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

DEPARTMENT OF ENERGY

Western Area Power Administration

Salt Lake City Area/Integrated Projects and Colorado River

Storage Project--Notice of Rate Order-WAPA-78

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of rate order.

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SUMMARY: Notice is given of the confirmation and approval by the Deputy

Secretary of the Department of Energy (DOE) of Rate Order No. WAPA-78

and Rate Schedule SLIP-F6, placing firm power rates from the Salt Lake

City Area/Integrated Projects (SLCA/IP) of the Western Area Power

Administration (Western) into effect on an interim basis. Also Rate

Schedules SP-PTP5, SP-NW1, and SP-NFT4, placing firm and nonfirm

transmission rates on the Colorado River Storage Project (CRSP)

transmission system into effect on an interim basis. Lastly, Rate

Schedules SP-SD1, SP-RS1, SP-EI1, SP-FR1, and SP-SSR1 placing rates for

ancillary services on the CRSP system into effect on an interim basis.

The provisional firm power, firm and nonfirm transmission, and

ancillary service rates will be effective from April 1, 1998 through

March 31, 2003. The provisional firm power rate consists of an energy

charge of 8.1 mills per kilowatthour (mills/kWh) and a capacity charge

of $3.44 per kilowatt month (kW-month), which results in a composite

rate of 17.57 mills/kWh. This is a 12.9 percent decrease from the

current composite rate of 20.17 mills/kWh.

The provisional firm point-to-point transmission rate for 1998 is

$2.23/kW-month. This is a 18.0 percent increase over the current firm

transmission rate of $1.89/kW-month. The provisional network

integration transmission service rate is the product of the network

customer's load ratio share times one twelfth of the annual

transmission revenue requirement. The non-firm point-to-point

transmission rate will still be negotiated between Western and the

customer, but under the new rate schedule, it shall never exceed the

firm point-to-point transmission rate, which is 3.0 mills/kWh.

DATES: Rate Schedules SLIP-F6, SP-PTP5, SP-NW1, SP-NFT4, SP-SD1, SP-

RS1, SP-EI1, SP-FR1, and SP-SSR1 will be placed into effect on an

interim basis on the first day of the first full billing period

beginning on April 1, 1998, and will be in effect until Federal Energy

Regulatory Commission confirms, approves, and places the rate schedules

in effect on a final basis through March 31, 2003, or until the rate

schedules are superseded.

FOR FURTHER INFORMATION CONTACT: Mr. Dave Sabo, CRSP Manager, CRSP

Customer Service Center, Western Area Power Administration, P.O. Box

11606, Salt Lake City, UT 84147-0606, (801) 524-5493. Ms. Carol Loftin,

Team Lead, Rate Analysis, CRSP Customer Service Center, Western Area

Power Administration, P.O. Box 11606, Salt Lake City, UT 84147-0606,

(801) 524-6380.

SUPPLEMENTARY INFORMATION: By Amendment No. 3 to Delegation Order No.

0204-108, published November 10, 1993 (58 FR 59716), the Secretary of

Energy delegated (1) the authority to develop long-term power and

transmission rates on a nonexclusive basis to the Administrator of

Western; (2) the authority to confirm, approve, and place such rates

into effect on an interim basis to the Deputy Secretary; and (3) the

authority to confirm, approve, and place into effect on a final basis,

to remand, or to disapprove such rates to the Federal Energy Regulatory

Commission (FERC).

Pursuant to Delegation Order No. 0204-108 and existing Department

of Energy procedures for public participation in power rate adjustments

at 10 CFR Part 903, and 18 CFR 300, procedures for approving Power

Marketing Administration rates by FERC, Rate Order No. WAPA-78,

confirming, approving, and placing the proposed SLCA/IP firm power rate

adjustment, CRSP firm and nonfirm point-to-point, and network

transmission rate adjustment, and ancillary services rates into effect

on an interim basis, is issued, and the new Rate Schedules SLIP-F6, SP-

PTP5, SP-NW1, SP-NFT4, SP-SD1, SP-RS1, SP-EI1, SP-FR1, and SP-SSR1 will

be promptly submitted to FERC for confirmation and approval on a final

basis.

Dated: March 23, 1998.

Elizabeth A. Moler,

Deputy Secretary.

In the matter of: Western Area Power Administration Rate

Adjustments for Salt Lake City Area Integrated Projects, and

Colorado River Storage Project.

[[Page 16797]]

[Rate Order No. WAPA-78]

Order Confirming, Approving, and Placing the Salt Lake City Area/

Integrated Projects Firm Power, Colorado River Storage Project

Transmission, and Ancillary Service Rates Into Effect on an Interim

Basis

April 1, 1998.

These power and transmission rates are established pursuant to

Section 302(a) of the Department of Energy (DOE) Organization Act, 42

U.S.C. 7152(a), through which the power marketing functions of the

Secretary of the Interior and the Bureau of Reclamation (Reclamation)

under the Reclamation Act of 1902, ch. 1093, 32 Stat. 388, as amended

and supplemented by subsequent enactments, particularly section 9(c) of

the Reclamation Project Act of 1939, 43 U.S.C. 485h(c), and other acts

specifically applicable to the project system involved, were

transferred to and vested in the Secretary of Energy (Secretary).

By Amendment No. 3 to Delegation Order No. 0204-108, published

November 10, 1993 (58 FR 59716), the Secretary delegated (1) the

authority to develop long-term power and transmission rates on a

nonexclusive basis to the Administrator of the Western Area Power

Administration (Western); (2) the authority to confirm, approve, and

place such rates into effect on an interim basis to the Deputy

Secretary; and (3) the authority to confirm, approve, and place into

effect on a final basis, to remand, or to disapprove such rates to the

Federal Energy Regulatory Commission. Existing DOE procedures for

public participation in power rate adjustments are found at 10 CFR Part

903. Procedures for approving Power Marketing Administration rates by

FERC are found at 18 CFR Part 300.

Acronyms and Definitions

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

apply:

$/kW/month: Monthly charge for capacity (i.e., $ per kilowatt (kW) per

month).

AHP: Available hydro power. Maximum amount of hydro capacity and energy

that will be made available to the Contractor monthly as determined by

Western based on prevailing water conditions and set forth in

Contractor's firm power contract.

Capacity Component: Part of the firm power rate; expressed in dollars

per kW per month ($/kW-month). Applied each billing period to the

maximum kW the Contractor is entitled to on a seasonal basis, as

established by the Contractor's firm power contract.

CDP: Customer displacement power. One of two options available under

the Replacement Purchase Options Amendment. It is the amount of

supplemental power acquired or generated by the Contractor, on its own

behalf, which will be used as part of the Contractor's CROD and Monthly

Energy within a given period.

CME: Capitalized movable equipment.

Collbran: Collbran Project.

Contractor: An entity which has a contract with Western for SLCA/IP

Firm Electric Service.

CROD: Contract rate of delivery. The maximum amount of capacity the

Contractor is entitled to receive under its long-term firm power

contract.

CRSP: Colorado River Storage Project (includes Seedskadee and Dolores

Projects).

CRSP Act: Act of April 11, 1956, ch. 203, 70 Stat. 105, as amended, 43

U.S.C. 620-620o.

CRSP CSC: The Colorado River Storage Project Customer Service Center,

Western's office in Salt Lake City, Utah.

Customer: Any entity which receives SLCA/IP power, CRSP transmission,

or ancillary services.

DOE: U.S. Department of Energy.

DOE Order RA 6120.2: An order addressing power marketing administration

financial reporting, used in determining revenue requirements for rate

development.

DSWR: Desert Southwest Region, Western's office in Phoenix, Arizona.

EIS: Environmental impact statement.

Energy Component: Part of the firm power rate; expressed in mills per

kilowatt-hour (kWh). Applied to each kWh delivered to each customer.

FERC: Federal Energy Regulatory Commission.

Firming Power: Power Western will purchase up to the AHP level. This

type of purchase is included in the firm power rate.

Firming Purchases: Power purchased by Western or the Contractor above

the AHP level up to the Contractor's CROD. This purchase cost is passed

directly to the Contractor.

FRN: Federal Register notice.

FY: Fiscal year.

Glen Canyon: One of the storage units of the CRSP.

GCD EIS: Glen Canyon Dam Environmental Impact Statement.

GWh: Gigawatt-hour; equal to one million kW for a period of 1 hour.

Interior: U.S. Department of Interior.

Interest Offset: An offset to interest accrued allowed customers for

the monthly payment of principal which is due on a yearly basis.

kW: Kilowatt; 1,000 watts.

kWh: Kilowatt-hour; the common unit of electric energy, equal to one kW

taken for a period of 1 hour.

kW-month: Unit of electric capacity, equal to maximum amount of kW

taken during 1 month.

mill: Unit of monetary value equal to .001 of a U.S. dollar; i.e., 1/

10th of a cent.

mills/kWh: Mills per kilowatt-hour.

MW: Megawatt; equal to 1,000 kW or 1,000,000 watts.

NEPA: National Environmental Policy Act of 1969.

OAT: Open access transmission tariff.

OMB: Office of Management and Budget.

O&M: Operation and maintenance.

OM&R: Operation, maintenance, and replacement.

PRS: Power repayment study.

Rate Brochure: A document prepared for public distribution explaining

the background and purpose of this rate adjustment proposal.

Reclamation: Bureau of Reclamation, U.S. Department of the Interior.

Replacement Purchase Options Amendment: Amendment to the SLCA/IP firm

electric service contract which provides options to the Contractor for

replacing Glen Canyon Dam generation lost as a result of the GCD EIS.

RMR: Rocky Mountain Region, Western's office in Loveland, Colorado.

SLCA/IP: The Salt Lake City Area/lntegrated Projects, which are the

CRSP, Collbran, and Rio Grande Projects.

Supporting Documentation: Work papers which support the rate proposal.

Western: Western Area Power Administration, U.S. Department of Energy.

WRP: Western replacement power. One of two options available under the

Replacement Purchase Options Amendment. It is the amount of

supplemental power requested by the Contractor to be acquired by

Western on behalf of the Contractor as part of the Contractor's CROD

and monthly energy within a given period and paid for by the Contractor

on a pass-through-cost basis.

Effective Date

The new rates will become effective on an interim basis on the

first day of the first full billing period beginning on or after April

1, 1998, and will remain in effect pending FERC's approval of them or

substitute rates on a final basis

[[Page 16798]]

through March 31, 2003, or until superseded.

Public Notice and Comment

The Procedures for Public Participation in Power and Transmission

Rate Adjustments and Extensions, 10 CFR Part 903, have been followed by

Western in the development of these rates. The provisional firm power

rate represents a change of more than 1 percent in total SLCA/IP

revenues, and the provisional firm transmission rate represents a

change of more than 1 percent in total CRSP transmission revenues.

Therefore, they are major rate adjustments as defined at 10 CFR

Secs. 903.2(e) and 903.2(f)(1). The distinction between a minor and a

major rate adjustment is used only to determine the public procedures

for the rate adjustment.

The following summarizes the steps Western took to ensure

involvement of interested parties in the rate process:

1. On March 21, 1997, letters were sent to all SLCA/IP customers

and other interested parties announcing informal public meetings to be

held in Utah, Colorado, New Mexico, and Arizona, from April 16 to April

25, 1997.

2. At these informal meetings, Western representatives explained

the need for a rate adjustment and answered questions.

3. An FRN was published June 25, 1997 (62 FR 34255), officially

announcing the proposed firm power, transmission, and ancillary

services rates adjustment, initiating the public consultation and

comment period, announcing the public information and public comment

forums, and outlining procedures for public participation.

4. On June 27, 1997, a rate announcement package was sent to all

SLCA/IP customers, CRSP firm transmission customers, and other

interested parties announcing the publication of the June 25, 1997,

FRN, and the beginning of the formal public process to adjust firm

power, transmission, and ancillary services rates. The package

contained (1) a letter announcing the upcoming public information and

comment forums and (2) a copy of the June 25 FRN.

5. On July 14, 1997, a copy of the July 1997 ``Brochure for

Proposed Rates: Salt Lake City Area Integrated Projects Firm Power,

CRSP Transmission, and Ancillary Services' was mailed to all SLCA/IP

firm power customers, CRSP transmission customers, and other interested

parties.

6. At the public information forums held from August 1 to August 7,

1997, in Utah, Colorado, New Mexico, and Arizona, Western

representatives provided detailed explanations of the proposed rates

for SLCA/IP and CRSP, provided a list of unresolved issues that could

affect the proposed rates, and answered questions. An information

handout was provided at the forum.

7. The comment forums were held from September 16 to September 19,

1997, in the same locations as the information forums to give the

public an opportunity to comment for the record. Eleven individuals

commented at these forums.

8. Eight comment letters were received during the 90-day

consultation and comment period. The consultation and comment period

ended on September 23, 1997. Two additional letters were received after

the 90-day consultation period. All comments have been considered in

the preparation of this rate order.

Comments

Written comments were received from the following organizations:

Citizens Power, Colorado

Colorado River Energy Distributors Association, Utah

Irrigation & Electrical Districts Association of Arizona, Arizona

K.R. Saline & Associates, Arizona, on behalf of:

Chandler Heights Citrus Irrigation District

Electrical District No. 3 of Pinal County

Electrical District No. 4 of Pinal County

Electrical District No. 5 of Pinal County

Electrical District No. 6 of Pinal County

Electrical District No. 7 of Maricopa County

City of Safford

San Carlos Irrigation Project

Maricopa Water District

Roosevelt Irrigation District

San Tan Irrigation District

Naslund, Salt Lake City, Utah

Platte River Power Authority, Colorado

Public Service Company of Colorado (2), Colorado

Tri-State Generation and Transmission Association, Inc., Colorado

Utah Associated Municipal Power Systems, Utah

Representatives of the following organizations made oral comments:

Arizona Power Pooling Association, Arizona

Colorado River Energy Distributors Association, Utah

Irrigation & Electrical District Association, Arizona

Electrical District No. 3 of Pinal County, Arizona

K.R. Saline & Associates, Arizona

Navajo Tribal Utility Authority, Arizona

Public Service Company of Colorado, Colorado

Platte River Power Authority, Colorado

R.W. Beck, on behalf of Colorado River Energy Distributors Association,

Utah

Tri-State Generation & Transmission, Inc., Colorado

Utah Municipal Power Association, Utah

Project History

The SLCA/IP consists of the CRSP, Rio Grande, and Collbran

Projects. The CRSP described herein includes two CRSP participating

projects which have power facilities, Dolores and Seedskadee Projects.

The Rio Grande and Collbran Projects were integrated with CRSP for

marketing and rate making purposes on October 1, 1987. The goals of

integration were to increase marketable resources and to simplify

contract and rate development and project administration by creating

one rate and assuring repayment of Projects' costs. All integrated

projects maintain their individual identities for financial accounting

and repayment purposes, but their revenue requirements are integrated

into one PRS for rate making, known as the SLCA/IP. A detailed

description of the Collbran, Rio Grande, and CRSP Projects is located

in the Supporting Documentation.

Power Repayment Studies--Firm Power Rate

Power repayment studies are prepared each FY to determine if power

revenues will be sufficient to repay, within the prescribed time

periods, all costs assigned to the SLCA/IP power function. 43 U.S.C.

620(d) sets forth payment and repayment obligations of the CRSP. DOE

Order RA 6120.2, section 12b, requires that:

In addition to the recovery of the above costs (operation and

maintenance and interest expenses) on a year-by-year basis, the

expected revenues are at least sufficient to recover (1) each dollar of

power investment at Federal hydroelectric generating plants within 50

years after they become revenue producing, except as otherwise provided

by law; plus, (2) each annual increment of Federal transmission

investment within the average service life of such transmission

facilities or within a maximum of 50 years, whichever is less; plus,

(3) the cost of each replacement of a unit of property of a Federal

power system within its expected service life up to a maximum of 50

years; plus, (4) each dollar of assisted irrigation investment within

the period established for the irrigation

[[Page 16799]]

water users to repay their share of construction costs; plus, (5) other

costs such as payments to basin funds, participating projects or

states.

A review of the PRS indicates that the existing firm power rates

under Rate Schedule SLIP-F5 must be adjusted. The provisional composite

rate for firm power is 17.57 mills/kWh, a 12.9 percent decrease from

the existing firm power composite rate of 20.17 mills/kWh. The

provisional firm power composite rate is comprised of a capacity charge

of $3.44 /kW-month and an energy charge of 8.10 mills/kWh.

CRSP Transmission Service Rate Study

A transmission service rate study was prepared to ensure that

transmission service rates are based on the cost of service of the CRSP

transmission system. This study includes all transmission expenses and

associated offsetting revenues. Transmission service rates are charged

separately to entities receiving transmission only services over the

CRSP transmission system. SLCA/IP long-term firm power customers also

incur the cost for transmission of their SLCA/IP power; and this

expense is included in the firm power rate.

A review of the CRSP transmission service rate study indicates that

the existing firm and nonfirm CRSP transmission service rates under

Rates Schedules SP-FT4 and SP-NFT3, respectively, must be increased.

The CRSP CSC is seeking approval of a rate formula for calculation of

the firm point-to-point transmission rate, to be applied annually, and

a formula for calculating the network integration transmission service

rate to be applied annually. These formulas will be effective April 1,

1998, through March 31, 2003. The provisional rate for firm, point-to-

point, CRSP transmission service is $2.23 per kW-month for 1998, an

18.0 percent increase from the existing firm transmission rate of $1.89

per kW-month, which became effective October 1, 1992. This rate will be

charged to existing firm transmission customers and future firm point-

to-point transmission customers.

The change in the firm CRSP transmission service rate is due to

increases in the formula numerator. These increases are in transmission

facilities' costs and in assigning all transmission costs to all users.

Also, the computation of the denominator changed. Western is basing

the transmission system reserved for its existing long-term firm power

customers on its maximum annual firm obligations instead of generating

plant capacity to determine the portion of the denominator associated

with the transmission of firm power.

The provisional rate for nonfirm CRSP transmission service is

determined by the current market rate, not to exceed the current CRSP

firm point-to-point transmission rate. The provisional rate is

expressed in mills/kWh, and is a maximum of 3.0 mills/kWh for 1998.

The provisional rate for network integration transmission service

is a formula calculation. The CRSP CSC has not calculated a rate

because Western does not currently have any network integration

transmission service customers on its CRSP transmission system.

Ancillary Services

Six ancillary services will be offered by CRSP; two are required to

be purchased by the CRSP transmission customer. These two are (1)

scheduling, system control, and dispatch service, and (2) reactive

supply and voltage control service. The remaining four ancillary

services--regulation and frequency response service, energy imbalance

service, spinning reserve service, and supplemental reserve service--

will also be offered but are subject to availability from SLCA/IP

resources.

Sales of regulation and frequency response, energy imbalance,

spinning reserve, and supplemental reserve services from SLCA/IP power

resources are limited since Western has allocated the SLCA/IP power

resources to preference entities under long-term commitments. The

availability and type of ancillary service will be determined based on

excess resources available at the time the service is requested, except

for the two ancillary services provided in conjunction with the sale of

CRSP transmission services. If Western is unable to provide these

services through SLCA/IP resources, the CRSP CSC will offer to provide

these services by making market purchases or obtaining these services

through a control area operator and passing these costs directly to the

customer, including a 10 percent administrative charge.

The provisional rates for ancillary services are designed to

recover only the costs associated with providing the service(s). The

costs for providing scheduling, system control, and dispatch service,

and reactive supply and voltage control service are included in the

appropriate provisional transmission services rates. However, the

charges for reactive supply and voltage control service will be in

accordance with Western's DSWR and RMR applicable tariffs when they

assume control area operator responsibility for the CRSP, expected to

be April 1, 1998.

Existing and Provisional Rates

A comparison of the existing and provisional firm power and

transmission rates follows:

Comparison of Existing and Provisional Salt Lake City Area/lntegrated Projects Firm Power, Colorado River

Storage Project Transmission and Ancillary Services

----------------------------------------------------------------------------------------------------------------

Existing rates Provisional rates (effective 4/1/98)

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Firm Power Service Rate Schedule SLIP-F5................... SLIP-F6.

(existing rate effective 12/94).

Firm Capacity Charge ($/kW/month)....... $3.83..................... $3.44.

Firm Energy Charge (mills/kWh).......... 8.90...................... 8.10.

Composite Rate (mills/kWh).............. 20.17..................... 17.57.

Firm Point-to-Point Transmission Rate SP-FT4.................... SP-PTP5.

Schedule (existing rate effective 10/

92).

Firm Transmission Rate ($/kW-month)..... $1.89..................... $2.23 for 1998.

Network Transmission.................... N/A....................... SP-NW1.

Nonfirm Transmission Rate Schedule SP-NNFT3.................. SP-NFT4.

(existing rate effective 8/89).

Nonfirm Transmission Rate............... Negotiated................ Same, but not to exceed the firm rate.

Ancillary Services...................... N/A....................... SP-SD1, SP-RS1, SP-EI1, SP-FR1, SP-SSR1.

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[[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