EXHIBIT 10.115
Contract No. DE-MS79-94BP93947
GENERAL TRANSMISSION AGREEMENT
entered into by the
UNITED STATES OF ANLERICA
DEPARTMENT OF ENERGY
acting by and through the
BONNEVILLE POWER ADMINISTRATION
and
PUGET SOUND POWER & LIGHT COMPANY
Index to Sections
_____________________________________________________________________________
Section Page
1. Term of Agreement............................................... 3
2. Termination of Prior Agreements................................. 4
3. Definitions and Explanation of Terms............................ 4
4. Exhibits: Interpretations...................................... 8
5. Transmission of Electric Power.................................. 9
6. Payment by the Company.......................................... 14
7. Power Scheduling................................................ 15
8. Reactive Power.................................................. 16
9. Revision of Exhibits............................................ 16
10. Addition or Deletion of Points of Integration and Points of
Delivery and Changes in Transmission Demands.................... 18
11. Special Provisions.............................................. 22
12. Miscellaneous................................................... 23
Exhibit A (Transmission Rate Schedules and General
Transmission Rate Schedule Provisions)........... 8
Exhibit B (General Wheeling Provisions [GWP Form 4R])........ 8
Exhibit C (Transmission Parameters).......................... 8
Exhibit D (Calculation of Losses)............................ 8
This GENERAL TRANSMISSION AGREEMENT (Agreement) is entered into as of
December 1, 1994, by the UNITED STATES OF AMERICA (Government), Department of
Energy, acting by and through the BONNEVILLE POWER ADMINISTRATION
(Bonneville), and PUGET SOUND POWER & LIGHT COMPANY (Company), a corporation
of the State of Washington. Each of Bonneville and the Company is sometimes
referred to in this Agreement as "Party"; both of Bonneville and the Company
are sometimes referred to in this Agreement as "Parties".
WITNESSETH:
WHEREAS Bonneville and the Company on August 27, 1982, entered into
Contract No. DE-MS79-81BP90426, as amended and replaced to the date hereof,
and
WHEREAS Bonneville and the Company have entered into Letter Agreement
No. DE-MS79-91BP93160 (Letter Agreement) which contemplates a new General
Transmission Agreement (IR Agreement) for integration of resources and for
certain other contractual arrangements, and Bonneville and the Company intend
this Agreement to be the IR Agreement contemplated by the Letter Agreement;
and
WHEREAS the Parties have entered into the following agreements for
transmission of Electric Power (collectively referred to herein as Prior
Agreements): Contract No. DE-MS79-88BP92292, providing transmission service
for the Company's share of the electric output of the Centralia Project;
Contract No. DE-MS79-81BP90169, providing transmission service for the
Company's share of the electric output of the Colstrip Thermal Generating
Plant; and Contract No. DE-MS79-92BP93741, providing transmission service for
a portion of the electric output of Montana Power Company's Colstrip # 4; and
WHEREAS Bonneville and the Company desire to terminate the Prior
Agreements and replace the Prior Agreements with this Agreement; and
WHEREAS Bonneville recognizes that the Company's Tono Transmission
Facilities have a design capacity of 400 MW, but due to parallel path and
other considerations, the Parties desire to transmit Electric Power pursuant
to the terms of this Agreement; and
WHEREAS the Company and The Washington Water Company (WWP) have
entered into an agreement pursuant to which WWP exchanges 197 MW of Electric
Power from the Centralia Project, located in Centralia, Washington, with the
Company for an equal amount of Electric Power from the Colstrip Thermal
Generating Plant, located in Colstrip, Montana, and the Company intends to
enter into an amendment or replacement of such exchange agreement with WWP;
and
WHEREAS Bonneville and the Company, concurrently with the
effectiveness of this Agreement, have entered into a Pacific Northwest (PNW)
AC Intertie Capacity Ownership Agreement, Contract No. DE-MS79-94BP94521
, (Capacity Ownership Agreement) which,
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among other things, provides for ownership by the Company of a portion of the
capability of Bonneville's PNWAC Intertie (as defined in the Capacity
Ownership Agreement); and
WHEREAS the Parties desire to provide in this Agreement for, among other
things, the transmission over the Federal Columbia River Transmission System,
to and from the Company's transmission system, of Electric Power scheduled
for transmission over the PNW AC Intertie pursuant to the Capacity Ownership
Agreement; and
WHEREAS Bonneville is authorized pursuant to law to dispose of Electric
Power generated at various Federal hydroelectric projects in the PNW 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 agree as follows:
1. TERM OF AGREEMENT
(a) This Agreement shall be effective at 2400 hours on the latest
of (1) the date of execution and delivery of this Agreement; (2)
the earliest date on which the Company may exercise its Capacity
Ownership Rights (as defined in the Capacity Ownership Agreement)
pursuant to the Capacity Ownership Agreement; and (3) the date by
which this Agreement has, with respect to the Company, been
approved, accepted for filing or otherwise permitted to become
effective by FERC; provided, that if FERC approves or accepts for
filing this Agreement, or otherwise permits this Agreement to
become effective with any change or new condition, this Agreement
shall not be or become effective unless both of the Parties have
agreed in writing, and until the date by which both of the Parties
have so agreed, to such change or new condition (such latest date,
the Effective Date). This Agreement shall continue in effect until
2400 hours on July 31, 2014; provided, however, that all
liabilities accrued under this Agreement shall be preserved until
satisfied.
(b) One (1) year prior to the expiration of this Agreement, Bonneville
shall offer to provide to the Company transmission services as
provided hereunder, on terms and conditions consistent with the
terms and conditions for such
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transmission services being offered at that time by Bonneville to
other Bonneville customers similarly situated.
(c) If the Total Transmission Demand is reduced to zero pursuant to the
terms and provisions of section 10(c), the Company may, subject to
satisfaction of all obligations accrued hereunder and completion
of all notice periods specified in section 10(c), terminate this
Agreement by written notice of such termination to Bonneville.
(d) The Company may terminate this Agreement or any Transmission Demand
under this Agreement upon 1-year's prior written notice of such
termination to Bonneville if Bonneville discontinues application
of cost-based rates for service provided under this Agreement.
2. TERMINATION OF PRIOR AGREEMENTS
(a) The Prior Agreements are hereby terminated as of 2400 hours on the
Effective Date but all liabilities accrued thereunder to the
Effective Date are hereby preserved until satisfied.
(b) Contract No. DE-MS79-91BP93053 (Intertie and Network Transmission
Agreement) shall terminate as of 2400 hours on the Effective Date
but all liabilities accrued thereunder to the Effective Date are
hereby preserved until satisfied; provided, that the penultimate
sentence of section 5(b) of such contract shall not be applicable
for seasons during which such contract terminates pursuant to this
Agreement.
3. DEFINITIONS AIND EXPLANATION OF TERMS
(a) "Connecting Transmission" means, with respect to a Resource
integrated at a Point of Integration, transmission service or
facilities needed or used for transmission of such Resource to
such Point of Integration for transmission under this Agreement.
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(b) "DC Intertie" means Bonneville's rights in the 1000 kV direct
current (DC) transmission line, and associated substation
facilities, extending from the Government's Big Eddy Substation to
the Nevada-Oregon Border.
(c) "Eastern Intertie" means the transmission facilities
consisting of the Townsend-Garrison double-circuit 500 kV
transmission line segment, including related terminals at the
Garrison Substation.
(d) "Electric Power" or "Power" means electric peaking capacity,
expressed in kilowatts, or electric energy, expressed in
kilowatthours, or both.
(e) "FCRTS" or "Federal Columbia River Transmission System" means the
transmission facilities of the Federal Columbia River Power System,
which include all transmission facilities owned by the Government
and operated by Bonneville, and other facilities over which
Bonneville has obtained transmission rights.
(f) "FERC" means the Federal Energy Regulatory Commission or its
regulatory successors.
(g) "Montana Intertie Agreement" means Contract No. DE-MS79-8IBP90210
between Bonneville and the Company, as amended.
(h) "Operational Constraints" means limitations on the ability of the
FCRTS to operate due to any system emergency, loading condition,
or maintenance outage with respect to Bonneville facilities, or
the facilities of an interconnected utility, that make it prudent
to reduce system loadings consistent with Prudent Utility
Practice, whether or not all facilities are in service.
(i) "PNW AC Intertie has the meaning set forth in the Capacity
Ownership Agreement.
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(j) "Point of Delivery" means:
(1) any of the points set forth in Exhibit C, Part B, where
Electric Power shall be made available to the Company pursuant
to this Agreement; and
(2) any other point mutually agreed upon by the Parties where
Electric Power shall be made available to the Company pursuant
to this Agreement.
(k) "Point of Integration" means:
(1) any of the points set forth in Exhibit C, Part A, where
Electric Power from Resources shall be integrated into the
FCRTS pursuant to this Agreement; and
(2) any other point mutually agreed upon by the Parties where
Electric Power from Resources may be made available to
Bonneville for nonfirm transmission to any of the Points of
Delivery pursuant to this Agreement.
(l) "Prudent Utility Practice" means, at any particular time, the
generally accepted practices, methods, and acts in the electrical
utility industry in the Western Systems Coordinating Council area
immediately prior to such time that would achieve the desired
result or, if there are no such practices, methods, and acts, then
the practices, methods and acts which, in the exercise of
reasonable judgment in the light of facts known at the time the
decision was made, could have been expected to accomplish the
desired result consistent with reliability and safety.
(m) "Resource" means:
(1) any Electric Power from a source set forth in Exhibit C, Part
A; and
(2) any Electric Power transmitted over the PNW AC Intertie
pursuant to the Capacity Ownership Agreement and made
available to Bonneville
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at the John Day Substation Point of Integration. Upon request
by Bonneville, the Company shall identify the source of such
Electric Power; provided, however, that if such Electric Power
can only be identified as a system sale, then the Company
shall be obligated pursuant to this section 3(m)(2) to
identify only the utility generating such Electric Power; and
(3) any Electric Power (i) which the Company has a right to
receive, and (ii) for which nonfirm transmission service is
requested by the Company on the FCRTS, and (iii) the Electric
Power from which is made available to Bonneville at one or
more of the Points of Integration; and
(4) any other Electric Power for which nonfirm transmission
service is requested by the Company for the purpose of
providing station service to any of the Company's sources of
Electric Power interconnected with the FCRTS, and which
Electric Power is made available to Bonneville at any of the
Points of Integration.
(n) "Total Power Wheeled" means with respect to any hour the sum of the
Electric Power made available to Bonneville during such hour for
transmission on the FCRTS pursuant to this Agreement, including but
not limited to section 7, at all Points of Integration.
(o) "Total Transmission Demand" means the sum of the Company's
Transmission Demands.
(p) "Transmission Demand" with respect to any Point of Integration,
means the maximum firm transmission capacity (expressed in
kilowatts) as set forth in Exhibit C, Part A, which Bonneville
shall be obligated pursuant to this Agreement to have available at
such Point of Integration during any hour for the purpose of
integrating into the FCRTS any Resource. The level of each
Transmission Demand, with respect to each Point of Integration set
forth in Exhibit C, Part A, (except for the John Day Substation
Point of Integration). shall be based on the hourly peak capability
of the source(s) of Electric Power
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listed in Exhibit C, Part A, to be integrated into the FCRTS at
such Point of Integration.
(q) "Use-of-Facilities Charge" means the charges, if any, specified in
Exhibit C, applicable to Points of Integration and Points of
Delivery for the purpose of recovering the cost of identifiable
facilities provided by Bonneville for the Company's use. Such
charges and their application shall be consistent with the Use-of-
Facilities Transmission Rate Schedule, contained in Exhibit A, and
shall, subject to section 9(c), also be consistent with
Bonneville's Customer Service Policy.
(r) "Use Limit" means with respect to any Point of Delivery the amounts
(in kilowatts) set forth in Exhibit C, Part B, corresponding to
such Point of Delivery.
(s) "Northern Intertie" means that segment of the FCRTS assigned by
Bonneville for Bonneville transfer capability at the United States-
Canada border.
(t) "Workday" means any day which both of the Parties observe as a
regular workday.
4. EXHIBITS; INTERPRETATIONS
Exhibits A, B, C, and D (Exhibits) attached hereto are by this reference
incorporated into and made a part of this Agreement. The Parties agree
that "contract body" as used in section 1 of Exhibit B shall mean
sections 1 through 12 of this Agreement. The provisions of section 38 of
the General Wheeling Provisions (GWP Form-4R), require that Bonneville
provide a notice consistent with a minimum notice period prior to a Rate
Adjustment Date (as defined in Exhibit B). If the rates set forth in or
applicable to this Agreement are disapproved or if conditions are placed
on such rates by FERC, Bonneville shall not be required to give such
notice prior to resubmitting the rates to FERC or implementing FERC
approved rates. The headings used in this Agreement are for convenient
reference only, and shall not affect the interpretation of this
Agreement. The Company shall be deemed to be the "Transferee" and
Bonneville shall be deemed to be the "Transferor" referred to in the
General Wheeling Provisions, Exhibit B.
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5. TRANSMISSION OF ELECTRIC POWER
(a) Bonneville shall, during each hour of the term of this Agreement,
make an amount of Electric Power equal to the Total Power Wheeled
available to the Company at one or more of the Points of Delivery,
subject to sections 5(a)(1) through 5(a)(5) below. In the event
that service hereunder must be curtailed due to Operational
Constraints, Bonneville obligation to mitigate the effects of such
curtailment are set forth in section 5(e) below and in section 12
of Exhibit B, (except to the extent that such section 12 conflicts
with sections 1 through 12 of this Agreement), and in footnote 3
of Exhibit C, Part A, and Bonneville shall have no other
obligation to mitigate the effects of such curtailment pursuant to
this Agreement.
(1) Bonneville may, but shall not be obligated to, integrate into
the FCRTS during any hour amounts of Electric Power to the
extent that such amounts exceed the Total Transmission
Demand.
(2) Firm transmission capability of the FCRTS between the
Company's system and John Day Substation shall,
notwithstanding any Operational Constraints or any other
constraint on the ability of the FCRTS to operate, be deemed
to exist during any hour (i) for north-to-south transmission,
in an amount equal to the Company's Total Transmission Demand,
and (ii) for south-to-north transmission, in an amount equal
to the Company's Transmission Demand for the John Day
Substation Point of Integration. The net of the Company's
schedules in a north-to-south direction and in a south-to-nor-
north direction during any hour shall be used to determine
use of such transmission. The Company shall be billed for
transmission of Electric Power for such hour pursuant to the
provisions of section 6.
(3) Bonneville may, but shall not be obligated to, integrate at a
Point of Integration during any hour, amounts of Electric
Power to the extent that such amounts exceed the Transmission
Demand at such Point of Integration.
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(4) Bonneville may, but shall not be obligated to, integrate
Electric Power other than Resources set forth in Exhibit C,
Part A, provided that the Points of Integration for such
Electric Power have been mutually agreed upon by the Parties
pursuant to this Agreement.
(5) Notwithstanding anything to the contrary set forth in this
Agreement, Bonneville shall not withhold its agreement (A) to
any point proposed by the Company as a Point of Integration
pursuant to section 3(k)(2) or to any amount of Electric Power
proposed by the Company to be integrated at such point or (B)
to integrate at any Point of Integration set forth in Exhibit
C, Part A, amounts of Electric Power in excess of the
Transmission Demand with respect to such Point of Integration,
except to the extent that (i) capacity of the facilities
located at such point or at such Point of Integration, as the
case may be, is not available due to Operational Constraints,
or (ii) Bonneville requires the use of such capacity, or any
portion thereof, for purposes of transmitting Bonneville
nonfirm power; provided however, that capacity at such point
or at such Point of Integration, as the case may be, not
required by Bonneville for transmission of Bonneville's
nonfirm power shall be made available to the Company in an
amount equal to the product of (x) the ratio of (i) the amount
of Electric Power requested by the Company to be transmitted
on a nonfirm basis at such point or such Point of Integration,
as the case may be, to (ii) the total amount of Electric Power
requested by entities other than Bonneville to be transmitted
on a nonfirm basis at such point or such Point of Integration,
as the case may be, and (y) the amount of capacity at such
point or such Point of Integration, as the case may be, not
required by Bonneville for transmission of Bonneville's
nonfirm power. Nothing in this section 5(a)(5) is intended by
the Parties to constrain Bonneville from engaging in design of
a successor to the Energy Transmission Rate.
(b) The Parties' respective rights and obligations with respect to
Bonneville's PNW AC Intertie are set forth in the Capacity
Ownership Agreement. Nothing in this Agreement, including, without
limitation, delivery by Bonneville of Power at the John Day
Substation Point of Delivery, or
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integration of Power into the FCRTS at the John Day Substation
Point of Integration is intended by the Parties to limit, alter,
add to or otherwise affect the respective rights and obligations of
the Parties pursuant to the Capacity Ownership Agreement. Nothing
in this Agreement, including, without limitation, delivery by
Bonneville of Power at the Big Eddy Point of Delivery, is intended
by the Parties to provide rights to use the DC Intertie. Nothing
in this Agreement is intended by the Parties to limit, alter, add
to or otherwise affect the respective rights and obligations of the
Parties pursuant to the Montana Intertie Agreement.
(c) If the Company determines that it has an amount of Electric Power
available during any hour for nonfirm transmission on the FCRTS,
the scheduling and transmission of which would cause the Total
Power Wheeled to exceed in such hour the Total Transmission Demand,
the Company may request from Bonneville nonfirm transmission
service for transmission on the FCRTS for such amount of Electric
Power during such hour. Bonneville may provide such transmission
service. The Company shall be billed for such transmission service
pursuant to the provisions of section 6(d).
(1) The option pursuant to this section 5(c) to make available
Electric Power for nonfirm transmission on the FCRTS by
Bonneville shall not be used by the Company to avoid having a
Total Transmission Demand which reasonably reflects the
annual peak transmission needs of all of the sources of
Electric Power set forth in Exhibit C, Part A, and the
combined total annual peak demand for wheeling with respect to
all of such sources of Electric Power which the Company
regularly places on Bonneville. Bonneville shall have the
right to refuse to provide the Company transmission service on
a nonfirm basis to the extent Bonneville determines consistent
with this section 5(c)(1), that the Transmission Demand at a
Point of Integration should be increased.
(2) To the extent Bonneville wheels, pursuant to this Agreement,
any Electric Power of the Company's on the FCRTS in connection
with a transaction which is exempt from wheeling charges or
loss assessment
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at the time of actual transmission of such Electric Power,
(such as any qualifying transaction under the Coordination
Agreement (Contract No 14-03-48221)), and which is
subsequently converted to a sale other than under the terms of
the Coordination Agreement, to an entity other than
Bonneville, Bonneville shall have the right to retroactively
(to the date of such conversion) bill the Company for such
wheeling as nonfirm transmission service pursuant to
Bonneville's Energy Transmission (ET-93) Rate Schedule in
effect at the time such Electric Power was wheeled, or its
successor rate schedule, and the provisions of section 6(d),
and to assess losses consistent with this Agreement with
respect to any Electric Power so wheeled in connection with
such transaction unless billing or losses for such subsequent
conversion is otherwise provided for under another agreement
to which Bonneville is a Party. Such qualifying transactions
shall not be subject to sections 5(c)(1) above and 5(c)(3)
below.
(3) Except for any Electric Power made available by the Company
for nonfirm transmission pursuant to this section 5(c),
amounts of Electric Power wheeled hereunder from a Point of
Integration which exceed the Transmission Demand at such Point
of Integration shall be subject to billing as a Ratchet Demand
in accordance with section 6(b). To the extent the Energy
Transmission Rate Schedule (ET-93), or its successor rate
schedule, is applied, a Ratchet Demand shall not be applied.
(d) To compensate Bonneville for losses incurred in providing
transmission services pursuant to this Agreement, the Company shall
make available to Bonneville at one or more Points of Delivery
(unless otherwise mutually agreed between the Parties), on the
corresponding hour 168 hours later or on another hour mutually
agreed upon by the Parties, an amount of Electric Power equal to
the product of (1) the amount of Electric Power (expressed in
megawatthours) for which transmission service is provided to the
Company during a given hour pursuant to sections 5(a) and 5(c), and
(2) the appropriate loss factor set forth in Exhibit D.
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(e) Bonneville shall, if requested by the Company to do so and if it
is within Bonneville's capability to do so without adversely
affecting performance of its other obligations, make replacement
Electric Power available to the Company hereunder, without
additional cost to the Company except as provided in this section
5(e), if Electric Power cannot be made available by the Company to
Bonneville pursuant to this Agreement solely because of (i)
limitations on the ability of the FCRTS to operate due to any
system emergency, loading condition, or maintenance outage with
respect to Bonneville facilities that makes it prudent to reduce
system loadings consistent with Prudent Utility Practice, whether
or not all facilities are in service; or (ii) suspension or
interruption of, or interference with, the operation of the FCRTS;
or (iii) both. The Company shall, at Bonneville's option:
(1) reimburse Bonneville for any cost or loss of revenue incurred
by Bonneville in making such replacement Electric Power
available;
(2) replace all or a portion of such replacement Electric Power
with the Company's Electric Power at a time and place agreed
upon by the Parties prior to delivery; or
(3) reimburse and replace pursuant to sections 5(e)(1) and 5(e)(2)
above in amounts determined by Bonneville which in total are
equivalent in value to (A) the cost or loss of revenue
incurred by Bonneville in making replacement Electric Power
available to the Company pursuant to this section 5(e) or (B)
the Electric Power made available by Bonneville pursuant to
this section 5(e).
The method to replace or reimburse shall be specified by Bonneville
at the time of the Company's request for replacement Electric
Power. The Company shall have the right to withdraw such request
for replacement Electric Power, prior to delivery thereof and prior
to Bonneville's incurring any cost therefor, after Bonneville
specifies the method to replace and/or the amount to reimburse
pursuant to this section 5(e).
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(f) The Company shall not use its rights under this Agreement to
provide wheeling to another entity if such wheeling is inconsistent
with the Company's rights in the PNW AC Intertie Capacity Ownership
Agreement, Contract No. DE-MS79-94BP94521.
(g) Bonneville shall give the Company notice of any likely or actual
occurrence or existence of (i) any Operational Constraint and (ii)
any suspension or interruption of, or interference with, the
operation of the FCRTS, to the extent that the same affects the
provision of service by Bonneville with respect to any Point of
Integration or Point of Delivery pursuant to this Agreement. Such
notice shall be given as promptly as practicable by Bonneville.
6. PAYMENT BY THE COMPANY
As full compensation for services provided under sections 5(a) and 5(c),
the Company shall pay Bonneville each month during the term hereof,
amounts determined in accordance with Exhibit A and Exhibit C, and as
follows:
(a) For integration of Electric Power pursuant to section 5(a), the
Company shall, subject to sections 5(b), 5(c), and 5(d), pay
Bonneville in accordance with the Integration of Resources
Transmission Rate Schedule (IR-93), or its successor rate schedule,
and, to the extent expressly provided in other provisions of this
Agreement, in accordance with the Use-of-Facilities Rate Schedule
(UFT-83), or its successor rate schedule; provided, that for the
purposes of this Agreement, the term "scheduled" as used in Section
III.B. of the Integration of Resources Transmission Rate Schedule
(IR-93), or its successor rate schedule, shall mean or refer to any
submission (or arrangement for submission) by the Company of any
schedule or retroactive report pursuant to section 7 of this
Agreement.
(b) The billing demand shall be determined in accordance with the
Integration of Resources (IR-93) Transmission Rate Schedule, or its
successor rate schedule. Any Ratchet Demand that may occur is for
billing purposes only and does not constitute an increase in any
Transmission Demand pursuant to section 10. Any continued service
with respect to any Point of Integration pursuant to this Agreement
at a level, to the extent that such level exceeds the
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Transmission Demand with respect to such Point of Integration, will
depend on the availability of facilities for such purpose as
reasonably determined by Bonneville.
(c) The billing energy for each month pursuant to the Integration of
Resources Transmission Rate Schedule (IR-93), or its successor rate
schedule, and the Energy Transmission Rate Schedule (ET-93), or its
successor rate schedule, shall be the sum of the greater of the
hourly amounts of (A) kilowatthours scheduled from the Points of
Integration to the Company's transmission system over Bonneville's
transmission system hereunder, or (B) kilowatthours scheduled over
Bonneville's transmission system hereunder from the Company's
transmission system to the John Day Point of Delivery and the Big
Eddy Point of Delivery.
(d) The Company shall be billed for transmission of Electric Power up
to an amount equal to the Total Transmission Demand pursuant to the
Integration of Resources Transmission Rate Schedule (IR-93), or its
successor rate schedule. To the extent the Total Transmission
Demand is exceeded, the Company shall be billed for nonfirm
transmission of Electric Power pursuant to the Energy Transmission
Rate Schedule (ET-93), or its successor rate schedule. For
transmission pursuant to section 5(c)(2), the Company shall be
billed in accordance with the Energy Transmission (ET-93) Rate
Schedule, or its successor rate schedule.
7. POWER SCHEDULING
The Company shall submit or arrange to have submitted to Bonneville by
1000 hours (Pacific Time) (or any other hour agreed upon by the Parties)
of each Workday:
(a) for the Resource referred to in section 3(m)(1), a retroactive
report of the Electric Power made available to Bonneville for
integration into the FCRTS during each hour of the immediately
preceding Workday and of the days other than a Workday (if any)
succeeding such immediately preceding Workday;
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(b) for the Resources referred to in sections 3(m)(2), 3(m)(3) and
3(m)(4), a separate schedule of the Electric Power to be made
available to Bonneville for integration into the FCRTS during each
hour of the next succeeding Workday and of the days other than a
Workday (if any) immediately preceding such next succeeding
Workday; and
(c) a separate schedule of the Electric Power to be made available to
Bonneville for losses pursuant to section 5(d) during each hour of
the next succeeding Workday and of the days other than a Workday
(if any) immediately preceding such next succeeding Workday.
8. REACTIVE POWER
It is the intent of the Parties hereto that the voltage level at the
Points of Integration and the Points of Delivery be controlled in
accordance with Prudent Utility Practice. The Parties hereto shall
jointly plan and operate their systems so as not to place an undue
burden on the other Party to supply or absorb reactive power
accompanying or resulting from deliveries of Electric Power hereunder.
9. REVISION OF EXHIBITS
(a) The rate schedules included in Exhibit A shall be replaced by
successor rate schedules adopted in accordance with the provisions
of section 7(i) of the Pacific Northwest Power Act and FERC rules.
(b) Bonneville may review Exhibit D and, no more frequently than once
in a 12-month period commencing on the anniversary of the Effective
Date, may revise such Exhibit to reflect any change in condition
that would substantially affect the loss factor set forth in
Exhibit D; provided, however, that any change to the loss factor
pursuant to this Agreement
(1) shall be prospective only;
(2) shall be made in an equitable manner so as to be consistent
with such change in condition;
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(3) shall incorporate values which represent then current FCRTS
operating conditions or incorporate any value, used in Exhibit
D to calculate the losses, which has changed due to a change
in methodology; and
(4) shall in no event result in a loss factor that is greater than
the loss factor which Bonneville is then applying with respect
to any of its other customers for firm transmission under an
Integration of Resources Transmission Agreement.
Any changes to Bonneville's loss methodology or formula, other than
numerical values, shall be made only after consultation with the
Company. During such consultation, Bonneville shall provide to the
Company material used by Bonneville as a basis for such changes to such
loss methodology or formula. Exhibit D as revised pursuant to this
section 9(b) shall become effective as of the date specified therein;
provided, however, that in no event shall such revised Exhibit D be
effective sooner than the date on which the Company is notified by
Bonneville in writing of such revision to Exhibit D.
(c) No Use-of-Facilities Charges or any rates or charges other than
charges pursuant to the Integration of Resources Transmission Rate
Schedule (IR-93), or its successor rate schedule, or the Energy
Transmission Rate Schedule (ET-93), or its successor rate schedule,
shall be assessed pursuant to this Agreement for delivery from the
C.W. Paul Substation, Garrison Substation, or John Day Substation
Point of Integration to the Points of Delivery specified in Exhibit
C, Part D, on the Effective Date, at levels of service specified in
Exhibit C on the Effective Date, except if and to the extent that
the Parties mutually agree that conditions have changed and that
such charge is appropriate as a result of such change.
(d) In the event Bonneville proposes any wheeling rate for transmission
service on Bonneville's main grid that includes costs of the PNW AC
Intertie, the Eastern Intertie, the DC Intertie, or the Northern
Intertie, such proposed rate shall include a credit or other
mechanism that ensures that the Company is not charged any of the
PNW AC Intertie, the Eastern Intertie, the DC Intertie, or the
Northern Intertie costs for deliveries of power that
17
utilize up to the capacity share of each such intertie, if any, to
which the Company is entitled pursuant to other agreements with
Bonneville.
10. ADDITION OR DELETION OF POINTS OF INTEGRATION AND POINTS OF DELIVERY AND
CHANGES IN TRANSMISSION DEMANDS
(a) Except as otherwise provided in section 10(b), Points of
Integration and Points of Delivery shall be added and Transmission
Demands shall be increased, subject to mutual agreement of the
Parties, which agreement shall not be unreasonably withheld or
delayed, and to Bonneville's determination of available
transmission capacity, upon 3-months' prior written notice by the
Company to Bonneville of such addition or increase; provided, that
Points of Integration and Points of Delivery may not be added, and
Transmission Demands may not be increased, more frequently than
once during any 12-month period commencing on the anniversary of
the Effective Date.
(b) Transmission Demand associated with the John Day Substation Point
of Integration may be increased upon prior written notice from the
Company to Bonneville, to the extent that Bonneville has capacity
in excess of its needs and obligations at such time, in an amount
equal to an increase in the megawatt amount of the Company's
Capacity Ownership Rights under the PNW AC Intertie Capacity
Ownership Agreement in a south-to-north direction.
(c) Points of Integration and Points of Delivery may be deleted and
Transmission Demands may be reduced only upon the written request
of the Company and, upon such request, only in accordance with the
provisions of sections 10(c)(1) through 10(c)(5).
(1) Except as otherwise provided in this section 10(c),
Transmission Demands with respect to any individual Point of
Integration may be reduced once (but no more frequently than
once) in any 12-month period commencing on the anniversary of
the Effective Date for any Point of Integration, it being
understood that any such reduction shall be subject to section
10(c)(4) and shall be permitted pursuant to this Agreement
only:
18
(A) to the extent that the Company's right to receive any
Resource set forth in Exhibit C, Part A, as being
integrated at such Point of Integration (or right to
Connecting Transmission for such Resource) is reduced or
is eliminated or expires; or
(B) to the extent that the Company sells or assigns all or a
portion of its share of a Resource integrated at such
Point of Integration (or sells or assigns all or a
portion of the Company's right to Connecting Transmission
for such Resource); or
(C) to the extent of a permanent partial or total reduction
in the Company's entitlement to a share of a Resource
integrated at such Point of Integration (or partial or
total reduction of the Company's right to Connecting
Transmission for such Resource); or
(D) to the extent of any loss, destruction, abandonment, or
sale of any of the facilities generating or transmitting
a Resource integrated at such Point of Integration (or
loss, destruction, abandonment, or sale of the Connecting
Transmission for such Resource); or
(E) to the extent of the discontinuation of operation of any
of the facilities generating or transmitting a Resource
integrated at such Point of Integration (or
discontinuation of the Connecting Transmission for such
Resource) pursuant to a final order of a public official
having authority to issue such order; or
(F) with respect to the Garrison Substation Point of
Integration, to the extent of the expiration of the
Montana Intertie Agreement, including extensions thereof.
(2) A Point of Integration may be deleted, upon 3-months' prior
written notice by the Company of such deletion to Bonneville,
but only after the Transmission Demand with respect to such
Point of Integration has been reduced to zero pursuant to
sections 10(c)(1) and 10(c)(5).
19
(3) A Point of Delivery may be deleted, subject to mutual
agreement of the Parties and to section 10(c)(4), upon 3-
months' prior written notice by the Company of such deletion
to Bonneville.
(4) If, and to the extent that, any Use-of-Facilities charges are
added to this Agreement pursuant to section 9(c), the terms
and conditions related to such Use-of-Facilities charges shall
be subject to the mutual written agreement of the Parties
prior to the addition of such charges.
(5) The Company shall provide Bonneville no less than 3-
years' written notice of any decrease in a Transmission
Demand, except as follows:
(A) The Company shall provide no less than 3-months' written
notice of a decrease in Transmission Demand if there is
an equal increase in Transmission Demand by another
customer of Bonneville at the same Point of Integration
resulting from the sale or assignment of a Resource, or
of the facilities generating or transmitting a Resource,
and involving no loss of revenue to Bonneville; or
(B) The Company shall provide written notice as soon as
practicable, which would be effective on the later of the
date such notice is received by Bonneville or the date
stated in such notice, if such decrease in Transmission
Demand is due to any loss, destruction, or abandonment of
any of the facilities generating or transmitting a
Resource, or discontinuation of operation of a Resource
under a final order of a public official having authority
to issue such order, or if the Company's right to receive
Electric Power is reduced or eliminated according to the
terms of an agreement between the Company and another
entity for such Electric Power.
(6) Notwithstanding anything in this Agreement to the contrary, if
the megawatt amount of the capability of the PNW AC Intertie
to which the Company is entitled pursuant to the Capacity
Ownership Agreement is at any time reduced, Transmission
Demand with respect
20
to the John Day Substation Point of Integration shall be
concurrently reduced by a megawatt amount equal to such
reduction with respect to the PNW AC Intertie upon prior
written notice of such reduction by the Company to Bonneville.
(d) Projected Company loads at each Point of Delivery shall be
prepared, projected for 10 years, and forwarded to Bonneville by
October 1, of each year. If, based on long-range power flow studies
and actual system loadings, such projected loads are expected to
exceed the Use Limits with respect to such Point of Delivery within
the projected years, within a reasonable planning horizon for the
facilities involved, the Company and Bonneville shall enter into
joint discussions to:
(1) discuss how the Company plans to modify the load on Bonneville
at such Point of Delivery to stay within the Use Limit;
(2) discuss the Company's plan for facility additions, revisions,
or upgrades, which will increase capacity at such Point of
Delivery;
(3) discuss Bonneville's plan for facility additions, revisions,
or upgrades, which will increase capacity at such Point of
Delivery; or
(4) discuss the extent to which the capacity of facilities with
respect to such Point of Delivery would be available so as to
increase the Use Limit with respect to such Point of Delivery.
Prior to the implementation of any facility addition, revision or
upgrade that increases capacity at a Point of Delivery as
contemplated by this section 10(d), the Parties shall negotiate the
allocation of costs for such facility addition, revision or
upgrade, and the allocation of any increase in capacity at such
Point of Delivery, each such allocation to be pursuant to then-
existing FERC policies applicable to Bonneville and the Company,
respectively, as such policies apply to cost and capacity
allocations, and also subject to any other applicable statutory and
regulatory requirements. The Company shall be assessed costs for
studies conducted by Bonneville in connection with this section
10(d) consistent with the manner in which
21
Bonneville assesses study costs to other Bonneville customers who
receive transmission service pursuant to the Integration of
Resources (IR) Transmission Rate Schedule, or its successor rate
schedule; provided that, in any event, the costs of any such study
conducted by Bonneville in connection with this section 10(d) shall
be equitably allocated among the Company, Bonneville and
Bonneville's other customers based upon the respective system
benefits derived by such parties as a result of such facility
addition, revision or upgrade.
To the extent that other entities may receive system benefits from
such facility addition, revision or upgrade, Bonneville shall
invite such entities to participate in discussions with respect to
cost allocation and system benefits referred to in this section
10(d).
(e) When changes are made pursuant to this section, Bonneville shall
incorporate such changes in a new Exhibit C as soon as practicable.
11. SPECIAL PROVISIONS
(a) In recognition of the Company's existing agreement with Seattle
City Light (Seattle) to wheel Electric Power from the Centralia
Project, and notwithstanding anything in this Agreement to the
contrary, the Company may reduce the Transmission Demand with
respect to the C.W. Paul Substation Point of Integration no more
frequently than once in any 12-month period commencing on the
anniversary of the Effective Date to the extent of any reduction in
the amount of Electric Power that the Company is obligated pursuant
to such agreement to wheel from the Centralia Project to Seattle.
The Company shall provide 3-months' written notice to Bonneville of
any decrease in such Transmission Demand pursuant to this
subsection.
(b) If the Company contracts hereafter with another entity, including
Seattle, to transmit Electric Power over the Company's Tono
Transmission facilities the Transmission Demand with respect to the
C.W. Paul Point of Integration shall be increased in an amount
equal to the amount transmitted by the Company for such other
entity.
22
12. MISCELLANEOUS
(a) Any notice, demand, request or other communication
provided for in this Agreement, or served, given or made in
connection with this Agreement, shall be given in writing (unless
otherwise provided in this Agreement) and shall be deemed to be
served, given or made upon receipt if delivered in person or sent
by acknowledged delivery, or sent by registered or certified mail,
postage prepaid, to the persons addressed as set forth below:
If to Bonneville:
The Bonneville Power Administration
905 N.E. llth Avenue
Portland, Oregon 97232
Attention: Group Vice President for Marketing, Conservation
and Production
If to Puget:
Puget Sound Power & Light Company
411 108th Avenue N.E.
15th Floor
Bellevue, Washington 98005-5515
Attention: Vice President Power Planning
Either Party may change the address set forth above by giving the
other Party written notice of such change in accordance with this
section 12(a).
(b) Except as may be expressly otherwise provided in this Agreement,
this Agreement may be amended or modified only by a written
agreement hereafter entered into by Bonneville and Puget, and no
provision of this Agreement shall be varied or contradicted by any
oral agreement, any course of dealing or performance or any other
matter not hereafter set forth in a written agreement signed by
both of the Parties.
(c) The invalidity or unenforceability of any provision of this
Agreement shall not affect the other provisions hereof, and this
Agreement shall be construed in all respects as if such invalid or
unenforceable provision were omitted.
23
(d) Nothing contained in this Agreement shall be construed to create an
agency, association, joint venture, trust or partnership covenant,
obligation or liability on or with regard to either of the Parties.
Each Party shall be individually responsible for its own covenants,
obligations and liabilities under this Agreement. All rights and
obligations of the Parties are several, not joint. No Party shall
be deemed to control, to be under the control of, or to be the
agent of, the other Party.
(e) Nothing contained in this Agreement shall grant any rights to, or
obligate either Party to provide, any services hereunder directly
to or for retail customers of the other Party.
(f) There are no third-party beneficiaries of this Agreement. This
Agreement shall not be construed to create rights in, or grant
remedies to, any third party as a beneficiary of this Agreement or
of any duty, obligation or undertaking established herein.
(g) Whenever it is provided in this Agreement that either Party shall
determine or make a determination or judgment, or that any action,
determination or judgment shall be in such Party's determination or
judgment, the exercise of such determination or judgment shall be
made solely by such Party and shall be final and not subject to
challenge, so long as such Party exercises its
24
determination or judgment (a) in good faith and not arbitrarily or
capriciously, and (b) consistent with Prudent Utility Practice.
IN WITNESS WHEREOF, the Parties hereto have executed this Agreeemnt in
several counterparts.
UNITED STATES OF AMERICA
Department of Energy
Bonneville Power Administration
By Patrick McRae
------------------------
Senior Account Executive
Name Patrick McRae
------------------------
Date 12/1/94
------------------------
PUGET SOUND POWER & LIGHT COMPANY
By J. R. Lauckhart
-----------------------
Name J. R. Lauckhart
-----------------------
Title V. P. Power Planning
-----------------------
Date 12/1/94
-----------------------
25
EXHIBIT 10.115
Exhibit A
1993
TRANSMISSION RATE SCHEDULES AND
. . GENERAL TRANSMISSION RATE SCHEDULE PROVISIONS
TRANSMISSION RATE SCHEDULES AND GENERAL TRANSMISSION RATE
SCHEDULE PROVISIONS
TABLE OF CONTENTS
Transmission Rate Schedules Page
FPT-93.1 Formula Power Transmission................................1
FPT-91.3 Formula Power Transmission................................3
IR-93 Integration of Resources..................................5
IS-93 Southern Intertie Transmission............................6
IN-93 Northern Intertie Transmission............................7
IE-93 Eastern Intertie Transmission.............................8
ET-93 Energy Transmission.......................................9
MT-91 Market Transmission......................................10
UFT-83 Use-of-Facilides Transmission............................11
TGT-1 Townsend-Garrison Transmission...........................12
AC-93 Southern Intertie Annual Cost............................14
General Transmission Rate Schedule Provisions
Section I Adoption of Revised Transmission Rate Schedules and
General Transmission Rate Schedule Provisions............16
Section II Billing Factor Definitions and Billing Adjustments.......16
Section III Other Definitions........................................17
Section IV Billing Information......................................19
Schedule FPT-93.1
Formula Power Transmission
SECTION l. AVAILABILITY
This schedule supersedes schedule FPT-91.1 for all firm transmission
agreements which provide that rates may be adjusted not more frequently than
once a year. It is available for firm transmission of electric power and
energy using the Main Grid and/or Secondary System of the Federal Columbia
River Transmission System (FCRTS). This schedule is for full-year and
partial-year service and for either continuous or intermittent service when
firm availability of service is required. For facilities at voltages lower
than the Secondary System, a different rate schedule may be specified.
Service under this schedule is subject to BPA's General Transmission Rate
Schedule Provisions (GTRSPs).
SECTION 11. RATES
A. Full-Year Service
The monthly charge per kilowatt of billing demand shall be one-twelfth of
the sum of the Main Grid Charge and the Secondary System Charge, as
applicable and as specified in the Agreement.
1. Main Grid Charge
The Main Grid Charge per kilowatt of billing demand shall be the sum
of one or more of the following component factors as specified in the
Agreement:
a. Main Grid Distance Factor: amount computed by multiplying the
Main Grid Distance by $0.0371 per mile.
b. MainGrid Interconnection Terminal Factor: $0.27
c. Main Grid Terminal Factor: $0.44
d. Main Grid Miscellaneous Facilities Factor: $1.88
2. Secondary System Charge
The Secondary System Charge per kilowatt of billing demand shall the
the sum of one or more of the following component factors as
specified in the Agreement:
a. Secondary System Distance Factor: The amount determined by
multiplying the Secondary System Distance by $0.2784 per mile
b. Secondary System Transformation Factor: $4.10
c. Secondary System Intermediate Terminal Factor: $1.29
d. Secondary System Interconnection Terminal Factor: $0.68
B. Partial-Year Service
The monthly charge per kilowatt of billing demand shall be as specified
in Section II.A. for all months of the year except for agreements with
terms 5 years or less and which specify service for fewer than 12 months
per year. The monthly charge shall be:
1. During months for which service is specified, the monthly charge
defined in Section II.A., and
2. During other months, the monthly charge defined in Section II.A.
multiplied by 0.2.
SECTION III. BILLING FACTORS
Unless otherwise stated in the Agreement, the billing demand shall be the
largest of:
A. The Transmission Demand;
B. The highest hourly Scheduled Demand for the month; or
C. The Ratchet Demand
Schedule FPT-91.3
Formula Power Transmission
SECTION 1 AVAILABILITY
This schedule continues schedule FPT-91.3 for all firm transmission
agreements which provide that rates may he adjusted not more frequently than
once every 3 years. It is available for firm transmission of electric power
and energy using the Main Grid and/or Secondary System of the Federal
Columbia River Transmission System. This schedule is for full-year and
partial-year service and for either continuous or intermittent service when
firm availability of service is required. For facilities at voltages lower
than the Secondary System, a different rate schedule may be specified.
Service under this schedule is subject to BPA's General Transmission Rate
Schedule Provisions.
SECTION II. RATE
A. Full-Year Service
The monthly charge per kilowatt of billing demand shall be one-twelfth of
the sum of the Main Grid Charge and the Secondary System Charge, as
applicable and as specified in the Agreement.
1. The Main Grid Charge
The Main Grid Charge per kilowatt of billing demand shall be the sum
of one or more of the following component factors as specified in the
agreement.
a. Main Grid Distance Factor: The amount computed by multiplying
the Main Grid Distance by $0.0281 per mile
b. Main Grid Interconnection Terminal Factor: $0.27
c. Main Grid Terminal Factor: $0.30
d. Main Grid Miscellaneous Facilities Factor: $1.31
2. Secondary System Charge
The Secondary System Charge per kilowatt of billing demand shall be
the sum of one or more of the following component factors as
specified in the Agreement.
a. Secondary System Distance Factor: The amount determined by
multiplying the Secondary System Distance by $0.1961 per mile.
b. Secondary system Transformation Factor: $2.53
c. Secondary System Intermediate Terminal Factor: $0.84
d. Secondary System Interconnection Terminal Factor: $0.44
B. Partial-Year Service
The monthly charge per kilowatt of billing demand shall be as specified
in Section II.A. for all months of the year except for agreements with
terms 5 years or less and which specify service for fewer than 12 months
per year. The charge shall be:
1. during months for which service is specified, the monthly charge
defined in Section II.A., and
2. During other months, the monthly charge defined in Section II.A.
multiplied by 0.2.
SECTION III. BILLING FACTORS
Unless otherwise stated in the Agreement, the billing demand shall be the
largest of:
A. The Transmission Demand;
B. The highest hourly Scheduled Demand for the month; or
C. The Ratchet Demand
Schedule IR-93
Integration of Resources
SECTION 1. AVAILABILITY
Ths schedule supersedes IR-91 and is available for firm transmission service
for electric power and energy using the Main Grid and/or Secondary System of
the Federal Columbia River Transmission System. The definitions of Main Grid
and Secondary Systems are the same as for the FPT-93.1 and FPT-91.3 rate
schedules and are contained in the General Transmission Rate Schedule
Provisions (GTRSPs). For facilities at voltages lower than the Secondary
System, a different rate schedule may be specified. Service under this
schedule is subject to BPA's GTRSPS.
SECTION 11. RATE
The monthly charge shall be the sum of A and B where:
A. Demand Charge
1. $0.424 per kilowatt of billing demand; or
2. For Points of Integration (POI) specified in the Agreement as being
short distance POIs, for which Main Grid and Secondary System
facilities are used for a distance of less than 75 circuit miles, the
following formula applies:
[0.2 + (0.8/75 x transmission distance)]
($0.424 per kilowatt of billing demand)
Where:
the billing demand for a short distance POI is the demand level
specified in the Agreement for such POI, and the transmission
distance is the circuit miles between the POI for a generating
resource of the customer and a designated Point of Delivery serving
load of the customer. Short distance POIs are determined by BPA
after considering factors in addition to transmission distance.
B. Energy Charge
1.06 mills per kilowatthour of billing energy.
SECTION III. BILLING FACTORS
To the extent that the Agreement provides for the customer to be billed for
transmission in excess of the Transmission Demand or Total Transmission
Demand, as defined in the Agreement, at the nonfirm transmission rate
(currently ET-93), such transmission service shall not contribute to either
the Billing Demand or the Billing Energy for the IR rate provided that the
customer requests such treatment and BPA approves in accordance with the
prescribed provisions in the Agreement.
A. Billing Demand
The billing demand shall be the largest of:
1. The Transmission Demand, except under General Transmission Agreements
where a Total Transmission Demand is defined:
2. The highest hourly Scheduled Demand for the month; or
3. The Ratchet Demand.
B. Billing Energy
The billing energy shall be the monthly sum of scheduled kilowatthours.
SCHEDULE IS-93
SOUTHERN INTERTIE TRANSMISSION
SECTION I. AVAILABILITY
This schedule supersedes IS-91 and is available for all transmission on the
Southern Intertie. Service under this schedule is subject to BPA's General
Transmission Rate Schedule Provisions.
SECTION II. RATE
A. Nonfirm Transmission Rate
The charge for nonfirm transmission of non-BPA power shall be 3.11 mills
per kilowatthour of billing energy. This charge applies for both north-
to-south and south-to-north transactions.
B. Firm Transmission Rate
The charge for firm transmission service shall be $0.706 per kilowatt per
month of billing demand and 1.69 mills per kilowatthour of billing
energy. Firm transmission will only be made available to customers under
this rate schedule who have executed a contract with BPA specifying use
of the Firm Transmission rate for either north-to-south or south-to-north
transactions.
SECTION III. BILLING FACTORS
A. For services under Section II.A. the billing energy shall be the monthly
sum of the scheduled kilowatthours, plus the monthly sum of kilowatthours
allocated but not scheduled. The amount of allocated but not scheduled
energy that is subject to billing may be reduced pro rata by BPA due to
forced Intertie outages and other uncontrollable forces that may reduce
Intertie capacity. The amount of allocated but not scheduled energy that
is subject to billing also may be reduced upon mutual agreement between
BPA and the customer.
B. For services under Section II.B. the billing demand shall be the
Transmission Demand as defined in the Agreement. The billing energy
shall be the monthly sum of scheduled kilowatthours, unless otherwise
specified in the Agreement.
Schedule IN-93
NORTHERN INTERTIE TRANSMISSION
SECTION I. AVAILABILITY
This schedule supersedes IN-91 and is available for all transmission on the
Northern Intertie pursuant to an Agreement. Service under this schedule is
subject to BPA's General Transmission Rate Schedule Provisions.
SECTION II. RATE
The charge for transmission of non-BPA power on the Northern Intertie shall
be 0.86 mills per kilowatthour.
SECTION III. BILLING FACTORS
Billing Energy
The billing energy shall be the monthly sum of the scheduled kilowatthours.
Schedule IE-93
EASTERN INTERTIE TRANSMISSION
SECTION 1. AVAILABILITY
This schedule supersedes IE-91 and is available for all nonfirm transmission
on the Eastern lntertie. Service under this schedule is subject to BPA's
General Transmission Rate Schedule Provisions.
SECTION 11. RATE
The charge for nonfirm transmission on the Eastern Intertie shall be 2.04
mills per kilowatthour.
SECTION III. BILLING FACTORS
Billing Energy
The billing energy shall be the monthly sum of the scheduled kilowatthours.
Schedule ET-93
ENERGY TRANSMISSION
Section I. Availability
This schedule supersedes ET-91, unless otherwise specified in the Agreement,
with respect to delivery using Federal Columbia River Transmission System
facilities other than the Southern Intertie, Eastern Intertie, or the
Northern Intertie, and is available for firm (of not more than 1 year
duration) or nonfirm transmission between points within the Pacific
Northwest. BPA may interrupt nonfirm service which is provided under this
rate schedule. Service under this schedule is subject to BPA's General
Transmission Rate Schedule Provisions.
SECTION II. Rate
The charge for transmission of non-BPA power shall be 2.02 mills per
kilowatthour.
SECTION III. BILLING FACTORS
Billing Energy
The billing energy shall be the monthly sum of scheduled kilowatthours.
Schedule MT-91
MARKET TRANSMISSION
SECTION I. AVAILABILITY
This schedule supersedes MT-89 and is available for Transmission Service for
transactions using Federal Columbia River Transmission System facilities
pursuant to the Western Systems Power Pool (WSPP) Agreement. General
Transmission Rate Schedule Provisions.
SECTION II. RATE
The charge shall he determined in advance by BPA. The charge shall be based
on the duration of the proposed transaction and shall not exceed the
following rates.
A. Hourly Rate
The maximum charge shall be 6.5 mills per kilowatt hour where the total
hourly revenues from a given transaction during a calendar day shall not
exceed the product of the Daily rate and the maximum demand scheduled
during any such day.
B. Daily Rate
The maximum charge shall be $.105 per kilowattday where the total demand
charge revenues in any consecutive 7-day period shall not exceed the
product of the Weekly rate and the highest demand experienced on any day
in the 7-day period.
C. Weekly Rate
The maximum charge shall be $.52 per kilowattweek.
D. Monthly Rate.
The maximum charge shall be $2.27 per kilowattmonth.
SECTION III. BILLING FACTORS
The billing factors shall be specified in advance by BPA, as to representing
the Transmission Service use or reservation.
Schedule UFT-83
USE-OF-FACILITIES TRANSMISSION
SECTION I. AVAILABILITY
This schedule supersedes UFT-1 and UFT-2 unless otherwise provided in the
Agreement, and is available for firm transmission over specified Federal
Columbia River Transmssion system facilities. Service under this schedule is
subject to BPA's General Transmission Rate Schedule Provisions.
SECTION II. RATE
The monthly charge per kilowatt of Transmission Demand specified in the
Agreement shall be one-twelfth of the annual cost of capacity of the
specified facilities divided by the sum of Transmission Demands (in
kilowatts) using such facilities. Such annual cost shall be determined in
accordance with Section III.
SECTION III. DETERMINATION OF TRANSMISSION RATE
A. From time to time, but not more often than once in each Contract Year,
BPA shall determine the following data for the facilities which have been
constructed or otherwise acquired by BPA and which are used to transmit
electric power:
1. The annual cost of the specified FCRTS facilities, as determined from
the capital cost of such facilities and annual cost ratios developed
from the Federal Columbia River Power System financial statement,
including interest and amortization, operation and maintenance,
administrative and general, and general plant costs.
2. The yearly noncoincident peak demands of all users of such facilities
or other reasonable measurement of the facilities' peak use.
B. the monthly charge per kilowatt of billing demand shall be one-twelfth of
the sum of the annual cost of the FCRTS facilites used divided by the sum
of Transmission Demands. The annual cost per kilowatt of Transmission
Demand for a facility constructed or otherwise acquired by BPA shall be
determined in accordance with the following formula:
A
-
D
Where:
A = The annual cost of such facility as determined in accordance with
A.1. above.
D = The sum of the yearly noncoincident demands on the facility as
determined in accordance with A.2. above.
The annual cost per kilowatt of facilities listed in the Agreement which are
owned by another entity, and used by BPA for making deliveries to the
transferee, shall be determined from the costs specified in the Agreement
between BPA and such other entity.
SECTION IV. DETERMINATION OF BILLING DEMAND
Unless otherwise stated in the Agreement, the factor to be used in
determining the kilowatts of billing demand shall be the largest of:
A. The Transmission Demand in kilowatts specified in the Agreement;
B. The highest hourly Measured or Scheduled Demand for the month, the
Measured Demand being adjusted for power factor; or
C. The Ratchet Demand.
Schedule TGT-1
TOWNSEND-GARRISON TRANSMISSION
SECTION I. AVAILABILITY
This schedule shall apply to all agreements which provide for the firm
transmission of electric power and energy over transmission facilities of
BPA's section of the Montana [Eastern] Intertie. Service under this schedule
is subject to BPA's General Transmission Rate Schedule Provisions.
SECTION II. RATE
The monthly charge shall be one-twelfth of the sum of the annual charges
listed below, as applicable and as specified in the agreements for firm
transmission. The Townsend-Garrison 500-kV lines and associated terminal,
line compensation, and communication facilities are a separately identified
portion of the Federal Transmission System. Annual revenues plus credits for
government use should equal annual costs of the facilities, but in any given
year there may be either a surplus or a deficit. Such surpluses or deficits
for any year shall be accounted for in the computation of annual costs for
succeeding years. Revenue requirements for firm transmission use will be
decreased by any revenues received from nonfirm use and credits for all
government use. The general methodology for determining the firm rate is to
divide the revenue requirement by the total firm capacity requirements.
Therefore, the higher the total capacity requirements, the lower will be the
unit rate.
If the government provides firm transmission service in its section of the
Montana [Eastern] Intertie in exchange for firm transmission service in a
customer's section of the Montana Intertie, the payment by the government for
such transmission services provided by such customer will be made in the form
of a credit in the calculation of the Intertie Charge for such customer.
During an estimated 1- to 3-year period following the commercial operation of
the third generating unit at the Colstrip Thermal Generating Plant at
Colstrip, Montana, the capability of the Federal Transmission System west of
Garrison Substation may be different from the long-term situation. It may
not be possible to complete the extension of the 500-kV portion of the
Federal Transmission System to Garrison by such commercial operation date.
In such event, the 500/230 kV transformer will be an essential extension of
the Townsend-Garrison Intertie facilities, and the annual costs of such
transformer will be included in the calculation of the Intertie Charge.
However, starting 1 month after extension to Garrison of the 500-kV portion
of the Federal Transmission System, the annual costs of such transformer will
no longer be included in the calculation of the Intertie Charge.
A. Nonfirm Transmission Charge:
This charge will be filed as a separate rate schedule and revenues
received thereunder will reduce the amount of revenue to be collected
under the Intertie Charge below.
B. Intertie Charge for Firm Transmission Service:
Intertie Charge =
(CR-EC)
[((TAC/12)-NFR) x -------]
TCR
SECTION III. DEFINITIONS
A. TAC = Total Annual Costs of facilities associated with the Townsend-
Garrison 500-kV Transmission line including terminals, and prior to
extension of the 500-kV portion of the Federal Transmission System to
Garrison, the 500/230 kV transformer at Garrison. Such annual costs are
the total of: (1) interest and amortization of associated Federal
investment and the appropriate allocation of general plant costs; (2)
operation and maintenance costs; (3) allowance for BPA's general
administrative costs which are appropriately allocable to such
facilities, and (4) payments made pursuant to section 7(m) of Public Law
96-501 with respect to these facilities. Total Annual Costs shall be
adjusted to reflect reductions to unpaid total costs as a result of any
amounts received, under agreements for firm transmission service over the
Montana Intertie, by the government on account of any reduction in
Transmission Demand, termination or partial termination of any such
agreement or otherwise to compensate BPA for the unamortized investment,
annual cost, removal, salvage, or other cost related to such facilities.
B. NFR = Nonfirm Revenues, which are equal to: (1) the product of the
Nonfirm Transmission Charge described in II(A) above, and the total
nonfirm energy transmitted over the Townsend-Garrison line segment under
such charge for such month; plus (2) the product of the Nonfirm
Transmission Charge and the total nonfirm energy transmitted in either
direction by the Government over the Townsend-Garrison line segment for
such month.
C. CR = Capacity Requirement of a customer on the Townsend-Garrison 500-kV
transmission facilities as specified in its firm transmission agreement.
D. TCR = Total Capacity Requirement on the Townsend-Garrison 500-kV
transmission facilities as calculated by adding (1) the sum of all
Capacity Requirements (CR) specified in all transmission agreements
described in section I; and (2) the Government's firm capacity
requirement. The Government's firm capacity requirement shall be no less
than the total of the amounts, if any, specified in firm transmission
agreements for use of the Montana Intertie.
E. EC = Exchange Credit for each customer which is the product of: (1) the
ratio of investment in the Townsend-Broadview 500-kV transmission line to
the investment in the Townsend-Garrison 500-kV transmission line; and (2)
the capacity which the Government obtains in the Townsend-Broadview 500-
kV transmission line through exchange with such customer. If no exchange
is in effect with a customer, the value of EC for such customer shall be
zero.
Schedule AC-93
Southern Intertie Annual Cost
SECTION I. AVAILABILITY
This schedule is applicable to all parties (New Owners) that execute PNW AC
Intertie Capacity Ownership Agreements (Agreements) and will be effective on
the date described in the Agreement. Service under this schedule is subject
to BPA's General Transmission Rate Schedule Provisions.
SECTION II. RATE
The rate charges reflect the terms of the Memorandum of Understanding (MOU),
signed in the fall of 1991, between BPA and potential New owners. The MOU
provides for the payment by New Owners of their prorated share of: (1) BPA's
annual operations, maintenance and general plant expense (including
applicable overheads) properly chargeable to the AC Intertie facilities; and
(2) BPA's share of capitalized replacements on the AC Intertie. The monthly
charge shall be the sum of the charges specified in sections II.A. and II.B.
A. Operations, Maintenance, and General Plant
The monthly charge shall equal $325 per megawatt of billing demand.
B. Replacements
The monthly charge shall equal $0 per megawatt of billing demand.
SECTION III. ADJUSTMENT TO REPLACEMENTS RATE
A. Determination of Billing Adjustment
New Owners will receive a billing adjustment if BPA incurs AC Intertie
replacement cost during the rate period. The Replacements Rate
Adjustment equals
AC Intertie work orders ($000) * %
----------------------------------
725 MW * # months
where:
"# months" equals: (1) the number of months that this
rate schedule is in effect during the fiscal year for
the Initial Replacements Rate Adjustment; or (2) the
number of months in the rate period for the Final
Replacements Rate Adjustment; and
"%" equals the New Owners' percentage share of BPA's
total AC Intertie Rated Transfer Capability as specified
in the Agreements.
B. Initial Replacements Rate Adjustment
New Owners will receive a billing adjustment for each fiscal year that
BPA incurs AC Intertie replacement cost. At the end of each fiscal year,
the cost associated with AC Intertie capital replacement work orders that
have closed during the fiscal year will be determined. The unit rate
that would result using these closed work orders is the basis of the
Initial Replacements Rate Adjustment.
1. Notice Provisions
Following each fiscal year, BPA shall notify all New Owners by
December 15, of the proposed Replacements Rate Adjustment. BPA will
provide the calculation of the adjustment and a short description of
the work performed and the associated cost used as the basis for the
billing adjustment. In addition to written notification, BPA may,
but is not obligated to, hold a public meeting to clarify its
determinations.
Written comments on the Initial Replacements Rate Adjustment will be
accepted through the end of January. Consideration of comments
submitted by the New Owners may result in the billing adjustment
differing from the initially proposed adjustment. BPA shall notify
all New Owners of the Initial Replacements Rate Adjustment by the
last day of February.
2. Adjustment of Monthly Bills
An adjustment will be made on the New Owner's monthly bill prepared
during March. The Initial Replacements Rate adjustment will be
multiplied by the sum of the monthly billing factors from the
relevant fiscal year (i.e., the New Owner's share in megawatts of
BPA's PNW AC Intertie Rated Transfer Capability multiplied by the
numbers of months that this rate schedule is effective during the
fiscal year). The Initial Replacements Rate Adjustment will appear
as a charge to the New Owner on the monthly bill prepared during
March.
C. Final Replacements Rate Adjustment
The actual costs associated with the AC Intertie capital replacement work
orders that occur during the rate period may change after BPA performs
its final analysis of the work orders. BPA shall compare the unit rate
for the rate period using the results of the final work order analysis to
the weighted average of the unit rates from the Initial Replacements Rate
Adjustments.
1. Notice Provisions
BPA shall notify all New Owners in May 1998 of the results of the
calculations, an explanation of work order changes(s), and any
resulting billing adjustment. Written comments from New Owners will
be accepted through the end of June. BPA shall notify all New Owners
of the Final Replacements Rate Adjustment by July 31. Consideration
of comments submitted by the New Owners may result in the Final
Replacements Rate Adjustment differing from the initially proposed
adjustment.
2. Adjustment of Monthly Bills
If the absolute value of the Final Replacements Rate Adjustment is
greater than or equal to $1 per megawatt per month, an adjustment
will be made on the New Owner's monthly bill prepared during August.
For each New Owner, the Final Replacements Rate Adjustment will be
multiplied by the sum of the monthly billing factors from the
relevant fiscal years (i.e., the New Owner's share in megawatts of
BPA's PNW AC Intertie Rated Transfer Capability multiplied by the
number of months that this rate schedule is effective during the
fiscal years). The Final Replacements Rate Adjustment will appear as
a charge or credit to the New Owner on the monthly bill prepared
during August. Interest, as determined by BPA's Office of Financial
Management, will be included in any adjustment.
SECTION IV. BILLING FACTOR
The billing demand shall be the New Owner's capacity ownership share in
megawatts of BPA's PNW AC Intertie Rated Transfer Capability as specified in
the Agreement.
General Transmission Rate Schedule Provisions
SECTION I. ADOPTION OF REVISED TRANSMISSION RATE SCHEDULES AND GENERAL
TRANSMISSION RATE SCHEDULE PROVISIONS (GTRSPs)
A. Approval of Rates
These rate schedules and GTRSPs shall become effective upon interim
approval or upon final confirmation and approval by FERC. BPA will
request FERC approval effective October 1, 1993.
B. General Provisions
These 1993 Transmission Rate Schedules and associated GTRSPs are
virtually identical to and supersede BPA's 1991 Transmission Rate
schedules and GTRSPs (which became effective October 1, 1991) but do not
supersede prior rate schedules required by agreement to remain in force.
Transmission service provided shall be subject to the following Acts, as
amended: the Bonneville Project Act, the Regional Preference Act (P.L.
88-552), the Federal Columbia River Transmission System Act, and the
Pacific Northwest Electric Power Planning and Conservation Act, and the
Energy Policy Act of 1992, Pub. L. 102-486, 106 Stat. 2776 (1992).
The meaning of terms used in the transmission rate schedules shall be as
defined in agreements or provisions which are attached to the Agreement
or as in any of the above Acts.
C. Interpretation
If a provision in the executed Agreement is in conflict with a provision
contained herein, the former shall prevail.
SECTION II. BILLING FACTOR DEFINITIONS AND BILLING ADJUSTMENTS
A. Billing Factors
1. Scheduled Demand
The largest of hourly amounts wheeled which are scheduled by the
customer during the time period specified in the rate schedules.
2. Metered Demand
The Metered Demand in kilowatts shall be the largest of the 60-minute
clock-hour integrated demands measured by meters installed at each
POD during each time period specified in the applicable rate
schedule. Such measurements shall be made as specified in the
Agreement. BPA, in determining the Metered Demand, will exclude any
abnormal readings due to or resulting from: (a) emergencies or
breakdowns on, or maintenance of, the FCRTS; or (b) emergencies on
the customer's facilities, provided that such facilities have been
adequately maintained and prudently operated as determined by BPA.
If more than one class of power is delivered to any POD, the portion
of the metered quantities assigned to any class of power shall be as
agreed to by the parties. The amount so assigned shall constitute
the Metered Demand for such class of power.
3. Transmission Demand
The demand as defined in the Agreement.
4. Total Transmission Demand
The sum of the transmission demands as defined in the Agreement.
5. Ratchet Demand
The maximum demand established during the previous 11 billing months.
Exception: if a Transmission Demand or Total Transmission Demand has
been decreased pursuant to the terms of the Agreement during the
previous 11 billing months, such decrease will be reflected in
determining the Ratchet Demand.
B. Billing Adjustments
Average Power Factor
The adjustment for average power factor, when specified in a transmission
rate schedule or in the Agreement, shall be made in accordance with the
average power factor section of the General Wheeling Provisions.
To maintain acceptable operating conditions on the Federal system, BPA
may restrict deliveries of power 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 85 percent.
SECTION III. OTHER DEFINITIONS
Definitions of the terms below shall be applied to these provisions and the
Transmission Rate Schedules, unless otherwise defined in the Agreement.
A. Agreement
An agreement between BPA and a customer to which these rate schedules and
provisions may be applied.
B. Eastern Intertie
The segment of the FCRTS for which the transmission facilities consist of
the Townsend-Garrison double-circuit 500 kV transmission line segment
including related terminals at Garrison
C. Electric Power
Electric peaking capacity (kW) and/or electric energy (kWh).
D. Federal Columbia River Transmission System
The transmission facilities of the Federal Columbia River Power System,
which include all transmission facilities owned by the government and
operated by BPA, and other facilities over which BPA has obtained
transmission rights.
E. Firm Transmission Service
Transmission service which BPA provides for any non-BPA power except for
transmission service which is scheduled as nonfirm. If the firm service
is provided pursuant to the Agreement, the terms of the Agreement may
further define the service.
F. Integrated Network
The segment of the FCRTS for which the transmission facilities provide
the bulk of transmission of electric power within the Pacific Northwest,
excluding facilities not segmented to the network as shown in the
Wholesale Power Rate Development Study used in BPA's rate development.
G. Main Grid
As used in the FPT and IR rate schedules, that portion of the Integrated
Network with facilities rated 230 kV and higher.
H. Main Grid Distance
As used in the FPT rate schedules, the distance in airline miles on the
Main Grid between the POI and the POD, multiplied by 1.15.
I. Main Grid Interconnection Terminal
As used in the FPT rate schedules, Main Grid terminal facilities that
interconnect the FCRTS with non-BPA facilities.
J. Main Grid Miscellaneous Facilities
As used in the FPT rate schedules, switching, transformation, and other
facilities of the Main Grid not included in other components.
K. Main Grid Terminal
As used in the FPT rate schedules, the Main Grid terminal facilities
located at the sending and/or receiving end of a line exclusive of the
Interconnection terminals.
L. Nonfirm Transmission Service
Interruptible transmission service which BPA may provide for non-BPA
power.
M. Northern Intertie
The segment of the FCRTS for which the transmission facilities consist of
two 500 kV lines between Custer Substation and the United States-Canadian
border, one 500 kV line between Custer and Monroe Substations, and two
230 kV lines from Boundary Substation to the United States-Canadian
border, and the associated substation facilities.
N. Point of Integration (POI)
Connection points between the FCRTS and non-BPA facilities where non-
Federal power is made available to BPA for wheeling.
O. Point of Delivery (POD)
Connection points between the FCRTS and non-BPA facilities where non-
Federal power is delivered to a customer by BPA.
P. Secondary System
As used in the FPT and IR rate schedules that portion of the Integrated
Network facilities with operating voltage of 115 kV or 69 kV.
Q. Secondary System Distance
As used in the FPT rate schedules, the number of circuit miles of
Secondary System transmission lines between the secondary POI and the
Main Grid or the secondary POD, or the Main Grid and the secondary POD.
R. Secondary System Interconnection Terminal
As used in the FPT rate schedules, the terminal facilities on the
Secondary System that interconnect the FCRTS with non-BPA facilities.
S. Secondary System Intermediate Terminal
As used in the FPT rate schedules, the first and final terminal
facilities in the Secondary System transmission path exclusive of the
Secondary System Interconnection terminals.
T. Secondary Transformation
As used in the FPT rate schedules, transformation from Main Grid to
Secondary System facilities.
U. Southern Intertie
The segment of the FCRTS for which the major transmission facilities
consist of two 500 kV AC lines from John Day Substation to the Oregon-
California border, a portion of the 500 kV AC line from Buckley
Substation to Summer Lake Substation; when completed, the Third AC
facilities which include Captain Jack Substation and the Alvey-Meridian
500 kV AC line; one 1,000 kV DC line between the Celilo Substation and
the Oregon-Nevada border, and associated substation facilities.
V. Transmission Service
As used in the MT rate schedule, Transmission Service is as defined in
the Western Systems Power Pool Agreement.
SECTION IV. BILLING INFORMATION
A. Payment of Bills
Bills for transmission service shall be rendered monthly by BPA. Failure
to receive a bill shall not release the customer from liability for
payment. Bills for amounts due 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 following in making direct wire
transfers will be provided by the Office of Financial Management and
updated as necessary.
1. Computation of Bills
The transmission billing determinant is the electric power quantified
by the method specified in the Agreement or Transmission Rate
Schedule. Scheduled power or metered power will be used.
The transmission customer shall provide necessary information to BPA
for any computation required to determine the proper charges for use
of the FCRTS, and shall cooperate with BPA in the exchange of
additional information which may be reasonably useful for respective
operations.
Demand and energy billings for transmission service under each
applicable rate schedule shall be rounded to whole dollar amounts, by
eliminating any amount which is less than 50 cents and increasing any
amounts from 50 cents through 99 cents to the next higher dollar.
2. Estimated Bills
At its option, BPA may elect to render an estimated bill to be
followed at a subsequent billing date by a final bill. The estimated
bill shall have the validity of and be subject to the same payment
provisions as a final bill.
3. Billing Month
For charges based on scheduled quantities, the billing month is the
calendar month. For charges based on metered quantities, the billing
month is defined as the interval between scheduled meter-reading
dates. The billing month will not exceed 31 days in any case. While
it may be necessary to read meters on a day other than the scheduled
meter-reading date, for determination of billing demand, the billing
month will cease at 2400 hours on the last scheduled meter-reading
date. Schedules will be predetermined. The customer must give 30
days notice to request a change to the schedule.
4. Due Date
Bills shall be due by close of business on the 20th day after the
date of the bill (due date). should the 20th day be a Saturday,
Sunday, or holiday (as celebrated by the customer), the due date
shall be the next following business day.
5. Late Payment
Bills not paid in full on or before close of business on the due date
shall be subject to a penalty charge of $25. In addition, an
interest charge of one-twentieth percent (0.05 percent) 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.
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.
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 customer. However,
such cancellation shall not affect the customer's liability for any
charges accrued prior thereto under such agreement.
6. 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
customer is entitled to the disputed amount, BPA shall refund the
disputed amount with interest, as determined by BPA's Office of
Financial Management.
BPA retains the right to verify, in a manner satisfactory to the
Administrator, all data submitted to BPA for use in the calculation
of BPA's rates and corresponding rate adjustments. BPA also retains
the right to deny eligibility for any BPA rate or corresponding rate
adjustment until all submitted data have been accepted by BPA as
complete, accurate, and appropriate for the rate or adjustment under
consideration.
7. Revised Bills
As necessary, BPA may render a revised bill.
a. If the amount of the revised bill is less than or equal to the
amount of the original bill, the revised bill shall replace all
previous bills issued by BPA that pertain to the specified
customer for the specified billing period and the revised bill
shall have the same date as the replaced bill.
b. If a revision causes an additional amount to be due BPA or the
specified customer beyond the amount of the original bill, a
revised bill will be issued for the difference and the date of
the revised bill shall be its date of issue.
Exhibit B
GWP Form-4R (04-15-83)
GENERAL WHEELING PROVISIONS
---------------------------
Index to Sections
Section ----------------- Page
GENERAL APPLICATION
1. Interpretation.................................................. 2
2. Definitions..................................................... 2
3. Prior Demands................................................... 4
4. Measurements.................................................... 4
5. Measurements and Installation of Meters......................... 5
6. Tests of Metering Installations................................. 5
7 Adjustment for Inaccurate Metering.............................. 5
B. Character of Service............................................ 6
9. Point(s) of Delivery and Delivery Voltage....................... 6
10. Combining Deliveries Coincidentally............................. 6
11. Suspension of Deliveries........................................ 6
12. Continuity of Service........................................... 6
13. Uncontrollable Forces........................................... 7
14. Reducing Charges for Interruptions............................ 7
15. Net Billing..................................................... 7
16. Average Power Factor............................................ 7
17. Permits......................................................... 8
18. Ownership of Facilities......................................... 8
19. Adjustment for Change of Conditions............................. 8
20. Dispute Resolution and Arbitration.............................. 9
21. Contract Work Hours and Safety Standards........................ 10
22. Convict Labor................................................... 11
23. Equal Employment Opp6rtunity.................................... 11
24. Additional Provisions........................................... 12
25. Reports......................................................... 12
26. Assignment of Contract.......................................... 12
27. Waiver of Default............................................... 13
28. Notices and Computation of Time................................. 13
29. Interest of Member of Congress.................................. 13
APPLICABLE ONLY IF TRANSFEREE IS A PARTY TO THIS CONTRACT
30. Balancing Phase Demands......................................... 13
31. Adjustment for Unbalanced Phase Demands..13
32. Changes in Requirements or Characteristics...................... 13
33. Inspection of Facilities.........................................13
34. Electric Disturbances............................................14
35. Harmonic Control................................................ 15
APPLICABLE ONLY IF TRANSFEREE IS NOT A PARTY TO THIS CONTRACT
36. Protection of the Transferor.................................... 15
RELATING ONLY TO RURAL ELECTRIFICATION BORROWERS
37. Approval of Contract............................................ 15
APPLICABLE ONLY IF BONNEVILLE IS THE TRANSFEROR
38. Equitable Adjustment of Rates................................... 15
GENERAL APPLICATION
1. 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 herein, the
former shall prevail.
(b) If a provision in the General Transmission Rate Schedule Provisions
is in conflict with a provision 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 thereto of any
means of enforcing any remedy, either at law or in equity, for the
breach of any of the provisions thereof which it would otherwise
have.
2. Definitions. As used in this contract:
(a) "Contractor," "Utility" or "Borrower" means the party- to this
contract other than Bonneville.
(b) "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
(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.
(c) "Integrated Demand" means the number of kilowatts which is equal to
the number of kilowatt-hours delivered at any point during a clock
hour.
(d) "Measured Demand" means the maximum Integrated Demand for a billing
month determined from measurements made as specified in the
contract or as determined in section 4 hereof when metering or
other data are not available
2
for such purpose. Bonneville, in determining the Measured Demand,
will exclude any abnormal Integrated Demands due to, or resulting
from (a) emergencies or breakdowns on, or maintenance of, either
parties' facilities, and (b) emergencies on facilities of the
Transferee, provided that such facilities have been adequately
maintained and prudently operated as determined by Bonneville.
If the contract provides for delivery of more than one class of
power to a Transferee at any Point of Delivery, the portion of each
Integrated Demand assigned to any class of power shall be
determined as specified in the contract. The portion of the
Integrated Demand so assigned shall constitute the Measured Demand
for such class of power.
(e) "Month" means the period commencing at the time when the meters
mentioned in this contract are read by Bonneville and ending
approximately 30 days thereafter when a subsequent reading of such
meters is made by Bonneville.
(f) "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.
(g) "System" or "Facilities" means the transmission facilities: (1)
which are owned or controlled by either party, or (2) which either
party may use under lease, easement, or license.
(h) "Transferee" means an entity which receives power or energy from
the system of the Transferor.
(i) "Transferor" means an entity which receives at one point on its
system a supplying entity's power or energy and makes such power or
energy available at another point an its system for the account of
the delivering entity or a third party.
(j) "Uncontrollable Forces" means:
(1) strikes or work stoppage affecting the operation of the
Contractor's works, system, or other physical facilities or of
the Federal System Facilities or the physical facilities of
any Transferee 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 Transferee to restrict or
terminate its operations to prevent substantial loss or damage
to its works, system, or other physical facilities; or
(2) such of the following events as the Contractor or Bonneville
or any Transferee 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 Transferee, causing failure, damage, or destruction
of any works, system or facilities of such party or
Transferee; the word "failure"
3
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 Transferee,
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 Transferee 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 prosecuted by said party or
Transferee 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 Transferee, 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.
3. Prior Demands.
(a) In determining any credit demand mentioned in, or money
compensation to be paid under this contract for any month,
Integrated Demands at which electric energy was delivered by the
Transferor at Points of Delivery mentioned herein for the account
of the other party to this contract prior to the date upon which
the contract takes effect shall be considered in the same manner as
if this contract had been in effect.
(b) If either party has delivered electric power and energy to the
other party at any Point of Delivery specified in this contract or
in any previous contract, and such Point of Delivery is superseded
by another Point of Delivery specified in this contract, the
Measured Demands, if any, at the superseded Point of Delivery shall
be considered for the purpose of determining the charges paid to
the Transferor for the electric power and energy delivered under
this contract at such superseded point.
4. Measurements. Except as it is otherwise provided in section 7, each
measurement of each meter mentioned in this contract shall be the
measurement
4
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.
5. 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.
6. 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 7. 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.
7. Adjustment for Inaccurate Metering
(a) If any meter mentioned in this contract fails to register, or if
the measurement made by such meter during a test made as provided
in section 6 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) six months. Such corrected
measurements shall be used to recompute the amounts of any electric
power and energy to be made available, or any credits to be made in
any exchange energy account, and of any money compensation to be
paid to the Transferor as provided in this contract.
(b) If the credit theretofore made to the Transferor in the exchange
energy account varies from the credit to be made as recomputed, the
amount of the variance will be credited in such exchange energy
account to the party entitled thereto.
(c) If the money compensation theretofore paid to the Transferor varies
from the money compensation to be paid as recomputed, the amount of
the variance will be paid to the party entitled thereto after both
parties have agreed to such recomputation and within 30 days after
receipt of invoice by the designated payment office of the payer
provided, however, that the other
5
party may deduct such amount due it from any money compensation
which thereafter becomes due the Transferor under this contract.
8. Character of Service. Unless otherwise specifically provided for in the
contract, electric power and energy made available pursuant to this
contract shall be in the form of three-phase current, alternating at a
nominal frequency of 60 hertz.
9. Point(s) of Delivery and Delivery Voltage. Electric power and energy
shall be delivered to each Transferee at such point or points and at
such voltage or voltages as are agreed upon by the parties hereto.
10. Combining Deliveries Coincidentally. 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:
(a) 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 Transferee at all such
points after adjusting said Integrated Demands as appropriate to
such points;
(b) 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
(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 such month.
11. Suspension of Deliveries. The other party to this contract may at any
time notify the Transferor in writing to suspend the deliveries of
electric power and energy provided for in this contract. Upon receipt
of any such notice, the Transferor will forthwith discontinue, and will
not resume, such deliveries until notified to do so by the other party,
and upon receipt of such notice from the other party to do so, will
forthwith resume such deliveries.
12. Continuity of Service. Either party may temporarily interrupt or
reduce deliveries of electric power and energy if such party determines
that such interruption or reduction is necessary or desirable in case of
system emergencies, Uncontrollable Forces, or in order to install
equipment in, make repairs to, make replacements within, make
investigations and inspections of, or perform other maintenance work on
its system. Except in case of emergency and in order that each party's
operations will not be unreasonably interfered with, such party shall
give notice to the other party of any such interruption or reduction,
the reason therefor, and the probable duration thereof to the extent
such party has knowledge thereof. Each party 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.
13. Uncontrollable Forces. Each party shall notify the other as soon as
possible of any Uncontrolled 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. Reducing Charges for Interruptions. If deliveries of electric power
and energy to the Transferee are suspended, interrupted, interfered with
or curtailed due to Uncontrollable Forces on either the Transferee's
System or Transferor's System, or if the Transferor interrupts or
reduces deliveries to the Transferee for any of the reasons stated in
section 12 hereof, the credit in the exchange energy account which would
otherwise be made, or the money compensation which would otherwise be
paid to the Transferor, shall be appropriately reduced. No
interruption, or equivalent interruption, of less than 30 minutes
duration will be considered for computation of such reduction in
charges.
15. Net Billing. Upon mutual agreement of the parties, payment due one
Party may be offset against payments due the other party under all
contracts between the parties hereto 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.
16. Average Power Factor.
(a) The formula for determining average power factor is as follows:
Average Power Factor = Kilowatthours
------------------------------------------------------
2 2
/(Kilowatthours) + (Reactive Kilovolt-ampere-hours)
The data used in the above formula shall be obtained from meters
which are ratcheted to prevent reverse registration.
(b) When delivery of electric poster and energy by the Transferor at
any point is commingled with any other class or classes of power
and it is impracticable to separately meter the kilowatthours and
reactive kilovolt-ampere-hours for each class, the average power
factor of the total delivery of such electric power and energy for
the month will be used, where applicable, as the power factor for
each of the separate classes.
(c) Except as it is otherwise specifically provided in this contract,
no adjustment will be made for power factor at any point of
delivery described in this contract while the varhours delivered at
such point are not measured.
(d) The Transferor may, but shall not be obligated to, deliver electric
energy hereunder at a power factor of less than 0.85 leading or
lagging.
17. 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 a 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.
18. Ownership of Facilities.
(a) Except as otherwise expressly provided, ownership of any and all
equipment, and of 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 facilities.
19. Adjustment for Change of Conditions. If changes in conditions hereafter
occur which substantially affect any factor required by this contract to
be used in determining (a) any credit in any exchange energy account to
be made, money compensation to be paid, or amount of electric power and
energy or losses to be made available to one party by the other party,
or (b) any maximum replacement demand, or average power factor mentioned
in this contract, such factor will be changed in an equitable manner
which will conform to such changes of conditions, If an increase in the
capacity of the facilities being used by the Transferor in making
deliveries hereunder is required at any time after execution of this
contract to enable the Transferor to make the deliveries herein required
together with those required for its own operations, the construction or
installation of additional or other
8
equipment or facilities for that purpose shall be deemed to be a change
of conditions within the meaning of the preceding sentence.
If, pursuant to the terms of the agreement establishing such exchange
energy account, another rate is substituted for the rate to be used in
settling the balance in such account, the number of kilowatthours to be
credited to the Transferor in such account for each month as provided in
this agreement, shall be changed for each month thereafter to the amount
computed by multiplying such number of kilowatthours by 2.5 mills and
dividing the resulting product by the currently effective substituted
rate in mills per kilowatthour.
20. 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 Contractor.
(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 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 4;
(2) the correction of the measurements to be made pursuant to
section 7;
9
(3) the duration of the interruption or equivalent interruption
in section 14;
(4) whether changes in conditions mentioned in section 19 have
occurred;
(5) whether the changes mentioned in section 30 were made
"promptly";
(6) whether an increase or decrease in load or change in load
factor mentioned in section 32 is unusual;
(7) any issue which both parties agree is an issue of fact
mentioned in sections 30, 31, and 34;
(8) the occurrence of an abnormal nonrecurring demand and the
amount and time thereof;
(9) whether a party has complied with section 34(b); and
(10) the acceptable level of harmonics for purposes of section 35.
21. Contract Work Hours and Safety Standards. This contract, if and to the
extent required by applicable law and 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 hours 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.
10
(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.
(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.
22. 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 Public Law 89-
176, September 10, 1965 (18 U.S.C. 4082(c)(2)) and Executive Order
11755, December 29, 1973.
23. 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 other contract or understanding, a notice, to be
provided by Bonneville, advising the labor union or worker's
representative of the Contractor's commitments under this 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 by the
rules, regulations, and relevant orders of the Secretary of Labor,
or pursuant
11
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 paragraphs (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 provisions 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.
24. 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.
25. Reports. The other party to this contract will furnish Bonneville such
information as is necessary for making any computation required for the
purposes of this contract, and the parties will cooperate in exchanging
such additional information as may be reasonably useful for their
respective operations.
26. 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
12
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 Contractor and any mortgagee, trustee, secured party,
subsidiary of the Contractor or holder of such instrument of
indebtedness, as security for bonds of other indebtedness of such
Contractor, present or future; such mortgagee, 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 Contractor.
27. 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.
28. 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.
29. 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 this contract if made with a
corporation for its general benefit.
APPLICABLE ONLY IF TRANSFEREE IS A PARTY TO THIS CONTRACT
30. Balancing Phase Demands. If required by the Transferor at any time
during the term of this contract, the Transferee shall promptly 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.
31. Adjustment for Unbalanced Phase Demands. If the Transferee fails to
promptly make the changes mentioned in section 30, the Transferor may,
after giving written-notice one month in advance, determine that the
Measured Demand of the Transferee 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.
32. Changes in Requirements or Characteristics. The Transferee will,
Whenever possible, give reasonable notice to the transferor of any
unusual increase or decrease of its demands for electric power and
energy on the Transferor's system, or of any unusual change in the load-
factor or power factor at which the Transferee will take delivery of
electric power and energy under this contract.
33. 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
13
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.
34. Electric Disturbances.
(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 utility practices:
(1) to minimize electric disturbances such as, but not limited
to, the abnormal flow of power which may damage or interfere
with the electric system of 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 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.
14
(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
person not a party to this contract.
35. 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.
APPLICABLE ONLY IF TRANSFEREE IS NOT A PARTY TO THIS CONTRACT
36. Protection of the Transferor. Protection is or will be afforded to
Bonneville or its Transferor under such of the following provisions and
conditions as are specified in each contract executed or to be executed
by Bonneville and each third party Transferee named in this contract:
the power factor clause of the applicable Bonneville Wholesale Rate
Schedule and the subject matter set forth in the General Contract
Provisions under the following titles, namely:
Adjustment for Unbalanced Phase Demands; Uncontrollable Forces;
Continuity of Service; Changes in Demands or Characteristics; Electric
Disturbances; Harmonic Control; Balancing Phase Demands; Permits;
Ownership of Facilities; and Inspection of Facilities.
RELATING TO RURAL ELECTRIFICATION ADMINISTRATION BORROWERS
37. Approval of Contract. If the Contractor 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 Contractor shall notify Bonneville of any such
entity. If approval is given, such contract or amendment shall be
effective at the time stated therein.
APPLICABLE ONLY IF BONNEVILLE IS THE TRANSFEROR
38. Equitable Adjustment of Rates.
(a) Bonneville shall establish, periodically review and revise rates
for the wheeling of electric power and/or energy 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" shall
mean any date 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 Contractor 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
15
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 Contractor; 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 Contractor shall pay Bonneville for the service 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 Transmission
Rate Schedule Provisions, if any, 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 bases by a governmental agency
designated by law to approve Bonneville's rates. Rates shall be
applied in accordance with the terms thereof, the General
Transmission Rate Schedule Provisions as changed with, incorporated
in or referred to in such rate schedule and the terms of this
contract.
(WP-PKJ-0222f)
Exhibit C, Page 1 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
TRANSMISSION PARAMETERS
A. Points Of Integration, Transmission Demands, Resources, And Use-Of
Facilities Charges
Use-of-
Facilities
Transmission Sources to Charge
Point of Integration (Voltage) Demand (kW) be Integrated $/kW/mo.
- -------------------------------- ------------ ------------- ----------
1. C.W. Paul Substation (500kV) 173,000 Electric Output 0
Centralia(1)
2. Garrison Substation (500 kV) 466,000(2) Electric Output 0
of Colstrip
Nos. 1-4(2)
3. Garrison Substation (230 kV) 94,000 Electric Output 0
of Colstrip
No. 4(3)
4. John Day Substation (500 kV) 300,000 Any Electric Power 0
transmitted over
the PNW AC Intertie
pursuant to the
Capacity Ownership
Agreement
Total Transmission Demand 1,033,000
(1) The Transmission Demand with respect to this Resource shall be reduced
to 100,000 kW on the effective date of the 197 MW (or lesser amount) of
incremental Transmission Demand specified in footnote 2 below.
Bonneville shall integrate at the C. W. Paul Substation Point of
Integration, in an amount up to the Transmission Demand with respect to
such Point of Integration, shares of the Centralia Project Electric
Power acquired by Puget from other entities. Bonneville shall integrate
such Electric Power on the same basis that Bonneville integrates
Electric Power from the Company's ownership share of the Centralia
Project.
(2) Bonneville shall integrate at the Garrison Substation Point of
Integration in an amount up to the Transmission Demand, Electric Power
from Colstrip 1, 2, 3, and 4 acquired by Puget. Bonneville shall
integrate at the Garrison Substation Point of Integration in an amount
up to the Transmission Demand with respect to such Point of Integration,
Electric Power from other resources, unless Bonneville determines that
Electric Power from such other resources cannot be integrated due to
Operational Constraints. Bonneville shall integrate such Electric Power
on the same basis that Bonneville is obligated to integrate Electric
Power from the Company's Colstrip ownership share. This provision does
not increase or decrease any rights that the Company has pursuant to
Contract No. DE-MS79-81BP90210 (Montana Intertie Agreement).
(2) (cont'd):
In consideration of the Company's maintaining in effect with The
Washington Water Power Company (WWP) until November 30, 1998, the
Exchange Agreement, as amended or replaced, pursuant to which the
Company exchanges 197 MW of its Colstrip Project generation for 197 MW
of WWP's Centralia Project generation, Bonneville shall provide the
Company beginning December 1, 1998, with a right to 197 MW of East-to-
West incremental firm
Exhibit C, Page 2 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
transmission service. At such time that the Company exercises such
right, a Transmission Demand in the amount of 197 MW, or a lesser amount
if so requested by the Company, shall be added to this Exhibit C, Part
A. with respect to the Garrison Substation Point of Integration. To the
extent of such Transmission Demand, Bonneville shall provide
transmission service under this Agreement from the Garrison Substation
Point of Integration to one or more of the Points of Delivery. The
Company's right as provided for in this paragraph shall terminate if not
exercised prior to November 30, 2000, or a later date determined by
Bonneville. If the Company does not maintain in effect until November
30, 1998, the Exchange Agreement with WWP pursuant to which the Company
exchanges 197 MW of its Colstrip Project generation for 197MW of WWP's
Centralia Project generation, then upon the Company's request a
Transmission Demand in the amount of 197 MW, or a lesser amount if so
requested by the Company, shall be added to Exhibit C, Part A, with
respect to the Garrison Substation Point of Integration; provided,
however, that to the extent the transmission service Bonneville provides
to the Company with respect to such 197 MW must be curtailed due to
Operational Constraints, the Company shall receive a pro rata reduction
in Demand Charge, and the Company shall not be assessed charges for
energy pursuant to the Integration of Resources Transmission Rate
Schedule (IR-93), or its successor rate schedule. If and to the extent
the Company contracts with WWP to provide access across the "West-of-
Hatwai Cutplane" (as defined in footnote 3 below), the Company will he
assessed losses as if such Electric Power had flowed on the FCRTS;
provided, that, notwithstanding the foregoing, Bonneville shall deliver
on a firm basis to one or more Points of Delivery such 197 MW of
Electric Power (or any lesser amount) as may be scheduled by the
Company.
(3) If this Resource (94 MW Colstrip 4 purchase from Montana) cannot be made
available to Bonneville due solely because of (i) Operational
Constraints, including, without limitation, Western System Coordinating
Council scheduling requirements. involving the West-of-Hatwai Cutplane,
which do not involve an outage of transmission facilities (ii)
suspension or interruption of, or interference with, the operation of
the FCRTS, or (iii) both, and it is within Bonneville's capability to do
so without adversely affecting performance of its existing obligations
on the Effective Date, then Bonneville shall, if requested by the
Company, make replacement Electric Power available to the Company equal
to the amount of-such Resource the Company would have otherwise made
available to Bonneville at the Garrison Substation Point of Integration
and the Company shall at Bonneville's option: (1) reimburse Bonneville
at Bonneville's Nonfirm Energy rate or Surplus Firm Energy rate when
Bonneville is selling such energy; or (2) return replacement Electric
Power 168 hours later or at a time and place agreed upon by Bonneville
and the Company, or (3) reimburse Bonneville for Bonneville's costs to
obtain replacement Electric Power from third parties including
associated wheeling and administrative fees. If Bonneville is unable to
make replacement Electric Power available, then transmission services
for this Resource under this Agreement shall be curtailed before any
other firm wheeling contracts executed prior to the effective date of
Contract No. DE-MS79-92BP93741, as amended or replaced, with the
exception of Bonneville's Electric Power purchase from Basin Electric
Power Cooperative (Basin). "West-of-Hatwai Cutplane" means the parallel
transmission facilities consisting of the following transmission lines
and facilities, Grand Coulee-Bell 230 kV lines 3 and 5, Grand Coulee-
Bell 115 kV lines 1 and 2, Grand Coulee-Westside 230 kV line, Hatwai-
Lower Granite 500 kV line, Hatwai-Lolo 230 kV line, Lind-Warden 115 kV
line, Lolo 230/115 kV Transformer #1 and #2. Harrington-Odessa 115 kV
line, Dry Gulch Transformer 115/69 kV, North Lewiston-Walla Walla 230 kV
line, and the North Lewiston-Walla Walla 115 kV line which connect two
areas of a power system. The provisions set forth in this footnote shall
be void and of no force or effect after November 30, 1998.
Exhibit C, Page 3 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
B. Points of Delivery and Use Limits
Point of Delivery Use Limit
----------------------- --------------
(Voltage) (kW)(1)
Christopher Tap 230 kV 450,000 kW
Covington Substation 230 kV 880,000 kW (2)
Custer Substation 230 kV 475,000 kW (3)(8)
Maple Valley Substation 230 kV 1,570,000 kW
Monroe Substation 230 kV 430,000 kW (4)
Sedro Woolly Substation 230 kV 125,000 kW (8)
White River Substation 230 kV 170,000 kW
Big Eddy Substation 230 kV (5)
John Day Substation 500 kV 400,000 kW (6)
Fairmount Substation 69 kV 60,000 kW (7)
(115 kV upon installation and
energization of 115 kV facilities)
Kitsap Substation 115 kV 410,000 kW
Olympia Substation 115 kV 270,000 kW
Bellingham Substation 115 kV 100,000 kW (8)
Beverly Park Substation 115 kV 50,000 kW
C. W. Paul Substation 500 kV 280,000 kW
Sedro Woolley Tap 230 kV 265,000 kW (9)
(1) Use Limits may be developed based on the rating of the
Government's limiting facility at each Point of Delivery. These
values are determined based on (A) the rating of the Bonneville
facilities at the Point of Delivery, and (B) an allocation of such
rating between (i) the Company's Use Limit under this Agreement at
such Point of Delivery (including but not limited to any requested
increases in such Use Limit) and (ii) other Bonneville uses but
these values shall in any event, if requested by the Company in
writing pursuant to this footnote be not less than the sum of
contract demands at such Point of Delivery. Each numerical Use
Limit set forth above indicates that for the Point of Delivery
opposite such numerical Use Limit there is a limit (equal to such
Use Limit) to the rate of delivery on a firm basis at such Point of
Delivery that is available to the Company under this Agreement.
The Company's Use Limit under this Agreement at any Point of
Delivery may be increased pursuant to the provisions of section
10(d). The Use Limit under this Agreement at a Point of Delivery
shall be decreased upon written request of the Company. Bonneville
shall not unilaterally decrease any Use Limit. In the event it is
determined that the total deliveries by Bonneville pursuant to all
agreements between the Company and Bonneville which require
deliveries of Electric Power to be made at a specific Point of
Delivery may exceed the Use Limit for that Point of Delivery, and
joint studies indicate a need for reinforcement, Bonneville and the
Company will conduct and conclude the joint discussions described
in section 10(d) within 6 months of the above determination, and
implement any resulting plan as soon as is reasonably practicable.
Under no circumstances, and notwithstanding anything to the
contrary set forth in this Agreement, shall Use Limits, without the
Company's prior written consent, be less than the transmission
demands in effect under the Prior Agreements immediately prior to
their termination pursuant to section 2(a).
Exhibit C, Page 4 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
(2) The Use Limit with respect to the Covington Substation Point of
Delivery includes the Use Limits for the Christopher Tap and White
River Substation Points of Delivery.
(3) The Use Limit with respect to the Custer Substation Point of
Delivery includes the Use Limits for the Bellingham Substation and
Sedro Woolley Substation Points of Delivery, and includes
deliveries to Portal Way.
(4) The Use Limit with respect to the Monroe Substation Point of
Delivery includes the Use Limits for the Sedro Woolley Tap and
Beverly Park Substation Points of Delivery.
(5) Nothing in this Agreement or the Capacity Ownership Agreement
provides the Company with rights to use the DC Intertie.
Deliveries at this Point of Delivery are subject to available
transmission capacity and any nonfirm rights the Company has on an
hour to wheel Electric Power over the DC Intertie.
(6) If the megawatt amount of the capability of the PNW AC Intertie to
which the Company is entitled pursuant to the Capacity Ownership
Agreement is at any time increased or reduced, the Use Limit with
respect to the John Day Substation Point of Delivery shall be
concurrently increased or reduced by a megawatt amount equal to
such increase or reduction with respect to the PNW AC Intertie upon
prior written notice of such increase or reduction by the Company
to Bonneville.
(7) The Use Limit with respect to the Fairmount Substation Point of
Delivery shall be increased to 70,000 kW upon installation and
energization of 115 kV facilities at Fairmount Substation.
(8) The Use Limits for the Custer Substation, Sedro Woolley Substation
and Bellingham Substation Points of Delivery will be adjusted, if
necessary, to be consistent with the Bellingham Upgrade Northern
Intertie agreement.
(9) The Sedro Woolley Tap Point of Delivery is a temporary Point of
Delivery, pursuant to the terms of Contract No. 14-03-64431. The
provisions of Contract No. 14-03-64431 shall continue to apply to
this Point of Delivery.
Exhibit C, Page 5 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
C. Calculation of Charges Pursuant to the UFT-83 Rate Schedule
I&A I&A O&M Sum of Non-
Annual Annual Annual Coincidental
Facility Investment Cost Ratio Cost Cost Demands $/kW/yr Demand
-------- ---------- ---------- ------ ------ ------------ ------- ------
None
------- ------
Total UFT Charge = 0.00/kW/yr kW
$0.00/KW/mo
____________________
Unit Charge = (I&A Annual Cost) + O&M Annual Cost = $/kW yr
---------------------------------------------
Sum of Non-Coincidental Demands
Monthly Charge = ($/kW yr) (Project Demand) = $/mo.
--------------------------
12 Months
Exhibit C, Page 6 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
D. Description of Points of Integration and Points of Delivery
Note: These are definitions only. Designations of these points as
either Points of Integration or Points of Delivery are in Part A
or Part B of this exhibit.
1. Big Eddy Substation
Location: the points in the Government's Big Eddy Substation
where the line terminals of the Government's Celilo Converter
Station are connected to the 230 kV bus.
Voltage: 230 kV.
2. C.W. Paul Substation
Location: the points in the Government's C.W. Paul Substation
where the 500 kV facilities of the Government and the Centralia
Thermal Project are connected;
Voltage: 500 kV,
Metering: at the Centralia Thermal Project, in the 20 kV circuits
over which Electric Power flows.
Exception: There shall be an adjustment for losses between the
Point of Integration and the metering point.
3. Christopher Tap
Location: the point on the Government's Covington-Tacoma 230 kV
circuit over which Electric Power flows;
Voltage: 230 kV;
Metering: in the Company's O'Brien Substation, in the 230 kV
circuit over which Electric Power flows;
Exception: there shall be an adjustment for losses between the
Point of Delivery and the point of metering.
4. Covington Substation
Location: the point in the Government's Covington Substation where
the 230 kV facilities of the parties hereto are connected;
Exhibit C, Page 7 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
Voltage: 230 kV;
Metering: in the Government's Covington Substation in the 230 kV
circuit over which Electric Power flows;
Exception: the integrated demands at the Covington and White River
Point of Delivery's are totaled.
5. Custer Substation
Location: the point in the Government's Custer Substation in the
230 kV facilities of the Parties hereto are connected;
Voltage: 230 kV;
Metering: in the Government's Custer Substation in the 230 kV
circuits over which Electric Power flows.
6. Garrison Substation
Location: the points in the Government's Garrison Substation where
the line terminals of the Garrison-Townsend transmission lines are
connected to the 500 kV bus;
Voltage: 500 kV;
Metering: in the Government's Garrison Substation in the 500 kV
circuits over which Electric Power flows.
7. John Day Substation
Location: the points in the Government's John Day Substation where
the line terminals of the Southern Intertie are connected to the
500 kV bus;
Voltage: 500 kV.
8. Maple Valley Substation
Location: the points in the Government's Maple Valley Substation
where the 230 kV facilities of the Parties hereto are connected;
Voltage: 230 kV;
Metering: in the Government's Maple Valley Substation, in the 230
kV circuits over which Electric Power flows.
Exhibit C, Page 8 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
9. Monroe Substation
Location: the point in the Government's Monroe Substation where
the Monroe-Sammamish No. 1 Line is connected;
Voltage: 230 kV;
Metering: in the Company's Sammamish Substation, in the 230 kV
circuits over which Electric Power flows; until such time as the
Government's Sno-King tap is disconnected from the Monroe-Sammamish
No. 1 Line and thereafter in the Government's Monroe Substation, in
the 230 kV circuit over which such Electric Power will flow;
Exceptions: there shall be an adjustment for losses between the
Point of Delivery and the metering point.
10. Sedro Woolley Substation
Location: the point at Structure No. 26/7 of the Government's
Murray-Bellingham 230 kV Line where the facilities of the Parties
hereto are connected;
Voltage: 230 kV;
Metering: in the Company's Sedro Woolley Substation, in the 230 kV
circuits over which Electric Power flows;
Exceptions: the current and potential transformers are owned by
Puget.
11. White River Substation
Location: the points in the Company's White River Substation where
the 230 kV facilities of the Government and the Company are
interconnected;
Voltage: 230 kV;
Exhibit C, Page 9 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
Metering:
(1) the Government's Covington-White River No. 1 Line is metered
at the Government's Covington Substation in the 230 kV
circuits over which Electric Power flows;
(2) the Government's Olympia-White River No. 1 Line is metered in
the Company's White River Substation in the 230 kV circuits
over which Electric Power flows;
Exception: there shall be an adjustment for losses between metering
point (1) above, and the Point of Delivery.
12. (a) Fairmount Substation
Location: the point in the Government's Fairmount Substation where
the 69 kV facilities (115 kV upon installation and energization) of
the Parties are connected;
Voltage: 69 kV (115 kV upon installation and energization of such
facilities );
Metering: in the Government's Fairmount Substation. in the 69 kV
circuits (115 kV circuit upon installation and energization) over
which Electric Power flows.
(b) Fairmount Substation
Location: the point in the Government's Fairmount Substation where
the 69 kV facilities of Public Utility District No. 1 of Clallam
County, Washington, and the Government are connected;
Voltage: 69 kV;
Metering: in the Company's Discovery Bay Substation, in the 12.5
kV circuits over which Electric Power is distributed by the
Company;
Exception: there shall be an adjustment for losses between the
Point of Delivery and the metering point.
13. Kitsap Substation
Location: the points in the Government's Kitsap Substation where
the 115 kV facilities of the Parties hereto are connected;
Voltage: 115 kV;
Exhibit C, Page 10 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
Metering: in the Government's Kitsap Substation, in the 115 kV
circuits over which Electric Power flows.
14. Olympia Substation
Location: the point in the Government's Olympia Substation where
the 115 kV facilities of the Parties are connected;
Voltage: 115 kV;
Metering: in the Government's Olympia Substation, in the 115 kV
circuits over which Electric Power flows.
15. Bellingham Substation
Location: the point in the Government's Bellingham Substation
where the 115 kV facilities of the Parties are connected;
Voltage: 115 kV;
Metering: in the Government's Bellingham Substation, in the 115 kV
circuits over which Electric Power flows.
16. Beverly Park Substation
Location: the point in Snohomish's Beverly Park Substation where
the 115 kV facilities of the Government and Snohomish are
connected;
Voltage: 115 kV;
Metering: in Snohomish's Beverly Park Substation, in the 115 kV
circuits over which Electric Power flows.
17. C. W. Paul Substation
Location: the point in the Government's C.W. Paul Substation where
the 500 kV facilities of the Parties are connected;
Voltage: 500 kV;
Metering: in the Company's Tono Substation, in the 115 kV circuits
over which Electric Power flows;
Exhibit C, Page 11 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
Exception: there shall be an adjustment for losses between the
Point of Delivery and the metering point.
18. Sedro Woolley Tap
Location: the point at structure 5/2 at the Sedro Woolley Tap to
the Monroe-Snohomish Line No. 1 where the 230 kV facilities of the
Parties are connected,
Voltage: 230 kV;
Metering: in the Company's Sedro Woolley Substation, in the 230 kV
circuits over which Electric Power flows;
Exception: there shall be an adjustment for losses between the
Point of Delivery and the metering point.
PMLAN-MPSM-W:\PMT\CT\93947\EXC.DOC))
Exhibit D, Page 1 of 1
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
TRANSMISSION LOSS FACTORS
-------------------------
A. Transmission Loss Factor to be Applied to Transmission Pursuant to the
Integration of Resources (IR) Rate Schedule.
Rate Loss
Schedule Factor
-------- ------
IR-93 1.6%(1)
B. Transmission Loss Factor to be Applied to Transmission Pursuant to the
Energy Transmission (ET) Rate Schedule.
Rate Loss
Schedule Factor
-------- ------
ET-93 1.6%(1)
- ------------------------------------------
(1) Bonneville reserves the right to change the Loss Factor in accordance
with section 9(b).
(PMLAN-PMT-W:\PMT\CT\93947\ExD.DOC)