04-10776. 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.

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 [e-mail]. 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 [phone], e-mail [e-mail].

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:

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 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 Power Revenue Requirement	N/A.
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:

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 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:

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.

 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

Season	Existing rate (kWmonth)	Estimated rates from proposed rate formula (kWmonth)	Percent increase
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

Season	Existing rate (mill/kWh)	Estimated rate from proposed rate formula (mills/kWh)	Percent increase
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:

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.

Table 4.—Estimated Rates From Component 1 of the Proposed Rate Formula for PACI Transmission

Season	Estimated firm rate (kW month)	Estimated non-firm rate (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.

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 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 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.