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

[Federal Register: September 26, 2002 (Volume 67, Number 187)]
[Notices]
[Page 60656-60672]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr26se02-62]

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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superseded.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 loftinc@wapa.gov.

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
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Current Proposed
rate rate
Rate schedule ------------------------ Increase
SLIP-F6 SLIP-F7
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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
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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

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

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

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

Notices For
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994

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

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