. BPA
shall revise the contractually specified diversity factor(s)
according to the terms of the power sales contract.
6. Exchange Adjustment Clause
To the extent that the accounting net cost of exchange
resources (the cost to BPA of the exchange resources minus the
revenue collected from the exchange loads) differs from that
forecast for the development of rates, a rebate shall be given
or a surcharge assessed to all those purchasing under rate
schedules that include this adjustment (PF -85, CF -85, and
NR -85).
An Exchange Adjustment shall be applied for the period July 1,
1985, through September 30, 1986 (period A), another such
adjustment for the period October 1, 1986 through
September 30, 1987 (period B), and a third adjustment for the
period October 1, 1987 until the next Rate Adjustment Date
(Period C) provided BPA does not adjust its wholesale power
rates on October 1, 1987.
a. Calculation of the Exchange Adjustment
The total amount of revenue that must be rebated or
recovered in order for BPA to adjust for changes in the
net accounting cost of the exchange shall be calculated
for each exchange adjustment period according to the
formula below.
TAR (AEC AER) (FEC FER)
where:
TAR total amount of revenue underrecovery (if TAR
is negative) or overrecovery (if TAR is
positive) of the accounting net cost of the
exchange for the exchange adjustment period;
AEC actual total exchange cost for the exchange
adjustment period; AEC includes exchange costs
from the utilities whose average system cost
(ASC) is deemed equal to the Priority Firm
Power Rate (deeming utilities);
AER actual exchange revenue for the exchange
adjustment period; both AEC and AER will be
FEC forecasted exchange cost;
for period A, the value of FEC is equal to
$1,329,990,000;
for period B, the value of FEC is equal to
$1,107,574,000; and
for period C, the value of FEC shall be
calculated after BPA has determined the number
of months in period C;
FER forecasted exchange revenue;
for period A, the value of FER is equal to
$1,059,437,000;
for period B, the value of FER is equal to
$873,877,000; and
for period C, the value of FER shall be
calculated after BPA has determined the number
of months in period C;
Next, the rebate or surcharge for each customer class for
each period shall be calculated.
CCEA TAR ECP
where:
calculated without considering the effect of
the Exchange Adjustment Clause, but including
the effect of the Supply System Adjustment
Clause; AER includes exchange revenue from
deeming utilities;
CCEA rebate or surcharge for each customer class for
the exchange adjustment period; two values of
CCEA shall be calculated for Firm Capacity
service, one value for contract year service
and another for contract season service.
ECP exchange cost percentage for the customer
class; the value of "ECP" is provided in the
rate schedule for each class of service subject
to the Exchange Adjustment Clause; different
values are given in the Firm Capacity Rate
Schedule for the different types of Firm
Capacity service.
Finally, BPA shall apply the following formula in order
to calculate the exchange adjustment for an individual
customer:
where:
1 (Z.Nr ik Mo)
ICEA (CCEA ICB)
SCB ?ti
ICEA individual customer's exchange adjustment (in
dollars) for the exchange adjustment period;
ICB sum of the individual customer's bills (in
dollars and net of the LDD) associated with a
given ECP for the class of power in question
during the exchange adjustment period;
SCB sum of all the customer's bills (in dollars and
net of the LDD) for the class of power in
question during the exchange adjustment period;
INT average interest rate charged to BPA by the
U.S. Treasury during the exchange adjustment
period.
MO number of months in the subperiod.
N,o exchange adjustment will be made to any rate schedule
if the absolute value of:
CCEA is less than .01 for that rate class.
SCB
b Implementation of the Exchange Adjustment
The rebate or surcharge shall be calculated as soon as
possible after:
(1) October 1, 1986, for period A,
(2) October 1, 1987, for period B, and
(3) the end of period C, or in yearly intervals after
October 1, 1987, should these rates continue in
effect.
BPA shall notify affected purchasers of the impending
adjustment as soon as the amount of the adjustment has
been calculated. Payment of the adjustment (either the
rebate or the surcharge) shall be made within 30 days of
the date on the adjustment notice provided to the
purchaser. Late payment shall be subject to late payment
charges as described in section VI.G.4 of these GRSPs.
The Due Date for the Exchange Adjustment, as defined in
section VI.G.3, shall be 30 days from the date on the
adjustment notice.
c. Provisions for Final Adjustment
Approximately 1 year from the end of each exchange
adjustment period, BPA shall recalculate the exchange
adjustment rebate or surcharge for each customer. The
recalculation shall be based on the most current values
of the variables used in the adjustment formula. This
recalculation shall be final and not subject to later
modification, except pursuant to orders of FERC or the
United States Court of Appeals for the Ninth Circuit.
BPA shall calculate the difference between the amount of
the initial adjustment and the amount of the final
adjustment. That difference shall be subject to an
interest charge for the period beginning 30 days from the
date on the initial adjustment notice and ending on the
date of the final adjustment notice. The interest rate
used in the computation of the interest charge shall be
the average interest rate charged to BPA by the
U.S. Treasury for the period in question.
BPA shall then notify affected customers of the amount to
be rebated or surcharged. Payment shall be made within
30 days of the date on the adjustment notice provided to
the purchaser. Late payment shall be subject to late
payment charges as described in section VI.G.4 of these
GRSPs. The Due Date, as defined in section VI.G.3, for
the Exchange Adjustment shall be 30 days from the date on
the adjustment notice.
Where necessary, BPA shall later modify the recalculation
to reflect any changes in average system cost
determination ordered by FERC or the United States Court
of Appeals for the Ninth Circuit. In making such
additional adjustment, BPA shall adhere to the procedures
outlined above.
7. Supply System Adjustment Clause
BPA shall adjust the energy charges for the period October 1,
1986, to September 30, 1987, in those rates schedules that
include the Supply System Adjustment Clause (SSAC), if the
SSAC is triggered as determined herein. If these rates remain
in effect after September 30, 1987, no SSAC shall be applied
for that period. The SSAC adjusts for differences between the
total cost of Supply System ownership shares of WNP -1, -2,
and -3 and the cost that was forecast for the development of
the rates.
a. Calculation of the Supply System Adjustment
The adjustment for each rate schedule shall be calculated
as follows:
SS [(ACT $815.266,000) (BUD1 $814,548,000) +(BUD2 $207,863,000)]
where:
BD
SS the percentage of total Supply System costs
allocable to the specified class of service for
fiscal year (FY) 1987; the value for "SS" is
provided in the rate schedule for the class of
service in question;
ACT The Net Funding Requirements (in thousands of
dollars) in the Supply System Annual Budgets or
amendments thereto for operating year (0Y) 1986
as of June 1, 1986;
BUD1
BUD2
the Net Funding Requirements (in thousands of
dollars) in the Supply System Annual Budgets or
amendments thereto for OY 1987, as of June 1,
1986;
one quarter of the estimated Net Funding
Requirements (in thousands of dollars) for
OY 1988, as of June 1, 1986;
BD for the Priority Firm Power Rate Schedule, PF -85,
the sum of the winter and summer energy billing
determinants (in gigawatthours) for Priority Firm
service as forecasted in the Wholesale Power Rate
Design Study; and for the CF -85 Firm Capacity
Rate Schedule, the sum of the winter and summer
generation capacity billing determinants (in
megawattmonths); the value of "BD" is provided in
the rate schedule for each class of service
subject to the SSAC.
Costs associated with any restart of construction on WNP -1
and WNP -3 shall not be included in ACT and BUD.
No Supply System Adjustment shall be made if:
C(ACT $815,266,000) (BUD1 $814,548,000) (BUD2 $207,863,000)]
$1,837,677,000
is less than 1 percent.
b. Implementation of the Supply System Adjustment
1. Peak Period
2. Offpeak Period
During the month of August 1986, BPA shall identify:
(1) the difference between ACT and $815,266,000,
(2) the difference between BUD1 and $814,548,000, and
(3) the difference between BUD2 and $207,863,000.
By August 15, 1986, BPA shall notify interested parties
of BPA's initial findings concerning the changes in
Supply System Costs. If no adjustment is required, the
notice will so state and no further action will be
initiated by BPA. However, if BPA determines that an
adjustment to the rates is required, BPA shall also file
written testimony with interested parties, by August 15,
1986, explaining how BPA arrived at its initial findings
and how the proposed adjustment was calculated. Parties
wishing to submit comments or to file written testimony
have until close of business on September 8, 1986, to
submit their comments or their testimony to BPA and other
parties. Interested parties shall be afforded a
resonable opportunity to examine all comments and
testimony received. Comments and testimony should be
directed to the proper calculation of the adjustment, and
not to the appropriateness of the level of Supply System
budgets or construction schedules. Consideration of
comments and more current information may'result in the
final adjustment differing from the proposed adjustment.
Before implementing the adjustment, BPA shall notify all
affected parties of the amount of the final adjustment.
D. Billing- Related Definitions
The Peak Period includes the hours from 7 a.m. through 10 p.m.
on any day Monday through Saturday inclusive. There are no
exceptions to this definition; that is, it does not matter
whether the day is a normal working day or a holiday. Any
charges based on Peak Period hours shall be computed starting
with the 8 a.m. meter reading since this reading applies to
the 7 o'clock hour (i.e. 7 a.m. to 8 a.m.). The 10 p.m. meter
reading (for the 9 p.m. to 10 p.m. period) is the last meter
reading of the day applicable to the Peak Period.
The Offpeak Period includes all hours which do not occur
during the Peak Period. Thus, the Offpeak Period consists of
the hours from 10 p.m. through 7 a.m., Monday through Saturday
SECTION IV. OTHER DEFINITIONS
and all hours on Sunday. This definition does not apply to the
Special Industrial Offpeak Rate.
A. Computed Reauirements Purchasers
1. Designation as a Comouted Reauirements Purchaser
A purchaser shall be designated as a computed requirements
purchaser if:
a. it is so designated pursuant to the provisions of its
power sales contract executed after December 5, 1980, or
b. its power sales contract was executed prior to
December 5, 1980, and it meets one or more of the
following conditions as described in paragraphs (1) and
(2) below:
(1) Such purchaser has generation of its own which can
be sold in such a way as to increase EPA's
obligation to deliver firm power to that purchaser
because of such sale or,
(2) such purchaser has the ability to redistribute
generation from its resources over time in such a
manner as to cause losses of power or revenue on the
Federal system.
When a purchaser operates two or more separate systems, only
those systems designated by BPA will be covered by this
section.
2. Purpose of the Computed Reauirements Desianation
Use of the computed requirements designation is intended to
assdre that each purchaser who purchases power from BPA to
supplement its own firm resources will purchase amounts of
firm capacity and firm energy substantially equal to that
which the purchaser would otherwise have to provide on the
basis of normal and prudent operations.
The amount of capacity and energy required for normal and
prudent operations shall be determined pursuant to the
purchaser's power sales contract for all computed requirements
purchasers with power sales contracts executed after
December 5, 1980.
For computed requirements purchasers with power sales
contracts executed before December 5, 1980, the amount of
capacity and energy required for normal and prudent operations
is that which would be sufficient to meet the load and provide
adequate reserves through the most critical water or other
conditions which might reasonably be expected to occur.
Purchase on a computed requirements basis for a purchaser with
a power sales contract executed before December 5, 1980,
depends on the relationship of the purchaser's resource
capability to the purchaser's system requirements. Thus, the
billing factors to be applied to such a computed requirements
purchaser for any month cannot be determined until after the
end of the month. As each such purchaser must estimate its
own load and is in the best position to follow that load from
day to day, it is the purchaser's responsibility to request
scheduling of power from BPA.
3. Definitions and Terms Relatina to Computed Reauirements
Purchasers with Power Sales Contracts Executed Prior to
December 5, 1980
Those purchasers whose power sales contracts were executed
prior to December 5, 1980, and who are designated as computed
requirements purchasers based on the abilities listed in
section IV.A.1.b, above, shall be governed by the terms of
this subsection.
a. General Principles
(1) The assured peaking capability and assured average
energy capability of each of the purchaser's systems
shall be determined and applied separately.
(2) As used in this section, "year" or "operating year"
shall mean the 12 -month period commencing July 1.
(3) The critical period is that period, described below,
during which the purchaser would have the maximum
requirement for peaking or energy from BPA. That
period would be determined for the purchaser's
system under adverse streamflow conditions and
adjusted for:
(a) current water uses,
(b) assured storage operation, and
(c) appropriate operating agreements.
In determining the maximum requirement for peaking
or energy from BPA, the firm capability of all
resources available to the purchaser shall be
utilized in such a manner as to place the least
requirement on BPA.
(4) Critical water conditions are those conditions of
streamflow in the operating year or years which
would result in the minimum capability of the
purchaser's firm resources during the critical
period. Those conditions of streamflow are based on
historical records as adjusted for:
(a) current water uses,
(b) assured storage operation, and
(c) appropriate operating agreements.
(5) Prior to the beginning of each operating year, the
purchaser shall determine the assured capability of
each of the purchaser's systems in terms of peaking
and average energy for each month of each year or
years within the critical period. The firm
capability of all resources available to the
purchaser's system shall be utilized in such a
manner as to place the least requirement for
capacity and energy on BPA. Such assured capability
shall be effective after review and approval by BPA.
(6) The purchaser's assured average energy capability
shall be determined by shaping its firm resources to
its firm load in a manner which places a uniform
requirement on BPA within each year of the critical
period. The requirement placed on BPA may increase
each year, but by no more than the sum of:
(a) the purchaser's annual load growth and
(b) any reductions in assured average energy
capability caused by retirement or loss of one
of the purchaser's firm resources.
(7) As used herein, the capability of a firm resource
shall include only that portion of the total
capability of such resource which the purchaser can
deliver to its load on a firm basis. The
capabilities of all generating facilities which are
claimed as part of the purchaser's assured
capability shall be determined by test or other
substantiating data acceptable to BPA. BPA may
require verification of the capabilities of any or
all of the purchaser's generating facilities. Such
verification shall not be required more often than
once each year for operating plants, or more often
than once each third year for thermal plants in cold
standby status, if BPA determines that adequate
annual preventive maintenance is performed and the
plant is capable of operating at its claimed
capability.
(8) In determining assured capability, the aggregate
capability of the purchaser's firm resources shall
be appropriately reduced to provide adequate
reserves.
b. Determination of Assured Capability
The purchaser's assured peaking and assured energy
capabilities shall be the respective sums of:
(1) the capabilities of its hydroelectric generating
plants based on the most critical water conditions
experienced to date on the purchaser's system,
(2) the capabilities of its thermal generating plants
based on such adverse fuel or other conditions which
might reasonably be expected to occur, and
(3) the firm capabilities of other resources made
available to the purchaser under contracts executed
prior to the beginning of the operating year. The
firm capabilities of these acquired resources will
be based on the capabilities after adjustment for
reserves.
Assured capabilities shall be determined for each month
if the purchaser has seasonal storage. The capabilities
of the purchaser's firm resources shall be determined as
follows:
(1) Hydroelectric Generating Facilities
The capability of each of the purchaser's
hydroelectric generating plants shall be determined
in terms of both peaking and average energy using
critical water conditions. The average energy
capability shall be that capability which would be
available under the conditions necessary to produce
the claimed peaking capability.
Seasonal storage shall mean storage sufficient to
regulate all the purchaser's hydroelectric resources
in such a manner that, when combined with the
purchaser's thermal generating facilities, if any,
and with firm capacity and energy available to the
purchaser under contracts, a uniform energy
requirement on BPA for a period of one (1) month or
more would result.
A purchaser having seasonal storage shall, within
10 days after the end of each month in the critical
period, notify BPA in writing of the assured average
nergy capability to be applied tentatively to the
preceding month. Such notice shall also specify the
purchaser's best estimate of its average system
energy load for such month. If such notice is not
submitted, or is submitted later than 10 days after
the end of the month to which it applies, subject to
the limitations stated herein, the assured average
energy capability determined for such month prior to
the beginning of the year shall be applied to such
month and may not be changed thereafter.
If notice has been submitted pursuant to the
preceding paragraph, the purchaser shall, within
30 days after the end of the month, submit final
specification of the assured average energy
capability to be applied to the preceding month,
provided that the assured energy capability so
specified shall not differ from the amount shown in
the original notice by more than the amount by which
the purchaser's actual average system energy load
for such month differs from the estimate of that
load shown in the original notice. If the assured
average energy capability for such month differs
from that determined prior to the beginning of the
year for such month, the purchaser, if required by
BPA, shall demonstrate by a suitable regulation
study based on critical water conditions:
(a) that such change could actually be
accomplished, and
(b) that the remaining balance of its total
critical period assured average energy
capability could be developed without adversely
affecting the firm capability of other
purchaser's resources.
The algebraic sum of all such changes in the
purchaser's assured average energy capability shall
be zero at the end of the critical period or year,
whichever is earlier. Appropriate adjustments in
the assured peaking capability shall be made if
required by any change in reservoir operation as
indicated by revisions in the monthly distribution
of critical period energy capability.
(2) Thermal Generating Facilities
The capability of each of the purchaser's thermal
generating plants shall be determined in terms of
both peaking and average energy. Such peaking and
average energy capabilities shall be based on those
adverse fuel or other conditions that might
reasonably be expected to occur. The effect of
limitations on fuel supply due to war or other
extraordinary situations will be evaluated at the
time, should any such situation arise.
(3) Other Sources of Power
The peaking and average energy assured capability of
other firm resources available under contracts to
the purchaser shall be determined prior to each
operating year.
B. Definitions Relating to the Nonfirm Energy Rate (NF -85)
A.
1. Decremental Cost of a displaceable thermal resource or
end -user load with alternate fuel source is defined as all
identifiable costs (expressed in mills per kilowatthour) that
the purchaser is able to avoid by purchasing power at this
rate, rather than generating the power itself or using an
alternate fuel source.
2. Decremental Cost of a displaceable purchase of energy is
defined as all identifiable costs to serve load (expressed in
mills per kilowatthour) that the purchaser is able to avoid by
choosing not to make the alternate energy purchase.
SECTION V. APPLICATION OF RATES UNDER SPECIAL CIRCUMSTANCES
Energv Supplied for Emergency Use
A purchaser taking Priority Firm and /or New Resource Firm Power
shall pay in accordance with the Nonfirm Energy Rate Schedule,
NF -85, and Emergency Capacity Rate Schedule, CE -85, for any
electric energy or capacity which has been supplied:
1. for use during an emergency on the purchaser's system, or
2. following an emergency to replace energy secured from sources
other than BPA during such emergency.
Mutual emergency assistance may, however, be provided and payment
therefor settled under exchange agreements.
B. Construction, Test and Start -Up, and Station Service
Power for the purpose of construction, test and start -up, and
station service shall be made available to eligible purchasers
under the Priority Firm and New Resource Firm Power Rate
Schedules. Such power must be used in the manner specified below:
1. Power sold for construction is to be used in the construction
of the project.
2. Power sold for test and start -up may be used prior to
commercial operation both to bring the project on line and to
ensure that the project is working properly.
3. Power sold for station service may be purchased at any time
following commercial operation of the project. Station
service power may be used for project start -up, project
shut -down, normal plant operations, and operations during a
plant shut -down period.
C. Application of Rates during Initial Operation Period Transitional
Service
1. Eligibility for Transitional Service
For an initial operating period, as specified in the power
sales contract, beginning with the commencement of operation
of a new industrial plant, a major addition to an existing
plant, or reactivation of an existing plant or important part
thereof, BPA may agree to bill the purchaser in accordance
with the provisions of this section. This section shall apply
to both:
a DSIs having new, additional or reactivated plant
facilities, and
b utility purchasers serving industrial purchasers with
power purchased from BPA. BPA will provide transitional
service to utilities only for those industrial loads for
which the demand can be separately metered by the utility
and recorded on a daily basis.
2. Calculation of the Daily Demand
If BPA agrees to provide transitional service, the billing
demand for the industrial load for the billing month shall be
the average of the daily billing demands, as adjusted for
power factor. The Daily Demand for each day shall be the
higher of factors "a" and "b" below:
a. 100 percent of the Measured Demand for the day
(regardless of whether such Measured Demand occurs during
the Peak Period or the Offpeak Period), or
b. the highest daily billing demand that has occurred during
the period of restoration as defined in section 4(e) of
the power sales contract.
3. Billing for Transitional Service
Utilities receiving transitional service shall provide BPA
with daily demand information for the industrial consumer for
whom transitional service is provided. To compute the power
bill for the point of delivery which includes the load being
served with transitional service, BPA shall, at its
discretion, either:
a. determine the demand for the pertinent point of delivery
without the industrial load and then add the average
daily demand for such industrial load, or
b. bill the entire point of delivery on a daily demand basis.
Daily demand billing shall not affect the level of any
curtailment charge, or energy charge assessed by BPA.
For DSIs purchasing Industrial Firm Power, transitional
service may be purchased only under the Standard Industrial
Rate or the Premium Industrial Rate, unless otherwise
requested by the DSI and approved by BPA. BPA will provide
transitional service to purchasers of Special Industrial Power
only under the Standard Special Industrial Power Rate.
D. Changes in a DSIs' BPA Operating Level
If a DSI requests a waiver regarding the notice requirements
specified in the DSI's power sales contract for a voluntary change
in its BPA Operating Level, and if BPA does not grant the waiver,
or if the DSI fails to give notice of such a change and does not
request a waiver, the DSI shall be billed as if no notice has been
provided until such time as the number of days in the notice period
have passed. If, however, BPA agrees to waive the notice
requirement, the power bill shall reflect the requested changes as
of the requested effective date specified in the notice or, at
BPA's discretion, a date of BPA's choosing within the notice period.
E. Application of the Industrial Incentive Rate
The Industrial Incentive Rate shall apply solely to those DSIs
purchasing under the IP -85 wholesale power rate and consenting to
purchase under this special rate. BPA shall determine when and if
the Industrial Incentive Rate shall be offered to purchasers of
Industrial Firm Power. In order to make that determination, BPA
shall use the following procedure:
1. Industrial Incentive Rate Feasibility Study
a. If BPA anticipates that the Industrial Incentive Rate
might trigger, BPA shall conduct an Industrial Incentive
Rate Feasibility Study (Study). In addition, BPA may
(but is not obligated to) conduct the Study if so
requested by one or more of BPA's customers.
b. BPA shall first consider the period of time for which the
Industrial Incentive Rate would be effective. Such
period shall be for no less than 6 months or the end of
the rate period, whichever comes first, and no more than
12 months or the end of the rate period, whichever comes
first. If BPA wishes to have the flexibility to extend
the Industrial Incentive Rate beyond the proposed
contract period (but not beyond 12 months) without
further public involvement, BPA shall include scenarios
in its Study which use data for both the proposed period
and for the projected extension.
c. To conduct the Study, BPA may use the Aluminum Smelter
Model (ASM) or an equivalent model to determine potential
DSI load under various discount levels (for example,
averaging 1 mill, 2 mills, etc., but not necessarily
limited to 1 mill increments) from the Standard rate.
BPA will use this information, as appropriate, to conduct
the revenue impact analysis. The revenue impact analysis
may be extended beyond the Incentive Rate period. The
Nonfirm Revenue Analysis program (NFRAP) and the Revenue
Forecasting Model (REFORM) or equivalent models may be
used in this determination.
d. BPA shall then determine which of the discount levels
examined in step c would increase BPA's total revenue
over the anticipated revenue if the Standard Industrial
rate were in effect for the proposed Incentive Rate
period. The Incentive Rate period determined in step b,
the load information gathered in step c, and BPA's
forecasts of Nonfirm Energy, and expected Surplus Firm
Power sales shall be used as inputs to the Study.
e. The Incentive Rate shall be determined by reducing the
Standard Industrial Rate by X mills /kWh during the months
for which the Incentive Rate is proposed to be in
effect. In choosing the discount level from among those
identified in step d to increase BPA's revenues during
the incentive rate period, BPA will consider the relative
level of those revenue increases but may also consider
other factors such as:
1. the effect on the commitment levels of
(a) the take -or -pay risk facing the DSIs, and
(b) the additional economic benefits to the
DSIs of a reduced rate applying to all
their loads, including those portions that
would operate even at higher rates;
2. the sensitivity of the results to small changes
in assumptions; and
3. revenue impacts outside the incentive rate
period including, but not limited to:
(a) the time lag and additional cost
associated with changing a plant's
operating status (i.e., shutting down or
bringing on a potline), and
(b) the forestalling of potential plant
closure.
f. The Study shall indicate the level of the DSI load
required in order to trigger implementing the
Incentive rate. The required load may or may not
precisely equal the load projected for that discount
level in the ASM.
2. Contractual Arrangements Relating to Implementation of the
Industrial Incentive Rate
BPA and each interested DSI customer shall negotiate and
execute a generic contract regarding the sale of Industrial
Firm Power under the Industrial Incentive Rate. The
information specified in (a), (b), (c) and (d) below, shall be
specified in an exhibit to the contract. Because all of this
information may not be available until an Industrial Incentive
Rate is offered to the DSIs, this exhibit shall be attached to
the contract only after BPA adopts an Incentive Rate:
a. the demand and energy charges for the Industrial
Incentive Rate,
b. the Committed Demand and Committed Energy for each DSI
customer electing to purchase under the Industrial
Incentive Rate, and
c. the time period for which the rate is to be effective.
d. the extent to which purchases above the Committed Demand
and Committed Energy may be made at the Industrial
Incentive Rate.
3. Industrial Incentive Rate Implementation Procedure
a. If the results of the Study indicate that the Industrial
Incentive Rate might reasonably be expected to trigger
given appropriate commitment levels from the DSIs, BPA
shall notify its customers that it is proposing to offer
the DSIs the opportunity to purchase Industrial Firm
Power under the Industrial Incentive Rate, providing the
minimum commitment level is met. BPA shall provide a
copy of the Study to all of its customers and shall make
supporting documentation available to interested parties.
b. BPA shall accept comments on the proposed rate and
supporting Study for a period of no less than 3 weeks
(21 days) from the date of the notice to the customers.
BPA may elect to seek comments on its draft contract as
well.
c. BPA shall evaluate the comments received and revise its
Study (if necessary) to reflect the comments. If the
updated Study supports implementation of an Incentive
rate, BPA shall solicit, from each DSI, its Committed
Demand and Committed Energy at the specified rate or
rates. In the solicitation, BPA shall notify the DSIs of
the period for which the Industrial Incentive Rate is
proposed to be effective and the level of each of the
charges comprising any Industrial Incentive Rate. BPA
reserves the right to impose specific requirements on the
minimum commitment level solicited from each of the
individual DSIs, including but not limited to:
(1) confining the Industrial Incentive Rate to only the
committed load, with service above that level to be
charged the Industrial Standard Rate; or
(2) requiring a percentage of plant capacity or
Operating Demand. The DSI response to this
solicitation shall be contractually binding, and the
response shall be attached as an exhibit to the
generic contract upon adoption of the proposed
Industrial Incentive rate.
d. If BPA receives a commitment level from the DSIs equal to
or greater than the commitment level determined to be the
minimum acceptable level, BPA shall implement the
Industrial Incentive Rate.
e. BPA shall publish a Record of Decision regarding any
decision to implement the Industrial Incentive Rate.
That Record shall be made available to interested parties.
F. Restriction of Deliveries
Deliveries of capacity and /or energy to any purchaser may be
restricted when operation of the facilities used by BPA to service
such purchaser is:
1. suspended,
2. interrupted,
3. interfered with,
4. curtailed, or
5. restricted
SECTION VI. BILLING INFORMATION
by the occurrence of any condition described in the
Uncontrollable Forces or Continuity of Service sections of the
General Contract Provisions of the power sales contract.
A. Determination of Estimated Billing Data
If the amounts of capacity, energy, or the 60- minute integrated
demands for energy purchased from BPA must be estimated from data
other than metered or scheduled quantities, historical patterns,
and pertinent weather data, BPA and the purchaser will agree on
billing data to be used in preparing the bill. If the parties
cannot agree on estimated billing quantities, derived by any
method, a determination binding on both parties shall be made in
accordance with the arbitration provisions of the power sales
contract.
B. Load Shift and Outage Reports
Load shift and outage reports must be submitted to BPA within
4 days of the corresponding load shift or outage. Reports may be
made by telephone, mail, or other electronic processes where
available. Customers are not required to submit reports for load
shifts or outages caused by BPA switching, maintenance, or
equipment failure. If customer reports are not received in a timely
manner, BPA has the option to withhold load shift or outage credit.
C. Billing for New Large Single Loads
Any BPA customer whose total load includes one or more New Large
Single Loads (NLSL) as defined by section 3.(13) of the Northwest
Power Act or as determined by section 8 of the purchaser's power
sales contract shall be billed for the NLSL(s) at the New Resource
Firm Power Rate. The power requirements associated with the NLSL
shall be established in a manner consistent with the provisions of
this section.
The purchaser shall warrant to BPA that NLSLs are separately
metered. The metering must include provisions for determining:
1. the NLSL demand during BPA's diurnal capacity billing periods,
2. the NLSL energy during BPA's energy billing periods, and
3. the NLSL reactive energy for the billing month.
The design for the metering equipment for the NLSL must be approved
by BPA. Testing and inspections of such metering installations
shall be as provided in the General Contract Provisions.
On a monthly basis, each purchaser of New Resource Firm Power shall
report to BPA the quantity of power used by the NLSL during the
purchaser's billing period. Data provided to BPA by the purchaser
must be submitted to BPA within 2 normal working days of the date
the purchaser reads the meters. BPA may elect to adjust the NLSL
data for losses from the point of metering to the closest BPA point
of delivery for the purchaser.
D. Determination of Measured Demand
1. For points of delivery with fully operational metering under
the Remote Metering System (RMS), demand shall be measured
from 0000 hours on the first day of the billing period through
2400 hours on the last day of the billing period.
2. For points of delivery that do not have RMS metering, measured
demand shall be adjusted to arrive at billing demand by
adjusting all measured quantities back to the most recent day
on which there is a 2400 hour reading on the demand meter.
E. Determination of Measured Energy
1. For points of delivery with fully operational metering under
RMS, energy shall be measured from 0000 hours on the first day
of the billing period through 2400 hours on the last day of
the billing period.
2. For points of delivery that do not have RMS metering, measured
energy shall be the quantity of usage recorded on the meter
between meter readings.
F. Billing Month
Meters normally will be read and bills computed at intervals of
1 month. A month is defined as the interval between meter reading
dates which normally will be approximately 30 days. If service is
for less than or more than the normal billing month, the monthly
charges stated in the applicable rate schedule shall be adjusted
appropriately.
The calendar month in which the purchaser's meter is scheduled to
be read determines the billing month. (Thus, a bill associated
with a meter scheduled to be read on April 10th would be an April
bill.) The charges for the winter and summer periods identified in
the rate schedules apply to the purchaser's billing months. Annual
changes in a purchaser's low density discounts take effect with the
January billing month. (Retroactive billing for the LDD may be
required if the data are not available by the January billing date.)
G. Payment of Bills
Bills for power shall be rendered monthly by BPA. Failure to
receive a bill shall not release the purchaser from liability for
payment. Bills for amounts due BPA of $50,000 or more must be paid
by direct wire transfer; customers who expect that their average
monthly bill will not exceed $50,000 and who expect special
difficulties in meeting this requirement may request, and BPA may
approve, an exemption from this requirement. Bills for amounts due
BPA under $50,000 may be paid by direct wire transfer or mailed to
the Bonneville Power Administration, P.O. Box 6040, Portland,
Oregon 97228 -6040, or to another location as directed by BPA. The
procedures to be followed in making direct wire transfers will be
provided by the Office of Financial Management and updated as
necessary.
1. Computation of Bills
Demand and energy billings for power purchased under each rate
schedule shall be rounded to whole dollar amounts, by
eliminating any amount which is less than 50 cents and
increasing any amount from 50 cents through 99 cents to the
next higher dollar.
2. Estimated Bilis
At its option, BPA may elect to render an estimated bill for
that month to be followed at a subsequent billing date by a
final bill. Such estimated bill shall have the validity of
and be subject to the same payment provisions as a final bill.
3. Due Date
Bilis shall be due by close of business on the 20th day after
the date of the bill (due date). This requirement holds also
for revised bills (see section 6 below). Should the 20th day
be a Saturday, Sunday, or holiday (as celebrated by the
purchaser), the due date shall be the next following business
day.
4. Late Payment
Bills not paid in full on or before close of business on the
due date shall be subject to a penalty charge which shall be
the greater of one fourth percent (0.25%) of the unpaid amount
or $50. In addition, an interest charge of one twentieth
percent (0.05,) shall be applied each day to the sum of the
unpaid amount and the penalty charge. This interest charge
shall be assessed on a daily basis until such time as the
unpaid amount and penalty charge are paid in full. BPA will
bill the customer for the late payment interest charge on the
purchaser's next power bill.
Remittances received by mail will be accepted without
assessment of the charges referred to in the preceding
paragraph provided the postmark indicates the payment was
mailed on or before the due date. In order to avoid
assessment of late payment charges for metered mail received
subsequent to the due date, the payment must bear a postal
department cancellation which demonstrates that payment was
mailed on or before the due date.
Whenever a power bill or a portion thereof remains unpaid
subsequent to the due date and after giving 30 days advance
notice in writing, BPA may cancel the contract for service to
the purchaser. However, such cancellation shall not affect
the purchaser's liability for any charges accrued prior
thereto under such contract.
5. Disputed Billings
In the event of a disputed billing, full payment shall be
rendered to BPA and the disputed amount noted. Disputed
amounts are subject to the late payment provisions specified
above. BPA shall separately account for the disputed amount.
If it is determined that the purchaser is entitled to the
disputed amount, BPA shall refund the disputed amount with
interest, as determined by BPA's Office of Financial
Management.
6. Revised Bills
As necessary, BPA may render a revised bill. Any revised bill
shall replace all previous bills issued by BPA that pertain to
a specified customer for a specified billing period.
The date of the revised bill shall be determined as follows:
a. If the amount of the revised bill is equal to or less
than the amount of the bill which it is replacing, the
revised bill shall have the same date as the replaced
bill.
b. If the amount of the revised bill is greater than the
amount of the bill which it is replacing, the date of the
revised bill shall be its date of issue.
GCP Form PSC' -2
Index to Sections
Section Page
I. RELATING TO ALL PURCHASERS
A. IN REFERENCE TO MEANING
1. Definitions 1
2. Interpretation 4
B. IN REFERENCE TO COMPUTATION OF CHARGES
3. Measurements 5
4. Adjustment for Change of Conditions 5
5. Adjustment for Inaccurate Metering 5
6. Adjustment for Unbalanced Phase Demands 6
7. Reducing Charges for Interruptions 6
C. IN REFERENCE TO RATES
GENERAL CONTRACT PROVISIONS
8. Equitable Adjustment of Rates 7
Exhibit B
2/7/84
D. IN REFERENCE TO DELIVERY OF POWER
9. Character of Service 15
10. Point(s) of Delivery and Delivery Voltage 15
11. Metered Quantities 15
Index to Sections (Continued)
Section Page
12. Where Additional Facilities Required 15
13. Uncontrollable Forces 16
14. Continuity of Service 16
15. Delivery by Transfer 17
E. IN REFERENCE TO PAYMENT FOR POWER
16. Determination of and Assignment of Measured Demand 18
17. Billing of Multiple Points of Delivery 18
18. Payment of Bills 19
19. Determination of Estimated Billing Data 20
20. Average Power Factor 20
F. IN REFERENCE TO USE OF POWER
21. Changes in Requirements or Characteristics 21
22. Electric Disturbance 21
23. Harmonic Control 23
24. Balancing Phase Demands 23
G. IN REFERENCE TO FACILITIES
25. Measurements and Installation of Meters 23
26. Tests of Metering Installations 24
27. Permits 24
28. Ownership of Facilities 25
i i
t
b
Index to Sections (Continued)
Section Page
29. Inspection of Facilities 25
30. Facilities for Maintenance of Voltage 26
H. MISCELLANEOUS PROVISIONS
31. General Environmental Provision 26
32. Dispute Resolution and Arbitration 28
33. Enforcement of Rights for Benefit of Transferors 30
34. Net Billing 31
35. Contract Work Hours and Safety Standards 31
36. Convict Labor 33
37. Equal Employment Opportunity 33
38. Additional Provisions 35
39. Assignment of Contract 36
40. Waiver of Default 36
41. Notices and Computation of Time 36
42. Interest of Member of Congress 37
43. Priority of Pacific Northwest Customers 37
44. Resource Acquisition and Management 38
45. Cooperation with Regional Council 39
46. Rights of the Purchaser 39
II. RELATING ONLY TO PREFERENCE AGENCIES
47. Separation of Electric Operations and Funds
(All Public Agencies) 40
48. Statement of General Policies and Practices (Cities) 40
Section
Index to Sections (Continued)
49. Approval of Contract 42
50. Prior Demands 42
III. RELATING ONLY TO PUBLIC BODY, COOPERATIVE, FEDERAL AGENCY, AND
INVESTOR -OWNED UTILITY PURCHASERS
A. IN REFERENCE TO COMPUTATION OF CHARGES
51. Effect of Reduction of Contract Demand 43
52. Combining Deliveries Coincidentally 43
53. Combining Deliveries Noncoincidentally 44
54. Power Factor Adjustment 45
B. IN REFERENCE TO PURCHASERS' OPERATING POLICIES
55. Retail Rates 1 45
C. IN REFERENCE TO USE OF POWER
56. Resale of Power 47
D. IN REFERENCE ONLY TO PURCHASERS WITH GENERATING FACILITIES
57. Nonfirm Deliveries 47
58.' Emergency or Breakdown Relief 48
59. Effect on Generating Utility by Direct Service
Industrial Customer Power Sales Contract Provisions 48
iv
Page r
Index to Sections (Continued)
Section
IV. RELATING ONLY TO DIRECT SERVICE INDUSTRY PURCHASERS
A. IN REFERENCE TO COMPUTATION OF CHARGES
Page
60. Demands 49
B. IN REFERENCE TO PURCHASE
61. Use and Resale of Power 49
v
I. RELATING TO ALL PURCHASERS
A. IN REFERENCE TO MEANING
1. Definitions. The definitions in the body of this contract and the
following additional definitions apply to this exhibit.
(a) "Billing Month," when used with respect to a Direct Service
Industrial Customer, means a calendar month.
(b) "Contractor" means the Purchaser.
(c) "Direct Service Industrial Customer" means a purchaser of industrial
firm power, modified firm power, or similar classes of power under contracts
providing for the purchase of any such class of power directly from Bonneville.
(d) "Federal System" or "Federal System Facilities" means the facilities
of the Federal Columbia River Power System, which for the purposes of this
contract shall be deemed to include the generating facilities of the
Government in the Pacific Northwest for which Bonneville is designated as
marketing agent; the facilities of the Government under the jurisdiction of
Bonneville; and any other facilities:
(1) from which Bonneville receives all or a portion of the
generating capability (other than station service) for use in meeting
Bonneville's loads, such facilities being included only to the extent
Bonneville has the right to receive such capability; provided, however,
that "Bonneville's loads" shall not include that portion of the loads of
any Bonneville customer which are served by a nonfederal generating
resource purchased or owned directly by such customer which may be
scheduled by Bonneville;
(2) which Bonneville may use under contract, or license; or
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(3) to the extent of the rights acquired by Bonneville pursuant to
the Treaty, between the Government and Canada, relating to the cooperative
development of water resources of the Columbia River Basin, signed in
Washington, D.C., on January 17, 1961.
(e) "Federal Energy Regulatory Commission" means the Federal Energy
Regulatory Commission or its successor.
(f) "Measured Demand" when used with respect to a Direct Service
Industrial Purchaser means the largest of the Integrated Demands, adjusted as
appropriate to the Point of Delivery, for the time periods for which there is a
demand charge specified in the applicable rate schedule in the Wholesale Power
Rate Schedule and General Rate Schedule Provisions Exhibit during a Billing
Month.
(g) "Point(s) of Delivery" means the point(s) of delivery listed either in
the Points of Delivery Exhibit to this contract or in the body of this contract.
(h) "P.L. 96 -501" means the Regional Act.
(i) "Transferor" means an entity which receives Bonneville's power or
energy at one point on such entity's system and makes such power or energy
available at another point on its system for the account of Bonneville.
(j) "Uncontrollable Forces" means:
(1) strikes or work stoppage affecting the operation of the
Purchaser's works, system, or other physical facilities or of the Federal
System Facilities or the physical facilities of any Transferor upon which
such operation is completely dependent; the term "strikes or work stoppage"
shall be deemed to include threats of imminent strikes or work stoppage
which reasonably require a party or Transferor to restrict or terminate its
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operations to prevent substantial loss or damage to its works, system, or
other physical facilities; or
(2) such of the following events as the Purchaser or Bonneville or
any Transferor by exercise of reasonable diligence and foresight, could not
reasonably have been expected to avoid:
(A) events, reasonably beyond the control of either party or any
Transferor, causing failure, damage, or destruction of any works,
system or facilities of such party or Transferor; the word "failure"
shall be deemed to include interruption of, or interference with, the
actual operation of such works, system, or facilities;
(B) floods or other conditions caused by nature which limit or
prevent the operation of, or which constitute an imminent threat of
damage to, any such works, system, or facilities; and
(C) orders and temporary or permanent injunctions which prevent
operation, in whole or in part, of the works, system, or facilities of
either party or any Transferor, and which are issued in any bona fide
proceeding by:
(i) any duly constituted court of general jurisdiction; or
(ii) any administrative agency or officer, other than
Bonneville or its officers, provided by law (a) if said party or
Transferor has no right to a review of the validity of such order
by a court of competent jurisdiction; or (b) if such order is
operative and effective unless suspended, set aside, or annulled
by a court of competent jurisdiction and such order is not
suspended, set aside, or annulled in a judicial proceeding
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prosecuted by said party or Transferor in good faith; provided,
however, that if such order is suspended, set aside, or annulled
in such a judicial proceeding, it shall be deemed to be an
"uncontrollable force" for the period during which it is in
effect; provided, further, that said party or Transferor, shall
not be required to prosecute such a proceeding, in order to have
the benefits of this section, if the parties agree that there is
no valid basis for contesting the order.
The term "operation" as used in this subsection shall be
deemed to include construction, if construction is required to
implement the contract and is specified therein.
(k) "Utility" means a party to a residential purchase and sale agreement
offered pursuant to section 5(c) of P.L. 96 -501 which shall also be referred to
as the "Purchaser" for the purposes of this exhibit.
2. Interpretation.
(a) The provisions in this exhibit shall be deemed to be a part of the
contract body to which they are an exhibit. If a provision in such contract
body is in conflict with a provision contained in this exhibit, the former
shall prevail.
(b) If a provision in the General Rate Schedule Provisions incorporated in
the Wholesale Power Rate Schedules and General Rate Schedule Provisions Exhibit
is in conflibt with a provision contained in this exhibit or the contract body,
this exhibit or the contract body shall prevail.
(c) Nothing contained in this contract shall, in any manner, be construed
to abridge, limit, or deprive any party hereto of any means of enforcing any
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remedy, either at law or in equity, for the breach of any of the provisions of
this contract which it would otherwise have.
B. IN REFERENCE TO COMPUTATION OF CHARGES
3. Measurements. Each measurement of each meter mentioned in this
contract shall be the measurement automatically recorded by such meter or, at
the request of either party, the measurement as mutually determined by the best
available information.
If it is provided in this contract that measurements made by any of
the meters specified therein are to be adjusted for losses, such adjustments
shall be made by using factors, or by compensating the meters, as agreed upon
by the parties hereto. If changes in conditions occur which substantially
affect any such loss factor or compensation, it will be changed in a manner
which will conform to such change in conditions.
4. Adjustment for Change of Conditions. Changes in conditions may occur
after the date of execution of this contract which substantially affect factors
required by this contract to be used in determining (a) the charge for a
service or for use of facilities provided by Bonneville other than charges for
the sale of electric power and energy; or (b) the amount of losses from the
transmission or transformation of electric power or energy. Such factors will
then be changed in an equitable manner which will conform to such changes in
conditions.
5. Adjustment for Inaccurate Metering. If any meter mentioned in this
contract fails to register, if the measurement made by such meter during a test
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made as provided in section 26 hereof varies by more than one percent from the
measurement made by the standard meter used in such test or if an error in
meter reading occurs, adjustment shall be made correcting all measurements for
the actual period during which such inaccurate measurements were made, if such
period can be determined. If such period cannot be determined the adjustment
shall be made for the period immediately preceding the test of such meter which
is equal to the lesser of (a) one -half the time from the date of the last
preceding test of such meter; or (b) 6 months. Such corrected measurements
shall be used to recompute the amounts due from the Purchaser for the electric
power and energy made available under this contract during such period and
shall be used, when applicable, in future billings to the Purchaser. If the
total amount due from the Purchaser for such period as recomputed varies from
the total amount previously billed by Bonneville, Bonneville shall adjust the
wholesale power bill(s) as soon as practicable.
6. Adjustment for Unbalanced Phase Demands. If the Purchaser fails to
make promptly the changes mentioned in section 24 hereof, Bonneville may, after
giving written notice one month in advance, determine that the Pleasured Demand
of the Purchaser at the Point of Delivery in question during each month
thereafter, until such changes are made, is equal to the product obtained by
multiplying by three the largest of the Integrated Demands on any phase
adjusted as appropriate to such point during such month.
7. Reducing Charges for Interruptions. If deliveries of electric power
and energy to the Purchaser are suspended, interrupted, interfered with or
curtailed due to Uncontrollable Forces on either the Purchaser's system, the
Federal System or any Transferor's system, or if Bonneville or any Transferor
interrupts or reduces deliveries to the Purchaser for any of the reasons stated
in section 14 hereof, the charges for power shall be appropriately reduced.
Partial interruptions shall be converted to an equivalent outage of total
Measured Demand. No total outage or equivalent outage of less than 30 minutes
duration shall be considered for computation of such reduction in charges.
C. IN REFERENCE TO RATES
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8. Equitable Adjustment of Rates.
(a) Bonneville shall establish, periodically review and revise rates for
the sale and disposition of electric power, capacity or energy sold pursuant to
the terms of this contract. Such rates shall be established in accordance with
applicable law.
(b) As used in this section, the words "Rate Adjustment Date" mean any
date as specified by Bonneville in a notice of intent to file revised rates as
published in the Federal Register; provided, however, that such date shall not
occur sooner than (1) nine months from the date that such notice of intent is
published; or (2) twelve months from any previous Rate Adjustment Date. By
giving written notice to the Purchaser 45 days prior to such Rate Adjustment
Date, Bonneville may delay such Rate Adjustment Date for up to 90 days if
Bonneville determines either that the revenue level of the proposed rates
differs by more than five percent from the revenue requirements indicated by
most recent repayment studies entered in the hearings record or that external
events beyond Bonneville's control will prevent Bonneville from meeting such
Rate Adjustment Date. Bonneville may cancel a notice of intent to file revised
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rates at any time (1) by written notice to the Purchaser; or (2) by publishing
in the Federal Register a new notice of intent to file revised rates which
specifically cancels a previous notice.
(c) The Purchaser shall pay Bonneville for the electric power and energy
made available under this contract during the period commencing on each Rate
Adjustment Date and ending at the beginning of the next Rate Adjustment Date at
the rate specified in any rate schedule available at the beginning of such
period for service of the class, quality, and type provided for in this
contract, and in accordance with the terms thereof, and of the General Rate
Schedule Provisions as changed with, incorporated in or referred to in such
rate schedule. New rates shall not be effective on any Rate Adjustment Date
unless they have been approved on a final or interim basis by a governmental
agency designated by law to approve Bonneville rates. Rates shall be applied
in accordance with the terms thereof, the General Rate Schedule Provisions as
changed with, incorporated in or referred to in such rate schedule and the
terms of this contract.
(d) (1). Bonneville reserves the authority to impose a conservation
surcharge as provided by section 4(f) and 7(h) of P.L. 96 -501. The
Purchaser shall pay the amount of any such surcharge so imposed as part of
its payment to Bonneville for wholesale power.
(2) Bonneville and the Purchaser recognize that cost effective model
conservation standards are to be adopted by the Pacific Northwest Electric
Power and Conservation Planning Council "the Council pursuant to
P.L. 96 -501, and that, in accordance with section 4(f) of P.L. 96 -501, such
standards are required to include, but are not limited to, standards
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applicable to Customer and governmental conservation programs. Bonneville
will make available financial assistance to implement such cost effective
standards pursuant to its obligations under section 6(a)(1) and 6(e)(1) of
P.L. 96 -501, and as described at page 43 of the Report of the Committee,on
Interior Affairs of the U.S. House of Representatives (Report No. 96 -976,
Part II) regarding section 4(f).
(3) Upon adoption of a methodology as provided in section 4(f)(2) and
section 4(e)(3)(G) of P.L. 96 -501, Bonneville will give notice of intent to
adopt a policy, provide opportunity for public comment, and publish draft
procedures in the Federal Register for imposing surcharges. Such proposed
policy shall include:
(A) standards to be met before Bonneville will excuse surcharges
which would otherwise be appropriate, consistent with Bonneville's
obligations to implement cost effective conservation measures to the
maximum extent practicable;
(B) that Bonneville will impose surcharges to the extent not
excused or suspended under the terms of the policy;
(C) an opportunity for interested persons to present views,
data, questions, and arguments to Bonneville relevant to the
imposition of surcharges in specific instances, and the adequacy of
financial assistance made available by Bonneville;
(D) that surcharges imposed will be continued to the extent and
for the period projected energy savings attributable to cost effective
model conservation standards are not achieved;
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(E) for recovery from the Purchaser of the additional costs
(including increases in the Utility's average system cost) that
Bonneville will incur because the projected energy savings
attributable to model conservation standards have not been achieved,
subject to the limitations set forth in sections 4(f)(1) and 4(f)(2)
of P.L. 96 -501; provided, however, that surcharges will not be levied
as a result of an increase in a Utility's average system cost except
to the extent that the Utility failed to implement conservation
measures that are designed to be cost effective for its Consumers in
terms of the electric rates its Consumers pay.
(4) Nothing in this section shall waive or prejudice the right of any
person or Customer to assert any of its legal rights with respect to the
model conservation standards, their application, or the imposition of any
surcharges.
(e) Bonneville's wholesale power rates established on any Rate Adjustment
Date shall be developed consistent with the provisions of section 7 of
P.L. 96 -501. Bonneville shall develop in consultation with its utility
Customers and shall publish methodologies as required for implementing
section 7(b)(2).
(f) Power Cost Allocations After July 1, 1985. Power cost allocations
among Customer classes will follow the same methods set forth in Appendix B of
the Senate Report S.885 (S. Rep. 272, 96 Cong., 1st Sess. 1979) for the period
after July 1, 1985, and in the same general manner as further explained in the
1981 Bonneville wholesale power rate case by Exhibit U submitted in such rate
case and the accompanying Bonneville testimony.
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(g) Bonneville shall establish and apply a discount to the rate or rates
of utility Customers with low system densities. The level of such discount and
the standards for determining which Customers qualify for such discount shall
be established pursuant to the rate adjustment process described in this
section.
After five years of experience in the application of such discount,
Bonneville shall review the level and standards of such discount. Such review
will occur independent of the rate adjustment process, and at such time
Bonneville and the Purchaser may consider an amendment to this contract to fix
the level of the discount and the standards for Customer qualification for the
balance of the term of this contract, or such other amendments as the parties
deem appropriate. Any such amendments shall be by mutual agreement of
Bonneville and the Purchaser.
(h) Individual Customer Rate Limit Under Section 7(f) of P.L. 96 -501.
(1) The provisions of this subsection shall apply to any Customer
from whom or on behalf of whom Bonneville has acquired a resource pursuant
to section 6 of P.L. 96 -501, if and to the extent such Customer purchases
Firm Power from Bonneville at a rate established pursuant to section 7(f)
of P.L. 96 -501.
(2) The rate established pursuant to section 7(f) charged to any such
Customer for an amount of Firm Power not exceeding that acquired by
Bonneville from or on behalf of such Customer, exclusive of any costs
allocated to such rate in accordance with sections 7(b)(3), 7(g), and 7(h)
of P.L. 96 -501, shall not exceed the average cost of the resources acquired
by Bonneville from such Customer, exclusive of resources whose costs are
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allocated by Bonneville pursuant to section 7(g) and any resources acquired
under section 5(c). The average cost of such resources shall be adjusted
for any additional costs such Customer would have incurred in order to
provide itself the same quantity and quality of power from such resources
if such resources had not been acquired by Bonneville.
(3) Bonneville shall develop a methodology for performing the
adjustments required by paragraph (2) by procedures comparable to those
employed in establishing the methodology referred to in subsection (e)
above.
(4) Costs not recovered from any Customer because of the provisions
of paragraph (2) shall be recovered from other Customers through rates
established pursuant to section 7(f), to the extent that such recovery can
be made without exceeding the allowable section 7(f) rates for such other
Customers pursuant to paragraph (2). To the extent such recovery cannot be
made without exceeding the allowable section 7(f) rates established
pursuant to paragraph (2), the unrecovered balance shall be spread on a pro
rata kilowatt and kilowatthour basis among all Firm Power purchased by
Customers under rates established pursuant to section 7(f) and not be borne
by other Customer classes under rates established pursuant to sections 7(b)
and 7(c) of P.L. 96 -501. The pro rata recovery shall be limited to rates
established pursuant to section 7(f) and shall not increase the cost of the
"other resources" specified in section 7(b)(1) of P.L. 96 -501.
(i) Rates for Firm Power sold pursuant to sections 14 and 17 of the
utility power sales contract shall be established in such a fashion that the
Purchaser shall not be billed for Firm Power during any twelve month rate
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period in excess of the amount to which the Purchaser was entitled to take
during such twelve -month period.
(j) Allocation of Certain Section 7(g) Costs. Costs of uncontrollable
events, including but not limited to costs of a terminated generating facility,
and costs of experimental resources, in excess of the cost of cost effective
resources, shall be allocated pursuant to section 7(g) of P.L. 96 -501 and shall
be allocated among Customers on a uniform per kilowatt or kilowatthour basis.
Beginning on July 1, 1985, such costs and other costs allocated pursuant to
section 7(g) of P.L. 96 -501 will be reflected in the rates charged
Direct Service Industrial Customers only to the extent they modify Bonneville's
wholesale power rates to public body and cooperative Customers for power that
serves such Customers' retail industrial Consumers.
(k) Bonneville's wholesale power rates shall include the amount by which
the cost of resources acquired either at the request of the Purchaser pursuant
to section 17(j) of the utility power sales contract or at the request of other
Customers under similar power sales contracts exceed the estimated revenues
Bonneville expects to recover for sale of such power pursuant to
section 19(b)(1)(E) of such contract or similar power sales contracts. Such
costs shall be recovered from Bonneville's Customers pursuant to section 7(g)
of P.L. 96 -501, as the cost of an uncontrollable event.
(1) Allocation of Exchange Resources. The energy or capacity, or both,
associated with resources acquired by Bonneville pursuant to section 5(c)(2) of
P.L. 96 -501 shall be allocated at the cost thereof to Customers purchasing Firm
Power under rates established pursuant to section 7(b) of P.L. 96 -501 to the
extent that the load requirements of such Customers exceed the amount of
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Federal base system resources, including replacements thereto, determined to be
available for ratemaking purposes. Such energy and capacity allocated to
Customers purchasing Firm Power under rates established pursuant to
section 7(f) of P.L. 96 -501 shall be allocated at the cost thereof. The total
cost of resources acquired under section 5(c) of P.L. 96 -501 allocated to
Direct Service Industrial Customers purchasing power under rates established
pursuant to section 7(c)(1)(A) of P.L. 96 -501 shall not exceed the average
costs associated with the amount of such resources determined by Bonneville to
be required to serve that portion of the firm load of Direct Service Industrial
Customers not served by other resources.
(m) Revenue obtained by Bonneville through the recapture of costs
associated with section 5(c)(7)(C) of P.L. 96 -501 shall be equitably allocated
through Bonneville's wholesale power rates to Customer classes in proportion to
the respective prior payment of such costs by such classes through Bonneville's
wholesale power rates.
(n) Bonneville shall consult with the Purchaser and other Customers prior
to making a determination to replace reductions in the capability of the
Federal base system resources and shall make such replacements in an
economically prudent manner. Resources acquired as a replacement shall not be
from resources purchased by Bonneville under section 5(c) of P.L. 96 -501. All
or a portion of a resource acquired from or on behalf of the Purchaser may be
used as a replacement according to the terms specified in the resource purchase
agreement. Bonneville may replace reductions in the capability of the Federal
base system resources for plant delays when and to the extent needed to meet
the sum of (1) Bonneville's obligation to supply Firm Power during an Operating
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Year to public bodies, cooperatives and Federal agencies; and (2) Bonneville's
firm contractual obligations with its other Customers in place on the effective
date of P.L. 96 -501 and which contracts are or would have been effective during
such Operating Year.
D. IN REFERENCE TO DELIVERY OF POWER
9. Character of Service. Unless otherwise specifically provided for in
the contract, electric power or energy made available pursuant to this contract
shall be in the form of three -phase current, alternating at a nominal frequency
of 60 hertz.
10. Point(s) of Delivery and Delivery Voltage. Electric power and energy
shall be delivered to each Purchaser at the Point(s) of Delivery and at such
voltage(s) as specified. Unless otherwise agreed, delivery at more than one
voltage shall constitute delivery at more than one point.
11. Metered Quantities. The amount(s) of energy, Integrated Demands
therefor and amount(s) of reactive energy delivered to the Point(s) of Delivery
during each month shall be determined from measurements made by meters
installed for such Point(s) of Delivery in the circuit specified.
12. Where Additional Facilities Required. If additional delivery point
facilities must be constructed or installed to enable Bonneville to supply any
increase in the Purchaser's contract demand, or in the Purchaser's requirements
if Bonneville agrees by this contract to supply such requirements, Bonneville
shall not be required to provide such additional facilities unless the parties
mutually agree: (a) that Bonneville's providing such facilities is in
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accordance with its customer service policies; (b) that reasonable utilization
has been made of existing facilities; and (c) that reasonable utilization of
such additional facilities will be assured. If the parties so agree,
Bonneville nevertheless shall not become obligated to supply such increase in
such demand or requirements until such period of time has elapsed as may be
reasonably necessary to complete the installation of such additional facilities.
13. Uncontrollable Forces. Each party shall notify the other as soon as
possible of any Uncontrollable Forces which may in any way affect the delivery
of power hereunder. In the event the operations of either party are
interrupted or curtailed due to such Uncontrollable Forces, such party shall
exercise due diligence to reinstate such operations with reasonable dispatch.
14. Continuity of Service. The Purchaser, Bonneville or a Transferor may
temporarily interrupt or reduce deliveries of electric power or energy if the
Purchaser, Bonneville or the Transferor determines that such interruption or
reduction is necessary or desirable in case of system emergencies, or in order
to install equipment in, make repairs to, make replacements within, make
investigations and inspections of, or perform other maintenance work on, the
Purchaser's facilities, the Federal System or the Transferor's system. Except
in case of emergency and in order that the Purchaser's operations will not be
unreasonably interfered with, Bonneville shall give notice to the Purchaser of
any such interruption or reduction, the reason therefor, and the probable
duration thereof to the extent Bonneville has knowledge thereof. The Purchaser
or Bonneville shall effect the use of temporary facilities or equipment to
minimize the effect of any such interruption or outage to the extent reasonable
or appropriate.
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15. Delivery by Transfer. If it is provided in this contract that
delivery to the Purchaser at any Point of Delivery will be made by transfer
over the facilities of a Transferor or Transferors:
(a) Bonneville shall be obligated to make available to the Purchaser at
such point only such amounts of electric power and energy as are made available
to the Purchaser by such Transferor or Transferors at such point, and the
obligation of Bonneville to make electric power and energy available to the
Purchaser at such point shall be in all respects subject to all provisions
contained in the agreement or agreements executed, or to be executed, if not
already in effect, by Bonneville and such Transferor or Transferors providing
for such transfer;
(b) Bonneville shall use its best efforts to effect a quality of service
to the Purchaser comparable to that provided under direct service from
Bonneville; and
(c) Bonneville's right to terminate deliveries at such point, under the
agreement or agreements providing for such transfer, shall not be exercised
while such Transferor or Transferors meet their obligations to make such
deliveries under such agreement or agreements unless (1) the Purchaser consents
thereto; or (2) Bonneville determines that the Purchaser's requirements for
electric power and energy at such point may be adequately supplied under
reasonable conditions and circumstances at another point or points (A) directly
from the Federal System (B) indirectly from the facilities of another
Transferor or Transferors, or (C) both.
E. IN REFERENCE TO PAYMENT FOR POLDER
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16. Determination of and Assignment of Measured Demand. Bonneville in
determining Measured Demand shall exclude any abnormal Integrated Demand or
Measured Amount due to or resulting from (a) emergencies or breakdowns on, or
maintenance of, the Federal System Facilities; and (b) emergencies on the
Purchaser's facilities to the extent Bonneville determines that such facilities
have been adequately maintained and prudently operated.
If timely determination of Measured Demand cannot be made, such
determination shall be made in accordance with section 19 below.
Where Bonneville delivers, pursuant to this or other contracts, more
than one class of electric power to the Purchaser at any Point of Delivery, the
portion of the Measured Demand assigned to each such class of power shall be as
specified in such contracts. Any portion of Measured Demand which is not
assigned to other classes of power delivered pursuant to this or other
contracts shall be deemed to be a Firm Power delivery under this contract.
17. Billing At Multiple Points of Delivery. For electric power or energy
made available hereunder to the Purchaser at more than one Point of Delivery,
the Purchaser shall be billed for each Point of Delivery separately on a
non coincidental basis under the applicable rate schedule in the Wholesale
Power Rate Schedules and General Rate Schedule Provisions Exhibit, unless
otherwise provided herein. The Points of Delivery Exhibit may provide for
combined billing on a coincidental basis under specified conditions and terms
either when delivery at more than one point is beneficial to Bonneville or when
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the flow of power at several Points of Delivery is reasonably beyond the
control of the Purchaser.
If deliveries at more than one Point of Delivery are billed on a
coincidental basis for the convenience of the Purchaser, a charge shall be made
for the diversity among Measured Demands at such Points of Delivery. Charges
for diversity shall be specified in the Special Provisions Exhibit and
determined in a uniform manner among Customers.
At any rate adjustment date after January 1, 1982, Bonneville may
establish its wholesale power rate schedules applicable to this contract using
Customers' coincidental peak demands as the basis for proportioning its revenue
recovery. In such event all diversity factors or charges applicable to
Measured Demands determined on a coincidental basis shall be invalid and
appropriate factors to reduce Measured Demands determined on a non coincidental
basis shall be developed and applied.
18. Payment of Bills. Bills for power shall be rendered monthly and shall
-be payable at Bonneville's headquarters. Failure to receive a bill shall not
release the Purchaser from liability for payment. Each calculated monetary
amount in a wholesale power bill shall be rounded to a whole dollar amount, by
elimination of any amount of less than 50 cents and increasing any amount from
50 cents through 99 cents to the next higher dollar.
If Bonneville is unable to render the Purchaser a timely monthly bill
which includes a full disclosure of all billing factors, it may elect to render
an estimated bill for that month to be followed by the final bill. Such
estimated bill, if so issued, shall have the validity of and be subject to the
same payment provisions as shall a final bill.
Kilowatthours
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Bills not paid in full on or before the date specified in the Payment
of Bills section, or its successor, of the General Rate Schedule Provisions
incorporated in the Wholesale Power Rate Schedules and General Rate Schedule
Provisions Exhibit shall bear additional charges as specified therein.
Remittances received by mail will be accepted without assessment of
the charges referred to in the preceding paragraph provided the postmark
indicates the payment was mailed on or before the 20th day after the date of
the bill. If the 20th day after the date of the bill is a Sunday or other
nonbusiness day of the Purchaser, the next following business day shall be the
last day on which payment may be made to avoid such further charges. Payment
made by metered mail and received subsequent to the 20th day must bear a postal
department cancellation in order to avoid assessment of such further charges.
Bonneville may, whenever a power bill or a portion thereof remains
unpaid subsequent to the 20th day after the date of the bill, and after giving
30 days advance notice in writing, cancel the contract for service to the
Purchaser, but such cancellation shall not affect the Purchaser's liability for
any charges accrued prior thereto.
19. Determination of Estimated Billing Data. If the amounts of power or
energy which have been delivered hereunder must be estimated from data other
than metered quantities, scheduled quantities or tabulations of hourly
interchange prepared by the Purchaser, Bonneville and the Purchaser shall agree
on estimated billing data to be used in preparing the bill.
20. Average Power Factor. The formula for determining average power
factor is as follows:
Average Power Factor
(Kilowatthours)' (Reactive Kilovolt-ampere-hours)
F. IN REFERENCE TO USE OF POWER
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The data used in the above formula shall be obtained from meters
which are ratcheted to prevent reverse registration.
When deliveries to a Purchaser at any Point of Delivery include more
than one class of power or are under more than one rate schedule, and it is
impracticable to separately meter the kilowatthours and reactive kilovolt
ampere-hours for each class, the average power factor of the total deliveries
for the month shall be used, where applicable, as the power factor for each of
the separate classes of power and rate schedules.
21. Changes in Requirements or Characteristics. The Purchaser will,
whenever possible, give reasonable notice to Bonneville of any unusual
increase or decrease of its demands for electric power and energy on the
Federal System, or of any unusual change in the load factor or power factor at
which the Purchaser will take delivery of electric power and energy under this
contract.
22. Electric Disturbance.
(a) For the purposes of this section an electric disturbance is any
sudden, unexpected, changed, or abnormal electric condition occurring in or on
an electric system which causes damage.
(b) Each party shall design, construct, operate, maintain, and use its
electric system in conformance with accepted electric utility practices:
(1) to minimize electric disturbances such as, but not limited to,
the abnormal flow of power which may interfere with the electric system of
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the other party or any electric system connected with such other party's
electric system; and
(2) to minimize the effect on its electric system and on its
customers of electric disturbances originating on its own or another
electric system.
(c) If both parties to this contract are parties to the Western
Interconnected Electric System Agreement, their relationship with respect to
system damages shall be governed by that agreement.
(d) During such time as a party to this contract is not a party to the
Agreement Limiting Liability Among Western Interconnected Systems, its
relations with the other party with respect to system damages shall be
governed by the following sentence, notwithstanding the fact that the other
party may be a party to said Agreement Limiting Liability Among Western
Interconnected Systems. A party to this contract shall not be liable to the
other party for damage to the other party's system or facilities caused by an
electric disturbance on the first party's system, whether or not such electric
disturbance is the result of negligence by the first party, if the other party
has failed to fulfill its obligations under subsection (b)(2) above.
(e) If one of the parties to this contract is not a party to the
Agreement Limiting Liability Among Western Interconnected Systems, each party
to this contract shall hold harmless and indemnify the other party, its
officers and employees, from any claims for loss, injury, or damage suffered
by those to whom the first party delivers power not for resale, which loss,
injury, or damage is caused by an electric disturbance on the other party's
system, whether or not such electric disturbance results from the negligence
G. IN REFERENCE TO FACILITIES
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of such other party, if such first party has failed to fulfill its obligations
under subsection (b)(2) above, and such failure contributed to the loss,
injury, or damage.
(f) Nothing in this section shall be construed to create any duty to, any
standard of care with reference to, or any liability to any persons not a
party to this contract.
23. Harmonic Control. Each party shall design, construct, operate,
maintain and use its electric facilities in accordance with good engineering
practices to reduce to acceptable levels the harmonic currents and voltages
which pass into the other party's facilities. Harmonic reductions shall be
accomplished with equipment which is specifically designed and permanently
operated and maintained as an integral part of the facilities of the party
which owns the system on which harmonics are generated.
24. Balancing Phase Demands. If required by Bonneville at any time
during the term of this contract, the Purchaser shall make such changes as are
necessary on its system to balance the phase currents at any Point of Delivery
so that the current of any one phase shall not exceed the current on any other
phase at such point by more than 10 percent.
25. Measurements and Installation of Meters. Bonneville may at any time
install a meter or metering equipment to make the measurements for any Point
of Delivery required for any computation or determination mentioned in this
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contract, and if so installed, such measurements shall be used thereafter in
such computation or determination.
26. Tests of Metering Installations. Each party to this contract shall,
at its expense, test its metering installations associated with this contract
at least once every two years, and, if requested to do so by the other party,
shall make additional tests or inspections of such installations, the expense
of which shall be paid by such other party unless such additional tests or
inspections show the measurements of such installations to be inaccurate as
specified in section 5 hereof. Each party shall give reasonable notice of the
time when any such test or inspection is to be made to the other party who may
have representatives present at such test or inspection. Any component of
such installations found to be defective or inaccurate shall be adjusted,
repaired, or replaced to provide accurate metering.
27. Permits.
(a) If any equipment or facilities associated with any Point of Delivery
and belonging to a party to this contract are or are to be located on the
property of the other party, a permit to install, test, maintain, inspect,
replace, repair, and operate during the term of this contract and to remove
such equipment and facilities at the expiration of said term, together with
the right of entry to said property at all reasonable times in such term, is
hereby granted by the other party.
(b) Each party shall have the right at all reasonable times to enter the
property of the other party for the purpose of reading any and all meters
mentioned in this contract which are installed on such property.
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(c) If either party is required or permitted to install, test, maintain,
inspect, replace, repair, remove, or operate equipment on the property of the
other, the owner of such property shall furnish the other party with accurate
drawings and wiring diagrams of associated equipment and facilities, or, if
such drawings or diagrams are not available, shall furnish accurate
information regarding such equipment or facilities. The owner of such
property shall notify the other party of any subsequent modification which may
affect the duties of the other party in regard to such equipment, and furnish
the other party with accurate revised drawings, if possible.
28. Ownership of Facilities.
(a) Except as otherwise expressly provided, ownership of any and all
equipment and all salvable facilities installed or previously installed by a
party to this contract on the property of the other party shall be and remain
in the installing party.
(b) Each party shall identify all movable equipment and all other
salvable facilities which are installed by such party on the property of the
other, by permanently affixing thereto suitable markers plainly stating the
name of the owner of the equipment and facilities so identified. Within a
reasonable time subsequent to initial installation, and subsequent to any
modification of such installation, representatives of the parties shall
jointly prepare an itemized list of said movable equipment and salvable
facilities so installed.
29. Inspection of Facilities. Each party may for any reasonable purpose
under this contract inspect the other party's electric installation at any
reasonable time. Such inspection, or failure to inspect, shall not render
H. MISCELLANEOUS PROVISIONS
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such party, its officers, agents, or employees, liable or responsible for any
injury, loss, damage, or accident resulting from defects in such electric
installation, or for violation of this contract. The inspecting party shall
observe written instructions and rules posted in facilities and such other
necessary instructions or standards for inspection as the parties agree to.
Only those electric installations used in complying with the terms of this
contract shall be subject to inspection.
30. Facilities for Maintenance of Voltage. Bonneville shall design and
construct Federal System Facilities to maintain, under normal conditions and
in accordance with generally accepted operating practices, the voltage at each
Point of Delivery from the Federal System within a range of 5 percent above or
below the operating voltage agreed upon by the operators of the parties to
this contract where such voltage is 25 kV or less. Where the delivery voltage
is in excess of 25 kV, Bonneville will design and construct Federal System
Facilities to maintain such operating voltage within a range of 10 percent
above or below such voltages. The parties shall jointly plan and operate
their interconnected electrical facilities so that the flow of reactive power
accompanying or resulting from deliveries of electric power and energy under
this contract will not adversely affect the system of either party.
31. General Environmental Provision.
(a) Policy. Bonneville in the performance of this contract shall comply
with all of its obligations pursuant to the National Environmental Policy Act.
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(b) Affirmative Obligations. The parties agree to:
(1) comply fully with all applicable Federal, State, and local
environmental laws;
(2) to assist and to cooperate with each other in meeting each
other's environmental obligations, to the fullest extent economically and
technically practicable and mutually agreeable; and
(3) provide upon request of the other party a copy of pollution
abatement plans as required by the Clean Air Act, by the Clean Water Act,
by other Federal statutes, or by an agency having jurisdiction and within
a reasonable time submit evidence that such plans have been approved or
have not been objected to by agencies with jurisdiction.
(c) Breach of Obligations. A breach of this General Environmental
Provision exists only if a final determination, including all appeals, has
been entered by a court or pollution control agency or agencies having
jurisdiction that the Purchaser's facility is not in compliance with
applicable laws respecting the control and abatement of environmental
pollution.
(d) Remedy. Bonneville, after consulting with state or local agencies
having jurisdiction may restrict delivery of electric capacity or energy to
the Purchaser pursuant to this contract, if Bonneville determines that:
(1) a breach of this General Environmental Provision exists;
(2) such breach is resulting in a significant adverse effect on the
environment;
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(3) no governmental agency has jurisdiction or authority to impose
sanctions or to seek remedy for such significant adverse effect on the
environment; and
(4) restriction of delivery is the only appropriate remedy and bears
a reasonable relationship to the breach.
Before restricting delivery of capacity or energy pursuant to this
section, Bonneville shall give the Purchaser written notice and a reasonable
opportunity to cure the breach and to seek any legal recourse available to the
Purchaser.
32. Dispute Resolution and Arbitration.
(a) Pending resolution of a disputed matter the parties will continue
performance of their respective obligations pursuant to this contract. If the
parties cannot reach timely mutual agreement on any matter in the
administration of this contract Bonneville shall, unless otherwise
specifically provided for in subsection (b) below and, to the extent necessary
for its continued performance, make a determination of such matter without
prejudice to the rights of the other party. Such determination shall not
constitute a waiver of any other remedy belonging to the Purchaser.
(b) The questions of fact stated below shall be subject to arbitration.
Other questions of fact under this contract may be submitted to arbitration
upon written mutual agreement of the parties. The party calling for
arbitration shall serve notice in writing upon the other party, setting forth
in detail the question or questions to be arbitrated and the arbitrator
appointed by such party. The other party shall, within 10 days after the
receipt of such notice, appoint a second arbitrator, and the two so appointed
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shall choose and appoint a third. In case such other party fails to appoint
an arbitrator within said 10 days, or in case the two so appointed fail for
10 days to agree upon and appoint a third, the party calling for the
arbitration, upon 5 days' written notice delivered to the other party, shall
apply to the person who at the time shall be the presiding judge of the United
States Court of Appeals for the Ninth Circuit for appointment of the second
and third arbitrator, as the case may be.
The determination of the question or questions submitted for
arbitration shall be made by a majority of the arbitrators and shall be
binding on the parties. Each party shall pay for the services and expenses of
the arbitrator appointed by or for it, for its own attorney fees, and for
compensation for its witnesses or consultants. All other costs incurred in
connection with the arbitration shall be shared equally by the parties thereto.
The questions of fact to be determined as provided in this section
shall be limited to:
(1) the determination of the measurements to be made by the parties
hereto pursuant to section 3 above;
(2) the occurrence of changes in conditions for purposes of section 4
above;
(3) the correction of the measurements to be made pursuant to
section 5 above;
(4) whether the changes mentioned in section 6 hereof were made
"promptly
(5) the duration of the interruption or equivalent interruption
mentioned in section 7 above;
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(6) the occurrence of an abnormal nonrecurring demand and the amount
and time thereof;
(7) any fact mentioned in section 21 above and in section 24 above;
(8) whether a party has complied with section 22(b) above; and
(9) the acceptable level of harmonics for purposes of section 23
above.
The questions of fact in the body of the Power Sales Contract with
Public Agency, Cooperative, Federal Agency, and Investor -Owned Utility
Purchasers to be determined as provided in this section shall be limited to:
(1) the order of receipt of written notices of addition of Firm
Resources under section 12(b)(7);
(2) whether the Purchaser's electrical system is interconnected with
electrical systems of other utilities directly or indirectly connected
with Bonneville's electrical system for purposes of section 13(d);
(3) whether a Purchaser's documentation under section 17(e)
demonstrates the actual implementation of a load curtailment program; and
(4) the level of base load under section 8.
33. Enforcement of Rights for Benefit of Transferors. If delivery of
electric power and energy under this contract is to be made by transfer over
the facilities of any Transferor or Transferors, Bonneville may enforce
Government rights under the power factor clause of the Government's applicable
rate schedule incorporated in this contract, and under sections 6, 13, 14, 21,
22, 23, 24, 27, 28, and 29 hereof, for the benefit of such Transferor or
Transferors, and all references to the Federal System, property, or Facilities
in said section shall be deemed to include the facilities of the Transferor or
35.
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Transferors being used to deliver electric power or energy for the account of
Bonneville.
34. Net Billing. Upon mutual agreement of the parties, payments due one
party may be offset against payments due the other party under all contracts
between the Purchaser and Bonneville for the sale and exchange of electric
power and energy, use of transmission facilities, operation and maintenance of
electric facilities, lease of electric facilities, mutual supply of emergency
and standby electric power and energy, and under such other contracts between
such parties as the parties may agree unless otherwise provided in existing
contracts between the parties. Under contracts included in this procedure all
payments due one party in any month shall be offset against payments due the
other party in such month, and the resulting net balance shall be paid to the
party in whose favor such balance exists unless the latter elects to have such
balance carried forward to be added to the payments due it in a succeeding
month.
Contract Work Hours and Safety Standards. This contract, if and to
the extent required by applicable law or if not otherwise exempted, is subject
to the following provisions:
(a) Overtime Requirements. No Contractor or subcontractor contracting
for any part of the contract work which may require or involve the employment
of laborers or mechanics shall require or permit any laborer or mechanic in
any workweek in which such worker is employed on such work to work in excess
of 8 hours in any calendar day or in excess of 40 hours in such workweek
unless such laborer or mechanic receives compensation at a rate not less than
one and one -half times such worker's basic rate of pay for all such hours
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worked in excess of eight hours in any calendar day or in excess of 40 hours
in such workweek, as the case may be.
(b) Violation; Liability for Unpaid Wages; Liquidated Damages. In the
event of any violation of the provisions of subsection (a), the Contractor and
any subcontractor responsible therefor shall be liable to any affected
employee for such employee's unpaid wages. In addition, such Contractor and
subcontractor shall be liable to the Government for liquidated damages. Such
liquidated damages shall be computed with respect to each individual laborer
or mechanic employed in violation of the provisions of subsection (a) in the
sum of $10 for each calendar day on which such employee was required or
permitted to be employed in such work in excess of eight hours or in excess of
such employee's standard workweek of 40 hours without payment of the overtime
wages required by subsection (a) above.
(c) Withholding for Unpaid Wages and Liquidated Damages. Bonneville may
withhold, or cause to be withheld, from any moneys payable on account of work
performed by the Contractor or subcontractor, such sums as may
administratively be determined to be necessary to satisfy any liabilities of
such Contractor or subcontractor for unpaid wages and liquidated damages as
provided in subsection (b) above.
(d) Subcontracts. The Contractor shall insert in any subcontracts the
clauses set forth in subsections (a) through (c) of this provision and also a
clause requiring the subcontractors to include these clauses in any lower tier
subcontracts which they may enter into, together with a clause requiring this
insertion in any further subcontracts that may in turn be made.
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36. Convict Labor. In connection with the performance of work under this
contract, the Contractor agrees, if and to the extent required by applicable
law or if not otherwise exempted, not to employ any person undergoing sentence
of imprisonment except as provided by P.L. 89 -176, September 10, 1965
(18 U.S.C. 4082(c)(2)) and Executive Order 11755, December 29, 1973.
37. Equal Employment Opportunity. During the performance of this
contract, if and to the extent required by applicable law or if not otherwise
exempted, the Contractor agrees as follows:
(a) The Contractor will not discriminate against any employee or
applicant for employment because of race, color, religion, sex, or national
origin. The Contractor will take affirmative action to ensure that applicants
are employed, and that employees are treated during employment, without regard
to their race, color, religion, sex, or national origin. Such action shall
include, but not be limited to, the following: employment, upgrading,
demotion or transfer; recruitment or recruitment advertising; layoff or
termination; rates of pay or other forms of compensation; and selection for
training, including apprenticeship. The Contractor agrees to post in
conspicuous places, available to employees and applicants for employment,
notices to be provided by Bonneville setting forth the provisions of the Equal
Opportunity clause.
(b) The Contractor will, in all solicitations or advertisements for
employees placed by or on behalf of the Contractor, state that all qualified
applicants will receive consideration for employment without regard to race,
color, religion, sex, or national origin.
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(c) The Contractor will send to each labor union or representative of
workers with which said Contractor has a collective bargaining agreement or
other contract or understanding, a notice, to be provided by Bonneville,
advising the labor union or workers' representative of the Contractor's
commitments under the Equal Opportunity clause and shall post copies of the
notice in conspicuous places available to employees and applicants for
employment.
(d) The Contractor will comply with all provisions of Executive Order
No. 11246 of September 24, 1965, and of the rules, regulations, and relevant
orders of the Secretary of Labor.
(e) The Contractor will furnish all information and reports required by
Executive Order No. 11246 of September 24, 1965, and of the rules,
regulations, and relevant orders of the Secretary of Labor, or pursuant
thereto, and will permit access to said Contractor's books, records, and
accounts by Bonneville and the Secretary of Labor for purposes of
investigations to ascertain compliance with such rules, regulations, and
orders.
(f) In the event of the Contractor's noncompliance with the Equal
Opportunity clause of this contract or with any of such rules, regulations, or
orders, this contract may be cancelled, terminated, or suspended in whole or
in part and the Contractor may be declared ineligible for further Government
contracts in accordance with procedures authorized in Executive Order
No. 11246 of September 24, 1965, and such other sanctions may be imposed and
remedies invoked as provided in Executive Order No. 11246 of September 24,
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1965, or by rule, regulation, or order of the Secretary of Labor, or as
otherwise provided by law.
(g) The Contractor will include the provisions of subsections (a) through
(f) in every subcontract or purchase order unless exempted by rules,
regulations, or orders of the Secretary of Labor issued pursuant to
Section 204 of Executive Order No. 11246 of September 24, 1965, so that such
provisons will be binding upon each subcontractor or vendor. The Contractor
will take such action with respect to any subcontract or purchase order as
Bonneville may direct as a means of enforcing such provisions, including
sanctions for noncompliance. In the event the Contractor becomes involved in,
or is threatened with, litigation with a subcontractor or vendor as a result
of such direction by Bonneville, the Contractor may request the Government to
enter into such litigation to protect the interests of the Government.
38. Additional Provisions. The Contractor agrees to comply with the
clauses for Government contracts contained in the following statutes,
Executive Orders, and regulations to the extent applicable:
(a) the Rehabilitation Act of 1973, Public Law 93 -112, as amended, and
41 CFR 60 -741 (affirmative action for handicapped workers);
(b) the Vietnam Era Veterans Readjustment Assistance Act of 1974, Public
Law 92 -540, as amended, and 41 CFR 60 -250 (affirmative action for disabled
veterans and veterans of the Vietnam era);
(c) Executive Order 11625 and 41 CFR 1- 1.1310 -2 (utilization of minority
business enterprises);
(d) The Small Business Act, as amended.
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39. Assignment of Contract. This contract shall inure to the benefit of,
and shall be binding upon the respective successors and assigns of the parties
to this contract. Such contract or any interest therein shall not be
transferred or assigned by either party to any party other than the Government
or an agency thereof without the written consent of the other except as
specifically provided in this section. The consent of Bonneville is hereby
given to any security assignment or other like financing instrument which may
be required under terms of any mortgage, trust, security agreement or holder
of such instrument of indebtedness made by and between the Purchaser and any
mortgagee, trustee, secured party, subsidiary of the Purchaser or holder of
such instrument of indebtedness, as security for bonds or other indebtedness
of such Purchaser, present or future; such mortagagee, trustee, secured party,
subsidiary, or holder may realize upon such security in foreclosure or other
suitable proceedings, and succeed to all right, title, and interests of such
Purchaser.
40. Waiver of Default. Any waiver at any time by any party to this
contract of its rights with respect to any default of any other party thereto,
or with respect to any other matter arising in connection with such contract,
shall not be considered a waiver with respect to any subsequent default or
matter.
41. Notices and Computation of Time. Any notice required by this
contract to be given to any party shall be effective when it is received by
such party, and in computing any period of time from such notice, such period
shall commence at 2400 hours on the date of receipt of such notice.
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42. Interest of Member of Congress. No Member of or Delegate to
Congress, or Resident Commissioner shall be admitted to any share or part of
this contract or to any benefit that may arise therefrom, but this provision
shall not be construed to extend to such contract if made with a corporation
for its general benefit.
43. Priority of Pacific Northwest Customers.
(a) The provisions of sections 9(c) and (d) of P.L. 96 -501 and the
provisions of P.L. 88 -552 as amended by section 8(e) of P.L. 96 -501 "the
Provisions are by this reference incorporated herein.
(b) To further the policy of the Provisions, Bonneville agrees that the
Purchaser, together with other Customers in the Pacific Northwest, shall have
priority on electric power and energy Bonneville has available for sale, in
conformity with the Provisions.
(c) Bonneville agrees that it will comply with all restrictions and
_requirements of the Provisions, and will perform all duties and obligations
imposed on it by the Provisions, as the Provisions existed on the effective
date of this contract, regardless of any subsequent modification, amendment or
repeal of the Provisions.
(d) Bonneville further agrees that, to the extent and at such times as
may be necessary to meet demands for energy or peaking capacity at any
established rate for use within the Pacific Northwest, it will exercise its
rights, under contractual provisions required by the Provisions to be included
in contracts for the disposition of surpl Us energy or surplus peaking capacity
for use outside of the Pacific Northwest, to require:
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(1) the return of energy delivered in connection with its supplying
peaking capacity for use outside the Pacific Northwest; and
(2) the delivery within the Pacific Northwest of energy, peaking
capacity, or both, which Bonneville has the right to receive in any
exchange for energy, capacity, or both, which it has delivered for use
outside the Pacific Northwest.
44. Resource Acquisition and Management.
(a) Principles of Resource Acquisition:
(1) Bonneville is obligated under section 6(a)(2) of P.L. 96 -501 to
acquire sufficient firm resources to meet its firm loads after taking into
account planned savings from conservation.
(2) Bonneville is obligated to attempt to meet its firm loads
pursuant to section 6(a)(2) with resources, including conservation,
implemented or acquired on a long -term basis pursuant to P.L. 96 -501.
(3) To the extent Bonneville is unable to acquire, on a planning
basis, sufficient resources on a long -term basis to meet its firm
obligations, Bonneville is obligated to and will attempt to meet its
remaining firm load obligations through the acquisition of additional
resources pursuant to section 11(b)(6) of the Federal Columbia River
Transmission System Act. The obligation contained in this subparagraph is
a continuing one, and applies on both a planning basis and during the
Pacific Northwest Coordination Agreement Critical Period.
(b) Principles of Resource Management. Bonneville will manage the
resources of the Federal Columbia River Power System and resources acquired
pursuant to P.L. 96 -501 and the Federal Columbia River Transmission System Act
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for the purpose of meeting the loads of its customers at the lowest possible
expected cost to Bonneville, to the extent consistent with Bonneville's legal
obligations, environmental responsibilities, and prudent operating criteria,
particularly for firm loads, without reducing its obligation to acquire
sufficient resources to meet its firm loads, and with due regard for the risks
and expected reliability of such resources.
(c) Consultation with Customers. In the development of its plans and
programs to effect the provisions of this section, including for ratemaking
purposes, Bonneville will provide a timely opportunity for prior consultation
with its customers.
45. Cooperation with Regional Council. The parties will negotiate
amendments to this contract as may be necessary to permit the plan or program
adopted by the Pacific Northwest Electric Power and Conservation Planning
Council pursuant to P.L. 96 -501, including but not limited to provisions
pertaining to conservation, renewable resources, and fish and wildlife, to be
effective in the manner and for the purposes set forth in sections 4 and 6 of
P.L. 96 -501.
46. Rights of the Purchaser. No provision of this contract nor any
action or lack of action by the Purchaser pursuant to the terms of this
contract shall be construed to abrogate, modify, limit or otherwise waive in
any respect any right of the Purchaser including the right of the Purchaser to
exercise its preference and priority as provided by law.
II. RELATING ONLY TO PREFERENCE AGENCIES
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47. Separation of Electric Operations and Funds (All Public Agencies).
(a) The Purchaser shall operate its electric system as a separate
department from other utility functions, if any, and shall establish and
maintain a separate fund for the revenues derived from the operation of such
system. Such revenues shall not be commingled with funds or accounts of other
departments, if any.
48. Statement of General Policies and Practices (Cities).
(a) Publicly owned city electric systems should be operated and
maintained:
(1) primarily for the benefit of the users of electricity;
(2) in accordance with reasonable standards of safety, reliability,
quality, and efficiency; and
(3) to maintain the cost of electric power at the lowest level
consistent with good service and proper maintenance.
(b) Revenue requirements shall insure a financially sound and
self- supporting electrical system. This requires that revenues be sufficient
for:
(1) Reasonable and necessary current maintenance and operating
expenses, including salaries, wages, cost of power at wholesale,
materials, supplies, insurance, necessary renewals and replacements of
plant, and the establishment of reasonable funds for such purposes,
contingencies, and other lawful charges.
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(2) Interest and principal of indebtedness incurred for the electric
plant and payments required to be made into any special bond funds.
(3) Depreciation of electric system property to the extent not
adequately provided for by amortization of debt and by renewals and
replacement.
(4) Payments made into a governmental entity general fund via taxes
or payments in lieu of taxes. The percentage of gross electric revenues
used for this purpose shall be an amount not exceeding the greater of the
following:
(i) an amount which is equal to five percent of the gross
electric revenues, unless a greater amount is provided pursuant to
the city charter or agreements in effect as of December 5, 1980; or
(ii) the amount of State or local taxes levied upon the
Purchaser's electric system or its operations.
(c) A local governmental entity, when acting in its governmental
capacity, and receiving electric service, shall be a Consumer and be billed
for such services consistent with the rates charged other Consumers in the
same class. The Purchaser shall receive prompt payment for such electric
services. Payments by the Purchaser for necessary services or materials
received by the Purchaser from other governmental departments, shall be
limited to a fair, reasonable and nondiscriminatory charge.
(d) Taxpayers' investments in the electric system, made through use of
general government funds of the city, should be treated in the same manner as
funds borrowed by the electric system from outside sources, and should receive
a return approximating the market rate of interest on comparable securities.
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Such market rate of interest shall not exceed 6 percent per annum unless a
larger amount is approved by Bonneville.
(e) All surplus revenues from retail sales remaining after meeting the
requirements of subsections (b), (c), and (d) above, where applicable, should
be applied to reduction of rates. Surplus revenues earned in any year may
properly be devoted to the purchase or retirement of system indebtedness
before maturity, to the extent that such use thereof is consistent with the
above principles and practices.
49. Approval of Contract. If the Purchaser borrows from the Rural
Electrification Administration or any other entity under an indenture which
requires the lender's approval of contracts, this contract and any amendment
thereto shall not be binding on the parties thereto if they are not approved
by the Rural Electrification Administration or such other entity. The
Purchaser shall notify Bonneville of any such entity. If approval is given,
such contracts or amendment shall be effective at the time stated in such
contract or amendment.
50. Prior Demands.
(a) If Bonneville has delivered electric power or energy to the Purchaser
at any Point of Delivery specified in this contract prior to the time this
contract takes effect, the Purchaser's Measured Demands, if any, at such point
or Measured Demands for its system for Purchasers on Computed Requirements
prior to such time shall be considered for the purpose of determining the
charges to the Purchaser for the electric power and energy delivered under
this contract, during any month in the term hereof, in the same manner as if
this contract had been in effect.
Page 43 of 49
General Contract Provisions
2/7/84
(b) If Bonneville has delivered electric power and energy to the
Purchaser at any Point of Delivery specified in this contract or in any
previous contract with the Purchaser, and such Point of Delivery is superseded
by another Point of Delivery specified in this contract, the Purchaser's
Measured Demands, if any, at such superseded point shall be considered for the
purpose of determining the charges to the Purchaser for the electric power and
energy delivered under this contract at such superseding point.
III. RELATING ONLY TO PUBLIC BODY, COOPERATIVE, FEDERAL
AGENCY AND INVESTOR -OWNED UTILITY PURCHASERS
A. IN REFERENCE TO COMPUTATION OF CHARGES
51. Effect of Reduction of Contract Demand. If the Purchaser's contract
_,demand is specified in this contract and is reduced after this contract is
executed, the prior Measured Demands, if any, of the Purchaser shall, for the
purpose of computing charges for electric power and energy delivered
thereafter, be reduced by the amount of such reduction.
52. Combining Deliveries Coincidentally.
(a) If it is provided in this contract that charges for electric power
and energy made available at two or more Points of Delivery will be made by
combining deliveries at such points coincidentally:
(1) the total Measured Demand to be considered in determining the
billing demand for each Billing Month shall be the largest sum obtained by
adding for each demand interval of such month the corresponding Integrated
Page 44 of 49
General Contract Provisions
2/7/84
Demands of the Purchaser at all such points after adjusting said
Integrated Demands as appropriate to such points;
(2) the number of kilowatthours to be used in determining the energy
charge, if any, and the average power factor at which electric energy is
delivered at such points under this contract, during such month, shall be
the sum of the amounts of electric energy delivered at such points under
this contract during such month; and
(3) the number of reactive kilovolt- ampere -hours to be used in
determining such average monthly power factor shall be the sum of the
reactive kilovolt- ampere -hours delivered at such points under this
contract during such month.
(b) If electric power and energy is made available under this contract to
the Purchaser at two or more Points of Delivery, Bonneville may, upon
two years written notice, place the Purchaser on a coincidental billing demand
basis pursuant to the terms of this section.
53. Combining Deliveries Noncoincidentally. If it is provided in this
contract that charges for electric power and energy made available at two or
more Points of Delivery will be made by combining deliveries at such points
noncoincidentally:
(a) the total Measured Demand to be considered in determining the
billing demand for each month in the period specified in such contract
shall be the sum obtained by adding together the Measured Demands of the
Purchaser for each of such points during such month;
(b) the number of kilowatthours to be used in determining the energy
charge, if any, and the average monthly power factor at which electric
Page 45 of 49
General Contract Provisions
2/7/84
energy is delivered at such points under this contract, during such month,
shall be the sum of the amounts of electric energy delivered at such
points under this contract during such month; and
(c) the number of reactive kilovolt- ampere -hours to be used in
determining such average monthly power factor shall be the sum of the
reactive kilovolt- ampere -hours delivered at such points under this
contract during such month.
54. Power Factor Adjustment. Except as it is otherwise specifically
provided in this contract, no adjustment shall be made for power factor at any
Point of Delivery for any period of time during which the reactive power
delivered at such point is not measured.
B. IN REFERENCE TO PURCHASERS' OPERATING POLICIES
55. Retail Rates.
(a) Copies of the Purchaser's schedules of retail rates, including
special contract rates, if any, in effect when this contract is executed, and
those hereafter adopted, endorsed with the effective date thereof, shall be
furnished to Bonneville, and Bonneville shall keep said rates on file. The
Purchaser agrees to serve each of its Consumers at, and in accordance with,
the rates, charges, and provisions set forth in the applicable rate schedules
on file where and as required by law or on file in Bonneville's office.
Notice of the intent to change retail rates shall be given to Bonneville
either 45 days prior to their effective date or as soon as the regulatory
process allows or shall be mailed to Bonneville on the same day as a notice of
Page 46 of 49
General Contract Provisions
2/7/84
a rate change given to a state regulatory authority by the Purchaser,
whichever will result in the later receipt of such notice by Bonneville.
(b) The retail rates and charges shall be reasonable and
nondiscriminatory, consistent with the principles of the Bonneville Project
Act, subject to the right of the Purchaser to adopt retail rates designed to
achieve cost effective conservation or renewable resources; provided, however,
that rates and charges which have been approved in accordance with the
procedures of a state regulatory agency having jurisdiction shall be deemed
prima facie reasonable and nondiscriminatory. The Purchaser shall maintain
records containing the data, analyses, and other factors which are used to
develop and form the basis for its proposed or final retail rates. At
Bonneville's request, such records as are available for public inspection
shall be supplied during the rate development process or after the rates have
been adopted.
(c) At the Purchaser's request, Bonneville shall (1) provide assistance
in analyzing and developing rate structures, including retail rate structures
that will encourage cost effective conservation and Consumer -owned renewable
resources; (2) provide estimates of the probable power savings and the
probable amount of billing credits under section 6(h) of P.L. 96 -501 that
might be realized by the Purchaser adopting and implementing such retail rate
structures; and (3) solicit additional information and analytical assistance
from appropriate state regulatory bodies and Bonneville's other Customers.
C. IN REFERENCE TO USE OF POWER
Page 47 of 49
General Contract Provisions
2/7/84
56. Resale of Power. The Purchaser shall not resell Firm Power delivered
under this contract except to those Consumers and utilities within its service
area in the Pacific Northwest to the extent such Consumers and utilities are
normally dependent on the Purchaser for their firm power supplies. The
Purchaser shall not sell power from its Firm Resources in such a manner as to
increase the Purchaser's Computed Peak Requirement or Computed Average Energy
Requirement on Bonneville in any month. These prohibitions on resale in this
section shall not be interpreted as a general prohibition against the
Purchaser simultaneously purchasing Firm Power from Bonneville and selling
power generated at its own facilities to other utilities or entities, nor
shall these prohibitions be interpreted to preclude the Purchaser from
reflecting the cost of Firm Power delivered under this contract in pricing
such sales to other utilities or entities.
D. IN REFERENCE ONLY TO PURCHASERS WITH GENERATING FACILITIES
57. Nonfirm Deliveries.
(a) At the request of either the Purchaser or Bonneville, the other party
will make available on the terms stated herein, such thermal- generated energy
or hydro generated energy as the supplying party determines, when such request
is made, that it has available for delivery to the requesting party.
(b) Neither party, by this contract, assures the other that it has, or
will have available, any thermal- generated energy or hydro- generated energy
Page 48 of 49
General Contract Provisions
2/7/84
for delivery to such other party, and the determination made by the supplier,
provided for in subsection (a) above, of the amount, if any, of such energy
which it will supply to the other party shall be final and conclusive as to
both parties.
(c) Nothing in this contract shall prohibit supply of nonfirm, emergency
or breakdown relief energy under any other contract.
58. Emergency or Breakdown Relief.
(a) If a breakdown of, or emergency on, the system of either the
Purchaser or Bonneville occurs, while such breakdown or emergency exists, the
other party will make available upon request, all or such part of the electric
energy required for such system as the supplier determines it can supply,
consistent with its obligations to its other customers. The determination so
made by the supplier shall be final and conclusive as to both parties.
(b) If either party supplies electric energy to the other party pursuant
to the provisions of subsection (a) of this section and requests replacement
thereof, the other party shall make an equivalent amount of electric energy
available to such supplier at such times as may be agreed upon by the
dispatchers of the parties hereto.
59. Effect on Generating Utility by Direct Service Industrial Customer
Power Sales Contract Provisions. Bonneville will notify the Purchaser of the
proposed adoption of an annual operating plan, annual operating agreement or
energy accounting system in the Direct- Service Industrial Customers' power
sales contracts. If, in Bonneville's sole, determination, the system of a
generating utility will be materially affected by a proposed annual operating
plan, annual operating agreement, or energy accounting system provided in the
Direct Service Industrial Customers' power sales contracts, Bonneville will
consult with such utility prior to adopting such proposed plan, agreement, or
accounting system.
IV. RELATING ONLY TO DIRECT- SERVICE INDUSTRY PURCHASERS
A. IN REFERENCE TO COMPUTATION OF CHARGES
60. Demands. During periods when Bonneville is delivering to the
Purchaser hourly amounts of electric power or energy under the terms of
agreements other than this contract, such amounts shall be subtracted each
hour from the Integrated Demand for deliveries hereunder for each such hour
after adjusting such Integrated Demands as appropriate to the Point of
Delivery.
(WP- PCI- 2000c)
(2/7/84)
B. IN REFERENCE TO PURCHASE
Page 49 of 49
General Contract Provisions
2/7/84
61. Use and Resale of Power. All electric power and energy delivered
under this contract shall be used by the Purchaser in its own operations, and
the Purchaser shall not resell such electric power and energy delivered under
this contract, or any part thereof. If the Purchaser resells such electric
power and energy, or any part thereof, Bonneville shall immediately terminate
this contract.
Department of Energy
Bonneville Power Administration
Puget Sound Area
415 First Avenue North, Room 250
Seattle, Washington 98109
In reply refer to OSC
Lew Cosens, Director, Light Department
City of Port Angeles
P.O. Box 1150
Port Angeles, Washington 98362
Dear Lew:
-n ca
i? ^YES MANAGER
COYSER:AiION MO4
February 16, 1' OSaAM snve SST
Enclosed are two original and three authenticated copies of the November 2,
1982, letter waiving Paragraph 8(e), Exhibit B, of the General Contract
Provisions, of your Power Sales Contract. This postpones the formal hearing
process on the 7(b)(2) methodology until after completion of the 1983 rate
process. These enclosures are for your records.
Sincerely,
Geo T. Reich
Area Power Manager
Enclosures:
Two Original Executed Copies of the November 2, 1982, Letter
Three Authenticated Copies of the November 2, 1982, Letter
7.
,nT ANGELES CITY f
FEB 2 '84
Department of Energy
Bonneville Power Administration
P.O. Box 3621
Portland, Oregon 97208
In reply refer to Ply I
Mr. Lew Cosens, Director
Light Department
City of Port Angeles
P.O. Box 1150
Port Angeles, WA 98362
Dear Mr. Cosens:
ANn; FS CV
1E:; E L'P'
FL;, EN")
ENG S"f&IAL:ST
0:3 WI
'ugcP,�°i�ivG
IELEC I:ISi'ECTDR
VIEFM%
NOV 3 '82
OFFICE OF THE ADMINISTRATOR
MNLS:S
I C..f.3FR;; 'CN !S''R
FH7,: "4"+1 SFr IAL "ST
;rjy ANA: 6
F "LE
November 2, 1982
The second sentence of section 8(e) of the General Contract Provisions of all
new Regional Act power sales and residential exchange contracts provides,
"Bonneville shall develop in consultation with its utility customers and shall
publish by July 1, 1983, methodologies as required for implementing
section 7(b)(2)." In order to meet this deadline, the proposed schedule would
require hearings simultaneously with the hearings on Bonneville Power
Administration's (Bonneville) 1983 rate adjustment.
Both Bonneville and customer representatives working with Bonneville on the
7(b)(2) methodology are concerned that such simultaneous hearings could lead
to conflicts and confusion in the development of the 7(b)(2) methodology. The
Public Power Council has requested on behalf of all preference customers that
BPA propose an amendment to the General Contract Provisions to extend the
July 1, 1983, deadline for 8 months to March 1, 1984. Bonneville agrees that
the interests of Bonneville and its customers would be better served by
postponing the formal hearing process on the 7(b)(2) methodology until after
the completion of the 1983 rate process.
To accomplish this end, Bonneville offers the following amendment to the
General Contract Provisions of all the Regional Act power sales and
residential exchange contracts which will extend the section 8(e) deadline for
8 months to March 1, 1984. Section 8(e) of the General Contract Provisions,
Exhibit B, is hereby amended as follows:
Section 8(e) is deleted and replaced by the following section 8(e):
"(e) Bonneville's wholesale power rates established on any Rate Adjustment
Date shall be developed consistent with the provisions of section 7 of
P.L. 96 -501. Bonneville shall develop in consultation with its utility
Customers and shall publish by March 1, 1984, methodologies as required
for implementing section 7(b)(2)."
The only change made by this amendment is in the date, March 1, 1984. This
amendment does not in any way affect your rights under Regional Act
section 7(b)(2). Section 7(b)(2) does not go into effect until after July 1,
1985, according to the terms of the Regional Act. This contract amendment
Ao
merely postpones by 8 months, to March 1, 1984, the date by which the
methodology to implement secton 7(b)(2) must be published in the Federal
Register.
Bonneville is seeking to have this amendment signed and returned by all
parties involved by Nov. 30, 1982, or as soon thereafter as possible. This
will permit Bonneville and those customer representatives who are working with
Bonneville on the 7(b)(2) methodology to know at the earliest date whether the
methodology must be completed by July 1, 1983; or may be delayed until
March 1, 1984. Therefore, please indicate your acceptance of this offer by
signing and returning to your Bonneville Area or District Office three copies
of this agreement, along with a certified copy of the authorizing resolution,
as appropriate.
This agreement shall become effective only when like agreements have been
signed by all parties receiving this offer. The parties receiving this offer
are all of Bonneville's power sales and residential exchange customers under
contracts offered by Bonneville on August 28, 1981.
If you have any questions regarding either Regional Act section 7(b)(2) or
this contract amendment, please call your Area or District Office.
ACCEPTED:
4 -4 6/cA,Eaa
:1;a4
By
a
Title
Date #662,71.10i/ /9 1-2-
(WP- PKI- 2428b)
ATTEST:
By G 4' s Ci Aa44e2
Title L l&e.46
Date y�� ,Z./ 9 �-z-
Sincerely,
2
Department of Energy
Bonneville Power Administration
P.O. Box 3621
Portland, Oregon 97208
In reply refer to PKI
Mr. Lew Cosens, Director
Light Department
City of Port Angeles
P.O. Box 1150
Port Angeles, WA 98362
Dear Mr. Cosens:
OFFICE OF THE ADMINISTRATOR
November 2, 1982
The second sentence of section 8(e) of the General Contract Provisions of all
new Regional Act power sales and residential exchange contracts provides,
"Bonneville shall develop in consultation with its utility customers and shall
publish by July 1, 1983, methodologies as required for implementing
section 7(b)(2)." In order to meet this deadline, the proposed schedule would
require hearings simultaneously with the hearings on Bonneville Power
Administration's (Bonneville) 1983 rate adjustment.
Both Bonneville and customer representatives working with Bonneville on the
7(b)(2) methodology are concerned that such simultaneous hearings could lead
to conflicts and confusion in the development of the 7(b)(2) methodology. The
Public Power Council has requested on behalf of all preference customers that
BPA propose an amendment to the General Contract Provisions to extend the
July 1, 1983, deadline for 8 months to March 1, 1984. Bonneville agrees that
the interests of Bonneville and its customers would be better served by
postponing the formal hearing process on the 7(b)(2) methodology until after
the completion of the 1983 rate process.
To accomplish this end, Bonneville offers the following amendment to the
General Contract Provisions of all the Regional Act power sales and
residential exchange contracts which will extend the section 8(e) deadline for
8 months to March 1, 1984. Section 8(e) of the General Contract Provisions,
Exhibit B, is hereby amended as follows:
Section 8(e) is deleted and replaced by the following section 8(e):
"(e) Bonneville's wholesale power rates established on any Rate Adjustment
Date shall be developed consistent with the provisions of section 7 of
P.L. 96 -501. Bonneville shall develop in consultation with its utility
Customers and shall publish by March 1, 1984, methodologies as required
for implementing section 7(b)(2)."
The only change made by this amendment is in the date, March 1, 1984. This
amendment does not in any way affect your rights under Regional Act
section 7(b)(2). Section 7(b)(2) does not go into effect until after July 1,
1985, according to the terms of the Regional Act. This contract amendment
merely postpones by 8 months, to March 1, 1984, the date by which the
methodology to implement secton 7(b)(2) must be published in the Federal
Register.
Bonneville is seeking to have this amendment signed and returned by all
parties involved by Nov. 30, 1982, or as soon thereafter as possible. This
will permit Bonneville and those customer representatives who are working with
Bonneville on the 7(b)(2) methodology to know at the earliest date whether the
methodology must be completed by July 1, 1983; or may be delayed until
March 1, 1984. Therefore, please indicate your acceptance of this offer by
signing and returning to your Bonneville Area or District Office three copies
of this agreement, along with a certified copy of the authorizing resolution,
as appropriate.
This agreement shall become effective only when like agreements have been
signed by all parties receiving this offer. The parties receiving this offer
are all of Bonneville's power sales and residential exchange customers under
contracts offered by Bonneville on August 28, 1981.
If you have any questions regarding either Regional Act section 7(b)(2) or
this contract amendment, please call your Area or District Office.
ACCEPTED:
6 °4 77re,,a
By
JiY lAt r
Title 7)tax4o.t,
U
Date 0.,.4,,Lrn G. _21, /9f
ATTEST:
By C i-25a24p1.4
Title &G.
Date
(WP
Sincerely,
2
k
AMENDATORY AGREEMENT
executed by the
UNITED STATES OF AMERICA
DEPARTMENT OF ENERGY
acting by and through
BONNEVILLE POWER ADMINISTRATION
and
THE CITY OF PORT ANGELES
Amendatory Agreement No. 2 to
Contract No. DE- MS79- 81BP90450
8/10/82
This AMENDATORY AGREEMENT, executed April 21 1987, by the
UNITED STATES OF AMERICA (Government), Department of Energy, acting by and
through the BONNEVILLE POWER ADMINISTRATION (Bonneville), and THE CITY OF PORT
ANGELES (Purchaser), a municipal corporation of the State of Washington,
WITNESSETH:
WHEREAS Bonneville offered a power sales contract to the Purchaser on
August 28, 1981, and the parties hereto have executed such power sales
contract (Contract No. DE- MS79- 81BP90450, which as amended is hereinafter
referred to as "Power Sales Contract providing for the sale and delivery of
firm power and energy to the Purchaser; and
WHEREAS the parties hereto have agreed to the following amendments to the
Power Sales Contract offered August 28, 1981; and
T.
Q l 2
RECEIVED 4
r
MAY 151987
MAR tE EP :INCH
YCH
5
WHEREAS Bonneville is authorized pursuant to law to dispose of electric
power and energy generated at various Federal hydroelectric projects in the
Pacific Northwest, or acquired from other resources, to construct and operate
transmission facilities, to provide transmission and other services, and to
enter into agreements to carry out such authority;
NOW, THEREFORE, the parties hereto mutually agree as follows:
1. Effective Date of Agreement. This amendatory agreement shall be
effective on the later of 2400 hours on the date of execution or the effective
date of ie Power Sales Contract.
2. Amendment of Power Sales Contract. The Power Sales Contract is
hereby amended as follows:
(a) Section 2 is amended by adding a new section 2(b) as follows:
"(b) This contract may be terminated by the Purchaser upon
(i) 7 years' prior notice to Bonneville; (ii) concurrent submission by the
Purchaser to Bonneville of a Firm Resource Exhibit reciting zero demand
upon Bonneville as of the proposed date of termination; and (iii) a
determination that termination will cause no adverse economic impacts on
Bonneville's other customers."
(b) Section 4 is amended by deleting Exhibit C and replacing it with a
new Exhibit C attached hereto and by this reference made a part of this
contract in accordance with the specific provisions of this contract relating
to Exhibit C.
(c) Section 11 is deleted and replaced by a new section 11 as follows:
"11. Compensation Program for Regional Curtailment of Firm Loads.
a) The parties agree to commence negotiations as soon as
practicable to develop a comprehensive agreement among utilities in the
Pacific Northwest to buy and sell electric energy made available due to
2
curtailments in consumption or from resources on a party's system during a
period when governmental bodies having the authority to do so have so
ordered such curtailments or sales.
(b)(1) If the Bonneville Power Administrator and the governor of the
State encompassing the Purchaser's service area publicly appeal for
curtailments of electric power consumption or if mandatory curtailments of
electric power consumption in the Purchaser's service area are ordered by
governmental bodies having the authority to so order, Bonneville shall
compensate the Purchaser as provided in this section for any reduction in
Bonneville's obligation to supply Firm Power to the Purchaser. If the
Purchaser's service area extends into more than one State and all of such
States do not participate in the curtailments described above, the
procedures of this section shall be applied only to those loads in service
areas in the participating States.
"Compensation under this section shall not be available to the
Purchaser during any Operating Year that the Purchaser is purchasing Firm
Power from Bonneville on a Planned Computed Requirements or Contracted
Requirements basis. The compensation under this section may be reduced
partially or in its entirety as described in paragraph (4) or
paragraph (5) below. The reductions described in paragraph (4) below
shall be made after the adjustments described in paragraph (5) below.
"Compensation shall begin with the first full month following such
appeal for curtailment or ordered curtailment. Compensation shall end
with the month during which the Bonneville Power Administrator and the
appropriate State political leaders publicly indicate that a need for
curtailment no longer exists or such State officials rescind an order for
curtailment.
3
(2) Bonneville shall pay the Purchaser each month an amount equal to
the product of the rate set forth in this paragraph and the amount of load
curtailment determined in paragraph (3) below unless such amount of load
curtailment is reduced partially or in its entirety as set forth in
paragraph (4) below. Such rate shall be the amount in mills per
kilowatthour by which the Purchaser's average revenue from retail sales of
electric energy exceeds the wholesale firm power rate the Purchaser would
have paid Bonneville for the increment of energy determined pursuant to
paragraph (3) below.
(3) The amount of regional load curtailment on the Purchaser's
system during a month shall be deemed to be the amount, if any, by which
the Purchaser's Estimated Firm Energy load, after adjustment as specified
below, exceeds the Purchaser's Actual Firm Energy load for such month
after adjustment, if any, as set forth below. If the Purchaser does not
regularly publish an Estimated Firm Energy Load, such Purchaser's
Estimated Firm Energy Load for purposes of this section shall be the
Purchaser's component of Bonneville's latest published estimate of its
firm energy loads.
The Purchaser's most recently published Estimated Firm Energy Load
shall be used herein to determine amounts of regional load curtailment in
conjunction with information submitted by the Purchaser to Bonneville as
soon as possible following the end of each month in which a regional load
curtailment program is in effect. Such information shall be provided for
each such month and for the three most recent, but not necessarily
consecutive, months in which a regional load curtailmemt program or a load
curtailment program pursuant to section 17(e) was not in effect. Such
information shall include: (A) the Purchaser's Actual Firm Energy Load
4
for such months; and (B) detail on any separately identifiable significant
changes in the Purchaser's Actual Firm Energy Load from its Estimated Firm
Energy Load which were not the result of a regional load curtailment
program, a load curtailment program pursuant to section 17(e), or an
interruption of load for the purpose of providing economic operation of
the Purchaser's system including its Firm Resources.
The Purchaser's Actual Firm Energy Loads for all months used for
calculations herein shall be adjusted to reflect only those loads in the
Purchaser's service area which are in States participating in the regional
curtailment program. Such adjustments shall be made by subtracting the
portion of the Purchaser's Actual Firm Energy Load in States which are not
participating in the regional curtailment program from the Purchaser's
Actual Firm Energy Load for such month. Such adjustment may be changed
monthly to reflect changes in the States which are participating in the
regional curtailment program.
The Purchaser's Estimated Firm Energy Load for all months for which
information was requested above shall first be adjusted to reflect
separately identifiable changes in load which were not the result of a
regional load curtailment program, a load curtailment program pursuant to
section 17(e), or an interruption of load for the purpose of providing
economic operation of the Purchaser's system including its Firm
Resources. The Estimated Firm Energy Load shall then be adjusted in the
manner specified for Actual Firm Energy Loads above to reflect only those
loads in the Purchaser's service area which are in States participating in
the regional curtailment program. An adjusted Estimated Firm Energy Load
for each month in which a regional load curtailment program is in effect
shall then be determined by multiplying the Estimated Firm Energy Load for
5
such month, as adjusted above, by the ratios of the Purchaser's Actual
Firm Energy Load, as adjusted above, to its Estimated Firm Energy Load, as
adjusted above, for the three most recent, but not necessarily
consecutive, months in which a regional load curtailment program or a load
curtailment program pursuant to section 17(e) was not in effect.
(4) If regional curtailment has been requested after July 1, 1983,
because Bonneville is unable to acquire sufficient resources to meet its
firm obligations, Bonneville shall reduce the amount of load curtailment
determined in paragraph (3) above during any month if the Purchaser's load
growth as specified in subparagraph (A) below exceeds the amount of
resources which the Purchaser dedicated to its own load or made available
to Bonneville as specified in subparagraph (B) below. Such amount of load
curtailment for each month shall be reduced partially or in its entirety
by the amount which (A) exceeds (B) below:
(A) the excess of the Purchaser's Actual Firm Energy Load in
average megawatts over the Purchaser's Actual Firm Energy Load in
average megawatts for the same month during the Operating Year prior
to the first Operating Year for which Bonneville's load growth notice
provided in section 10(e) of this agreement is effective; and
(B) the annual firm energy capability in average megawatts of
(i) resources acquired by Bonneville from the Purchaser under
P.L. 96 -501; and (ii) the portion of the Purchaser's Firm Resources
which are included as 5(b)(1)(B) resources in its Firm Resources
Exhibit. Such resources shall not include conservation programs to
the extent such programs have been reflected in the Purchaser's
Actual Firm Energy Load in subparagraph (A) above.
6
(5) If the Purchaser purchases Firm Power from Bonneville on an
Actual Computed Requirements basis, the amount of load curtailment
determined in paragraph (3) above for any month shall be determined after
the following adjustments:
(A) The amount of load curtailment determined in paragraph (3)
above shall be reduced to provide compensation only for the portion
of the Purchaser's Actual Firm Energy Load served by Bonneville.
Such reduction shall be made by increasing the Purchaser's Actual
Firm Energy Load used to determine the amount of load curtailment in
paragraph (3) by the amount of load curtailment attributable to the
Purchaser's Firm Resources. Such increase in the Purchaser's Actual
Firm Energy Load shall be deemed to be the amount determined in the
manner specified in section 17(e)(5) even if the Purchaser has not
implemented a load curtailment program pursuant to section 17(e).
(B) If the Purchaser initially purchased Firm Power from
Bonneville on a Metered Requirements basis, but is purchasing Firm
Power from Bonneville on an Actual Computed Requirements basis at the
time regional curtailment is requested hereunder, subparagraph (A)
above will apply only if the Purchaser has implemented a load
curtailment program pursuant to section 17(e). This subparagraph (B)
shall no longer apply if the Purchaser was offered the opportunity to
be a party to a comprehensive agreement among utilities in the
Pacific Northwest described in subsection (a) above after it
commenced purchasing on a Computed Requirements basis."
7
follows:
(d) Section 17(b) is deleted and replaced by a new section 17(b) as
"(b) On or before the effective date of this contract, and
thereafter, as provided in paragraph (1) below, the Purchaser may request
in writing to purchase on the basis of Contracted Requirements by
submitting the data and proposed schedule of Contracted Requirements
purchases of peak and energy pursuant to paragraph (2) below.
(1) The Purchaser may request that it begin to purchase on a
Contracted Requirements basis at the time of submittal of any revised
Firm Resources Exhibit. Such request shall become effective, in
accordance with this subsection (b), for the seventh Operating Year
of such exhibit, or for an earlier Operating Year if Bonneville is
expected to have an excess of firm load over its firm resources in
the first Operating Year for which the Purchaser requests to purchase
on a Contracted Requirements basis. Bonneville's expected firm
load- resource balance and the priority of competing requests for
purposes of allocating the availability of this subparagraph of
paragraph (1) shall be determined in the manner described in
section 12(b)(7) above.
The Purchaser may elect to cease purchasing on a Contracted
Requirements basis at the time of submittal of any revised Firm
Resources Exhibit. Such election shall become effective for the
seventh Operating Year of such exhibit, or for an earlier Operating
Year if Bonneville is expected to have an excess of firm resources
over its firm load in the first Operating Year for which the
Purchaser proposes to cease purchasing on a Contracted Requirements
basis. Bonneville's expected firm load resource balance and the
8
priority of competing requests for purposes of allocating the
availability of this subparagraph of paragraph (1) shall be
determined in the manner described in section 12(b)(9) above.
(2) If the Purchaser requests to purchase on the basis of
Contracted Requirements, it shall submit to Bonneville in the
Purchaser's initial Firm Resources Exhibit in addition to data
required in section 12(a), the Purchaser's annual Estimated Firm Peak
Load, the annual average of Purchaser's Estimated Firm Energy Load,
the estimated Assured Capabilities of the Purchaser's Firm Resources
corresponding to the time period of such loads, and a schedule of
annual Contracted Requirements purchases of peak and energy for each
of the first seven Operating Years. If the Purchaser's Contracted
Requirements peak purchase amount for any such Operating Year is
based on its Estimated Firm Peak Load for the months June through
November, such amount shall be the Purchaser's Contracted
Requirements peak purchase amounts for June through November and the
Purchaser shall also submit a lower amount which is based on its
Estimated Peak Load for the months December through May. With each
revised Firm Resources Exhibit submitted in accordance with
section 12(b), such Purchaser shall submit a new schedule deleting
the amounts of Contracted Requirements peak and energy purchases for
the current Operating Year and adding the amounts to be purchased in
the seventh succeeding Operating Year together with Purchaser's
annual Estimated Firm Peak Load and annual average Estimated Firm
Energy Load in the seventh Operating Year, and new information on the
estimated Assured Capability of all Firm Resources and Estimated Firm
Loads for which information is provided for under paragraphs (4),
(5), and (6) below. Such revised Firm Resources Exhibit shall be
prepared in the same format as the initial Firm Resources Exhibit or
such other format as Bonneville and the Purchaser may agree upon.
Submission of the data specified in this paragraph (2) shall be in
lieu of preparation of an Assured Capability Exhibit as provided for
in section 16 above.
If Bonneville determines that the Purchaser's Estimated Firm
Loads do not conform to the definitions in this contract, Bonneville
shall notify the Purchaser, as soon as practicable, of the specific
deficiencies and the Purchaser may submit revised data or revised
schedule of Contracted Requirements purchases. If Bonneville expects
to approve a reduced quantity of peak or energy in any period of time
included in a schedule of Contracted Requirements purchases and
Bonneville determines that such reduction under this paragraph (2) or
paragraph (6) below is in any way affected by the Purchaser's
Estimated Firm Loads, Bonneville shall notify the Purchaser in the
manner specified above of specific deficiencies in the Purchaser's
Estimated Firm Load data submission and shall determine any reduction
described in this paragraph (2) on Bonneville's determination of the
Purchaser's Estimated Firm Loads unless the Purchaser submits revised
data or revised schedule of Contracted Requirements purchases prior
to the start of the Operating Year following initial submission of
the data and such data or schedule are approved by Bonneville.
Bonneville shall approve either each requested schedule of
Contracted Requirements purchases or a reduced schedule of Contracted
Requirements purchases in any period of time included in such
10
schedule; provided, however, that such reduced schedule shall not
be reduced below the lesser of the following:
(A) the amount by which the Purchaser's Estimated Firm
Load exceeds its estimated Assured Capability in such period of
time; or
(B) the minimum amount of peak or energy which Bonneville
would be obligated to make available to the Purchaser under the
following assumptions: (1) such amount shall be determined as
though a notice of restriction issued under section 7(a) was in
effect during such period of time for the Purchaser and its
class of Customers; (2) such amount shall be limited to the
amounts that Bonneville would be obligated to make available to
the Purchaser as determined under section 7(e), section 7(f),
and Exhibit D for amounts of resources acquired by Bonneville
under P.L. 96 -501 from or on behalf of the Purchaser or its
class of Customers with the amounts calculated under
section 7(f) determined as though section 7(f)(1) and 7(f)(2)
did not apply; and (3) such amount shall be deemed to be equal
to the amount specified in (A) above, unless Bonneville has
issued a notice of restriction under section 7(a) to such class
applicable to such period of time or has reasonable expectation
of issuing such notice, pursuant to the provisions of section 7,
either with, or in the absence of, this reduction.
(3) The amounts of power shown in Purchaser's schedule of
Contracted Requirements purchases, as submitted with the Firm
Resources Exhibit for an Operating Year and approved by Bonneville,
shall not be revised thereafter except for changes as specifically
11
provided for by paragraphs (4), (5) and (6) below. The Estimated
Firm Load on which the Purchaser's Contracted Requirements purchases
for each Operating Year were based shall be deemed to be the
Purchaser's Actual Firm Load during such Operating Year for the
purpose of determining whether the Purchaser is using its purchase
from Bonneville for resale.
(4) If the Purchaser makes a change in its Firm Resources as
permitted by section 12(b), the Purchaser shall, at the time such
change is submitted to Bonneville, make a change in its schedule of
Contracted Requirements purchases shown in its Firm Resources
Exhibit. Such change shall be equal and opposite to the change in
the Purchaser's Assured Capability resulting from such change in Firm
Resources.
(5) If the Purchaser's Estimated Firm Loads change for any
Operating Year for which the Purchaser is purchasing on a Contracted
Requirements basis, and if such change corresponds to changes in
Purchaser's Firm Resources which are permitted by sections 12(b)(7),
(9), and (11) (as though an increase in Estimated Firm Loads
corresponds to a removal of Firm Resource and a decrease in Estimated
Firm Loads corresponds to an addition to Firm Resource) the Purchaser
may submit such changed loads to Bonneville at the time it submits a
revised Firm Resources Exhibit and may, at such time, make an
equivalent change in its schedule of Contracted Requirements
purchases shown in its Firm Resources Exhibit.
(6) If prior to any Operating Year Bonneville determines that
it would be required to acquire a resource under P.L. 93 -454 or
Section 6(a)(2) of P.L. 96 -501 to meet Bonneville's firm loads
12
including the Purchaser's previously approved schedule of Contracted
Requirements purchases for such Operating Year, Bonneville may
request the Purchaser to submit revised Estimated Firm Loads for such
Operating Year for Bonneville's approval in the manner specified in
section 17(b)(2) above. Such request shall be made not less than
30 days prior to the date for submission of data for the modified
regulation under the Coordination Agreement. Such revised Estimated
Firm Loads shall be the Purchaser's most current estimate and shall
include power savings for such Operating Year from all conservation
measures and direct application renewable resources including those
funded by Bonneville either directly or through billing credits. If
due to the Purchaser's revised Estimated Firm Loads, the Purchaser's
schedule of Contracted Requirements purchases are in excess of the
amount specified in section 17(b)(2)(A) above, Bonneville may reduce
the Purchaser's schedule of Contracted Requirements purchases to the
amount specified in section 17(b)(2)(A) above. Bonneville shall
notify the Purchaser of such reduction prior to the submission of
data for the modified regulation.
In addition the schedule of Contracted Requirements purchases
shown in the Purchaser's Firm Resource Exhibit may be changed for any
Operating Year if and to the extent that Bonneville has given prior
written consent.
(7) Within 7 days after receipt of the preliminary regulation
under the Coordination Agreement prior to each Operating Year, the
Purchaser shall allocate its annual Contracted Requirements energy
purchase among months of such Operating Year in a manner which
results in a requirement on Bonneville each month equal to or between
the amounts determined by (A) or (B):
(A) one twelfth of the Purchaser's annual Contracted
Requirements energy purchase from Bonneville for that Operating
Year; and
(B) a fraction of such annual Contracted Requirements
energy purchase obtained by dividing the Estimated Firm Energy
Load for that month by the total of the twelve Estimated Firm
Energy Loads for that Operating Year.
If requested by the Purchaser and if Bonneville agrees, the Purchaser
may allocate its annual Contracted Requirements energy purchase among
months so as to place monthly requirements on Bonneville other than
those determined by (A) or (B) above to reflect a period of planned
thermal maintenance or other causes. The Purchaser's total
Contracted Requirements purchase shall not be changed by such
reallocation.
(8) For the purpose of determining the amount of power
Bonneville shall make available to the Purchaser under this contract,
the Purchaser's Contracted Requirements peak purchases shown in its
schedule of such purchases submitted pursuant to paragraph (2) above
shall be deemed to be the Purchaser's Computed Peak Requirement in
each month of the Operating Year as specified in such schedule and
the twelve monthly amounts of energy determined pursuant to
paragraph (7) above shall be deemed to be the Purchaser's Computed
Average Energy Requirement for each such month of the Operating Year.
(9) Before requesting implementation on its behalf of a
regional load curtailment program affecting loads besides its own or
14
a regional shortage- sharing mechanism affecting such loads, the
Purchaser shall purchase all energy, to the extent necessary to make
up its resource deficiency, from resources available to the Purchaser
as documented by Bonneville at a cost equal to or less than the sum
of 115 percent of the incremental operating cost of oil -fired
generation from simple cycle combustion turbines and the cost for
transmission and transmission losses not to exceed 15 percent of the
cost of such generation.
For the purpose of this paragraph (9) a Purchaser's resource
deficiency shall be the amount, if any, by which the Purchaser's most
current estimate of its annual average Estimated Firm Energy Load for
such Operating Year exceeds the sum of:
(A) The estimated Assured Energy Capability of the
Purchaser's Firm Resources for such Operating Year, determined
in the manner provided in paragraph (2) above;
(B) The assured energy capability, determined in the
manner provided in section 16 and paragraph (2) above, of
resources acquired by the Purchaser on a firm basis in addition
to the Purchaser's Firm Resources for such Operating Year; and
(C) The amounts of energy shown in the Purchaser's
schedule of Contracted Requirements purchases for such Operating
Year."
(e) Section 17(c) is deleted and replaced by a new section 17(c) as
follows:
"(c) If the Purchaser does not request that Bonneville sell to it on
the basis of Planned Computed Requirements or Contracted Requirements or
if Bonneville disapproves the Purchaser's request to purchase on the basis
15
of Planned Computed Requirements, the Purchaser shall purchase on the
basis of Actual Computed Requirements and its Computed Peak Requirement
and Computed Average Energy Requirement shall be determined after the end
of each month based on the Purchaser's Actual Firm Load."
(f) Section 17(g)(1) is deleted and replaced by a new section 17(g)(1) as
follows:
"(1) During Heavy Load Hours: the larger of the Purchaser's
Computed Peak Requirement or its Computed Average Energy Requirement;
provided, however, that after June 30, 1987, Bonneville may limit
the amounts of power it makes available during up to six Heavy Load
Hours of each day designated by Bonneville to amounts less than the
Purchaser's Computed Average Energy Requirement but not less than the
Purchaser's Computed Peak Requirement. Bonneville shall not so limit
the amounts of power it makes available unless: (A) Bonneville has
informed the Purchaser's representative by the time specified in the
Power Scheduling Provisions Exhibit that Bonneville will make such
limitation; (B) Bonneville has limited all other Customers having
contracts which permit this limitation approximately in proportion to
the amount by which each such Customer's Computed Average Energy
Requirement exceeds its Computed Peak Requirement for such month; and
(C) Bonneville has determined that such limitation is reasonably
necessary either (1) to enable Bonneville to meet loads which
Bonneville serves from firm load carrying capability as defined in
the Coordination Agreement or (2) to serve other loads in the Pacific
Northwest which Bonneville has previously committed to serve provided
that the Purchaser, using its best efforts, is able to comply with
such request on an operating basis. Bonneville shall demonstrate to
16
the Purchaser and to other Customers having similar contracts that
Bonneville has sufficient firm capacity resources to meet its firm
capacity obligations without invoking the limitations of this
paragraph (1) before Bonneville renews any existing contracts or
enters into any new contracts to deliver capacity to entities outside
the Pacific Northwest."
(g) Section 19(c) is amended by adding a new section 19(c)(3) as follows:
"(3) For any amounts due as compensation for reductions in
Bonneville's obligation to supply Firm Power as set forth in
section 11(b)."
IN WITNESS WHEREOF, the parties hereto have executed this amendatory
agreement in several counterparts.
By
Title
Date
ATTEST:
By Sherri L. Anderson
Title City Clerk
Date April 21, 1987
(WP- PKI- 1419c)
17
UNITED STATES OF AMERICA
Department of Energy
By
Bonneville Power d inistrator
THE CITY OF PORT ANGELES
Charles D. Whidden
Ma
April 21, 1987
1'
RECEIVED
MAY 1
1
Customer Service Objectives Exhibit
Exhibit C, Page 1 of 2
Table 1
8/10/82
Table 1 of the Customer Service Objectives Exhibit is applicable to the
Purchaser if the Purchaser is a public body, cooperative or Federal agency.
The provisions of Table 1 are subject to the provisions of Bonneville's
Customer Service Policy, which Bonneville may amend from time to time.
Bonneville will provide service to its Customers by constructing transmission
lines (115 kV or higher) and stepdown substations to the Customers utilization
voltage (12.5 kV or higher), (Customer Service Facilities), which are
necessary to provide the widest possible, diversified and efficient use of
electric power. To accomplish this objective, construction of new Customer
Service Facilities will be undertaken following studies conducted jointly by
Bonneville and the Customer to determine the best engineering, economic, and
environmental plan of service based on a one utility concept of evaluation.
Bonneville's primary transmission responsibility is to provide a stable and
reliable transmission system for the integration and delivery of the bulk
power requirements in the Pacific Northwest. It is intended that the Customer
will assume the primary role for distribution of this power to the Consumer.
In recognition of this basic division of responsibility, Bonneville will
construct the necessary Customer Service Facilities, providing that capital
recovery is reasonably assured, until such time that the load density in the
area under consideration reaches a point that requires construction of
customer service substations in relatively close proximity. At this point,
the Customer will assume as part of its distribution utility responsibility,
construction of the transmission lines and stepdown substations required to
serve the loads within this high load density area. Therefore, the scope of
Bonneville's participation will be narrowed to providing the required high
voltage transmission facilities into the load area and stepdown substations to
the local transmission level while conforming with Bonneville's published
reliability standards, which may be amended by Bonneville from time to time.
It is the intent that the dividing line between Bonneville's transmission
responsibility and the Customer's distribution responsibility be a dynamic
relationship which will shift from Bonneville to the Customer as the load
density in a particular area increases.
Joint utility planning and one utility concept of evaluation will be the
foundation for all Bonneville customer service planning efforts. These
concepts have become more important in recent years to insure maximum
electrical system efficiencies, and minimize impact on the environment in
addition to meeting other economic and engineering criteria.
Bonneville's Customer Service Policy will encourage additional joint utility
planning including (1) better long -range planning; (2) energy loss reduction
studies, including common standards of conductor economics, and distribution
(WP- PKI- 1419c)
Exhibit C, Page 2 of 2
Table 1
8/10/82
voltage levels; (3) voltage regulation on the transmission and distribution
system; and (4) elimination of duplicate facilities such as may result from
separate substations and low voltage circuit breakers.
At the request of Purchaser, which has not specified an amount of residential
load or has specified an amount of zero under Exhibit D of the Residential
Purchase and Sale Agreement, Bonneville shall enter into a transmission
services agreement which shall provide benefits to such Purchaser for its
transmission system which the Purchaser would have received under a
Residential Purchase and Sale Agreement and the Average System Cost
methodology.
(WP- PKI- 1419c)
Customer Service Objectives Exhibit
Exhibit C, Page 1 of 1
Table 2
8/10/82
Table 2 of the Customer Service Objectives Exhibit is applicable to the
Purchaser if the Purchaser is an investor -owned utility. Bonneville and the
Purchaser have not agreed on objectives for the provision of new Customer
Service Facilities by Bonneville. Bonneville shall not have any obligation to
provide Customer Service Facilities to the Purchaser until Bonneville and the
Purchaser mutually agree upon a set of objectives for the provision of such
facilities.
At the request of Purchaser, which has not specified an amount of residential
load or has specified an amount of zero under Exhibit D of the Residential
Purchase and Sale Agreement, Bonneville shall enter into a transmission
services agreement which shall provide benefits to such Purchaser for its
transmission system which the Purchaser would have received under a
Residential Purchase and Sale Agreement and the Average System Cost
methodology.
RECEIVED
MAY 1 5 1987gt-
E
c i
This revision adds a metering point to the Port Angeles Point of Delivery at
the Morse Creek Hydroelectric Generation Plant.
1. CROWN ZELLERBACH POINT OF DELIVERY:
Location: the point in the Government's Port Angeles Substation where the
69 kV facilities of the parties hereto are connected;
Voltage: 69 kV;
Metering: in the Government's Port Angeles Substation, in the 69 kV
circuit over which such electric power flows;
Exception: charges for electric power shall be computed by combining
deliveries at the Crown Zellerbach, Port Angeles, and Rayonier Points of
Delivery coincidentally pursuant to the Combining Deliveries
Coincidentally section of Exhibit B. Charge for diversity in demands for
electric energy at such points shall be $2,323 per month. Such charge
shall be subject to review not more often than once every three years.
2. PORT ANGELES POINT OF DELIVERY:
Voltage: 69 kV;
Metering:
POINTS OF DELIVERY
Revision No. 1
Exhibit H, Page 1 of 3
Contract No. DE- MS79- 81BP90450
The City of Port Angeles
Effective at 2400 hours on the date
of execution of this Revision
Location: the point in the Government's Port Angeles Substation where the
69 kV facilities of the parties hereto are connected;
(a) in the Government's Port Angeles Substation, in the 69 kV circuit
over which such electric power flows;
(b) in the Purchaser's Morse Creek Hydroelectric Generation Plant, in the
0.48 kV circuit over which such electric power flows;
Exceptions:
Revision No. 1
Exhibit H, Page 2 of 3
Contract No. DE- MS79- 81BP90450
The City of Port Angeles
Effective at 2400 hours on the date
of execution of this Revision
(a) the revenue meters at metering point (b) are owned by the Purchaser;
(b) the period of service for metering point (b) shall only be in effect
when the City of Port Angeles has a contract for the transmission of
the output from the Morse Creek Hydroelectric Generation Plant;
(c) there shall be an adjustment for losses between the Point of Delivery
and metering point (b), and such adjustment shall be specified in
correspondence transmitted between Bonneville and the Purchaser;
(d) after adjustment for losses to metering point (b) as specified above,
amounts of electric power delivered at the Port Angeles Point of
Delivery shall be determined by subtracting amounts measured at
metering point (b) from coincidental amounts measured at metering
point (a);
(e) charges for electric power shall be computed by combining deliveries
at the Crown Zellerbach, Port Angeles, and Rayonier Points of
Delivery coincidentally pursuant to the Combining Deliveries
Coincidentally section of Exhibit B. Charge for diversity in demands
for electric energy at such points shall be $2,323 per month. Such
charge shall be subject to review not more often than once every
three years;
(f) the Purchaser and Bonneville agree and hereby ratify that metering
point (b) has been included as a metering point under this Agreement
since 2400 hours on June 14, 1987.
3. RAYONIER POINT OF DELIVERY:
Title
Date
Location: the point in the Government's Port Angeles Substation where the
69 kV facilities of the parties hereto are connected;
Voltage: 69 kV;
Metering: in the Government's Port Angeles Substation, in the 69 kV
circuit over which such electric power flows;
Exception: charges for electric power shall be computed by combining
deliveries at the Crown Zellerbach, Port Angeles, and Rayonier Points of
Delivery coincidentally pursuant to the Combining Deliveries
Coincidentally section of Exhibit B. Charge for diversity in demands for
electric energy at such points shall be $2,323 per month. Such charge
shall be subject to review not more often than once every three years.
ACCEPTED:
THE CITY OF PO !ANGELES
B y
Title
Date 4 -5 -88
ATTESTED:
Mayor
By yAgeida
City Clerk
4 -5 -88
(WP- TC- 2292j)
Revision No. 1
Exhibit H, Page 3 of 3
Contract No. DE- MS79- 81BP90450
The City of Port Angeles
Effective at 2400 hours on the date
of execution of this Revision
UNITED STATES OF AMERICA
DEPARTMENT OF ENERGY
Bonnevilke Power Administration
By 4 A.
Admi s trator
Date of Execution
4
f
RESOLUTION NO. L I? rY.2
"ae
el 94
A RESOLUTION of the City of Port Angeles
authorizing the Mayor and City Clerk to
execute a Residential Purchase and Sale
Agreement with the United States of
America, Department of Energy, acting
by and through the Bonneville Power
Administration, under the provisions
of the Pacific Northwest Electric Power
Planning and Conservation Act, P. L.
96 -501.
WHEREAS, the City of Port Angeles, a Municipal Corpora-
tion of the State of Washington (hereafter "City is authorized
by law to purchase electric power and energy for its customers;
and
WHEREAS, the'United States of America, Department of
Energy, acting by and through the Bonneville Power Administration
(hereafter "Bonneville has requested the City to execute a
Residential Purchase and Sale Agreement (Contract No.
DE- MS79- 81BP90628), the provisions of which will enable the
utility to sell electric power to Bonneville at the average
system cost of its resources, and Bonneville in return to sell an
equivalent amount for resale to the utility's residential and
farm users, all under the provisions of the Northwest Electric
Power Planning and Conservation Act, P. L. 96 -501; and
WHEREAS, the City Council determines that execution of
this Contract is in the best interests of the City and its light
utility customers; NOW, THEREFORE,
BE IT RESOLVED THAT: The Mayor and City Clerk are
hereby authorized and directed, on behalf of the City, to execute
with Bonneville Contract No. DE- MS79- 81BP90628, dated August 22,
1981.
PASSED by the City Council of the City of Port Angeles
this /2 of 61.Ge -,�,Q 1982.
ATTEST:
Marian C. Parrish, City Clerk
APPROVED AS TO FORM:
Craig/L. Miller, City Attorney
UBLISHED:
,1,24&
M A YOO R
RESIDENTIAL PURCHASE AND SALE AGREEMENT
executed by the
UNITED STATES OF AMERICA
DEPARTMENT OF ENERGY
acting by and through the
BONNEVILLE POWER ADMINISTRATION
and
THE CITY OF PORT ANGELES, WASHINGTON
Index to Sections
Contract No. DE- MS79- 81BP90628
8/22/81
Section Page
1. Term of Agreement 3
2. Purchase by Bonneville 3
3. Purchase by Utility 3
4. In Lieu Purchase by Bonneville 4
5. Provisions Relating to Delivery 5
6. Accounting, Review, and Budgeting 5
7. Payment 6
8. Cost Benefits 6
9. Termination of Agreement 6
10. Election to Equalize Rates 6
11. Relating Only to Residential Purchase and Sale Agreements 8
12. Exhibits 8
Exhibit A (Priority Firm Power Rate Schedule PF -1)
and General Rate Schedule Provisions) 8
Section
Page
Exhibit B (General Contract Provisions [GCP Form PSC- 1]) 8
Exhibit C (Average System Cost Methodology) 8
Exhibit D (Residential Load Definition) 8
Exhibit E (Load Factor Specification) 8
Exhibit F (Determination of New Large Single Loads) 8
This AGREEMENT, 'executed /7 /R__by the UNITED STATES OF
O
AMERICA (Government), Department of Energy, acting by and through the
BONNEVILLE POWER ADMINISTRATION (Bonneville), and THE CITY OF PORT ANGELES,
WASHINGTON Utility), a municipal corporation of the state of Washington,
WITNESSETH:
WHEREAS the 96th Congress of the United States of America at the Second
Session enacted the Pacific Northwest Electric Power Planning and Conservation
Act, P.L. 96 -501, as amended (Regional Act); and
WHEREAS the Regional Act, among other matters, provides that a Pacific
Northwest electric utility may sell electric power to Bonneville at the
average system cost (ASC) of that utility's resources and that Bonneville
shall sell in return an equivalent amount of electric power for resale to that
utility's residential and farm users within the Pacific Northwest (Region); and
WHEREAS, Bonneville is required under Section 4(g)(1) of the Regional Act
to maintain comprehensive programs to insure widespread public involvement in
the formulation of regional power policies; and
WHEREAS Bonneville is authorized pursuant to law to dispose of electric
power and energy generated at various hydroelectric projects in the Pacific
Northwest or acquired from other resources, to construct and operate
2
1
WHEREAS Bonneville is authorized pursuant to law to dispose of electric
power and energy generated at various hydroelectric projects in the Pacific
Northwest or acquired from other resources, to construct and operate
transmission facilities, to provide transmission and other services, and to
enter into related agreements to carry out such authority;
POW, THEREFORE, the parties hereto mutually agree as follows:
1. Term of Agreement. This agreement shall be effective on the later of
(1) 2400 hours on the date of execution; or (2) 2400 hours on September 30,
1981, and shall terminate at 2400 hours on June 30, 2001, unless terminated
pursuant to section 9 below. Notwithstanding termination of this agreement,
all liabilities incurred hereunder shall continue until satisfied.
2. Purchase by Bonneville. Subject to the provisions of section 4 below
and subject to the per centum limitations specified in section 5(c)( of the
Regional Act which shall apply separately to each Jurisdiction, as defined in
Exhibit C, in which the Utility provides service, the Utility shall sell and
Bonneville shall purchase each month an amount of electric power not in excess
of the Utility's Residential Load, as defined in Exhibit D, for such month.
The amount of power to be sold by the Utility under this section shall be
determined pursuant to Exhibit 0 at the ASC determined pursuant to Exhibit C.
The Utility may sell power hereunder only for Residential Load that is
associated with its retail service areas. An exception to this is that the
Utility may also sell power for the Residential Loads of another utility as
agent for the other utility in accordance with an agreement with the other
utility that is approved by Bonneville and terminable at will by the other
utility.
3. Purchase by the Utility. Subject to the per centum limitations in
section 5(c)(2) of the Regional Act, Bonneville shall sell and the Utility
shall purchase each month an amount of electric power not in excess of the
3 Sec. 1, 2, 3
Utility's Pesidential Load for the month. The amount of energy purchased
shall be determined pursuant to Exhibit D, and the purchase price shall be the
rate determined pursuant to Exhibit A. Exhibit A shall be the then effective
rate established pursuant to section 7(b) of the Regional Act. For billing
purposes, the Utility's load factor shall be as determined pursuant to
Exhibit E.
4. In Lieu Purchase by Bonneville.
(a) In lieu of purchasing all or a portion of the electric power referred
to in section 2 above, Bonneville may acquire an equivalent amount of electric
power from other sources if the cost of such acquisition is less than the cost
of purchasing the electric power referred to in section 2. For the purpose of
determining the cost of any such in lieu purchase, transmission and production
costs, and transmission losses, as determined by Bonneville, shall be
included. Bonneville shall give the Utility not less than seven years prior
written notice of Bonneville's intent to use such acquisition in lieu of
purchasing all or a portion of the electric power referred to in section 2
above. This notice shall state the amount, duration, source, estimated cost
and estimated scheduling provisions of the intended acquisition. Any intended
acquisition shall be at least five years in duration.
(b) The Utility shall elect upon receipt of such notice: (1) to reduce,
in a manner determined by Bonneville pursuant to prudent utility practice, the
amount of power purchased by Bonneville pursuant to section 2 above by the
amount of the intended acquisition; or (2) to reduce to the cost of the
intended acquisition the ASC applicable to a portion of the power purchased by
Bonneville pursuant to section 2 above equal to the amount of the intended
acquisition. A Utility shall have 60 working days from the receipt of the
notice in subsection (a) above to elect (1) or (2).
4 Sec. 4
f
(c) Bonneville shall not acquire power from a resource for an in lieu
purchase hereunder if the Utility or another utility under a similar contract
has reduced its ASC rate pursuant to section 4(b)(^) above. Such resource may
be used for an in lieu purchase hereunder if such utility which reduced its
ASr later terminates its purchase from Bonneville under this agreement or such
similar agreement.
(d) Bonneville shall acquire power from a resource for an in lieu
purchase hereunder only if such resource is not needed to meet Bonneville's
obligations to supply firm power to customers in the Pegion, and such resource
shall not be a resource the cost of which previously has been assigned to
Bonneville's New Resource Firm Power rate under section 7(f) of the Regional
Act. Bonneville shall not execute a resource purchase agreement to acquire
power on behalf of the Utility in lieu of the electric power offered by the
Utility hereunder during periods when Bonneville has issued a notice of
restriction to any investor -owned utility, public body, cooperative, or
Federal agency.
5. Provisions Relating to Delivery. The Utility shall submit to
Bonneville no more frequently than once in any 30 -day period an accounting
invoice with supporting documentation for the Utility's Residential Load
billed during the billing period selected by the Utility. Such documentation
shall include the kilowatthours of energy which the Utility billed to its
Residential Load in each Jurisdiction. This accounting invoice shall be
deemed to be the receipt for the purchase and sale of power under this
agreement.
6. Accounting, Review, and Budgeting. The Utility shall keep up -to -date
records and documents showing all transactions and other arrangements made
pertaining to the terms of this agreement. These records and documents shall
5 Sec. 5, 6
contain information supporting the Utility's ASC as determined pursuant to
Exhibit C and the Utility's Residential Load. The Utility shall retain these
records and documents on file for at least five years. At Bonneville's
expense, Bonneville or its designee may, from time to time, conduct reviews or
inspection of the Utility's records, accounts, and related documents
pertaining to this agreement. The Utility shall fully cooperate in good faith
with any such reviews or inspections.
7. Payment. Within 30 days after receipt of the invoice referred to in
section 5 above, Bonneville shall verify the invoice, compute the amount due
the Utility from the sale under section 2 and the amount due Bonneville from
the sale under section 3, and either pay or bill the Utility for the
difference, as appropriate.
8. Cost Benefits. The cost benefits to the Utility within each
Jurisdiction attributable to Bonneville's providing electric power and energy
to the Utility's Residential Load under this agreement shall be passed through
directly to the Utility's Residential Load within such Jurisdiction. Cost
benefits means the reduction in the Utility's wholesale power costs during the
term of this agreement as a result of this agreement.
9. Termination of Agreement. The Utility may terminate or suspend this
agreement for a period of at least one year if the supplemental rate charge
provided for in section 7(b)(3) of the Regional Act is applied by Bonneville
and the cost of electric power sold to the Utility under section 3 of this
agreement exceeds the ASC of the power sold to Bonneville under section 2.
10. Election to Equalize Rates. The Utility may elect to have its
Exhibit C rate for any Jurisdiction deemed equal to the Exhibit A rate. Such
election shall be made in writing to Bonneville within 25 working days
following confirmation and approval by the Federal Energy Regulatory
6 Sec. 7, 8, 9, 10
Commission or its successor agency (FERC), on an interim or final basis, of a
change in the Exhibit A rate or in Exhibit C methodology, and will take effect
as of the effective date of that change.
During any period that such election is in effect, Bonneville shall debit
to a separate account the net exchange payment to Bonneville, if any, that
would have been required of the Utility if the Utility had not made such
election and shall credit to that account any exchange payments that would
have been made. The net balance in such account shall accumulate interest at
the rate specified in section IV.E. of Exhibit C.
During the period of any such election, any portion of the costs for
terminated resources associated with section 7(g) of the regional Act included
in the Exhibit A rate which would have been charged to the Utility shall be
payable by the Utility by means of a surcharge to the Utility's power sales
contract payments pursuant to section 5(b) of the Regional Act or, if the
Utility is not party to such a contract, monthly in cash as accrued. Such
surcharge payments shall not exceed the total costs incurred by Bonneville
during the same period and attributable to terminated resources which the
Utility has sold to Bonneville and which total costs are not otherwise
recovered currently through such section 7(g) allocations to any other rate or
rates paid by the Utility. Such payment also shall not exceed the payments
which the Utility would have made to Bonneville during each exchange period
had it not made such election. Section 7(g) costs so paid shall be excluded
from the separate account maintained pursuant to this section.
The Utility may rescind such election and resume full participation in the
exchange provided at that (a) the debit balance of such separate account be
less than or equal to zero; or (b) the Utility makes payments to Bonneville in
agreed upon installments to bring the debit balance to zero. Such recission
7
r
may be either by notice in writing effective upon delivery to Bonneville
within 25 working days following confirmation and approval by FERC, on an
interim or final basis, of a change in Exhibit A, or by notice in writing
effective on a date to be agreed upon by Bonneville and the Utility, which
date shall be within 13 months following delivery to Bonneville of the notice
of recission.
Upon termination of this agreement, any debit balance in such separate
account shall not be a cash obligation of the Utility, but shall be carried
forward to apply to any subsequent exchange by the Utility for the
Jurisdiction under any new or succeeding agreement.
11. Relating Only to Residential Purchase and Sale Agreements. The
Utility agrees to comply with the following statutes, Executive Orders, and
regulations to the extent applicable:
(a) the Rehabilitation Act of 1973, Public Law 93 -112, as amended, and
41 CFR 60 -741 (affirmative action for handicapped workers);
(b) the Vietnam Era Veterans Readjustment Assistance Act of 1974, Public
Law 92 -540, as amended, and 41 CFR 60 -250 (affirmative action for disabled
veterans and veterans of the Vietnam era);
(c) Executive Order 1162E and Al CFR 1- 1.1310 -2(a) (utilization of
minority business enterprises);
(d) the Small Business Act, as amended,
(e) Certification of Nonsegregated Facilities, 41 CFR 1 -1 ?.803 -10.
1 Exhibits. Exhibit A (Priority Firm Power Rate, Schedule PF -1, and
General Pate Schedule Provisions), Exhibit B (General Contract Provisions [GCP
Form PSC -1]), Exhibit C (Average System Cost Methodology), Exhibit D
(Residential Load Definition), Exhibit E (Load Factor Specification), and
Exhibit F (Determination of New Large Single Loads) are hereby made part of
8 Sec. 11, 12
this contract. Exhibit D shall be revised to incorporate additional
qualifying tariff schedules, subject to Bonneville's determination that the
loads served under these schedules are qualified under the Act. Each time
Bonneville has a new rate adjustment date, the Utility shall submit a revised
Exhibit E, prepared in the same manner as Exhibit E attached hereto, to
Bonneville within 20 working days of such date. The revised Exhibit E shall
become effective as of such date.
IN WITNESS WHEREOF, the parties have executed this Agreement in several
counterparts.
ATTEST:
By g iac4d.
Title (Fe.‘L.
Date 7 /9 cPc2
(WP- PCI- 0054c)
(8/22/81)
9
UNITED STATES OF AMERICA
Department of Energy
By
Bon eville Power 4cii nistrator
CITY OF PORT ANGELES
AK4 A/lette-1„_
Title 7)741.42,
Date &ter L,�.� i /9
By
EXHIBIT A
WHOLESALE POWER RATE SCHEDULES AND GENERAL RATE SCHEDULE PROVISIONS
SCHEDULE PF -1 PRIORITY FIRM POWER RATE
SECTION 1. Availability: This schedule is available for the purchase
of firm power to be used within the Pacific Northwest for resale or for
direct consumption by public bodies, cooperatives, Federal agencies, and
investor -owned utilities participating in the exchange under Section 5(c) of
the Pacific Northwest Electric Power Planning and Conservation Act (Regional
Act). This schedule supersedes Schedule EC -8 which went into effect on an
interim basis on December 20, 1979.
SECTION 2. Rate:
a. Demand Charge:
(1) for the billing months December through May, Monday
through Saturday, 7 a.m. through 10 p.m.: $2.80 per kilowatt of billing
demand.
(2) for the billing months June through November, Monday
through Saturday, 7 a.m. through 10 p.m.: $1.44 per kilowatt of billing
demand.
(3) all other hours: No demand charge.
b. Energy Charge:
(1) for the billing months September through March:
7.4 mills per kilowatthour of billing energy.
(2) for the billing months April through August: 6.9 mills
per kilowatthour of billing energy.
SECTION 3. Billing Factors: The factors to be used in determining the
billing for power purchased under this rate schedule are as follows:
a. For any purchaser not designated to purchase under
subsection 3(b), 3(c), or 3(d):
power factor;
(1) the contract demand as specified in the contract;
(2) the measured demand for the billing month adjusted for
(3) the measured energy for the billing month.
b. Designation of a purchaser to purchase on a computed demand
basis will be according to this section unless the terms of an existing
contract executed after December 5, 1980 provide otherwise. For any
A -1
EXHIBIT A
purchaser designated by BPA to purchase on a computed demand basis because
of such purchaser's potential ability either to sell generation from its
resources in such a manner as to increase BPA's obligation to deliver firm
power to such purchaser in an amount in excess of BPA's obligation prior to
such sale, or to redistribute the generation from its resources over time in
such a manner as to cause losses of power or revenue on the Federal System;
provided, however, that when a purchaser operates two or more separate
systems, only those systems designated by BPA will be covered by this
subsection:
(1) the peak computed demand for the billing month;
(2) the average energy computed demand for the billing month;
(3) the lesser of the peak computed demand for the billing
month or 60 percent of the highest peak computed demand during the previous
11 billing months;
power factor;
(4) the measured demand for the billing month adjusted for
(5) the measured energy for the billing month;
(6) the contract demand as specified in an agreement between
a purchaser and BPA for a specified period of time.
c. For any purchaser contractually limited to an allocation of
capacity and /or energy as determined by BPA pursuant to the terms of a
purchaser's power sales contract:
(1) the allocated demand for the billing month, as specified
in the contract;
power factor;
(3)
in the contract;
(2) the measured demand for the billing month adjusted for
the allocated energy for the billing month, as specified
(4) the measured energy for the billing month.
d. For any purchaser participating in the exchange under
Section 5(c) of the Pacific Northwest Electric Power Planning and
Conservation Act:
(1) sixty percent of the energy associated with the utility's
residential load as specified in the contract for each billing period;
(2) the demand calculated by applying the load factor,
determined as specified in the contract, to the energy in 3(d)(1) for each
billing period.
A -2
EXHIBIT A
SECTION 4. Determination of Billing Demand and Billing Energy:
a. For a purchaser governed by subsection 3(a):
(1) the billing demand for the month shall be factor 3(a)(1)
or 3(a)(2), as specified in the purchaser's power sales contract, except
that at such time as BPA determines that the limitation in Section 3(c) is
necessary, the billing demand for the month shall be factor 3(c)(2),
provided, however, that billing demand factor 3(c)(2), before adjustment for
power factor, shall not exceed factor 3(c)(1).
(2) the billing energy for the month shall be factor 3(a)(3)
except that at such time as BPA determines that the limitation in
Section 3(c) is necessary, the billing energy shall be factor 3(c)(4),
provided, however, that factor 3(c)(4) shall not exceed factor 3(c)(3).
b. For a purchaser governed by subsection 3(b):
(1) the billing demand for the month shall be the largest of
factors 3(b)(3), and 3(b)(4), or 3(b)(6) if applicable. Factor 3b(4),
before adjustment for power factor, shall not exceed the largest of factors
3(b)(1), 3(b)(2), or 3(b)(6) if applicable, except that at such time as BPA
determines that the limitation in Section 3(c) is necessary, the billing
demand for the month shall be factor 3(c)(2), provided, however, that
billing demand factor 3(c)(2), before adjustment for power factor, shall not
exceed factor 3(c)(1).
(2) the billing energy for the month shall be factor 3(b)(5)
except that at such time as BPA determines that the limitation in
Section 3(c) is necessary, the billing energy shall be factor 3(c)(4),
provided, however, that factor 3(c)(4) shall not exceed factor 3(c)(3).
Factor 3(b)(5) shall not exceed factor 3(b)(2) times the number of hours
during such month.
c. For purchaser governed by subsection 3(d):
(1) The billing demand for the month shall be factor 3(d)(2).
(2) The billing energy for the month shall be factor 3(d)(1).
SECTION 5. Adjustments:
a. Power Factor: The adjustment for power factor, when
specified in this rate schedule or in the power sales contract, may be made
by increasing the measured demand for each month by 1 percent for each
1 percent or major fraction thereof by which the average lagging power
factor, or average leading power factor, at which energy is supplied during
such month is less than 95 percent, such average power factor to be computed
to the nearest whole percent from the formula given in Section 9.1 of the
General Rate Schedule Provisions.
A -3
EXHIBIT A
The adjustment for power factor may be waived in whole or in part
by BPA. Unless specifically otherwise agreed, BPA may, if necessary to
maintain acceptable operating conditions on the Federal System, restrict
deliveries of power to a purchaser at a point of delivery or for a system at
any time that the average power factor for all classes of power delivered to
a purchaser at such point of delivery or for such system is below 75 percent
lagging or 75 percent leading.
b. At -Site Power: At -site power purchased for consumption by a
purchaser shall be used within 15 miles of the powerplant specified in the
power sales contract. At least 90 percent of any at -site power purchased
for resale shall be used within 15 miles of the specified powerplant.
The monthly demand charge for at -site firm power will be the
monthly demand charge for priority firm power reduced by $0.257 per kilowatt
of billing demand.
At -site priority firm power is made available only for those
utility customers purchasing at -site firm power under existing contracts.
At -site priority firm power may be purchased by such utility customers under
new contracts only until a date certain specified in such new contracts. If
deliveries are made from an interconnection with the Federal System other
than at one of such designated points, the purchaser shall pay an amount
adequate to cover the annual cost of the facilities which would have been
required to deliver such power to such point from either the generator bus
at the generating plant, or from the adjacent point as designated by BPA.
This use -of- facilities charge shall be in addition to the charge determined
by the application of Section 2 of the Rate Schedule as reduced by the
provisions of this subsection.
c. Low- Density Discount: A predetermined discount will be
applied each month of a calendar year to the charges for power purchased
under contracts between BPA and its customers. The amount of such discount
is based on the ratio of the total annual energy requirements of the
purchaser's electric operations during the preceding calendar year to the
purchaser's depreciated investment in electric plant in service (excluding
generating plant) at the end of such year, or the purchaser's ratio of
residential consumers per mile of line. This calculation of such ratio will
be made using the customer's entire system. Provided that the purchaser's
ratio of residential consumers per mile of line does not exceed ten, this
discount shall be:
(1) Seven percent if such ratio is less than 15 kilowatthours
per dollar of net investment or if the number of consumers per mile of line
is two or less.
(2) Five percent if such ratio is equal to or greater than 15
and less than 25 kilowatthours per dollar of net investment, or if the
number of consumers per mile of line is four or less.
EXHIBIT A
(3) Three percent if such ratio is equal to or greater than
25 and less than 35 kilowatthours per dollar of net investment, or if the
number of consumers per mile of line is six or less.
SECTION 6. Unauthorized Increase: That portion of (a) any 60- minute
clock -hour integrated demand or scheduled demand (the total amount of power
scheduled to the purchaser from BPA) that cannot be assigned to a class of
power which BPA delivers on such hour pursuant to contracts between BPA and
the purchaser or to a type of power which the purchaser acquires from
sources other than BPA which BPA delivers during such hour, or (b) the total
of a purchaser's 60- minute clock -hour integrated or scheduled demands during
a billing month which cannot be assigned to a class of power which BPA
delivers during such month pursuant to contracts between BPA and the
purchaser or to a type of power which the purchaser acquires from sources
other than BPA which BPA delivers during such month, may be considered an
unauthorized increase. Each 60- minute clock -hour integrated or scheduled
demand shall be considered separately in determining the amount which may be
considered an unauthorized increase pursuant to (a) and the total of such
amounts which are in fact considered unauthorized increases shall be
excluded from the total of the integrated or scheduled demands for such
month in determining the amount which may be considered an unauthorized
increase under (b).
The charge for an unauthorized increase shall be $0.13 per kilowatthour.
SECTION 7. General Provisions: Sales of power under this schedule
shall be subject to the provisions of the BPA Project Act, as amended, the
Regional Preference Act, the Federal Columbia River Transmission System Act,
the Pacific Northwest Electric Power Planning and Conservation Act, and the
General Rate Schedule Provisions.
GENERAL RATE SCHEDULE PROVISIONS
EXHIBIT A
SECTION 1.1. Priority and New Resource Firm Power: Priority and new
resource firm power is electric power which BPA will make continuously
available to a purchaser to meet its net firm load requirements within the
Pacific Northwest except when restricted because the operation of generation
or transmission facilities used by BPA to service such purchaser is
suspended, interrupted, interfered with, curtailed, or restricted as the
result of the occurrence of any condition described in the Uncontrollable
Forces or Continuity of Service Sections of the General Contract Provisions
of the contract. Such restriction of priority and new resource firm power
shall not be made until industrial firm power has been restricted in
accordance with Section 1.4 and until modified firm power has been
restricted in accordance with Section 1.2.
SECTION 1.2. Modified Firm Power: Modified firm power is electric
power which BPA will make continuously available to a purchaser on a
contract demand basis subject to: (a) the restriction applicable to
priority and new resource firm power, and (b) the following:
When a restriction is made necessary because the operation of generation
or transmission facilities used by BPA to serve such purchaser and one or
more priority and new resource firm power purchasers is suspended,
interrupted, interfered with, curtailed, or restricted as a result of the
occurrence of any condition described in the Uncontrollable Forces or
Continuity of Service Sections of the General Contract Provisions of the
contract BPA shall restrict such purchaser's contract demand for modified
firm power to the extent necessary to prevent, if possible, or miminize
restriction of any priority and new resource firm power, provided, however
that:
(1) such restriction of modified firm power shall not exceed
at any time 25 percent of the contract demand therefore, and
(2) the accumulation of such restrictions of modified firm
power during any calendar year, expressed in kilowatthours, shall not exceed
500 times the contract demand therefor. When possible, restrictions of
modified firm power will be made ratably with restrictions of industrial
firm power based on the proportion that the respective contract demands bear
to one another. The extent of such restrictions shall be limited for
modified firm power by this subsection and for industrial firm power by the
Restriction of Deliveries Section of the General Contract Provisions of the
contract.
SECTION 1.3. Firm Capacity: Firm capacity is capacity which BPA
assures will be available to a purchaser on a contract demand basis except
when operation of generation or transmission facilities used by BPA to serve
such purchaser is suspended, interrupted, interfered with, curtailed, or
restricted as the result of the occurrence of any condition described in the
A -6
EXHIBIT A
Uncontrollable Forces or Continuity of Service Sections of the General
Contract Provisions of the contract.
SECTION 1.4. Industrial Firm Power: Industrial firm power is electric
power which BPA will make continuously available to a purchaser on a
contract demand basis subject to: (a) the restriction applicable to
priority and new resource firm power; and (b) the following:
(1) the restrictions given in the Restriction of Deliveries
Section of the Power Sales Provisions of the contract.
(2) when a restriction is made necessary because of the
operation of generation or transmission facilities used by BPA to serve such
purchaser and one or more priority and new resource firm power purchasers is
suspended, interrupted, interfered with, curtailed, or restricted as a
result of the occurrence of any condition described in the Uncontrollable
Forces or Continuity of Service Sections of the General Contract Provisions
of the contract, BPA shall restrict such purchaser's operating demand for
industrial firm power to the extent necessary to prevent, if possible, or
minimize restriction of priority and new resource firm power. When
possible, restrictions of industrial firm power will be made ratably with
restrictions of modified firm power based on the proportion that the
respective contract and operating demands bear to one another. The extent
of such restrictions shall be limited for modified firm power by
Section 1.2(b) of these General Rate Schedule Provisions and for industrial
firm power by the Restrictions of Deliveries Section of the contract.
SECTION 1.5. Authorized Increase: An authorized increase is an amount
of electric power specified in the contract in excess of the contract or
operating demand for priority firm power, new resource firm power, modified
firm power, or industrial firm power that BPA may be able to make available
to the purchaser upon its request. The purchaser shall make such request in
writing stating the amount of increase requested, the purpose for which it
will be used, and the period for which it is needed. Such request shall be
made prior to the first calendar month beginning such specified period. BPA
will then determine whether such increase can be made available, but it
shall retain the right to restrict the delivery of such increase if it
determines at any subsequent time that such increase will no longer be
available.
The purchaser may curtail an authorized increase, in whole or in part,
at the end of any billing month within the period such authorized increase
is to be made available.
SECTION 1.6. Firm Energy: Firm energy is energy which BPA assures
will be available to a purchaser during the period or periods specified in
the contract except during hours as may be specified in the contact and when
the operation of the Government's facilities used to serve the purchaser are
suspended, interrupted, interfered with, curtailed, or restricted by the
occurrence of any condition described in the Uncontollable Forces or
A -7
SECTION 2.2. Measured Demand:
EXHIBIT A
Continuity of Service Sections of the General Contract Provisions of the
contract.
SECTION 2.1. Contract Demand: The contract demand shall be the number
of kilowatts that the purchaser agrees to purchase and BPA agrees to make
available. BPA may agree to make deliveries at a rate in excess of the
contract demand at the request of the purchaser (authorized increase), but
shall not be obligated to continue such excess deliveries.
a. The purchaser's measured demand will be determined
according to this section unless the terms of a contract executed after
December 5, 1980 provide otherwise.
b. Except where deliveries are scheduled as hereinafter
provided, the measured demand in kilowatts shall be the largest of the
60- minute clock -hour integrated demands at which electric energy is
delivered to a purchaser at each point of delivery during each time period
specified in the applicable rate schedule during any billing period. Such
largest 60- minute integrated demand shall be determined from measurements
made as specified in the contract, or as determined in Section 3.2 herein.
BPA, in determining the measured demand, will exclude any abnormal 60-minute
integrated demands due to or resulting from (a) emergencies or breakdowns
on, or maintenance of, the Federal System facilities; and (b) emergencies on
the purchaser's facilities, provided that such facilities have been
adequately maintained and prudently operated as determined by BPA. For
those contracts to which BPA is a party and which provide for delivery of
more than one class of electric power to the purchaser at any point of
delivery, the portion of each 60- minute integrated demand assigned to any
class of power shall be determined as specified in the contract. The
portion of the total measured demand so assigned shall constitute the
measured demand for each such class of power.
If the flow of electric energy to a purchaser's system through two
or more points of delivery cannot be adequately controlled because such
points are interconnected within the purchaser's system, or the purchaser's
system is interconnected directly or indirectly with the Federal System, the
purchaser's measured demand for each class of power for such system for any
billing period shall be the largest of the hourly amounts of such class of
power which are scheduled for delivery to the purchaser during each time
period specified in the applicable rate schedule.
SECTION 2.3. Peak Computed Demand and Energy Computed Demand:
The purchaser's peak computed demand and energy computed demand will be
determined according to this section unless terms of a contract executed
after December 5, 1980 provide otherwise.
The purchaser's peak computed demand for each billing month shall be the
largest amount during such month by which the purchaser's 60- minute system
demand exceeds its assured peaking capability.
The purchaser's average energy computed demand for each billing month
shall be the amount during such month by which the purchaser's actual system
average load exceeds its assured average energy capability.
a. General Principles:
EXHIBIT A
(1) The assured peaking and average energy capability of each
of the purchaser's systems shall be determined and applied separately.
(2) As used in this section, "year" shall mean the 12 -month
period commencing July 1.
(3) The critical period is that period, determined for the
purchaser's system under adverse streamflow conditions adjusted for current
water uses, assured storage operation, and appropriate operating agreements,
during which the purchaser would have the maximum requirement for peaking or
energy after utilizing the firm capability of all resources available to its
system in such a manner as to place the least requirement for capacity and
energy on BPA.
(4) Critical water conditions are those conditions of
streamflow based on historical records, adjusted for current water uses,
assured storage operation, and appropriate operating agreements, for the
year or years which would result in the minimum capability of the
purchaser's firm resources during the critical period.
(5) Prior to the beginning of each year the purchaser shall
determine the assured capability of each of the purchaser's systems in terms
of peaking and average energy for each month of each year or years within
the critical period. The firm capability of all resources available to the
purchaser's system shall be utilized in such a manner as to place the least
requirement for capacity and energy on BPA. Such assured capability shall
be effective after review and approval by BPA.
(6) The purchaser's assured energy capability shall be
determined by shaping its firm resources to its firm load in a manner which
places a uniform requirement on BPA within each year of the critical period
with such requirement increasing each year not in excess of the purchaser's
annual load growth.
(7) As used herein, the capability of a firm resource shall
include only that portion of the total capability of such resource which the
purchaser can deliver on a firm basis to its load. The capabilities of all
generating facilities which are claimed as part of the purchaser's assured
capability shall be determined by test or other substantiating data
acceptable to BPA. BPA may require verification of the capabilities of any
or all of the purchaser's generating facilities. Such verification will not
A -9
EXHIBIT A
be required more often than once each year for operating plants, or more
often than once each third year for thermal plants in cold standby status,
if BPA determines that adequate annual preventive maintenance is performed
and the plant is capable of operating at its claimed capability.
0) In determining assured capability, the aggregate
capability of the purchaser's firm resources shall be appropriately reduced
to provide adequate reserves.
b. Determination of Assured Capability: The purchaser's assured
peaking and energy capabilities shall be the respective sums of the
capabilities of its hydroelectric generating plants based on the most
critical water conditions on the purchaser's system, the capabilities of its
thermal generating plants based on the adverse fuel or other conditions
reasonably to be anticipated; and the firm capabilities of other resources
made available under contracts prior to the beginning of the year, after
deduction of adequate reserves. Assured capabilities shall be determined
for each month if the purchaser has seasonal storage. The capabilities of
the purchaser's firm resources shall be determined as follows:
(1) Hydroelectric Generating Facilities: The capability of
each of the purchaser's hydroelectric generating plants shall be determined
in terms of both peaking and average energy using critical water
conditions. The average energy capability shall be that capability which
would be available under the storage operation necessary to produce the
claimed peaking capability.
Seasonal storage shall mean storage sufficient to regulate all
the purchaser's hydroelectric resources in such a manner that when combined
with the purchaser's thermal generating facilities, if any, and with firm
capacity and energy available to the purchaser under contracts, a uniform
energy computed demand for a period of one (1) month or more would result.
A purchaser having seasonal storage shall, within 10 days
after the end of each month in the critical period, notify BPA in writing of
the assured energy capability to be applied tentatively to the preceding
month; such notice shall also specify the purchaser's best estimate of its
average system energy load for such month. If such notice is not submitted,
or is submitted later than 10 days after the end of the month to which it
applies, subject to the limitations stated herein, the assured energy
capability determined for such month prior to the beginning of the year
shall be applied to such month and may not be changed thereafter.
If notice has been submitted pursuant to the preceding
paragraph, the purchaser shall, within 30 days after the end of the month,
submit final specification of the assured energy capability to be applied to
the preceding month; provided that the assured energy capability so
specified shall not differ from the amount shown in the original notice by
more than the amount by which the purchaser's actual average system energy
load for such month differs from the estimate of that load shown in the
original notice. If the assured energy capability for such month differs
A -10
EXHIBIT A
from that determined prior to the beginning of the year for such month, the
purchaser, if required by BPA, shall demonstrate by a suitable regulation
study based on critical water conditions that such change could actually be
accomplished, and that the remaining balance of its total critical period
assured energy capability could be developed without adversely affecting the
firm capability of other purchaser's resources. The algebraic sum of all
such changes in the purchaser's assured energy capability shall be zero at
the end of the critical period or year, whichever is earlier. Appropriate
adjustments in the assured peaking capability shall be made if required by
any change in reservoir operation indicated by such revisions in the monthly
distribution of critical period energy capability.
(2) Thermal Generating Facilities: The capability of each
of the purchaser's thermal generating plants shall be determined in terms of
both peaking and average energy. Such capabilities shall be based on the
adverse fuel or other conditions reasonably to be anticipated. The effect
of limitations on fuel supply due to war or other extraordinary situations
will be evaluated at the time of occurrence.
(3) Other Sources of Power: The assured capability of other
resources available to the purchaser on a firm basis under contracts shall
be determined prior to each year in terms of both peaking and average energy.
c. Determination of Computed Demand: The purchaser's computed
demand for each billing month shall be the greater of:
(1) The largest amount during such month by which the
purchaser's actual 60-minute system demand, excluding any loads otherwise
provided for in the contract, exceeds its assured peaking capability for
such month, or period within such month, or
(2) The largest amount for such month, or period within such
month, by which the purchaser's actual system average energy load, excluding
the average energy loads otherwise provided for in the contract, exceeds its
assured average energy capability.
The use of computed demands as one of the alternatives in
determining billing demand is intended to assure that each purchaser who
purchases power from BPA to supplement its own firm resources will purchase
amounts of power substantially equivalent to the additional capacity and
energy which the purchaser would otherwise have to provide on the basis of
normal and prudent operations, viz, sufficient capacity and energy to carry
the load through the most critical water or other conditions reasonably to
be anticipated, with an adequate reserve.
Since the computed demand depends on the relationship of
capability of resources to system requirements, the computed demand for any
month cannot be determined until after the end of the month. As each
purchaser must estimate its own load, and is in the best position to follow
its development from day to day, it will be the purchaser's responsibility
to request scheduling of priority and new resource firm power, including any
A -11
EXHIBIT A
increase over previously established demands, on the basis estimated by the
purchaser to result in the most advantageous purchase of the power to be
billed at the end of the month.
SECTION 2.4. Restricted Demand: A restricted demand shall be the
number of kilowatts of priority firm power, new resource firm power,
modified firm power, industrial firm power, or authorized increase of any of
the preceding classes of power which results when BPA has restricted
delivery of such power for one (1) clock -hour or more. Such restrictions by
BPA are made pursuant to the power sales contract for industrial firm power
and pursuant to Section 1.1 and 1.2 of the General Rate Schedule Provisions
for priority and new resource firm power and modified firm power,
respectively. Such restricted demand shall be determined by BPA after the
purchaser has made its determination to accept such restriction or to
curtail its contract demand for the month in accordance with Section 2.5 of
the General Rate Schedule Provisions.
SECTION 2.5. Curtailed Demand: A curtailed demand shall be the number
of kilowatts of priority firm power, new resource firm power, modified firm
power, industrial firm power, or authorized increase of any of the preceding
classes of power which results from the purchaser's request for such power
in amounts less than the contract demand therefor. Each purchaser of
industrial firm power or modified firm power may curtail its demand in
accordance with the contract. Each purchaser of an authorized increase in
excess of priority firm power, new resource firm power, modified firm power,
or industrial firm power may curtail its demand in accordance with
Section 1.5 of the General Rate Schedule Provisions.
SECTION 3.1. Billing: Unless otherwise provided in the contract,
power made available to a purchaser at more than one point of delivery shall
be billed separately under the applicable rate schedule or schedules. The
contract may provide for combined billing under specified conditions and
terms when (a) delivery at more than one point is beneficial to BPA; or
(b) the flow of power at the several points of delivery is reasonably beyond
the control of the purchaser.
If deliveries at more than one point of delivery are billed on a
combined basis for the convenience of the customer, a charge will be made
for the diversity between the measured demands at the several points of
delivery. The charge for the diversity shall be determined in a uniform
manner among purchasers and shall be specified in the contract.
SECTION 3.2. Determination of Estimated Billing Data: If the
purchased amounts of capacity, energy, or the 60- minute integrated demands
for energy must be estimated from data other than metered or scheduled
quantities, BPA and the purchaser will agree on billing data to be used in
preparing the bill. If the parties cannot agree on estimated billing
quantities, a determination binding on both parties shall be made in
accordance with the arbitration provisions of the contract.
A -13
EXHIBIT A
SECTION 4.1 Application of Rates during Initial Operation Period: For
an initial operating period, not in excess of 3 months, beginning with the
commencement of operation of a new industrial plant, a major addition to an
existing plant, or reactivation of an existing plant or important part
thereof, BPA may agree (a) to bill for service to such new, additional, or
reactivated plant facilities on the basis of the measured demand for each
day, adjusted for power factor; or (b) if such facilities are served by a
distributor purchasing power therefor from BPA to bill for that portion of
such distributor's load which results from service to such facilities on the
basis of the measured demand for each day, adjusted for power factor. Any
rate schedule provisions regarding contract demand, billing demand, and
minimum monthly charge which are inconsistent with this Section shall be
inoperative during such initial operating period.
The initial operating period and the special billing provisions may, on
approval by Bonnevillle, be extended beyond the initial 3 -month period for
such additional time as is justified by the developmental character of the
operations.
SECTION 5.1. Energy Supplies for Emergency Use: A purchaser taking
priority and /or new resource firm power shall pay in accordance with
Wholesale Nonfirm Energy Rate Schedule NF -1 and Emergency Capacity Schedule
CE -1 for any electric energy which has been supplied; (a) for use during an
emergency on the purchaser's system; or (b) following an emergency to
replace energy secured from sources other than BPA during such emergency,
except that mutual emergency assistance may be provided and settled under
exchange agreements.
SECTION 6.1. Billing Month: Meters will normally be read and bills
computed at intervals of 1 month. A month is defined as the interval
between meter reading dates which normally will be approximately 30 days.
If service is for less or more than the normal billing month, the monthly
charges stated in the applicable rate schedule will be appropriately
adjusted. Winter and summer periods identified in the rate schedules will
begin and end with the beginning and ending of the purchaser's billing month
having meter reading dates closest to the periods so identified.
SECTION 7.1. Payment of Bills: Bills for power shall be rendered
monthly and shall be payable at BPA's headquarters. Failure to receive a
bill shall not release the purchaser from liability for payment. Demand and
energy billings under each rate schedule application shall be rounded to
whole dollar amounts, by elimination of any amount of less than 50 cents and
increasing any amount from 50 cents through 99 cents to the next higher
dollar.
If BPA is unable to render the purchaser a timely monthly bill which
includes a full disclosure of all billing factors, it may elect to render an
estimated bill for that month to be followed at a subsequent billing date by
a final bill. Such estimated bill, if so issued, shall have the validity of
and be subject to the same repayment provisions as shall a final bill.
Average Power Factor Kilowatthours
EXHIBIT A
Bills not paid in full on or before the close of business of the 20th
day after the date of the bill shall bear an additional charge which shall
be the greater of one fourth percent (0.25 of the amount unpaid or $50.
Thereafter a charge on one twentieth percent (0.05 of the sum of the
initial amount remaining unpaid and the additional charge herein described
shall be added on each succeeding day until the amount due is paid in full.
The provisions of this paragraph shall not apply to bills rendered under
contracts with other agencies of the United States.
Remittances received by mail will be accepted without assessment of the
charges referred to in the preceding paragraph provided the postmark
indicates the payment was mailed on or before the 20th day after the date of
the bill. If the 20th day after the date of the b i l l is a Sunday or other
nonbusiness day of the purchaser, the next following business day shall be
the last day on which payment may be made to avoid such further charges.
Payment made by metered mail and received subsequent to the 20th day must
bear a postal department cancellation in order to avoid assessment of such
further charges.
BPA may, whenever a power bill or a portion thereof remains unpaid
subsequent to the 20th day after the date of the bill, and after giving 30
days advance notice in writing, cancel the contract for service to the
purchaser, but such cancellation shall not affect the purchaser's liability
for any charges accrued prior thereto.
SECTION 8.1. Approval of Rates: Schedules of rates and charges, or
modifications thereof', for electric power sold by BPA shall become effective
on a final basis after confirmation and approval by the Federal Energy
Regulatory Commission. Pending the establishment of procedures by the
Commission to approve rates on a final basis, the entity or entities having
been designated by the Secretary of Energy prior to December 5, 1980, shall
have authority to confirm and approve schedules of rates and charges on an
interim basis.
SECTION 9.1. Average Power Factor: The formula for determining average
power factor is as follows:
(Kilowatthours) (Reactive Kilovolt- ampere- hours)
The data used in the above formula shall be obtained from meters which
are ratcheted to prevent reverse registration.
When deliveries to a purchaser at any point of delivery include more
than one class of power or are under more than one rate schedule, and it is
impracticable to separately meter the kilowatthours and reactive
kilovoltamperehours for each class, the average power factor of the total
deliveries for the month will be used, where applicable, as the power factor
for each of the separate classes of power and rate schedules.
r
EXHIBIT A
SECTION 10.1. Temporary Curtailment of Contract Demand: The
reduction of charges for power curtailed pursuant to the purchaser's
contract and Section 1.5 and 2.5 hereof shall be applied in a uniform manner.
SECTION 11.1. General Provisions: The Wholesale Rate Schedules and
General Rate Schedule Provisions of the BPA Power Administration effective
July 1, 1981, supersede in their entirety BPA's Wholesale Power Rate
Schedule Provisions effective December 20, 1979.
(WP- PCI- 0405c)
GCP Form PSC 1
GENERAL CONTRACT PROVISIONS
Exhibit B
8 -25 -81
Index to Sections
Section Page
I. RELATING TO ALL PURCHASERS
A. IN REFERENCE TO MEANING
1. Definitions 1
2. Interpretation 4
B. IN REFERENCE TO COMPUTATION OF CHARGES
3. Measurements 5
4. Adjustment for Change of Conditions 5
5. Adjustment for Inaccurate Metering 5
6. Adjustment for Unbalanced Phase Demands 6
7. Reducing Charges for Interruptions 6
C. IN REFERENCE TO RATES
8. Equitable Adjustment of Rates 7
D. IN REFERENCE TO DELIVERY OF POWER
9. Character of Service 15
10. Point(s) of Delivery and Delivery Voltage 15
11. Metered Quantities 15
i
Index to Sections (Continued)
Section Page
12. Where Additional Facilities Required 15
13. Uncontrollable Forces 16
14. Continuity of Service 16
15. Delivery by Transfer 16
E. IN REFERENCE TO PAYMENT FOR POWER
16. Determination of and Assignment of Measured Demand 17
17. Billing of Multiple Points of Delivery 18
18. Payment of Bills 19
19. Determination of Estimated Billing Data 20
20. Average Power Factor 20
F. IN REFERENCE TO USE OF POWER
21. Changes in Requirements or Characteristics 21
22. Electric Disturbance 21
23. Harmonic Control 23
24. Balancing Phase Demands 23
G. IN REFERENCE TO FACILITIES
25. Measurements and Installation of Meters 23
26. Tests of Metering Installations 23
27. Permits 24
28. Ownership of Facilities 25
ii
Index to Sections (Continued)
Section Page
29. Inspection of Facilities 25
30. Facilities for Maintenance of Voltage 26
H. MISCELLANEOUS PROVISIONS
31. General Environmental Provision 26
32. Dispute Resolution and Arbitration 28
33. Enforcement of Rights for Benefit of Transferors 30
34. Net Billing 30
35. Contract Work Hours and Safety Standards 31
36. Convict Labor 32
37. Equal Employment Opportunity 33
38. Assignment of Contract 35
39. Waiver of Default 36
40. Notices and Computation of Time 36
41. Interest of Member of Congress 36
42. Priority of Pacific Northwest Customers 36
43. Resource Acquisition and Management 37
44. Cooperation with Regional Council 38
45. Rights of the Purchaser 39
II. RELATING ONLY TO PREFERENCE AGENCIES
46. Separation of Electric Operations and Funds
(All Public Agencies) 39
47. Statement of General Policies and Practices (Cities) 39
iii
Index to Sections (Continued)
Section Page
48. Approval of Contract 41
49. Prior Demands 41
III. RELATING ONLY TO PUBLIC BODY, COOPERATIVE, FEDERAL AGENCY, AND
INVESTOR -OWNED UTILITY PURCHASERS
A. IN REFERENCE TO COMPUTATION OF CHARGES
50. Effect of Reduction of Contract Demand 42
51. Combining Deliveries Coincidentally 42
52. Combining Deliveries Noncoincidentally 43
53. Power Factor Adjustment 44
B. IN REFERENCE TO PURCHASERS' OPERATING POLICIES
54. Retail Rates 44
C. IN REFERENCE TO USE OF POWER
55. Resale of Power 46
D. IN REFERENCE ONLY TO PURCHASERS WITH GENERATING FACILITIES
56. Nonfirm Deliveries 46
57. Emergency or Breakdown Relief 47
58. Effect on Generating Utility by Direct Service
Industrial Customer Power Sales Contract Provisions 47
iv
Index to Sections (Continued)
Section
IV. RELATING ONLY TO DIRECT SERVICE INDUSTRY PURCHASERS
A. IN REFERENCE TO COMPUTATION OF CHARGES
59. Demands 48
B. IN REFERENCE TO PURCHASE
60. Use and Resale of Power 48
v
Page
Exhibit B, Page 1 of 48
General Contract Provisions
8/25/81
I. RELATING TO ALL PURCHASERS
A. IN REFERENCE TO MEANING
1. Definitions. The definitions in the body of this contract and the
following additional definitions apply to this exhibit.
(a) "Billing Month," when used with respect to a Direct Service Industrial
Customer, means a calendar month.
(b) "Contractor" means the Purchaser.
(c) "Direct Service Industrial Customer" means a purchaser of industrial
firm power, modified firm power, or similar classes of power under contracts
providing for the purchase of any such class of power directly from Bonneville.
(d) "Federal System" or "Federal System Facilities" means the facilities
of the Federal Columbia River Power System, which for the purposes of this
contract shall be deemed to include the generating facilities of the Government
in the Pacific Northwest for which Bonneville is designated as marketing agent;
the facilities of the Government under the jurisdiction of Bonneville; and any
other facilities:
(1) from which Bonneville receives all or a portion of the generating
capability (other than station service) for use in meeting Bonneville's
loads, such facilities being included only to the extent Bonneville has the
right to receive such capability; provided, however, that "Bonneville's
loads" shall not include that portion of the loads of any Bonneville
customer which are served by a nonfederal generating resource purchased or
owned directly by such customer which may be scheduled by Bonneville;
(2) which Bonneville may use under contract, or license; or
Exhibit B, Page 2 of 48
General Contract Provisions
8/25/81
(3) to the extent of the rights acquired by Bonneville pursuant to
the Treaty, between the Government and Canada, relating to the cooperative
development of water resources of the Columbia River Basin, signed in
Washington, D.C., on January 17, 1961.
(e) "Federal Energy Regulatory Commission" means the Federal Energy
Regulatory Commission or its successor.
(f) "Measured Demand" when used with respect to a Direct Service
Industrial Purchaser means the largest of the Integrated Demands, adjusted as
appropriate to the Point of Delivery, for the time periods for which there is a
demand charge specified in the applicable rate schedule in the Wholesale Power
Rate Schedule and General Rate Schedule Provisions Exhibit during a Billing
,Month.
(g) "Point(s) of Delivery" means the point(s) of delivery listed either in
the Points of Delivery Exhibit to this contract or in the body of this contract.
(h) "P.L. 96 -501" means the Regional Act.
(i) "Transferor" means an entity which receives Bonneville's power or
energy at one point on such entity's system and makes such power or energy
available at another point on its system for the account of Bonneville.
(j) "Uncontrollable Forces" means:
(1) strikes or work stoppage affecting the operation of the
Purchaser's works, system, or other physical facilities or of the Federal
System Facilities or the physical facilities of any Transferor upon which
such operation is completely dependent; the term "strikes or work stoppage"
shall be deemed to include threats of imminent strikes or work stoppage
which reasonably require a party or Transferor to restrict or terminate its
Exhibit B, Page 3 of 48
General Contract Provisions
8/25/81
operations to prevent substantial loss or damage to its works, system, or
other physical facilities; or
(2) such of the following events as the Purchaser or Bonneville or
any Transferor by exercise of reasonable diligence and foresight, could not
reasonably have been expected to avoid:
(A) events, reasonably beyond the control of either party or any
Transferor, causing failure, damage, or destruction of any works,
system or facilities of such party or Transferor; the word "failure"
shall be deemed to include interruption of, or interference with, the
actual operation of such works, system, or facilities;
(B) floods or other conditions Caused by nature which limit or
prevent the operation of, or which constitute an imminent threat of
damage to, any such works, system, or facilities; and
(C) orders and temporary or permanent injunctions which prevent
operation, in whole or in part, of the works, system, or facilities of
either party or any Transferor, and which are issued in any bona fide
proceeding by:
(i) any duly constituted court of general jurisdiction; or
(ii) any administrative agency or officer, other than
Bonneville or its officers, provided by law (a) if said party or
Transferor has no right to a review of the validity of such order
by a court of competent jurisdiction; or (b) if such order is
operative and effective unless suspended, set aside, or annulled
by a court of competent jurisdiction and such order is not
suspended, set aside, or annulled in a judicial proceeding
Exhibit B, Page 4 of 48
General Contract Provisions
8/25/81
prosecuted by said party or Transferor in good faith; provided,
however, that if such order is suspended, set aside, or annulled
in such a judicial proceeding, it shall be deemed to be an
uncontrollable force" for the period during which it is in
effect; provided, further, that said party or Transferor, shall
not be required to prosecute such a proceeding, in order to have
the benefits of this section, if the parties agree that there is
no valid basis for contesting the order.
The term "operation" as used in this subsection shall be
deemed to include construction, if construction is required to
implement the contract and is specified therein.
(k) "Utility" means a party to a residential purchase and sale agreement
offered pursuant to section 5(c) of P.L. 96-501 which shall also be referred to
as the "Purchaser" for the purposes of this exhibit.
2. Interpretation.
(a) The provisions in this exhibit shall be deemed to be a part of the
contract body to which they are an exhibit. If a provision in such contract
body is in conflict with a provision contained in this exhibit, the former
shall prevail.
(b) If a provision in the General Rate Schedule Provisions incorporated in
the Wholesale Power Rate Schedules and General Rate Schedule Provisions Exhibit
is in conflict with a provision contained in this exhibit or the contract body,
this exhibit or the contract body shall prevail.
(c) Nothing contained in this contract shall, in any manner, be construed
to abridge, limit, or-deprive any party hereto of any means of enforcing any
remedy, either at law or in equity, for the breach of any of the provisions of
this contract which it would otherwise have.
B. IN REFERENCE TO COMPUTATION OF CHARGES
Exhibit B, Page 5 of 48
General Contract Provisions
8/25/81
3. Measurements. Each measurement of each meter mentioned in this
contract shall be the measurement automatically recorded by such meter or, at
the request of either party, the measurement as mutually determined by the best
available information.
If it is provided in this contract that measurements made by any of
the meters specified therein are to be adjusted for Tosses, such adjustments
shall be made by using factors, or by compensating the meters, as agreed upon
by the parties hereto. If changes in conditions occur which substantially
affect any such loss factor or compensation, it will be changed in a manner
which will conform to such change in conditions.
4. Adjustment for Change of Conditions. Changes in conditions may occur
after the date of execution of this contract which substantially affect factors
required by this contract to be used in determining (a) the charge for a
service or for use of facilities provided by Bonneville other than charges for
the sale of electric power and energy or (b) the amount of losses from the
transmission or transformation of electric power or energy. Such factors will
then be changed in an equitable manner which will conform to such changes in
conditions.
5. Adjustment for Inaccurate Metering. If any meter mentioned in this
contract fails to register, if the measurement made by such meter during a test
Exhibit B, Page 6 of 48
General Contract Provisions
8/25/81
made as provided in section 26 hereof varies by more than one percent from the
measurement made by the standard meter used in such test or if an error in
meter reading occurs, adjustment shall be made correcting all measurements for
the actual period during which such inaccurate measurements were made, if such
period can be determined. If such period cannot be determined the adjustment
shall be made for the period immediately preceding the test of such meter which
is equal to the lesser of (a) one -half the time from the date of the last
preceding test of such meter or (b) 6 months. Such corrected measurements
shall be used to recompute the amounts due from the Purchaser for the electric
power and energy made available under this contract during such period and
shall be used, when applicable, in future billings to the Purchaser. If the
total amount due from the Purchaser for such period as recomputed varies from
the total amount previously billed by Bonneville, Bonneville shall adjust the
wholesale power bill(s) as soon as practicable.
6. Adjustment for Unbalanced Phase Demands. If the Purchaser fails to
make promptly the changes mentioned in section 24 hereof, Bonneville may, after
giving written notice one month in advance, determine that the Measured Demand
of the Purchaser at the Point of Delivery in question during each month
thereafter, until such changes are made, is equal to the product obtained by
multiplying by three the largest of the Integrated Demands on any phase
adjusted as appropriate to such point during such month.
7. Reducing Charges for Interruptions. If deliveries of electric power
and energy to the Purchaser are suspended, interrupted, interfered with or
curtailed due to Uncontrollable Forces on either the Purchaser's system, the
Federal System or any Transferor's system, or if Bonneville or any Transferor
C. IN REFERENCE TO RATES
Exhibit B, Page 7 of 48
General Contract Provisions
8/25/81
interrupts or reduces deliveries to the Purchaser for any of the reasons stated
in section 14 hereof, the charges for power shall be appropriately reduced.
Partial interruptions shall be converted to an equivalent outage of total
Measured Demand. No total outage or equivalent outage of less than 30 minutes
duration shall be considered for computation of such reduction in charges.
8. Equitable Adjustment of Rates.
(a) Bonneville shall establish, periodically review and revise rates for
the sale and disposition of electric power, capacity or energy sold pursuant to
the terms of this contract. Such rates shall be established in accordance with
applicable law.
(b) As used in this section, the words "Rate Adjustment Date" mean any
date as specified by Bonneville in a notice of intent to file revised rates as
published in the Federal Register; provided, however, that such date shall
not occur sooner than (1) nine months from the date that such notice of intent
is published; or (2) twelve months from any previous Rate Adjustment Date. By
giving written notice to the Purchaser 45 days prior to such Rate Adjustment
Date, Bonneville may delay such Rate Adjustment Date for up to 90 days if
Bonneville determines either that the revenue level of the proposed rates
differs by more than five percent from the revenue requirements indicated by
most recent repayment studies entered in the hearings record or that external
events beyond Bonneville's control will prevent Bonneville from meeting such
Rate Adjustment Date. Bonneville may cancel a notice of intent to file revised
rates at any time (1) by written notice to the Purchaser; or (2) by publishing
in the Federal Register a new notice of intent to file revised rates which
specifically cancels a previous notice.
(c) The Purchaser shall pay Bonneville for the electric power and energy
made available under this contract during the period commencing on each Rate
Adjustment Date and ending at the beginning of the next Rate Adjustment Date at
the rate specified in any rate schedule available at the beginning of such
period for service of the class, quality, and type provided for in this
contract, and in accordance with the terms thereof, and of the General Rate
Schedule Provisions as changed with, incorporated in or referred to in such
rate schedule. New rates shall not be effective on any Rate Adjustment Date
unless they have been approved on a final or interim basis by a governmental
agency designated by law to approve Bonneville rates. Rates shall be applied
in accordance with the terms thereof, the General Rate Schedule Provisions as
changed with, incorporated in or referred to in such rate schedule and the
terms of this contract.
(d) (1) Bonneville reserves the authority to impose a conservation
surcharge as provided by section 4(f) and 7(h) of P.L. 96 -501. The
Purchaser shall pay the amount of any such surcharge so imposed as part of
its payment to Bonneville for wholesale power.
(2) Bonneville and the Purchaser recognize that cost effective model
conservation standards are to be adopted by the Pacific Northwest Electric
Power and Conservation Planning Council "the Council pursuant to
P.L. 96 -501, and that, in accordance with section 4(f) of P.L. 96 -501, such
standards are required to include, but are not limited to, standards
Exhibit B, Page 8 of 48
General Contract Provisions
8/25/81
Exhibit B, Page 9 of 48
General Contract Provisions
8/25/81
applicable to Customer and governmental conservation programs. Bonneville
will make available financial assistance to implement such cost effective
standards pursuant to its obligations under section 6(a)(1) and 6(e)(1) of
P.L. 96 -501, and as described at page 43 of the Report of the Committee on
Interior Affairs of the U.S. House of Representatives (Report No. 96 -976,
Part II) regarding section 4(f).
(3) Upon adoption of a methodology as provided in section 4(f)(2) and
section 4(e)(3)(G) of P.L. 96 -501, Bonneville will give notice of intent to
adopt a rule, provide opportunity for public comment, and publish draft
procedures in the Federal Register for imposing surcharges. Such rule
shall include:
(A) standards to be met before Bonneville will excuse surcharges
which would otherwise be appropriate, consistent with Bonneville's
obligations to implement cost effective conservation measures to the
maximum extent practicable;
(B) that Bonneville will impose surcharges to the extent not
excused or suspended under the terms of the rule;
(C) an opportunity for interested persons to present views,
data, questions, and arguments to Bonneville relevant to the
imposition of surcharges in specific instances, and the adequacy of
financial assistance made available by Bonneville;
(D) that surcharges imposed will be continued to the extent and
for the period projected energy savings attributable to cost effective
model conservation standards are not achieved;
Exhibit B, Page 10 of 48
General Contract Provisions
8/25/81
(E) for recovery from the Purchaser of the additional costs
(including increases in the Utility's average system cost) that
Bonneville will incur because the projected energy savings
attributable to model conservation standards have not been achieved,
subject to the limitations set forth in sections 4(f)(1) and 4(f)(2)
of P.L. 96 -501; provided, however, that surcharges will not be
levied as a result of an increase in a Utility's average system cost
except to the extent that the Utility failed to implement conservation
measures that are designed to be cost effective for its Consumers in
terms of the electric rates its Consumers pay.
(4) Nothing in this section shall waive or prejudice the right of any
person or Customer to assert any of its legal rights with respect to the
model conservation standards, their application, or the imposition of any
surcharges.
(e) Bonneville's wholesale power rates established on any Rate Adjustment
Date shall be developed consistent with the provisions of section 7 of
P.L. 96 -501. Bonneville shall develop in consultation with its utility
Customers and shall publish by July 1, 1983, methodologies as required for
implementing section 7(b)(2).
(f) Power Cost Allocations After July 1, 1985. Power cost allocations
among Customer classes will follow the same methods set forth in Appendix B of
the Senate Report S.885 (S. Rep. 272, 96 Cong., 1st Sess. 1979) for the period
Exhibit B, Page 11 of 48
General Contract Provisions
8/25/81
after July 1, 1985, and in the same general manner as further explained in the
1981 Bonneville wholesale power rate case by Exhibit U submitted in such rate
case and the accompanying Bonneville testimony.
(h) Individual Customer Rate Limit Under Section 7(f) of P.L. 96 -501.
(1) The provisions of this subsection shall apply to any Customer
from whom or on behalf of whom Bonneville has acquired a resource pursuant to
section 6 of P.L. 96 -501, if and to the extent such Customer purchases Firm
Power from Bonneville at a rate established pursuant to section 7(f) of
P.L. 96 -501.
(2) The rate established pursuant to section 7(f) charged to any such
Customer for an amount of Firm Power not exceeding that acquired by Bonneville
from or on behalf of such Customer, exclusive of any costs allocated to such
rate in accordance with sections 7(b)(3), 7(g), and 7(h) of P.L. 96 -501, shall
not exceed the average cost of the resources acquired by Bonneville from such
Customer, exclusive of resources whose costs are allocated by Bonneville
pursuant to section 7(g) and any resources acquired under section 5(c). The
average cost of such resources shall be adjusted for any additional costs such
Customer would have incurred in order to provide itself the same quantity and
quality of power from such resources if such resources had not been acquired by
Bonneville.
(3) Bonneville shall develop a methodology for performing the
adjustments required by paragraph (2) by procedures comparable to those
employed in establishing the methodology referred to in subsection (e) above.
Exhibit B, Page 12 of 48
General Contract Provisions
8/25/81
(4) Costs not recovered from any Customer because of the provisions
of paragraph (2) shall be recovered from other Customers through rates
established pursuant to section 7(f), to the extent that such recovery can be
made without exceeding the allowable section 7(f) rates for such other
Customers pursuant to paragraph (2). To the extent such recovery cannot be
made without exceeding the allowable section 7(f) rates established pursuant to
paragraph (2), the unrecovered balance shall be spread on a pro rata kilowatt
and kilowatthour basis among all Firm Power purchased by Customers under rates
established pursuant to section 7(f) and not be borne by other Customer classes
under rates established pursuant to sections 7(b) and 7(c) of P.L. 96 -501. The
pro rata recovery shall be limited to rates established pursuant to
section 7(f) and shall not increase the cost of the "other resources" specified
in section 7(b)(1) of P.L. 96 -501.
(i) Rates for Firm Power sold pursuant to sections 14 and 17 of the
utility power sales contract shall be established in such a fashion that the
Purchaser shall not be billed for Firm Power during any twelve month rate
period in excess of the amount to which the Purchaser was entitled to take
during such twelve -month period.
(j) Allocation of Certain Section 7(g) Costs. Costs of uncontrollable
events, including but not limited to costs of a terminated generating facility,
and costs of experimental resources, in excess of the cost of cost effective
resources, shall be allocated pursuant to section 7(g) of P.L. 96 -501 and shall
be allocated among Customers on a uniform per kilowatt or kilowatthour basis.
Beginning on July 1, 1985, such costs and other costs allocated pursuant to
Exhibit B, Page 13 of 48
General Contract Provisions
8/25/81
section 7(g) of P.L. 96 -501 will be reflected in the rates charged
Direct Service Industrial Customers only to the extent they modify Bonneville's
wholesale power rates to public body and cooperative Customers for power that
serves such Customers' retail industrial Consumers.
(k) Bonneville's wholesale power rates shall include the amount by which
the cost of resources acquired either at the request of the Purchaser pursuant
to section 17(j) of the utility power sales contract or at the request of other
Customers under similar power sales contracts exceed the estimated revenues
Bonneville expects to recover for sale of such power pursuant to
section 19(b)(1)(E) of such contract or similar power sales contracts. Such
costs shall be recovered from Bonneville's Customers pursuant to section 7(g)
of P.L. 96 -501, as the cost of an uncontrollable event.
(1) Allocation of Exchange Resources. The energy or capacity, or both,
associated with resources acquired by Bonneville pursuant to section 5(c)(2) of
P.L. 96 -501 shall be allocated at the cost thereof to Customers purchasing Firm
Power under rates established pursuant to section 7(b) of P.L. 96 -501 to the
extent that the load requirements of such Customers exceed the amount of
Federal base system resources, including replacements thereto, determined to be
available for ratemaking purposes. Such energy and capacity allocated to
Customers purchasing Firm Power under rates established pursuant to
section 7(f) of P.L. 96 -501 shall be allocated at the cost thereof. The total
cost of resources acquired under section 5(c) of P.L. 96 -501 allocated to
Direct Service Industrial Customers purchasing power under rates established
pursuant to section 7(c)(1)(A) of P.L. 96 -501 shall not exceed the average
Exhibit B, Page 14 of 48
General Contract Provisions
8/25/81
costs associated with the amount of such resources determined by Bonneville to
be required to serve that portion of the firm load of Direct Service Industrial
Customers not served by other resources.
(m) Revenue obtained by Bonneville through the recapture of costs
associated with section 5(c)(7)(C) of P.L. 96 -501 shall be equitably allocated
through Bonneville's wholesale power rates to Customer classes in proportion to
the respective prior payment of such costs by such classes through Bonneville's
wholesale power rates.
(n) Bonneville shall consult with the Purchaser and other Customers prior
to making a determination to replace reductions in the capability of the
Federal base system resources and shall make such replacements in an
economically prudent manner. Resources acquired as a replacement shall not be
from resources purchased by Bonneville under section 5(c) of P.L. 96 -501. All
or a portion of a resource acquired from or on behalf of the Purchaser may be
used as a replacement according to the terms specified in the resource purchase
agreement. Bonneville may replace reductions in the capability of the Federal
base system resources for plant delays when and to the extent needed to meet
the sum of (1) Bonneville's obligation to supply Firm Power during an Operating
Year to public bodies, cooperatives and Federal agencies; and (2) Bonneville's
firm contractual obligations with its other Customers in place on the effective
date of P.L. 96 -501 and which contracts are or would have been effective during
such Operating Year.
D. IN REFERENCE TO DELIVERY OF POWER
Exhibit B, Page 15 of 48
General Contract Provisions
8/25/81
9. Character of Service. Unless otherwise specifically provided for in
the contract, electric power or energy made available pursuant to this contract
shall be in the form of three -phase current, alternating at a nominal frequency
of 60 hertz.
10. Point(s) of Delivery and Delivery Voltage. Electric power and energy
shall be delivered to each Purchaser at the Point(s) of Delivery and at such
voltage(s) as specified. Unless otherwise agreed, delivery at more than one
voltage shall constitute delivery at more than one point.
11. Metered Quantities. The amount(s) of energy, Integrated Demands
therefor and amount(s) of reactive energy delivered to the Point(s) of Delivery
during each month shall be determined from measurements made by meters
installed for such Point(s) of Delivery in the circuit specified.
12. Where Additional Facilities Required. If additional delivery point
facilities must be constructed or installed to enable Bonneville to supply any
increase in the Purchaser's contract demand, or in the Purchaser's requirements
if Bonneville agrees by this contract to supply such requirements, Bonneville
shall not be required to provide such additional facilities unless the parties
mutually agree: (a) that Bonneville's providing such facilities is in
accordance with its customer service policies; (b) that reasonable utilization
has been made of existing facilities; and (c) that reasonable utilization of
such additional facilities will be assured. If the parties so agree,
Bonneville nevertheless shall not become obligated to supply such increase in
Exhibit B, Page 16 of 48
General Contract Provisions
8/25/81
such demand or requirements until such period of time has elapsed as may be
reasonably necessary to complete the installation of such additional facilities.
13. Uncontrollable Forces. Each party shall notify the other as soon as
possible of any Uncontrollable Forces which may in any way affect the delivery
of power hereunder. In the event the operations of either party are
interrupted or curtailed due to such Uncontrollable Forces, such party shall
exercise due diligence to reinstate such operations with reasonable dispatch.
14. Continuity of Service. The Purchaser, Bonneville or a Transferor may
temporarily interrupt or reduce deliveries of electric power or energy if the
Purchaser, Bonneville or the Transferor determines that such interruption or
reduction is necessary or desirable in case of system emergencies, or in order
to install equipment, in, make repairs to, make replacements within, make
investigations and inspections of, or perform other maintenance work on, the
Purchaser's facilities, the Federal System or the Transferor's system. Except
in case of emergency and in order that the Purchaser's operations will not be
unreasonably interfered with, Bonneville shall give notice to the Purchaser of
any such interruption or reduction, the reason therefor, and the probable
duration thereof to the extent Bonneville has knowledge thereof. The Purchaser
or Bonneville shall effect the use of temporary facilities or equipment to
minimize the effect of any such interruption or outage to the extent reasonable
or appropriate.
"15. Delivery by Transfer. If it is provided in this contract that
delivery to the Purchaser at any Point of Delivery will be made by transfer
over the facilities of a Transferor or Transferors:
E. IN REFERENCE TO PAYMENT FOR POWER
Exhibit B, Page 17 of 48
General Contract Provisions
8/25/81
(a) Bonneville shall be obligated to make available to the Purchaser at
such point only such amounts of electric power and energy as are made available
to the Purchaser by such Transferor or Transferors at such point, and the
obligation of Bonneville to make electric power and energy available to the
Purchaser at such point shall be in all respects subject to all provisions
contained in the agreement or agreements executed, or to be executed, if not
already in effect, by Bonneville and such Transferor or Transferors providing
for such transfer;
(b) Bonneville shall use its best efforts to effect a quality of service
to the Purchaser comparable to that provided under direct service from
Bonneville; and
(c) Bonneville's right to terminate deliveries at such point, under the
agreement or agreements providing for such transfer, shall not be exercised
while such Transferor or Transferors meet their obligations to make such
deliveries under such agreement or agreements unless (1) the Purchaser consents
thereto; or (2) Bonneville determines that the Purchaser's requirements for
electric power and energy at such point may be adequately supplied under
reasonable conditions and circumstances at another point or points (A) directly
from the Federal System (B) indirectly from the facilities of another
Transferor or Transferors, or (C) both.
16. Determination of and Assignment of Measured Demand. Bonneville in
determining Measured Demand shall exclude any abnormal Integrated Demand or
Exhibit B, Page 18 of 48
General Contract Provisions
8/25/81
Measured Amount due to or resulting from (a) emergencies or breakdowns on, or
maintenance of, the Federal System Facilities; and (b) emergencies on the
Purchaser's facilities to the extent Bonneville determines that such facilities
have been adequately maintained and prudently operated.
If timely determination of Measured Demand cannot be made, such
determination shall be made in accordance with section 19 below.
Where Bonneville delivers, pursuant to this or other contracts, more
than one class of electric power to the Purchaser at any Point of Delivery, the
portion of the Measured Demand assigned to each such class of power shall be as
specified in such contracts. Any portion of Measured Demand which is not
assigned to other classes of power delivered pursuant to this or other
contracts shall be deemed to be a Firm Power delivery under this contract.
17. Billing At Multiple Points of Delivery. For electric power or energy
made available hereunder to the Purchaser at more than one Point of Delivery,
the Purchaser shall be billed for each Point of Delivery separately on a
non coincidental basis under the applicable rate schedule in the Wholesale
Power Rate Schedules and General Rate Schedule Provisions Exhibit, unless
otherwise provided herein. The Points of Delivery Exhibit may provide for
combined billing on a coincidental basis under specified conditions and terms
either when delivery at more than one point is beneficial to Bonneville or when
the flow of power at several Points of Delivery is reasonably beyond the
control of the Purchaser.
If deliveries at more than one Point of Delivery are billed on a
coincidental basis for the convenience of the Purchaser, a charge shall be made
Exhibit B, Page 19 of 48
General Contract Provisions
8/25/81
for the diversity among Measured Demands at such Points of Delivery. Charges
for diversity shall be specified in the Special Provisions Exhibit and
determined in a uniform manner among Customers.
At any rate adjustment date after January 1, 1982, Bonneville may
establish its wholesale power rate schedules applicable to this contract using
Customers' coincidental peak demands as the basis for proportioning its revenue
recovery. In such event all diversity factors or charges applicable to
Measured Demands determined on a coincidental basis shall be invalid and
appropriate factors to reduce Measured Demands determined on a non coincidental
basis shall be developed and applied.
18. Payment of Bills. Bills for power shall be rendered monthly and
shall be payable at Bonneville's headquarters. Failure to receive a bill shall
not release the Purchaser from liability for payment. Each calculated monetary
amount in a wholesale power bill shall be rounded to a whole dollar amount, by
elimination of any amount of less than 50 cents and increasing any amount from
50 cents through 99 cents to the next higher dollar.
If Bonneville is unable to render the Purchaser a timely monthly bill
which includes a full disclosure of all billing factors, it may elect to render
an estimated bill for that month to be followed by the final bill. Such
estimated bill, if so issued, shall have the validity of and be subject to the
same payment provisions as shall a final bill.
Bills not paid in full on or before the date specified in the Payment
of Bills section, or its successor, of the General Rate Schedule Provisions
incorporated in the Wholesale Power Rate Schedules and General Rate Schedule
Provisions Exhibit shall bear additional charges as specified therein.
Average Power Factor Kilowatthours
The data used in the above formula shall be obtained from meters
which are ratcheted to prevent reverse registration.
Remittances received b y mail w i l l be accepted without assessment of
the charges referred to in the preceding paragraph provioeu the postmark
indicates the payment was mailed on or before the 2Uth Gay after the Gate of
the bill. If the 20th day after the date of the bill is a Sunuay or other
nonbusiness day of the Purchaser, the next following business day shall be the
last day on which payment may be made to avoid such further charges. Payment
made by metered rail and received subsequent to the 20th day must bear a postal
department cancellation in order to avoid assessment of such further charges.
Bonneville may, whenever a power bill or a portion thereof remains
unpaid subsequent to the 20th day after the date of the bill, ano after giving
30 days advance notice in writing, cancel the contract for service to the
Purchaser, but such cancellation shall not affect the Purchaser's liability for
any charges accrued prior thereto.
19. Determination of Estimated Billing Data. If the amounts of power or
energy which have been delivered hereunder must be estimated from data other
than metered quantities, scheduled quantities or tabulations of hourly
interchange prepared by the Purchaser, Bonneville and the Purchaser shall agree
on estimated billing data to be used in preparing the bill.
20. Average Power Factor. The formula for uetermaining average power
factor is as follows:
Exhibit B, Page 20 of 49
General Contract Provisions
8/24/81
J(Kilowatthours)' (Reactive Kilovolt- ampere- hours)2
F. IN REFERENCE TO USE OF POWER
Exhibit B, Page 21 of 48
General Contract Provisions
8/25/81
When deliveries to a Purchaser at any Point of Delivery include more
than one class of power or are under more than one rate schedule, and it is
impracticable to separately meter the kilowatthours and reactive kilovolt
ampere -hours for each class, the average power factor of the total deliveries
for the month shall be used, where applicable, as the power factor for each of
the separate classes of power and rate schedules.
21. Changes in Requirements or Characteristics. The Purchaser will,
whenever possible, give reasonable notice to Bonneville of any unusual
increase or decrease of its demands for electric power and energy on the
Federal System, or of any unusual change in the load factor or power factor at
which the Purchaser will take delivery of electric power and energy under this
contract.
22. Electric Disturbance.
(a) For the purposes of this section an electric disturbance is any
sudden, unexpected, changed, or abnormal electric condition occurring in or on
an electric system which causes damage.
(b) Each party shall design, construct, operate, maintain, and use its
electric system in conformance with accepted electric utility practices:
(1) to minimize electric disturbances such as, but not limited to,
the abnormal flow of power which may interfere with the electric system of
the other party or any electric system connected with such other party's
electric system; and
Exhibit B, Page 22 of 48
General Contract Provisions
8/25/81
(2) to minimize the effect on its electric system and on its
customers of electric disturbances originating on its own or another
electric system.
(c) If both parties to this contract are parties to the Western
Interconnected Electric System Agreement, their relationship with respect to
system damages shall be governed by that agreement.
(d) During such time as a party to this contract is not a party to the
Agreement Limiting Liability Among Western Interconnected Systems, its
relations with the other party with respect to system damages shall be
governed by the following sentence, notwithstanding the fact that the other
party may be a party to said Agreement Limiting Liability Among Western
Interconnected Systems. A party to this contract shall not be liable to the
other party for damage to the other party's system or facilities caused by an
electric disturbance on the first party's system, whether or not such electric
disturbance is the result of negligence by the first party, if the other party
has failed to fulfill its obligations under subsection (b)(2) above.
(e) If one of the parties to this contract is not a party to the
Agreement Limiting Liability Among Western Interconnected Systems, each party
to this contract shall hold harmless and indemnify the other party, its
officers and employees, from any claims for loss, injury, or damage suffered
by those to whom the first party delivers power not for resale, which loss,
injury, or damage is caused by an electric disturbance on the other party's
system, whether or not such electric disturbance results from the negligence
of such other party, if such first party has failed to fulfill its obligations
under subsection (b)(2) above, and such failure contributed to the loss,
injury, or damage.
Exhibit B, Page 23 of 48
General Contract Provisions
8/25/81
(f) Nothing in this section shall be construed to create any duty to, any
standard of care with reference to, or any liability to any persons not a
party to this contract.
23. Harmonic Control. Each party shall design, construct, operate,
maintain and use its electric facilities in accordance with good engineering
practices to reduce to acceptable levels the harmonic currents and voltages
which pass into the other party's facilities. Harmonic reductions shall be
accomplished with equipment which is specifically designed and permanently
operated and maintained as an integral part of the facilities of the party
which owns the system on which harmonics are generated.
24. Balancing Phase Demands. If required by Bonneville at any time
during the term of this contract, the Purchaser shall make such changes as are
necessary on its system to balance the phase currents at any Point of Delivery
so that the current of any one phase shall not exceed the current on any other
phase at such point by more than 10 percent.
G. IN REFERENCE TO FACILITIES
25. Measurements and Installation of Meters. Bonneville may at any time
install a meter or metering equipment to make the measurements for any Point
of Delivery required for any computation or determination mentioned in this
contract, and if so installed, such measurements shall be used thereafter in
such computation or determination.
26. Tests of Metering Installations. Each party to this contract shall,
at its expense, test its metering installations associated with this contract
Exhibit B, Page 24 of 48
General Contract Provisions
8/25/81
at least once every two years, and, if requested to do so by the other party,
shall make additional tests or inspections of such installations, the expense
of which shall be paid by such other party unless such additional tests or
inspections show the measurements of such installations to be inaccurate as
specified in section 5 hereof. Each party shall give reasonable notice of the
time when any such test or inspection is to be made to the other party who may
have representatives present at such test or inspection. Any component of
such installations found to be defective or inaccurate shall be adjusted,
repaired, or replaced to provide accurate metering.
27. Permits.
(a) If any equipment or facilities associated with any Point of Delivery
and belonging to a party to this contract are or are to be located on the
property of the other party, a permit to install, test, maintain, inspect,
replace, repair, and operate during the term of this contract and to remove
such equipment and facilities at the expiration of said term, together with
the right of entry to said property at all reasonable times in such term, is
hereby granted by the other party.
(b) Each party shall have the right at all reasonable times to enter the
property of the other party for the purpose of reading any and all meters
mentioned in this contract which are installed on such property.
(c) If either party is required or permitted to install, test, maintain,
inspect, replace, repair, remove, or operate equipment on the property of the
other, the owner of such property shall furnish the other party with accurate
drawings and wiring diagrams of associated equipment and facilities, or, if
Exhibit B, Page 25 of 48
General Contract Provisions
8/25/81
such drawings or diagrams are not available, shall furnish accurate
information regarding such equipment or facilities. The owner of such
property shall notify the other party of any subsequent modification which may
affect the duties of the other party in regard to such equipment, and furnish
the other party with accurate revised drawings, if possible.
28. Ownership of Facilities.
(a) Except as otherwise expressly provided, ownership of any and all
equipment and all salvable facilities installed or previously installed by a
party to this contract on the property of the other party shall be and remain
in the installing party.
(b) Each party shall identify all movable equipment and all other
salvable facilities which are installed by such party on the property of the
other, by permanently affixing thereto suitable markers plainly stating the
name of the owner of the equipment and facilities so identified. Within a
reasonable time subsequent to initial installation, and subsequent to any
modification of such installation, representatives of the parties shall
jointly prepare an itemized list of said movable equipment and salvable
facilities so installed.
29. Inspection of Facilities. Each party may for any reasonable purpose
under this contract inspect the other party's electric installation at any
reasonable time. Such inspection, or failure to inspect, shall not render
such party, its officers, agents, or employees, liable or responsible for any
injury, loss, damage, or accident resulting from defects in such electric
installation, or for violation of this contract. The inspecting party shall
observe written instructions and rules posted in facilities and such other
necessary instructions or standards for inspection as the parties agree to.
Only those electric installations used in complying with the terms of this
contract shall be subject to inspection.
30. Facilities for Maintenance of Voltage. Bonneville shall design and
construct Federal System Facilities to maintain, under normal conditions and
in accordance with generally accepted operating practices, the voltage at each
Point of Delivery from the Federal System within a range of 5 percent above or
below the operating voltage agreed upon by the operators of the parties to
this contract where such voltage is 25 kV or less. Where the delivery voltage
is in excess of 25 kV, Bonneville will design and construct Federal System
Facilities to maintain such operating voltage within a range of 10 percent
above or below such voltages. The parties shall jointly plan and operate
their interconnected electrical facilities so that the flow of reactive power
accompanying or resulting from deliveries of electric power and energy under
this contract will not adversely affect the system of either party.
H. MISCELLANEOUS PROVISIONS
Exhibit B, Page 26 of 48
General Contract Provisions
8/25/81
31. General Environmental Provision.
(a) Policy. Bonneville in the performance of this contract shall comply
with all of its obligations pursuant to the National Environmental Policy Act.
(b) Affirmative Obligations. The parties agree to:
(1) comply fully with all applicable Federal, State, and local
environmental laws;
Exhibit B, Page 27 of 48
General Contract Provisions
8/25/81
(2) to assist and to cooperate with each other in meeting each
other's environmental obligations, to the fullest extent economically and
technically practicable and mutually agreeable; and
(3) provide upon request of the other party a copy of pollution
abatement plans as required by the Clean Air Act, by the Clean Water Act,
by other Federal statutes, or by an agency having jurisdiction and within
a reasonable time submit evidence that such plans have been approved or
have not been objected to by agencies with jurisdiction.
(c) Breach of Obligations. A breach of this General Environmental
Provision exists only if a final determination, including all appeals, has
been entered by a court or pollution control agency or agencies having
jurisdiction that the Purchaser's facility is not in compliance with
applicable laws respecting the control and abatement of environmental
pollution.
(d) Remedy. Bonneville, after consulting with state or local agencies
having jurisdiction may restrict delivery of electric capacity or energy to
the Purchaser pursuant to this contract, if Bonneville determines that:
(1) a breach of this General Environmental Provision exists;
(2) such breach is resulting in a significant adverse effect on the
environment;
(3) no governmental agency has jurisdiction or authority to impose
sanctions or to seek remedy for such significant adverse effect on the
environment; and
(4) restriction of delivery is the only appropriate remedy and bears
a reasonable relationship to the breach.
Exhibit B, Page 28 of 48
General Contract Provisions
8/25/81
Before restricting delivery of capacity or energy pursuant to this
section, Bonneville shall give the Purchaser written notice and a reasonable
opportunity to cure the breach and to seek any legal recourse available to the
Purchaser.
32. Dispute Resolution and Arbitration.
(a) Pending resolution of a disputed matter the parties will continue
performance of their respective obligations pursuant to this contract. If the
parties cannot reach timely mutual agreement on any matter in the
administration of this contract Bonneville shall, unless otherwise
specifically provided for in subsection (b) below and, to the extent necessary
for its continued performance, make a determination of such matter without
prejudice to the rights of the other party. Such determination shall not,
constitute a waiver of any other remedy belonging to the Purchaser.
(b) The questions of fact stated below shall be subject to arbitration.
Other questions of fact under this contract may be submitted to arbitration
upon written mutual agreement of the parties. The party calling for
arbitration shall serve notice in writing upon the other party, setting forth
in detail the question or questions to be arbitrated and the arbitrator
appointed by such party. The other party shall, within 10 days after the
receipt of such notice, appoint a second arbitrator, and the two so appointed
shall choose and appoint a third. In case such other party fails to appoint
an arbitrator within said 10 days, or in case the two so appointed fail for
10 days to agree upon and appoint a third, the party calling for the
arbitration, upon 5 days' written notice delivered to the other party, shall
apply to the person who at the time shall be the presiding judge of the United
Exhibit B, Page 29 of 48
General Contract Provisions
8/25/81
States Court of Appeals for the Ninth Circuit for appointment of the second
and third arbitrator, as the case may be.
The determination of the question or questions submitted for
arbitration shall be made by a majority of the arbitrators and shall be
binding on the parties. Each party shall pay for the services and expenses of
the arbitrator appointed by or for it, for its own attorney fees, and for
compensation for its witnesses or consultants. All other costs incurred in
connection with the arbitration shall be shared equally by the parties thereto.
The questions of fact to be determined as provided in this section
shall be limited to:
(1) the determination of the measurements to be made by the parties
hereto pursuant to section 3 above;
(2) the occurrence of changes in conditions for purposes of section 4
above;
(3) the correction of the measurements to be made pursuant to
section 5 above;
(4) whether the changes mentioned in section 6 hereof were made
"promptly
(5) the duration of the interruption or equivalent interruption
mentioned in section 7 above;
(6) the occurrence of an abnormal nonrecurring demand and the amount
and time thereof;
(7) any fact mentioned in section 21 above and in section 24 above;
(8) whether a party has complied with section 22(b) above; and
(9) the acceptable level of harmonics for purposes of section 23
above.
Exhibit B, Page 30 of 48
General Contract Provisions
8/25/81
The questions of fact in the body of the Power Sales Contract with
Public Agency, Cooperative, Federal Agency, and Investor -Owned Utility
Purchasers to be determined as provided in this section shall be limited to:
(1) the order of receipt of written notices of addition of Firm
Resources under section 12(b)(7);
(2) whether the Purchaser's electrical system is interconnected with
electrical systems of other utilities directly or indirectly connected
with Bonneville's electrical system for purposes of section 13(d);
(3) whether a Purchaser's documentation under section 17(e)
demonstrates the actual implementation of a load curtailment program; and
(4) the level of base load under section 8.
33. Enforcement of Rights for Benefit of Transferors. If delivery, of
electric power and energy under this contract is to be made by transfer over
the facilities of any Transferor or Transferors, Bonneville may enforce
Government rights under the power factor clause of the Government's applicable
rate schedule incorporated in this contract, and under sections 6, 13, 14, 21,
22, 23, 24, 27, 28, and 29 hereof, for the benefit of such Transferor or
Transferors, and all references to the Federal System, property, or Facilities
in said section shall be deemed to include the facilities of the Transferor or
Transferors being used to deliver electric power or energy for the account of
Bonneville.
34. Net Billing. Upon mutual agreement of the parties, payments due one
party may be offset against payments due the other party under all contracts
between the Purchaser and Bonneville for the sale and exchange of electric
Exhibit B, Page 31 of 48
General Contract Provisions
8/25/81
power and energy, use of transmission facilities, operation and maintenance of
electric facilities, lease of electric facilities, mutual supply of emergency
and standby electric power and energy, and under such other contracts between
such parties as the parties may agree unless otherwise provided in existing
contracts between the parties. Under contracts included in this procedure all
payments due one party in any month shall be offset against payments due the
other party in such month, and the resulting net balance shall be paid to the
party in whose favor such balance exists unless the latter elects to have such
balance carried forward to be added to the payments due it in a succeeding
month.
35. Contract Work Hours and Safety Standards. This contract, if and to
the extent required by applicable law or if not otherwise exempted, is subject
to the following provisions:
(a) Overtime Requirements. No Contractor or subcontractor contracting
for any part of the contract work which may require or involve the employment
of laborers, mechanics, apprentices, trainees, watchmen, and guards shall
require or permit any laborer, mechanic, apprentice, trainee, watchman, or
guard in any workweek in which such worker is employed on such work to work in
excess of 8 hours in any calendar day or in excess of 40 hours in such
workweek on work subject to the provisions of the Contract Work Hours and
Safety Standards Act unless such laborer, mechanic, apprentice, trainee,
watchman, or guard receives compensation at a rate not less than one and
one -half times such worker's basic rate of pay for all such hours worked in
excess of eight hours in any calendar day or in excess of 40 hours in such
workweek, whichever is the greater number of overtime hours.
Exhibit B, Page 32 of 48
General Contract Provisions
8/25/81
(b) Violation; Liability for Unpaid Wages; Liquidation of Damages. In
the event of any violation of the provisions of subsection (a), the Contractor
and any subcontractor responsible therefor shall be liable to any affected
employee for such employee's unpaid wages. In addition, such Contractor and
subcontractor shall be liable to the Government for liquidated damages. Such
liquidated damages shall be computed with respect to each individual laborer,
mechanic, apprentice, trainee, watchman, or guard employed in violation of the
provisions of subsection (a) in the sum of $10 for each calendar day on which
such employee was required or permitted to be employed in such work in excess
of eight hours or in excess of such employee's standard workweek of 40 hours
without payment of the overtime wages required by subsection (a) above.
(c) Withholding for Unpaid Wages and Liquidated Damages. Bonneville may
withhold from the Government Prime Contractor, from any moneys payable on
account of work performed by the Contractor or subcontractor, such sums as may
administratively be determined to be necessary to satisfy any liabilities of
such Contractor or subcontractor for unpaid wages and liquidated damages as
provided in subsection (b) above.
(d) Subcontracts. The Contractor shall insert subsections (a) through
(d) of this section in all subcontracts, and shall require their inclusion in
all subcontracts of any tier.
(e) Records. The Contractor shall maintain payroll records containing
the information specified in 29 CFR 516.2(a). Such records shall be preserved
for 3 years from the completion of the contract.
36. Convict Labor. In connection with the performance of work under
this contract, the Contractor agrees, if and to the extent required by
J
Exhibit B, Page 33 of 48
General Contract Provisions
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applicable law or if not otherwise exempted, not to employ any person
undergoing sentence of imprisonment except as provided by P.L. 89 -176,
September 10, 1965 (18 U.S.C. 4082(c)(2)) and Executive Order 11755,
December 29, 1973.
37. Equal Employment Opportunity. During the performance of this
contract, if and to the extent required by applicable law or if not otherwise
exempted, the Contractor agrees as follows:
(a) The Contractor will not discriminate against any employee or
applicant for employment because of race, color, religion, sex, or national
origin. The Contractor will take affirmative action to ensure that applicants
are employed, and that employees are treated during employment, without regard
to their race, color, religion, sex, or national origin. Such action shall
include, but not be limited to, the following: employment, upgrading,
demotion or transfer; recruitment or recruitment advertising; layoff or
termination; rates of pay or other forms of compensation; and selection for
training, including apprenticeship. The Contractor agrees to post in
conspicuous places, available to employees and applicants for employment,
notices to be provided by Bonneville setting forth the provisions of the Equal
Opportunity clause.
(b) The Contractor will, in all solicitations or advertisements for
employees placed by or on behalf of the Contractor, state that all qualified
applicants will receive consideration for employment without regard to race,
color, religion, sex, or national origin.
(c) The Contractor will send to each labor union or representative of
workers with which said Contractor has a collective bargaining agreement or
Exhibit B, Page 34 of 48
General Contract Provisions
8/25/81
other contract or understanding, a notice, to be provided by Bonneville,
advising the labor union or workers' representative of the Contractor's
commitments under the Equal Opportunity clause and shall post copies of the
notice in conspicuous places available to employees and applicants for
employment.
(d) The Contractor will comply with all provisions of Executive Order
No. 11246 of September 24, 1965, and of the rules, regulations, and relevant
orders of the Secretary of Labor.
(e) The Contractor will furnish all information and reports required by
Executive Order No. 11246 of September 24, 1965, and of the rules,
regulations, and relevant orders of the Secretary of Labor, or pursuant
thereto, and•will permit access to said Contractor's books, records; and
accounts by Bonneville and the Secretary of Labor for purposes of
investigations to ascertain compliance with such rules, regulations, and
orders.
(f) In the event of the Contractor's noncompliance with the Equal
Opportunity clause of this contract or with any of such rules, regulations, or
orders, this contract may be cancelled, terminated, or suspended in whole or
in part and the Contractor may be declared ineligible for further Government
contracts in accordance with procedures authorized in Executive Order
No. 11246 of September 24, 1965, and such other sanctions may be imposed and
remedies invoked as provided in Executive Order No. 11246 of September 24,
1965, or by rule, regulation, or order of the Secretary of Labor, or as
otherwise provided by law.
(g) The Contractor will include the provisions of subsections (a) through
(g) in every subcontract or purchase order unless exempted by rules,
Exhibit B, Page 35 of 48
General Contract Provisions
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regulations, or orders of the Secretary of Labor issued pursuant to
Section 204 of Executive Order No. 11246 of September 24, 1965, so that such
provisons will be binding upon each subcontractor or vendor. The Contractor
will take such action with respect to any subcontract or purchase order as
Bonneville may direct as a means of enforcing such provisions, including
sanctions for noncompliance. In the event the Contractor becomes involved in,
or is threatened with, litigation with a subcontractor or vendor as a result
of such direction by Bonneville, the Contractor may request the Government to
enter into such litigation to protect the interests of the Government.
38. Assignment of Contract. This contract shall inure to the benefit
of, and shall be binding upon the respective successors and assigns of the
parties to this contract. Such contract or any interest therein shall not be
transferred or assigned by either party to any party other than the Government
or an agency thereof without the written consent of the other except as
specifically provided in this section. The consent of Bonneville is hereby
given to any security assignment or other like financing instrument which may
be required under terms of any mortgage, trust, security agreement or holder
of such instrument of indebtedness made by and between the Purchaser and any
mortgagee, trustee, secured party, subsidiary of the Purchaser or holder of
such instrument of indebtedness, as security for bonds or other indebtedness
of such Purchaser, present or future; such mortagagee, trustee, secured party,
subsidiary, or holder may realize upon such security in foreclosure or other
suitable proceedings, and succeed to all right, title, and interests of such
Purchaser.
Exhibit B, Page 36 of 48
General Contract Provisions
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39. Waiver of Default. Any waiver at any time by any party to this
contract of its rights with respect to any default of any other party thereto,
or with respect to any other matter arising in connection with such contract,
shall not be considered a waiver with respect to any subsequent default or
matter.
40. Notices and Computation of Time. Any notice required by this
contract to be given to any party shall be effective when it is received by
such party, and in computing any period of time from such notice, such period
shall commence at 2400 hours on the date of receipt of such notice.
41. Interest of Member of Congress. No Member of or Delegate to
Congress, or Resident Commissioner shall be admitted to any share or part of
this contract or to any benefit that may arise therefrom, but this provision
shall not be construed to extend to such contract if made with a corporation
for its general benefit.
42. Priority of Pacific Northwest Customers.
(a) The provisions of sections 9(c) and (d) of P.L. 96 -501 and the
provisions of P.L. 88 -552 as amended by section 8(e) of P.L. 96 -501 "the
Provisions are by this reference incorporated herein.
(b) To further the policy of the Provisions, Bonneville agrees that the
Purchaser, together with other Customers in the Pacific Northwest, shall have
priority on electric power and energy Bonneville has available for sale, in
conformity with the Provisions.
(c) Bonneville agrees that it will comply with all restrictions and
requirements of the Provisions, and will perform all duties and obligations
imposed on it by the Provisions, as the Provisions existed on the effective
1
Exhibit B, Page 37 of 48
General Contract Provisions
8/25/81
date of this contract, regardless of any subsequent modification, amendment or
repeal of the Provisions.
(d) Bonneville further agrees that, to the extent and at such times as
may be necessary to meet demands for energy or peaking capacity at any
established rate for use within the Pacific Northwest, it will exercise its
rights, under contractual provisions required by the Provisions to be included
in contracts for the disposition of surplus energy or surplus peaking capacity
for use outside of the Pacific Northwest, to require:
(1) the return of energy delivered in connection with its supplying
peaking capacity for use outside the Pacific Northwest; and
(2) the delivery within the Pacific Northwest of energy, peaking
capacity, or both, which Bonneville has the right to receive in any
exchange for energy, capacity, or both, which it has delivered for use
outside the Pacific Northwest.
43. Resource Acquisition and Management.
(a) Principles of Resource Acquisition.
(1) Bonneville is obligated under section 6(a)(2) of P.L. 96 -501 to
acquire sufficient firm resources to meet its firm loads after taking into
account planned savings from conservation.
(2) Bonneville is obligated to attempt to meet its firm loads
pursuant to section 6(a)(2) with resources, including conservation,
implemented or acquired on a long -term basis pursuant to P.L. 96 -501.
(3) To the extent Bonneville is unable to acquire, on a planning
basis, sufficient resources on a long -term basis to meet its firm
obligations, Bonneville is obligated to and will attempt to meet its
Exhibit B, Page 38 of 48
General Contract Provisions
8/25/81
remaining firm load obligations through the acquisition of additional
resources pursuant to section 11(b)(6) of the Federal Columbia River
Transmission System Act. The obligation contained in this subparagraph is
a continuing one, and applies on both a planning basis and during the
Pacific Northwest Coordination Agreement Critical Period.
(b) Principles of Resource Management. Bonneville will manage the
resources of the Federal Columbia River Power System and resources acquired
pursuant to P.L. 96 -501 and the Federal Columbia River Transmission System Act
for the purpose of meeting the loads of its customers at the lowest possible
expected cost to Bonneville, to the extent consistent with Bonneville's legal
obligations, environmental responsibilities, and prudent operating criteria,
particularly for firm loads, without.reducing its.obligation to acquire
sufficient resources to meet its firm loads, and with due regard for the risks
and expected reliability of such resources.
(c) Consultation with Customers. In the development of its plans and
programs to effect the provisions of this section, including for ratemaking
purposes, Bonneville will provide a timely opportunity for prior consultation
with its customers.
44. Cooperation with Regional Council. The parties will negotiate
amendments to this contract as may be necessary to permit the plan or program
adopted by the Pacific Northwest Electric Power and Conservation Planning
Council pursuant to P.L. 96 -501, including but not limited to provisions
pertaining to conservation, renewable resources, and fish and wildlife, to be
effective in the manner and for the purposes set forth in sections 4 and 6 of
P.L. 96 -501.
45. Rights of the Purchaser. No provision of this contract nor any
action or lack of action by the Purchaser pursuant to the terms of this
contract shall be construed to abrogate, modify, limit or otherwise waive in
any respect any right of the Purchaser including the right of the Purchaser to
exercise its preference and priority as provided by law.
46. Separation of Electric Operations and Funds (All Public Agencies).
(a) The Purchaser shall operate its electric system as a separate
department from other utility functions, if any, and shall establish and
maintain a separate fund for the revenues derived from the operation of such
system. Such revenues shall not be commingled with funds or accounts of other
departments, if any.
II. RELATING ONLY TO PREFERENCE AGENCIES
Exhibit B, Page 39 of 48
General Contract Provisions
8/25/81
47. Statement of General Policies and Practices (Cities).
(a) Publicly owned city electric systems should be operated and
maintained:
(1) primarily for the benefit of the users of electricity;
(2) in accordance with reasonable standards of safety, reliability,
quality, and efficiency; and
(3) to maintain the cost of electric power at the lowest level
consistent with good service and proper maintenance.
(b) Revenue requirements shall insure a financially sound and
self- supporting electrical system. This requires that revenues be sufficient
for:
Exhibit B, Page 40 of 48
General Contract Provisions
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(1) Reasonable and necessary current maintenance and operating
expenses, including salaries, wages, cost of power at wholesale,
materials, supplies, insurance, necessary renewals and replacements of
plant, and the establishment of reasonable funds for such purposes,
contingencies, and other lawful charges.
(2) Interest and principal of indebtedness incurred for the electric
plant and payments required to be made into any special bond funds.
(3) Depreciation of electric system property to the extent not
adequately provided for by amortization of debt and by renewals and
replacement.
(4) Payments made into a governmental entity general fund via taxes
or payments in lieu of taxes. The percentage of gross electric revenues
used for this purpose shall be an amount not exceeding the greater of the
following:
(i) an amount which is equal to five percent of the gross
electric revenues, unless a greater amount is provided pursuant to
the city charter or agreements in effect as of December 5, 1980; or
(ii) the amount of State or local taxes levied upon the
Purchaser's electric system or its operations.
(c) A local governmental entity, when acting in its governmental
capacity, and receiving electric service, shall be a Consumer and be billed
for such services consistent with the rates charged other Consumers in the
same class. The Purchaser shall receive prompt payment for such electric
services. Payments by the Purchaser for necessary services or materials
received by the Purchaser from other governmental departments, shall he
limited to a fair, reasonable and nondiscriminatory charge.
Exhibit B, Page 41 of 48
General Contract Provisions
8/25/81
(d) Taxpayers' investments in the electric system, made through use of
general government funds of the city, should be treated in the same manner as
funds borrowed by the electric system from outside sources, and should receive
a return approximating the market rate of interest on comparable securities.
Such market rate of interest shall not exceed 6 percent per annum unless a
larger amount is approved by Bonneville.
(e) All surplus revenues from retail sales remaining after meeting the
requirements of subsections (b), (c), and (d) above, where applicable, should
be applied to reduction of rates. Surplus revenues earned in any year may
properly be devoted to the purchase or retirement of system indebtedness
before maturity, to the extent that such use thereof is consistent with the
above principles and practices.
48. Approval of Contract. If the Purchaser borrows from the Rural
Electrification Administration or any other entity under an indenture which
requires the lender's approval of contracts, this contract and any amendment
thereto shall not be binding on the parties thereto if they are not approved
by the Rural Electrification Administration or such other entity. The
Purchaser shall notify Bonneville of any such entity. If approval is given,
such contracts or amendment shall be effective at the time stated in such
contract or amendment.
49. Prior Demands.
(a) If Bonneville has delivered electric power or energy to the Purchaser
at any Point of Delivery specified in this contract prior to the time this
contract takes effect, the Purchaser's Measured Demands, if any. at such point
or Measured Demands for its system for Pu ?chasers on Computed Requirements
AGENCY AND INVESTOR -OWNED UTILITY PURCHASERS
A. IN REFERENCE TO COMPUTATION OF CHARGES
Exhibit B, Page 42 of 48
General Contract Provisions
8/25/81
prior to such time shall be considered for the purpose of determining the
charges to the Purchaser for the electric power and energy delivered under
this contract, during any month in the term hereof, in the same manner as if
this contract had been in effect.
(b) If Bonneville has delivered electric power and energy to the
Purchaser at any Point of Delivery specified in this contract or in any
previous contract with the Purchaser, and such Point of Delivery is superseded
by another Point of Delivery specified in this contract, the Purchaser's
Measured Demands, if any, at such superseded point shall be considered for the
purpose of determining the charges to the Purchaser for the electric power and
energy delivered under this contract at such superseding point.
III. RELATING ONLY TO PUBLIC BODY, COOPERATIVE, FEDERAL
50. Effect of Reduction of Contract Demand. If the Purchaser's contract
demand is specified in this contract and is reduced after this contract is
executed, the prior Measured Demands, if any, of the Purchaser shall, for the
purpose of computing charges for electric power and energy delivered
thereafter, be reduced by the amount of such reduction.
51. Combining Deliveries Coincidentally.
(a) If it is provided in this contract that charges for electric power
and energy made available .t two or more Points_of'Dalivery will be made by
combining deliveries at such points coincidentally:
Exhibit B, Page 43 of 48
General Contract Provisions
8/25/81
(1) the total Measured Demand to be considered in determining the
billing demand for each Billing Month shall be the largest sum obtained by
adding for each demand interval of such month the corresponding Integrated
Demands of the Purchaser at all such points after adjusting said
Integrated Demands as appropriate to such points;
(2) the number of kilowatthours to be used in determining the energy
charge, if any, and the average power factor at which electric energy is
delivered at such points under this contract, during such month, shall be
the sum of the amounts of electric energy delivered at such points under
this contract during such month; and
(3) the number of reactive kilovolt- ampere hours to be used in
determining such average monthly power factor shall be the sum of the
reactive kilovolt- ampere hours delivered at such points under this
contract during such month.
(b) If electric power and energy is made available under this contract to
the Purchaser at two or more Points of Delivery, Bonneville may, upon
two years written notice, place the Purchaser on a coincidental billing demand
basis pursuant to the terms of this section.
52. Combining Deliveries Noncoincidentally. If it is provided in this
contract that charges for electric power and energy made available at two or
more Points of Delivery will be made by combining deliveries at such points
noncoincidentally:
(a) the total Measured Demand to be considered in determining the
billing demand for each month in the period specified in such contract
shall the sum obtained by adding together the Me.:Lured Demands of the
Purchaser for each of such points during such month;
Exhibit B, Page 44 of 48
General Contract Provisions
8/25/81
(b) the number of kilowatthours to be used in determining the energy
charge, if any, and the average monthly power factor at which electric
energy is delivered at such points under this contract, during such month,
shall be the sum of the amounts of electric energy delivered at such
points under this contract during such month; and
(c) the number of reactive kilovolt- ampere -hours to be used in
determining such average monthly power factor shall be the sum of the
reactive kilovolt- ampere -hours delivered at such points under this
contract during such month.
53. Power Factor Adjustment. Except as it is otherwise specifically
provided in this contract, no adjustment shall be made for power factor at any
Point of Delivery for any period of time during which the reactive power
delivered at such point is not measured.
B. IN REFERENCE TO PURCHASERS' OPERATING POLICIES
54. Retail Rates.
(a) Copies of the Purchaser's schedules of retail rates, including
special contract rates, if any, in effect when this contract is executed, and
those hereafter adopted, endorsed with the effective date thereof, shall be
furnished to Bonneville, and Bonneville shall keep said rates on file. The
Purchaser agrees to serve each of its Consumers at, and in accordance with,
the rates, charges, and provisions set forth in the applicable rate schedules
on file where and as required by law or on file in Bonneville's office.
Notice c; the intent to change r�cail rates shall be g to Bonneville
Exhibit B, Page 45 of 48
General Contract Provisions
8/25/81
either 45 days prior to their effective date or as soon as the regulatory
process allows or shall be mailed to Bonneville on the same day as a notice of
a rate change given to a state regulatory authority by the Purchaser,
whichever will result in the later receipt of such notice by Bonneville.
(b) The retail rates and charges shall be reasonable and
nondiscriminatory, consistent with the principles of the Bonneville Project
Act, subject to the right of the Purchaser to adopt retail rates designed to
achieve cost effective conservation or renewable resources; provided,
however, that rates and charges which have been approved in accordance with
the procedures of a state regulatory agency having jurisdiction shall be
deemed prima facie reasonable and nondiscriminatory. The Purchaser shall
maintain records containing the data, analyses, and other factors which are
used to develop and form the basis for its proposed or final retail rates. At
Bonneville's request, such records as are available for public inspection
shall be supplied during the rate development process or after the rates have
been adopted.
(c) At the Purchaser's request, Bonneville shall (1) provide assistance
in analyzing and developing rate structures, including retail rate structures
that will encourage cost effective conservation and Consumer -owned renewable
resources; (2) provide estimates of the probable power savings and the
probable amount of billing credits under section 6(h) of P.L. 96 -501 that
might be realized by the Purchaser adopting and implementing such retail rate
structures; and (3) solicit additional information and analytical assistance
from appropriate state regulatory bodies and Bonneville's other Customers.
C. IN REFERENCE TO USE OF POWER
Exhibit B, Page 46 of 48
General Contract Provisions
8/25/81
55. Resale of Power. The Purchaser shall not resell Firm Power
delivered under this contract except to those Consumers and utilities within
its service area in the Pacific Northwest to the extent such Consumers and
utilities are normally dependent on the Purchaser for their firm power
supplies. The Purchaser shall not sell power from its Firm Resources in such
a manner as to increase the Purchaser's Computed Peak Requirement or Computed
Average Energy Requirement on Bonneville in any month. These prohibitions on
resale in this section shall not be interpreted as a general prohibition
against the Purchaser simultaneously purchasing Firm Power from Bonneville and
selling power generated at its own facilities to other utilities.
D. IN REFERENCE ONLY TO PURCHASERS WITH GENERATING FACILITIES
56. Nonfirm Deliveries.
(a) At the request of either the Purchaser or Bonneville, the other party
will make available on the terms stated herein, such thermal generated energy
or hydro- generated energy as the supplying party determines, when such request
is made, that it has available for delivery to the requesting party.
(b) Neither party, by this contract, assures the other that it has, or
will have available, any thermal generated energy or hydro generated energy
for delivery to such other party, and the determination made by the supplier,
orovided for in subsection (a) above, of the amount, if any, of such energy
Exhibit B, Page 47 of 48
General Contract Provisions
8/25/81
which it will supply to the other party shall be final and conclusive as to
both parties.
(c) Nothing in this contract shall prohibit supply of nonfirm, emergency
or breakdown relief energy under any other contract.
57. Emergency or Breakdown Relief.
(a) If a breakdown of, or emergency on, the system of either the
Purchaser or Bonneville occurs, while such breakdown or emergency exists, the
other party will make available upon request, all or such part of the electric
energy required for such system as the supplier determines it can supply,
consistent with its obligations to its other customers. The determination so
made by the supplier shall be final and conclusive as to both parties.
(b) If either party supplies electric energy to the other party pursuant
to the provisions of subsection (a) of this section and requests replacement
thereof, the other party shall make an equivalent amount of electric energy
available to such supplier at such times as may be agreed upon by the
dispatchers of the parties hereto.
58. Effect on Generating Utility by Direct Service •Industrial Customer
Power Sales Contract Provisions. Bonneville will notify the Purchaser of the
proposed adoption of an annual operating plan, annual operating agreement or
energy accounting system in the Direct Service Industrial Customers' power
sales contracts. If, in Bonneville's sole determination, the system of a
generating utility will be materially affected by a proposed annual operating
plan, annual operating agreement, or energy accounting system provided in the
Direct Service Industrial Customers' power sales contracts, Bonneville will
(WP- PCI- 0144c)
(8/25/81)
B. IN REFERENCE TO PURCHASE
Exhibit B, Page 48 of 48
General Contract Provisions
8/25/81
consult with such utility prior to adopting such proposed plan, agreement, or
accounting system.
IV. RELATING ONLY TO DIRECT- SERVICE INDUSTRY PURCHASERS
A. IN REFERENCE TO COMPUTATION OF CHARGES
59. Demands. During periods when Bonneville is delivering to the
Purchaser hourly amounts of electric power or energy under the terms of
agreements other than this contract, such amounts shall be subtracted each
hour from the Integrated Demand for deliveries hereunder for each such hour
after adjusting such Integrated Demands as appropriate to the Point of
Delivery.
60. Use and Resale of Power. All electric power and energy delivered
under this contract shall be used by the Purchaser in its own operations, and
the Purchaser shall not resell such electric power and energy delivered under
this contract, or any part thereof. If the Purchaser resells such electric
power and energy, or any part thereof, Bonneville shall immediately terminate
this contract.
I. Summary
Average System Cost Methodology
Exhibit C, Page 1 of 7
This exhibit sets forth the method for computation and payment of
average system cost" for the purpose of an exchange of power between
Bonneville and a Utility pursuant to section 5(c) of Public Law 96 -501
(Regional Act). The method provides that for an exchanging Utility the
average system cost (ASC) is: the costs allowed or established for
retail ratemaking that are eligible for exchange divided by the
kilowatthours of load assumed for retail ratemaking, adjusted consistent
with this methodology. Under this method, a separate ASC will be
calculated for each exchanging Utility for each jurisdiction in which
the Utility does business. Each ASC so calculated will be changed when
revised retail rates go into effect.
This exhibit sets forth specific procedures for reporting cost items and
recognition of those items in determining ASC, including procedures for
the exclusion of particular costs as required by statute. The exhibit
also sets forth the procedures for the filing of relevant data by the
Utility and for the review of that data by Bonneville.
II. Definitions
The following definitions apply to all sections of Exhibit C.
A. "Average System Cost" or "ASC" means for each Jurisdiction and each
Exchange Period the quotient obtained by dividing Contract System
Costs by Contract System Load.
B. "Commission" means a State regulatory body, preference Utility
governing body, or other entity authorized to establish retail
electric rates in a Jurisdiction.
C. "Contract System Costs" means the Utility's costs for production
and transmission resources, including power purchases and
conservation measures, which costs are includable in,
jurisdictionally allocated by, and subject to the provisions of
Appendix 1. Contract System Costs do not include costs required to
be excluded from ASC by section 5(c)(7) of the Regional Act; the
exclusion of these costs is provided for in Footnote 15 to
Appendix 1.
D. "Costs" means the aggregate dollar amount or any portion of the
amount allowed or relied upon by the Commission to determine the
Test Period revenue requirement for the Utility in a Jurisdiction.
E. "Exchange Period" means the period of time during which a Utility's
Jurisdictional retail rate schedules are in effect, commencing with
the effective date of these schedules and ending with the effective
Exhibit C, Page 2 of 7
date of new retail rate schedules in the Jurisdiction; provided
that no Exchange Period shall commence prior to or extend beyond
the term of the Utility's Residential Purchase and Sale Contract
Agreement.
F. "Contract System Load" means the firm energy load used by the
Commission for the purpose of establishing retail rates, adjusted
pursuant to Appendix 1.
G. "Jurisdiction" means the service territory of the exchanging
Utility within which a Commission has authority to approve the
retail rates.
H. "New Large Single Load" means that load defined in section 3(13) of
the Regional Act, and as determined by Bonneville as specified in
power sales contracts with its customers.
I. "Regional Power Sales Customer" means any entity that contracts
directly with Bonneville for the purchase of power for delivery in
the region as defined by section 3(14) of the Regional Act.
J. "Test Period" means the time period, not to exceed 12 months, used
by the Commission to determine Costs for retail ratemaking.
III. Procedures for Determining Average System Cost
The procedures set forth in this section will enable Bonneville to
determine the ASC, in accord with the methodology in Appendix 1, for
each exchanging Utility for each Jurisdiction within the region where
the Utility provides service. The ASC so determined will be in effect
during the Exchange Period and will apply to the amount of exchange
power acquired by Bonneville from the Utility during the Exchange
Period. The amount of exchange power will be equal to the Utility's
eligible load within the Jurisdiction. Bonneville will determine and
pay a separate ASC for the exchange power related to the Utility's
eligible load in each Jurisdiction. The procedures are as follows:
A. Appendix 1 is a form that identifies Contract System Costs and
Contract System Load and permits the calculation of ASC.
Appendix 1 is an integral part of this document.
8. For each Exchange Period and for each regional Jurisdiction in
which a Utility provides service, the Utility shall complete and
file with Bonneville five copies of Appendix 1 as follows:
1. On or prior to the effective date of the Utility's residential
exchange contract, the Utility shall file an Appendix 1
reflecting its existing Costs for each Jurisdiction for which
it is participating in the exchange. Subject to the
Exhibit C, Page 3 of 7
provisions of Section IV, the ASC determined from each
Appendix 1 shall be the rate applicable to exchange power from
that Jurisdiction during the initial Exchange Period.
2. Thereafter, not later than five working days after filing for
a Jurisdictional rate change or otherwise commencing a rate
change proceeding, the Utility shall file with Bonneville a
preliminary Appendix 1, setting forth the Costs proposed by
the Utility. In addition, within five working days from the
day a Utility files for a Jurisdictional rate change or
otherwise commences a rate change proceeding, the Utility
shall deliver to Bonneville all information initially provided
to the Commission. The Utility also will provide to
Bonneville within a reasonable period of time any other
information reasonably requested by Bonneville.
3. Not later than five working days following the commencement
date of a new Exchange Period, the Utility shall file with
Bonneville a revised Appendix 1, reflecting its Costs as
approved by the Commission. In addition, the Utility shall
provide within 20 working days following the commencement date
of a new Exchange Period a reconciliation of all differences
between the preliminary Appendix 1 and the revised
Appendix 1. Subject to the provisions of Section IV, the ASC
included in the revised Appendix 1 will be the ASC applicable
to exchange power for that Jurisdiction during the Exchange
Period; provided, that if a Utility files a revised Appendix 1
after the five -day deadline Bonneville may make the new ASC
payable only from the date the revised Appendix 1 was actually
filed. However, Bonneville shall not delay as a result of a
late filing of an Appendix 1 the effective date of any change
in the ASC for power provided to it under this agreement if
the late filing was the result of unavoidable delay or
excusable neglect, and the Utility proceeded to correct the
filing error in good faith and with diligence.
C. If Bonneville or any of its Regional Power Sales Customers have
been denied the right to participate in a Jurisdictional rate
review proceeding on the basis of standing as an intervenor or
otherwise with rights equivalent to any retail customer of the
Utility, no change in ASC based on a change of Costs authorized in
that proceeding shall be effective until Bonneville has completed
its review pursuant to Section IV.
IV. Bonneville Review Process
A. Each Appendix 1 shall be reviewed by Bonneville or its designate to
determine whether the Costs are not inconsistent with generally
accepted accounting principles for electric utilities, whether
Contract System Costs contains only allowed Costs, and whether the
Appendix 1 complies with the requirements of this Exhibit C
including applicable definitions and requirements incorporated from
Exhibit C, Page 4 of 7
the FERC Uniform System of Accounts. If a retail rate change is
authorized without substantive Commission findings as to Costs or
if Bonneville or any of its Regional Power Sales Customers are
denied the right to participate in a Jurisdictional rate review
proceeding on the basis of standing as an intervenor or otherwise
with rights equivalent to any retail customer of the Utility, the
review by Bonneville or its designate also may consider whether
Contract System Costs have changed by the amount of the retail rate
change, and Bonneville shall not be obligated to pay an ASC
different than the ASC based,on Contract System Costs as determined
by Bonneville.
B. The Appendix 1 described in Section III(B)(1) shall be subject to
review for a period of 180 days following the effective date of the
contract. A revised Appendix 1 described in Section III(B)(2) and
(3) shall be subject to review for a period of 120 days from the
start of the relevant Exchange Period.
C. Bonneville or its designate will conduct its review as promptly as
reasonably possible, shall make a written report of its
determinations, and shall make any resulting increase or decrease
in the ASC for the relevant Exchange Period; provided, that if
Bonneville has not issued a report as of the last date of the
review period, then the ASC rate shown on the revised Appendix 1
described in Section III(B)(3) filed by the Utility shall be the
ASC for the Exchange Period.
D. Bonneville will afford its Regional Power Sales Customers and other
interested persons an opportunity to comment in writing on each
Appendix 1 filed by a Utility. To facilitate this process, a
Utility filing an Appendix 1 shall mail written notice thereof to
each of Bonneville's Regional Power Sales Customers or their
designates, in accordance with a list provided by Bonneville. This
notice shall summarize the adjustment to costs proposed, make
reference to the customers' right to comment thereon, and specify
where materials relevant to the Cost adjustment process may be
examined. The Utility and Bonneville shall permit Regional Power
Sales Customers and interested parties to examine each Appendix 1
submitted to Bonneville. The utilities shall respond to reasonable
information requests revelant to ASC from Bonneville and its
Regional Power Sales Customers, provided that the furnishing of
proprietary or confidential information to Bonneville or to a
Regional Power Sales Customer may be made contingent on the
granting of proper safeguards to prevent unauthorized use or
disclosure. All comments from Bonneville's Power Sales Customers
and interested parties must be received in writing by Bonneville no
later than 20 days prior to the end of Bonneville's review period.
All such comments will be included as part of the record supporting
the ASC determined by Bonneville.
Exhibit C, Page 5 of 7
E. If Bonneville determines that the ASC computed by the Utility in
Appendix 1 was excessive or inadequate, the injured party shall
recover the excess or deficiency with interest which shall be
computed from time to time on the outstanding balance at the rate
or rates of interest charged to Bonneville by the U.S. Treasury
during the period unless another form of refund is ordered by the
Joint State Board, the FERC, or a reviewing court. If a final
order of the Joint State Board, the FERC or a reviewing court
revises Bonneville's ASC determination, the difference between this
revised ASC and the ASC determined by Bonneville, together with the
interest at the above rate, shall be paid to the party entitled
thereto by the other party, unless another interest rate is so
ordered.
F. If costs associated with a generating facility are included in ASC
and that generating facility is later terminated prior to the date
of initial commercial operation, Bonneville shall be entitled to
recover revenues as follows.
For any exchange period in which Construction Work in Progress
(CWIP) was included in the rate base:
1. If the CWIP included in the rate base was identified with
a particular generating facility terminated prior to the
date of initial commercial operation, Bonneville shall
recover revenue based on the amount of CWIP identified
with that terminated facility that was included in the
ASC rate base.
2. If the terminated facility was among a group of
facilities for which CWIP was allowed in the ASC rate
base, Bonneville shall recover revenues based on the
amount that the CWIP included in the ASC rate base
exceeded the utility's total available jurisdictional
CWIP for the same group of facilities, after exclusion of
any CWIP for generating facilities subsequently
terminated prior to the date of initial commercial
operation.
When a generating plant is terminated prior to the date of initial
commercial operation, the Utility will submit to Bonneville a
calculation of the recoverable revenue attributable to the
inclusion of the amount of CWIP specified above, if any, for each
exchange period, including a reconciliation with the final
Appendix 1 for that period. This calculation shall include the
effect of any inclusion of Allowance For Funds During Construction
(AFUDC) as an offset to test year revenue requirement and the
impact on related taxes. The interest rate on revenue to be
recovered shall be calculated as in Section IV(E). Bonneville
shall bill the Utility in equal monthly installments over a period
Exhibit C, Page 6 of 7
of the same length as the period during which costs of the
terminated facility were included in ASC unless another arrangement
is mutually agreed upon.
V. FERC Procedure (Applicable Only to Utilities Subject to Part II of the
Federal Power Act)
A. Each Utility that is subject to the FERC's jurisdiction under Part
II of the Federal Power Act shall file Bonneville's written report,
the ASC determined by Bonneville, and the Utility's Appendix 1 with
the FERC, its delegate or successor, within 15 working days of
Bonneville's determination of ASC according to Section IV(C)
above. During the period between the date of Bonneville's
determination of ASC and the date of the final order issued by the
FERC, its delegate or successor, the ASC determined by Bonneville
shall be in effect.
This filing with the FERC shall be deemed to be compliance by the
Utility with Section 205(c) of the Federal Power Act. The ASC
ordered by the FERC, its delegate or successor, shall be the lawful
ASC in effect from the start of the relevant Exchange Period, and
the FERC shall be deemed to have so ordered under Section 205(d) of
the Federal Power Act. The Utility may contest any ASC adjustment
made by Bonneville in any ASC review proceeding before the FERC,
its delegate or successor, and may argue for an ASC to be effective
from the start of the relevant Exchange Period calculated pursuant
to the Appendix 1 described in Section III(B)(3) it filed with
Bonneville.
B. The Utility shall notify all parties that made comment to
Bonneville on the Utility's Appendix 1 of its ASC filing with the
FERC. The FERC shall publish notice of the filing in the Federal
Register. The notice shall specify that parties will be allowed an
opportunity to comment in writing and to respond in writing to
comments filed by any other party. If one or more members of the
FERC, its delegate or successor, determine that a substantial issue
of fact or law exists, an opportunity for oral presentation of
arguments shall be provided.
C. The FERC's review of ASC shall ascertain whether Bonneville's ASC
was determined in accord with the methodology described in this
Exhibit C. If the FERC, its delegate or successor, should
determine that Bonneville's ASC rate was not determined in accord
with the methodology, it shall order that such ASC be changed,
specifying in the order the necessary changes. The FERC shall
publish its final order approving or disapproving the ASC in the
Federal Register.
(WP- PLB- 0016n)
Exhibit C, Page 7 of 7
VI. Change in Average System Cost Methodology
The Administrator, at his or her discretion, or upon written request
from three quarters of the utilities who are parties to contracts
pursuant to section 5(C) of the Regional Act, or from three quarters of
his preference customers, or from three quarters of Bonneville's
direct service industry customers, shall initiate a consultation process
as provided for in section 5(c) of the Regional Act. After completion
of this process, the Administrator may propose a new ASC methodology,
provided that any consultation process may not be initiated sooner than
1 year after the immediately previous ASC methodology has been adopted
by Bonneville and approved by the FERC.
The schedules are as follows:
Average System Cost Methodology
Exhibit C, Page 1 of 1
Appendix 1, Instructions
Exhibit C Appendix 1 is the form on which a Utility participating in a
Residential Purchase and Sale Agreement shall report its Contract System Costs
and other necessary data for the calculation of ASC.
The form consists of six schedules that shall be completed by the Utility in
accord with these instructions and the provisions of the footnotes following
the schedules. Any items not applicable to the Utility shall be so identified.
Schedule 1 Plant Investment /Rate Base /Rate -of- Return
2 Capital Structure and Cost of Capital
3 Expenses
4 Income Taxes
5 Average System Cost
6 Total Utility and Jurisdictional Results of Operations
The filing Utility shall reference and attach workpapers that support Costs,
including details of allocation and functionalization.
All references to the FERC accounts are to the FERC Uniform System of Accounts
as of October 1, 1981. The Costs includable in the attached schedules are
those includable by reason of the definitions in the FERC accounts. If the
FERC accounts are later revised or renumbered, any changes shall be
incorporated into this form by reference, except to the extent that
Bonneville, upon a showing of good cause, demonstrates that a particular
change results in a substantial change in the type of Costs allowable for
exchange purposes. If the Utility does not follow the FERC accounts, its
filing must include a reconciliation between its accounts and the items
allowed as Contract System Costs.
Bonneville may require the Utility to account for purchase power transactions
with affiliated entities as though the affiliated entities were owned in whole
or in part by the utility, if necessary to properly determine and /or
functionalize the utility's costs.
A Utility operating in more than one Jurisdiction shall allocate its total
system costs among Jurisdictions in accord with the same allocation methods
and procedures used by the Commission to establish jurisdictional Costs and
resulting revenue requirements. Appendix 1 shall include details of the
allocation. This allocation also accomplishes the exclusion of the Costs of
additional resources to meet loads outside the region, as required by
section 5(c)(7) of the Regional Act.
All schedule entries and supporting data shall be in accord with generally
accepted accounting principles and practices as these principles and practices
apply to the electric utility industry.
(WP- PLB- 0016n)
Functionalization
Line Jurisdiction Excluded Total To Be Total for
No. Items /FERC Accounts /Footnotes Total Amount 15b c/ Functionalized Production Transmission Exchange Other
(1) (2) (3) (4) (5) (6) (8)
1 Plant -in- Service /310 -373 1/ 7/ 8/
2 General Plant /389 -399 2/
3 Intangible Plant /301 -3M3 3/
4 CWIP /107, 120.1 3/
5 Acquisition Adjustment /114 1/
6 Total Gross Plant
7 Less:
8 PIS Depreciation Reserve /108 1/ 4/
9 General Plant Depreciation
Reserve /108 4/
10 Accumulated Amortization /111, 115 4/
11 Total Plant Deductions
12 Total Net Plant
13 Plant Held for Future Use /105 3/
14 Nuclear Fuel /120.2 -120.4 Less 120.5 1/
15 Accumulated Deferred Debits /186 3/
WP- PLB -0016n
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Plant Investment /Rate Base /Rate -of- Return
Jurisdiction
AVERAGED SYSTEM COST CALCULATION IS NOT YET COMPLETED.
Exhibit C
Appendix 1
Schedule 1
Page 1 of 2
Functionalization
Line Jurisdiction Excluded Total To Be Total for
No. Items /FERC Accounts /Footnotes Total Amount 15b c/ Functionalized Production Transmission Exchange Other
(1) (2) (3) (4) (5) (6) (7) (8)
16 Less:
17 Customer Advances /252 19/
18 Accumulated Deferred Investment.
Tax Credits /255 3/
19 Accumulated Deferred Income
Taxes /281 -283 3/
20 Other Accumulated Deferred
Credits /253, 256 -257 3/
21 Total Net Accumulated
Deferred Debits /Credits
22 Cash Working Capital /Various 6/
23 Materials and Supplies /151 -157, 163 3/
24 Other /106, 124, 184, Various 3/ 20/
25 Total Rate Base
26 Times Rate -of- Return 16/ 23/
WP- PLB -0016n
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Plant Investment /Rate Base /Rate -of- Return
Jurisdiction
Exhibit C
Appendix 1
Schedule 1
Page 2 of 2
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Rate Base Summary
Jurisdiction
Functionalization
Line Jurisdiction Excluded Total To Be Total for
No. Items Total Amount 15b c/ Functionalized Production Transmission Exchange Other
(1) (2) (3) (5) (6) (8)
1 Utility Plant -in- Service
2 Less: Accumulated Provision for
Depreciation and Amortization
3 Net Utility Plant -in- Service
4 Construction Work in Progress
5 Plant Held for Future Use
6 Utility Plant Acquisition Adjustments
7 Nuclear Fuel
8 Customer Advances for Construction
9 Materials and Supplies
10 Cash Working Capital
11 Unamortized Leasehold Improvements and
Other Miscellaneous Deferred Items
12 Weatherization- Interest Free Loans
13 Extraordinary Property Losses
14 Total Rate Base
Note: 1. Supporting workpapers are to be attached.
2. Footnotes referenced on Schedule 1 will be relied upon in determining ASC.
Exhibit C
Appendix 1
Schedule lA
Page 1 of 3
Functionalization
Line Jurisdiction Excluded Total To Be Total for
No. Items Total Amount 15b c/ Functionalized Production Transmission Exchange Other
(1) (2) (3) (4) (5) (6) (7) (8)
1 Intangible Plant
Production Plant:
2 Steam Production Plant
3 Nuclear Production Plant
4 Hydraulic Production Plant
5 Other Production Plant
6 Total Production Plant
7 Transmission Plant
8 Distribution Plant
9 General Plant
10 Total Electric Plant -in-
Service
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Electric Plant -In- Service
Jurisdiction
Note: 1. Supporting workpapers are to be attached.
2. Footnotes referenced on Schedule 1 will be relied upon in determining ASC.
Exhibit C
Appendix 1
Schedule IA
Page 2 of 3
Functionalization
Line Jurisdiction Excluded Total To Be Total for
No. Items Total Amount 15b c/ Functionalized Production Transmission Exchange Other
(1) (2) (3) (4) (5) (6) (7) (8)
Depreciation Reserve
Production Plant:
1 Steam Production
2 Nuclear Production
3 Hydraulic Production
4 Other Production
5 Transmission
6 Distribution
7 General
8 Total Depreciation Reserve
9 Amortization Reserve
10 Total Depreciation and
Amortization Reserve
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Reserve for Depreciation and Amortization of Electric Plant -in- Service
Jurisdiction
Note: 1. Supporting workpapers are to be attached.
2. Footnotes referenced on Schedule 1 will be relied upon in determining ASC.
Exhibit C
Appendix 1
Schedule lA
Page 3 of 3
Line
No.
Items /Footnotes
11)
1 Debt
2 Preferred Stock
3 Common Equity
4 Deferred Income Taxes 10/
5 Deferred Investment Tax Credit 10/
6 Total Weighted Cost
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Capital Structure and Cost of Capital
Jurisdiction
Exhibit C
Appendix 1
Schedule 2
Amount Ratio Component Cost Weighted Cost
(2) (3) (4) (b)
Line
No.
Items
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Debt Summary 11/
Jurisdiction
Exhibit C
Appendix 1
Schedule 2A
Date of Date of Interest Face Issue Net Interest
Issue Maturity Rate Amount Premium Discount Expense Proceeds Expense
(1) (2) (3) (4) (5) (6) (7) (8) (9)
Line
No.
Items
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Preferred Stock Summary
Jurisdiction
Exhibit C
Appendix 1
Schedule 2B
Shares Dividend Outstanding Issue Net
Issued Rate Balance Premium Expense Proceeds Dividends
(1) (2) (3) (4) (5) (6) (7)
Functionalization
Line Jurisdiction Excluded Total To Be Total for
No. Items /FERC Accounts /Footnotes Total Amount 15b c/ Functionalized Production Transmission Exchange Other
(1) (2) (3) (4) (5) (6) (7) (8)
1 Production:
2 Fuel /501, 518, 547 1/
3 Purchased Power /555 1/
4 Other /500, 502 -517, 319 -546,
548 -577 1/
5 Transmission7560 -573 1/ 4/
6 Distribution /580 -598 1/ 4/
7 Customer Accounting /0405 19/
8 Customer Assistance /907 -910 TY
9 Admin. General /920 -932 12/
10 Total Operations Main.
11 Depreciation Amortization/
403 -407 1/ 4/
12 Taxes Other than Federal Income/
408, 409.1 3/ 4/ 13/ 14/
13 Federal Income lax /9.17
410.1, 411.1, 411.4 9/
14 Other /411.6, 411.7 3/
15 Less:
16 Nonfirm Sales for Resale Rev. /447 22/
17 Other Operating Rev. /450 -456 3/ 25/
18 Billing Credits 5/
19 Total Operating Expenses
20 Return from Schedule 1
21 Less Subsidiary Income
22 Total Cost 18/
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Expenses
Jurisdiction
Exhibit C
Appendix 1
Schedule 3
POWER PRODUCTION EXPENSES
Steam Power Generation:
1 Operation
2 Fuel
3 Other
4 Maintenance
5 Total Steam Power Generation
Nuclear Power Generation:
6 Operation
7 Fuel
8 Other
9 Maintenance
10 Miscellaneous Nuclear Research
11 Total Nuclear Power Generation
Hydraulic Power Generation:
12 Operation
13 Maintenance
14 Total Hydraulic Power Generation
Other Power Generation:
15 Operation
16 Maintenance
17 Total Other Power Generation
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Electric Operating Expenses
Jurisdiction
Exhibit C
Appendix 1
Schedule 3A
Page 1 of 2
Functionalization
Line Jurisdiction Excluded Total To RP Total for
No. Items Total Amount 15b c/ Functionalized Production Transmission Exchange Other
(1) (2) (3) (4) (5) (6) (7) (8)
21 Total Power Production Expenses
1AISMISSION EXPENSES
22 Operation
23 Wheeling
21 Other
2 Maintenance
2> Total Distribution Expenses
DIS RIBUTION EXPENSES
2/ Uperation
23 Maintenance
2') Total Distribution Expenses
30 CUSTOMER ACCOUNTS EXPENSES
31 CUSTOMER SERVICE AND INFORMATION EXPENSES
N)MINISTRATIVE AND GENERAL EXPENSES
32 Operation
33 Maintenance
34 Total Administrative and General
Expenses
35 TOTAL ELECTRIC OPERATING EXPENSES
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Electric Operating Expenses
Jurisidiction
Functionalization
Line Jurisdiction Excluded Total To Be total for
No. Items Total Amount 15b c/ Functionalized Production Transmission Exchange Other
(1) (2) (3) (4) (5) (6) (7) T8T
Other Power Supply Expenses:
18 Purchased Power
19 Other
20 Total Other Power Supply Expenses
Not': 1. Supporting workpapers are to be attached.
2. Footnotes referenced on Schedule 3 will be relied upon in determining ASC.
Exhibit C
Appendix 1
Schedule 3A
Page 2 of 2
Depreciation:
1 Steam Production Plant
2 Nuclear Production Plant
3 Hydraulic Production Plant
4 Other Production Plant
5 Transmission Plant
6 Distribution Plant
7 General Plant
8 Total Depreciation
9 Amortization of Limited -Term Plant
10 Amortization of Utility Plant
Acquisition Adjustments
11 Amortization of Property Losses
12 Total Depreciation and Amortization
Accrual
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Depreciation and Amortization Accrual
Jurisdiction
Functionalization
Line Jurisdiction Excluded Total To Be Total for
No. Items Total Amount 15b c/ Functionalized Production Transmission Exchange Other
(1) (2) (3) (4) (5) (6) (7) (8)
Note: 1. Supporting workpapers are to be attached.
2. Footnotes referenced on Schedule 3 will be relied upon in determining ASC.
4
Exhibit C
Appendix 1
Schedule 3B
Line Jurisdiction Excluded Total To Be
No. Items Total Amount 15b c/ Functionalized Production
(1) (2) (3) (4) (5)
1 FEDERAL Insurance Contributions
2 Unemployment
STATE
3 California Property
4 Unemployment
5 Oregon Property
6 Tri -Met
7 Lane County
8 Unemployment
9 Regulatory Commission
10 Washington Property
11 Unemployment
12 Generating Tax
13 Pollution Control Credit
14 Idaho Property
15 Montana Property
16 Unemployment
17 Wyoming Property
18 Unemployment
19 Utah Property
20 LOCAL Occupation and Franchise
21 STATE INCOME TAXES
22 IN -LIEU TAXES
23 OTHER
2$ TOTAL
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Taxes Other Than Federal Income Taxes
Jurisdiction
Note: 1. Supporting workpapers are to be attached.
2. Footnotes referenced on Schedule 3 will be relied upon in determining ASC.
Exhibit C
Appendix 1
Schedule 3C
Functionalization
Total for
Transmission Exchange Other
(6) (7) (8)
1
1 Federal Income Taxes
2 Deferred Income Taxes
3 Income Taxes Deferred in Prior Years
4 Investment Tax Credit Adjustment
5 Total Federal Taxes
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Income Taxes
Jurisdiction
Exhibit C
Appendix 1
Schedule 4
4
Functionalization
Line Jurisdiction Excluded Total To Be Total for
No. Items Total Amount 15b c/ Functionalized Production Transmission Exchange Other
(1) (2) (3) (4) (5) (6) (7) (8)
Functionalization
Line Jurisdiction Excluded Total To Be Total for
No. Items Total Amount 15b c/ Functionalized Production Transmission Exchange Other
(1) (Z) (3) (4) (5) (6) (7) (8)
INCOME
1 Operating Revenues
Deductions
2 Operating and Maintenance Expense
3 Depreciation Expense
4 Amortization Expense
5 Taxes Other Than Federal Income Taxes
6 Interest Expense
7 Total Deductions
8 Net Income Before Federal Income Tax
TAX ADJUSTMENTS
9 Book Depreciation
10 Tax Depreciation
11 Charges to Construction
12 Coal Depletion
13 Other Adjustments
1.
2.
14 Total Tax Adjustments
15 Taxable Income
16 Preferred Dividends Paid Credit
17 Total Taxable Income
18 Federal Income Tax
19 Less Investment Credit
20 Net Federal Income Tax
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Federal Taxes on Income
Jurisdiction
Note: 1. Supporting work papers are to be attached.
2. Footnotes referenced on Schedule 4 will be relied upon in determining ASC.
Exhibit C
Appendix 1
Schedule 4A
Line Jurisdiction Excluded Total To Be
No. Items /FERC Account Total Amount 15b c/ Functionalized
(1) (2) (3) (4)
Operating Revenues:
1 Nonfirm Sale for Resale /447
2 1.
3 2.
4 3.
Other Operating Revenues /450 -456
5 Acct. 450
6 Acct. 451
7 Acct. 452
8 Acct. 453
9 Acct. 454
10 Acct. 455
11 Acct. 456
12 Total Revenues
Other Items:
13 Investment Tax Credit Adjustment /411.5
14 Deferred Current Year
15 Restored Current Year
16 Restored from Prior Years
17 Total ITC Adjustment
18 Defer Income Tax Current /410.1
19 Deferred Income Tax from prior years /411.1
20 Other Accounts
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Other Included Items
Jurisdiction
Note: 1. Supporting workpapers are to be attached.
2. Footnotes referenced on Schedule 4 will be relied upon in determining ASC.
Exhibit C
Appendix 1
Schedule 4B
Functionalization
Total for
Production Transmission Exchange Other
(6) (7) (8)
Line
1 Contract System Costs:
2 Production Cost (from Schedule 3)
3 Transmission Cost (from Schedule 3)
4 Total Contract System Costs
5 Contract System Load:
5 Total Load (MWh)
7 Less:
3 Nonfirm Adjustment (MWh)
l Other Adjustments (MWh)
10 Net Load (MWh)
11 Plus:
12 Distribution Losses (MWh) 17/
13 Total Net Load (MWh)
14 Less:
15 Excluded Load (MWh)
16 Excluded Load Distribution Losses (MWh)
17 Total Contract System Load (MWh)
18 Average System Cost (mills /kWh)
(Line 4 Line 17)
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Average System Cost
Jurisdiction
Exhibit C
Appendix 1
Schedule 5
Items Amount
1 Intangible Plant
Production Plant:
2 Steam Production Plant
3 Nuclear Production Plant
4 Hydraulic Production Plant
5 Other Production Plant
6 Total Production Plant
7 Transmission Plant
8 Distribution Plant
9 General Plant
10 Total Electric Plant -in- Service
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Electric Plant -In- Service
Jurisdiction
Exhibit C
Appendix 1
Schedule 6A
Line Total Allocation Jurisdictional
No. Items Utility Basis 15a/ Amount
(1) (2) (3) (4)
10 Total Depreciation and
Amortization Reserve
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Reserve for Depreciation and Amortization of Electric Plant -In- Service
Jurisdiction
Exhibit C
Appendix 1
Schedule 6B
Line Total Allocation Jurisdictional
Items Utility Basis 15a/ Amount
(1) (2) (3) (4)
Depreciation Reserve
Production Plant:
1 Steam Production
2 Nuclear Production
3 Hydraulic Production
4 Other Production
5 Transmission
6 Distribution
7 General
8 Total Depreciation Reserve
Amortization Reserve
1 Utility Plant -in- Service
2 Less: Accumulated Provision for
Depreciation and Amortization
3 Net Utility Plant -in- Service
4. Construction Work in Progress
5 Plant Held for Future Use
6 Utility Plant Acquisition Adjustments
7 Nuclear Fuel
8 Customer Advances for Construction
9 Materials and Supplies
10 Cash Working Capital
11 Unamortized Leasehold Improvements and
Other Miscellaneous Deferred Items
12 Weatherization- Interest Free Loans
13 Extraordinary Property Losses
14 Total Rate Base
BONNEVILLE POWER ADMINCSTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Rate Base Summary
Jurisdiction
Exhibit C
Appendix 1
Schedule 6C
Lane Total Allocation Jurisdictional
No. Items Utility Basis 15a/ Amount
(1) (3) (4)
POWER PRODUCTION EXPENSES
Steam Power Generation:
1 Operation
2 Fuel
3 Other
4 Maintenance
5 Total Steam Power Generation
Nuclear Power Generation:
6 Operation
7 Fuel
8 Other
9 Maintenance
10 Miscellaneous Nuclear Research
11 Total Nuclear Power Generation
Hydraulic Power Generation:
12 Operation
13 Maintenance
14 Total Hydraulic Power Generation
Other Power Generation:
15 Operation
16 Maintenance
17 Total Other Power Generation
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Electric Operating Expenses
Jurisdiction
Exhibit C
Appendix 1
Schedule 6D
Page 1 of 2
Line Total Allocation Jurisdictional
No. Items Utility Basis 15a/ Amount
(1) (2) (3) (4)
Line Total Allocation Jurisdictional
No. Items Utility Basis 15a/ Amount
(1) (2) (3) (4)
Other Power Supply Expenses:
18 Purchased Power
19 Other
20 Total Other Power Supply Expenses
21 Total Power Production Expenses
TRANSMISSION EXPENSES
22 Operation
23 Wheeling
2.4 Other
25 Maintenance
26 Total Distribution Expenses
DISTRIBUTION EXPENSES
27 Operation
28 Maintenance
29 Total Distribution Expenses
20 CUSTOMER ACCOUNTS EXPENSES
31 CUSTOMER SERVICE AND INFORMATION EXPENSES
ADMINISTRATIVE AND GENERAL EXPENSES
32 Operation
33 Maintenance
34 Total Administrative and General
Expenses
35 TOTAL ELECTRIC OPERATING EXPENSES
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Electric Operating Expenses
Jurisdiction
Exhihit C
Appendix 1
Schedule 6D
Page 2 of 2
1 Depreciation:
2 Steam Production Plant
3 Nuclear Production Plant
4 Hydraulic Production Plant
5 Other Production Plant
6 Transmission Plant
7 Distribution Plant
8 General Plant
9 Total Depreciation
10 Amortization of Limited -Term Plant
11 Amortization of Utility Plant
Acquisition Adjustments
12 Amortization of Property Losses
13 Total Depreciation and Amortization
Accrual
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Depreciation and Amortization Accrual
Jurisdiction
Exhibit C
Appendix 1
Schedule 6E
Line Total Allocation Jurisdictional
No. Items Utility Basis 15a! Amount
(1) (2) (4)
1 FEDERAL Insurance Contributions
2 Unemployment
STATE
3 California Property
4 Unemployment
5 Oregon Property
6 Tri-Met
7 Lane County
8 Unemployment
9 Regulatory Commission
10 Excise
11 Washington Property
12 Unemployment
13 Generating Tax
14 Pollution Control Credit
15 Idaho Property
16 Montana Property
17 Unemployment
18 Wyoming Property
19 Unemployment
20 Utah Property
21 LOCAL Occupation and Franchise
22 IN -LIEU TAXES
23 TOTAL
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Taxes Other Than Federal Income Taxes
Jurisdiction
Exhibit C
Appendix 1
Schedule 6F
Line Total Allocation Jurisdictional
No. Items Utility Basis 15a/ Amount
(1) (Y1 (4)
INCOME
1 Operating Revenues
DEDUCTIONS
2 Operating and Maintenance Expense
3 Depreciation Expense
4 Amortization Expense
5 Taxes Other Than Federal Income Taxes
6 Interest Expense
7 Total Deductions
8 Net Income Before Federal Income Tax
TAX ADJUSTMENTS
9 Book Depreciation
10 Tax Depreciation
11 Charges to Construction
12 Coal Depletion
13 Other Adjustments
1.
2.
14 Total Tax Adjustments
15 Taxable Income
16 Preferred Dividends Paid Credit
17 Total Taxable Income
18 Gross Federal Income Tax
19 Less Investment Credit
20 Net Federal Income Tax
WP- PLB -0016n
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Federal Taxes on Income
Jurisdiction
Exhibit C
Appendix 1
Schedule 6G
Line Total Allocation Jurisdictional
No. Items Utility Basis 15a/ Amount
(1) (2) (3) (4)
1 Operating Revenues:
2 IJonfirm Sale for Resale /447
3 1.
4 2.
5 3.
6 Other Operating Revenues /450 -456
7 Acct. 450
8 Acct. 451
9 Acct. 452
10 Acct. 453
11 Acct. 454
12 Acct. 455
13 Acct. 456
14 Total Revenues
15 Other Items:
16 Investment Tax Credit Adjustment /411.S
17 Deferred Current Year
18 Restored Current Year
19 Restored from Prior Years
20 Total ITC Adjustment
21 Deferred Income Tax Current /410.1
22 Deferred Income Tax from prior years /411.1
23 Other Accounts
BONNEVILLE POWER ADMINISTRATION
RESIDENTIAL PURCHASE AND SALE AGREEMENT
Average System Cost Methodology
Other Included Items
Jurisdiction
Exhibit C
Appendix 1
Schedule 6H
Line Total Allocation Jurisdictional
No. Items /FERC Accounts Utility Basis 15a/ Amount
(1) (2) (3) (4)
Average System Cost Methodology Footnotes
Exhibit C, Page 1 of 6
Appendix 1, Footnotes
1/ Functionalized directly from the FERC Uniform System of Accounts.
2/ Unless it can be determined that a plant item or plant related item is
associated directly with regional generation, transmission,
distribution, customer or other directly functionalized category, the
item shall be functionalized on the following basis in the following
order:
(a) If the location codes of the plant item can be used to identify a
principal generation, transmission, distribution or
customer related facility at that location, the plant item shall be
functionalized based on the functionalization of such principal
facility.
(b) For plant items not otherwise functionalized, the functionalization
formula in footnote 24 shall apply.
3/ (a) The utility shall functionalize these items according to an
analysis it performs that demonstrates the actual and /or intended
functional use of the items, or the plant item related thereto, and
include a detailed showing of the factors used to determine the
functionalization as a supplement to Exhibit C, Appendix 1. Costs
incurred only because the utility is engaged in the retail
distribution of electricity shall be functionalized to Other.
These items include, for example, retail revenue taxes and
uncollectible amounts for retail sales.
(b) In cases where items included are not directly assigned to a
particular function, these items shall be separately identified,
and a statement shall be provided as to why the items are not
directly functionalized by the 3(a) procedure. The
functionalization formula described in footnote 24 herein shall
apply to these items.
4/ Calculation of functionalized amount is to be consistent with property
items included in functionalized Total Gross Plant.
5/ The offset against Contract System Costs for billing credit revenue
arising from implementation of conservation measures and retail rate
structures that induce conservation shall be limited to the costs
included in Contract System Cost of the related conservation measures
and retail rate structures. These billing credit revenues shall be
functionalized on the same basis as the cost of the related conservation
measure.
Exhibit C, Page 2 of 6
Appendix 1, Footnotes
6/ Functionalization is to be directly related to the functional nature of
the items included in the Working Capital calculation approved by the
Commission. Should items included in the approved Working Capital
calculation not be directly assignable to a function and should there be
no footnote in this methodology directing the functionalization of the
item, these items shall be separately identified and the
functionalization formula in footnote 24 shall apply.
7/ Transmission plant means all land, conversion structures, and equipment
employed at a primary source of supply (i.e., generating station or
point of receipt in the case of purchased power) to change the voltage
or frequency of electricity for the purpose of its more efficient or
convenient transmission; all land, structures, lines, switching and
conversion stations, high tension apparatus and their control in
protection of equipment between a generating or receiving point and the
entrance to a distribution center or wholesale point; and all lines and
equipment whose primary purpose is to augment, integrate or tie together
the sources of power supply. The entrance to a distribution center
means all land, structures, conversion equipment, lines, line
transformers and other facilities utilized to deliver power to specific
customers or distribution substations.
8/ Distribution plant means all land, structures, conversion equipment,
lines, line transformers, and other facilities employed between the
primary source of supply (i.e, generating station, or point of receipt
in the case of purchased power) and of delivery to customers, which are
not includable in transmission system, as defined in footnote 7, whether
or not such land, structures, and facilities are operated as part of a
transmission system or as part of a distribution system.
Note: Stations that change electricity from transmission to
distribution voltage shall be classified as distribution stations.
Where poles or towers support both transmission and distribution
conductors, the poles, towers, anchors, guys, and rights -of -way shall be
classified as transmission system. The conductors, crossarms, braces,
grounds, tiewire, insulators, etc., shall be classified as transmission
or distribution facilities, according to the purpose for which they are
used.
Where underground conduit contains both transmission and distribution
conductors, the underground conduit and right -of -way shall be classified
as distribution facilities. The conductors shall be classified as
transmission or distribution facilities according to the purpose for
which they are used.
Land (other than rights -of -way) and structures used jointly for
transmission and distribution purposes shall be classified as
transmission or distribution according to their major use.
9/ Functionalized as specified in Schedule 4.
10/ If these items are treated in Schedule 1 as deductions from gross plant
investment in determining rate base, these items shall not be included
in the capital structure.
11/ Should a Commission approve a method for determining debt costs by a
means other than that shown here, Schedule 2A shall be modified in a
manner that shows the approved method, including accompanying
explanatory material.
12/ Expenses related to the FERC Accounts 920 -932 shall be functionalized
in accord with the following:
FERC Account Functionalization
Method
920 Footnote 3
921 3
922 3
923 3
924 3(a) or
24(a)
925 3
926 13
927 19
928 19
929 3
930.1 19
930.2 3
931 3
932 4
Exhibit C, Page 3 of 6
Appendix 1, Footnotes
13/ Functionalization is to be determined on a pro rata percentage basis
using the salary and wage data for production, transmission, and
distribution /other functions included in the Test Period costs on
which Appendix 1 is based. If, however, this information is
unavailable, comparable data shall be used for the most recent
calendar year as reported on the FERC Form 1 (at page 355), or similar
document. Furthermore, a portion of this expense shall be included in
Schedule 3, column 3, Excluded Amount, based on the amount of
labor- related costs included therein.
14/ A tax exempt Utility may include in -lieu taxes up to an amount that
is comparable, for each unit of government paid in -lieu taxes, with
taxes that would have been paid by a non -tax exempt Utility to that
unit of government, but in no event shall the jurisdictional total in
column 2 be greater than the actual amount paid.
Exhibit C, Page 4 of 6
Appendix 1, Footnotes
15/ Excluded Resources
(a) The cost of additional resources in an amount sufficient to meet
any additional load outside the region occurring after
December 5, 1980, will be determined by utilizing allocation
notes of multi -State utilities as assigned and utilized in State
retail rate filings.
(b) The cost of additional resources sufficient to serve any New
Large Single Load that was not contracted for, or committed to,
prior to September 1, 1979, is to be determined as follows:
(1) To the extent that any New Large Single Loads are served by
dedicated resources, at the cost of those resources,
including applicable transmission;
(2) In the amount that New Large Single Loads are not served by
dedicated resources, at Bonneville's New Resource rate as
established from time to time pursuant to section 7(f) of
the Regional Act and as applicable to the Utility, and
applicable Bonneville transmission charges if transmission
costs are excluded in the determination of Bonneville's New
Resource rates, to the extent such costs are recovered by
the Utility's retail rates in the applicable jurisdiction;
and
(3)
To the extent that New Large Single Loads are not served by
dedicated resources plus the Utility's purchases at the New
Resource rate, the costs of such excess load shall be
determined by multiplying the kilowatthours not served under
subsections (1) and (2) above by the cost (annual fixed plus
variable cost, including an appropriate portion of general
plant, administrative and general expense and other items
not directly assignable) per kilowatthour of all baseload
resources and long term power purchases (five years or more
in duration), as allowed in the regulatory jurisdiction to
establish retail rates during the. Exchange Period, exclusive
of the following resources and purchases: (a) purchases at
the New Resources rate pursuant to section 7(f) of the Act;
(b) purchases at the Federal Base System rate, pursuant to
section 5(c) of the Act; (c) resources sold to Bonneville,
pursuant to section 6(c)(1) of the Act; (d) dedicated
resources specified in footnote 15(b)(1) of this agreement;
(e) resources and purchases committed to the Utility's load
as of September 1, 1979 under a power requirements contract
or that would have been so committed had the Utility entered
into such a contract; and (f) experimental or demonstration
units or purchases therefrom. Transmission needed to carry
Exhibit C, Page 5 of 6
Appendix 1, Footnotes
power from such generation resources or power purchases
shall be priced at the average cost of transmission for the
Jurisdiction during the Exchange Period.
(4) Any kilowatthours of New Large Single Loads not met under
subsections (1), (2), or (3) above will be assumed to be
supplied from the most recently completed or acquired
baseload resource(s) or long term power purchase(s),
exclusive of dedicated resources and experimental or
demonstration resources or purchases therefrom, that are
committed to the Utility's load as of September 1, 1979,
under a power requirements contract with Bonneville or would
have been so committed had the Utility entered into such a
power requirements contract. The cost of these generation
resources and long -term power purchases and the transmission
cost associated with these resources or purchases will be
calculated as specified in subsection (3) above.
(5) If the New Large Single Load is served on an energy or
capacity interruptible basis, the Utility shall prepare a
calculation subject to review by Bonneville of the fixed (if
any) and variable costs of providing such service, except
that the amount excluded from ASC for the New large Single
Load shall not be less than the transmission and generation
costs included in the retail rate charged the New Large
Single Load.
(c) Any costs associated with a generation facility that is
terminated prior to initial commercial operation shall be
excluded if termination occurred after December 5, 1980.
16/ Authorized Jurisdictional rate of return as specified in Schedule 2.
17/ The losses shall be the distribution energy losses occurring between
the transmission portion of the Utility's system and the meters
measuring firm energy load used by the Commission for the purpose of
establishing retail rates. Losses shall be established according to a
study (engineering, statistical or other) that is submitted to
Bonneville by the exchanging Utility subject to review by Bonneville.
This study shall be in sufficient detail so as to accurately identify
average distribution losses associated with the Utility's total load,
excluded loads, and the Residential load. Distribution losses shall
include losses associated with distribution substations, primary
distribution facilities, distribution transformers, secondary
distribution facilities and service drops.
18/ This amount is to be reduced by revenues from firm sales for resale
(to the extent that these sales are included in the Jurisdictional
allocation factors) to be determined by the firm resale revenue for
the Test Period as used for retail ratemaking purposes.
Exhibit C, Page 6 of 6
Appendix 1, Footnotes
19/ Functionalize entirely to distribution /other unless Utility
demonstrates that other functionalization treatment is appropriate.
20/ "Other" rate base items may include Unclassified Plant -In- Service
(106), Extraordinary Property Losses (182), Other Investments (124),
or other investments approved for rate base treatment by a Commission
consistent with the provisions of this Exhibit.
21/ Only the conservation related portion is to be functionalized to
production.
22/ These revenues shall be divided proportionally between Excluded
Amount and Total To Be Functionalized based on the total expenses in
those two categories shown on Schedule 3 (sum of lines 1 to 13, 19,
and 20), less all terminated plant expenses excluded pursuant to
footnote 15(c). The portion to be functionalized shall be
functionalized to production.
23/ Public Agencies shall be allowed a total return (operating income) on
Schedule 1, line 26, column 2, equal to their demonstrated need for
revenues exceeding Total Operating Expenses shown on Schedule 3 to
cover the cost of capital. These demonstrated capital costs generally
will be in the form of coverage requirements or the need to maintain
an equity ratio consistent with favorable bond ratings for that
Utility. In order to receive an operating income in addition to
interest expense, the utility must submit evidence of the specific
coverage or equity ratio needed by that utility and a calculation of
the corresponding minimum operating income. Assignment to excluded
resources and functionalization of the operating income shall be based
on the assignment and functionalization of the rate base.
24/ Functionalization of these items shall be based on a formula that
averages on an equal weighting basis the percentages for generation,
transmission, distribution, and customer related functions for (a) the
gross plant in each function, including general plant and other plant
items functionalized in step 1 of footnote 2 and, (b) the
functionalized operations and maintenance (0 &M) expenses shown in
Schedule 3, except that the fuel cost included in O &M shall not
include the cost of fuel acquired from non Utility sources. Material
detailing the application of this functionalization formula shall be
included as a supplement to Appendix 1.
25/ Revenues from the transmission of electricity for others shall be
functionalized to transmission.
(WP- PLB- 0016n)
Such tariff schedules, as presently effective include:
where:
Residential Load Definition
Exhibit D, Page 1 of 2
I. The Utility's Residential Load means the sum of the Regional loads the
Utility elects to use as a basis for the exchange under the tariff
schedules described below adjusted for distribution losses as determined
pursuant to Exhibit C, as the same may be amended, supplemented, or
superseded. If Bonneville determines that any such action changes the
Utility's general tariffs or service schedules in a manner which would
allow loads other than residential loads, as defined in the Regional
Act, to be included under these tariff schedules, such nonresidential
loads shall, from the date the Utility is notified of Bonneville's
determination, be excluded from the residential purchase and sale
transaction hereunder.
A. all schedules listed below, the following designated percentages,
or kilowatthours of the load supplied by the Utility under:
B. a portion of the load as determined pursuant to section II below
supplied by the Utility under:
II. Any farm's monthly irrigation and pumping load qualifying hereunder for
each billing period shall not exceed the amount of the energy determined
by the following formula:
400 x 0.746 x days in billing period x 24, provided, however, that
this amount shall not exceed that farm's measured energy tor the
same billing period.
400 is equal to the horsepower limit defined in the Regional Act,
size
use
ownership
control
operating practices
distance between parcels
custom in the trade
billing treatment by the utility.
Exhibit D, Page 2 of 2
0.746 is the factor for converting horsepower to kW, days in
billing period is determined in accordance with prudent and normal
utility business practices, and 2A is the number of hours in a
day.
III. When more than one farm is supplied from a common pumping installation,
the irrigation and pumping load of the installation shall be allocated
among the farms using the installation, based on the method (e.g., water
shares, acreage) that the farms use to allocate the power costs among
themselves. These allocated loads shall then be combined with any other
irrigation and pumping loads attributed to the farms under section II
above. In no instance shall any farm's total qualifying irrigation
loads for any billing month exceed 222,000 kWh.
IVV. For purposes of this contract, a farm is defined as a parcel or parcels
of land owned or leased by one or more persons (person includes
partnerships, corporations, or any legal entity capable of owning farm
land) that is used primarily for agriculture. Agriculture is defined to
include the raising and incidental primary processing of crops,
pasturage, or livestock. Incidental primary processing means those
activities necessarily undertaken to prepare agricultural products for
safe and efficient storage or shipment. All electrical loads ordinarily
associated with agriculture as defined above shall be considered as
usual farm use.
Contiguous parcels of land under single- ownership or leasehold shall be
considered to be one farm and noncontiguous parcels of land under
single ownership or leasehold shall be considered as one farm unit when
operated as a single farm, unless demonstrated otherwise by the owner or
lessee of the parcels.
A number of factors shall determine whether contiguous or noncontiguous
parcels constitute one or more farms. These factors shall include but
are not limited to:
V. Unused irrigation allocations may not be reallocated to other farms or
to another billing period.
VI. The operator of a farm may be required to certify to the Utility all
irrigation accounts, including horsepower rating, with the Utility for
that farm, including all irrigation accounts commonly shared.
(WP- PCI- 0054c)
Using data from the 60 months prior to the last Bonneville rate filing, the
monthly Load Factor of the Utility shall be averaged over each seasonal period
in Bonneville's demand charge according to the formula below. The seasonal
period is all months of the year that have the same demand charge in Exhibit A.
where,
Load Factor p x H for each month;
Load Factor Specification
Exhibit E, Page 1 of 1
E the sum of monthly energy loads in the seasonal periods the Utility
filed with the FERC or other appropriate body for the previous five
years.
D the sum of monthly peak demands in the seasonal periods the Utility
filed with the FEPC or other appropriate body for the previous five
years.
N the number of months in the seasonal period.
the sum of hours in the month for all months in the seasonal period.
If the Utility acts as an agent for another utility (Principal Utility) the
Load Factor for the portion of the purchase equal to the Residential Load of
the Principal utility shall be determined based on the Principal utility's own
load data.
If Bonneville commences billing the majority of its public agency customers on
a basis other than monthly noncoincidental demand, the Utility's Load Factor
shall be computed from the 60 month historic data using a basis comparable to
the billing criteria applied to the majority of public agencies.
The historic data used for Load Factor computation shall not be adjusted for
normal temperature or streamflow. The historic data used for Load Factor
computations shall not include surplus or special sales. The Utility shall
provide, at Bonneville's request, the necessary information regarding the
incidence and timing of such sales.
0
Determination of New Large Single Loads
Exhibit F, Page 1 of 2
(a) Determination of a Facility. Bonneville and the Utility shall make
a reasonable determination of what constitutes a single facility,
for the purpose of identifying a New Large Single Load, based upon
the following criteria: (1) whether the load is operated by a
single Consumer; (2) whether the load is in a single location;
(3) whether the load serves a manufacturing process which produces
a single product or type of product; (4) whether separable portions
of the load are interdependent; (5) whether the load is contracted
for, served, or billed as a single load under the individual
Utility's customary billing and service policy; (6) consistent
application of foregoing criteria in similar fact situations; and
(7) any other factors the parties determine to be relevant.
(b) Determination of Ten Average Megawatt Increase. An increase in
load shall be considered a New Large Single Load if the energy
consumption of the consumer's load associated with a new facility,
existing facility or expansion of an existing facility during the
immediately past 12 -month period exceeds by 10 average megawatts or
more the consumer's energy consumption for such new facility,
existing facility, or expansion of an existing facility for the
consecutive 12 -month period one year earlier, or the amount of the
contracted for, or committed to load of the consumer as of
September 1, 1979, whichever is greater.
The contracted for, or committed to load as of September 1, 1979,
shall be the maximum amount of energy specified in such contract or
commitment, or the maximum energy consumption of the load or the
capacity limitation contained in such contract or commitment if
energy is not specified or limited.
(c) Identification of Potential New Large Single Loads. The Utility
shall make reasonable ettorts to i en ity potential Frew Large
Single Loads, and shall report to Bonneville (1) the addition of
electrical equipment of ten MVA or more by a single consumer;
(2) the installation of additional transformation capacity of
ten MVA or more by the Utility or a consumer which is designed to
serve a single facility; or (3) the potential change in operation
of a facility which may result in an increase of 10 average
megawatts or more in a 12 -month period.
(d) Service to New Large Single Loads. If a consumer of a Purchaser
provides a renewable or cogeneration resource to serve all or a
portion of a load associated with a facility which would otherwise
be a New Large Single Load, and thereby reduces the demand on the
Utility, that portion of such load on the Utility, if any, shall
not be a New Large Single Load, unless the load or portion thereof
on the Utility is 10 average megawatts or more; provided, however,
that if a consumer sells, displaces or removes a resource or
portion thereof, from service to the consumer's load at such
facility, then all the load on the Utility shall be a New "Large
Single Load unless Bonneville, after consultation with the Utility
and the consumer, determines that uncontrollable events prevent
service to the consumer's load by such resource.
(e) Normalization of Consumer's Load. For the sole purpose of
computing the increase in energy consumption between any two
consecutive 1P -month periods of comparison under this exhibit,
reductions in the consumer's load associated with a facility during
the first 12 -month period of comparison due to unusual events
reasonably beyond the control of the consumer shall be determined,
and the energy consumption shall be computed as if such reductions
had not occurred.
(f) Changes in Load. If an increase in load becomes a New Large Single
Load, such increase shall, subject to the last paragraph of this
subsection, remain a New Large Single Load and all subsequent
increases in such load or portion thereof shall also be considered
a New Large Single Load.
Load reductions to a consumer's load at a facility shall be on a
last on, first off basis. Any load reductions made by a consumer
at a facility shall first reduce that portion of the consumer's
load at that facility which has been identified as a New Large
Single Load.
If a consumer with a New Large Single Load physically and
permanently removes equipment which imposes a load at a facility
identified as a New Large Single Load the consumer's load may be
reclassified as no longer being a New Large Single Load if
Bonneville determines such equipment imposed a load equivalent to
the original increase in load at each facility which caused such
load to be classified as a New Large Single Load.
(g) Renewal, Relocation, and Transfer. The following events shall not
cause a goad to be considered a New Large Single Load, if such
event does not result in an increase in power requirements of a
consumer on the Utility of 10 average megawatts or more during any
consecutive 12 -month period: (1) renewal or replacement of a
contract between the Utility and the consumer if the capacity
specified in the new contract based on the original commitment or
contract does not exceed the capacity specified in the contract
being renewed or replaced; (2) relocation, replacement, or
renovation of a consumer's.facility within the Utility's service
area; and (3) transfer of a facility to a successor -in- interest
provided that the service or product associated with the facility
is essentially unchanged.
(WP- PCI- 0054c)
Exhibit F, Page 2 of 2