HomeMy WebLinkAbout5.627 Original Contract
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SETTLEMENT AGREEMENT
Bonneville Power Administration 2004 Transmission Rate Case
The undersigned signatories to this Settlement Agreement hereby agree to the following:
1. In the Bonneville Power Administration (BPA) 2004 Transmission Rate Case (Rate Case),
the Transmission Business Line (TBL) will submit a proposal (Initial Proposal) commencing
the rate process for the period FYs 2004 - 2005 (Rate Period) that reflects the following:
a. Current 2002 transmission rates will be increased by 1.5%, and the 2002 transmission
rate schedules and the general rate schedule provisions will otherwise be unchanged
except as explicitly set forth below. If a rate schedule includes a maximum charge for
any rate, the increase in rate level will be applied to the maximum charge. The following
transmission rates will be increased by 1.5%: FPT-02.1; IR-02; NT.02 (Base Charge
and Load Shaping Charge); PTP-02; IS-02; IM-02; and Delivery Charge (Utility Delivery).
The FPT-02.3 charges will remain in effect for FY 2004, and will be increased by 3% for
FY 2005. The increase in the FPT-02.3 rate shall be considered an adjustment to such
rate. Therefore, such rate will next be subject to adjustment on October 1, 2007.
In addition, the General Transfer Agreement Delivery Charge will increase 1.5%.
b. In addition to the above increase, the NT Load Shaping Charge will be increased by an
additional $0.015/kW per month to recover approximately $1 million of the total amount
paid by the TBL to the BPA Power Business Line (PBL) for redispatch associated with
NT service. The NT rate schedule will otherwise be,unchanged.
c. The ACS rate schedule and General Rate Schedule Provision Spill Condition definition
will be as specified in Attachment 1 to this Settlement Agreement.
d. The Unauthorized Increase Charge (UIC) rate under all rate schedules that apply to
Point-te-Point Transmission Service (the PTP, IS, and 1M rate schedules) will equal two
times the transmission rate (which, for short~term service, is based on the length of the
reservation), but shall not In any month exceed 2 times the monthly rate for Long-Term
Firm Transmission Service under such rate schedule. The UIC under the NT rate
schedule will equal two times the NT Base Charge. Examples of the calculation of the
UIC charge are shown in Attachment 2.
The Initial Proposal transmission and ancillary service rates are shown in Attachment 3.
2. Redispatch
a. The signatories recognize and agree that there is value associated with the redispatch of
hydro resources. The signatories further agree that during the FY 2004-2005 Rate
Period they will work towards devising an approach so that hydro-electric and other
generation can be appropriately compensated for redispatch in future rate periods. If
TBL develops information during the Rate Period regarding the amount of redispatch by
PBL, TBL will provide such information to any party requesting it.
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b. The revised Open Access Transmission Tariff (OATT) Attachment K (shown in
Attachment 4 to this Settlement Agreement) will replace the existing Attachment K. The
TBl will compensate the PBl for redispatch services associated with Attachment K by
paying PBl $3 million per year in FY 2004 and FY 2005 for all such services provided
during such period. In the interest of reaching a settlement the signatories have agreed
to this amount of compensation to the BPA PBL for providing redispatch during the Rate
Period. However, nothing in this Settlement Agreement nor actions taken pursuant to
section 2.a, above, will serve as a precedent for any methodology for implementing or
valuing redispatch for future rate periods, or for the purpose of determining the rights of
an RTO or any other regional transmission provider to require redispatch.
c. TBL will submit the revised Attachment K (Attachment 4 to this Settlement Agreement) to
the Federal Energy Regulatory Commission (FERC) as a proposed amendment to BPA's
Open Access Transmission Tariff, and will request that it be effective as of October 1,
2003. The signatories agree not to challenge the approval of the revised Attachment K
by FERC, and, if FERC approves the revised Attachment K without change, the
signatories agree not to challenge such approval in any judicial forum.
3. The TBl will convene a Business Practices and Systems Forum as set forth in Attachment 5
to this Settlement Agreement.
4. No later than October 1, 2003, TBl will have appropriate scheduling and reservation
systems in place so that customers are able to redirect firm transmission service by
modifying points of receipt and delivery and are able to return to their original points upon
expiration of the redirected service, in accord with FERC policy. To the extent permitted by
FERC policy, customers will be permitted to redirect firm transmission irrespective of other
requests for firm transmission if and to the extent that the redirected firm transmission
service would make the same use of the same constrained paths as the original
transmission service to the original points of receipt and delivery. TBl will make all
reasonable efforts to have such systems available for testing by March 1, 2003.
5. The signatories agree not to contest any aspect of the TBl's Initial Proposal, including but
not limited to the level of any transmission or ancillary or control area services rate or any of
the elements thereof, the methodologies and principles used to derive such rates, or any
aspect of the rate schedules, and agree to waive their rights to cross-examination and
discovery with respect thereto. If, however, the TBl does not submit an Initial Proposal
consistent with the terms of this Settlement Agreement, the signatories may contest any
aspect of the TBl's proposal.
6. If no party in the Rate Case contests any aspect of the TBl Initial Proposal, the TBl will
propose to the Administrator that he adopt the TBL's Initial Proposal and establish rates
consistent therewith.
7. The signatories will move the Hearing Officer to specify a date within a reasonable time of
the prehearing conference by which any party to the Rate Case that has not executed this
Settlement Agreement i) must object to the settlement proposed in this Settlement
Agreement and identify each issue such party chooses to preserve for hearing; or ii) be
deemed to have waived any right to object to the settlement proposal or preserve issues for
hearing. If no party objects to the settlement proposal and preserves issues for hearing, the
TBl shall propose to the Administrator that he adopt the Initial Proposal in its entirety. In
the event that any party does so object, the TBl may, but shall not be required to, revise the
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Initial Proposal as it believes appropriate, either after such party states its objection or after
parties file their direct testimony. If the TBL decides not to revise its Initial Proposal, the
TBL will propose to the Administrator that he adopt the Initial Proposal in its entirety. If the
TBL decides to revise its Initial Proposal, the TBL and the parties will meet promptly to
discuss a new procedural schedule that they will propose to the Hearing Officer, allowing
the TBL a reasonable time in which to present a revised proposal and the parties a
reasonable time to respond to such revised proposal. The signatories may contest any
aspect of such revised proposal.
8. If the TBL submits an Initial Proposal consistent with the terms of this Settlement
Agreement, and does not submit a revised proposal pursuant to section 7, the signatories
agree not to enter any evidence into the Rate Case or make any argument in the Rate Case
contesting any provision of section 36 of BPA's current OATT. If the Administrator
establishes transmission rates consistent with the TBL's Initial Proposal and submits such
rates to FERC for confirmation and approval, the signatories agree not to make any such
argument before the FERC or any judicial forum during the Rate Period.
9. Nothing in this Settlement Agreement is intended in any way to alter the Administrator's
authority and responsibility to periodically review and revise the Administrator's transmission
rates or the signatories' rights to challenge such revisions.
10. If the Administrator establishes transmission rates consistent with the Initial Proposal and
submits such rates to FERC for confirmation and approval only under the applicable
standards of the Northwest Power Act and as part of a reciprocity filing, the signatories
agree not to challenge such confirmation and approval of ,such rates or any element thereof,
including the methodologies and principles used to establish such rates, or support or join
any such challenge, and agree not to challenge such rates or any element thereof, including
the methodologies and principles used to establish such rates, in any judicial forum. In
addition, the TBL's commitment in section 4 of this Settlement Agreement shall apply only if
the Administrator establishes rates consistent with the Initial Proposal and submits such
rates to FERC for confirmation and approval.
11. The signatories agree that they will not assert in any forum that anything in this Settlement
Agreement or any action with regard to this Settlement Agreement taken or not taken by any
signatory, the Hearing Officer, the Administrator, FERC, or a court, creates or implies any
procedural or substantive precedent or creates or implies agreement to any underlYing
principle or methodology, or creates any precedent under any contract between BP A and
any signatory.
12. By executing this Settlement Agreement, no signatory waives any right to pursue BPA OATT
dispute resolution procedures consistent with BPA's OATT (including without limitation any
complaint concerning implementation of BPA's OATT) or any claim that a particular charge,
methodology, practice or rate schedule has been Improperly applied.
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13. Nothing in this Settlement Agreement amends any contract or modifies rights or obligations
or limits the remedies available thereunder.
This Settlement Agreement may be executed in counterparts.
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Attachment 1
SCHEDULE ACS-04
ANCILLARY SERVICES AND
CONTROL AREA SERVICES RATE
SECTION I.
AVAILABILITY
This schedule supersedes Schedule ACS-02. It is available to all Transmission Customers
taking service under the Open Access Transmission Tariff and other contractual arrangements.
This schedule is available also for transmission service of a similar nature that may be ordered
by the Federal Energy Regulatory Commission (FERC) pursuant to sections 211 and 212 of the
Federal Power Act (16 V.S.C. ~~824j and 824k). Service under this schedule is subject to
BPA-TBL's General Rate Schedule Provisions (GRSPs).
Ancillary Services are needed with transmission service to maintain reliability within and
among the Control Areas affected by the transmission service. The Transmission Provider is
required to provide, and the Transmission Customer is required to purchase, the following
Ancillary Services: (a) Scheduling, System Control and Dispatch, and (b) Reactive Supply and
V oltage Control from Generation Sources.
The Transmission Provider is required to offer to provide the following Ancillary Services only
to the Transmission Customer serving load within the Transmission Provider's Control Area:
(a) Regulation and Frequency Response and (b) Energy Imbalance. The Transmission
Customer serving load within the Transmission Provider's Control Area is required to acquire
these Ancillary Services, whether from the Transmission Provider, from a third party. or by
self-supply. The Transmission Provider is required to offer to provide (a) Operating Reserve-
Spinning, and (b) Operating Reserve - Supplemental to the Transmission Customer serving
load with generation located in the Transmission Provider's Control Area. The Transmission
Customer serving load with generation located in the Transmission Provider's Control Area is
required to acquire these Ancillary Services, whether from the Transmission Provider, from a
third party, or by self-supply. The Transmission Customer may not decline the Transmission
Provider's offer of Ancillary Services unless it demonstrates that it has acquired the Ancillary
Services from another source. The Transmission Customer must list in its Application which
Ancillary Services it will purchase from the Transmission Provider.
Ancillary Service rates available under this rate schedule are:
1. Scheduling, System Control, and Dispatch Service
2. Reactive Supply and Voltage Control from Generation Sources Service
3. Regulation and Frequency Response Service
4. Energy Imbalance Service
5. Operating Reserve -- Spinning Reserve Service
6. Operating Reserve -- Supplemental Reserve Service
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Control Area Services are available to meet the Reliability Obligations of a party with
resources or loads in the BP A Control Area. A party that is not satisfying all of its Reliability
Obligations through the purchase or self-provision of Ancillary Services must purchase Control
Area Services to meet its Reliability Obligations. Control Area Services are also available to
parties with resources or loads in the BP A Control Area that have Reliability Obligations, but
do not have a transmission agreement with BP A. Reliability Obligations for resources or loads
in the BP A Control Area shall be determined consistent with the applicable North American
Electric Reliability Council (NERC), Western Electricity Coordinating Council (WECC), and
Northwest Power Pool (NWPP) criteria.
Control Area Service rates available under this rate schedule are:
1. Regulation and Frequency Response Service
2. Generation Imbalance Service
3. Operating Reserve -- Spinning Reserve Service
4. Operating Reserve -- Supplemental Reserve Service
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SECTION II. ANCILLARY SERVICE RATES
A. SCHEDULING, SYSTEM CONTROL AND DISPATCH SERVICE
The rates below apply to Transmission Customers taking Scheduling, System Control and
Dispatch Service from BPA-TBL. These rates apply to both firm and non-firm
transmission service. Transmission arrangements on the Network, on the Southern
Intertie, and on the Montana Intertie are each charged separately for Scheduling, System
Control and Dispatch Service.
1. RATES
a. Long- Term Firm PTP Transmission Service and NT Service
The rate shall not exceed $0.166 per kilowatt per month.
b. Short- Term Firm and Non-Firm PTP Transmission Service
For each reservation, the rates shall not exceed:
(1) Monthly, Weekly, and Daily Firm and Non-Firm Service
(a) Days 1 through 5 $0.008 per kilowatt per day
(b) Day 6 and beyond $0.005 per kilowatt per day
(2) Hourly Firm and Non-Firm Service
The rate shall not exceed 0.48 mills per kilowatthour.
2. BILLING FACTORS
a. Point. To-Point Transmission Service
For Transmission Customers taking Point-to-Point Transmission Service
(PTP, IS, and 1M rates), the Billing Factor for each rate specified in
section 1.a, l.b( 1), and for Hourly Firm PTP Transmission Service
specified in 1.b(2) shall be the Reserved Capacity, which is the greater
of:
1. the sum of the capacity reservations at the Point{s) of Receipt, or
2. the sum of the capacity reservations at the Point(s) of Delivery.
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The Reserved Capacity for Firm PTP Transmission Service shall not be
adjusted for any Short-Distance Discounts or for any modifications on a
non-firm basis in determining the Scheduling, System Control and
Dispatch Service Billing Factor.
The Billing Factor for the rate specified in section l.b(2) for Hourly
Non-Firm Service shall be the scheduled kilowatthours.
These Billing Factors apply to all PTP transmission service under the
Open Access Transmission Tariff regardless,of whether the
Transmission Customer actually uses (schedules) the transmission.
b. Network Integration Transmission Service
For Transmission Customers taking Network Integration Transmission
Service, the Billing Factor for the rate specified in section l.a. shall equal
the NT Base Charge Billing Factor determined pursuant to section IILA of
the Network Integration Rate Schedule (NT -02).
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SECTION II. ANCILLARY SERVICE RATES
B. REACTIVE SUPPLY AND VOLTAGE CONTROL FROM GENERATION
SOURCES SERVICE
The rates below apply to Transmission Customers taking Reactive Supply and Voltage
Control from Generation Sources Service from BPA-TBL. These rates apply to both
firm and non-firm transmission service. Transmission arrangements on the Network, on
the Southern Intertie, and on the Montana Intertie are each charged separately for
Reactive Supply and Voltage Control from Generation Sources Service.
1. RATES
a. Long- Term Firm PTP Transmission Service and NT Service
The rate shall not exceed $0.067 per kilowatt per month.
b. Short- Term Firm and Non-Firm PTP Transmission Service
For each reservation, the rates shall not exceed:
(1) Monthly, Weekly, and Daily Firm and Nonfirm Service
(a) Days 1 through 5 $0.003 per kilowatt per day
(b) Day 6 and beyond $0.002 per kilowatt per day
(2) Hourly Firm and Non-Firm Service
The rate shall not exceed 0.19 mills per kilowatthour.
2. BILLING FACTORS
a. Point-To-Point Transmission Service
For Transmission Customers taking Point-to-Point Transmission Service
(PTP, IS, and 1M rates), the Billing Factor for each rate specified in
section La, 1.b(l) and for Hourly Firm PTP Transmission Service
specified in I.b(2) shall be the Reserved Capacity, which is the greater of:
1. the sum of the capacity reservations at the Point(s) of Receipt, or
2. the sum of the capacity reservations at the Point(s) of Delivery.
The Reserved Capacity for Firm PTP Transmission Service shall not be
adjusted for any Short-Distance Discount or for any modifications on a
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non-firm basis in determining the Reactive Supply and Voltage Control
from Generation Sources Service Billing Factor.
The Billing Factor for the rate specified in section 1.b(2) for Hourly Non-
Firm Service shall be the scheduled kilowatthours.
These Billing Factors apply to all PTP transmission service under the
Open Access Transmission Tariff regardless of whether the
Transmission Customer actually uses (schedules) the transmission.
b. Network Integration Transmission Service
For Transmission Customers taking Network Integration Transmission
Service, the Billing Factor for the rate specified in section l.a. shall equal
the NT Base Charge Billing Factor determined pursuant to section UI.A of
the Network Integration Rate Schedule (NT -02).
c. Adjustment for Self-Supply
The Billing Factors in sections 2.a. and 2.b. above may be reduced as
specified in the Transmission Customer's Service Agreement to the extent
the Transmission Customer demonstrates to BP A- TBL' s satisfaction that
it can self-provide Reactive Supply and Voltage Control from Generation
Sources Service.
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SECTION II. ANCILLARY SERVICE RATES
C. REGULATION AND FREQUENCY RESPONSE SERVICE
The rate below for Regulation and Frequency Response Service applies to Transmission
Customers serving loads in the BP A Control Area. Regulation and Frequency Response
Service provides the generation capability to follow the moment-to-moment variations of
loads in the BP A Control Area and maintain the power system frequency at 60 Hz in
conformance with NERC and WECC reliability standards.
1. RATE
The rate shall not exceed 0.30 mills per kilowatthour.
2. BILLING FACTOR
The Billing Factor is the customer's total load in the BP A Control Area, in
kilowatthours.
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SECTION II.
ANCILLARY SERVICE RATES
D. ENERGY IMBALANCE SERVICE
The rates below apply to Transmission Customers taking Energy Imbalance Service
from BP A- TBL. Energy Imbalance Service is taken when there is a difference between
scheduled and actual energy delivered to a load in the BPA Control Area during a
schedule hour.
1. RATES
a. Imbalances Within Deviation Band 1
Deviation Band 1 applies to deviations that are less than or equal to:
i):t 1.5% of the scheduled amount of energy, or ii):t 2 MW, whichever is
larger in absolute value. BPA-TBL will maintain deviation accounts
showing the net Energy Imbalance (the sum of positive and negative
deviations from schedule for each hour) for Heavy Load Hour (HLH) and
Light Load Hour (LLH) periods. Return energy may be scheduled at any
time during the month to bring the deviation account balances to zero at
the end of each month. BPA-TBL will approve the hourly schedules of
return energy. The customer shall make the arrangements and submit the
schedule for the balancing transaction.
The following rates will be applied when a deviation balance remains at
the end of the month:
(i) When the monthly net energy (determined for HLH and LLH
periods) taken by the Transmission Customer is greater than the
energy scheduled, the charge is BPA's incremental cost based on
the applicable average HLH and average LLH incremental cost for
the month.
(ii) When the monthly net energy (determined for HLH and LLH
periods) taken by the Transmission Customer is less than the
energy scheduled, the credit is BP A's incremental cost based on
the applicable average HLH and LLH incremental cost for the
month.
b. Imbalances Within Deviation Band 2
Deviation Band 2 applies to the portion of the deviation i) greater than
:t 1.5% of the scheduled amount of energy or:t 2 MW, whichever is
larger in absolute value, ii) up to and including :t 7.5% of the scheduled
amount of energy or:t 10 MW, whichever is larger in absolute value.
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(i) When energy taken by the Transmission Customer in a schedule
hour is greater than the energy scheduled, the charge is 110%
of BPA's incremental cost.
(ii) When energy taken by the Transmission Customer in a schedule
hour is less than the scheduled amount, the credit is 90% ofBPA's
incremental cost.
c. Imbalances Within Deviation Band 3
Deviation Band 3 applies to the portion of the deviation i) greater than
:t 7.5% of the scheduled amount of energy, or ii) greater than :t 10 MW
of the scheduled amount of energy, whichever is larger in absolute value.
(i) When energy taken by the Transmission Customer in a schedule
hour is greater than the energy scheduled, the charge is 125% of
BPA's highest incremental cost that occurs during the that day.
The highest daily incremental cost shall be determined separately
for HLH and LLH.
(ii) When energy taken by the Transmission Customer in a schedule
hour is less than the scheduled amount, the credit is 75% of BPA's
lowest incremental cost that occurs during that day. The lowest
daily incremental cost shall be determined separately for HLH and
LLH.
2. OTHER RATE PROVISIONS
a. BP A Incremental Cost
BPA's incremental cost will be based on an hourly energy index in the
PNW. If no adequate hourly index exists, an alternative index will be
used. The index to be used will be posted on the OASIS at least 30 days
prior to use for determining the BP A incremental cost and will not be
changed more often than once per year unless BPA-TBL determines that
the existing index is no longer a reliable price index.
b. Spill Conditions
For any day that the Federal System is in a Spill Condition, no credit is
given for negative deviations (actual energy delivered is less than
scheduled) for any hour of that day.
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c. Intentional Deviation
For any hour(s) that an imbalance is determined by BPA-TBL to be an
Intentional Deviation:
(1) No credit is given when energy taken is less than the scheduled
energy.
(2) When energy taken exceeds the scheduled energy, the charge is the
greater of: i) 125% of BP A's highest incremental cost that occurs
during that day, or ii) 100 mills per kilowatthour.
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SECTION II. ANCILLARY SERVICE RATES
E. OPERATING RESERVE .. SPINNING RESERVE SERVICE
The rates below apply to Transmission Customers taking Operating Reserve -- Spinning
Reserve Service from BPA-TBL and to generators in the BPA Control Area for
settlement of energy deliveries. Spinning Reserve Service is needed to serve load
immediately in the event of a system contingency. For a Transmission Customer's load
(located inside or outside of the BP A Control Area) served by generation located in the
BP A Control Area, the Transmission Customer's Spinning Reserve Requirement shall be
determined consistent with applicable NERC, WECC and NWPP standards.
1. RATES
a. The rate shall not exceed 8.39 mills per kilowatthour of the Transmission
Customer's Spinning Reserve Requirement.
b. For energy delivered, the generator shall, as directed by BP A- TBL, either:
(i) Purchase the energy at the hourly market index price applicable at
the time of occurrence, or
(ii) Return the energy at the times specified by BP A- TBL.
2. BILLING FACTORS
a. The Billing Factor for Spinning Reserve Service is determined in
accordance with applicable WECC and NWPP standards. Application of
current standards establish a minimum Spinning Reserve Requirement
equal to the sum of:
(i) Two and a half percent (2.5%) of the hydroelectric generation
dedicated to the Transmission Customer's firm load responsibility;
and
(ii) Three and a half percent (3.5%) of non-h ydroelectric generation
dedicated to the Transmission Customer's firm load responsibility.
b. The Billing Factor for energy delivered when Spinning Reserve Service is
called upon is the energy delivered, in kilowatthours.
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SECTION II. ANCILLARY SERVICE RATES
F. OPERATING RESERVE -- SUPPLEMENTAL RESERVE SERVICE
The rates below apply to Transmission Customers taking Operating Reserve --
Supplemental Reserve Service from BPA-TBL and to generators in the BPA Control
Area for settlement of energy deliveries. Supplemental Reserve Service is available
within a short period of time to serve load in the event of a system contingency. For a
Transmission Customer's load (located inside or outside the BPA Control Area) served
by generation located in the BPA Control Area, the Transmission Customer's
Supplemental Reserve Requirement shall be determined consistent with applicable
NERC, WECC and NWPP standards.
1. RATES
a. The rate shall not exceed 8.39 mills per kilowatthour of Supplemental
Reserve Requirement.
b. For energy delivered, the Transmission Customer (for interruptible
imports only) or the generator shall, as directed by BPA-TBL, either:
(i) Purchase the energy at the hourly market index price applicable at
the time of occurrence, or
(ii) Return the energy at the times specified by BP A- TBL.
The TransmissIOn Customer shall be responsible for the settlement of
delivered energy associated with interruptible imports (see section
2.a(iii)). The generator shall be responsible for the settlement of delivered
energy associated with generation in the BPA Control Area.
2. BILLING FACTORS
a. The Billing Factor for Supplemental Reserve Service is determined in
accordance with applicable WECC and NWpP standards. Application of
current standards establish a minimum Supplemental Reserve
Requirement equal to the sum of:
(i) Two and one half percent (2.5%) of the hydroelectric generation
dedicated to the Transmission Customer's firm load responsibility,
plus
(ii) Three and one half percent (3.5%) of non-hydroelectric generation
dedicated to the Transmission Customer's firm load responsibility,
plus
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(iii) Any power scheduled into the BP A Control Area that can be
interrupted on ten (to) minutes' notice.
b. The Billing Factor for energy delivered when Supplemental Reserve
Service is called upon is the energy delivered, in kilowatthours.
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"
SECTION III.
CONTROL AREA SERVICE RATES
A. REGULATION AND FREQUENCY RESPONSE SERVICE
The rate below applies to all loads in the BPA Control Area that are receiving Regulation
and Frequency Response Service from the BP A Control Area, and such Regulation and
Frequency Response Service is not provided for under a BP A- TBL transmission
agreement. Regulation and Frequency Response Service provides the generation
capabIlity to follow the moment-to-moment variations of loads in the BP A Control Area
and maintain the power system frequency at 60 Hz in conformance with NERC and
WECC reliability standards.
1. RATE
The rate shall not exceed 0.30 mills per kilowatthour.
2. BILLING FACTOR
The Billing Factor is the customer's total load in the BPA Control Area, in
kilowatthours.
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. .
SECTION III.
CONTROL AREA SERVICE RATES
B. GENERATION IMBALANCE SERVICE
The rates below apply to generation resources in the BP A Control Area if Generation
Imbalance Service is provided for in an interconnection agreement or other arrangement.
Generation Imbalance Service is taken when there is a difference between scheduled and
actual energy delivered from generation resources in the BPA Control Area during a
schedule hour.
1. RATES
a. Imbalances Within Deviation Band 1
Deviation Band 1 applies to deviations that are less than or equal to:
i) ::t 1.5% of the scheduled amount of energy, or ii) ::t 2 MW, whichever is
larger in absolute value. BPA-TBL will maintain deviation accounts
showing the net Generation Imbalance (the sum of positive and negative
deviations from schedule for each hour) for Heavy Load Hour (HLH) and
Light Load Hour (LLH) periods. Return energy may be scheduled at any
time during the month to bring the deviation account balances to zero at
the end of each month. BP A- TBL will approve the hourly schedules of
return energy. The customer shall make the arrangements and submit the
schedule for the balancing transaction.
The following rates will be applied when a deviation balance remains at
the end of the month:
(i) When the monthly net energy (determined for HLH and LLH
periods) delivered from a generation resource is less than the
energy scheduled, the charge is BPA's incremental cost based on
the applicable average HLH and average LLH incremental cost for
the month.
(ii) When the monthly net energy (determined for HLH and LLH
periods) delivered from a generation resource is greater than the
energy scheduled, the credit is BPA's incremental cost based on
the applicable average HLH and LLH incremental cost for the
month.
b. Imbalances Within Deviation Band 2
Deviation Band 2 applies to the portion of the deviation i) greater than
:t 1.5% of the scheduled amount of energy or:t 2 MW, whichever is
larger in absolute value, ii) up to and including ::t 7.5% of the scheduled
amount of energy or::t 10 MW, whichever is larger in absolute value.
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(i) When energy delivered in a schedule hour from the generation
resource is less than the energy scheduled, the charge is 110%
of BP A's incremental cost.
(ii) When energy delivered from the generation resource is greater
than the scheduled amount, the credit is 90% of BPA's incremental
cost.
c. Imbalances Within Deviation Band 3
Deviation Band 3 applies to the portion of the deviation i) greater than
::t 7.5% of the scheduled amount of energy, or ii) greater than ::t 10 MW
of the scheduled amount of energy, whichever is larger in absolute value.
(i) When energy delivered in a schedule hour from the generation
resource is less than the energy scheduled, the charge is 125% of
BPA's highest incremental cost that occurs during that day. The
highest daily incremental cost shall be determined separately for
HLH and LLH.
(ii) When energy delivered from the generation resource is greater
than the scheduled amount, the credit is 75% of BPA's lowest
incremental cost that occurs during that day. The lowest daily
incremental cost shall be determined separately for HLH and LLH.
2. OTHER RATE PROVISIONS
a. BPA Incremental Cost
BPA's incremental cost will be based on an hourly energy index in the
PNW. If no adequate hourly index exists, an alternative index will be
used. The index to be used will be posted on the OASIS at least 30 days
prior to use for determining the BPA incremental cost and will not be
changed more often than once per year unless BPA-TBL determines that
the existing index is no longer a reliable price index.
b. Spill Conditions
For any day that the Federal System is in a Spill Condition, no credit is
given for negative deviations (actual generation greater than schedules) for
any hour of that day.
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c. Intentional Deviation
No credit is given for negative deviations (actual generation greater than
schedules) for any hour(s) that the imbalance is an Intentional Deviation
(as determined by BPA-TBL).
For positive deviations (actual generation less than schedules) which are
determined by BPA-TBL to be Intentional Deviations, the charge is the
greater of: i) 125% of BPA's highest incremental cost that occurs during
that day, or ii) 100 mills per kilowatthour.
d. Exemptions from Deviation Band 3
The following resources are not subject to Deviation Band 3:
i) wind resources; and
ii) new generation resources undergoing testing before commercial
operation for up to 90 days.
All such deviations greater than f: 1.5% or :t 2 MW will be charged
consistent with section I.b., Imbalances Within Deviation Band 2.
21
SECTION III.
CONTROL AREA SERVICE RATES
C. OPERATING RESERVE .. SPINNING RESERVE SERVICE
Operating Reserve -- Spinning Reserve Service must be purchased by a party with
generation in the BPA Control Area that is receiving this service from BPA-TBL, and
such Spinning Reserve Service is not provided for under a BPA-TBL transmission
agreement. Service is being received if there are no other qualifying resources providing
this required reserve service in conformance with NERC, WECC and NWPP standards.
1. RA TES
a. The rate shall not exceed 8.39 mills per kilowatthour of Spinning Reserve
Requirement
b. For energy delivered, the customer shall, as directed by BPA-TBL, either:
(i) Purchase the energy at the hourly market index price applicable at
the time of occurrence, or
(ii) Return the energy at the times specified by BPA-TBL.
2. BILLING FACTORS
a. The Billing Factor for Spinning Reserve Service is determined in
accordance with applicable WECC and NWPP standards. Application of
current standards establish a minimum Spinning Reserve Requirement
equal to the sum of:
(i) Two and one half percent (2.5%) of the hydroelectric generation
dedicated to the customer's firm load responsibility, plus
(ii) Three and one half percent (3.5%) of non-hydroelectric generation
dedicated to the customer's firm load responsibility.
b. The Billing Factor for energy delivered when Spinning Reserve Service is
called upon is the energy delivered, in kilowatthours.
22
, .
SECTION III.
CONTROL AREA SERVICE RATES
D. OPERATING RESERVE .. SUPPLEMENTAL RESERVE SERVICE
Operating Reserve -- Supplemental Reserve Service must be purchased by a party with
generation in the BP A Control Area that is receiving this service from BP A - TBL, and
such Supplemental Reserve Service is not provided for under a BPA.TBL transmission
agreement. Service is being received if there are no other qualifying resources providing
this required reserve service in conformance with NERC, WECC and NWPP standards.
1. RATES
a. The rate shall not exceed 8.39 mills per kilowatthour of Supplemental
Reserve Requirement
b. For energy delivered, the customer shall, as directed by BPA-TBL, either:
(i) Purchase the energy at the hourly market index price applicable at
the time of occurrence, or
(ii) Return the energy at the times specified by BP A- TBL.
2. BILLING FACTORS
a. The Billing Factor for Supplemental Reserve Service is determined in
accordance with applicable WECC and NWPP guidelines. Application
of current guidelines establish a minimum Supplemental Reserve
Requirement equal to the sum of:
(i) Two and one half percent (2.5%) of the hydroelectric generation
dedicated to the customer's firm load Responsibility, plus
(ii) Three and one half percent (3.5%) of non-hydroelectric generation
dedicated to the customer's firm load responsibility, plus
(iii) Any power scheduled into the BP A Control Area that can be
interrupted on ten (10) minutes' notice.
b. The Billing Factor for energy delivered when Supplemental Reserve
Service is called upon is the energy delivered, in kilowatthours.
23
" .
SECTION IV.
ADJUSTMENTS, CHARGES, AND OTHER RATE PROVISIONS
A. RATE ADJUSTMENT DUE TO FERC ORDER UNDER FPA ~212
Customers taking service under this rate schedule are subject to the Rate Adjustment
Due to FERC Order under FPA ~212 specified in section n.D of the GRSPs.
24
" .
GRSP - Section III Definitions
61. Spill Condition
Spill Condition, for the purpose of determining credit or payment for Deviations under
the Energy Imbalance and Generation Imbalance rates, exists when spill physically
occurs on the BP A system due to lack of load or market. Spill due to lack of load or
market typically occurs during periods of high flows or flood control implementation, but
can also occur at other times. Discretionary spill, where BPA may choose whether to
spill, does not constitute a Spill Condition. Spill for fish is included in discretionary spill
and is not a Spill Condition.
25
.. I I ,.
Attachment 2
Unauthorized Increase Charge (UIC) Examples
1. Reservation
The customer purchases 10 MWs of PTP for 9 days, January 29 to February 6.
Unauthorized Increase (UI)
On January 30, the customer schedules 15 MWs under this reservation, a UI of 5 MWs.
This is the highest UI for this Reservation for the month of January.
PTP rate for 9-dav service (Short-Term Weeklv Service)
(5 days*.047) + ( 4 days*.035) = $0.375 per kW
PTP rate for Lana-Term service
$1.028 per kW per month
Since the 9-day rate for short-term weekly service is less than the monthly rate for long-
term service, the 9-day rate is used.
UIC rate
2 * .375 = $0.75 per kW
UIC charae for Januarv
5,000 kW * $0.75 per kW = $3,750
26
. ' I l
2. Reservation
The customer purchases 10 MWs of IS for 40 days, January 20 to February 28.
Unauthorized Increase (UI)
On January 30, the customer schedules 15 MWs under this reservation, a UI of 5 MWs.
This is the highest UI for this Reservation for the month of January.
IS rate for 40-dav service (Short-Term Monthlv Service)
(5 days" .054) + (35 days" .040) = $1.670 per kW
IS rate for Long-Term Service
$1.176 per kW per month
Since the 4D-day rate for short-term monthly service is greater than the monthly
rate for long-term service, the monthly rate for long-term service is used to
calculate the Ute.
UIC rate
2 .. 1.176 = $2.352 per kW
UIC charae for Januarv
5,000 kW .. $2.352 per kW = $11,760
27
. . I ..
Attachment 3
Initial Proposal Rates
FPT -04.1
Main Grid
· Distance
. Interconnection Terminal
· Terminal
· Miscellaneous Facilities
Secondary System
· Distance
· Transformation
· Intermediate Terminal
· Interconnection Terminal
$0.0511/mile
0.53
0.59
2.91
$0.5021/mile
5.49
2.12
1.50
FPT-04.3 (FY 2005) *
Main Grid
· Distance
· Interconnection Terminal
· Terminal
· Miscellaneous Facilities
Secondary System
· Distance
· Transformation
· Intermediate Terminal
· Interconnection Terminal
$0.0518/mile
0.54
0.60
2.96
$0.5095/mile
5.57
2.15
1.52
. FPT-04.3 rates will remain at FPT-02.3Ievels for FY 2004, and
increase by 3% (shown here) over FPT-02.3 levels for FY 2005.
IR-G4
1.261
NT -04
· Base
· Load Shaping
1.028
0.425 "
"(reflects 1.5% + $1M)
PTP-04
· Long-Term
· Short-Term (per day)
· Days 1-5
· Day 6 and beyond
· Hourly
1.028
.047
.035
2.96 mills/kWh
28
. \' ..
Attachment 3
Initial Proposal Rates (cont'd)
15-04
· Long-Term
. Short-Term (per day)
· Days 1-5
. Day 6 and beyond
· Hourly
IM-04
· Long-Term
. Short-Term (per day)
· Days 1-5
· Day 6 and beyond
· Hourly
Utility Delivery Charge
GT A Delivery Charge
Unauthorized Increase Charge
ACS-04
Scheduling
· Long-Term
· Short-Term (per day)
· Days 1-5
· Day 6 and beyond
· Hourly
Generation Reactive
· Long-Term
· Short-Term (per day)
· Days 1-5
· Day 6 and beyond
· Hourly
Regulation and Frequency
Response (Ancillary &
Control Area rates)
Operating Reserves
(Ancillary & Control Area rates)
29
1.176
.054
.040
3.39 millslkWh
1.258
.058
.042
3.61 mills/kWh
.946
.946
· PTP Service: Not to
exceed 2 times the
monthly rate for
Long-Term Service
· NT Service:
$2.056/kW/mo
.166
.008
.005
0.48 millslkWh
.067
.003
.002
0.19 millslkWh
.30 mills/kWh
8.39 mills/kWh
4 \ I ~
Attachment 4
Open Access Transmission Tariff
Revised Attachment K
For the period October 1, 2003, through September 30, 2005, to the extent the Transmission
Provider determines that redispatch of Network Resources is necessary to maintain Network
Integration Transmission (NT) Service, the Transmission Provider shall implement redispatch in
accordance with the provisions of this Attachment K. Attachment K addresses only
circumstances in which the Tariff requires NT and Point-to-Point (PTP) uses on a constraint be
reduced on a comparable basis.
1. The Transmission Provider shall not issue redispatch instructions under this
Attachment K to increase A TC.
2. The BPA Power Business Line (PBL) will inform the Transmission Provider of all non-
power constraints that limit the PBL's ability to redispatch generation resources. The
Transmission Provider will not violate these non-power constraints unless an emergency
situation leaves no other alternative for maintaining system reliability or providing safety
to individuals or property. Notwithstanding any other provision of Attachment K, the
protection of transmission system reliability and the safety of people and property will be
the primary criteria the Transmission Provider will use in an emergency situation.
3. PBl will provide the Transmission Provider federal hydroelectric generation resource set
points. The Transmission Provider may request changes to such set points Not all
changes to set points are redispatch.
4. For redispatch that occurs within the hour of delivery:
If the Transmission Provider determines that a redispatch of federal hydro-electric
projects is necessary to maintain the reliability of the FCRTS in real-time and the
Transmission Provider is unable to calculate the portion of the constraint attributable to
NT schedules, the Transmission Provider may redispatch the federal hydro-electric
projects as necessary to relieve the constraint for the remainder of the hour and, if the
event occurs twenty minutes past the hour, for the next hour also. However, the
Transmission Provider must make the determination described in section 5 as soon as
possible, not to exceed 100 minutes after the need for redispatch arises, and adjust the
redispatch instructions accordingly.
30
. ~! .
5. For Day-ahead and Hour-ahead redispatch:
a. The Transmission Provider will use redispatch only to manage congestion on the
FeRTS that would impact NT schedules. The Transmission Provider will redispatch
the system only to the extent necessary to maintain the NT schedules.
b. The Transmission Provider will not issue any redispatch instructions until it has
curtailed all non-firm schedules across the constrained path.
c. If the Transmission Provider determines that a constraint can be relieved by
redispatching federal hydro-electric projects, the Transmission Provider will
determine what portion of the constraint is caused by NT schedules and what portion
is caused by PTP schedules. Then the Transmission Provider will issue a redispatch
instruction in an amount that will relieve the NT portion of the constraint and will
curtail the PTP schedules in an amount necessary to relieve the PTP portion of the
constraint.
d. If the Transmission Provider determines that the portion of the constraint caused by
NT schedules cannot be relieved by only redispatching federal hydro-electric
projects, the Transmission Provider will contact the PBl schedulers and inform the
PBl schedulers of the amount of NT schedule associated with the constraint. The
PBl schedulers will attempt to relieve the constraint by the least cost means,
including, but not limited to, purchasing alternative transmission from a third party,
purchasing replacement generation from a third-party and redispatching federal
generation accordingly, or requesting third party generation to decrease and using
federal generation to replace the third-party generation. In making these
arrangements the PBl will act as a purchasing agent for the Transmission Provider.
6. The Transmission Provider will not request redispatch for any purpose under the Tariff
other than that stated herein or otherwise required by the Tariff.
31
.. , , ~
~\
l.
Attachment 5
Business Practices and Systems Forum
BPA TBL will meet with Transmission Customers at least three times between November 2002
and September 2003 to discuss Business Practices and systems used to implement TBL's
Open Access Transmission Tariff and its Transmission and Ancillary Service Rate Schedules.
TBL agrees to discuss the following issues identified during TBL Rate Case Workshops held in
September and October 2002:
1. TBL's Business Practices on Operating Reserves - Spinning and Supplemental Services,
2. Real Power Losses,
3. Curtailment during Real-Time, including PTP curtailment based on contract demand vs.
schedules, and
4. Scheduling practices and associated systems, including wind resource scheduling.
Prior to the first meeting, TBL will draft and circulate principles to govern the meetings. TBl will
post on its website the meeting location and agenda at least 10 days prior to each meeting. The
first meeting will take place no later than December 13, 2002.
TBL and the Transmission Customers agree to use best efforts to ensure that the appropriate
technical, and other, staff attend the meetings (either in person or by telephone conference) to
facilitate meaningful discussions.
The parties agree that these meetings are designed to supplement, not revise, TBL's existing
process to develop its Business Practices and systems. Further, while TBL agrees to work in
good faith to discuss and address Transmission Customer concerns, TBl retains discretion to
determine whether to make any changes to its Business Practices or systems as a result of the
meetings. TBL will use the meetings to solicit feedback for use in developing or revising its
Business Practices or systems, but is under no obligation to develop new Business Practices or
systems or make any changes to existing Business Practices or systems. If TBL changes its
Business Practices or systems, whether on its own or as a result of Transmission Customer
input at the meetings, it will use its best efforts to implement those changes in a timely manner
pursuant to TBl's established Business Practice process. The Transmission Customers retain
all rights under TBl's Open Access Transmission Tariff, as it may be amended, to challenge
TBl's Business Practices.
32