[Federal Register Volume 67, Number 187 (Thursday, September 26, 2002)]
[Notices]
[Pages 60656-60672]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 02-24424]


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DEPARTMENT OF ENERGY

Western Area Power Administration


Salt Lake City Area Integrated Projects and Colorado River 
Storage Project--Rate Order No. WAPA-99

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of Rate Order.

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SUMMARY: The Secretary of the Department of Energy (DOE) confirmed and 
approved Rate Order No. WAPA-99 and Rate Schedule SLIP-F7, placing firm 
power rates from the Salt Lake City Area Integrated Projects (SLCA/IP) 
of the Western Area Power Administration (Western) into effect on an 
interim basis. The Secretary also confirmed Rate Schedules SP-PTP6, SP-
NW2, SP-NFT5, SP-SD2, SP-RS2, SP-EI2, SP-FR2, and SP-SSR2, placing firm 
and non-firm transmission rates and ancillary services rates on the 
Colorado River Storage Project (CRSP) transmission system into effect 
on an interim basis. The provisional rates will be in effect until the 
Federal Energy Regulatory Commission (FERC) confirms, approves, and 
places them into effect on a final basis or until they are replaced by 
other rates. The provisional rates will provide sufficient revenue to 
pay all annual costs, including interest expense, repayment of 
investment, and irrigation aid within the allowable periods.

DATES: Rate Schedules SLIP-F7, SP-PTP6, SP-NW2, SP-NFT5, SP-SD2, SP-
RS2, SP-EI2, SP-FR2, and SP-SSR2 will be placed into effect on an 
interim basis on the first day of the first full billing period 
beginning on October 1, 2002, and will be in effect until FERC 
confirms, approves, and places the rate schedules in effect on a final 
basis through September 30, 2007, or until the rate schedules are 
superseded.

FOR FURTHER INFORMATION CONTACT: Mr. Bradley S. Warren, CRSP Manager, 
CRSP Management Center, Western Area Power Administration, P.O. Box 
11606, Salt Lake City, UT 84147-0606, (801) 524-6372, or Ms. Carol 
Loftin, Rates Manager, CRSP Management Center, Western Area Power 
Administration, P.O. Box 11606, Salt Lake City, UT 84147-0606, (801) 
524-6380, or e-mail [email protected].

SUPPLEMENTARY INFORMATION: The Deputy Secretary of Energy approved the 
existing Rate Schedule SLIP-F6 for SLCA/IP firm power, Rate Schedules 
SP-PTP5, SP-NW1, and SP-NFT4 for firm and non-firm transmission, and 
Rate Schedules SP-SD1, SP-RS1, SP-EI1, SP-FR1, and SP-SSR1 for 
ancillary

[[Page 60657]]

services on March 23, 1998 (Rate Order No. WAPA-78, April 6, 1998), and 
FERC confirmed and approved the rate schedules on July 17, 1998, in 
FERC Docket No. EF98-5171-000. The existing rate schedules became 
effective April 1, 1998, through March 30, 2003.
    The existing firm power Rate Schedule is being superseded by Rate 
Schedule SLIP-F7. Under Rate Schedule SLIP-F6, the energy rate is 8.10 
mills per kilowatthour (mills/kWh), and the capacity rate is $3.44 per 
kilowattmonth (kWmonth). The composite rate is 17.57 mills/kWh. The 
provisional firm power rate consists of an energy charge of 9.5 mills/
kWh and a capacity charge of $4.04 per kWmonth. The provisional rates 
for SLCA/IP firm power in Rate Schedule SLIP-F7 will result in an 
overall composite rate of 20.72 mills/kWh on October 1, 2002, and will 
result in an increase of about 18 percent when compared with the 
existing SLCA/IP firm power rates under Rate Schedule SLIP-F6.
    Rate Schedules SP-PTP6, SP-NW2, and SP-NFT5 supersede Rate 
Schedules SP-PTP5, SP-NW1, and SP-NFT4, respectively. Provisional 
formula rates developed for CRSP transmission services are consistent 
with FERC Order No. 888. Under Rate Schedules SP-PTP5 and SP-NFT4, the 
CRSP transmission rates are $1.78/kWmonth for firm service and a 
maximum of 2.43 mills/kWh for non-firm service. On October 1, 2002, the 
provisional formula rate in Rate Schedule SP-PTP6 results in a rate of 
$2.06/kWmonth for firm CRSP transmission service, a 16-percent increase 
when compared with the existing rate. The provisional formula rate in 
Rate Schedule SP-NFT5 results in a maximum rate of 2.82 mills/kWh for 
non-firm service, a 16-percent increase when compared with the existing 
rate.
    The provisional formula for network integration transmission 
service in Rate Schedule SP-NW2 will be the same as the existing 
formula rate for network integration transmission service under Rate 
Schedule SP-NW1.
    The existing transmission rates include costs for scheduling, 
system control, and dispatch services. The transmission provisional 
formula rates include the costs of this service.
    Rate Schedules SP-SD2, SP-RS2, SP-EI2, SP-FR2, and SP-SSR2 
supersede Rate Schedules SP-SD1, SP-RS1, SP-EI1, SP-FR1, and SP-SSR1, 
respectively. Ancillary services are being updated slightly to reflect 
minor changes.
    By Delegation Order No. 00-037.00, effective December 6, 2001, the 
Secretary of DOE delegated (1) the authority to develop long-term power 
and transmission rates on a nonexclusive basis 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 FERC. Existing DOE 
procedures for public participation in power rate adjustments (10 CFR 
part 903) became effective on September 18, 1985.
    Pursuant to Delegation Order No. 00-037.00 and existing Department 
of Energy procedures for public participation in power rate adjustments 
at 10 CFR part 903 and 18 CFR part 300, procedures for approving Power 
Marketing Administration rates by FERC, Rate Order No. WAPA-99, 
confirming, approving, and placing the proposed SLCA/IP firm power 
rate, CRSP firm and non-firm transmission rates, and ancillary services 
rates into effect on an interim basis, is issued, and the new Rate 
Schedules SLIP-F7, SP-PTP6, SP-NW2, SP-NFT5, SP-SD2, SP-RS2, SP-EI2, 
SP-FR2, and SP-SSR2 will be promptly submitted to FERC for confirmation 
and approval on a final basis.

    Dated: September 10, 2002.
Spencer Abraham,
Secretary.

Western Area Power Administration Rate Adjustment for the Salt Lake 
City Area Integrated Projects and Colorado River Storage Project; Order 
Confirming, Approving, and Placing the Salt Lake City Area Integrated 
Projects Firm Power, Colorado River Storage Project Transmission, and 
Ancillary Services Rates into Effect on an Interim Basis

    The Western Area Power Administration (Western) developed these 
rates pursuant to the Department of Energy Organization Act (42 U.S.C. 
7101-7352). The Department of Energy Organization Act transferred the 
power marketing functions of the Secretary of the Interior and the 
Bureau of Reclamation under 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. 485h(c)), and other acts specifically applicable to the projects 
involved, to the Secretary of Energy (Secretary).
    By Delegation Order No. 00-037.00, effective December 6, 2001, the 
Secretary of DOE delegated (1) the authority to develop long-term power 
and transmission rates on a nonexclusive basis 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 FERC. Existing DOE 
procedures for public participation in power rate adjustments (10 CFR 
part 903) became effective on September 18, 1985.

Acronyms and Definitions

    As used in this rate order, the following acronyms and definitions 
apply:

1-CP: 1-month coincident peak for year.
12-CP: 12-month coincident peak average.
A-LP: Animas-LaPlata Project.
Administrator: Western's Administrator.
Ancillary Services: Those services necessary to support the transfer of 
electricity while maintaining reliable operation of the transmission 
system in accordance with standard utility practice.
AHP: Available Hydropower.
Basin Fund: Upper Colorado River Basin Fund.
Capacity: The electric capability of a generator, transformer, 
transmission circuit, or other equipment. It is expressed in kW.
Capacity Rate: The rate which sets forth the charges for capacity. It 
is expressed in $ per kWmonth.
CDP: Customer Displacement Power.
Collbran: Collbran Project.
Composite Rate: The rate for commercial firm power and is the total 
annual revenue requirement for capacity and energy divided by the total 
annual energy sales. It is expressed in mills/kWh and used for 
comparison purposes.
Contractor: An entity which has a contract with Western for SLCA/IP 
Firm Electric Service. (See also Customer)
CME: Capitalized Movable Equipment.
CROD: Contract rate of delivery. The maximum amount of capacity made 
available to a preference customer for a period specified under a 
contract.
CRSP: Colorado River Storage Project.
CRSP Act: Act of April 11, 1956, ch. 203, 70 Stat. 105, as amended, 43 
U.S.C. 620-620o.
CRSP MC: The CRSP Management Center of Western.
CUP: Central Utah Project.
Customer: An entity with a contract which is receiving service from 
Western's CRSP MC.
DOE: United States Department of Energy.

[[Page 60658]]

DOE Order RA 6120.2: An order dealing with power marketing 
administration financial reporting and rate-making procedures.
DPR: Definite Plan Report of the CUP.
DSWR: The Desert Southwest Region of Western.
Energy: Measured in terms of the work it is capable of doing over a 
period of time. It is expressed in kWh.
Energy Rate: The rate which sets forth the charges for energy. It is 
expressed in mills/kWh and applied to each kWh delivered to each 
customer.
FERC: Federal Energy Regulatory Commission.
Firm: A type of product and/or service available at the time requested 
by the customer.
FRN: Federal Register notice.
FTE: Full-time equivalent. Represents one full-time employee.
FY: Fiscal year; October 1 to September 30.
GCPA: Grand Canyon Protection Act of 1992.
GWh: Gigawatthour--the electrical unit of energy that equals 1 billion 
watthours or 1,000,000 kWh.
Integrated Projects: The resources and revenue requirements of the 
Collbran, Dolores, Rio Grande, and Seedskadee projects blended together 
with the CRSP to create the SLCA/IP resources and rate.
kW: Kilowatt--the electrical unit of capacity that equals 1,000 watts.
kWmonth: Kilowattmonth--the electrical unit of the monthly amount of 
capacity.
kWh: Kilowatthour--the electrical unit of energy that equals 1,000 
watts in 1 hour.
Load: The amount of electric power or energy delivered or required at 
any specified point(s) on a system.
Merchant Function: A Power Marketing function within the CRSP MC that 
balances loads and resources for the CRSP MC, other regions within 
Western, and customers and purchases and sells energy on the open 
market.
Mill: A monetary denomination of the United States that equals one 
tenth of a cent or one thousandth of a dollar.
Mills/kWh: Mills per kilowatthour--the unit of charge for energy.
MW: Megawatt--the electrical unit of capacity that equals 1 million 
watts or 1,000 kilowatts.
NEPA: National Environmental Policy Act of 1969 (42 U.S.C. 4321, et 
seq.).
Net Revenue: Revenue remaining after paying all annual expenses.
Non-firm: A type of product and/or service not always available at the 
time requested by the customer.
O&M: Operation and maintenance.
OASIS: Open Access Same-Time Information System--provides access to 
information on transmission pricing and availability for potential 
transmission customers.
OM&R: Operation, Maintenance & Replacement.
PAR: Purchase Adder Rate.
Participating Projects: The Dolores and Seedskadee projects 
participating with CRSP according to the CRSP Act of 1956.
Power: Capacity and energy.
Project Use: Power used to operate SLCA/IP and CRSP facilities pursuant 
to Reclamation Law.
Provisional Rate: A rate which has been confirmed, approved, and placed 
into effect on an interim basis by the Deputy Secretary of DOE.
PRS: Power repayment study.
Rate Brochure: A document explaining the rationale and background of 
the rate proposal contained in this Rate Order dated February 2002.
Rate-Setting PRS: The PRS used for the rate adjustment proposal.
Reclamation: United States Department of the Interior, Bureau of 
Reclamation.
Reclamation Law: A series of Federal laws. Viewed as a whole, these 
laws create the originating framework under which Western markets 
power.
Revenue Requirement: The revenue required to recover annual expenses, 
such as O&M, purchase power, transmission service expenses, interest, 
deferred expenses, and repayment of Federal investments, and other 
assigned costs.
RIP: Recovery Implementation Program.
RMR: The Rocky Mountain Region of Western.
Secretary: Secretary of Energy.
SCADA: Supervisory Control and Data Acquisition.
SHP: Sustainable Hydro Power.
SLCA/IP: Salt Lake City Area Integrated Projects--The resources and 
revenue requirements of the Collbran, Dolores, Rio Grande, and 
Seedskadee projects blended together with the CRSP to create the SLCA/
IP resources and rate.
Supporting Documentation: A compilation of data and documents that 
support the Rate Brochure and the rate proposal.
WACM: Western Area Colorado Missouri control area, operated by RMR.
WALC: Western Area Lower Colorado control area, operated by DSWR.
Western: United States Department of Energy, Western Area Power 
Administration.
Western Regions: Customer service regions of Western Area Power 
Administration.
Western's Tariff: Western's Open Access Transmission Service Tariff.
Work Plan: A draft estimate of costs that are expected to become the 
Congressional Budget for Western and Reclamation.
WRP: Western Replacement Power.
WECC: Western Electricity Coordinating Council.
WSPP: Western Systems Power Pool.

Effective Date

    The new interim rates will take effect on the first day of the 
first full billing period beginning on or after October 1, 2002, and 
will be in effect pending their approval by FERC or substitute final 
rates for 5 years ending September 30, 2007, or until superseded.

Public Notice and Comment

    Western followed the Procedures for Public Participation in Power 
and Transmission Rate Adjustments and Extensions, 10 CFR part 903, in 
developing these rates. The steps Western took to ensure involvement of 
interested parties in the rate process were:
    1. The proposed rate adjustment process began September 18, 2001, 
when Western mailed a notice announcing informal customer meetings to 
all SLCA/IP customers and interested parties.
    2. Western mailed a notice on October 3, 2001, announcing the 
change of dates and locations for informal customer meetings to one 
meeting. The meeting was held on October 18, 2001, in Salt Lake City, 
Utah. At this informal meeting, Western explained the rationale for the 
rate adjustment, presented rate designs and methodologies, and answered 
questions.
    3. On March 4, 2002, Western's CRSP MC mailed letters to all SLCA/
IP preference customers and interested parties transmitting the 
Brochure for Proposed Rates and the Federal Register notice due to be 
published on March 6, 2002.
    4. A Federal Register notice published on March 6, 2002 (67 FR 
10189), officially announced the proposed rates for SLCA/IP and CRSP, 
began a public consultation and comment period, and announced the 
public information and public comment forums.
    5. On March 19, 2002, beginning at 10 a.m., Western held a public 
information forum at the Hilton Salt Lake City Center in Salt Lake 
City, Utah. Western provided detailed explanations of the proposed 
rates for SLCA/IP and CRSP, provided a list of issues that could change 
the proposed rates, answered questions, and gave notice that additional 
information would be provided at a second information forum

[[Page 60659]]

before the public comment forum. Rate Brochures, Supporting 
Documentation, and informational handouts were also provided.
    6. On April 12, 2002, Western's CRSP MC mailed letters to all SLCA/
IP preference customers and interested parties notifying them of the 
second public information forum and providing a table which illustrated 
the proposed changes to be discussed.
    7. On April 23, 2002, beginning at 10 a.m., Western held a second 
public information forum at the Hilton Salt Lake City Center in Salt 
Lake City, Utah. Western provided updates to the proposed firm power 
rates, and answered questions.
    8. On April 23, 2002, beginning at 11:15 a.m., Western held a 
comment forum to give the public an opportunity to comment for the 
record. Seven individuals commented at this forum.
    9. Western received 21 comment letters during the consultation and 
comment period, which ended June 4, 2002. All formally submitted 
comments have been considered in preparing this Rate Order.

Comments

    Written comments were received from the following organizations:

Bureau of Reclamation, Upper Colorado Region, Utah
Bountiful City Light and Power, Utah
Bridger Valley Electric Association, Wyoming
City of Farmington, New Mexico
Colorado River Energy Distributors Association, Arizona
Deseret Power Electric Cooperative, Utah
Dixie-Escalante Electric Cooperative, Utah
Fillmore City, Utah
Holden Town, Utah
Holy Cross Energy, Inc., Colorado
Irrigation & Electrical Districts Association of Arizona, Arizona
Kanosh Town, Utah
Kaysville City, Utah
Morgan City, Utah
Murray City Corporation, Utah
Platte River Power Authority, Colorado
Provo City Power, Utah
Salt River Project, Arizona
Strawberry Electric Service District, Utah
Tri-State Generation and Transmission Association, Inc., Colorado
Utah Associated Municipal Power Systems, Utah

    Representatives of the following organizations made oral comments:

Colorado River Energy Distributors Association, Arizona
Deseret Power Electric Cooperative, Utah
Irrigation & Electrical District Association, Arizona
Manti City Power, Utah
Nephi City Power, Utah
Utah Municipal Power Association, Utah

Project Description

    The SLCA/IP consists of the CRSP, Rio Grande, and Collbran 
projects. The CRSP described here includes two CRSP participating 
projects that have power facilities, the Dolores and Seedskadee 
projects. The Rio Grande and Collbran projects were integrated with 
CRSP for marketing and rate-making purposes on October 1, 1987. The 
goals of integration were to increase marketable resources and to 
simplify contract and rate development and project administration by 
creating one rate and assuring repayment of the Projects' costs. All 
Integrated Projects maintain their individual identities for financial 
accounting and repayment purposes, but their revenue requirements are 
integrated into one PRS for rate-making, known as the SLCA/IP.

Power Repayment Study--Firm Power Rate

    Western prepares a PRS each FY to determine if revenues will be 
sufficient to repay, within the prescribed time periods, all costs 
assigned to the SLCA/IP revenues. Repayment criteria are based on law, 
policies including DOE Order RA 6120.2, and authorizing legislation.
    The proposed rates for SLCA/IP firm power result in an overall 
composite rate increase of approximately 18 percent on October 1, 2002, 
when compared to the existing SLCA/IP firm power rates in Rate Schedule 
SLIP-F6. The composite rate under Rate Schedule SLIP-F6 is 17.57 mills/
kWh, and the proposed composite rate is 20.72 mills/kWh. The following 
table compares the current and proposed firm power rates.

                               Comparison of Current and Proposed Firm Power Rates
----------------------------------------------------------------------------------------------------------------
                                                                                Current    Proposed
                                                                                 rate        rate
                                Rate schedule                                ------------------------  Increase
                                                                                SLIP-F6     SLIP-F7
----------------------------------------------------------------------------------------------------------------
Energy (mills/kWh)..........................................................        8.1         9.5         1.4
Capacity ($/kWmonth)........................................................        3.44        4.04         .60
Composite Rate: (mills/kWh).................................................       17.57       20.72        3.15
----------------------------------------------------------------------------------------------------------------

CRSP Transmission Rate Study

    A transmission service rate study was prepared to ensure that 
transmission service rates are based on the cost of service of the CRSP 
transmission system. This study includes all transmission expenses and 
associated offsetting revenues. Transmission service rates are charged 
separately to entities receiving transmission-only services over the 
CRSP transmission system.
    Western is proposing firm and non-firm transmission rate formulas 
to annually calculate rates applicable to all current and future CRSP 
transmission service. The current firm and non-firm CRSP transmission 
rate formulas became effective on April 1, 1998. The proposed 
transmission rate formulas are expected to be effective October 1, 
2002, through September 30, 2007. These rate formulas include costs for 
scheduling, system control, and dispatch service. The cost of 
transmission service for Western's SLCA/IP long-term firm electric 
service will continue to be included in the SLCA/IP firm power rate. 
Transmission services are outlined in Western's Tariff.
    A new rate methodology is being proposed that is more consistent 
with the methodology used at other Western regions and other utilities. 
The proposed methodology is an annual fixed charge formula that will be 
used to determine the revenue requirement to be recovered from firm and 
non-firm transmission service. The annual transmission revenue 
requirement includes O&M expenses, administrative and general expenses, 
interest expense, and depreciation expense. This methodology is updated 
annually using the most recent historical test year. This revenue 
requirement is offset by appropriate CRSP transmission system revenues.

[[Page 60660]]

    The provisional rate for non-firm CRSP transmission service is 
based upon the current CRSP firm point-to-point transmission rate, and 
may be discounted. The provisional rate is expressed in mills/kWh and 
is a maximum of 2.82 mills/kWh for FY 2003.
    The provisional rate for network integration transmission service 
is a formula calculation based on the annual transmission revenue 
requirement. There are no changes to the existing network integration 
transmission service formula under Rate Schedule SP-NW1.

Firm Point-to-Point

    The CRSP MC is seeking approval of a rate formula for calculation 
of the firm point-to-point transmission rate, to be applied annually. 
The provisional rate for firm point-to-point CRSP transmission service 
is $2.06 per kWmonth for FY 2003, a 16-percent increase from the 
existing firm transmission rate of $1.78 per kWmonth, which became 
effective April 1, 2002.
    The firm point-to-point transmission rate is based on a test year 
using an annual fixed charge methodology. This test year is the most 
recent historical data available. The annual transmission revenue 
requirement is reduced by revenue credits such as non-firm 
transmission, existing contracts at different rates, scheduling and 
dispatch services, and phase shifter revenues. The resultant net annual 
transmission revenue requirement is divided by the capacity reservation 
needed to meet firm power and transmission-only commitments in kW, 
including the total network integration loads at system peak, to derive 
a cost/kWyear. The formula is updated each year by applying the most 
current historical test year. If needed, a revised rate will become 
effective each October 1. The rate formula is proposed to be effective 
October 1, 2002, through September 30, 2007.
    The cost/kWyear is calculated using the following formula:

    [GRAPHIC] [TIFF OMITTED] TN26SE02.015
    

Where:
ARR = Annual Revenue Requirement. The costs associated with facilities 
that support the transfer capability of the CRSP transmission system, 
excluding generation facilities. These costs include investment costs, 
interest expense, depreciation expense, administrative and general 
expenses, and operation and maintenance expense, including transmission 
purchases. Transmission purchases reflect those costs associated with 
CRSP contractual rights.
TRC = Transmission Revenue Credits. The revenues generated by the CRSP 
transmission system not related to the revenues from the sale of long-
term firm transmission.
NARR = Net Annual Transmission Revenue Requirement. The Annual Revenue 
Requirement minus Transmission Revenue Credits.
TSTL = CRSP Transmission System Total Load. The sum of the total CRSP 
transmission capacity under long-term reservation including the total 
network integration loads at system peak.

Non-Firm Point-to-Point

    The proposed rate for non-firm point-to-point CRSP transmission 
service is a mills/kWh rate which is based upon the current firm point-
to-point rate and may be discounted. This rate will remain in effect 
concurrently with the firm point-to-point rate and will also be 
reviewed annually. Transmission availability will be posted on 
Western's OASIS.

Network

    The proposed rate for network transmission is a formula calculation 
based upon the annual revenue requirement then in effect, as determined 
by the annual fixed charge methodology. Western is not currently 
providing network transmission on its CRSP transmission system.

Ancillary Services

    Six ancillary services will be offered by CRSP MC, two of which are 
required. These are (1) scheduling, system control, and dispatch 
service and (2) reactive supply and voltage control service. The 
remaining four ancillary services, (3) regulation and frequency 
response service, (4) energy imbalance service, (5) spinning reserve 
service, and (6) supplemental reserve service, will also be offered 
either from the control area or from the CRSP Merchant Function. Sales 
of regulation and frequency response, energy imbalance, spinning 
reserve, and supplemental reserve services from SLCA/IP power resources 
are limited since Western has allocated the SLCA/IP power resources to 
preference entities under long-term commitments. The availability and 
type of ancillary service will be determined based on excess resources 
available at the time the service is requested, except for the two 
ancillary services required to be provided in conjunction with the sale 
of CRSP transmission services.
    Since the CRSP transmission system lies in two control areas 
operated by Western's RMR and DSWR, many of the ancillary services are 
offered through their respective control areas.
    The provisional rates for ancillary services are designed to 
recover only the costs associated with providing the service(s). The 
costs for providing scheduling, system control, and dispatch service 
are included in the appropriate provisional transmission services 
rates. However, the charges for reactive supply and voltage control 
service will be in accordance with Western's DSWR and RMR applicable 
rate schedules.

Existing and Provisional Rates

    A comparison of the existing and provisional firm power, 
transmission and ancillary services rates follows:

    Comparison of Existing and Provisional Salt Lake City Area/Integrated Projects Firm Power, Colorado River
                               Storage Project Transmission and Ancillary Services
----------------------------------------------------------------------------------------------------------------
                                                                             Provisional rates
                                                  Existing rates            (effective 10/1/02)        % Change
----------------------------------------------------------------------------------------------------------------
Firm Capacity Charge ($/kWmonth).........  $3.44......................  $4.04......................           17
Firm Energy Charge (mills/kWh)...........  8.10.......................  9.50.......................           17
Composite Rate (mills/kWh)...............  17.57......................  20.72......................           18
Firm Transmission Rate ($/kWmonth).......  1.78.......................  2.06.......................           16
Network Transmission (Net Annual Revenue   54,968,215.................  65,279,468.................           19
 Requirement).
Non-firm Transmission Rate...............  2.43 mills/kWh, may be       2.82 mills/kWh, may be                16
                                            discounted.                  discounted.

[[Page 60661]]

 
Ancillary Services \1\...................  N/A........................  N/A........................          N/A
----------------------------------------------------------------------------------------------------------------
\1\ Since most of CRSP transmission facilities are located in two other Western control areas, many of these
  services are provided through these control areas.

Certification of Rates

    Western's Administrator certified that the interim rates for SLCA/
IP firm power, CRSP transmission, and ancillary services are the lowest 
possible rates consistent with sound business principles. The 
provisional rates were developed following administrative policies and 
applicable laws.

SLCA/IP Firm Power Rate Discussion

    According to Reclamation law, Western must establish power rates 
sufficient to recover operation, maintenance, and purchased power 
expenses, interest expenses, and repayment of investment and irrigation 
aid.
    The SLCA/IP firm power rate needs to be increased due to recent 
higher-than-expected O&M and purchased power costs that have occurred 
since the existing rate was established. Future projections for O&M 
have also increased in the Rate-Setting PRS. It is also expected that 
near term hydrogeneration will be lower than normal in the next 2 years 
which will require greater than normal purchased power costs.
    These higher-than-expected O&M and purchased power costs have 
created deficits or near-deficits within the CRSP PRS since 1999. These 
deficit or near-deficit conditions are expected to continue through 
2004. The deficits are projected to be repaid by 2005.
    The increased revenue requirements are partially offset by an 
increase in projections for offsetting revenues such as Merchant 
Function, non-firm transmission, and ancillary services revenues.
    The existing rate for SLCA/IP firm power under Rate Schedule SLIP-
F6 expires March 30, 2003. Effective October 1, 2002, Rate Schedule 
SLIP-F6 will be superseded by the new rates in Rate Schedule SLIP-F7. 
The provisional rates for SLCA/IP firm power consist of a capacity rate 
and an energy rate. The provisional capacity rate is $4.04/kWmonth, and 
the provisional energy rate is 9.5 mills/kWh.

Statement of Revenue and Related Expenses

    The following table provides a summary of projected revenue and 
expense data for the SLCA/IP firm power rate through the 5-year 
provisional rate approval period.

  SLCA/IP Firm Power Comparison of 5-Year Rate Period (FY 2003-FY 2007)
                       Total Revenues and Expenses
------------------------------------------------------------------------
                                     Existing     Proposed
                                       rate         rate      Difference
                                      ($000)       ($000)       ($000)
------------------------------------------------------------------------
Total Revenues...................     $636,189     $772,317     $136,128
Revenue Distribution:
    Annual expenses
        O&M......................      176,600      286,644      110,044
        Purchased Power and             59,375      131,926       72,551
         Wheeling................
        Integrated Projects             42,331       43,335        1,004
         Requirements............
        Interest.................       60,442      174,765      114,323
        Other....................        9,428       31,323       21,895
                                  --------------
            Total annual expenses      348,176      667,993      319,817
    Annual principal payments
        Capitalized Expenses.....            0       19,257       19,257
        Original Project and           158,654       79,941     (78,713)
         Additions \1\...........
        Replacements \1\.........      127,117        2,810    (124,307)
        Irrigation...............        2,242        2,316           74
                                  --------------
             Total principal           288,013      104,324    (207,316)
             payments............
                                  ===========================
Total Revenue Distribution.......      636,189      772,317     136,128
------------------------------------------------------------------------
\1\ Due to the deficit or near-deficit conditions between 1999 and 2004,
  revenues generated in the cost evaluation period are applied towards
  repayment of deficits rather than repayment of project, additions, and
  replacements. All deficits are projected to be repaid by 2005.

Basis for Rate Development

    The existing rates for SLCA/IP firm power in Rate Schedule SLIP-F6 
expire March 30, 2003. The existing rates no longer provides sufficient 
revenues to pay all annual costs, including interest expense, and 
repayment of investment and irrigation aid within the allowable period. 
The adjusted rates reflect increases primarily in O&M costs, purchase 
power costs, and interest expenses. The provisional rates will provide 
sufficient revenue to pay all annual costs, including interest expense, 
and repayment of investment and irrigation aid within the allowable 
periods. The provisional rates will take effect on October 1, 2002, to 
correspond with the start of the Federal fiscal year, and will remain 
in effect through September 30, 2007.
    The provisions for transformer losses adjustment, power factor 
adjustment, Western Replacement Power adjustment, and Customer 
Displacement Power administrative charges adjustment are part of the 
provisional

[[Page 60662]]

rates for SLCA/IP firm power. The provisions and methodologies for 
these adjustments are not being modified and will remain as specified 
in SLIP-F6.

Comments

    The comments and responses regarding the firm power rate, 
paraphrased for brevity when not affecting the meaning of the 
statement(s), are discussed below. Direct quotes from comment letters 
are used for clarification where necessary.
    The issues discussed are (1) Purchase Adder Rate (PAR), (2) 
Purchase Power, (3) O&M, (4) Central Utah Project (CUP), (5) status of 
issues which were identified as outstanding in the Rate Brochure, (6) 
Merchant Function Revenues, (7) Basin Fund, and (8) miscellaneous 
comments.
1. PAR
    Comment: Because of the potential volatility and magnitude of the 
PAR, a majority of the comment letters received by the CRSP MC 
suggested that Western eliminate the PAR and put purchase power costs 
back into the PRS and include the costs in the firm power rate.
    Response: In its March 6, 2002, proposal, at the request of some 
firm power customers, Western removed all purchase power costs from the 
PRS and included the near-term purchase power costs in a PAR. The PAR 
was initially calculated at 2.6 mills/kWh. At its second Public 
Information Forum on April 23, 2002, the CRSP MC provided a revised 
calculation of the PAR at 5.1 mills/kWh. This revision reflected 
updated reservoir conditions which resulted in increased purchased 
power needs for the next 2 years. The PAR would be subject to further 
revisions, depending upon hydrological projections at the time of the 
rate order submission.
    The CRSP MC received an overwhelming number of comments and 
concerns expressed by the customers concerning the PAR. The CRSP MC has 
made the decision to eliminate the PAR and include purchase power 
expenses in the Rate-Setting PRS when calculating the firm power rate. 
Western has not included additional comments received regarding the PAR 
calculation since it has determined to eliminate the PAR.
2. Purchase Power
    A. Comment: Customers suggest that Western reconsider its approach 
in determining purchase power costs for the PRS, at least in the early 
years, to recognize the near-term hydrology, depleted reservoirs, and 
Western's commitment to deliver all energy in excess of SHP to its 
customers at the firm power rate. Customers further recommend that 
Western determine purchase power projections in a manner similar to 
that under Rate Schedule SLIP-F6 (current rate schedule). Customers 
recommend that Western determine rates consistent with its historical 
methodologies. The customers also desire to work with Western to 
determine the adequate amount of purchases that should be included in 
the rate-setting PRS.
    Response: The CRSP MC recognizes the current dry hydrological 
conditions and subsequent depleted reservoirs and has attempted to 
reflect this in the purchase power estimates. The near-term purchases 
are based on Reclamation's 24-month hydrological study for FY's 2003 
and 2004 and average hydrology for the remainder of the rate-setting 
years.
    B. Comment: Several customers suggest Western use average hydrology 
to project purchase power in the PRS. Customers believe this conforms 
to the Post-1989 Marketing Criteria and is consistent with historic and 
current treatment in the PRS. In particular, some customers also 
commented on the May 2, 2002, data provided regarding average 
hydrology, which indicated purchases of $42 million in FY 2002 and no 
purchases in FY 2004 through 2007 to support their position on the use 
of hydrology.
    Response: The CRSP MC has used Reclamation's 24-month hydrological 
study for projecting purchase power costs in FY's 2003 and 2004. Beyond 
those years, the CRSP MC used average hydrology in projecting purchase 
power costs in the long-term.
    The data provided May 2, 2002, was an estimate developed for 
discussion purposes only. The CRSP MC further updated its analysis of 
average hydrology, which indicates purchases are needed throughout the 
Rate-Setting PRS.
    C. Comment: To the extent it is allowed by law and regulation, a 
customer recommended that Western use physical as well as financial 
risk mitigation methods to minimize the rate risk. As part of this, 
customers suggest that Western, to the extent it is not prohibited by 
law and/or regulation, evaluate using hydro availability hedges.
    Response: Western is open to considering such possibilities which 
would limit its risk. Western does have Federal laws, regulations, 
etc., that need to be taken into consideration, depending on the 
details of customer suggestions.
    D. Comment: A customer suggests that Western use an 11 percent loss 
factor at Glen Canyon when determining energy available for purchase 
power projections.
    Response: The purchase power projections reflect an 11 percent loss 
factor at Glen Canyon and 5.5 percent at other SLCA/IP generating 
units. Assuming that 70 percent of SLCA/IP generation comes from Glen 
Canyon Power Plant, the average loss factor applied is 9.35 percent.
    E. Comment: Western received a small number of comments regarding 
various alternatives for assessing purchase power costs. These 
proposals include: (1) Western should allow its preference power 
customers to make a decision to temporarily reduce their SHP 
entitlements, (2) Western should develop rate-based alternatives such 
as a ``slice of the system,'' possibly under conditions of low 
hydrology or high purchase power expense, and (3) Western should 
provide a more flexible situation where additional firming purchases 
are a customer decision, rather than solely Western's. A customer wants 
assurance that the revised rate will provide for delivery of full SHP.
    Response: Based on the large number of comments Western received 
suggesting that it should not implement a PAR and include purchased 
power costs in the firm power rate, Western has decided to include 
purchases in the Rate-Setting PRS in developing the firm energy and 
capacity rates. On October 1, 2002, Western expects to begin providing 
the contractually obligated capacity and energy as provided for under 
the Post-1989 Marketing Plan and what is commonly referred to as 
Contract Amendment No. 4.
3. O&M
    A. Comment: Customers support inclusion of Western's FY 2004 Work 
Plan O&M budgets, but believe it is premature to include Reclamation's 
FY 2004 Work Plan O&M budgets.
    Response: Based on customers' requests, Western included its FY 
2004 Work Plan in the Rate-Setting PRS. For consistency purposes, 
Western believes that it is appropriate to also include Reclamation's 
FY 2004 Work Plan. Western believes that both agency Work Plan 
documents are in similar stages of development, and have been made 
available for customer review.
    B. Comment: A customer is concerned that CRSP is only reducing by 5 
percent its budget request for FY 2003, rather than the 10 percent the 
other Western regions appear to be receiving in FY 2003.

[[Page 60663]]

    Response: The DOE, in an effort to shift its priorities more toward 
domestic security, has asked agencies such as Western to reduce FTE and 
thereby appropriations. Other budget items such as operation, 
maintenance, replacements, and emergency expenditures, were not 
reduced; therefore, the overall CRSP reduction was 5 percent.
    C. Comment: Customers suggest that Western and Reclamation further 
review the OM&R and capital costs for FY 2003 and FY 2004 and 
aggressively pursue opportunities to reduce or defer costs beyond the 
rate-setting window.
    Response: Western will continue to pursue cost reduction 
opportunities; however, it must also satisfy the need to provide a 
reliable system. Western believes that the Work Program Review process 
that it conducts with its customers has been beneficial in reducing 
both Reclamation and Western's O&M.
    D. Comment: A customer wants to know how the allocation from other 
Western Regions impacted the budget projections after Transformation.
    Response: Overall costs decreased following Transformation as 
Western reduced FTE, with a major reduction coming from CRSP.
    As part of the reorganization, most of the O&M functions of the 
CRSP MC were moved to Western's RMR and DSWR. There were some costs in 
the other Western Regions that were appropriate to be allocated to CRSP 
that had not been anticipated in the FY 1998 budget, which the existing 
firm power rate is based upon. An example of this is the allocation to 
CRSP for a portion of a region's facility costs and capitalized SCADA 
costs.
    E. Comment: A customer wants an explanation of the significant 
increase in costs of the Reclamation offices. As part of this, the 
customer wants to know what power program services costs became 
allocated to power.
    Response: In the proposed rate, Reclamation has allocated costs 
associated with CRSP O&M costs of Upper Colorado River Basin offices to 
power based on their allocated, multipurpose, cost-share percentages. 
These percentages are described in the Reclamation Report on Allocation 
of Costs for the Colorado River Storage Project, dated December 1974. 
Reclamation's offices allocate O&M costs to various projects, such as 
CRSP. The costs that are directly charged to CRSP are further allocated 
to various purposes, such as power. The following provides power's 
percentage share of these that are charged to CRSP:
    Ninety-two percent of the charges to CRSP from the Regional Office 
in Salt Lake City, Utah, are included in the Rate-Setting PRS. The 
Regional Office operates the mainstream reservoirs, including 
forecasting flow recommendations, coordination of conflicting multiple 
uses, and meeting legal requirements.
    Ninety percent of the charges to CRSP from the Provo Office in 
Provo, Utah, are included in the Rate-Setting PRS. The Provo Office 
provides assistance associated with the operation of Flaming Gorge Dam 
including coordination of release requirements.
    Ninety-seven percent of the charges to CRSP from the Grand Junction 
Office in Grand Junction, Colorado, are included in the Rate-Setting 
PRS. This office provides assistance on water operations and O&M 
activities for the Curecanti Unit.
    Ninety-seven percent of the charges to CRSP from the Denver Power 
Office in Denver, Colorado, are included in the Rate-Setting PRS. The 
Denver Power Office provides support with the Power Program Services 
Division and O&M support of CRSP facilities.
    Although the allocated share of CRSP costs allocated to power in 
these offices is between 90 and 100 percent, this amounts to only a 
small share of the total costs incurred by these offices for all of 
their project needs. For example, 5.6 percent of the Regional Office 
cost is a direct charge to the CRSP Project. Of those costs, 92 percent 
is allocated to power.
    F. Comment: Customers request that Western not include the budgets 
for the proposed A-LP transmission line and switchyard. Customers 
encourage Western to consider potential rate impacts prior to including 
new projects in its work plans.
    Response: The total budgeted costs for the proposed transmission 
line and switchyard are approximately $6 million from FY 2002 through 
FY 2006. This has a .07 mills/kWh impact on the firm power rate. 
Western will continue to include these costs in the Rate-Setting PRS as 
long as these costs are reflected in its budgets.
    G. Comment: Customers suggest Western consider the potential 
outcome of legislation on the treatment of Federal Civil Service 
Retirement System (CSRS) costs and remove those costs from the PRS.
    Response: The DOE General Counsel stated by memorandum dated July 
1, 1998, the Power Marketing Administrations (PMAs) have the authority 
to collect, through the rates, the full costs of the retirement 
benefits. In addition, FERC has issued numerous orders approving the 
inclusion of such costs in PMA rates: Western Area Power Administration 
(Boulder Canyon Project), 96 FERC ] 61,171 (2001), Western Area Power 
Administration (Central Valley Project), 96 FERC ] 62,150 (2001), 
Southeastern Power Administration, 91 FERC ] 61,272 (2000), Western 
Area Power Administration (Intertie Project), 87 FERC ] 61,346 (1999), 
and Southeastern Power Administration, 86 FERC ] 61,195 (1999). 
Therefore, Western believes it should continue to include these costs 
in the Rate-Setting PRS.
    If pending legislation addressing Federal retirement and health 
benefit costs is enacted into law, Western will assess the impact of 
that law on its decision to include these costs in the Rate-Setting 
PRS.
    H. Comment: A customer wants to understand how the Western 
Electricity Coordinating Council (WECC) dues are broken out by the 
various projects.
    Response: WECC assesses dues by control area and the amount of load 
in the control area. Western Area Colorado Missouri (WACM) and Western 
Area Lower Colorado (WALC) control areas both receive an assessment 
from WECC, and CRSP has loads in both control areas. The control areas 
break down the recovery by loads and bill the loads directly for their 
portion of the bill, based on their proportional share of the load. For 
firm electric service, Western pays for that portion of the load at 
each Federal delivery point, and the remainder is recovered through 
billing the load directly.
    I. Comment: Customers request that Western not include the Common 
Electronic Scheduling System budgeted for in its FY 2004 Work Plan. 
Customers believe that these items should not be included in the PRS 
until the operational benefits associated with the investment are 
quantified.
    Response: The Common Electronic Scheduling System costs are not 
included in the projected revenue requirement. Once Western purchases 
the system, the costs will be added to the CRSP CME. Then, depreciation 
charges are assessed against the total amount of CRSP CME. The sum of 
the depreciation charges is recorded annually in the PRS as an O&M 
expense. The Rate-Setting PRS projects CME depreciation costs based 
upon historical charges.
    J. Comment: Several customers suggest that Western make security 
costs non-reimbursable as has the Department of the Interior.
    Response: Western recognizes that Reclamation has made a 
determination that the security expenses funded by

[[Page 60664]]

Public Law 107-117, ``for emergency expenses to respond to the 
September 11, 2001, terrorist attacks,'' are to be considered non-
reimbursable. Western has not received any appropriations to respond to 
post-September 11 security concerns. If Western does, it will make a 
determination at that time regarding the reimbursability of the 
expenses.
4. CUP
    A. Comment: Customers support Western and Reclamation's agreement 
not to include certain CUP costs within the PRS, which resulted in 
approximately 2 mills/kWh savings. Several customers request that 
Western eliminate the CUP irrigation repayment costs from the PRS. 
Customers suggest that Western does not need to proceed with a rate 
adjustment at this time. Customers believe that there is significant 
``cushion'' in the PRS due to an expected change in the CUP purposes 
from agricultural to municipal and industrial uses, which the customers 
believe will cause a major reduction in the CRSP rate. Customers 
believe that the CUP is the ``driver'' of the apportionment. Customers 
encourage timely completion of the revised DPR and cost allocations.
    Response: There are $149.8 million of costs attributable to 
completion of the Bonneville Unit that have not met the criteria set 
forth by a 1983 agreement between Reclamation and Western and, 
therefore, are not included in the SLCA/IP firm power rate base. In FY 
2001, $34.7 million of these costs met the 1983 agreement criteria 
which allows for these construction dollars to be included in the Rate-
Setting PRS. However, these costs were not included, because of the 
potential change in the revised draft DPR and cost allocations. In 
December 2001, Western and Reclamation signed an agreement with the CUP 
Completion Act Office that the amount ($536.6 million) that was 
currently in the Rate-Setting PRS for the Bonneville Unit not be 
revised until the CUP Completion Act Office approves a draft supplement 
to the 1988 DPR.
    It is expected that this draft supplement will be available in late 
FY 2003. At that time, Western, Reclamation, and the CUP Completion Act 
Office will discuss the implications of the change in the irrigation 
costs to be repaid by the power users. It is unknown what the rate 
impact of the draft supplement will be on the firm power rate. Until a 
draft supplement is completed, Western will continue to include the CUP 
irrigation repayment costs in the Rate-Setting PRS in accordance with 
the agreement between Western and Reclamation.
    B. Comment: A customer wants to know why 10 years is being used for 
the Bonneville Unit power investigation costs amortization period. 
Several customers request that Western remove from the PRS the $12.6 
million of ``sunk'' power investigation costs for the Bonneville Unit 
of the CUP. A customer argues that these costs should not be included 
in accordance with RA 6120.2, which states that expenditures booked to 
construction accounts become part of the rate analysis when the asset 
is placed in service. Customers cite the pending Federal legislation to 
make these costs non-reimbursable as cause to exclude these costs from 
the PRS.
    Response: The Rate-Setting PRS amortizes these costs over a 10-year 
period without interest. Western's independent auditors suggested using 
a 10-year period because it lessened the impact to the customers as 
opposed to expensing this amount in a single year. Western believes 
that the $12.6 million, which is without interest during construction 
or interest in investment expenses, of power investigation costs should 
not be recognized as construction costs. Rather, these costs are 
considered investigation costs and not construction costs and, 
therefore, need to be recovered. Western is aware of the pending 
Federal legislation that potentially changes these costs to a non-
reimbursable treatment. If this legislation is passed, Western will 
remove these costs from the financial statements and the PRS.
5. Outstanding Issues
    A. Comment: A customer requests that the pending issues of 
reconstructing CRSP investments, accounting for system losses, deferred 
costs of the Bonneville unit completion and the A-LP, and Glen Canyon 
cost allocations under the GCPA be resolved and reflected in the rate 
as much as possible.
    Response: The CRSP MC will continue to work on resolving these 
outstanding issues. Once the issues are resolved, the CRSP MC will 
reflect its resolution in the PRS. None are expected to have a major 
impact on the firm power rate. In accordance with RA 6120.2, Western 
will continue to perform yearly PRSs to determine if the rate is 
sufficient to meet all required payments.
    B. Comment: Customers recognize that the outstanding issue of 
``CRSP Reconstruction of Investment'' is internal to Western and 
request that the scenario that Western believes will most likely occur 
be included in the PRS.
    Response: At the time of this rate order, Western is uncertain of 
the final resolution of this issue. There remains an amount of internal 
review regarding this issue. Therefore, the CRSP MC believes it is 
premature to speculate as to the likelihood or the extent of the 
potential resolution in the Rate-Setting PRS. Western will include the 
final determination in the PRS once a decision is made and the dollar 
amount is recorded in the audited financial statements.
    C. Comment: A customer wants to know the status of the 
determination of non-reimbursability of Aspinall and Flaming Gorge 
studies which are budgeted by Reclamation.
    Response: Flaming Gorge and Aspinall studies associated with the 
RIP are considered non-reimbursable. Costs associated with preparing an 
Environmental Impact Statement at Flaming Gorge, Aspinall, and Navajo 
have been determined by Reclamation to be partially non-reimbursable. 
Reclamation will continue to evaluate the costs of environmental 
studies at Aspinall, Flaming Gorge, and Navajo to determine if there is 
any justification to change the status of all of these expenses to non-
reimbursable.
6. Merchant Function Revenues
    A. Comment: Customers expressed concern over the revision which 
decreased the Merchant Function revenue projection. A customer 
recognizes the aberration the 2001 data caused to the Merchant Function 
revenues. A customer believes that Western should go back to the 
original estimate of non-firm transmission and Merchant Function 
revenues.
    Response: Because the historical data for Merchant Function and 
non-firm transmission revenues is quite volatile, Western chose to use 
a 5-year average of these revenues instead of the 3-year average 
initially proposed. Currently, in FY 2002, CRSP is experiencing a 
drastic reduction in Merchant Function and non-firm transmission 
revenues. The CRSP MC believes that placing too much emphasis on 
historic revenues stemming from volatile conditions that occurred in 
FYs 2000 and 2001 might be overstating future revenues for rate-making 
purposes. The FY 2002 projection is based on actual data through 2002.
    B. Comment: Customers support Western's recalculation of non-firm 
transmission and Merchant Function revenue projections as being a 
reasonable approach.
    Response: Western believes that the recalculation of both non-firm 
transmission and Merchant Function revenues based on 5 years of 
historical data instead of the 3 years originally

[[Page 60665]]

proposed is a better estimate of future revenues.
    C. Comment: A customer questions if Merchant Function revenue 
includes sales of AHP at current rate.
    Response: Merchant Function revenues include revenue from purchases 
for resale activities and from transaction fees. These do not include 
any AHP revenues either historically or in the projection. Revenues 
from AHP sales are included historically as part of firm power sales 
revenues and are netted against future purchases.
    D. Comment: A customer questions the costs of the Merchant Function 
activities on an annual basis. Customers question profitability and the 
viability of this function. A customer believes Merchant Function 
revenues should be increasing due to increased Merchant Function staff.
    Response: Western believes that the $5.5 million of annual revenues 
forecasted more than offset the costs of this function. The activities 
solely related to the Merchant Function are approximately $1.3 million 
yearly. These costs include labor, programming support, computer costs, 
and building expenses. These are offset by transaction fee charges and 
by purchases-for-resale activities. The transaction fees are updated 
each FY to ensure recovery of Merchant Function activities performed 
for others.
7. Basin Fund
    A. Comment: A customer suggests that Western devote more staff and 
attention to plan for and regularly update its cash reserve 
requirements, so customers and Western are not faced with Basin Fund 
cash flow concerns in the future. Customers encourage Western to 
maintain a reasonable Basin Fund level to accomplish project purposes 
and to work with its customers to maintain options to address Basin 
Fund cash flow constraints.
    Response: Due to market volatility, recent drought conditions, and 
environmental test flows, the Basin Fund has been severely depleted of 
its available cash. As a result, the CRSP MC worked closely with its 
customers to find alternative solutions to remedy this situation. The 
CRSP MC is fully devoted and attentive to the cash balance in the Basin 
Fund and routinely performs cash flow analysis to help ensure the 
solvency of the Basin Fund. As part of the fiscal year end process, 
Western works in consultation with its customers and Reclamation in 
determining the appropriate level of cash balance for the following 
fiscal year. Western is obligated, under the CRSP Act, to annually 
return revenues in the Basin Fund in excess of operating needs to the 
General Fund of the Treasury.
    B. Comment: A customer expressed concern that the CRSP MC's 
management of a collaborative process is flawed. A customer cites 
example of customer's assistance in receiving a ``slice'' to help build 
the Basin Fund level to reasonable levels. This customer is concerned 
that now that the Basin Fund level is at a reasonable level, Western is 
proposing to return to providing the full contract commitment and will 
no longer continue providing a ``slice,'' even at customers' requests.
    Response: The CRSP MC believes in the benefits of a collaborative 
process. Unfortunately, it is not always able to achieve an optimal 
resolution for Western and its customers.
    C. Comment: Customers encourage Western to consider other options 
to alleviate immediate cash flow pressures. Customers have significant 
concern about the impacts to Basin Fund cash flows resulting from non-
reimbursable expenses, primarily associated with environmental 
programs.
    Response: Western continues to be open to options which assist in 
alleviating cash flow constraints. When the Basin Fund provides for 
non-reimbursable expenses, it reduces the amount of cash available for 
other expenditures within the Basin Fund. The non-reimbursable costs 
are primarily a result of environmental programs under the GCPA and the 
RIP.
    Section 1807 of the GCPA, states that: ``The Secretary is 
authorized to use funds received from the sale of electric power and 
energy from the Colorado River Storage Project to prepare the 
environmental impact statement, described in Section 1804, including 
supporting studies, and the long-term monitoring programs and 
activities described in Section 1805. Except, funds will be treated as 
having been repaid and returned to the General Fund of the Treasury as 
costs assigned to power for repayment under Section 5 of the CRSP 
Act.'' This legislation allows for, but does not mandate, the use of 
power revenues for these purposes. Western has informed the Adaptive 
Management Work Group that should funds not be available to conduct an 
experiment, Western will work with Reclamation and others to obtain 
alternative sources of funds.
    The Recovery Implementation Program legislation, Pub. L. 106-392, 
Section 3(d)(3)(2) provides that: ``If Western Area Power 
Administration and the Bureau of Reclamation determine that the funds 
in the Colorado River Basin Fund will not be sufficient to meet the 
obligations of section 5(c)(1) of the Colorado River Storage Project 
Act for a 3-year period, the Western Area Power Administration and the 
Bureau of Reclamation shall request appropriations to meet base funding 
obligations.'' This legislation provides Western with more flexibility 
in funding those costs. Western will notify Reclamation that 
alternative funding sources should be sought if Basin Fund projections 
indicate it to be insufficient.
    D. Comment: A customer is opposed to the use of the PAR as the 
method to increase the level of the Basin Fund.
    Response: The PAR was proposed to recover the cost of near-term 
purchase power costs only and was not designed to increase the level of 
the Basin Fund. The ``true-up'' component of the PAR formula was 
developed to ensure that firm power customers only paid for their 
actual purchased power costs.
    E. Comment: Several customers expressed concern over the reduction 
in resources available at the firm power rate as a result of the 
reduced Basin Fund balance which was largely drawn down by 
environmental programs, below average hydrology, and high market prices 
for purchase power. Customers suggested this reduction in resources be 
taken into account when setting a new rate so that CRSP costs are not 
further exacerbated.
    Response: Due to market volatility, recent drought conditions, and 
environmental test flows, the Basin Fund was severely depleted of its 
available cash. The Basin Fund balance reached a level that CRSP MC 
could no longer provide the cash for the firming purchases. As a 
result, the CRSP MC worked closely with its customers to find 
alternative solutions to remedy this situation. Western appreciates its 
firm power customers' assistance in this matter and recognizes the 
financial hardships to the customers due to market volatility and 
market conditions. The CRSP MC is establishing a firm power rate at the 
lowest possible rate consistent with sound business practices. This 
rate will allow the CRSP MC to return to including firming purchases to 
meet contract capacity and energy commitments in the firm power rate.
8. Miscellaneous
    A. Comment: Several customers expressed concerns regarding 
decreased project use energy for A-LP and its impact on the firm power 
rate. Some customers questioned if this energy should be AHP.
    Response: The total energy sales used to calculate the existing 
rate is different

[[Page 60666]]

from the proposed rate due to the reduction in project use commitments. 
The energy used as the rate denominator is the sum of firm power and 
project use commitments. This difference is made available as AHP if 
Western has surplus generation, or it is used to reduce the amount of 
purchased power needs. Annually, Western experiences changes in the 
amount of total energy sales because of updated estimates for project 
use loads. For example, in the last rate process, the energy amount 
increased by 453 GWh because the contractual energy delivered was 
projected to increase throughout the rate-setting period.
    B. Comment: Customers inquired if the PRS reflects the downsized A-
LP in aid to irrigation amounts.
    Response: The PRS currently includes no revenue requirements 
associated with the A-LP. The irrigation assistance requirements of the 
CUP and the provisions for the State of Colorado's apportionment as 
included in the CRSP Act provides more than enough revenue to Colorado 
for its planned irrigation development projects.
    C. Comment: A customer wants to understand what non-reimbursable 
costs are excluded from the Rate-Setting PRS.
    Response: All non-reimbursable costs are excluded from the Rate-
Setting PRS. For Western, non-reimbursable costs excluded are RIP 
initiatives and purchased power costs for low-water monitoring studies 
pertaining to implementing the GCPA. This includes costs for some 
personnel at CRSP MC and the Corporate Services Office who perform 
activities related to the RIP and GCPA. RIP costs also include a 
contract with Argonne National Laboratories (DOE).
    In Reclamation's budget, costs for the Glen Canyon Adaptive 
Management Program as well as the RIP base funding are considered non-
reimbursable costs. Also excluded from the PRS because of non-
reimbursability are such Reclamation costs as land resources 
management.
    D. Comment: A customer wants assurance that Glen Canyon 
experimental flows are non-reimbursable.
    Response: Glen Canyon experimental test flows occurred in FY 2000. 
The purchased power expense that was deemed to be non-reimbursable 
amounted to $21.5 million in FY 2000. These were a result of 
experimental flows and are reflected as non-reimbursable expenses in 
the Rate-Setting PRS. As stated in Section 1807 of the GCPA, ``All 
costs of preparing the environmental impact statement described in 
section 1804, including supporting studies, and the long-term 
monitoring programs and activities described in section 1805 shall be 
non-reimbursable.''
    E. Comment: A customer wants to know when the FYs 2000 and 2001 
audited financial data will be available.
    Response: Western finalized the audited financial statements for FY 
2000 in March 2002. Western expects to complete FY 2001 audited 
financial statements before the end of 2002.
    F. Comment: A customer wants to know what is included in 
Miscellaneous Revenues.
    Response: This category includes ancillary services, facility-use 
charges, administrative charges, auxiliary services, and other 
miscellaneous operating revenues.
    G. Comment: Customers expressed concern that AHP revenues are not 
in the PRS.
    Response: AHP sales result when Western has additional 
hydrogeneration above what is obligated to the firm power customer by 
contract. Revenue from these sales is reflected historically in the 
firm power revenues. In forecasting future years in the Rate-Setting 
PRS, this additional hydro is used to offset projected purchase power 
needs.

CRSP Transmission Discussion

    A new rate methodology is being proposed that is more consistent 
with the methodology used at other Western regions and other utilities. 
The proposed methodology is an annual fixed charge formula that will be 
used to determine the revenue requirement to be recovered from 
transmission service. The annual transmission revenue requirement 
includes O&M expense, administrative and general expense, interest 
expense, and depreciation expense from the most recent historical test 
year. This transmission revenue requirement is offset by appropriate 
CRSP revenue credits.
    The CRSP transmission system includes its own facilities and the 
transmission facilities owned by others over which the CRSP MC has 
contractual rights. All the costs of the CRSP transmission system, 
including the costs paid to others for the contractual rights on their 
transmission lines, are in the total CRSP transmission revenue 
requirement.
    The provisional firm transmission rate will be applied to customers 
who purchase transmission services. The costs of CRSP firm transmission 
associated with the delivery of SLCA/IP firm power are included in the 
firm power rate.
    The costs for providing scheduling, system control, and dispatch 
service are included in the appropriate provisional transmission 
services rates. Because the CRSP transmission system lies in two other 
Western Regions, the charges for reactive supply and voltage control 
service will be in accordance with each Region's applicable tariff.
    The provisional transmission rate formulas are scheduled to go into 
effect October 1, 2002, to correspond with the effective date of the 
provisional firm power rate.

CRSP Transmission Rate

Point-to-Point

    The current firm transmission rate expires March 30, 2003. The 
provisional rate for firm point-to-point CRSP transmission service for 
FY 2003 is $2.06 per kWmonth and will result in a 16 percent increase 
from the existing rate of $1.78 per kWmonth under Rate Schedule SP-
PTP6, effective April 1, 2002. The provisional rate for non-firm CRSP 
transmission service is expressed in mills/kWh and is based on the 
current CRSP firm point-to-point rate, and may be discounted. The non-
firm transmission rate for FY 2003 is 2.82 mills/kWh.
    The proposed transmission rate methodology is different from the 
current transmission rate methodology, primarily in four areas. The 
first area is the basis for cost projections. In the current 
transmission rate calculation, the CRSP MC uses the average of 5-year 
projections. The provisional transmission rate is based on the most 
recent financial data from 1 year.
    The second area is the allocating of Western's O&M costs in the 
revenue requirement that are allocable to generation and transmission. 
In the current transmission rate calculation, the CRSP MC determines 
the percentage of CRSP transmission investment relative to total CRSP 
Reclamation and Western investment and applies this percentage to 
projected Western CRSP O&M budgets. The provisional transmission rate 
is based on the percentage of Western's CRSP transmission investment to 
total Western CRSP investment, and this percentage is applied to 
Western's test year O&M costs.
    The third area is the allocation of Western's capital costs 
attributable to both generation and transmission. In the current 
transmission rate calculation, the CRSP MC assigns these costs to 
generation and transmission on a 50/50 basis. In the provisional 
transmission rate calculation, Western has analyzed capital costs more 
closely and assigned

[[Page 60667]]

them more specifically relative to transmission usage.
    The fourth area is the annual recalculation of the formula. In the 
current transmission rate, the CRSP MC annually updates revenue credits 
and transmission capacity reservations and holds the annual revenue 
requirement constant. The provisional transmission rate recalculates 
all components of the formula annually as new test year data become 
available.
    The increase in the CRSP firm transmission service rate is due to 
the gross transmission revenue requirement increasing. This increase is 
being offset by an increase in transmission revenue credits and in firm 
wheeling reservations.
    This table summarizes the difference in calculations between the 
current transmission rate and the provisional transmission rate. The 
table compares the change in the average annual projections used in the 
FY 2002 transmission study (which set the rate effective April 1, 2002) 
and the annual projections used in the rate-setting transmission study 
for this rate adjustment.

                                    Comparison of Annual Revenue Requirements
----------------------------------------------------------------------------------------------------------------
                                                                                    Provisional
                  Item                             Unit            Existing rate       rate          % Change
----------------------------------------------------------------------------------------------------------------
Annual Revenue Requirement.............  $......................      63,271,051      77,134,227              22
Transmission Revenue Credits...........  $......................       8,302,800      11,854,759              43
Net Annual Revenue Requirement.........  $......................      54,968,215      65,279,468              19
Firm Obligations.......................  kW.....................       2,134,792       2,226,740               4
Firm Point-to-Point Transmission         .......................         442,420         444,132               1
 Contracts.
Network Integration Loads..............  .......................               0               0
Transmission System Total Load.........  kW.....................       2,577,212       2,640,341               2
Cost per Year..........................  $......................           21.33           24.72              16
Cost per Month.........................  $......................            1.78            2.06              16
----------------------------------------------------------------------------------------------------------------

    The increase in annual Revenue Requirements is primarily a result 
of a revised methodology and increased O&M expenses. The increase in 
transmission credits is primarily a result of increased non-firm 
transmission and ancillary service revenues. The increase in firm power 
obligations is primarily a result of applying test year data instead of 
a 5-year average.

Network

    The same revenue requirement that was used in determining the 
provisional firm point-to-point transmission rate will also be used in 
the provisional rate formula for network integration transmission 
service. The provisional charge for the monthly demand for network 
integration transmission service will be the product of the network 
customer's load ratio share times one-twelfth (\1/12\) of the annual 
transmission revenue requirement. The load ratio share will be based on 
the network customer's hourly load (including its designated network 
load not physically interconnected with Western), coincident with 
CRSP's monthly transmission system peak, which will be calculated on a 
rolling 12-CP basis. Western's transmission system peak includes the 
sum of capacity reserved for point-to-point transmission, 12-CP monthly 
entitlements for SLCA/IP firm power customers, and the average 12-CP 
monthly system peak for network transmission service. The provisional 
rate formula is to be effective for the period beginning October 1, 
2002, through September 30, 2007.

Basis for Rate Development

    The existing rates for CRSP firm and non-firm transmission in Rate 
Schedules SP-PTP5, SP-NW1, and SP-NFT4 expire March 30, 2003. The rate 
adjustment contains rates that replace existing rates. The adjusted 
rates reflect a revised methodology and increases in O&M costs, revenue 
credits, and transmission system load. The provisional rates will 
provide sufficient revenue to pay all annual costs, including interest 
expense, and repayment of required investment within the allowable 
period. The provisional rates will take effect on October 1, 2002, to 
correspond with the start of the Federal fiscal year and will remain in 
effect through September 30, 2007.
    The provision for reactive power adjustment is part of the 
provisional rates for CRSP firm and non-firm transmission. The 
provisions and methodologies for this adjustment are not being modified 
and will remain as specified in SP-PTP5, SP-NW1, and SP-NFT5.
    The adjustment for losses provision contained in Rate Schedules SP-
PTP5, SP-NW1, and SP-NFT5 will remain the same and also include a 
statement to allow for financial compensation to recover losses.
    The proposed rates for CRSP transmission include a provision to 
pass through electric industry restructuring costs associated with 
providing transmission service. These costs will be passed through to 
each appropriate transmission customer.

Comments

    The comments and responses regarding the transmission rates, 
paraphrased for brevity when not affecting the meaning of the 
statement(s), are discussed below. Direct quotes from comment letters 
are used for clarification where necessary.
    A. Comment: A customer inquired if there is an additional 
methodology to reconcile between the old method and the proposed 
transmission method in terms of revenues collected.
    Response: Western has proposed a revised methodology for 
determining a rate to charge for transmission service. Any costs that 
are not included in the transmission revenue requirement are in the 
firm power revenue requirement. The firm power rate includes both 
transmission and power revenue requirements for firm power customers 
and reflects the revenues from firm and non-firm transmission as an 
offset. Therefore, the reconciling or balancing occurs in the firm 
power rate.
    B. Comment: A customer requested an explanation of the change in 
the components of the transmission rate denominator from the 
transmission rate effective April 1, 2001, to the proposed rate.
    Response: The April 1, 2001, rate included the (1) 1-CP firm power 
contract commitments, (2) 130,000 kW of Merchant Function reservation, 
(3) 250,000 kW for the Salt River Project

[[Page 60668]]

Exchange, and (4) 406,446 kW for firm transmission reservations.
    The provisional transmission rate includes the (1) 12-CP of firm 
power contract commitments, (2) 555,000 kW of Merchant Function 
reservation, (3) 250,000 kW for the Salt River Project Exchange, and 
(4) 444,132 kW for firm transmission reservations.
    C. Comment: A customer requested an explanation of the impact of 
the Reclamation investment exclusion in transmission O&M.
    Response: The existing transmission rate methodology allocates 
Western budgeted O&M based on the relationship between Western 
transmission investment to total Western and Reclamation investment. 
The proposed method allocates Western's test year O&M based on CRSP 
transmission investment to total CRSP investment and does not include 
Reclamation investment. More of Western's O&M expenses are allocated to 
transmission under the proposed methodology.
    D. Comment: A customer wanted to know if multi-project cost 
allocations impact the CRSP transmission amount included in the rate 
formula.
    Response: The CRSP transmission rate includes test year O&M 
expenses for Western's CRSP MC, DSWR, and RMR offices. O&M expenses are 
derived consistently with how these are budgeted, which is based on 
appropriate cost allocation, e.g. multi-project. Therefore, multi-
project cost allocations do have an impact on the CRSP transmission 
rate.
    E. Comment: A customer requested an explanation of the ``adjustment 
for industry restructuring'' and questioned if this clause was included 
in the existing rate schedule.
    Response: As discussion about Regional Transmission Organizations, 
Independent Transmission Companies, and Independent System Operators 
continues, Western is concerned that, if it joins such a group, the 
costs to join groups such as these be recovered through the 
transmission rate and that such recovery of costs could be delayed with 
substantial costs accruing. Furthermore, these costs (such as 
scheduling and dispatch) may not be allocable to all transmission 
customers. Therefore, the adjustment will allow Western to pass through 
those costs as they occur to the appropriate customer. Inasmuch as 
these costs are reflected as O&M expenses, Western will ensure that 
these costs are not being accounted for twice.
    F. Comment: A customer wanted to know how current the 9.10-percent 
fixed charge rate is in the Supporting Documentation. The customer 
wanted to know when the FY 2000 data will be available.
    Response: The fixed charge rate is a percentage calculation applied 
to the net transmission investment to derive an annual transmission 
revenue requirement. The 9.10 percent is the amount of interest charge 
listed in the Supporting Documentation. The fixed charge rate listed is 
23.57 percent. This is based on FY 1999 data.
    The FY 2000 data became available in early March 2002. The 9.10-
percent interest charge and the annual fixed charge rate have changed 
as a result of incorporating FY 2001 data as the test year. These 
amounts are now 9.55 percent for the interest charge, and 25.17 percent 
for the annual fixed charge rate.
    G. Comment: A customer believes there is a difference in 
transmission rates between the firm transmission and firm power 
customers. Firm power customers are assessed a constant bundled rate; 
firm transmission customers are assessed the rate that is developed 
annually. The customer wants to understand how the annual transmission 
rate changes impact the power repayment study.
    Response: The calculation for delivery to Firm Electric Service 
customers is on the same basis as for other firm transmission 
customers. The transmission rate denominator reflects the use of the 
CRSP transmission system by all parties, including the CRSP Merchant 
Function and Firm Electric Service customers. The same costs are 
applied to both transmission and firm power customers using the CRSP 
transmission system.
    The CRSP MC prepares a power repayment study annually. As part of 
this, a projection of firm transmission revenues and all costs of 
transmission service are included. These firm transmission revenues are 
based on the transmission rate then in effect. If the annual 
recalculation of the transmission rate results in a change in the 
forecast and if no other changes in the power repayment study occur, a 
revision to the firm power rate will likely be needed. However, because 
the transmission costs of the firm power customers are only one 
component of the bundled service and many other components of the power 
repayment study are changing and may offset the impact of a firm 
transmission rate change, a firm power rate change may not be 
necessary.
    H. Comment: A customer wanted to know if Western offers Network 
Service.
    Response: CRSP is not currently providing Network Service to any 
transmission customers. Once Western receives a request for this 
service, a study would be conducted to determine its feasibility.

Ancillary Services Discussion

    On April 1, 1998, the Western Area Upper Colorado control area, 
within which most of the CRSP transmission system lies, operated by the 
CRSP MC, was merged into two other control areas. These control areas 
are WACM, operated by Western's RMR, and WALC, operated by Western's 
DSWR.
    Six transmission ancillary services will be offered by the CRSP MC. 
These are (1) scheduling, system control, and dispatch service, (2) 
reactive supply and voltage control service, (3) regulation and 
frequency response service, (4) energy imbalance service, (5) spinning 
reserve service, and (6) supplemental reserve service. The first two--
scheduling, system control, and dispatch service; and reactive supply 
and voltage control service--are required services. The remaining four 
will also be offered from the control area or from the CRSP Merchant 
Function. These ancillary services are listed in Western's Tariff.
    Western's use of SLCA/IP resources to provide sales of ancillary 
services is subject to availability. Western has allocated most of its 
SLCA/IP power resources to preference entities under long-term 
commitments. Western will determine if any of its SLCA/IP resources are 
available to provide the ancillary service requested at the time of the 
request.
    The provisional rates for ancillary services are designed to 
recover only the costs associated with providing the service(s). The 
costs for providing scheduling, system control, and dispatch service 
are included in the provisional transmission service rates. The 
provisional rates and descriptions for the six ancillary services are:

[[Page 60669]]



                  Provisional Ancillary Services Rates
------------------------------------------------------------------------
                                   Ancillary service
     Ancillary service type           description      Provisional rate
------------------------------------------------------------------------
Scheduling, System Control, and   Required to         Included in
 Dispatch.                         schedule the        appropriate
                                   movement of power   transmission
                                   through, out of,    rates.
                                   within, or into a
                                   control area.
Reactive Supply and Voltage       Reactive power      DSWR rate
 Control.                          support provided    schedule--DSW-RS1
                                   from generation     , or RMR rate
                                   facilities that     schedule--L-AS2,
                                   is necessary to     or as superseded.
                                   maintain
                                   transmission
                                   voltages within
                                   acceptable limits
                                   of the system.
Regulation and Frequency          Generation          If available from
 Response.                         provided to match   SLCA/IP
                                   resources and       resources, the
                                   loads on a real-    firm capacity
                                   time continuous     rate will apply.
                                   basis.              If unavailable,
                                                       DSWR rate
                                                       schedule--DSW-FR1
                                                       , or RMR rate
                                                       schedule--L-AS3
                                                       or as superseded
                                                       will apply.
Energy Imbalance................  Provided when a     DSWR rate
                                   difference occurs   schedule--DSW-EI1
                                   between the         , or RMR rate
                                   scheduled and       schedule--L-AS4
                                   actual delivery     or as superseded,
                                   of energy to a      or the customer
                                   load or from a      can make
                                   generation          alternative
                                   resource within a   comparable
                                   control area over   arrangements.
                                   a single hour.
Spinning Reserve................  Needed to serve     Based on terms and
                                   load immediately    conditions of
                                   in the event of a   WSPP contract.
                                   system
                                   contingency.
Supplemental Reserve............  Needed to serve     Based on terms and
                                   load in the event   conditions WSPP
                                   of a system         contract.
                                   contingency;
                                   however, it is
                                   not available
                                   immediately to
                                   serve load, butof
                                   rather within a
                                   short period of
                                   time.
------------------------------------------------------------------------

Comments

    The comments and responses regarding ancillary service rates, 
paraphrased for brevity when not affecting the meaning of the 
statement(s), are discussed below. Direct quotes from comment letters 
are used for clarification where necessary.

Comments

    A. Comment: A customer wanted to know where regulation services 
come from that go to WACM.
    Response: CRSP resources provide 20 MW to the WACM control area to 
regulate SLCA/IP firm electric service loads in that control area. WACM 
uses its own resources to provide regulation to its customers.
    B. Comment: A customer questioned the role of Western's control 
area consolidation in causing the increase in losses.
    Response: Western is still examining this issue and believes that 
the increase in the Glen Canyon loss factor from previous amounts is 
likely due to several factors, one of which is increased use of the 
CRSP transmission system.
    CRSP MC has recently reduced the losses applied in determining 
available generation from 11 percent from all generators to 5.5 
percent, with the exception of Glen Canyon which remains at 11 percent. 
The average loss factor applied equates to 9.35 percent.
    C. Comment: A customer questioned if CRSP is being fairly 
compensated for ancillary services. The customer requested assurance 
that ancillary services are appropriately credited to the Basin Fund 
from other regions.
    Response: The CRSP MC revenue requirements for ancillary services 
are used to calculate rates for ancillary services in each particular 
region. Accounting mechanisms have been put into place to track these 
revenues. Since 1998, the CRSP MC has received approximately $8 million 
into the Basin Fund from ancillary service revenues.

Environmental Compliance

    In compliance with the National Environmental Policy Act (NEPA) of 
1969, 42 U.S.C. 4321, et seq.; Council on Environmental Quality 
Regulations, 40 CFR parts 1500-1508; and DOE NEPA Regulations, 10 CFR 
part 1021, Western has determined that 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; accordingly, no clearance of this notice by the 
Office of Management and Budget is required.

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. Western has 
determined that 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.

Small Business Regulatory Enforcement Fairness Act

    Western has determined that 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.

Availability of Information

    Information about this rate adjustment, including power repayment 
studies, comments, letters, memorandums, and other supporting material 
made or kept by Western used to develop the provisional rates, is 
available for public review in the Colorado River Storage Project 
Management Center, Western Area Power Administration, 150 East Social 
Hall Avenue, Suite 300, Salt Lake City, Utah.

Submission to the Federal Energy Regulatory Commission

    The interim rates herein confirmed, approved, and placed into 
effect, together with supporting documents, will be submitted to FERC 
for confirmation and final approval.

Order

    In view of the foregoing and pursuant to the authority delegated to 
me, I confirm and approve on an interim basis, effective October 1, 
2002, Rate Schedules SLIP-F7, SP-PTP6, SP-NW2, SP-NFT5, SP-SD2, SP-RS2, 
SP-EI2, SP-FR2, and SP-SSR2 for the Salt Lake City Area Integrated 
Projects and the

[[Page 60670]]

Colorado River Storage Project of the Western Area Power 
Administration. The rate schedules shall remain in effect on an interim 
basis, pending FERC's confirmation and approval of them or substitute 
rates on a final basis through September 30, 2007.

    Dated: September 10, 2002.
Spencer Abraham,
Secretary.

Salt Lake City Area Integrated Projects; Arizona, Colorado, Nevada, New 
Mexico, Utah, Wyoming; Schedule of Rates for Firm Power Service

    Effective: The first day of the first full billing period beginning 
on or after October 1, 2002, and extending through September 30, 2007, 
or until superseded by another rate schedule, whichever occurs earlier.
    Available: In the area served by the Salt Lake City Area Integrated 
Projects.
    Applicable: To the wholesale power customer for firm power service 
supplied through one meter at one point of delivery, or as otherwise 
established by contract.
    Character and Conditions of Service: Alternating current, 60 hertz, 
three-phase, delivered and metered at the voltages and points 
established by contract.
    Monthly Rates: Demand Charge: $4.04 per kilowatt of billing demand.
    Energy Charge: 9.5 mills per kilowatthour of billing energy.

Billing Demand

    The billing demand will be the greater of:
    1. The highest 30-minute integrated demand measured during the 
month up to, but not more than, the delivery obligation under the power 
sales contract, or
    2. The Contract Rate of Delivery.
    Billing Energy: The billing energy will be the energy measured 
during the month up to, but not more than, the delivery obligation 
under the power sales contract.
    Adjustment for Transformer Losses: If delivery is made at 
transmission voltage but metered on the low-voltage side of the 
substation, the meter readings will be increased to compensate for 
transformer losses as provided for in the contract.
    Adjustment for Power Factor: The customer will be required to 
maintain a power factor at all points of measurement between 95 percent 
lagging and 95 percent leading.
    Adjustment for Western Replacement Power: Pursuant to the 
Contractor's Firm Electric Service Contract, as amended, Western will 
bill the Contractor for its proportionate share of the costs of Western 
Replacement Power (WRP) within a given time period. Western will 
include in the Contractor's monthly power bill the cost of the WRP and 
the incremental administrative costs associated with Western 
Replacement Power.
    Adjustment for Customer Displacement Power Administrative Charges: 
Western will include in the Contractor's regular monthly power bill the 
incremental administrative costs associated with Customer Displacement 
Power.

Colorado River Storage Project; Arizona, Colorado, Nevada, New Mexico, 
Utah; Schedule of Rate for Firm Point-to-Point Transmission Service

    Effective: The first day of the first full billing period beginning 
on or after October 1, 2002, and extending through September 30, 2007, 
or until superseded by another rate schedule, whichever occurs earlier.
    Available: In the area served by the Colorado River Storage Project 
(CRSP) transmission system.
    Applicable: To firm point-to-point transmission service customers 
for which power and energy are supplied to the CRSP transmission system 
at points of interconnection with other systems and transmitted and 
delivered, less losses, to points of delivery on the CRSP transmission 
system established by contract.
    Character and Conditions of Service: Transmission service for 
alternating current, 60 hertz, three-phase, delivered and metered at 
the voltages and points of delivery established by contract.
    Point-to-Point Rate Formula: The firm point-to-point rate is based 
on a test year using an annual fixed charge methodology. The test year 
is the most recent historical data available. The annual revenue 
requirement is reduced by revenue credits. The resultant net annual 
cost to be recovered is divided by the capacity reservation needed to 
meet firm power and transmission commitments in kW, including the total 
network integration loads at system peak, to derive a cost/kWyear. The 
cost/kWyear is calculated using the following formula:
[GRAPHIC] [TIFF OMITTED] TN26SE02.016

Where:

ARR = Annual Revenue Requirement. The costs associated with facilities 
that support the transfer capability of the CRSP transmission system, 
excluding generation facilities. These costs include investment costs, 
interest expense, depreciation expense, administrative and general 
expenses, and operation and maintenance expense, including transmission 
purchases. Transmission purchases reflect those costs associated with 
CRSP contractual rights.
TRC = Transmission Revenue Credits. The revenues generated by the CRSP 
transmission system, such as scheduling and dispatch ancillary service 
revenues and phase shifter revenues, and excluding long-term firm 
transmission revenues.
NARR = NetAnnual Transmission Revenue Requirement. The Annual Revenue 
Requirement less Transmission Revenue Credits.
TSTL = CRSP Transmission System Total Load. The sum of the total CRSP 
transmission capacity under the long-term reservation plus the total 
network integration loads at system peak.

    This formula will be recalculated annually by applying the data 
from the most current historical test year. If needed, a revised rate 
will be placed into effect every October 1. Western will provide 
notification 30 days prior to a revised rate becoming effective.
    The rate for transmission service includes scheduling, system 
control, and dispatch. Rate Schedule SP-RS2, or any superseding rate 
schedule, for reactive supply and voltage control is attached as part 
of this Rate Schedule and applies to firm point-to-point transmission 
customers.
    Billing: The point-to-point transmission customer will be billed 
monthly by applying the resulting rate to the maximum amount of 
capacity reserved, payable whether used or not, except as otherwise 
provided in existing contracts.
    Requirements for Reactive Power: Requirements for reactive power 
shall be as established by contract; otherwise, there shall be no 
entitlement to transfer of reactive kilovolt amperes at delivery points 
except when such transfers may be mutually agreed upon by the 
Contractor and the contracting officer or their authorized 
representatives.
    Adjustment for Losses: Power and energy losses incurred in 
connection with the transmission and delivery of power and energy under 
this rate schedule shall be supplied by the customer as established by 
contract. If losses are not fully provided by a transmission customer, 
charges for financial compensation may apply.
    Adjustment for Industry Restructuring: Any transmission-related

[[Page 60671]]

costs incurred by Western due to electric industry restructuring or 
other industry changes associated with providing CRSP transmission 
service will be passed through to each transmission customer, as 
appropriate.

Colorado River Storage Project; Arizona, Colorado, Nevada, New Mexico, 
Utah; Monthly Charge Calculation for Network Integration Transmission 
Service

    Effective: The first day of the first full billing period beginning 
on or after October 1, 2002, and extending through September 30, 2007, 
or until superseded by another rate schedule, whichever occurs earlier.
    Available: In the area served by the Colorado River Storage Project 
(CRSP) transmission system.
    Applicable: To network transmission service customers for which 
power and energy are supplied to the CRSP transmission system at points 
of interconnection with other systems and transmitted and delivered, 
less losses, to points of delivery on the CRSP transmission system 
established by contract.
    Character and Conditions of Service: Transmission service for 
alternating current, 60 hertz, three-phase, delivered and metered at 
the voltages and points of delivery established by contract.
    Monthly Network Formula: The network integration transmission 
service charge will be the product of the network customer's load ratio 
share times one twelfth (1/12) of the total net annual transmission 
revenue requirement. The same Net Annual Transmission Revenue 
Requirement is used in determining the rate for network transmission 
service as for point-to-point transmission service. It is based on a 
test year using an annual fixed charge methodology. The test year is 
the most recent historical data available. The annual revenue 
requirement is reduced by revenue credits. The formula is as follows:
[GRAPHIC] [TIFF OMITTED] TN26SE02.017

Where:

ARR = Annual Revenue Requirement. The costs associated with facilities 
that support the transfer capability of the CRSP transmission system, 
excluding generation facilities. These costs include investment costs, 
interest expense, depreciation expense, administrative and general 
expenses, and operation and maintenance expense, including transmission 
purchases. Transmission purchases reflect those costs associated with 
CRSP contractual rights.
TRC = Transmission Revenue Credits. The revenues generated by the CRSP 
transmission system, such as scheduling and dispatch ancillary services 
revenues and phase shifter revenues, and excluding long-term firm 
transmission revenues.
NARR = Net Annual Transmission Revenue Requirement. The Annual Revenue 
Requirement less Transmission Revenue Credits.
Load-Ratio Share = Network customer's hourly load (including its 
designated network load not physically interconnected with Western) 
coincident with Western's monthly CRSP transmission system peak.

    This formula will be recalculated annually by applying the data 
from the most current historical test year. If needed, a revised rate 
will be placed into effect every October 1. Western will provide 
notification 30 days prior to a revised rate becoming effective.
    The monthly charge for network transmission service includes 
scheduling, system control, and dispatch. Rate Schedule SP-RS2, or any 
superseding rate schedule, will be attached as part of this Rate 
Schedule and applies to network transmission customers.
    Billing: Billing determinants for the formula rate above will be as 
specified in the service agreement.
    Requirements for Reactive Power: Requirements for reactive power 
shall be as established by contract; otherwise, there shall be no 
entitlement to transfer of reactive kilovolt amperes at delivery points 
except when such transfers may be mutually agreed upon by the 
Contractor and the contracting officer or their authorized 
representatives.
    Adjustment for Losses: Power and energy losses incurred in 
connection with the transmission and delivery of power and energy under 
this rate schedule shall be supplied by the customer as established by 
contract. If losses are not fully provided by a transmission customer, 
charges for financial compensation may apply.
    Adjustment for Industry Restructuring: Any transmission-related 
costs incurred by Western due to electric industry restructuring or 
other industry changes associated with providing CRSP transmission 
service will be passed through to each transmission customer, as 
appropriate.

Colorado River Storage Project; Arizona, Colorado, Nevada, New Mexico, 
Utah; Schedule of Rate for Non-Firm, Point-to-Point, Transmission 
Service

    Effective: The first day of the first full billing period beginning 
on or after October 1, 2002, and extending through September 30, 2007, 
or until superseded by another rate schedule, whichever occurs earlier.
    Available:
    In the area served by the Colorado River Storage Project (CRSP) 
transmission system.
    Applicable: To non-firm, point-to-point, transmission service 
customers for which power and energy are supplied to the CRSP 
transmission system at points of interconnection with other systems and 
transmitted and delivered, less losses, to points of delivery on the 
CRSP transmission system as established by contract.
    Character and Conditions of Service: Transmission service on an 
interruptible basis for three-phase alternating current at 60 hertz, 
delivered and metered at the voltages and points of delivery specified 
in the service contract or in advance by the Western Area Power 
Administration (Western). Conditions for curtailment shall be 
determined by Western and in accordance with Western's Tariff.
    Rate: The proposed rate for non-firm, point-to-point, CRSP 
transmission service is based upon the firm point-to-point rate 
expressed in mills/kWh. This rate may be discounted.
    Billing: The rate will be applied to each kWh delivered at the 
point of delivery, as specified in the service contract.
    Adjustments for Reactive Power: None. There shall be no entitlement 
to transfer of reactive kilovolt-amperes at delivery points, except 
when such transfers may be mutually agreed upon by the Contractor and 
the contracting officer or their authorized representatives.
    Adjustments for Losses: Power and energy losses incurred in 
connection

[[Page 60672]]

with the transmission and delivery of power and energy under this rate 
schedule shall be supplied by the customer in accordance with the 
service contract. If losses are not fully provided by a transmission 
customer, charges for financial compensation may apply.
    Adjustment for Industry Restructuring: Any transmission-related 
costs incurred by Western due to electric industry restructuring or 
other industry changes associated with providing CRSP transmission 
service will be passed through to each transmission customer, as 
appropriate.

Colorado River Storage Project; Arizona, Colorado, Nevada, New Mexico, 
Utah; Schedule of Rates for Scheduling, System Control, and Dispatch 
Ancillary Service

    Effective: Beginning on October 1, 2002, and extending through 
September 30, 2007.
    Available: In the area served by the Colorado River Storage Project 
(CRSP) transmission system.
    Applicable: To all CRSP transmission customers receiving this 
service.
    Character of Service: Scheduling, System Control, and Dispatch is 
required to schedule the movement of power through, out of, within, or 
into a control area.
    Rate: Included in appropriate transmission rates.

Colorado River Storage Project; Arizona, Colorado, Nevada, New Mexico, 
Utah; Schedule of Rate for Reactive Supply and Voltage Control 
Ancillary Service

    Effective: Beginning on October 1, 2002, and extending through 
September 30, 2007.
    Available: In the area served by the Colorado River Storage Project 
(CRSP) transmission system.
    Applicable: To all CRSP transmission customers receiving this 
service.
    Character of Service: Reactive power is support provided from 
generation facilities that is necessary to maintain transmission 
voltages within acceptable limits of the system.
    Rate: Provided through WALC under Rate Schedule DSW-RS1 or WACM 
under Rate Schedule L-AS2, or as superseded.

Colorado River Storage Project; Arizona, Colorado, Nevada, New Mexico, 
Utah; Schedule of Rates for Energy Imbalance Ancillary Service

    Effective: Beginning on October 1, 2002, and extending through 
September 30, 2007.
    Available: In the area served by the Colorado River Storage Project 
(CRSP) transmission system.
    Applicable: To all CRSP transmission customers receiving this 
service.
    Character of Service: Provided when a difference occurs between the 
schedules and the actual delivery of energy to a load located within a 
control area over a single hour.
    Rates: Provided through WALC under Rate Schedule DSW-E1 or WACM 
under Rate Schedule L-AS3, or as superseded, or the customer can make 
alternative comparable arrangements to satisfy its Energy Imbalance 
service obligations.

Colorado River Storage Project; Arizona, Colorado, Nevada, New Mexico, 
Utah; Schedule of Rate for Regulation and Frequency Response Ancillary 
Service

    Effective: Beginning on October 1, 2002, and extending through 
September 30, 2007.
    Available: In the area served by the Colorado River Storage Project 
(CRSP) transmission system.
    Applicable: To all CRSP transmission customers receiving this 
service.
    Character of Service: Necessary to provide for the continuous 
balancing of resources, generation and interchange, with load and for 
maintaining schedules interconnection frequency at sixty cycles per 
second (60 Hz).
    Rate: If the CRSP MC has regulation available for sale, the SLCA/IP 
firm power capacity rate, currently in effect, will be charged. If 
regulation is unavailable from SLCA/IP resources, the WALC or WACM 
control areas can provide the service, in accordance with their 
respective rate schedules.

Colorado River Storage Project; Arizona, Colorado, Nevada, New Mexico, 
Utah; Schedule of Rates for Spinning and Supplemental Reserve Ancillary 
Service

    Effective: Beginning on October 1, 2002, and extending through 
September 30, 2007.
    Available: In the area served by the Colorado River Storage Project 
(CRSP) transmission system.
    Applicable: To all CRSP transmission customers receiving this 
service.
    Character of Service: Spinning Reserve is defined in Schedule 5 of 
Western Area Power Administration's Open Access Transmission Tariff.
    Supplemental Reserve is defined in Schedule 6 of Western Area Power 
Administration's Open Access Transmission Tariff.
    Rate: The transmission customer serving loads within the 
transmission provider's control area must acquire Spinning and 
Supplemental Reserve services from Western, from a third party, or by 
self supply. If the CRSP MC provides these services, the rates under 
the Western Systems Power Pool contract will apply.

[FR Doc. 02-24424 Filed 9-25-02; 8:45 am]
BILLING CODE 6450-01-P