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The Central Valley Project, the California-Oregon Transmission Project, and the Pacific Alternating Current Intertie
Note: EPA no longer updates this information, but it may be useful as a reference or resource.
[Federal Register: May 12, 2004 (Volume 69, Number 92)]
[Notices]
[Page 26370-26378]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr12my04-39]
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DEPARTMENT OF ENERGY
Western Area Power Administration
The Central Valley Project, the California-Oregon Transmission
Project, and the Pacific Alternating Current Intertie
AGENCY: Western Area Power Administration, DOE.
ACTION: Notice of proposed power, transmission, and ancillary services
rates.
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SUMMARY: The Western Area Power Administration (Western) is proposing
new rates for ancillary, Western power, the Central Valley Project
(CVP) transmission, the California-Oregon Transmission Project (COTP)
transmission, and the Pacific Alternating Current Intertie (PACI)
transmission services. PACI transmission is a new service. The current
rates for existing services expire December 31, 2004, which coincides
with the expiration of the current CVP marketing plan. The CVP 2004
Power Marketing Plan goes into effect January 1, 2005. The proposed
rates will apply under the 2004 Power Marketing Plan.
The proposed rates will provide sufficient revenue to pay all
annual costs, including interest expense, and repay required investment
within the allowable time period. Rate impacts are detailed in a rate
brochure available to all interested parties. The proposed new rates
are scheduled to go into effect on January 1, 2005, and will remain in
effect through September 30, 2009. This Federal Register notice
initiates the public process to replace the existing approved rates
that expire December 31, 2004.
DATES: The consultation and comment period will begin on the date of
publication of the Federal Register notice and will end August 10,
2004. Western will present a detailed explanation of the proposed rates
at a public information forum. The public information forum date is:
May 18, 2004, 1 p.m. PDT, Folsom, CA.
Western will accept oral and written comments at a public comment
forum. The public comment forum date is: June 17, 2004, 1 p.m. PDT,
Folsom, CA.
Western will accept written comments anytime during the
consultation and comment period.
ADDRESSES: Send written comments to Ms. Debbie R. Dietz, Sierra Nevada
Customer Service Region, Western Area Power Administration, 114
Western will accept written comments anytime during the consultation
and comment period. Western will post comments received within the
consultation and comment period on Western's external Web site at
http://www.wapa.gov/sn/initiatives/post2004/rates/. 
Western
must receive written comments by the end of the consultation and comment
period to ensure consideration in Western's decision process.
The public information and public comment forum location is: Folsom
Community Center, 52 Natoma Street, Folsom, CA.
FOR FURTHER INFORMATION CONTACT: Ms. Debbie Dietz, Rates Manager,
Sierra Nevada Customer Service Region, Western Area Power
Administration, 114 Parkshore Drive, Folsom, CA 95630-4710, telephone
(916) 353-4453, e-mail ddietz@wapa.gov.
SUPPLEMENTARY INFORMATION: This Federal Register notice initiates the
public process to replace the existing rates that expire December 31,
2004. Western will estimate the power revenue requirement for January
through September 2005 prior to January 1, 2005. Thereafter, an annual
power revenue requirement will be estimated prior to the start of each
fiscal year (FY). The power revenue requirement includes operation and
maintenance (O&M) expenses, purchased power for project use and first
preference customers' loads, interest and other expenses (including any
other statutorily required costs or charges), and investment repayment
for the CVP and the Washoe Project annual power revenue requirement
that remains after project use loads are met. In addition, the annual
power revenue requirement includes any charges or credits associated
with the creation, termination, or modification to any tariff,
contract, or rate schedule approved or accepted by the Federal Energy
Regulatory Commission (Commission) or other regulatory body, and any
charges or credits from the Host Control Area (HCA). To the extent
possible, these charges or credits applied to Western will be passed
through directly to the appropriate customer in the same manner Western
is charged or credited. If the Commission or other regulatory body
charges or credits, or the HCA charges or credits cannot be passed
through to the appropriate customer in the same manner Western is
charged or credited, the charges or credits will be passed through as
part of the power revenue requirement. Revenues from project use,
transmission, ancillary services, and other services are applied to the
power revenue requirement, and the remainder is collected from Base
Resource and first preference customers.
Under the 2004 Power Marketing Plan, each preference customer
(except first preference customers) that has signed a Base Resource
contract is a Base Resource customer and is allocated a percentage of
the Base Resource. Base Resource is defined in the 2004 Power Marketing
Plan as CVP and Washoe Project power output and power purchase
contracts extending beyond 2004 determined by Western to be available
for marketing, after meeting the requirements of project use and first
preference customers, and any adjustments for maintenance, reserves,
transformation losses, and certain ancillary services.
The CVP has a unique type of preference customer called a first
preference customer. A first preference customer is defined in the 2004
Power Marketing Plan as a preference customer and/or a preference
entity (an entity qualified to use, but not using, preference power)
within a county of origin (Trinity, Calaveras, and Tuolumne) as
specified under the Trinity River Division Act (69 Stat. 719) and the
New Melones project provisions of the Flood Control Act of 1962 (76
Stat.1173, 1191-1192).
Proposed Rate Formula for First Preference Customer Power
To have a consistent billing process for Base Resource and first
preference customers, before the start of each FY, a percentage will be
developed for each first preference customer based on the following
formula:
[GRAPHIC]
[TIFF OMITTED]
TN12MY04.023
[[Page 26371]]
Where:
FP Customer load = A first preference customer's forecasted annual load
in megawatthours (MWh).
Gen = The forecasted annual CVP and Washoe generation (MWh).
Power Purchases = Power purchased for project use and first preference
loads (MWh).
Project Use = The forecasted annual project use load (MWh).
For January through September 2005, the same formula will be used
with data for the 9-month period instead of annual data.
During March of each year (except March 2005), each first
preference customer's percentage will be reviewed by Western. The
review will take into account the actual and estimated current FY data
used in the first preference customer's percentage formula. If
Western's review results in a change in a first preference customer's
percentage of more than one-half of 1 percent, the percentage will be
revised for that first preference customer for the remainder of the
current FY. The review will not occur in March 2005 because the 2004
Power Marketing Plan will have been in effect for a very short period
of time.
Each first preference customer's monthly charges are determined by
the following formula: First preference customer's monthly costs = (All
first preference customers' share of 6-month power revenue requirement
divided by 6) times the first preference customer's percentage.
The first preference customers' share of the annual power revenue
requirement is determined by summing all the first preference
customers' percentages and multiplying that sum by the annual power
revenue requirement. Starting with FY 06, the first preference
customers' share of the annual power revenue requirement is divided
into two 6-month revenue requirements. The first 6-month revenue
requirement will be collected from October through March and the second
6-month revenue requirement will be collected from April through
September. The estimated April through September power revenue
requirement will be reviewed by Western in March (with the exception of
March 2005). Western's review will analyze financial data relating to
the power revenue requirement for October through February, to the
extent it is available, as well as forecasted data for March through
September. If, as a result of Western's review, the power revenue
requirement changes by $5 million or more, the April through September
power revenue requirement will be revised.
After the first preference customers' percentages have been
calculated for January through September 2005, their share of the power
revenue requirement will be determined and divided by nine to calculate
the monthly first preference customers' revenue requirement.
Proposed Rate Formula for Base Resource
Base Resource customer's monthly cost = Base Resource customer's
percentage times the Base Resource monthly revenue requirement.
A customer's Base Resource percentage may be adjusted as provided
for in their contract; e.g., participation in the exchange program.
After the first preference customers' share of the annual power
revenue requirement has been determined, the remainder of the annual
power revenue requirement is recovered from the Base Resource customers
(Base Resource revenue requirement). The estimated annual Base Resource
revenue requirement will be collected in two 6-month periods; 25
percent will be collected from October through March and 75 percent
will be collected from April through September. Allocating the Base
Resource revenue requirement in this manner more closely aligns the
Base Resource revenue requirement with the Base Resource available
during the two 6-month periods. A Base Resource monthly revenue
requirement is calculated by dividing the Base Resource estimated 6-
month revenue requirement by 6 months. The estimated April through
September Base Resource revenue requirement will be reviewed by Western
in March. Western's review will analyze financial data relating to the
Base Resource revenue requirement for October through February, to the
extent it is available, as well as forecasted data for March through
September. If, as a result of Western's review, there is a change in
the Base Resource revenue requirement of $5 million or more, the April
through September Base Resource revenue requirement will be revised. A
customer's Base Resource costs are independent of the Base Resource
received. Base Resource energy not used by any preference customer
would be sold, if possible, and the revenues would reduce the Base
Resource revenue requirement.
Before January 1, 2005, Western will estimate the power revenue
requirement for January through September 2005 and calculate the first
preference customers' share. Once the first preference customers' share
of the power revenue requirement has been determined, the Base Resource
revenue requirement will be allocated 25 percent to the 3-month period,
January through March 2005, and 75 percent to the 6-month period, April
through September 2005. Western will not review the power revenue
requirement, the Base Resource revenue requirement, or the first
preference customers' percentages in March 2005, since very limited
actual data under the 2004 Power Marketing Plan would be available in
March 2005. The estimated January through September 2005 power revenue
requirement is $30 million of which the first preference customers'
share is 3.7 percent, or $123,333 per month. The estimated January
through September 2005 Base Resource revenue requirement is
$28,890,000. For January through March 2005, the estimated Base
Resource revenue requirement is $2,407,500. For April through September
2005, the estimated Base Resource monthly revenue requirement is
$3,611,250. This estimated data is subject to change prior to the rates
taking effect. The estimated data for the power revenue requirement,
first preference customers' percentages, and the Base Resource Revenue
Requirement for January through September 2005 will be finalized by
Western on or before December 1, 2004.
Proposed Rate Formula for Custom Product Power
All costs associated with custom product power will be recovered
through a power rate formula that passes through the cost of the
purchase to a specific customer(s). Under the 2004 Power Marketing
Plan, custom product power is power supplied by Western to meet a
customer's load. Western may make custom product power purchases for a
group of customers or for an individual customer. Costs for custom
product power purchases that are funded in advance by the customer(s)
will be passed through to that customer(s) based on the power scheduled
to the customer(s). Custom product power funded in advance that is
surplus to the load requirements of the customer(s) will be sold. If
the customer(s) fails to have an account available to receive the
proceeds from the sale of surplus custom product power, the proceeds
are forfeited to Western and will be applied to the custom product
power purchase cost for the customer(s).
If the custom product power purchase is funded through
appropriations or use of receipts authority, the cost of the custom
product power is passed through to the customer(s) that uses the power.
Custom product power funded
[[Page 26372]]
through appropriations or use of receipts authority that is surplus to
the load requirements of the customer(s) will be sold. Proceeds from
the sale of surplus custom product power funded through use of receipts
or appropriations will be applied to the custom product power purchase
cost for the customer(s).
Table 1.--Comparison of Existing Rates and Proposed Rate Formulas for Western Power
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Proposed Percent
Power service Existing rate rate formula change
-----------------------------------------------------------------------------------
Contract Rate of Delivery.......... 30.83 mills/kWh... N/A................ N/A.
Base Resource & First Preference... N/A............... Percent of Annual N/A.
Power Revenue
Requirement.
Custom Product Power............... N/A............... Pass-through....... N/A.
-----------------------------------------------------------------------------------
The 2004 Power Marketing Plan does not offer the same type of power
service that is available under the current power marketing plan. Under
the current power marketing plan, a contract rate of delivery allocates
an amount of capacity with associated energy to each preference
customer, and the customer can take up to that amount of capacity in
any hour. The Base Resource and first preference power is primarily
hydrogeneration available subject to water conditions and operating
constraints. Custom product power is power purchased by Western to meet
a customer's load and may include long- and short-term purchases at
various rates.
Proposed Rate Formula for CVP Transmission
The proposed rate formula for CVP firm transmission includes three
components:
Component 1:
[GRAPHIC]
[TIFF OMITTED]
TN12MY04.024
Where:
TRR = Transmission revenue requirement.
TTc = The total transmission capacity under long-term contract between
Western and other parties, including point-to-point and existing pre-
Open Access Transmission Tariff (pre-OATT) transmission contracts.
NITSc = The coincident peak of network integrated transmission service
(NITS) customers at the time of the CVP transmission system peak. For
rate design purposes, Western's use of the transmission system to meet
its statutory obligations is treated as NITS.
Component 2: Any charges or credits associated with the creation,
termination, or modification to any tariff, contract, or rate schedule
accepted or approved by the Commission or other regulatory body will be
passed on to each appropriate customer. The Commission or other
regulatory body accepted or approved charges or credits apply to the
service to which this rate methodology applies.
When possible, Western will pass through directly to the
appropriate customer, the Commission or other regulatory body accepted
or approved charges or credits in the same manner Western is charged or
credited. If the Commission or other regulatory body accepted or
approved charges or credits cannot be passed through directly to the
appropriate customer in the same manner Western is charged or credited,
the charges or credits will be passed through using Component 1 of the
CVP transmission rate formula.
Component 3: Any charges or credits from the HCA applied to Western
for providing this service will be passed through directly to the
appropriate customer in the same manner Western is charged or credited,
to the extent possible. If the HCA costs or credits cannot be passed
through to the appropriate customer in the same manner Western is
charged or credited, the charges or credits will be passed through
using Component 1 of the CVP transmission rate formula.
Western will revise the rate resulting from Component 1 of the
proposed rate formula based on: (a) Updated financial data available in
March of each year; and (b) a change in the numerator or denominator
that results in a rate change of at least $0.05 per kilowattmonth
(kWmonth). The estimated rate resulting from Component 1 of the
proposed rate formula for January through September 2005 is $0.93 per
kWmonth. This is a 63-percent increase from the existing rate of $0.57
per kWmonth.
The proposed rate formula for CVP non-firm transmission includes
the same three components used in the proposed rate formula for CVP
firm transmission. The estimated rate resulting from Component 1 of the
proposed rate formula for CVP non-firm transmission service for January
through September 2005 is 1.30 mills/kilowatthour (kWh). This rate is a
30-percent increase from the existing rate of 1.00 mill/kWh. The
percentage increase for the CVP non-firm transmission estimated rates
is smaller than the percentage increase for CVP firm transmission
estimated rates because the existing CVP non-firm transmission rate was
rounded up to 1.00 mill/kWh. The increase in CVP transmission rates is
primarily due to an increase in O&M costs and a change in Western's use
of the CVP transmission system under the 2004 Power Marketing Plan.
Under the current power marketing plan, Western is reserving
transmission capacity based on the maximum output of directly connected
CVP generating plants under normal operating conditions. Under the 2004
Power Marketing Plan, for rate design purposes, Western is treated as
taking CVP NITS. The rates resulting from Component 1 of the proposed
rate formula may be discounted for short-term sales.
The proposed rate formula for CVP transmission service is based on
a revenue requirement that recovers: (1) The CVP transmission system
costs for facilities associated with providing transmission service;
(2) the nonfacility costs allocated to transmission service; (3) CVP
generation costs for providing reactive supply and voltage control; (4)
the pass through of the Commission or other regulatory body accepted or
approved charges or credits; (5) the pass through of HCA charges or
credits; (6) any other statutorily required costs or charges; and (7)
any other costs associated with transmission service, including
uncollectible debt. Revenues from the sales of short-term transmission
will offset the TRR.
Component 1 of the proposed rate formula includes Western's cost
for transmission scheduling, system control and dispatch service, and
reactive supply and voltage control associated with the transmission
service. The proposed rate formula applies to CVP firm point-to-point
transmission service and existing CVP firm pre-OATT transmission
service. The estimated rates resulting from the proposed rate formula
are subject to change prior to the rates taking effect. The rates will be
[[Page 26373]]
finalized by Western on or before December 1, 2004.
Proposed Rate Formula for CVP NITS
The proposed rate formula for CVP NITS includes three components:
Component 1: NITS Customer's monthly costs = NITS customer's load
ratio share times one-twelfth of the annual network TRR.
Where:
NITS customer's load ratio share = The NITS customer's hourly load
coincident with the monthly CVP transmission system peak minus the
coincident peak for all firm CVP (including reserved transmission
capacity) transmission service, expressed as a ratio.
Annual network TRR = The total CVP TRR less CVP firm point-to-point and
pre-OATT transmission revenues.
Component 2: Any charges or credits associated with the creation,
termination, or modification to any tariff, contract, or rate schedule
accepted or approved by the Commission or other regulatory body will be
passed on to each appropriate customer. The Commission accepted or
approved charges or credits apply to the service to which this rate
methodology applies.
When possible, Western will pass through directly to the
appropriate customer, the Commission or other regulatory body accepted
or approved charges or credits in the same manner Western is charged or
credited. If the Commission or other regulatory body accepted or
approved charges or credits cannot be passed through directly to the
appropriate customer in the same manner Western is charged or credited,
the charges or credits will be passed through using Component 1 of the
CVP NITS rate formula.
Component 3: Any charges or credits from the HCA applied to Western
for providing this service will be passed through directly to the
appropriate customer in the same manner Western is charged or credited,
to the extent possible. If the HCA costs or credits cannot be passed
through to the appropriate customer in the same manner Western is
charged or credited, the charges or credits will be passed through
using Component 1 of the CVP NITS rate formula.
The proposed rate formula for CVP NITS is based on a revenue
requirement that recovers: (1) The CVP transmission system costs for
facilities associated with providing transmission service; (2) the
nonfacility costs allocated to transmission service; (3) CVP generation
costs for providing reactive supply and voltage control; (4) the pass
through of Commission or other regulatory body accepted or approved
charges or credits; (5) the pass through of HCA charges or credits; (6)
any other statutorily required costs or charges; and (7) any other
costs associated with transmission service, including uncollectible
debt. For January through September 2005, the estimated monthly NITS
revenue requirement is $923,932.
The proposed rate formula includes Western's cost for transmission
scheduling, system control and dispatch service, and reactive supply
and voltage control associated with the CVP NITS. The proposed rate
formula applies to CVP NITS. The estimated NITS monthly revenue
requirement, resulting from the proposed rate formula, may change prior
to the rates taking effect based on the final CVP TRR. The NITS monthly
revenue requirement will be finalized by Western on or before December
1, 2004.
Proposed Rate for Third-Party Transmission
The proposed rate formula for third-party transmission includes
three components:
Component 1: Western will directly pass through to the requesting
customer any transmission service costs it incurs for using a third-
party's transmission system. Rates under this schedule are proposed to
be automatically adjusted as third-party transmission costs are
adjusted.
Component 2: Any charges or credits associated with the creation,
termination, or modification to any tariff, contract, or rate schedule
accepted or approved by the Commission or other regulatory body will be
passed on to each appropriate customer. The Commission or other
regulatory body accepted or approved charges or credits apply to the
service to which this rate methodology applies.
Western will pass through directly to the appropriate customer, the
Commission or other regulatory body accepted or approved charges or
credits in the same manner Western is charged or credited, to the
extent possible.
Component 3: Any charges or credits from the HCA applied to Western
for providing this service will be passed through directly to the
appropriate customer in the same manner Western is charged or credited,
to the extent possible.
Proposed Rate Formula for COTP Point-to-Point Transmission
The proposed rate formula for COTP transmission includes three
components:
Component 1:
[GRAPHIC]
[TIFF OMITTED]
TN12MY04.025
Component 1 is the ratio of the COTP TRR to Western's share of the
COTP seasonal capacity. Western will update the rate resulting from
Component 1 at least 15 days before the start of each California-Oregon
Intertie (COI) rating season. Seasonal definitions for summer, winter,
and spring are June through October, November through March, and April
through May, respectively.
Component 2: Any charges or credits associated with the creation,
termination, or modification to any tariff, contract, or rate schedule
accepted or approved by the Commission or other regulatory body will be
passed on to each appropriate customer. The Commission accepted or
approved charges or credits apply to the service to which this rate
methodology applies.
When possible, Western will pass through directly to the
appropriate customer, the Commission or other regulatory body accepted
or approved charges or credits in the same manner Western is charged or
credited. If the Commission or other regulatory body accepted or
approved charges or credits cannot be passed through directly to the
appropriate customer in the same manner Western is charged or credited,
the charges or credits will be passed through using Component 1 of the
COTP transmission rate formula.
Component 3: Any charges or credits from the HCA applied to Western
for providing this service will be passed through directly to the
appropriate customer in the same manner Western is charged or credited,
to the extent possible. If the HCA costs or credits cannot be passed
through to the appropriate customer in the same manner Western is
charged or credited, the charges or credits will be passed through
using Component 1 of the COTP transmission rate formula.
A comparison of the estimated rates resulting from Component 1 of
the proposed rate formula for COTP firm point-to-point transmission
service to the existing COTP firm point-to-point transmission service
rates are shown in the table below.
[[Page 26374]]
Table 2.--Comparison of Existing Rates to Estimated Rates From
Component 1 of the Proposed Rate Formula for COTP Firm Point-To-Point
Transmission Service
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Estimated rates
Existing rate from proposed Percent
Season (kWmonth) rate formula increase
(kWmonth)
--------------------------------------------------------------------------
Spring........... $0.73 $1.60 119
Summer........... 0.53 1.59 200
Winter........... 0.66 1.61 144
--------------------------------------------------------------------------
The proposed rate formula for COTP non-firm transmission includes
the same three components used in the proposed rate formula for COTP
firm transmission. A comparison of the estimated rates resulting from
Component 1 of the proposed rate formula for COTP non-firm point-to-
point transmission service to the existing COTP non-firm point-to-point
transmission service rates, are shown in the table below.
Table 3.--Comparison of Existing to Estimated Rates From Component 1
of the Proposed Rate Formula for COTP Non-Firm Point-To-Point
Transmission Service
-------------------------------------------------------------------------
Estimated rate
Existing rate from proposed Percent
Season (mill/kWh) rate formula increase
(mills/kWh)
-------------------------------------------------------------------------
Spring................ $1.00 $2.18 118
Summer................ 0.72 2.17 201
Winter................ 0.91 2.22 144
-------------------------------------------------------------------------
The estimated firm and non-firm rates from Component 1 of the
proposed rate formula change minimally from season to season due to a
constant COI rating. The increase in COTP transmission rates is
primarily due to a decrease in Western's COTP capacity available for
sale. The decrease in capacity occurs because of increased usage by the
Department of Energy (DOE) of its statutory entitlement at a rate which
recovers only O&M costs.
The proposed rate formula for COTP firm and non-firm point-to-point
transmission service is based on a revenue requirement that recovers:
(1) The COTP transmission system costs for facilities associated with
providing transmission service; (2) the nonfacility costs allocated to
transmission service; (3) CVP generation costs for providing reactive
supply and voltage control; (4) the pass through of Commission or other
regulatory body accepted or approved charges or credits; (5) the pass
through of HCA charges or credits; (6) any other statutorily required
costs or charges; and (7) any other costs associated with transmission
service, including uncollectible debt.
The proposed firm and non-firm rate formula includes Western's cost
for transmission scheduling, system control and dispatch service, and
reactive supply and voltage control associated with COTP transmission.
The proposed rate formula applies to COTP point-to-point transmission
service. The rates resulting from Component 1 of the proposed rate
formula may be discounted for short-term sales. The estimated rates
resulting from the proposed rate formula are subject to change prior to
the rates taking effect. The rates resulting from the proposed rate
formula for the winter season will be finalized by Western on or before
December 15, 2004.
Proposed Rate Formula for PACI Transmission
The proposed rate formula for PACI transmission includes three
components:
Component 1:
[GRAPHIC]
[TIFF OMITTED]
TN12MY04.026
Component 1 is the ratio of the PACI TRR to Western's share of the
PACI seasonal capacity. Western will update the rate resulting from
Component 1 at least 15 days before the start of each COI rating
season. Seasonal definitions for summer, winter, and spring are June
through October, November through March, and April through May,
respectively.
Component 2: Any charges or credits associated with the creation,
termination, or modification to any tariff, contract, or rate schedule
accepted or approved by the Commission or other regulatory body will be
passed on to each appropriate customer. The Commission accepted or
approved charges or credits apply to the service to which this rate
methodology applies.
When possible, Western will pass through directly to the
appropriate customer, the Commission or other regulatory body accepted
or approved charges or credits in the same manner Western is charged or
credited. If the Commission or other regulatory body accepted or
approved charges or credits cannot be passed through directly to the
appropriate customer in the same manner Western is charged or credited,
the charges or credits will be passed through using Component 1 of the
PACI transmission rate formula.
Component 3: Any charges or credits from the HCA applied to Western
for providing this service will be passed through directly to the
appropriate customer in the same manner Western is charged or credited,
to the extent possible. If the HCA costs or credits cannot be passed
through to the appropriate customer, the charges or credits will be
passed through using Component 1 of the PACI transmission rate formula.
The proposed rate formula for PACI non-firm transmission includes
the same three components used in the proposed rate formula for PACI
firm transmission.
The estimated firm and non-firm rates resulting from Component 1 of
the proposed rate formula for PACI firm transmission service are shown
in the table below.
[[Page 26375]]
Table 4.--Estimated Rates From Component 1 of the Proposed Rate Formula
for PACI Transmission
------------------------------------------------------------------------
Estimated
Estimated non-firm
Season firm rate rate
(kW month) (mill/kWh)
------------------------------------------------------------------------
Spring.......................................... $0.22 0.31
Summer.......................................... 0.22 0.31
Winter.......................................... 0.22 0.31
------------------------------------------------------------------------
The estimated rates from Component 1 of the proposed rate formula
do not change from season to season due to a constant COI rating. There
are no existing rates for PACI transmission since it is currently
covered under an existing contract. The proposed rate formula for PACI
transmission service is based on a revenue requirement that recovers:
(1) The PACI transmission system costs for facilities associated with
providing transmission service; (2) the nonfacility costs allocated to
transmission service; (3) CVP generation costs for providing reactive
supply and voltage control; (4) the pass through of Commission or other
regulatory body accepted or approved charges or credits; (5) the pass
through of HCA charges or credits; (6) any other statutorily required
costs or charges; and (7) any other costs associated with transmission
service, including uncollectible debt.
The proposed rate formula includes Western's cost for transmission
scheduling, system control and dispatch service, and reactive supply
and voltage control associated with PACI transmission. The proposed
rate formula applies to PACI point-to-point transmission service. The
rates resulting from Component 1 of the proposed rate formula may be
discounted for short-term sales. The estimated rates resulting from the
proposed rate formula are subject to change prior to the rates taking
effect. The rates resulting from the proposed rate formula for the
winter season will be finalized by Western on or before December 15,
2004.
Path 15 Transmission Service
Western intends to turn over operational control of its rights on
Path 15 to the California Independent System Operator (CAISO).
Transmission service for Western's right on Path 15 must be obtained
under the terms and conditions established by the CAISO. Revenues
received by Western for wheeling and congestion will be applied against
Western's Path 15 TRR. If a significant overcollection occurs, Western
will work with the CAISO on the treatment of the overcollection.
Proposed Rates for Ancillary Services
Western's costs for providing transmission scheduling, system
control and dispatch service, and reactive supply and voltage control
are included in the appropriate transmission rate formulas.
Proposed Rate Formula for Spinning Reserve
The proposed rate formula for spinning reserve includes three
components:
Component 1: The Sub Control Area (SCA) spinning reserve monthly
revenue requirement will be recovered through a ratio using each SCA
customer's spinning reserve requirements. For rate design purposes,
Western's merchant function is treated as an SCA customer. Each SCA
customer's spinning reserve requirement will be calculated hourly based
on 2.5 percent of their maximum demand megawatt (MW) for that hour. A
ratio is calculated of each SCA customer's hourly spinning reserve
requirements summed for the month to the total of all SCA customers'
hourly spinning reserve requirements for the month. This ratio is then
applied to the monthly revenue requirement to determine SCA customers'
costs for spinning reserve. SCA customers that self-provide spinning
reserves will have their hourly spinning reserve requirement adjusted
to reflect the self-provision. The penalty for nonperformance by an SCA
customer who has committed to self-provision of their share of the SCA
spinning reserve requirements will be the greater of actual costs or
150 percent of the market price. Western will revise the revenue
requirement used in Component 1 of the proposed rate formula based on:
(a) Updated financial data available in March of each year; and (b) a
change in the annual revenue requirement of $100,000 or more.
Component 2: Any charges or credits associated with the creation,
termination, or modification to any tariff, contract, or rate schedule
accepted or approved by the Commission or other regulatory body will be
passed on to each appropriate customer. The Commission accepted or
approved charges or credits apply to the service to which this rate
methodology applies.
When possible, Western will pass through directly to the
appropriate customer, the Commission or other regulatory body accepted
or approved charges or credits in the same manner Western is charged or
credited. If the Commission or other regulatory body accepted or
approved charges or credits cannot be passed through directly to the
appropriate customer in the same manner Western is charged or credited,
the charges or credits will be passed through using Component 1 of the
spinning reserve rate formula.
Component 3: Any charges or credits from the HCA applied to Western
for providing this service will be passed through directly to the
appropriate customer in the same manner Western is charged or credited,
to the extent possible. If the HCA costs or credits cannot be passed
through to the appropriate customer, the charges or credits will be
passed through using Component 1 of the spinning reserve rate formula.
The proposed rate formula for spinning reserve service is based on
a revenue requirement that recovers: (1) The CVP generation costs
associated with providing spinning reserve service; (2) the nonfacility
costs allocated to spinning reserve service; (3) the cost of energy,
capacity, or foregone generation that supports spinning reserve
service; (4) the pass through of Commission or other regulatory body
accepted or approved charges or credits; (5) the pass through of HCA
charges or credits; and (6) any other statutorily required costs or
charges. For January through September 2005, the estimated monthly
revenue requirement is $165,657 per month, which results in a per-unit
cost of $3.31 per kWmonth. The existing rate for spinning reserve is
$1.35 per kWmonth. The spinning reserve per-unit cost calculated using
the proposed rate formula is an increase of 145 percent over the
existing rate. The increase is primarily due to purchases needed to
support the SCA reserve requirements and increased O&M costs.
The cost for spinning reserve required to firm CVP generation for
the current hour and the following hour is included in the power
revenue requirement. Spinning reserves surplus to those required to
support the SCA and firm CVP generation may be sold. Surplus spinning
reserves will be sold at prices consistent with the CAISO markets.
Revenues from the sale of surplus spinning reserves will offset the
power revenue requirement. The spinning reserve rate formula will apply
to SCA customers who contract with Western to provide this service. The
estimated revenue requirement resulting from the proposed rate formula
is subject to change prior to the rates taking effect. The revenue
requirement will be finalized by Western on or before December 1, 2004.
[[Page 26376]]
Proposed Rate Formula for Supplemental (Non-Spinning) Reserve
The proposed rate formula for non-spinning reserve includes three
components:
Component 1: The non-spinning reserve monthly revenue requirement
will be recovered through a ratio using the individual SCA customer's
non-spinning reserve requirement. Each SCA customer's non-spinning
reserve requirement will be calculated hourly based on 2.5 percent of
their maximum demand (MW) for that hour. A ratio is calculated of each
SCA customer's hourly non-spinning reserve requirements summed for the
month to the total SCA customers' hourly non-spinning reserve
requirements for the month. This ratio is then applied to the monthly
revenue requirement to determine the SCA customer's costs for non-
spinning reserve. SCA customers that self-provide non-spinning reserves
will have their hourly non-spinning reserve requirement adjusted to
reflect the self-provision. The penalty for nonperformance by an SCA
customer who has committed to self-provision of their share of the SCA
non-spinning reserve requirement will be the greater of actual costs or
150 percent of the market price. Western will revise the revenue
requirement used in Component 1 of the proposed rate formula based on:
(a) Updated financial data available in March of each year; and (b) a
change in the annual revenue requirement of $100,000 or more.
Component 2: Any charges or credits associated with the creation,
termination, or modification to any tariff, contract, or rate schedule
accepted or approved by the Commission or other regulatory body will be
passed on to each appropriate customer. The Commission accepted or
approved charges or credits to the service to which this rate
methodology applies.
When possible, Western will pass through directly to the
appropriate customer, the Commission or other regulatory body accepted
or approved charges or credits in the same manner Western is charged or
credited. If the Commission or other regulatory body accepted or
approved charges or credits cannot be passed through directly to the
appropriate customer in the same manner Western is charged or credited,
the charges or credits will be passed through using Component 1 of the
non-spinning reserve rate formula.
Component 3: Any charges or credits from the HCA applied to Western
for providing this service will be passed through directly to the
appropriate customer in the same manner Western is charged or credited,
to the extent possible. If the HCA costs or credits cannot be passed
through to the appropriate customer in the same manner Western is
charged or credited, the charges or credits will be passed through
using Component 1 of the non-spinning reserve rate formula.
The proposed rate formula for non-spinning reserve service is based
on a revenue requirement that recovers: (1) The CVP generation costs
associated with providing non-spinning reserve service; (2) the
nonfacility costs allocated to non-spinning reserve service; (3) the
cost of energy, capacity, or foregone generation that supports non-
spinning reserve service; (4) the pass through of HCA charges or
credits; (5) the pass through of Commission or other regulatory body
accepted or approved charges or credits; and (6) any other statutorily
required costs or charges. For January through September 2005, the
estimated monthly revenue requirement is $126,465 per month, which
results in a per-unit cost of $2.53 per kWmonth. The existing rate for
non-spinning reserve is $1.27 per kWmonth. The non-spinning reserve
per-unit cost calculated using the proposed rate formula is an increase
of 99 percent over the existing rate. The increase is primarily due to
purchases needed to support the SCA reserve requirements and increased
O&M costs.
The cost for non-spinning reserves required to firm CVP generation
for the current hour and the following hour is included in the power
revenue requirement. Non-spinning reserves surplus to those required to
support the SCA and firm CVP generation may be sold. Surplus non-
spinning reserves will be sold at prices consistent with the CAISO
markets. Revenues from the sale of non-spinning reserves will offset
the power revenue requirement. The non-spinning reserve rate formula
will apply to SCA customers who contract with Western to provide this
service. The estimated revenue requirement resulting from the proposed
rate formula is subject to change prior to the rates taking effect. The
revenue requirement will be finalized by Western on or before December
1, 2004.
Proposed Rate Formula for Regulation and Frequency Response Service
(Regulation)
The proposed rate formula for Regulation includes three components:
Component 1: The Regulation monthly revenue requirement will be
recovered through a ratio using the individual SCA customer's
regulating capacity requirement. Each SCA customer's regulating
capacity requirement will be calculated using the following formula:
SCA Customer Regulating Capacity Requirement (total bandwidth) = 2*(.05
* Load change + 5 MW)
Where:
Load change = The absolute value of the largest load change between any
two consecutive hours during a calendar year.
For SCA customers with an annual peak load of 30 MW or less, the
regulating capacity requirement is deemed to be 2 MW.
A ratio is calculated of each SCA customer's regulating capacity
requirement to the total regulating capacity requirement of all SCA
customers. This ratio is then applied to the monthly revenue
requirement to determine the SCA customer's costs for Regulation. SCA
customers that self-provide Regulation will have their regulating
capacity requirement adjusted to reflect the self-provision. The
penalty for nonperformance by an SCA customer who has committed to
self-provision for their regulating capacity requirement will be the
greater of actual costs or 150 percent of the market price. Western
will revise the revenue requirement used in Component 1 of the proposed
rate formula based on: (a) Updated financial data available in March of
each year; and (b) a change in the annual revenue requirement of
$100,000 or more.
Component 2: Any charges or credits associated with the creation,
termination, or modification to any tariff, contract, or rate schedule
accepted or approved by the Commission or other regulatory body will be
passed on to each appropriate customer. The Commission accepted or
approved charges or credits apply to the service to which this rate
methodology applies.
When possible, Western will pass through directly to the
appropriate customer the Commission or other regulatory body accepted
or approved charges or credits in the same manner Western is charged or
credited. If the Commission or other regulatory body accepted or
approved charges or credits cannot be passed through directly to the
appropriate customer in the same manner Western is charged or credited,
the charges or credits will be passed through using Component 1 of the
Regulation rate formula.
Component 3: Any charges or credits from the HCA applied to Western
for providing this service will be passed through directly to the
appropriate customer in the same manner Western
[[Page 26377]]
is charged or credited, to the extent possible. If the HCA costs or
credits cannot be passed through to the appropriate customer in the
same manner Western is charged or credited, the charges or credits will
be passed through using Component 1 of the Regulation rate formula.
The revenue requirement includes: (1) The CVP generation costs
associated with providing regulation; (2) the nonfacility costs
allocated to regulation; (3) the cost of energy, capacity, or foregone
generation that supports Regulation; (4) the pass through of HCA
charges or credits; (5) the pass through of Commission or other
regulatory body accepted or approved charges or credits; and (6) any
other statutorily required costs or charges.
For January through September 2005, the estimated monthly revenue
requirement is $258,098 per month, which results in a per-unit cost of
$6.45 per kWmonth. The existing rate for Regulation is $1.48 per
kWmonth. The Regulation per-unit cost calculated using the proposed
rate formula is an increase of 336 percent over the existing rate. The
increase is primarily due to purchases needed to support the Regulation
and increased O&M costs.
The Regulation revenue requirement will be recovered from SCA
customers that have contracted with Western for this service. The
revenues from Regulation service will be applied to the power revenue
requirement. The estimated revenue requirement resulting from the
proposed rate formula is subject to change prior to the rates taking
effect. The revenue requirement will be finalized by Western on or
before December 1, 2004.
Proposed Rate for Energy Imbalance Service
The proposed rate formula for energy imbalance service includes
three components:
Component 1: If there is an hourly average negative deviation
(under delivery) outside the bandwidth, the amount of the deviation
outside of the bandwidth (MWh) will be charged at the greater of 150
percent of market price or actual cost. If there is an hourly average
positive deviation outside the bandwidth, the amount of the deviation
outside of the bandwidth (MWh) is lost to the system.
Component 2: Any charges or credits associated with the creation,
termination, or modification to any tariff, contract, or rate schedule
accepted or approved by the Commission or other regulatory body will be
passed on to each appropriate customer. The Commission accepted or
approved charges or credits apply to the service to which this rate
methodology applies.
To the extent possible, Western will pass through directly to the
appropriate customer, the Commission or other regulatory body accepted
or approved charges or credits in the same manner Western is charged or
credited.
Component 3: Any charges or credits from the HCA applied to Western
for providing this service will be passed through directly to the
appropriate customer in the same manner Western is charged or credited,
to the extent possible.
The existing rate for energy imbalance is the same as the proposed
rate formula with three exceptions. Under the existing rate, deviations
are measured as the amount of energy outside the bandwidth. Under the
proposed rate formula, deviations outside the bandwidth are energy
calculations done on an hourly average basis. Under the existing rate,
the charge for deviations (energy) within the bandwidth not returned is
the CVP composite rate. Under the proposed rate, there is no financial
charge for deviations (energy) within the bandwidth that is not
returned. Under the existing rates, the charge for negative deviations
(under delivery) outside the bandwidth during on-peak hours is the
greater of three times the CVP composite rate or additional costs
incurred. During off-peak hours, it is the greater of the CVP composite
rate or additional costs incurred. Under the proposed rate, negative
deviations (under delivery) outside the bandwidth are charged at the
greater of 150 percent of market price or actual cost.
The energy imbalance rate will apply to SCA customers that have
contracted with Western for this service. The revenues from energy
imbalance service will be applied to the power revenue requirement.
Change in Revenue Adjustment Clause (RAC) in Existing CVP Firm Power
Rate Schedule CV-F10
Western is proposing a change to the RAC for FY 04. Under the
existing CVP Firm Power Rate Schedule CV-F10, a RAC credit for FY 04
would be applied in equal amounts to the nine power bills issued by
Western from January through September 2005. Western is proposing to
change the RAC to allow Western to make lump sum payments to customers
for their share of the FY 04 RAC credit, as opposed to issuing credits
in equal amounts to the power bills issued from January through
September 2005. This change in the RAC will allow Western more
flexibility as it moves to the 2004 Power Marketing Plan. This change
will not affect the calculation of the FY 04 RAC or the determination
of each customer's share of the FY 04 RAC.
For the October to December 2004 RAC, Western proposes to change
the existing process of calculating the RAC and applying the resulting
RAC credit or surcharge to the power bills issued from April through
September 2005. Western proposes to delay calculation of the October
through December 2004 RAC so that any outstanding project use true-ups
and any unmet obligations under existing contracts associated with
business that occurred prior to January 1, 2005, could be included in
the October through December 2004 RAC. This would likely delay the
October through December 2004 RAC until sometime in FY 06. Once this
data was available, Western would calculate the October through
December 2004 RAC using the existing methodology. The resulting RAC
credit or surcharge would be allocated among the power customers taking
firm power during October through December 2004 under the existing
methodology. Western would initiate distribution of the RAC credit or
surcharge within 30 days of completing the RAC calculation. If the
result was a RAC credit, at Western's discretion, Western would either
credit the customers' power bills to the extent possible, or Western
would make a lump sum payment to the customers for their share of the
RAC. If the result was a RAC surcharge, at Western's discretion,
Western could collect the payment in equal installments over 9 months
or as a lump sum.
Legal Authority
These proposed rates for COTP, PACI, CVP transmission, Western
power, and related services are being established pursuant to the DOE
Organization Act, (42 U.S.C. 7101-7352); the Reclamation Act of 1902,
(ch. 1093, 32 Stat. 388), as amended and supplemented by subsequent
enactments, particularly section 9(c) of the Reclamation Project Act of
1939 (43 U.S.C. 485(c)); and other acts that specifically apply to the
project involved.
By Delegation Order No. 00-037.00, effective December 6, 2001, the
Secretary of Energy delegated: (1) The authority to develop power and
transmission rates to Western's Administrator; (2) the authority to
confirm, approve, and place such rates into effect on an interim basis
to the Deputy Secretary; and (3) the authority to confirm, approve, and
place into effect on a final basis, to remand, or to disapprove such
rates to the Commission. Existing DOE procedures
[[Page 26378]]
for public participation in power rate adjustments (10 CFR 903) were
published on September 18, 1985 (50 FR 37835).
Availability of Information
All brochures, studies, comments, letters, memorandums, or other
documents made or kept by Western for developing the proposed rates are
available for inspection and copying at the Sierra Nevada Regional
Office, located at 114 Parkshore Drive, Folsom, California.
Regulatory Procedural Requirements
Regulatory Flexibility Analysis
The Regulatory Flexibility Act of 1980 (5 U.S.C. 601, et seq.)
requires Federal agencies to perform a regulatory flexibility analysis
if a final rule is likely to have a significant economic impact on a
substantial number of small entities and there is a legal requirement
to issue a general notice of proposed rulemaking. This action does not
require a regulatory flexibility analysis since it is a rulemaking of
particular applicability involving rates or services applicable to
public property.
Environmental Compliance
In compliance with the National Environmental Policy Act of 1969
(NEPA) (42 U.S.C. 4321, et seq.); Council on Environmental Quality
Regulations (40 CFR 1500-1508); and DOE NEPA Regulations (10 CFR 1021),
Western has determined this action is categorically excluded from
preparing an environmental assessment or an environmental impact
statement.
Determination Under Executive Order 12866
Western has an exemption from centralized regulatory review under
Executive Order 12866; so this notice requires no clearance by the
Office of Management and Budget.
Small Business Regulatory Enforcement Fairness Act
Western has determined this rule is exempt from congressional
notification requirements under 5 U.S.C. 801 because the action is a
rulemaking of particular applicability relating to rates or services
and involves matters of procedure.
Dated: April 29, 2004.
Michael S. Hacskaylo,
Administrator.
[FR Doc. 04-10776 Filed 5-11-04; 8:45 am]
BILLING CODE 6450-01-P