[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)   
----------------------------------------------------------------------------------------------------------------
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

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
    Provided when a difference occurs between the scheduled and the 
actual delivery of energy to a load located within a control area over 
a single hour.
Rate
    Will obtain from control area operator and pass through the costs, 
with an added 10 percent adminstrative charge.

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

Schedule of Rates for Regulation and Frequency Response 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
    Is necessary to provide for the continuous balancing of resources, 
generation and interchange, with load and for maintaining scheduled 
interconnection frequency at sixty cycles per second (60 Hz).
Rate
    Will obtain regulation 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 capacity rate, currently in effect, will be charged.

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