[Federal Register Volume 69, Number 92 (Wednesday, May 12, 2004)]
[Notices]
[Pages 26370-26378]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 04-10776]


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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 
Parkshore Drive, Folsom, CA 95630-4710, e-mail [email protected]. 
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/ 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 [email protected].

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
----------------------------------------------------------------------------------------------------------------
           Power service                  Existing rate       Proposed rate formula         Percent 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
----------------------------------------------------------------------------------------------------------------
                                                                                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