Federal Register, Volume 63 Issue 65 (Monday, April 6, 1998)

[Federal Register Volume 63, Number 65 (Monday, April 6, 1998)]
[Notices]
[Pages 16796-16812]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-8939]

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DEPARTMENT OF ENERGY

Western Area Power Administration

Salt Lake City Area/Integrated Projects and Colorado River
Storage Project--Notice of Rate Order-WAPA-78

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of rate order.

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SUMMARY: Notice is given of the confirmation and approval by the Deputy
Secretary of the Department of Energy (DOE) of Rate Order No. WAPA-78
and Rate Schedule SLIP-F6, 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. Also Rate
Schedules SP-PTP5, SP-NW1, and SP-NFT4, placing firm and nonfirm
transmission rates on the Colorado River Storage Project (CRSP)
transmission system into effect on an interim basis. Lastly, Rate
Schedules SP-SD1, SP-RS1, SP-EI1, SP-FR1, and SP-SSR1 placing rates for
ancillary services on the CRSP system into effect on an interim basis.
The provisional firm power, firm and nonfirm transmission, and
ancillary service rates will be effective from April 1, 1998 through
March 31, 2003. The provisional firm power rate consists of an energy
charge of 8.1 mills per kilowatthour (mills/kWh) and a capacity charge
of $3.44 per kilowatt month (kW-month), which results in a composite
rate of 17.57 mills/kWh. This is a 12.9 percent decrease from the
current composite rate of 20.17 mills/kWh.
The provisional firm point-to-point transmission rate for 1998 is
$2.23/kW-month. This is a 18.0 percent increase over the current firm
transmission rate of $1.89/kW-month. The provisional network
integration transmission service rate is the product of the network
customer's load ratio share times one twelfth of the annual
transmission revenue requirement. The non-firm point-to-point
transmission rate will still be negotiated between Western and the
customer, but under the new rate schedule, it shall never exceed the
firm point-to-point transmission rate, which is 3.0 mills/kWh.

DATES: Rate Schedules SLIP-F6, SP-PTP5, SP-NW1, SP-NFT4, SP-SD1, SP-
RS1, SP-EI1, SP-FR1, and SP-SSR1 will be placed into effect on an
interim basis on the first day of the first full billing period
beginning on April 1, 1998, and will be in effect until Federal Energy
Regulatory Commission confirms, approves, and places the rate schedules
in effect on a final basis through March 31, 2003, or until the rate
schedules are superseded.

FOR FURTHER INFORMATION CONTACT: Mr. Dave Sabo, CRSP Manager, CRSP
Customer Service Center, Western Area Power Administration, P.O. Box
11606, Salt Lake City, UT 84147-0606, (801) 524-5493. Ms. Carol Loftin,
Team Lead, Rate Analysis, CRSP Customer Service Center, Western Area
Power Administration, P.O. Box 11606, Salt Lake City, UT 84147-0606,
(801) 524-6380.

SUPPLEMENTARY INFORMATION: By Amendment No. 3 to Delegation Order No.
0204-108, published November 10, 1993 (58 FR 59716), the Secretary of
Energy delegated (1) the authority to develop long-term power and
transmission rates on a nonexclusive basis to the Administrator of
Western; (2) the authority to confirm, approve, and place such rates
into effect on an interim basis to the Deputy Secretary; and (3) the
authority to confirm, approve, and place into effect on a final basis,
to remand, or to disapprove such rates to the Federal Energy Regulatory
Commission (FERC).
Pursuant to Delegation Order No. 0204-108 and existing Department
of Energy procedures for public participation in power rate adjustments
at 10 CFR Part 903, and 18 CFR 300, procedures for approving Power
Marketing Administration rates by FERC, Rate Order No. WAPA-78,
confirming, approving, and placing the proposed SLCA/IP firm power rate
adjustment, CRSP firm and nonfirm point-to-point, and network
transmission rate adjustment, and ancillary services rates into effect
on an interim basis, is issued, and the new Rate Schedules SLIP-F6, SP-
PTP5, SP-NW1, SP-NFT4, SP-SD1, SP-RS1, SP-EI1, SP-FR1, and SP-SSR1 will
be promptly submitted to FERC for confirmation and approval on a final
basis.

Dated: March 23, 1998.
Elizabeth A. Moler,
Deputy Secretary.

In the matter of: Western Area Power Administration Rate
Adjustments for Salt Lake City Area Integrated Projects, and
Colorado River Storage Project.

[[Page 16797]]

[Rate Order No. WAPA-78]

Order Confirming, Approving, and Placing the Salt Lake City Area/
Integrated Projects Firm Power, Colorado River Storage Project
Transmission, and Ancillary Service Rates Into Effect on an Interim
Basis

April 1, 1998.
These power and transmission rates are established pursuant to
Section 302(a) of the Department of Energy (DOE) Organization Act, 42
U.S.C. 7152(a), through which the power marketing functions of the
Secretary of the Interior and the Bureau of Reclamation (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 project system involved, were
transferred to and vested in the Secretary of Energy (Secretary).
By Amendment No. 3 to Delegation Order No. 0204-108, published
November 10, 1993 (58 FR 59716), the Secretary delegated (1) the
authority to develop long-term power and transmission rates on a
nonexclusive basis to the Administrator of the Western Area Power
Administration (Western); (2) the authority to confirm, approve, and
place such rates into effect on an interim basis to the Deputy
Secretary; and (3) the authority to confirm, approve, and place into
effect on a final basis, to remand, or to disapprove such rates to the
Federal Energy Regulatory Commission. Existing DOE procedures for
public participation in power rate adjustments are found at 10 CFR Part
903. Procedures for approving Power Marketing Administration rates by
FERC are found at 18 CFR Part 300.

Acronyms and Definitions

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

$/kW/month: Monthly charge for capacity (i.e., $ per kilowatt (kW) per
month).
AHP: Available hydro power. Maximum amount of hydro capacity and energy
that will be made available to the Contractor monthly as determined by
Western based on prevailing water conditions and set forth in
Contractor's firm power contract.
Capacity Component: Part of the firm power rate; expressed in dollars
per kW per month ($/kW-month). Applied each billing period to the
maximum kW the Contractor is entitled to on a seasonal basis, as
established by the Contractor's firm power contract.
CDP: Customer displacement power. One of two options available under
the Replacement Purchase Options Amendment. It is the amount of
supplemental power acquired or generated by the Contractor, on its own
behalf, which will be used as part of the Contractor's CROD and Monthly
Energy within a given period.
CME: Capitalized movable equipment.
Collbran: Collbran Project.
Contractor: An entity which has a contract with Western for SLCA/IP
Firm Electric Service.
CROD: Contract rate of delivery. The maximum amount of capacity the
Contractor is entitled to receive under its long-term firm power
contract.
CRSP: Colorado River Storage Project (includes Seedskadee and Dolores
Projects).
CRSP Act: Act of April 11, 1956, ch. 203, 70 Stat. 105, as amended, 43
U.S.C. 620-620o.
CRSP CSC: The Colorado River Storage Project Customer Service Center,
Western's office in Salt Lake City, Utah.
Customer: Any entity which receives SLCA/IP power, CRSP transmission,
or ancillary services.
DOE: U.S. Department of Energy.
DOE Order RA 6120.2: An order addressing power marketing administration
financial reporting, used in determining revenue requirements for rate
development.
DSWR: Desert Southwest Region, Western's office in Phoenix, Arizona.
EIS: Environmental impact statement.
Energy Component: Part of the firm power rate; expressed in mills per
kilowatt-hour (kWh). Applied to each kWh delivered to each customer.
FERC: Federal Energy Regulatory Commission.
Firming Power: Power Western will purchase up to the AHP level. This
type of purchase is included in the firm power rate.
Firming Purchases: Power purchased by Western or the Contractor above
the AHP level up to the Contractor's CROD. This purchase cost is passed
directly to the Contractor.
FRN: Federal Register notice.
FY: Fiscal year.
Glen Canyon: One of the storage units of the CRSP.
GCD EIS: Glen Canyon Dam Environmental Impact Statement.
GWh: Gigawatt-hour; equal to one million kW for a period of 1 hour.
Interior: U.S. Department of Interior.
Interest Offset: An offset to interest accrued allowed customers for
the monthly payment of principal which is due on a yearly basis.
kW: Kilowatt; 1,000 watts.
kWh: Kilowatt-hour; the common unit of electric energy, equal to one kW
taken for a period of 1 hour.
kW-month: Unit of electric capacity, equal to maximum amount of kW
taken during 1 month.
mill: Unit of monetary value equal to .001 of a U.S. dollar; i.e., 1/
10th of a cent.
mills/kWh: Mills per kilowatt-hour.
MW: Megawatt; equal to 1,000 kW or 1,000,000 watts.
NEPA: National Environmental Policy Act of 1969.
OAT: Open access transmission tariff.
OMB: Office of Management and Budget.
O&M: Operation and maintenance.
OM&R: Operation, maintenance, and replacement.
PRS: Power repayment study.
Rate Brochure: A document prepared for public distribution explaining
the background and purpose of this rate adjustment proposal.
Reclamation: Bureau of Reclamation, U.S. Department of the Interior.
Replacement Purchase Options Amendment: Amendment to the SLCA/IP firm
electric service contract which provides options to the Contractor for
replacing Glen Canyon Dam generation lost as a result of the GCD EIS.
RMR: Rocky Mountain Region, Western's office in Loveland, Colorado.
SLCA/IP: The Salt Lake City Area/lntegrated Projects, which are the
CRSP, Collbran, and Rio Grande Projects.
Supporting Documentation: Work papers which support the rate proposal.
Western: Western Area Power Administration, U.S. Department of Energy.
WRP: Western replacement power. One of two options available under the
Replacement Purchase Options Amendment. It is the amount of
supplemental power requested by the Contractor to be acquired by
Western on behalf of the Contractor as part of the Contractor's CROD
and monthly energy within a given period and paid for by the Contractor
on a pass-through-cost basis.

Effective Date

The new rates will become effective on an interim basis on the
first day of the first full billing period beginning on or after April
1, 1998, and will remain in effect pending FERC's approval of them or
substitute rates on a final basis

[[Page 16798]]

through March 31, 2003, or until superseded.

Public Notice and Comment

The Procedures for Public Participation in Power and Transmission
Rate Adjustments and Extensions, 10 CFR Part 903, have been followed by
Western in the development of these rates. The provisional firm power
rate represents a change of more than 1 percent in total SLCA/IP
revenues, and the provisional firm transmission rate represents a
change of more than 1 percent in total CRSP transmission revenues.
Therefore, they are major rate adjustments as defined at 10 CFR
Secs. 903.2(e) and 903.2(f)(1). The distinction between a minor and a
major rate adjustment is used only to determine the public procedures
for the rate adjustment.
The following summarizes the steps Western took to ensure
involvement of interested parties in the rate process:
1. On March 21, 1997, letters were sent to all SLCA/IP customers
and other interested parties announcing informal public meetings to be
held in Utah, Colorado, New Mexico, and Arizona, from April 16 to April
25, 1997.
2. At these informal meetings, Western representatives explained
the need for a rate adjustment and answered questions.
3. An FRN was published June 25, 1997 (62 FR 34255), officially
announcing the proposed firm power, transmission, and ancillary
services rates adjustment, initiating the public consultation and
comment period, announcing the public information and public comment
forums, and outlining procedures for public participation.
4. On June 27, 1997, a rate announcement package was sent to all
SLCA/IP customers, CRSP firm transmission customers, and other
interested parties announcing the publication of the June 25, 1997,
FRN, and the beginning of the formal public process to adjust firm
power, transmission, and ancillary services rates. The package
contained (1) a letter announcing the upcoming public information and
comment forums and (2) a copy of the June 25 FRN.
5. On July 14, 1997, a copy of the July 1997 ``Brochure for
Proposed Rates: Salt Lake City Area Integrated Projects Firm Power,
CRSP Transmission, and Ancillary Services' was mailed to all SLCA/IP
firm power customers, CRSP transmission customers, and other interested
parties.
6. At the public information forums held from August 1 to August 7,
1997, in Utah, Colorado, New Mexico, and Arizona, Western
representatives provided detailed explanations of the proposed rates
for SLCA/IP and CRSP, provided a list of unresolved issues that could
affect the proposed rates, and answered questions. An information
handout was provided at the forum.
7. The comment forums were held from September 16 to September 19,
1997, in the same locations as the information forums to give the
public an opportunity to comment for the record. Eleven individuals
commented at these forums.
8. Eight comment letters were received during the 90-day
consultation and comment period. The consultation and comment period
ended on September 23, 1997. Two additional letters were received after
the 90-day consultation period. All comments have been considered in
the preparation of this rate order.

Comments

Written comments were received from the following organizations:

Citizens Power, Colorado
Colorado River Energy Distributors Association, Utah
Irrigation & Electrical Districts Association of Arizona, Arizona
K.R. Saline & Associates, Arizona, on behalf of:
Chandler Heights Citrus Irrigation District
Electrical District No. 3 of Pinal County
Electrical District No. 4 of Pinal County
Electrical District No. 5 of Pinal County
Electrical District No. 6 of Pinal County
Electrical District No. 7 of Maricopa County
City of Safford
San Carlos Irrigation Project
Maricopa Water District
Roosevelt Irrigation District
San Tan Irrigation District
Naslund, Salt Lake City, Utah
Platte River Power Authority, Colorado
Public Service Company of Colorado (2), Colorado
Tri-State Generation and Transmission Association, Inc., Colorado
Utah Associated Municipal Power Systems, Utah

Representatives of the following organizations made oral comments:

Arizona Power Pooling Association, Arizona
Colorado River Energy Distributors Association, Utah
Irrigation & Electrical District Association, Arizona
Electrical District No. 3 of Pinal County, Arizona
K.R. Saline & Associates, Arizona
Navajo Tribal Utility Authority, Arizona
Public Service Company of Colorado, Colorado
Platte River Power Authority, Colorado
R.W. Beck, on behalf of Colorado River Energy Distributors Association,
Utah
Tri-State Generation & Transmission, Inc., Colorado
Utah Municipal Power Association, Utah

Project History

The SLCA/IP consists of the CRSP, Rio Grande, and Collbran
Projects. The CRSP described herein includes two CRSP participating
projects which have power facilities, 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 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. A detailed
description of the Collbran, Rio Grande, and CRSP Projects is located
in the Supporting Documentation.

Power Repayment Studies--Firm Power Rate

Power repayment studies are prepared each FY to determine if power
revenues will be sufficient to repay, within the prescribed time
periods, all costs assigned to the SLCA/IP power function. 43 U.S.C.
620(d) sets forth payment and repayment obligations of the CRSP. DOE
Order RA 6120.2, section 12b, requires that:
In addition to the recovery of the above costs (operation and
maintenance and interest expenses) on a year-by-year basis, the
expected revenues are at least sufficient to recover (1) each dollar of
power investment at Federal hydroelectric generating plants within 50
years after they become revenue producing, except as otherwise provided
by law; plus, (2) each annual increment of Federal transmission
investment within the average service life of such transmission
facilities or within a maximum of 50 years, whichever is less; plus,
(3) the cost of each replacement of a unit of property of a Federal
power system within its expected service life up to a maximum of 50
years; plus, (4) each dollar of assisted irrigation investment within
the period established for the irrigation

[[Page 16799]]

water users to repay their share of construction costs; plus, (5) other
costs such as payments to basin funds, participating projects or
states.
A review of the PRS indicates that the existing firm power rates
under Rate Schedule SLIP-F5 must be adjusted. The provisional composite
rate for firm power is 17.57 mills/kWh, a 12.9 percent decrease from
the existing firm power composite rate of 20.17 mills/kWh. The
provisional firm power composite rate is comprised of a capacity charge
of $3.44 /kW-month and an energy charge of 8.10 mills/kWh.

CRSP Transmission Service 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. SLCA/IP long-term firm power customers also
incur the cost for transmission of their SLCA/IP power; and this
expense is included in the firm power rate.
A review of the CRSP transmission service rate study indicates that
the existing firm and nonfirm CRSP transmission service rates under
Rates Schedules SP-FT4 and SP-NFT3, respectively, must be increased.
The CRSP CSC is seeking approval of a rate formula for calculation of
the firm point-to-point transmission rate, to be applied annually, and
a formula for calculating the network integration transmission service
rate to be applied annually. These formulas will be effective April 1,
1998, through March 31, 2003. The provisional rate for firm, point-to-
point, CRSP transmission service is $2.23 per kW-month for 1998, an
18.0 percent increase from the existing firm transmission rate of $1.89
per kW-month, which became effective October 1, 1992. This rate will be
charged to existing firm transmission customers and future firm point-
to-point transmission customers.
The change in the firm CRSP transmission service rate is due to
increases in the formula numerator. These increases are in transmission
facilities' costs and in assigning all transmission costs to all users.
Also, the computation of the denominator changed. Western is basing
the transmission system reserved for its existing long-term firm power
customers on its maximum annual firm obligations instead of generating
plant capacity to determine the portion of the denominator associated
with the transmission of firm power.
The provisional rate for nonfirm CRSP transmission service is
determined by the current market rate, not to exceed the current CRSP
firm point-to-point transmission rate. The provisional rate is
expressed in mills/kWh, and is a maximum of 3.0 mills/kWh for 1998.
The provisional rate for network integration transmission service
is a formula calculation. The CRSP CSC has not calculated a rate
because Western does not currently have any network integration
transmission service customers on its CRSP transmission system.

Ancillary Services

Six ancillary services will be offered by CRSP; two are required to
be purchased by the CRSP transmission customer. These two are (1)
scheduling, system control, and dispatch service, and (2) reactive
supply and voltage control service. The remaining four ancillary
services--regulation and frequency response service, energy imbalance
service, spinning reserve service, and supplemental reserve service--
will also be offered but are subject to availability from SLCA/IP
resources.
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 provided in conjunction with the sale of
CRSP transmission services. If Western is unable to provide these
services through SLCA/IP resources, the CRSP CSC will offer to provide
these services by making market purchases or obtaining these services
through a control area operator and passing these costs directly to the
customer, including a 10 percent administrative charge.
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,
and reactive supply and voltage control 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 tariffs when they
assume control area operator responsibility for the CRSP, expected to
be April 1, 1998.

Existing and Provisional Rates

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

Comparison of Existing and Provisional Salt Lake City Area/lntegrated Projects Firm Power, Colorado River
Storage Project Transmission and Ancillary Services
----------------------------------------------------------------------------------------------------------------
Existing rates Provisional rates (effective 4/1/98)
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Firm Power Service Rate Schedule SLIP-F5................... SLIP-F6.
(existing rate effective 12/94).
Firm Capacity Charge ($/kW/month)....... $3.83..................... $3.44.
Firm Energy Charge (mills/kWh).......... 8.90...................... 8.10.
Composite Rate (mills/kWh).............. 20.17..................... 17.57.
Firm Point-to-Point Transmission Rate SP-FT4.................... SP-PTP5.
Schedule (existing rate effective 10/
92).
Firm Transmission Rate ($/kW-month)..... $1.89..................... $2.23 for 1998.
Network Transmission.................... N/A....................... SP-NW1.
Nonfirm Transmission Rate Schedule SP-NNFT3.................. SP-NFT4.
(existing rate effective 8/89).
Nonfirm Transmission Rate............... Negotiated................ Same, but not to exceed the firm rate.
Ancillary Services...................... N/A....................... SP-SD1, SP-RS1, SP-EI1, SP-FR1, SP-SSR1.
----------------------------------------------------------------------------------------------------------------

[[Page 16800]]

Certification of Rate

Western's Acting Administrator has certified that the SLCA/IP firm
power, CRSP point-to-point, network integration and nonfirm
transmission, and ancillary services rates placed into effect on an
interim basis herein are the lowest possible consistent with sound
business principles. The rates have been developed in accordance with
agency administrative policies and applicable laws.

SLCA/IP Firm Power Rate Discussion

The provisional rate for SLCA/IP firm power is designed to recover
an annual amount of revenue requirement that includes the repayment of
power investment, payment of interest, purchased power expenses, OM&R
expenses, and the repayment of irrigation assistance costs, as required
by law.
The existing rate for SLCA/IP firm power under Rate Schedule SLIP-
F5 expires November 30, 1999. Effective April 1, 1998, Rate Schedule
SLIP-F5 will be superseded by the new rates in Rate Schedule SLIP-F6.
The April 1, 1998, date corresponds with the implementation of the WRP
and CDP options under the Replacement Purchase Options Amendment to the
SLCA/IP Firm Electric Service Contracts (Amendment).
Recently, the CRSP CSC developed the Amendment which implements the
Record of Decision for the Electric Power Marketing EIS to return the
Contractors' allocations back to those established in the Post-89
Marketing Plan. This action increased Western's long-term firm annual
contract commitment for energy from 5,699 GWh to 6,007 GWh and peak
seasonal CROD from 1,290 MW to 1,406 MW. CRSP CSC's firm power
commitments to meet Reclamation project use loads also increased. This
increase in units sold contributes towards a lower per unit cost.
Additionally, this Amendment provides solutions which are
reflective of the operational changes and reduced generating levels
that resulted from the GCD EIS Record of Decision. Based on current
year hydrology coupled with the reduced generating levels, Western will
at times lack sufficient hydroelectric generation to meet the full CROD
commitment. The Amendment provides options for either Western or the
Contractor to supply the additional resources necessary to meet the
full CROD commitment, at costs borne directly by the Contractor. At the
Contractor's option, Western may provide the power under the WRP
program through purchases on the open market, or the Contractor may
provide the power under the CDP program or a combination of the two
programs. Seasonal WRP and CDP provisions are effective April 1, 1998.
Each season, a portion of the resource commitments, determined by
Western, will be made available to the customer through AHP. In the
past, Western purchased all necessary firming power up to the CROD and
included all the associated costs in the firm power rate. Under the
Amendment, Western will firm up to the AHP level, if needed, and all
the associated costs will be included in the firm power rate. The
customer can then use WRP and/or CDP to augment the AHP to reach its
full CROD.
The Amendment provisions concerning WRP and CDP programs
necessitate an incremental administrative charge for those services.
Western will estimate costs for these administrative charges during the
first year these programs are effective--April 1, 1998, through March
31, 1999. During this first year, Western will work in consultation
with customers to develop a method for tracking actual incremental WRP
and CDP administrative charges. This first year will be considered a
base year, and subsequent years' charges will be based upon actual
costs and streamlining experiences. Contractors will be billed monthly
for their share of the costs.
The provisional rates for SLCA/IP firm power consist of a capacity
rate and an energy rate. The provisional capacity rate is $3.44/kW-
month, and the provisional energy rate is 8.10 mills/kWh. The
provisional rates for SLCA/IP firm power will result in an overall
composite rate decrease of approximately 12.9 percent on April 1, 1998,
when compared to the existing SLCA/IP firm power rate in Rate Schedule
SLIP-F5. The total cost to the customer will depend upon the market
prices for WRP and CDP. It is expected that the Contractors' total
costs of receiving its full contract entitlement will be higher in the
future since they will be receiving a different service under the
Amendment. The firm power rate includes the cost of AHP, transmission
delivery up to the Contractor's CROD at its designated point of
delivery, and ancillary services.
Many factors influenced this firm power rate adjustment. The major
factors having an impact upon the provisional SLCA/IP firm power rate
are summarized in the table below. Because rates are calculated to
return sufficient revenues based on estimated future costs, the table
compares the change in the average annual projections used in the FY
1993 Rate Order PRS (which set the rate effective December 1, 1994)
with the rate setting PRS prepared for this rate adjustment.

Major Factors Affecting the Salt Lake City Area Integrated Projects Firm
Power Rate Average During Rate Setting Periods
------------------------------------------------------------------------
Change in
average
annual Estimated
Factors revenue rate effect
requirement (mills/kWh)
(thousands)
------------------------------------------------------------------------
Projected O&M costs decreased................. $-11,359 -1.8
Purchased power expense projections and
transmission costs increased................. 3,636 0.6
The Integrated Projects annual expenses have
increased, mostly due to the inclusion of the
Dolores Project.............................. 3,582 0.6
Interest expenses have decreased as a result
of Western applying an Interest Offset to the
CRSP PRS..................................... -5,098 -0.8
Other annual expenses have decreased, mostly
due to revised estimates for Capital Movable
Equipment (CME) interest..................... -2,889 -0.5
Payments to project investments and additions
have decreased \1\........................... -663 -0.1
The projected cost of replacements increased
\1\.......................................... 2,718 0.4
Annual average payments to irrigation
assistance increased......................... 4,505 0.7
Offsetting revenues increased................. -1,827 -0.3

[[Page 16801]]

The total amount of energy delivered increased N/A -1.4
------------------------------------------------------------------------
\1\ These changes occurred as an average over the rate setting periods,
and as a result, the same impact is not exhibited in the 5 year
comparison table below.

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 1998-FY 2002) Total Revenues and Expenses
----------------------------------------------------------------------------------------------------------------
Existing
rate ($000) Proposed rate ($000) Difference ($000)
----------------------------------------------------------------------------------------------------------------
Revenue Requirements:
Annual expenses:
O&M............................................ $233,974 $179,481 ($54,493)
Purchased Power and Wheeling................... 69,075 41,265 (27,810)
Integrated Projects Requirements............... 28,612 39,648 11,036
Interest....................................... 210,639 161,534 (49,105)
Other.......................................... 69,759 (7,053) (76,812)
------------------------------------------------------------
Total annual expenses...................... 612,059 414,875 (197,184)
============================================================
Annual principal payments:
Original Project and Additions................. 104,069 187,592 83,524
Replacements................................... 29,030 26,376 (2,654)
Irrigation..................................... 11,266 2,469 (8,797)
------------------------------------------------------------
Total principal payments................... 144,365 216,437 72,073
============================================================
Total Annual Revenue Requirements.......... 756,424 631,312 (125,111)
(less Offsetting Annual Revenue)............... 136,603 85,197 (51,406)
------------------------------------------------------------
Net Annual Revenue Requirements.................... 619,821 546,115 (73,705)
----------------------------------------------------------------------------------------------------------------

Basis for Rate Development

The provisional power rate contains a composite rate of 17.57
mills/kWh, which is a decrease of 12.9 percent below the existing rate
of 20.17 mills/kWh. It should be noted that although there appears to
be a significant decrease from the existing firm power composite rate
to the provisional firm power composite rate, the Contractor will not
be receiving the same type of service as a result of the Amendment;
therefore, the decrease is not as substantial as it appears.

Comments

The comments and responses regarding the firm power rate,
paraphrased for brevity when they do not affect 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) purchased power, (2) status of issues
which were identified as outstanding in the Rate Brochure, (3) O&M
costs, (4) WRP/CDP administrative charges, and (5) miscellaneous
comments.
1. Purchased-Power Issues
Comment: Western needs to make it very clear that, although the
rates are going down, the responsibility to purchase above AHP will be
transferred to the customer.
Response: As stated in the Rate Brochure page 2-2, the total cost
to the customer will depend upon the market prices for WRP and CDP.
However, it is expected that the Contractor's costs of receiving its
full contract entitlement will be higher in the future.
Comment: Does the firm power rate include the 400 GWh of firming
purchases?
Response: Yes. The Record of Decision for the Power Marketing EIS
allowed Western to return to the original Post-1989 marketing CRODs and
allowed for the additional purchase of 400 GWh as mentioned in the
power marketing plan. The cost associated with the approximate 400 GWh
of purchases are included in the firm power rate.
Comment: Customer wants clarification as to the difference between
firming purchases and firming power that is referenced in the Rate
Brochure. Are they purchases that Western will be making to firm up to
the AHP level, or are they purchases that will be made for WRP or CDP?
Response: In general, firming power refers to the power Western
will purchase up to the AHP level. This type of purchase is included in
the firm power rate.
Firming purchases above the AHP level will be made by Western for
those who elect WRP up to their CROD. These firming purchases will be
on a pass-through-cost basis. Contractors may also elect to purchase
their own power, through CDP, above what is provided by Western.

[[Page 16802]]

Comment: It appears that in the table that summarizes the costs,
the purchased power costs increased. Yet, most of the purchased power
is going to be passed through to the customers. Please explain.
Response: The annual purchased power costs shown in Table 3 of the
Rate Brochure increased because of an assumption change in the PRS. In
the existing rate, contractual power sales were projected to the end of
the current contract period (2004), after which it was assumed that
sales equaled generation, which required no additional power purchases.
In the provisional rate, contractual power sales were projected to
extend through the rate setting period (60 years). This assumption
change makes the average annual purchased power costs in the
provisional rate higher than for the existing rate.
This modification in assumption is supported by criteria set forth
in RA 6120.2 (10)(e)(2), which allows Western to forecast revenues
based on past trends of customer load growth rates.
2. Status of Outstanding Issues
Comment: Customer stated Western should not include personnel
retirement costs in the firm power costs.
Response: Retirement costs were not included in this provisional
rate.
Comment: In the Rate Brochure on page 2-9, it says, ``If an updated
depletion schedule is available during the comment period, Western may
use the revised forecasts if the changes are significant in the rate
setting PRS.'' One, what are the possibilities of that and, two, how
will the customers know if some revised depletion schedule is
available?
Response: It is CRSP CSC's policy to use the latest official data
in all PRSs. An updated depletion schedule was not provided to Western
and, therefore, the rate setting PRS was not modified. When an updated
schedule is provided, Western will notify firm power customers in
writing that the data is available for review, and this data will be
included in the annual PRS prepared by Western.
Comment: On page 2-10, Western acknowledges that, ``The financial
report from Reclamation or the Secretary of Interior under the Grand
Canyon Protection Act has not yet been completed.'' Does Western have
any knowledge of when that report will be available?
Response: Western has not received a final report signed by the
Secretary of Interior and does not know when one will be provided to
Western. Western included the estimate of $14 million of costs in this
rate setting PRS.
3. Operation and Maintenance Costs
Comment: Western indicated that O&M costs decreased the rate by 1.5
mills/kWh. Please explain why this decrease occurred.
Response: Western has been undergoing a streamlining process
throughout the agency. This streamlining reduced annual operation and
maintenance costs approximately $11 million from the existing rate
setting PRS.
Comment: The fifth year of projected O&M costs displays a
substantial increase from previous years. This higher cost is projected
throughout the remainder of the study. Western needs to analyze this to
see if it is an appropriate estimate of fifth year costs.
Response: This increase in FY 2001 is due to some non-recurring O&M
costs associated with a generator rewind at Crystal Powerplant, a part
of the Aspinall Unit of the CRSP. This is a one-time cost and should
not be carried in the study beyond that year. For this reason, the O&M
cost estimates for the fifth and future years do not include the amount
for the rewind. This adjustment has been made in the rate setting PRS
and decreased projected O&M by approximately $2 million annually.
4. WRP/CDP Administrative Charges
Comment: Please explain how WRP customers will be charged, and if
and how CDP customers will be charged. Also, the rate schedule needs to
be clarified.
Response: A customer receiving WRP or other Firming Purchases on a
pass-through-cost basis will pay for its proportionate share of the
costs, including administrative, associated with providing this
service. CDP customers, who are using the CRSP transmission system for
the delivery of their CDP, will also pay for the proportionate share of
the administrative costs associated with Western providing this
service.
The WRP and CDP administrative charges will consist mostly of labor
hours for the CRSP CSC, DSWR, and RMR employees who are working on WRP
and CDP activities and will be treated as incremental labor costs. With
WRP, these tasks include market studies, contract negotiation, and
scheduling. With CDP, the charge will be for scheduling and determining
available transfer capacity.
In the first year the WRP/CDP options are in effect (April 1,
1998), estimated charges will be applied. During that first year,
actual costs will be tracked and used as a basis for subsequent years'
charges.
Comment: The final paragraph of page 3-1 of the Rate Brochure seems
to contradict the understanding that purchased power costs to firm
allocations are carried as an expense to be recovered in the firm power
rate. CDP customers should only be charged for the administrative
costs.
Response: To clarify, CDP customers will not be charged firming
purchases, but will be charged an administrative charge, if applicable.
The costs of firming purchases made to meet customers' allocations
above AHP are not included in the firm power rate. These costs will be
proportionately passed through to customers, except those receiving
only CDP. The only firming power costs included in the firm power rate
are those which firm up to the AHP level and which all firm power
customers will pay through the firm power rate.
Comment: Customer strongly encourages Western to quickly initiate a
process to determine the appropriate cost-tracking system for WRP and
CDP costs as described in Section III, WRP and CDP Charges, of the Rate
Brochure.
Response: A group of customers and Western employees has been
organized. A meeting was held October 16, 1997, to begin this process.
Once a draft of charges is completed, it will be provided to customers
for comment.
Comment: Are CDP or WRP customer specific? If Western does not
incur the cost as a result of the customer, then the customer does not
get charged?
Response: The assumption is, if a customer is receiving CDP, that
customer is purchasing its own resource. Western will deliver this
resource over its system to the customer's delivery point if it has the
available transmission, and this will be handled as a separate schedule
by Western's schedulers. Thus, the schedulers will spend a certain
amount of time each day in scheduling and accounting for this resource.
In this scenario, Western will be charging a CDP administrative charge.
If the CDP is completely off Western's system, where a customer
purchased power from elsewhere and Western did not have to schedule or
account for it, there will be no CDP administrative charge because no
additional tasks will be performed by Western.
Any customer receiving WRP will incur an administrative charge.
With WRP, Western will always be performing tasks to provide this
service, and, therefore, an administrative charge will always accompany
WRP service.

[[Page 16803]]

Comment: In Section 3-2, the statements in the beginning are
regarding WRP/CDP administrative costs; it ends with a paragraph
regarding pass-through costs. Is Western still referring to the
administrative costs associated with these pass-through-cost purchases,
or are these some other costs being referred to in this paragraph?
Response: To clarify, in Section 3-1, Western is discussing two
separate charges for those Contractors who are receiving WRP, or other
Firming Purchases on a pass-through-cost basis, and CDP. The first
charge is for the cost of WRP or Firming Purchases on a pass-through-
cost basis. The second charge is for the administrative costs Western
incurs as a result of providing the service. The last paragraph is
referring to the firming purchase costs that will be passed-through to
those Contractors who are receiving WRP, or other Firming Purchases on
a pass-through-cost basis. CDP was incorrectly included in this
paragraph.
5. Miscellaneous Comments
Comment: Traditionally there has been a 50/50 split between
capacity and energy. Western calculated the total revenue requirements
and took half of the revenue requirement for capacity and half of the
revenue requirement for energy. Is that the way Western computed it
this time?
Response: The CRSP CSC has stated that half of the firm power rate
is allocated to capacity and half to energy based on an assumed 58.2
percent load factor. However, the actual load factor for SLCA/IP is
49.9 percent. Using the assumed load factor, rather than the actual
load factor, alters the revenue split to approximately 46-percent
energy and 54-percent capacity.
Comment: The Participating Projects will be collecting too much
revenue starting in FY 2021.
Response: The CRSP CSC believes this comment is in reference to the
Seedskadee and Dolores Participating Projects continuing to have
surplus revenues included as revenue requirements. Surplus revenues
from the sale of Seedskadee and Dolores Projects' power must assist in
the repayment of CRSP costs as provided in Section 5 (e) of the CRSP
Act of 1956.
Comment: Western used several different interest rates in
calculating CME interest for the SLCA/IP. Why were the different
interest rates used?
Response: Western used the coupon rate as required by Section 5(f)
of the CRSP Act for all CRSP facilities. For FY 1997, this rate is
9.012 percent. For the Collbran and Rio Grande Projects, Western used
the yield rate as required under RA 6120.2, Section 11. For FY 1997,
this rate is 6.875 percent.
Comment: The power allocation of Caballo Dam, part of the Rio
Grande Project, was increased from 40.5 percent to 100 percent. What
was the reason for this change?
Response: Western incorrectly allocated 100 percent to Caballo Dam
for O&M expenses. While Caballo Dam is allocated 100 percent for
investments, it is only allocated 40.45 percent for O&M costs.
Therefore, Western corrected the rate setting PRS to reflect an
allocation of 40.45 percent for O&M. This change had no significant
impact to the firm power rate.
Comment: Customer supports Western's inclusion of updated costs
allocable to power for the Bonneville Unit of the Central Utah Project
and urges that costs for future rate proceedings be similarly updated.
Response: Current cost estimates were included in the rate setting
PRS and are reflected in the provisional rate. As revised estimates
become available, they will be included in the annual CRSP power
repayment study.
Comment: In the Executive Summary, the Aid to Participating
Projects, which is labeled Cumulative Federal Investment, shows a large
step increase of $944 million from 2002 to 2004, and then an additional
step increase of $922 million from 2006 to 2007. What are the causes of
these increases, and how do these increases affect the results of the
power repayment study?
Response: The increase from 2002 to 2004 of $944 million results
from the estimated completion of additions to the Dolores Project in
Colorado and the Southern Utah County and Heber-Francis blocks of the
Bonneville Unit (Central Utah Project). The increase from 2006 to 2007
reflects the addition of the Juab-Mona-Nephi block of the Central Utah
Project. These are project construction costs allocated to irrigation
which are beyond the ability of the irrigators in those projects to
repay. These costs, along with their corresponding States'
apportionment obligations, are the responsibility of power users to
repay. These noninterest bearing power repayment obligations, which
total about $1.9 billion, have a rate impact of approximately 4.8
mills/kWh increase.
Comment: Customer would like to compliment Western on the rate
adjustment process, specifically the issue papers.
Response: The CRSP CSC believes the issue papers were beneficial
for Western and its customers to increase communication. As a result,
the CRSP CSC intends to continue to use issue papers for rate
processes.
Comment: There is a significant increase in project use. What
accounts for those increases?
Response: The projections for project use power are updated
annually by Reclamation. The reason that the projections increase in
successive years is due to the requirements of the Animas-La Plata
Project and the Bonneville Unit of the Central Utah Project. Other
projects requiring some future increase in project use power are the
Navajo Indian Irrigation Project and the Paradox Valley Salinity
Control Project. However, the total projections for project use power
in the provisional rate are lower than those in the existing rate.
Comment: The interest offset credit shown in the ``Miscellaneous
Annual Expense'' does not match the figure in the Supporting
Documentation. Also, the methodology for figuring interest offset
credit does not take compounding into consideration.
Response: In the Rate Brochure, the $40 million interest offset was
an estimated amount because the methodology for computing the offset
had not been completed. Before the rate proposal was published, the
CRSP CSC had prepared several analyses using varying methodologies
(including compounding and noncompounding interest) which yielded
amounts greater and less than the $40 million indicated in the Rate
Brochure.
Since the publication of the Rate Brochure, Western has determined
the appropriate methodology for the interest offset. Western finds it
appropriate to apply the interest offset methodology retroactively and
to include what the interest savings would have been if the interest
offset methodology would have been implemented from the beginning
(1963). For this historic adjustment, Western is working toward an
appropriate interest adjustment. The exact amount of the adjustment
will not be available for this rate adjustment but is expected to
become available during FY 1998. The estimate for this adjustment used
in the provisional rate was revised downward from $40 million to $20
million based on the methodology change.
Comment: Customer supports efforts to keep water depletion
assumptions realistic.
Response: The depletions were based on estimates projected using a
5-year cost evaluation period, 1998-2002, the fifth year being held
constant through 2057. Western believes that this is an equitable
treatment of depletions and is consistent with other projected data.

[[Page 16804]]

Comment: What revenues are credited to the firm power revenue
requirements?
Response: Offsetting revenues, or firm power revenue credits, are
any revenues that the CRSP receives which do not result from the sales
of firm power, such as revenue from wheeling or transmission of
nonproject power or nonfirm power sales. The major portion of the
revenue credit is from wheeling revenue.

CRSP Transmission Discussion

The provisional rates for CRSP transmission service are based on a
revenue requirement that recovers (i) the CRSP transmission system
investment and interest costs for facilities associated with providing
transmission service, and (ii) the operation, maintenance, and
replacement costs allocated to transmission service. The CRSP
transmission system includes facilities owned by CRSP CSC and the
transmission facilities owned by others over which the CRSP CSC has
contractual control. All the costs of the CRSP transmission system,
including the costs paid to others for the contractual control of their
transmission lines are in the total CRSP transmission revenue
requirement. These revenue requirements are offset by appropriate CRSP
transmission system revenues.
The firm transmission rate is based on all CRSP transmission costs.
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, and reactive supply and voltage control service are included
in the appropriate provisional transmission services rates. Once
Western's DSWR and RMR assume control area operator responsibility for
the CRSP, expected to be April 1, 1998, 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 April 1, 1998, 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 31, 1998. The
provisional rate for firm point-to-point CRSP transmission service for
1998 is $2.23 per kW-month and will result in an 18.0 percent increase
from the existing rate of $1.89 per kW-month under Rate Schedule SP-
FT4. The provisional rate for nonfirm CRSP transmission service is
expressed in mills/kWh and will be based on market conditions, but not
to exceed the firm point-to-point rate. The nonfirm transmission rate
for 1998 is 3.0 mills/kWh.
Western made three significant changes in its transmission rate
methodology.
1. Western is basing the transmission system reserved for its
existing long-term firm power customers on its maximum annual firm
obligation instead of generating plant capacity. Also, Western has
reserved 130 MW for use during high hydrological conditions. The
reservation of Western's transmission under certain hydrological
conditions is permitted under the provisions for determination of
Available Transmission Capacity which have been accepted by the
regional transmission planning groups of which Western is a member.
Western's interpretation of FERC Order No. 888 is that such capacity
reservations for favorable hydrological conditions under these
circumstances is acceptable. The sum of the maximum annual firm power
obligations, which includes the 130 MW reserved for use during high
hydrological conditions, is 2 MW less than the generating plant
capacity amount.
2. Western annually will be recalculating the firm and nonfirm
point-to-point and network integration transmission service rates to be
effective April 1 based upon the proposed formulas. The rate
denominator (reserved capacity) and the net annual transmisssion
revenue credits will be revised each year. This rate recalculation will
be done yearly by projecting for the 5 future years the revenue credits
and total transmission capacity reservation and then averaging these
amounts. The same average annual revenue requirement, $63.3 million,
will be used for the annual recalculation of the firm, nonfirm, and
network integration CRSP transmission service rates throughout the 5
years of the effective rate. Western will annually provide 30 days
advance notice prior to a revised rate becoming effective.
3. Based upon review, Western now includes all transmission costs
to better reflect comparability between transmission charges for firm
power customers and transmission for nonpower customers. Western
considers the entire transmission system, including purchase wheeling
contracts, integrated, with the exception of one small transmission
agreement that is purchased to serve Western's office in Montrose,
Colorado. Western believes this is consistent with FERC's ruling in
Order No. 888 that all transmission costs of an integrated transmission
system are included. As a result, Western has allocated approximately
$7.5 million of costs to transmission that had been allocated only to
its firm power customers in the initial rate proposal.
The change in the CRSP firm transmission service rate is due to
gross transmission revenue requirements increasing, but being offset,
to some extent, by transmission revenue credits and an increase in firm
wheeling reservations.
Major factors having an impact upon the provisional CRSP
transmission rates are summarized in the table below. Because rates
must return sufficient revenues to pay for estimated future costs, the
table compares the change in the average annual projections used in the
FY 1993 transmission study (which set the rate effective October 1,
1992) and the rate setting transmission study for this rate adjustment.

----------------------------------------------------------------------------------------------------------------
Estimated
rate effect
Major factors Unit Amount ($/kW-
month)
----------------------------------------------------------------------------------------------------------------
Increase in average annual revenue requirements.......................... $1,000 $13,125 +.51
Increase in total transmission revenue credits........................... $1,000 $2,544 -.10
Increase in amount of firm transmission only service..................... (\1\) 86,913 -.07
----------------------------------------------------------------------------------------------------------------
\1\ kW-year.

[[Page 16805]]

Network

Network integration transmission service is a new service for CRSP.
Western does not currently have any network integration transmission
customers on its CRSP transmission system. Western only has available
transfer capacity on isolated portions of the CRSP transmission system,
and therefore it does not believe it has sufficient capability to
satisfy the needs of most entities desiring network integration
transmission service.
The same revenue requirement that was used in determining the
provisional firm point-to-point transmission rate will also be used in
determining the provisional rate for the network integration
transmission service. The provisional rate formula for the monthly
demand charge for network integration transmission service, if
purchased, 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 Western's
monthly transmission system peak. Western's transmission system peak
includes the sum of capacity reserved for point-to-point transmission
and the SLCA/IP long-term firm power obligations. The provisional rate
formula is to be effective for the period beginning April 1, 1998,
through March 31, 2003.

Statement of Revenue and Related Expenses

The following table provides a summary of revenue requirements data
for the CRSP firm point-to-point transmission rate through the 5-year
provisional rate approval period.

CRSP Comparison of 5-Year Rate Period Revenues and Expenses (1998-2002)
------------------------------------------------------------------------
Existing Provisional Difference
rate ($000) rate ($000) ($000)
------------------------------------------------------------------------
Revenue Requirements Annual
Expenses:
Investment.................. $170,558 $188,550 $17,992
O&M......................... $80,013 $63,483 ($16,530)
Replacements................ $14,000 $26,716 $12,716
3rd Party Transmission
Expenses................... $0 $37,606 $37,606
---------------------------------------
Total Annual Expenses... $264,571 $316,355 $51,784
Less Revenue Credits
Miscellaneous............... $3,941 $1,590 ($2,351)
Exchange Capacity........... $8,635 $19,124 $10,489
Nonfirm Transmission........ $2,130 $6,566 $4,436
Provo River Project/
Ancillary.................. $0 $149 $149
Total Revenue Credits... $14,706 $27,429 $12,723
---------------------------------------
Total Net Annual Revenue
Requirements........... $249,865 $288,926 $39,061
------------------------------------------------------------------------

Basis for Rate Development

The provisional firm point-to-point transmission rate for 1998 is
$2.23 per kW-month, which is an 18.0 percent increase when compared to
the current firm transmission rate of $1.89 per kW-month. The rate
formula extends through March 31, 2003.

Comments

The comments and responses regarding the transmission rates,
paraphrased for brevity when it does not affect 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) applicability of transmission rate,
(2) offsetting revenues, (3) total capacity calculation, and (4)
miscellaneous comments.
1. Applicability of Transmission Rate
Comment: Western indicates in its Rate Brochure that the
provisional transmission rates will be applied to all ``transmission
only'' sales, and therefore will not be applied to the use of the
transmission system to deliver firm power obligations. Customers
strongly support this position.
Response: The CRSP CSC does not, at this time, intend to bill firm
power customers separately for the transmission use associated with
firm power deliveries since this cost is included in the firm power
rate. The CRSP CSC also does not intend, at this time, to bill firm
power customers separately for ancillary services associated with firm
power deliveries since this cost is also included in the firm power
rate.
The transmission rate denominator reflects the use of the CRSP
transmission system by all parties including the CRSP CSC. Also, the
transmission costs allocated to be repaid by the long-term firm power
customers are calculated on the same basis as those paid by firm point-
to-point transmission customers and both customer groups are allocated
an appropriate share of the transmission costs. However, they are
billed differently for the service. The same costs are applied whether
point-to-point or firm power customers are using the CRSP transmission
system.
Comment: Customer requests clarification of what ancillary services
are included in the transmission rate and why a separate scheduling and
dispatch charge was developed.
Response: The provisional point-to-point and network integration
transmission service rates include the CRSP CSC costs for scheduling,
system control, and dispatch. These rates also include the cost of
reactive supply and voltage control. Once DSWR and RMR assume control
area responsibility for CRSP, expected April 1, 1998, their respective
tariffs for reactive supply and voltage control will apply.
A charge for short-term sales of scheduling and dispatch service
was developed and placed into effect by the Acting Administrator,
pursuant to Delegation Order, and will remain in effect until DSWR and
RMR assume control area operator responsibility for the CRSP, expected
to be April 1, 1998. This rate was developed to be applied to those
utilities that schedule through CRSP's control area because their
transmission system is in CRSP's control area, but they are not using
CRSP's transmission facilities. However, given the short amount of time
this short-term charge would be effective,

[[Page 16806]]

Western has decided not to implement this short-term charge.
Comment: Will the new firm point-to-point rate be applicable to all
existing contracts for firm transmission?
Response: Yes. The provisional firm point-to-point transmission
rates will apply to all existing and future CRSP point-to-point
transmission contracts for as long as the rate is effective.
2. Offsetting revenues
Comment: In developing its transmission rate, Western did not
include any revenues from ancillary services. To the extent that
Western recovers more than a minor amount of revenues from ancillary
services, these revenues should offset costs in developing its
transmission rate. The scheduling, system control, and dispatch service
rate was determined using projected schedules, but no revenues were
projected in the transmission revenue credit.
Response: Western did not include revenues from ancillary services
for several reasons. First, the CRSP CSC disagrees that all revenues
from ancillary services should be applied to offset the transmission
expenses. Rather, the only ancillary service revenues the CRSP CSC
would consider applying to offset transmission expenses are from the
scheduling, system control, and dispatch. Any revenues from the
remaining ancillary services will be applied to offset the firm power
expenses, since they are all generation related.
Secondly, the charge for short-term sales that was developed for
scheduling, system control, and dispatch is only in effect until DSWR
and RMR assume control area responsibility. Since the initial rate
proposal, the projected control area merger date has been changed from
June 1, 1998 to April 1, 1998. Therefore, the CRSP CSC does not
anticipate applying a scheduling, system control, and dispatch charge,
since it will no longer have its own control area April 1, 1998.
Third, the CRSP CSC projects revenue credit estimates based on the
average amount of the previous 5 years. Since the CRSP CSC has not
charged a separate scheduling, system control, and dispatch service
during the previous 5 years, it is unable to develop a projected
estimate of revenues now.
The CRSP CSC will be annually recalculating the firm point-to-point
transmission rate and as part of this, revenue credits will be revised,
including ancillary services. During the first 5 years, the CRSP CSC
will project the scheduling, system control, and dispatch ancillary
service revenues based on the average of the years of data available
(e.g., 2 years of data will be summed and divided by 2). Therefore, as
CRSP receives the scheduling, system control, and dispatch ancillary
service revenue, they will be included and reflected in the future
annual recalculations of the firm point to point transmission rate.
Comment: What are the offsetting revenues for the transmission
rate?
Response: These are transmission related revenues that come into
the transmission system which are not from the sale of firm
transmission, such as the revenue Western receives from phase-shifting
transformers and nonfirm transmission service.
Comment: The 1992-96 back-up sheet shows an average for
miscellaneous revenue credit of approximately $753,000. The rate study
included about $318,000.
Response: The back-up sheet was incorrect. The amount included in
the transmission and firm power rate study was $318,000.
Comment: The CRSP CSC should adjust its annual formula to account
for annual changes in nonfirm transmission revenue. Customer suggests
that this be updated each year.
Response: Western agrees and plans to adjust its formula to account
for changing revenue credits, including nonfirm transmission revenue.
Comment: Nonfirm transmission revenue credit is understated for the
future. Suggest using 1996 number of $2.5 million rather than using the
historical average. Using the historical average for this revenue
credit assures an overrecovery of transmission revenues on a nonfirm
basis.
Response: The historical data provided shows fluctuations up and
down; e.g., in 1995 nonfirm wheeling revenue dropped from about $1.6
million (1994 level) to $0.8 million. For this reason, an average was
used instead of the most recent year historical data. Annually, Western
will be updating the 5-year rolling estimate based on previous years'
revenues.
Comment: The footnote to line F of tab 20 in the Supporting
Documentation states that the amount comes from the spreadsheet shown
in tab 23. The data reference does not add to the numbers on tab 20.
Response: When the exchange revenue and phase shifter revenues
($2,070,467 and $1,161,000 respectively for 1998) under tab 23 are
summed, they equal the amount reflected in tab 20, line F ($3,680,467
for 1998), for every year.
3. Total Capacity Calculation
Comment: Not all firm transmission reservations/requests have been
included in the rate study, particularly one customer's request for 78
MW in 1999, and 27 MW between 2000-2002. The customer has received
confirmation for these amounts. Furthermore, the customer has made a
verbal request, for 50 MW in 1998 that has not been confirmed.
Response: The 27 MW in years 1999 through 2002 are on the Pick-
Sloan transmission system, not on the CRSP transmission system and,
therefore, are not included in the CRSP transmission rate study. The
remaining 51 MW of the 78 MW requested in 1999 is for 4 months (June 1
through September 30). Since this is not a long-term firm arrangement,
Western will include the revenues as a revenue credit once it receives
the revenues.
The CRSP CSC has not confirmed the 50 MW verbal request because, as
the customer was informed, the transmission availability for this
particular request can not be confirmed until the first month of
request is closer. If Western is able to provide transmission service
to the customer, then the revenues will be accounted for as nonfirm
transmission revenues once they occur, since this request is also
short-term (May through December). Furthermore, this request is outside
the scope of this rate adjustment process.
Comment: Customer requests a breakdown of the denominator of the
firm point-to-point transmission rate. In particular, does the
denominator include Salt River Project exchange agreement?
Response: The denominator includes all of Western's long-term firm
obligations, which is the sum of the CROD under long-term firm power
contracts, plus an amount for high hydrological conditions, plus the
sum of the contracted transmission reservations. The denominator also
includes the maximum amount Western might be required to provide under
the agreement with Salt River Project.
Comment: The transmission rate calculation table shows 250 MW for
Salt River, but the customer believes this should be 500 MW.
Response: The 500 MW is the total exchange amount. Salt River
Project delivers up to 500 MW to Western at Craig, Hayden, and Four
Corners collectively. In exchange, Western delivers an equal amount at
Glen Canyon. The remaining Craig, Hayden, and/or Four Corners
generation, which does not exchange, is wheeled for Salt River to Glen
Canyon up to a maximum

[[Page 16807]]

of 250 MW depending upon system transfer capability. The 250 MW is the
maximum that Western would be required to wheel for Salt River Project
if the exchange did not work. The 500 MW that are exchanged meet part
of Western's CROD commitments.
Comment: The CRSP CSC is commended for proper treatment of the Salt
River Project Exchange Agreement, but the proposed treatment of the
Tri-State G&T Exchange Agreement is inconsistent. The 100 MW for the
Tri-State Exchange is not included in the reserve capacity, as the Salt
River Exchange is, and it is dealt with as an exchange credit. The
treatment of revenue from the Exchange Contracts as a revenue credit to
firm transmission revenue requirement results in the other firm
transmission customers essentially subsidizing the costs of these
contracts.
Response: The Salt River Exchange contract was entered into on the
premise that it was integral to the delivery of SLCA/IP power. The
revenues from the Salt River Exchange contracts are treated as a credit
to the CRSP transmission revenue requirements, and the capacity amount
is included in the calculation of total reserved capacity. Therefore,
Salt River Project and the firm power customers jointly share in the
full cost recovery of this exchange; the transmission customers do not.
However, the Tri-State contract was not entered into for the same
purpose. This Tri-State agreement was in existence prior to FERC Order
No. 888 and has negotiated capacity and annual payment calculation
amounts that cannot be changed unilaterally.
Western is required by law to recover all the transmission costs
through its revenues. In order to treat all transmission customers
equitably, all the transmission customers, including the firm power
customers, will share the burden of recouping the revenue requirements.
Comment: The rate study firm transmission capacity is not
consistent with the supporting documentation. The rates summary refers
to the firm wheeling contracted capacity in the years 2001 and 2002 as
370,315 kW; however, the Supporting Documentation shows 371,315 kW.
Also, assuming the historic growth in capacity for the Page, Arizona,
reservation, there needs to be an additional 1,400 kW in that year.
Response: The appropriate number of 371,315 kW is reflected in the
rate order transmission study. The Page, Arizona, transmission capacity
estimates are taken from projections provided by Page to Western.
Western will update the capacity projections annually when establishing
the yearly firm point-to-point transmission rate.
4. Miscellaneous Comments
Comment: Customer believes that the approximately $7.5 million of
third-party transmission costs should not be included in the rate
formula because the transmission usage of these systems will only be
available for firm power customers.
Response: Almost all of the third party transmission contracts
(costing approximately $7.5 million in transmission expenses) are
included in the total CRSP transmission revenue requirements except
one. The $2,610 annual cost paid to the Delta-Montrose Electric
Associaton is to transmit power to the CRSP Operations Center in
Montrose, Colorado. The Operations Center's functions deal with both
transmission and electric service. Therefore, the $2,610 is allocated
to both types of customers on an investment basis, the same method the
O&M costs are allocated between the two customer groups. All of the
other annual costs are for transmission that can be used to deliver
SLCA/IP power and the power of others to points of delivery and,
therefore, are included in the total CRSP transmission costs.
Western considers the entire transmission system, including
purchase wheeling contracts, integrated, and believes this is
consistent with FERC's ruling in Order No. 888 that all transmission
costs of an integrated transmission system are included.
Additionally, Western has received inquiries for use of available
transfer capacity over these contracted paths and may, in the future,
provide transmission service where capacity is available.
Comment: Western has shifted transmission revenue requirements from
generation to transmission-only customers by using peak annual CRODs
instead of powerplant capacity. Western has moved approximately 7
percent of the transmission revenue requirement from the generation
customers on the CRSP system to the transmission-only customers on the
system.
Response: Western is basing its total transmission capacity
reserved for its firm power obligations on the maximum CROD Western
might be required to deliver under its existing firm power contracts
instead of basing it on full nameplate power plant capacity. The CRSP
CSC changed its calculation methodology since this is a more reasonable
and accurate reflection of how much transmission system capacity must
be reserved for those firm power customers.
Using full nameplate resulted in undercollection of transmission
revenue requirements by transmission users, and overcollection of
revenues from firm power customers. Also, Western included 130 MW for
use during high hydrological conditions in its total reserved capacity
calculation. In fact, the total CRSP reserved transmission capacity,
less system transmission only contracts, is 2 MW less than the
nameplate generating capacity; therefore, this has resulted in no
impact to the transmission rate.
Comment: The proposed transmission rate structure is a good interim
step towards compliance with FERC Orders No. 888 and 889. It is hoped
that the CRSP transmission system will join other systems in a common
approach.
Response: Western is reviewing the possible merits of joining an
Independent System Operator (ISO). Should this occur, a joint ISO
transmission rate will likely be developed.
Comment: The Rate Brochure states that no network service is
offered at this time. Is Western using network integration transmission
service when delivering firm power?
Response: Network integration transmission service is a new service
being offered under Western's OAT. The firm power is transmitted under
existing contracts, not under Western's OAT. FERC's Order No. 888-A, 78
FERC para. 61,220, mimeo at 243-244 (1997), notes the fact that
Western's customers may neither be true point-to-point or network
integration transmission customers.
Comment: Is Western's point-to-point service really a flexible
point-to-point, that is a point could be multiple points?
Response: For existing contracts, it will depend on the contract.
For future contracts, Western intends to provide the point-to-point
service consistent with FERC Orders No. 888 and 888-A and under its
OAT, which was published January 6, 1998, at 63 FR 521 (1998) however,
the CRSP CSC is willing to customize transmission service, should that
be desired and requested by new transmission customers.
Comment: What kind of loss multipliers does Western contemplate?
Response: The CRSP CSC has not made any changes to the losses in
this rate adjustment. The average system loss factor is still 5.5
percent, unless otherwise stated in existing contracts.
Comment: In connection with the OAT that is being proposed, the
customer understands that the FERC is requiring unbundling of the rate.
The customer has been told that the

[[Page 16808]]

proposed firm power rate is bundled and includes transmission to
customers' points of delivery, up to the customers' CROD. Does the CRSP
CSC contemplate another rate proceeding with their OAT to unbundle this
rate?
Response: Western does not anticipate unbundling its firm power
rate at this time. The functional unbundling requirement of FERC Order
No. 888 does not apply to existing contracts. Furthermore, Western has
established a separate charge for transmission, and the firm power
customers are paying this same charge as part of their firm power rate.
Comment: Western should conduct a study of price elasticity and
competition in considering future funding proposals.
Response: Western appreciates the comment; however, the CRSP CSC is
unable to directly respond because it is outside the scope of this rate
adjustment process.
Comment: Western should ensure that direct assignment substations
costs are borne by the appropriate customers, and a breakdown of the
total substation costs should be made available to the public in any
transmission rate adjustment study. The customer is concerned that some
of these substations, if not properly and directly assigned to the
customer when they serve only a specific customer, be included in the
rate.
Response: The CRSP CSC does not have any direct assignment
facilities; all customers share the costs for the entire transmission
system. In some instances, third parties use a part of CRSP CSC's
facilities and CRSP receives revenues for this. These revenues are
included as credits to the gross transmission revenue requirement.
Comment: Commentor believes that there should be no power marketing
expense assigned to transmission. In general, the allocation percentage
based on investment has some flaws in it in terms of certain overhead
expenses.
Response: Western's power marketing staff supports both the
transmission and generation functions as appropriate. CRSP's allocation
methodology between power and transmission has historically been on the
basis of investment, and CRSP believes that this continues to be an
equitable and appropriate method.

Ancillary Services Discussion

Ancillary services are previously provided services now being
offered separately by Western. Of the six ancillary services offered by
the CRSP CSC, two are required to be purchased by the CRSP transmission
user. These two are scheduling, system control, and dispatch service,
and reactive supply and voltage control service. The remaining four
ancillary services--regulation and frequency response service, energy
imbalance service, spinning reserve service, and supplemental reserve
service--will be offered. 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. If Western does not have the resources
available from SLCA/IP, the CRSP CSC will offer to purchase the
resource from the open market or from a control area operator, and pass
the cost through to the customer, including a 10 percent administrative
fee.
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,
and reactive supply and voltage control are included in the provisional
transmission services rates. Once Western's DSWR and RMR assume control
area responsibility for CRSP, expected April 1, 1998, their respective
reactive supply and voltage control tariffs will apply.
The provisional rates and descriptions for the six ancillary
services are as follows:

Provisional Ancillary Services Rates
------------------------------------------------------------------------
Ancillary service
Ancillary service type description Provisional rate
------------------------------------------------------------------------
Scheduling, System Control, Required to schedule Included in
and Dispatch. the movement of appropriate
power through, out transmission rates.
of, within, or into Nonfirm customers
a control area. will be supplied
under the
respective control
area tariffs of
either RMR or DSWR
once control areas
merge.
Reactive Supply and Voltage Reactive power Included in
Control. support provided appropriate
from generation transmission rates
facilities that is until control areas
necessary to merge. After the
maintain control areas
transmission merge, RMR and DSWR
voltages within tariffs will apply
limits that are accordingly.
generally accepted
in the region and
consistently
adhered to by the
transmission
provider.
Regulation and Frequency Necessary to provide Will obtain
Response. for the continuous regulation on the
balancing of open market for the
resources, customer and pass
generation and through the costs,
interchange, with with an added 10
load and for percent
maintaining administrative
scheduled charge, if
interconnection unavailable from
frequency at sixty SLCA/IP resources.
cycles per second If available for
(60 Hz). sale, the effective
SLCA/IP firm power
capacity rate, will
be charged.
Energy Imbalance............ Provided when a Will obtain from
difference occurs control area
between the operator and pass
scheduled and the through the costs,
actual delivery of with an added 10
energy to a load percent
located within a administrative
control area over a charge.
single hour.
Spinning Reserve............ Needed to serve load Will obtain on the
immediately in the open market for the
event of a system customer and pass
contingency. through the costs,
with an added 10
percent
administrative
charge, if
unavailable from
SLCA/IP resources.
If available for
sale, the effective
SLCA/IP firm power
rate, will be
charged.
Supplemental Reserve........ Needed to serve load Will obtain on the
in the event of a open market for the
system contingency; customer and pass
however, it is not through the costs,
available with an added 10
immediately to percent
serve load but administrative
rather within a charge, if
short period of unavailable from
time. SLCA/IP resources.
If available for
sale, the effective
SLCA/IP firm power
rate, will be
charged.
------------------------------------------------------------------------

[[Page 16809]]

Comments

The comments and responses regarding ancillary service rates,
paraphrased for brevity when they do not affect 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) scheduling, system control, and
dispatch charge, (2) energy imbalance charge and deadband, and (3)
miscellaneous comments.
1. Scheduling, System Control, and Dispatch Charge
Comment: Clarification of scheduling, system control, and dispatch
charges is necessary. What charges will be assessed beyond the first
five schedule changes per day? Can transactions entering or leaving the
control area now be under one schedule? Will there be a separate
category for schedules which require hourly schedule changes?
Response: The CRSP CSC developed a short-term scheduling, system
control, and dispatch charge for those entities which have transmission
in the Western Area Upper Colorado control area. However, because this
control area is expected to be merged with two other control areas by
April 1, 1998, CRSP does not anticipate applying this short-term
charge.
Once DSWR and RMR assume control area operator responsibility, then
transactions entering or leaving different control areas will be
assessed charges appropriately by each control area.
Comment: There is an inherent conflict that exists between the
limitation of five schedule changes per day and the burden to follow a
load which is imposed under the Energy Imbalance Service provisions. To
avoid being charged for energy imbalance, one must make a large number
of schedule changes.
Response: The CRSP CSC developed a short-term scheduling, system
control, and dispatch rate which established a limitation of 5 schedule
changes per day. This rate, however, will not be applied because of the
timing of the control area merger. Once DSWR and RMR assume control
area responsibility for CRSP, the scheduling, system control, and
dispatch rate and scheduling limitation set forth in their applicable
tariffs will apply.
2. Energy Imbalance Charge
The CRSP CSC received several comments regarding its proposed
energy imbalance service charge. Since the rate proposal, Western has
revised the projected date from June 1, 1998, to April 1, 1998, for RMR
and DSWR to assume control area operator responsibility. As a result of
this revised control area merger date, the CRSP CSC will not be placing
a separate energy imbalance charge into effect, rather it will offer to
obtain this service from a control area operator, and pass the costs
through directly to the customer, with an added 10 percent
administrative charge. Therefore, the CRSP CSC is not responding to any
of the comments received regarding this charge.
3. Miscellaneous
Comment: Does Western expect the price for supplemental reserves to
be less than spinning reserves?
Response: The CRSP CSC developed the charges assuming the same
charge would apply to both services. The CRSP CSC does not anticipate
having reserves available from SLCA/IP resources. If these are
available, they will be priced at the firm power rate. If they are
unavailable, the CRSP CSC will purchase and pass these costs through to
the customer, including a 10 percent administrative charge for the cost
of providing the service.
Comment: The customer strongly supports Western continuing to
provide ancillary services as part of firm power services.
Response: As part of its long-term power obligations, Western will
continue to provide ancillary and transmission services and include the
costs in the firm power rate.
Comment: The customer wants tracking and allocation methodologies
for expenses and revenues associated with ancillary services to be
analyzed in detail for proper tracking and accounting for each Federal
Project customer in the future. Need to identify what resources are
available to provide ancillary services to those customers which are
not firm power customers.
Response: The CRSP CSC plans to begin a process of determining the
amount of services each customer receives and also to determine the
amount of ancillary services committed. However, the CRSP CSC does not
anticipate having any SLCA/IP resources available for ancillary
services to offer since these resources have already been committed to
the SLCA/IP firm power customers.

Regulatory Flexibility Analysis

The Regulatory Flexibility Act of 1980, 5 U.S.C. 601-612, requires
Federal agencies to perform a regulatory flexibility analysis if a
proposed rule is likely to have a significant economic impact on a
substantial number of small entities. Western has determined that this
action relates to rates or services offered by Western and, therefore,
is not a rule within the purview of the Act.

Environmental Evaluation

In compliance with the National Environmental Policy Act of 1969
(NEPA), 42 U.S.C. 4321 et seq.; Council on Environmental Quality
regulations, 40 CFR Parts 1500-1508; and DOE NEPA regulations, 10 CFR
Part 1021, Western has determined that this action is categorically
excluded from the preparation of an environmental assessment or an
environmental impact statement.

Executive Order 12866

Western has an exemption from centralized regulatory review under
Executive Order 12866; accordingly, no clearance of this notice by OMB
is required.

Submission to Federal Energy Regulatory Commission

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

Order

In view of the foregoing and pursuant to the authority delegated to
me by the Secretary of Energy, I confirm and approve on an interim
basis, effective April 1, 1998, Rate Schedules SLIP-F6, SP-PTP5, SP-
NW1, SP-NFT4, SP-SD1, SP-RS1, SP-EI1, SP-FR1, and SP-SSR1. The rate
schedules shall remain in effect on an interim basis, pending FERC
confirmation and approval of them or substitute rates on a final basis
through March 31, 2003.

Dated: March 23, 1998.
Elizabeth A. Moler,
Deputy Secretary.

Rate Schedule SLIP-F6, (Supersedes Schedule SLIP-F5); Salt Lake City
Area Integrated Projects; Arizona, Colorado, Nevada, New Mexico, Utah,
Wyoming

Schedule of Rates for Firm Power Service

Effective
First day of the first full billing period beginning on or after
April 1, 1998, and extending through March 31, 2003, or until
superseded by another rate schedule, whichever occurs earlier.
Available
In the area served by the Salt Lake City Area Integrated Projects.

[[Page 16810]]

Applicable
To the wholesale power customer for firm power service supplied
through one meter at one point of delivery, or as otherwise established
by contract.
Character
Alternating current, 60 hertz, three-phase, delivered and metered
at the voltages and points established by contract.
Monthly Rate
Demand Charge: $3.44 per kilowatt of billing demand.
Energy Charge: 8.10 mills per kilowatthour of use.
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 Purchased Resources
Purpose of Adjustment: The Record of Decision on Western's Electric
Power Marketing Environmental Impact Statement returned the
Contractor's allocations to those established in the Post-1989
Marketing Plan (Plan). This Plan originally included a 400 GWh pass-
through-cost purchase. However, this 400 GWh is now included in the
rate as a purchased power expense, but it may not be sufficient to meet
the Contractor's full contract entitlement. Therefore, additional
firming purchases may be needed in order to meet the Contractor's full
entitlement. Western developed a Replacement Purchase Options
Amendment, effective on April 1, 1997, which provided options for
either Western to replace the firming purchases on a pass-through-cost
basis through Western Replacement Power (WRP) or for the Contractor to
replace the firming purchases on its own through Customer Displacement
Power (CDP). Those Contractors who are not receiving service under the
Replacement Purchase Options Amendment will also receive additional
firming on a pass-through-cost basis. This adjustment is to ensure that
Western recovers the purchased power costs and any other associated
costs for the firming purchases.
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 within a given period and be
paid for on a pass-through-cost basis. Western will include in the
Contractor's monthly power bill 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.
Adjustment for Contractors not currently receiving service under the
Replacement Purchase Options Amendment.
When Western purchases firming resources on behalf of the
Contractor, the Contractor shall be billed for its proportionate share
of the costs associated with the additional firming purchase.

Rate Schedule SP-PTP5, (Supersedes Schedule SP-FT4); Colorado River
Storage Project; Arizona, Colorado, New Mexico, Wyoming, 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 April 1, 1998, and extending through March 31, 2003, 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 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 the net annual
transmission revenue requirement averaged over a 5-year cost evaluation
period (1998-2002). The total gross annual transmission revenue
requirement, $63,271,015, is reduced by the currently projected 5-year
average revenue credits to determine the total net annual costs to be
recovered. The total net annual transmission revenue requirement to be
recovered is divided by the currently projected 5-year average capacity
reservation needed to meet firm power and transmission commitments in
kW, plus the total network integration loads at system peak, to derive
a cost/kW-month. The formula is as follows:

$63,271,015 -Total Revenue Credits=Total Net Annual Transmission
Revenue RequirementTotal Firm Capacity reservations+Network
loads at system peak= Unit Cost/Year ($/kW-year)12

This formula will be recalculated by revising the rate denominator
(reserved capacity) based on current reservations and the net annual
transmission credits, and a revised rate, if needed, will be placed
into effect every April 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-RS1 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 utilized 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

[[Page 16811]]

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.

Rate Schedule SP-NW1; Colorado River Storage Project; Arizona,
Colorado, New Mexico, Wyoming, Utah

Schedule of Rate for Network Integration Transmission Service

Effective
The first day of the first full billing period beginning on or
after April 1, 1998, and extending through March 31, 2003, 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 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.
Network Rate Formula
The network integration transmission service rate 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. The formula is as follows:

$63,271,015 -Total Revenue Credits=Total Net Annual Transmission
Revenue RequirementTotal Firm Capacity reservations + Network
loads at system peak=Unit Cost/Year ($/kW-year)12

The rate for network transmission service includes scheduling,
system control, and dispatch. Rate Schedule SP-RS1 will be attached as
part of this Rate Schedule and apply to network transmission customers.
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.

Rate Schedule SP-NFT4; Colorado River Storage Project; Arizona,
Colorado, New Mexico, Wyoming, Utah

Schedule of Rate for Nonfirm Point-to-Point Transmission Service

Effective
The first day of the first full billing period beginning on or
after April 1, 1998, and extending through March 31, 2003, or until
superseded by another rate schedule, whichever occurs earlier.
Available
This schedule supersedes SP-NFT3 and is available for the Nonfirm
Transmission Service on the Colorado River Storage Project transmission
system.
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 Open Access Tariff.
Rate
The Proposed Rate for nonfirm point-to-point CRSP transmission
service is a mills/kWh rate based on market conditions but never higher
than the firm point-to-point rate as specified in Rate Schedule SP-FT5
or any superseding rate schedule.
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 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 a service contract is not available, the losses shall be
specified in advance and may be included in the rates for the service.

Rate Schedule SP-SD1; Colorado River Storage Project; Arizona,
Colorado, New Mexico, Wyoming, Utah

Schedule of Rates for Scheduling, System Control, and Dispatch
Ancillary Service

Effective
Beginning on April 1, 1998, and extending through March 31, 2003.
Available
In the area served by the Colorado River Storage Project (CRSP)
transmission system.
Applicable
To all customers who are not using the CRSP transmission but are
receiving scheduling, system control, and dispatch service.
Character of Service
Scheduling, System Control, and Dispatch--is required to schedule
the movement of power through, out of, within, or into a control area.
Rate
Included in appropriate transmission rates. Once control areas
consolidate, Rocky Mountain and Desert Southwest Regions' tariffs will
apply to nonfirm customers accordingly.

Rate Schedule SP-RS1; Colorado River Storage Project; Arizona,
Colorado, New Mexico, Wyoming, Utah

Schedule of Rates for Reactive Supply and Voltage Control Ancillary
Service

Effective
Beginning on April 1, 1998, and extending through March 31, 2003.
Available
In the area served by the Colorado River Storage Project (CRSP)
transmission system.
Applicable
To all CRSP transmission customers.
Character of Service
Is reactive power support provided from generation facilities that
is necessary to maintain transmission voltages within acceptable limits
of the system.

[[Page 16812]]

Rate
Service is included in appropriate transmission rates. Once control
areas merge, Rocky Mountain and Desert Southwest Regions' tariffs will
apply accordingly.

Rate Schedule SP-EI1; Colorado River Storage Project; Arizona,
Colorado, New Mexico, Wyoming, Utah

Schedule of Rates for Energy Imbalance Ancillary Service

Rate Schedule SP-FR1; Colorado River Storage Project; Arizona,
Colorado, New Mexico, Wyoming, Utah

Schedule of Rates for Regulation and Frequency Response Ancillary
Service

Rate Schedule SP-SSR1; Colorado River Storage Project; Arizona,
Colorado, New Mexico, Wyoming, Utah

Schedule of Rates for Spinning and Supplemental Reserve Ancillary
Service

Effective
Beginning on April 1, 1998, and extending through March 31, 2003.
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 6 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
Spinning Reserve will obtain on the open market for the customer
and pass through the costs, with an added 10 percent administrative
charge, if unavailable from SLCA/IP resources. If available for sale,
the SLCA/IP firm power rate currently in effect will be charged.
Supplemental Reserve will obtain on the open market for the
customer and pass through the costs, with an added 10 percent
administrative charge, if unavailable from SLCA/IP resources. If
available for sale, the SLCA/IP firm power rate currently in effect
will be charged.
[FR Doc. 98-8939 Filed 4-3-98; 8:45 am]
BILLING CODE 6450-01-P