Loveland Area ProjectsRate Order No. WAPA-80

DEPARTMENT OF ENERGY

Western Area Power Administration

Loveland Area Projects--Rate Order No. WAPA-80

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-80

and Rate Schedules L-NT1, L-FPT1, N-FPT1, L-AS1, L-AS2, L-AS3, L-AS4,

L-AS5, and L-AS6, placing formula rates into effect on an interim basis

for firm and non-firm transmission on the Western Area Power

Administration Loveland Area Projects (LAP) transmission system and for

ancillary services for the Western Area Colorado Missouri control area

(WACM). These schedules supersede Rate Schedules LT-3 and LT-4.

The charges for network and point-to-point transmission service and

energy imbalance service will be implemented in three steps, between

April 1, 1998, and October 1, 1999. The charges for the other five

ancillary services will be implemented in the first step. Each step and

subsequent annual recalculation will be based on updated financial data

and loads. Network transmission service charges will be based on the

Transmission Customer's load-ratio share of the annual revenue

requirement for transmission. Point-to-point transmission service will

be based on monthly reserved capacity on the transmission system. The

charges for ancillary services will be based on the costs of the WACM.

FOR FURTHER INFORMATION CONTACT: Mr. Daniel T. Payton, Rates Manager,

Rocky Mountain Customer Service Region, Western Area Power

Administration, P.O. Box 3700, Loveland, CO 80539-3003, (970) 490-7442,

or e-mail ([email protected]).

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 non-exclusive 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).

Rate Order No. WAPA-80, confirming, approving, and placing the LAP

network, firm point-to-point, and non-firm point-to-point transmission,

and the new ancillary services formula rates into effect on an interim

basis, is issued. Rate Order No. WAPA-80 was prepared pursuant to

Delegation Order No. 0204-108, existing DOE procedures for public

participation in power rate adjustments in 10 CFR Part 903, and

procedures for approving Power Marketing Administration rates by FERC

in 18 CFR 300. The new Rate Schedules L-NT1, L-FPT1, L-NFPT1, L-AS1, L-

AS2, L-AS3, L-AS4, L-AS5, and L-AS6 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

Adjustment for Loveland Area Projects Transmission and Ancillary

Services

April 1, 1998.

Order Confirming, Approving, and Placing the Loveland Area Projects

Transmission and Ancillary Service Formula Rates Into Effect on an

Interim Basis

These transmission and ancillary service formula rates are

established pursuant to Section 302 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) 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 non-

exclusive 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 (FERC).

Existing DOE procedures for public participation in power rate

adjustments are found in 10 CFR Part 903. Procedures for approving

Power Marketing Administration rates by FERC are found in 18 CFR Part

300.

Acronyms/Terms and Definitions

As used in this rate order, the following acronyms/terms and

definitions apply:

Acronym/Term Definition

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

per month).

12 cp: Rolling 12-month coincident peak average.

A&GE: Administrative and general expense.

C&RE: Conservation and Renewable Energy.

CME: Capitalized movable equipment.

CRSP: Colorado River Storage Project.

Customer Brochure: ``Loveland Area Projects Customer Brochure:

Proposed Rates for Transmission and Ancillary Services'' prepared in

September 1997 by the Rocky Mountain Customer

[[Page 16779]]

Service Region for public distribution explaining the background and

purpose of this rate adjustment proposal.

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.

Federal Customers: Loveland Area Projects (LAP) customers taking

delivery of long-term firm service under Firm Electric Service

Contracts, and Project Use Power Customers.

FERC: Federal Energy Regulatory Commission.

FERC Order No. 888: FERC Order Nos. 888, 888-A, 888-B, and 888-C

unless otherwise noted.

Firm Electric Service Contract: Contracts for the sale of long-term

firm LAP Federal energy and capacity, pursuant to the Post-1989 General

Power Marketing and Allocation Criteria (Marketing Plan).

FY: Fiscal Year.

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 the maximum of kW

taken during 1 month.

LAP: Loveland Area Projects.

LAP Transmission System Total Load: Average 12-cp monthly system

peak for network transmission service, average 12-cp monthly

entitlements of Federal Customers, and reserved capacity for all firm

point-to-point transmission service.

Load ratio share: Network Transmission Customer's hourly load

(including its designated network load not physically interconnected

with Western) coincident with Western's monthly transmission system

peak.

Long-term firm point-to-point transmission service: Annual firm

point-to-point transmission service reservation with 12 consecutive

equal monthly amounts.

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.

Monthly entitlements: Maximum capacity to be delivered each month

under Firm Electric Service Contracts. Each monthly entitlement is a

percentage of the seasonal contract-rate-of-delivery, based on 90-

percent hydrologic probability established in the Marketing Plan.

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

NEPA: National Environmental Policy Act of 1969.

NPPD: Nebraska Public Power District.

O&M: Operation and maintenance.

P-SMBP: Pick-Sloan Missouri Basin Program.

P-SMBP-WD: Pick-Sloan Missouri Basin Program-Western Division.

PMOC: Power Marketing and Operations Complex.

Post-1989 General Power Marketing and Allocation Criteria: Criteria

for the sale of energy with capacity from the P-SMBP-WD and the

Fryingpan-Arkansas Project by Criteria: the RMR.

Provisional Rate Schedule: Rate schedule approved on an interim

basis by the Deputy Secretary of the DOE.

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

Interior.

RMR: The Rocky Mountain Customer Service Region; Western's office

in Loveland, Colorado.

Service agreement: The initial agreement and any amendments or

supplements thereto entered into by the Transmission Customer and

Western for service under the Tariff.

SEPA: Southeastern Power Administration.

Short-term firm point-to-point transmission service: Firm point-to-

point transmission service with service of less duration than 12

consecutive monthly service amounts.

Supporting documentation: Work papers which support the rate

proposal.

Tariff: Western Area Power Administration, Open Access Transmission

Service Tariff, Docket No. NJ-98-1-000.

Transmission Customer: The RMR customer taking network or point-to-

point transmission service.

WACM: Western Area Colorado Missouri control area.

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

Energy.

Effective Date

The provisional formula 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 be in effect pending FERC's approval of

them or substitute formula rates on a final basis through March 31,

2003, or until superseded. These formula rates will be applied under

existing transmission contracts and Western's Open Access Transmission

Service Tariff (Tariff) and conform with the spirit and intent of the

FERC Order No. 888. The Rocky Mountain Customer Service Region (RMR)

will replace Schedules 1 through 8 and Attachment H of Western's Tariff

with these rate schedules for service on the Loveland Area Projects

(LAP) system.

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 formula rates and schedules. The

provisional firm transmission rate represents an increase of more than

1 percent in total LAP transmission revenues; therefore, it is a major

rate adjustment as defined at 10 CFR 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. During the spring of 1997, RMR representatives met informally

with individual LAP customers to explain the need for a rate

adjustment.

2. RMR published a Federal Register notice on September 19, 1997

(62 FR 49218), officially announcing the proposed 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.

3. On September 25, 1997, RMR mailed a copy of the ``Loveland Area

Projects Customer Brochure: Proposed Rates for Transmission and

Ancillary Services'' to all LAP Transmission Customers and other

interested parties.

4. RMR held a public information forum on October 23, 1997, in

Denver, Colorado. Western representatives explained the need for the

rate adjustment in greater detail and answered questions.

5. RMR held a comment forum on November 18, 1997, in Denver,

Colorado, to provide the public an opportunity to comment for the

record. Four individuals commented at this forum.

6. Seven commentors submitted letters during the 90-day

consultation and comment period. The consultation and comment period

ended on December 18, 1997. All comments have been considered in the

preparation of this Rate Order.

Comments

Representatives of the following organizations made oral comments:

Platte River Power Authority, Colorado, on behalf of Loveland Area

Customer Association

Colorado Springs Utilities (CSU), Colorado

[[Page 16780]]

Kansas Electric Power Cooperative, Inc., Kansas

New Century Energies, Texas, on behalf of Public Service Company of

Colorado, Colorado, and Cheyenne Light, Fuel and Power Company, Wyoming

The following organizations submitted written comments:

Arkansas River Power Authority, Colorado

Colorado Springs Utilities, Colorado

Loveland Area Customer Association, Colorado

Nebraska Public Power District (NPPD), Nebraska

Platte River Power Authority, Colorado

New Century Energies, Texas

Tri-State Generation and Transmission Association, Inc. (Tri-State),

Colorado

Project Description

RMR offers transmission service on LAP transmission facilities,

which include transmission lines, substations, communication equipment,

and related facilities. LAP is comprised of two power projects: the

Pick-Sloan Missouri Basin Program-Western Division (P-SMBP-WD) and the

Fryingpan-Arkansas Project (Fryingpan-Arkansas). The two projects were

integrated for operational and marketing purposes in 1989. LAP serves

Federal and Transmission Customers in a four-state area, over a

transmission system of approximately 3,485 miles (5,607 circuit

kilometers) and 80 substations.

Western will offer ancillary services from the Western Area

Colorado Missouri control area (WACM) resources, which represent a

combination of some Colorado River Storage Project (CRSP) generation

resources and all of the LAP generation resources.

P-SMBP-WD

The initial stages of the Missouri River Basin Project were

authorized by Section 9 of the Flood Control Act of 1944 (58 Stat. 887,

891, Pub. L. 534, 78th Congress, 2nd session). It was later renamed the

Pick-Sloan Missouri Basin Program (P-SMBP). The P-SMBP encompasses a

comprehensive program, with the following authorized functions: flood

control, navigation improvement, irrigation, municipal and industrial

water development, and hydroelectric production for the entire Missouri

River Basin. Multipurpose projects have been developed on the Missouri

River and its tributaries in Colorado, Montana, Nebraska, North Dakota,

South Dakota, and Wyoming.

The Colorado-Big Thompson, Kendrick, Riverton, and Shoshone

Projects were administratively combined with P-SMBP in 1954, followed

by the North Platte Project in 1959. These projects are known as the

``Integrated Projects'' of the P-SMBP. The Riverton Project was

reauthorized as a unit of the P-SMBP in 1970.

The P-SMBP-WD and the Integrated Projects include 19 powerplants.

There are six powerplants in the P-SMBP-WD: Glendo, Kortes, and Fremont

Canyon Powerplants on the North Platte River; Boysen and Pilot Butte on

the Wind River; and Yellowtail Powerplant on the Big Horn River.

In the Colorado-Big Thompson there are also six powerplants. The

Green Mountain Powerplant on the Blue River is on the West Slope of the

Rocky Mountains. The five remaining powerplants are on the East Slope

of the Continental Divide: Marys Lake, Estes, Pole Hill, Flatiron, and

Big Thompson.

The Kendrick Project has two power production facilities: Alcova

and Seminoe Powerplants. Power production facilities in the Shoshone

Project are Shoshone, Buffalo Bill, Heart Mountain, and Spirit Mountain

Powerplants. The only production facility in the North Platte Project

is the Guernsey Powerplant.

Fryingpan-Arkansas Project

The Fryingpan-Arkansas is a transmountain diversion project in

central and southeastern Colorado, which was authorized by the Act of

August 16, 1962 (Pub. L. 87-590, 76 Stat. 389, as amended by Title XI

of the Act of October 27, 1974, Pub. L. 93-493, 88 Stat. 1487, 1497).

The Fryingpan-Arkansas diverts water from the Fryingpan River and other

tributaries of the Roaring Fork River to the Arkansas River on the East

Slope of the Continental Divide. The Fryingpan and Roaring Fork Rivers

are part of the Colorado River Basin on the West Slope of the Rocky

Mountains. The water diverted from the West Slope, together with

regulated Arkansas River water, provides supplemental irrigation,

municipal and industrial water supplies, and hydroelectric power

production. Flood control, fish and wildlife enhancement, and

recreation are other important purposes of the Fryingpan-Arkansas. The

only generating facility in the Fryingpan-Arkansas Project is the Mt.

Elbert Pumped-Storage Powerplant on the East Slope of the Rocky

Mountains.

Colorado-River Storage Project

The CRSP was authorized by the Colorado River Storage Project Act,

ch. 203, 70 Stat. 105, on April 11, 1956. The CRSP provides for the

comprehensive development of the Upper Colorado River Basin (Upper

Basin). It furnishes the long-term regulatory storage needed to allow

states in the Upper Basin (Colorado, New Mexico, Utah, and Wyoming) to

meet their water delivery obligations to the states of the Lower Basin

(Arizona, California, and Nevada) and still use the water apportioned

to them by the Colorado River Compact of 1922. The part of the CRSP in

WACM is the territory north of Shiprock, New Mexico. The CRSP

hydroelectric facilities providing ancillary services for WACM are

Aspinall (formerly Curecanti) and part of Glen Canyon. As of April 1,

1998, the southern portion of the CRSP will be operated by Western's

Desert Southwest Customer Service Region in Phoenix, Arizona.

LAP Transmission Service

RMR prepared a transmission service rate study based on cost of

service for the LAP transmission system. RMR is seeking approval of

formula rates for calculation of point-to-point transmission rates and

the network transmission service revenue requirement. These formulas

will be applied annually. Transmission service for delivery of LAP

long-term firm Federal power to Federal Customers will continue to be

bundled in their firm power rate under existing contracts which expire

in 2024. The transmission rates include the cost of Scheduling, System

Control, and Dispatch Service.

The existing LAP transmission rate of $1.88/kW-month, placed into

effect under Rate Schedule L-T3 in 1994, is no longer sufficient to

recover annual costs (including interest expense) and capital

requirements. Although the cost basis for the transmission rates has

changed since 1994, the primary reason for a rate adjustment is the

reassessment of the load data. A detailed review of load and meter data

has determined that the loads used in the 1994 analysis (1,957,882 kW)

were significantly in excess of actual system use (1,126,263 kW) and

were not billable under the terms of LAP contracts.

About 500 MW of the difference is over-projections of actual usage

of the transmission service. Approximately 200 MW is due to the use of

a non-coincident annual peak in the 1994 rate analysis, as opposed to

the use of the FERC-endorsed 12-consecutive peak (12-cp) method in the

provisional rates. About 100 MW for an existing contract that is billed

at a discounted rate was excluded from the present rate denominator and

included as a revenue credit. In combination, these factors result in

approximately 800 MW of reduced load on the LAP transmission

[[Page 16781]]

system, with a corresponding increase in transmission rates.

RMR will offer existing Transmission Customers the opportunity to

convert their existing contracts to service agreements under Western's

Tariff. The customer will designate network or point-to-point

transmission service and applicable ancillary services. The earliest

that an existing transmission contract can be converted under the

Tariff and the Provisional Rate Schedules is April 1, 1998.

For the formula rates, RMR assumed that all existing contracts that

are based on capacity or energy transmitted will take network

transmission service, and that customers which currently reserve

capacity for transmission service will take point-to-point transmission

service. If an existing Transmission Customer elects to retain its

transmission contract, transmission service will continue under the

terms of the existing contract, but under the Provisional Rate

Schedules (L-NT1, L-FPT1, and L-NFPT1 for transmission, and L-AS1, L-

AS2, L-AS3, L-AS4, L-AS5, and L-AS6 for ancillary services). These

Provisional Rate Schedules will supersede the rate schedules in the

existing contracts. If an existing Transmission Customer is billed on

an energy (rather than capacity) basis, the Provisional Rate Schedules

stipulate that the rate per capacity unit will be converted to a rate

per energy unit, based on the individual Transmission Customer's load

factor.

RMR recognizes the impact that the increase in cost for

transmission service from $1.88/kW-month to $3.19/kW-month may have on

its customers. RMR is proposing a three-step implementation plan for

the transmission rate adjustment in an attempt to mitigate these

impacts. The implementation dates and basis for the calculation for

each of the three steps are described below. The starting point for the

calculation is an estimate of the third-step rate, based on Fiscal Year

(FY) 1996 financial data and 1995 load data. In subsequent steps, the

third-step rate will be recalculated based on the formula rate and

updated financial and load data.

Step 1--April 1, 1998

The first-step point-to-point rate is the existing rate ($1.88/kW-

month) plus one-third of the difference between the existing rate and

the estimated third-step rate. The network transmission service revenue

requirement is the first-step point-to-point rate multiplied by the LAP

Transmission System Total Load.

Step 2--October 1, 1998

The second-step point-to-point rate will be the existing rate

($1.88/kW-month) plus two-thirds of the difference between the existing

rate and the recalculated third-step rate. The third-step rate will be

recalculated, following the formula rate, using FY 1997 financial and

load data.

Step 3--October 1, 1999

The third-step point-to-point transmission service rate and network

transmission service revenue requirement will be recalculated,

following the formula rates and FY 1998 financial and load data.

The rates will subsequently be recalculated every year, effective

October 1, based on the approved formula rates and updated financial

and load data. RMR will provide customer notice of changes in rates no

later than July 1 of each year.

Ancillary Services

RMR will offer the six ancillary services defined by FERC to all

customers. The six ancillary services are: (1) Scheduling, System

Control, and Dispatch Service; (2) Reactive Supply and Voltage Control

from Generation Sources Service (VAR Support); (3) Regulation and

Frequency Response Service (Regulation); (4) Energy Imbalance Service;

(5) Spinning Reserves; and (6) Supplemental Reserves. The ancillary

services formula rates are designed to recover only the costs incurred

for providing the service(s). The rates for ancillary services are

based on WACM control area costs, per FERC.

RMR will implement the Energy Imbalance Service bandwidths

simultaneously with the transmission service rates to allow for a

transition period, whereby, customers may improve their equipment and

revise their scheduling practices. The implementation schedule will be:

April 1, 1998--6 percent bandwidth

October 1, 1998--5 percent bandwidth

October 1, 1999--3 percent bandwidth

Comparison of Existing and Provisional Rates for Transmission and

Ancillary Services

The following is a comparison of existing rates, step-one rates,

and an estimate of the step-three rates under the provisional formula

rates and using FY 1996 data. Rates for step-two and three will be

recalculated based on updated financial and load data prior to

implementation. Subsequently, these rates will be updated annually

based on approved formula rates.

Comparison of Existing, Step-One, and Estimated Step-Three Rates

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

Rate schedule and

Class of service Existing rate schedule Rate schedule and step- estimated step-three

and rate one rates April 1, 1998 rates \1\

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

Firm Transmission.................... LT-3................... L-NT1 or L-FPT1, and L- L-NT1 or L-FPT1, and L-

AS1 thr. 6. AS1 thr. 6.

$1.88/kW-mo............ See applicable classes See applicable classes

below. \2\. below.\2\

Network Transmission................. N/A.................... L-NT1.................. L-NT1

Load ratio share of \1/ Load ratio share of \1/

12\ of the revenue 12\ of the revenue

requirement of requirement of

$31,555.162 \3\. $43,153,308 \3\

Firm Point-to-Point Transmission..... N/A.................... L-FPT1................. L-FPT1

$2.32/kW-mo \3\........ $3.19/kW-mo \3\

Non-firm Point-to-Point Transmission. LT-4................... L-NFPT1................ L-NFPT1

2.6 mills/kWh.......... Maximum of 3.33 mills/ To be calculated

kWh. October 1, 1999.

Scheduling, System Control, and N/A.................... L-AS1.................. L-AS1

Dispatch. $25.71 per schedule per To be calculated

day for non- October 1, 1999.

transmission customers.

Reactive Supply and Voltage Control N/A.................... L-AS2.................. L-AS2

from Generation Sources. $0.112/kW-mo........... To be calculated

October 1, 1999.

Regulation and Frequency Response.... N/A.................... L-AS3.................. L-AS3

$0.147/kW-mo........... To be calculated

October 1, 1999.

Energy Imbalance..................... N/A.................... L-AS4.................. L-AS4

[[Page 16782]]

For negative excursions For negative excursions

outside of 6% outside of 3%

bandwidth (2 MW bandwidth (2 MW

minimum) and occurring minimum) and occurring

more than 5 times per more than 5 times per

month, RMR reserves month, RMR reserves

the right to charge the right to charge

100 mills/kWh. 100 mills/kWh.

Positive excursions Positive excursions

outside the bandwidth outside the bandwidth

may be credited to the may be credited to the

customer within 30 customer within 30

days for 50 % of the days for 50 % of the

regional average regional average

monthly price for non- monthly price for non-

firm purchases.\4\. firm purchases.\4\

Spinning/Supplemental Reserves....... N/A.................... L-AS5 and 6............ L-AS5 and 6

Long-term Reserves are Long-term Reserves are

not available from not available from

WACM. WACM.

Reserves will be Reserves will be

provided on a pass- provided on a pass-

through cost. through cost.

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

\1\ To be recalculated October 1, 1999.

\2\ Rate Schedule stipulates that if an existing Transmission Customer is billed on an energy basis, the rate

per capacity unit will be converted to a rate per energy unit, based on individual customer's load factor.

\3\ If a Transmission Customer requires use of LAP subtransmission facilities for delivery of non-Federal

energy, a specific facility use charge will be assessed.

\4\ During times when over deliveries would impinge on WACM operations, RMR reserves the right to eliminate

credits.

Certification of Rates

Western's Acting Administrator has certified that the LAP

transmission and ancillary services rates placed into effect on an

interim basis herein are the lowest possible consistent with sound

business principles. The formula rates have been developed in

accordance with agency administrative policies and applicable laws.

LAP Transmission Service Discussion

The charges for network and point-to-point transmission service

will be implemented in three steps between April 1, 1998, and October

1, 1999. Each step will be recalculated based on the updated financial

data and loads. Network service charges will be based on the

Transmission Customer's load-ratio share of the annual revenue

requirement for transmission. Point-to-point service will be based on

reserved capacity on the transmission system.

Annual Transmission Revenue Requirement: The Annual Transmission

Revenue Requirement will be applicable to both network and point-to-

point transmission service.

The Annual Transmission Revenue Requirement is the Annual

Transmission Cost, adjusted for revenue credits and costs associated

with expenses which expand the capacity available for transmission. The

formula is:

[GRAPHIC] [TIFF OMITTED] TN06AP98.003

Following is an estimate of the third-step revenue requirement,

using FY 1996 data. This revenue requirement will be recalculated every

October.

$43,153,308 = $44,669,889 + $0-$837,908-$678,671

The Transmission Expenses Which Increase Transmission System

Capacity will include any future credits paid to Transmission Customers

from augmentation of the system. The credits will be addressed in the

individual service agreements, and appropriate adjustments will be made

in subsequent rate calculations. Western will evaluate these requests

in accordance with guidance in FERC Order No. 888-A, Section IV.G.1.g:

``* * * for a customer to be eligible for a credit, its facilities must

not only be integrated with the transmission provider's system, but

must also provide additional benefits to the transmission grid in terms

of capability and reliability, and be relied upon for the coordinated

operation of the grid.''

Miscellaneous Revenue Credits may include, but will not be limited

to non-firm, discounted firm, and short-term firm transmission sales;

Scheduling, System Control, and Dispatch Service; or facility charges

for transmission facility investments included in the revenue

requirement. The non-firm point-to-point transmission service credit is

estimated to be $788,064, based on the non-firm transmission sales made

on the LAP transmission system during the time period of July 1996 to

June 1997. Credits for scheduling service are estimated to be $19,540.

Credits for facility charges are $30,304.

The Revenue Credit For Existing Transmission Contracts includes the

transmission revenue received from PacifiCorp under Contract No. 14-06-

400-2437. The loads served under this contract were excluded from the

total system load. This contract is a 1-mill reciprocal agreement that

requires a 3-year notification for cancellation. Western gave the

required 3-year notice to PacifiCorp in May 1997. This revenue credit

shall be included in the revenue requirement calculation until such

time as the contract terminates. At that time, the loads will be added

to the LAP Transmission System Total Load for rate determination.

[[Page 16783]]

The Annual Transmission Cost is the product of the Annual Fixed

Charge Rate and the Net Investment Cost for Transmission Facilities.

The formula is:

Annual Transmission Cost = Annual Fixed Charge Rate x Net Investment

Cost for Transmission Facilities

This formula applied to FY 1996 data is:

$44,669,889 = 19.194%* x $232,731,025

*Actual percentage carried out to five decimal places.

The Net Investment Cost for Transmission Facilities was determined

by an analysis of the LAP transmission system. Each LAP facility was

identified by function: transmission, subtransmission, distribution, or

generation-related. Only the investment costs of the facilities

identified as ``transmission'' were used in developing the proposed

transmission rates. The investment costs of facilities identified as

``subtransmission'' and ``distribution'' were allocated to LAP Federal

Customers. The LAP subtransmission system is used primarily for

delivery of Federal power to Federal Customers. If a Transmission

Customer requires the use of the subtransmission system, an additional

facility-use charge will be assessed. All costs of Fryingpan-Arkansas

were considered generation-related; and therefore, included with other

generated-related cost in the revenue requirement for ancillary

services.

The facilities identified as performing the function of

transmission include all transmission lines that are normally operated

in a continuously-looped manner and the associated substations and

switchyard facilities. In the LAP transmission system, these are

primarily the 115-kV and 230-kV transmission lines. In addition, a

portion of the communication and maintenance facilities was included in

the investment costs for transmission. The total investment cost for

transmission facilities, as of September 30, 1996, is $304,913,006. The

allowance for depreciation on these facilities is $72,181,981, yielding

a net investment cost of $232,731,025.

The Annual Fixed Charge Rate includes operation and maintenance

(O&M) expenses, administrative and general expenses (A&GE),

depreciation expenses, and interest expenses. The formula is:

[GRAPHIC] [TIFF OMITTED] TN06AP98.004

This formula applied to FY 1996 data is:

19.194% = 6.003% + 1.647% + 3.084% + 8.460%

The source for the annual O&M, A&GE, depreciation, and interest

expenses is the Results of Operations for the Rocky Mountain Customer

Service Region--Pick-Sloan Missouri Basin. The source for the unpaid

balance is the amount reported in the Historical Financial Document in

Support of the Power Repayment Study for the Pick-Sloan Missouri Basin

Program.

Transmission System Load: The LAP Transmission System Total Load is

the average 12-cp monthly system peak for network transmission service,

the 12-cp monthly entitlements for Federal Customers, and the reserved

capacity for all firm point-to-point transmission service.

The LAP Transmission System Total Load is calculated as follows,

based upon 1995 data and known and measurable charges:

[GRAPHIC] [TIFF OMITTED] TN06AP98.005

This load was derived as follows:

Obtained hourly individual revenue meter readings for

delivery points on the LAP transmission system. This included all

delivery points in the Firm Electric Service Contracts for Federal

power, auxiliary power from a non-Federal source, project use and

special customers, and third-party wheeling delivery points.

Subtracted the meter readings for point-to-point

Transmission Customers to determine the network transmission service

load.

Added the reserved capacity for point-to-point

Transmission Customers to determine the LAP Transmission System Total

Load.

Network Transmission Service: The monthly charge for network

transmission service is the product of the Transmission Customer's

load-ratio share times one-twelfth of the Annual Transmission Revenue

Requirement. The customer's load-ratio share is the ratio of its

network transmission load to the LAP Transmission System Total Load,

which will be calculated on a rolling 12-cp basis.

The customer's network load will be derived as follows:

Identify the LAP transmission system peak hour for each

month.

Calculate the total delivery to each individual Network

Transmission Customer for the 12 monthly peak hours.

Identify the part of the total delivery associated with

each customer's monthly LAP monthly entitlement.

Identify the network delivery during each of the 12

monthly peaks (total delivery minus monthly entitlement for delivery of

Federal power).

Sum the 12 monthly peaks and divide by 12 months to derive

the 12 cp for each Network Transmission Customer.

Firm Point-to-Point Transmission Service: The proposed rate for

firm point-to-point transmission service is the Annual Transmission

Revenue Requirement, divided by the LAP Transmission System Total Load.

Firm

[[Page 16784]]

point-to-point transmission service is available for a period of 1 day

or longer.

The formula for the proposed rate is as follows:

[GRAPHIC] [TIFF OMITTED] TN06AP98.006

Following is an estimate of the third-step rate, using FY 1996

data. This rate will be recalculated every October.

[GRAPHIC] [TIFF OMITTED] TN06AP98.007

Non-Firm Point-to-Point Transmission Service: Non-firm transmission

service is available for periods ranging from 1 hour to 1 month. The

rate for non-firm transmission service may be discounted based on

market conditions, but will never be higher than the firm point-to-

point transmission rate, converted to an energy equivalent at 100

percent load factor. The formula for the non-firm transmission service

rate is:

[GRAPHIC] [TIFF OMITTED] TN06AP98.008

Based on the Firm Point-to-Point Transmission Rate, an estimate of

the maximum Non-Firm Point-to-Point Transmission Rate for the third

step is:

Monthly delivery: $3.19/kW of reserved capacity per month

Weekly delivery: $0.74/kW of reserved capacity per week

Daily delivery: $0.11/kW of reserved capacity per day

Hourly delivery: 4.58 mills/kWh

Transmission Service Comments

The following comments were received during the public comment

period. RMR paraphrased and combined comments when it did not affect

the meaning. RMR's response follows each comment. Changes were made in

the formula rates and calculations as a result of the comments noted.

Comment: In order to avoid any confusion, Western may wish to

clarify that when using the term ``existing contracts'' it is referring

solely to transmission contracts and is not suggesting that the

unbundling provision of FERC Order No. 888 is applicable to the

statutory obligations of Western.

Response: RMR agrees and has made this change in the Rate Order to

avoid confusion.

Comment: One commentor is concerned that RMR has designed a single

transmission service rate to apply to existing agreements which have

drastically varying billing parameters. Historically, this practice of

billing non-standard agreements under a single rate schedule has

resulted in each Transmission Customer effectively paying a different

charge per kW of annual transmission capacity reserved, with the

customers being billed on annual reserved capacity paying the highest

charge. On pages 10-11 of the Customer Brochure, RMR proposes to

continue this inequitable treatment by billing these existing

agreements and any new service provided under Western's Tariff under

the same proposed rate schedule. In order to avoid under-recovery of

revenue requirements, RMR has essentially allocated cost responsibility

to each of its existing transmission arrangements on the basis of the

disparate billing parameters specified in these agreements and ignored

the annual transmission capacity reserved under these arrangements.

This approach is inequitable and inconsistent with the intent of FERC

Order No. 888 and causes Transmission Customers billed on annual

reserved capacity to subsidize other customers on the LAP system. One

of the fundamental principles established in FERC Order No. 888 is that

all Transmission Customers should pay, on a comparable basis, for the

full amount of the transmission capacity they reserve and/or use.

Response: RMR agrees with the commentor that the existing LAP

transmission rate applied to the existing transmission agreements has

resulted in Transmission Customers effectively paying different charges

per kW of annual transmission capacity reserved and/or used. RMR also

recognizes that because the existing LAP transmission rate was based on

a projected denominator, the existing LAP rate results in Federal

Customers paying about $6.9 million annually more than their comparable

share of the LAP transmission costs due to unbillable projections.

RMR will correct this disparity in charging. RMR developed the

formula rates under the assumption that all existing Transmission

Customers will switch to service agreements under Western's Tariff.

These service agreements will eliminate the disparity that currently

exists.

RMR has also taken steps to eliminate the disparity even if some

Transmission Customers elect to retain their existing contracts. With

the exception of Contract No. 14-60-400-2437 with PacifiCorp, LAP

transmission rate adjustments are implemented by changing the rate

schedules which are attached to the contracts. As stated on pages 10-11

of the Customer Brochure, if an existing customer elects to retain its

existing transmission contract, transmission service will continue

under the conditions of the existing contract, but under the

Provisional Rate Schedules. The Provisional Rate Schedules stipulate

that if an existing Transmission Customer is billed on an energy

(rather than capacity) basis, the rate per capacity unit will be

converted to a rate per energy unit, based on the

[[Page 16785]]

individual Transmission Customer's load factor. This stipulation and

the use of 12 cp for both network and point-to-point transmission

service will result in all customers (billed on capacity usage, energy

usage, or reserved capacity) paying the same rate per capacity unit.

To avoid over/under recovery, RMR has developed the rate

denominator (load) based on the same amount as the projected billing

determinant, assuming all customers switch to service agreements. If

necessary, the rate denominator will be adjusted for Step Two of the

rate adjustment to reflect the appropriate load for any Transmission

Customer that does not switch to a service agreement; e.g., if a

customer elects to retain its existing contract and is, therefore,

billed on non-coincidental peak capacity, or on an energy basis, the

appropriate billing determinant will be substituted in the rate

denominator. Therefore, Step One will also serve as a transition period

to align all customers on a comparable basis, with no risk of over

collecting.

During Step One and Step Two of the transition period, Transmission

Customers will actually be paying less than their full share of

transmission, with the Federal Customers making up the difference. By

the end of the Step Three, equitability between Federal Customers and

Transmission Customers will be achieved.

Comment: Several commentors support RMR's intent to continue to

provide bundled transmission service in the firm electric service rate.

One commentor states, ``The Flood Control Construction Act of 1944,

which authorized the Missouri River Basin Project, required that the

rate schedules be calculated with `regard to the recovery * * * of the

costs of producing and transmitting' the electric energy generated by

the hydro powerplants authorized. This is a statutory prescription of

bundled service.''

Response: LAP firm power rates were last adjusted in 1994,

following the public process as described in 10 CFR 903. These rates

were developed, consistent with the Post-1989 General Power Marketing

Plan and Allocation Criteria (Marketing Plan), which established the

capacity and energy available to market under Firm Electric Service

Contracts. The Firm Electric Service Contracts expire in 2024.

Transmission will remain bundled in RMR's firm power rate and

contracts. RMR's intent to continue to provide this service as a

bundled product is consistent with FERC Order No. 888, Section

IV.G.2.(a) which does not require that transmission service for bundled

native load be taken under the FERC Pro Forma.

Comment: RMR has improperly designated existing transmission

arrangements as network transmission service. RMR assumes that the

existing bundled transmission service, included with firm preference

power sales, and the existing firm transmission service, provided to

certain Preference Power Customers for delivery of auxiliary power

supplies in addition to RMR's scheduled sale, qualifies for rate

treatment as network transmission service loads. Such rate treatment is

improper because:

(1) These existing, partial requirements transmission arrangements

do not meet the FERC's definition of, or requirements for, network

loads, as discussed in FERC Order No. 888-A and the FERC Pro Forma, and

(2) Such treatment ignores the existing contractual arrangements

that reserve a specific, and in most cases, a limited amount of

transmission capacity for these deliveries.

The commentor states that the full requirements transmission

deliveries associated with LAP project and special use sales are the

only existing transmission service deliveries on LAP transmission

system which currently qualify as network loads. LAP preference power

sales are prescheduled deliveries with contractual limits that, by

design, are intended to serve only a portion of the customer's load

requirements.

The commentor quotes the definition of network load in the FERC Pro

Forma, Section 1.22, and quotes Section IV.G.1.c.(3) and (4) of FERC

Order No. 888-A in support of its position. To avoid duplicating the

transmission charges, the commentor recommends RMR follow the

guidelines in Section IV.G.1.c.(4).

Response: RMR has properly designated existing transmission

arrangements as network transmission service. The definition of network

load in the FERC Pro Forma, Section 1.22, states, ``A Network Customer

may elect to designate less than its total load as network load but may

not designate only part of the load at a discrete point of delivery.''

The Marketing Plan and the existing Firm Electric Service Contracts

(implementing Western's statutory obligations to market Federal power)

establish RMR's contractual rights for delivery of Federal long-term

firm capacity and energy to electric service and project-use customers.

RMR is the Transmission Customer for delivery of all long-term firm

electric service.

RMR, as a Transmission Customer, has designated its entire load at

the points of delivery in the Firm Electric Service Contracts as

network-type service. The remaining load at each discrete point of

delivery is served under a separate transmission service agreement. It

is anticipated that each Transmission Customer will take service for

its entire load at each discrete point of delivery in a Network

Integration Service Agreement. The entire load at each discrete point

will be served by network-type service.

RMR is following an alternative offered in FERC Order No. 888-A,

Section IV.G.1.c.(4), to avoid double payments for transmission

service. This Section states, ``The Network Customer then has two

options: pursue negotiations with the transmission provider to obtain a

credit on its network service bill for any separate transmission

arrangements . . . in recognition of the network transmission now being

provided and paid for under the tariff.''

Federal Customers will continue to pay a bundled firm power rate

under their Firm Electric Service Contract. A Network Transmission

Customer's network service bill will include a credit for the load

designated by RMR as Firm Electric Service, and the customer will only

pay network transmission service for the remainder of its loads,

thereby, eliminating any duplicate charge.

Without this arrangement, LAP Transmission Customers would be

precluded from receiving network transmission service, which would not

allow them the comparable use of the system that RMR and others enjoy.

FERC approved a similar crediting arrangement in a ruling on a Duke

Power Company (Duke) Case, Docket No. ER 97-2398-000, 81 FERC 61010. In

this case, FERC ruled that a portion of the customers' load could be

met by the Southeastern Power Administration (SEPA) allocation (which

is a network transmission service) and a portion could be served under

Duke's bundled service, which is of a network nature. The entire load

would be served on a network basis. Payment would be made to Duke by

SEPA for the SEPA Preference Customers' allocation and by the

Preference Customers for the remainder of their loads. Without such

arrangements, all Preference Customers of Federal power marketing

administrations would be precluded from receiving network transmission

service for their auxiliary supply.

Comment: In support of the above comment, the commentor states that

most of the existing auxiliary

[[Page 16786]]

transmission agreements include provisions that require RMR to make a

4-year commitment to reserve a specific amount of transmission

capacity.

Response: The commentor has misinterpreted RMR's auxiliary

transmission contracts. RMR's existing network-type Transmission

Customers pay only for the transmission service used, not for a firm

reservation, as implied by the commentor. RMR's existing network-type

transmission contracts include estimates of the amount of transmission

capacity required by the customer for service over and above the

capacity provided under the Firm Electric Service Contracts. This

estimate is similar to the 10-year forecast required in the Application

for Network Integration Service, which is updated annually by the

Network Transmission Customer for use in transmission planning. Also,

RMR retains the right to resell any capacity not used by the Network

Transmission Customer.

Comment: RMR's proposed capacity obligation is drastically

understated. The commentor gives eight reasons for this statement. Each

reason is addressed separately below:

Reason 1: It was the commentor's understanding that the LAP

hydrogeneration resources are required, by statute, to generate at

their full capacity and make every effort to avoid letting water from

the reservoir bypass the generators during high water/heavy runoff

conditions. RMR is then obligated to sell this excess generation

output. If this understanding is accurate, then RMR should include the

full output capacity of these resources as a firm reservation on the

LAP transmission system, as it did in the March 1993 transmission rate

study to insure that transmission capacity is available to accommodate

such required generation.

Response: The commentor's understanding is inaccurate. RMR is not

required to generate at full capacity. The full operating capacity of

the hydrogenerators is not a valid indicator of RMR's use of the LAP

transmission system. The maximum transmission capacity available to RMR

for delivery of firm electric service is the total capacity under

contract in the Firm Electric Service Contracts.

If high hydro conditions do occur, and the water cannot be stored

in the reservoirs, RMR offers available seasonal energy first to

existing Federal Customers to increase the load factor associated with

their contract rate of delivery, per Section V.D.2.b. of the Marketing

Plan. Any surpluses not marketed to Federal Customers will be marketed

by a Western merchant function and will require point-to-point

transmission under Western's Tariff. These non-firm sales on the

transmission system are reflected as a revenue credit to the firm

transmission revenue requirement; thereby, reducing the obligation of

the other users of the system.

RMR did not use the full output capacity of its hydro resources in

its 1993 transmission rate study. RMR used the P-SMBP-WD operating

plant capacity at the 90-percent hydrologic probability of exceedance

of 761,500 kW, which was established in the Marketing Plan. The 761,500

kW includes reserves and required maintenance which are not included in

the marketable capacity.

The rate denominator should only include the amounts that are

marketed and hence can be billed. Therefore, RMR included only the

monthly capacities marketed under the Firm Electric Service Contracts

in the rate denominator for the formula rates. These marketed

capacities are the monthly capacity entitlements. It is assumed that

these capacity entitlements are always used for peak monthly deliveries

of firm Federal power.

Reason 2: RMR does not recognize a separate transmission obligation

for the Town of Julesburg, Colorado, which established its own

arrangements for firm, auxiliary transmission service with RMR under

Contract No. 96-RMR-914, dated November 15, 1996.

Response: RMR agrees and has corrected the denominator to account

for network transmission service to the Town of Julesburg of 1,272 kW

(12 cp).

Reason 3: RMR did not recognize the October 2, 1997, revision to

Exhibit B of Contract No. 88-LAO-376 with Public Service Company of

Colorado (PSCo).

Response: This Exhibit B revision was made after the publication of

the Customer Brochure in September 1997. RMR has subsequently changed

the denominator (from 180,320 to 195,638 kW) to account for the FY 1998

reserved capacity for PSCo.

Reason 4: Several of the auxiliary transmission service agreements

provide for the transmission of pumped-storage return energy, but it is

not clear whether such off-peak, point-to-point transmission service is

provided on a firm or non-firm basis. To the extent that such service

is non-firm and the sum of the customer's firm and non-firm service

deliveries never exceed the customer's firm capacity reservation, it is

appropriate for RMR to provide such non-firm service without an

additional charge or reservation.

Response: This network-type service is for serving network load,

specifically the return of pumped-storage energy, from network

resources. The transmission of pumped-storage return energy is always

off-peak and, hence, does not add to the customer's usage on the system

monthly peak.

Reason 5: RMR and PacifiCorp have a reciprocal obligation, under

Contract No. 14-06-400-2437, to provide firm transmission service for

each other at a discounted rate of 1 mill per kWh delivered. The

agreement provides for a 3-year notice to terminate these arrangements,

but Western did not provide such notice to PacifiCorp until May 1997.

Instead of including this PacifiCorp transmission reservation (152,750

kW) in the LAP capacity obligation calculation, RMR proposes to include

the test period discounted transmission revenue from this agreement as

a credit to the LAP transmission revenue requirement. Under this

reciprocal arrangement, Western and PacifiCorp provide discounted firm

transmission service for each other that exclusively benefits the

generation/power merchant functions within these organizations. Long-

term, firm Transmission Customers of the LAP system are not offered

similar discounted rates. Western has received less than full

transmission compensation from PacifiCorp in exchange for wheeling

arrangements on the PacifiCorp system which benefits Western's

generation marketing efforts.

Response: This is an existing contract, which the Federal

Government arranged in good faith over 20 years ago at a regionally

standard rate of 1 mill/kWh. This contract did not include a provision

for adjusting the rate schedule. Over the years, PacifiCorp's use of

the RMR system has increased, and RMR's use of PacifiCorp's system has

remained relatively constant.

The commentor has contended that RMR has benefited from the

reciprocal arrangement. However, the loss of revenue to RMR has far

outweighed the benefit to RMR under this contract. This contract does

not exclusively benefit RMR's generation/merchant function. In 1998,

PacifiCorp will provide only 12,500 kW of transmission capacity for

RMR, and RMR will provide 164,500 kW of transmission capacity for

PacifiCorp. RMR receives a benefit of about $230,000 per year (if RMR

were to pay PacifiCorp's wheeling rate of $24.30/kW/year in place of

the 1 mill/kWh). RMR is annually foregoing over $3.0 million, assuming

PacifiCorp takes network transmission service. Therefore, RMR included

a revenue credit in the rate design, to reflect

[[Page 16787]]

transmission payment from PacifiCorp at a rate less than the embedded

costs and excluded the loads from the denominator.

Consistent with RMR's effort to align all Transmission Customers on

a comparable basis, Western has given PacifiCorp the required advance

notice that this contract will be terminated in May 2000. PacifiCorp

will then be required to pay the transmission rate based on embedded

costs, and the loads will be added to the denominator.

Reason 6: RMR included the summer and winter monthly reservations

for NPPD under Contract No. 87-LAO-200. RMR's proposed rate treatment

of this transmission obligation has the effect of discriminating

against Transmission Customers that purchase long-term, firm point-to-

point transmission service on the basis of an annual capacity

reservation and whose load patterns could be exactly like that of NPPD.

Response: It appears the commentor assumed that the NPPD contract

is a long-term point-to-point contract. RMR recognizes that long-term

point-to-point service is for 12 equal monthly reservations; however,

NPPD has an existing contract for a seasonal reservation, and RMR must

honor it for the remainder of its term. Future service agreements for

unequal monthly reservations (like the service provided to NPPD) will

be considered short-term point-to-point. Revenue from future short-term

point-to-point service agreements will be treated as a revenue credit,

and the load will be excluded from the denominator; thereby, not

affecting long-term Transmission Customers.

It is anticipated that NPPD will retain its existing transmission

contract; therefore, the monthly reservations for which it will pay the

point-to-point rate were included in the rate denominator. Thereby, the

rate design is consistent with the billing amounts in the contract and

no over/under recovery will occur.

Reason 7: RMR has understated the total capacity reservation for

Municipal Energy Agency of Nebraska (MEAN). Under Contract No. 89-LAO-

487, Exhibit A, RMR has a firm obligation to transmit up to 1,934 kW of

power and energy. Likewise, under Exhibit B, RMR is separately

obligated to transmit up to 22,156 kW. It is not clear why RMR's

calculation includes only the obligation in Exhibit B, but it appears

that RMR has understated the total capacity reservation.

Response: MEAN has indicated that they will elect to take network

transmission service. The 12 cp for MEAN has been added under network

load in the rate denominator. The issue raised by the commentor,

therefore, is no longer applicable.

Reason 8: RMR has a firm obligation to transmit up to 103,000 kW of

power and energy for the Rocky Mountain Generation Cooperative, Inc.

(RMGC). RMR's calculation shows a slightly different amount.

Response: RMGC has a firm transmission capacity reservation for

100,000 kW, to Sidney, Nebraska, which RMR included as point-to-point

service. RMGC also received firm transmission service to the Town of

Basin, Wyoming, and paid for the maximum service received, which is

estimated by RMGC as 3,000 kW. RMR included this 12-cp load of 2,583 kW

as network transmission service.

As of January 1998, transmission service from the Town of Basin was

deleted from the RMGC contract and added to the Tri-State transmission

agreement. RMR has made this adjustment in the rate denominator.

Comment: One commentor supports RMR's approach to pricing firm

point-to-point service, which cannot be discounted, and pricing non-

firm service on a maximum basis, which can then be discounted.

Response: Although RMR does not anticipate offering discounted firm

point-to-point service over the LAP transmission system, Western's

Tariff does allow for discounting of firm and non-firm point-to-point

service, consistent with the FERC Pro Forma.

Comment: One commentor suggests that credits for augmentation

facilities be included in the individual Network Integration Service

Agreement for the specific customer and not be a part of the initial

rate making process. Subsequent annual revisions of the transmission

service rates should take augmentation credits into account in the

calculation of the new rate. On the same topic, another commentor

suggested that RMR work with a group of customers to define

augmentation and establish criteria for determining when and where

augmentation exists on the LAP transmission system. The resulting

definitions and objective criteria can then be applied to instances in

which augmentation is claimed. This process should occur in a manner

which allows input from all affected Federal Customers. A third

commentor opposes RMR granting augmentation credits unless it can be

demonstrated that non-Federal transmission facilities were necessary to

deliver the firm electric service to Preference Customers.

Response: In accordance with FERC Order No. 888, credits for

customer-owned facilities are best resolved on a fact-specific, case-

by-case basis. We agree that credits will be addressed in the

individual Network Integration Service Agreement, and appropriate

adjustments may be made in subsequent rate calculations. If customers

feel that augmentation credits are warranted, they should submit a

written request with sufficient data to support their claim. RMR will

evaluate such requests, with input from all affected parties, in

accordance with guidance in FERC Order No. 888-A, Section IV.G.1.g: ``*

* * for a customer to be eligible for a credit, its facilities must not

only be integrated with the transmission provider's system, but must

also provide additional benefits to the transmission grid in terms of

capability and reliability, and be relied upon for the coordinated

operation of the grid.''

Comment: In RMR's cost of capital determinations, it applies the

composite interest rate on outstanding debt to the entire net plant

investment, rather than just to the unpaid component of the net

investment. By doing so, it creates an ongoing financing cost for the

principal component of the net investment that has already been paid

back to the U.S. Treasury. Since there is no cost associated with the

repaid principal component and since these governmental entities have

no equity owners that have invested capital, such treatment is improper

and overstates the true cost of capital.

Response: Although the revenue requirement includes interest

charges on the entire amount of undepreciated plant, no ongoing finance

charge is being created through its calculation. The methodology merely

ensures that transmission users pay finance charges related to the

plant they use. These finance charges are reduced over time by the

amount of plant investment removed to accumulated depreciation or

retirements. As these investments reduce in value, so do the financing

charges associated with them.

By applying an interest component to plant that has already been

paid but not yet depreciated, RMR is recognizing prepayments made by

Federal Customers and revenues from surplus generation sales that have

been applied against outstanding transmission debt. Western's repayment

of these investments is governed by DOE Order RA 6120.2, which

prescribes repayment of revenues to the highest interest-bearing

project investments first, regardless of whether they are related to

transmission or generation. This makes it possible for principal to be

significantly reduced on transmission debt without payment by

transmission users. If the interest component is not applied to net

plant, the Transmission

[[Page 16788]]

Customers would not pay their share of the interest expense.

Western revenues repay projects whose resources are entirely hydro;

therefore, average water is used to forecast repayment revenues. This

means that some years will have high-energy sales that can be used to

prepay debt in anticipation of drought conditions, such as those from

1988 through 1993, when revenues were insufficient to meet LAP's

repayment obligations. These prepayments act as stabilizing factors

during the ebb and flow of hydrologic cycles to ensure repayment of

project obligations. RMR's transmission rates have never included

charges for interest deficits, O&M deficits, or purchase power arising

from poor water years. RMR believed that these expenses were related to

insufficient energy to meet its obligations, and the associated costs

were incorporated in the firm power rate. It would be inappropriate for

Transmission Customers to share the benefit of good water, but none of

the costs of poor water.

Comment: Revenues derived from third-party transmission service

transactions should be accounted for in future repayment.

Response: In accordance with the DOE Order RA 6120.2, all

transmission revenues are credited to the P-SMBP power repayment study,

including an estimate of future revenues to reflect this transmission

rate adjustment.

Comment: A commentor has taken issue with the way that RMR has

functionally allocated the LAP microwave communications system and the

Power Marketing and Operations Complex (PMOC). By functionally

allocating the investment of these two facilities on the basis of LAP

plant investment, which includes almost no generation-related plant,

RMR understates the amount of service provided to the generation/power

merchant function by assigning a disproportionately large amount of the

annual cost of these items to transmission. The commentor recommends

including the net plant investment costs of Reclamation in calculating

the functional allocation of RMR's costs.

Response: Although Western and Reclamation are both agencies of the

Federal Government, they function as distinct and separate entities,

both financially and functionally. On December 21, 1977, under Section

302 of the Department of Energy Organization Act, Congress established

Western, whose primary responsibility is power marketing and

transmission of the Federal generation resource. These transferred

responsibilities were previously held by Reclamation, who continues to

own, operate, and maintain the generation resources for the Federal

Government.

With regard to the commentor's issue concerning the microwave

communications allocation, Reclamation owns, operates, and maintains

its own Supervisory Communications and Data Acquisition (SCADA) system

for microwave communications, none of which is included in the

transmission rate. The cost of Reclamation's SCADA facilities are in

the RMR's calculations for the generation based ancillary services.

RMR's SCADA and microwave communications system is designed, operated,

and maintained by RMR personnel primarily for transmission system use.

Therefore, RMR asserts that its allocation of SCADA and microwave

communications costs on the basis of LAP investment is proper.

With regard to the PMOC, RMR revisited its computation for

functionally allocating the PMOC costs. RMR's methodology for this

review was an analysis of PMOC office space, and specifically, what

percentage of the office space is occupied by personnel that support

the generation function. RMR found that based on space occupied in the

PMOC by generation-dedicated employees, the amount of the PMOC to be

functionally allocated to generation should be 2.928 percent, rather

than the 3.669 percent derived from investment costs. Reallocation of

the PMOC to accommodate this .741 percentage difference increases the

amount allocated to transmission by $176,080. This is insignificant

when contrasted against the total transmission allocation of

$304,913,006. Given the relatively insignificant amounts and immaterial

rate impacts, RMR maintains that its original allocation of the PMOC

building costs based on LAP plant investment is reasonable.

Comment: One commentor also feels that RMR should use cost-tracking

allocators to functionally assign expenses, rather than allocating on

the basis of the LAP net investment. Specific FERC accounts should be

functionally allocated on the basis of what function they benefit. A&GE

expenses associated with field-type offices that provide multi-function

services should be functionally allocated using a basis that fully

recognizes the generation/power merchant function performed at these

offices. The commentor points out that certain O&M expense items,

specifically the Conservation and Renewable Energy (C&RE) Expense and

the Power Marketing and Generation Power Resources Planning Expense,

should be entirely excluded from the transmission revenue requirement

and assigned specifically to the generation/power merchant function at

RMR.

Response: As previously stated, Western's primary responsibility is

the power marketing and transmission of the Federal generation

resource. RMR provides only incidental generation support. Reclamation

owns, operates, and maintains the generation resource for the Federal

Government. Reclamation costs have not been included in the

transmission revenue requirements.

Western undertook a line item analysis of the O&M costs. Western

agrees with the commentor that the cost of C&RE could be completely

assigned to the generation function. Adjustments could be made to the

line items for Power Users Account and Collection Expenses and Power

Marketing and Generation Power Resources Planning Expenses, which would

increase the 3.669 percent allocated to generation. However, these

three adjustments amount to a decrease in the O&M allocated to

transmission by $317,455, which would reduce the fixed charges for

transmission by less than 0.1 percent. Given the relatively

insignificant amounts and immaterial rate impacts, RMR will continue to

functionally allocate the LAP O&M and A&GE costs based upon plant

investment costs. RMR reiterates that Western staff do not perform

significant generation activity.

During RMR's review of the O&M costs, an extensive reexamination of

those costs was undertaken and a determination was made that the Mt.

Elbert Powerplant O&M was classified inappropriately in the original

calculations. The original calculations assumed that Mt. Elbert was

only used for the provision of firm power; in fact, Mt. Elbert is

actually used to provide a material amount of Regulation and Frequency

Response Service and Reserves support. Therefore, RMR's costs for the

O&M of Mt. Elbert, which were originally allocated to LAP Federal

Customers, are now being included in the Annual Fixed Charge Rate for

Generation. This adjustment increases the generation O&M costs by $3

million, the addition of which yielded no impact to the ancillary

service rates.

Comment: RMR included in the transmission revenue requirement the

charges it pays to NPPD for transmission service under Contract No. 87-

LAO-200. The transmission service from NPPD provides no long-term, firm

transmission capacity to RMR beyond

[[Page 16789]]

that which is required and reserved to serve RMR's firm generation

service loads located in southern Nebraska and northern Kansas and

which are captive to the NPPD transmission system. Consequently, the

long-term firm Transmission Customer on the LAP transmission system can

derive no benefit from this wheeling arrangement. To be consistent with

the functional unbundling requirements, this wheeling arrangement

should belong to the generation/power merchant function.

Response: RMR agrees and has eliminated this item from the

numerator of the rate design calculation.

Comment: RMR transmission rate proposal does not include any

revenue credit for the lease of facilities that have been included in

the functionalized LAP transmission plant investment.

Response: RMR reviewed all revenue from rental of facilities, which

are included in the transmission plant investment. Such revenues are

about $30,000, annually. These revenues have been included as a revenue

credit in the numerator.

Comment: One commentor supports separating the cost of

subtransmission facilities from the transmission rate. Clearly these

facilities are not part of the bulk supply system, but are used to

serve local loads, and, therefore, should be paid for separately.

Response: RMR agrees and assigned the subtransmission to the

Federal Customers. The subtransmission system is used primarily for

delivery of Federal power to the Federal Customers. If a Transmission

Customer requires the use of the subtransmission system, an additional

facility-use charge will be assessed.

Comment: The primary reason for the increase in the transmission

rate was due to a change in the denominator. One customer recognized

that a large portion of this change was because some customers included

their Federal load in the transmission load projections they provided

to Western for the 1993 transmission rate. This overstated the

denominator. This commentor suggested that when submitting to FERC, RMR

should include data showing how the loads change by customer.

Response: The suggested information has been provided in the

supporting data to this Rate Order. The transmission rate has been

understated since 1994. Western has corrected the rate so that the

transmission revenue requirement will be collected.

Comment: One commentor supports RMR keeping its firm power rate

bundled, but is concerned that RMR may not meet the comparability

requirements of FERC Order No. 888 because it does not charge itself

for transmission service, including all wholesale power deliveries to

Preference Customers, the same rate as it will charge others for use of

the transmission system.

Response: Firm Federal power is transmitted as a network-type

service under existing bundled Firm Electric Service Contracts, and not

under Western's Tariff. RMR uses whatever power or transmission is

required to meet its Firm Electric Service Contract commitments, like

network transmission service.

RMR believes that it meets the comparability requirement of FERC

Order No. 888. In FERC Order No. 888-A, Section IV.C.b., it is

clarified that the transmission provider must ``take service'' under

its own tariff for third-party sales for comparability. RMR's merchant

function will take service under Western's Tariff and point-to-point

rates for any third-party sales.

FERC Order No. 888-A recognizes that existing contracts will not

necessarily be at the same rate as the transmission service offered

under the Tariff. However, the service can still be considered

comparable. RMR has shown in its rate design for this Rate Order that

the calculation of transmission costs for delivery to Federal Customers

is on the same basis as for other firm Transmission Customers.

Comment: Several commentors support RMR's phased-in approach to

reach its required transmission rate level, as a means to mitigate the

rate shock associated with the large rate increase.

Response: RMR proposed a three-step approach to implement the

transmission rate increase between April 1, 1998, and October 1, 1999.

Comment: The commentor commended Western for its thoughtful

approach in developing the proposed transmission rates and the thorough

public process associated with encouraging comment from affected

parties and interested members of the public.

Response: RMR appreciates the input from its customers during the

public process.

Ancillary Services Discussion

Six ancillary services will be offered by WACM; two of which are

required to be purchased by the LAP Transmission Customer. These two

are: (1) Scheduling, System Control, and Dispatch Service, and (2) VAR

Support. The remaining four ancillary services--Regulation, Energy

Imbalance Service, Spinning Reserves, and Supplemental Reserves--will

also be offered, but are subject to availability.

Sales of Regulation, Energy Imbalance Service, Spinning Reserves,

and Supplemental Reserves may be limited since Western has allocated

its power resources to preference entities under long-term commitments.

If WACM is unable to provide these services from its own resources, an

offer will be made to purchase the services and pass through these

costs to the customer, including an administrative charge.

The formula rates for ancillary services will be based on the costs

of WACM control area and are designed to recover only the costs

associated with providing the service(s).

The WACM, as of April 1, 1998, will have a single control office,

combining the offices that formerly controlled the Western Area Upper

Colorado control area (WAUC) and the Western Area Lower Missouri

control area (WALM). WACM Federal power resources consist of all the

LAP Federal power resources and a portion of the Salt Lake City Area-

Integrated Projects (SLCA-IP) Federal power resources.

Scheduling, System Control, and Dispatch Service: The costs for

providing Scheduling, System Control, and Dispatch Service for

Transmission Customers are included in the appropriate transmission

service rates. This service can be provided only by the control area

operator in which the transmission facilities are located. The formula

rates will be applied to all schedules for WACM non-transmission

customers.

The formula rate for Scheduling, System Control, and Dispatch is

based on the annual cost of all personnel and related cost involved in

providing the service for WACM. The annual cost is divided by the

number of schedules per year to derive a ``rate per schedule'' applied

per day. RMR's definition of a ``schedule'' is a specific request for

energy or transmission through, within, into, or out of WACM, per day.

The entity requesting the schedule is generally the entity responsible

for the scheduling charge, unless other arrangements are made.

RMR will accept any reasonable number of schedule changes over the

course of a day, without any additional charge, so that entities trying

to follow their loads closely may do so without penalty.

Based on FY 1996 data, the rate for WACM, effective April 1, 1998,

will be $25.71 per schedule per day.

Reactive Supply and Voltage Control Service from Generation

Sources: The formula rate for VAR Support is based upon Reclamation's

net generation plant

[[Page 16790]]

investment in WACM. Annual Fixed Charge Rates based on annual

generation-related O&M, A&GE, depreciation, and interest expenses for

LAP and for SLCA-IP are applied to Reclamation's net generation plant

investment to calculate annualized costs. The percentage of WACM

generation capacity that is utilized for VAR Support is then

identified. This percentage is applied to the annualized costs for LAP

and SLCA-IP, and those results summed to derive the annual revenue

requirement for VAR Support for WACM. The annual revenue requirement is

then divided by the WACM 12-cp load being provided VAR Support, to

yield a $/kW-year rate, which is divided by 12 months to yield a kW-

month rate. Based upon FY 1996 data, the WACM rate for VAR Support is

$0.112/kW-month.

Credit may be given to those customers with generators in the

control area providing WACM with VAR Support. Any crediting arrangement

must be documented in the customers' service agreements.

Regulation and Frequency Response Service: The formula rate for

Regulation is based upon the annualized cost of Reclamation's net plant

investment for regulating plants in WACM (the investment costs for

SLCA-IP regulating plants that will provide Regulation in the Western

Area Lower Colorado control area were not included). The net investment

costs were included for only those plants that are able to provide

regulating service--run-of-the-river plants were excluded because

regulation control is not possible from those plants. The same Annual

Fixed Charge Rates used in the VAR Support formula were used to convert

the LAP and SLCA-IP net plant investments to annual costs for

Regulation. The annual costs are divided by the nameplate capacity of

the applicable plants to yield an average cost per kilowatt for LAP and

SLCA-IP.

The amount of capacity used to provide Regulation service is

identified. For LAP, one-half of the percentage of the resource used to

provide Regulation is multiplied by the load in the control area

requiring Regulation. For SLCA-IP, historical operational experience

shows that the amount of capacity provided for the SLCA-IP load is 40

MW. The April 1, 1998, division of the SLCA-IP load into two control

areas, discussed previously, has been determined to represent a 50/50

split of the load, and therefore, the capacity amount applicable to the

WACM from SLCA-IP is 20 MW.

The average cost per kilowatt for LAP and SLCA-IP is then

multiplied by the appropriate amounts of capacity providing Regulation,

to yield the annual revenue requirements for Regulation. The annual

revenue requirements are then summed and divided by the load in the

control area requiring Regulation service. This yields a rate per kW-

year, which is divided by 12 months to calculate a rate per kW-month.

Based upon FY 1996 data, the WACM rate for Regulation is $0.147/kW-

month.

Federal Customers will receive a credit for Regulation on their

power bill if they receive Regulation from another source, or self-

supply it for their own load. Credit will also be given to those

customers who provide WACM with Regulation. These types of crediting

arrangements must be documented in the Transmission Customers' service

agreements.

Energy Imbalance Service: FERC established guidelines for Energy

Imbalance Service of +/-1.5 percent hourly deviation (3 percent

bandwidth) with a 2 MW minimum deviation, as in their view, anything

more or less than that could affect the reliability of the system. RMR

established the 3 percent bandwidth for Energy Imbalance Service to be

consistent with FERC.

RMR recognizes that metering inadequacies, revision of scheduling

practices, and unit control problems may initially hinder a customer's

ability to meet the 3 percent bandwidth. Therefore, RMR is phasing in

the Energy Imbalance Service bandwidth simultaneously with the

transmission service rate to allow a transition period; whereby,

customers may improve their equipment and scheduling practices.

Effective April 1, 1998, the bandwidth will be set at 6 percent (+/-3

percent deviation); effective October 1, 1998, the bandwidth will drop

to 5 percent (+/-2.5 percent); and effective October 1, 1999, the

bandwidth will be in compliance with the FERC-endorsed bandwidth of 3

percent (+/-1.5 percent). Deviation accounting will be completed

monthly on an hour-to-hour basis.

RMR reserves the right to assess negative excursions (under

deliveries) outside the bandwidth and occurring more than five times

per month, a penalty charge of 100 mills/kWh.

During normal water conditions, any positive excursions (over

deliveries) outside the bandwidth will be credited on the customer's

bill, lagged by 1 month. The credit will be 50 percent of the regional

average monthly price for non-firm purchases, provided that these over

deliveries do not impinge on WACM operations. For example, during times

of high water conditions, RMR will reserve the right to eliminate any

credits for over deliveries.

Spinning/Supplemental Reserves: Based upon the Post-1999 Resource

Study (July 1995), WACM has no long-term Reserves available beyond its

own internal requirements.

An offer will be made to purchase Reserves for a customer and pass

through that cost, plus an amount for administration.

When Reserves are called on for Emergency Use, RMR will assess a

charge for energy used, at the greater of 30 mills/kWh or the

prevailing market energy rate in the region. The customer would be

responsible for providing the transmission to get the Reserves to its

destination.

Ancillary Services Comments

RMR received written comments concerning the ancillary services

during the public comment and consultation period. These comments have

been paraphrased where appropriate, without compromising the meaning of

the comment. Certain comments were duplicative in nature, and were

combined. RMR's response follows each comment.

Comment: A commentor believes that the load determinants for

Regulation and VAR Support, as referenced on page 38 of the Customer

Brochure, are understated for the following reasons.

For VAR Support, RMR has not accounted for Missouri Basin Power

Pool, Tri-State, and CSU generation within the WALM control area.

Likewise, RMR has not accounted for Craig, Nucla, Qualifying

Facilities, small hydro, and other western Colorado generation that

will be located in WACM.

Since VAR Support is a required service, why did RMR remove Black

Hills Power and Light's (Black Hills) load from the denominator?

For Regulation, RMR has not accounted for all PacifiCorp, Tri-

State, municipal, and Rural Electric Association (REA) loads located in

the WALM control area. Likewise, RMR has not accounted for any non-

Federal, western Colorado, Tri-State, municipal and REA loads located

in WACM.

Response: Page 38 of RMR's Customer Brochure incorrectly identified

``Tri-State Direct (in WALM)'' with a number that was actually

representative of cumulative ``other'' load in WACM. RMR did, in fact,

include the loads that the commentor believes were omitted; i.e.,

Missouri Basin Power Pool, Tri-State, CSU, PacifiCorp, municipal, and

REA. RMR also accounted for the western Colorado generation that will

be located in WACM.

[[Page 16791]]

Based upon this commentor's statements, however, Western revisited

and reconfirmed the load denominator for both VAR Support and

Regulation service for the ``other'' load in the control area, and has

refined them to be 1,047,979 kW for Regulation and 1,538,608 kW for VAR

Support, as contrasted with the loads in the Customer Brochure of

1,407,917 kW for Regulation and 1,437,638 kW for VAR Support.

Black Hills' load was omitted from the VAR Support service load as

they cannot receive this service from a WACM generation source. Load

data for Black Hills were accounted for as part of the Regulation load,

as they are in WACM's control area and RMR has a specific contract with

Black Hills to provide them Regulation service. RMR also reassessed the

277 MW included in the Regulation load for Black Hills as RMR does not

provide Regulation for Black Hill's total load. Based upon bills

submitted in 1997, the average amount of load that RMR regulates for

Black Hills is 89 MW. In conjunction with this adjustment to Black

Hill's Regulation load, RMR included a $90,000 revenue credit for the

existing contract for Regulation service.

Comment: A commentor is concerned about the narrow bandwidth (+/-

1.5 percent) allowed for deviation from scheduled transactions,

maintaining that it will be extremely difficult to stay within this

bandwidth because of limitations and errors in metering, scheduling

practices, and unit control.

This same commentor also requests that generating entities within

the control area also be given the opportunity to participate with

Western in the provision of Energy Imbalance Service, rather than

merely taking the service from RMR as the control area operator.

Response: FERC has established guidelines for Energy Imbalance

Service of +/-1.5 percent deviation (or 3 percent bandwidth), as in

their view, anything more or less than that could affect the

reliability of the system. RMR established a bandwidth for Energy

Imbalance Service to be consistent with FERC and with what the industry

has been using as a standard.

RMR points out to its customers that FERC did establish a larger

minimum deviation of 2 megawatts (MW) in an attempt to meet the needs

of smaller customers. This minimum allows Transmission Customers with

load less than 133 MW to have more flexibility in the bandwidth.

However, RMR does recognize that some of its customers may construe

the 3 percent bandwidth as too narrow, from the perspective that there

are currently limitations in metering, scheduling practices, and unit

control. Therefore, RMR is phasing in the Energy Imbalance Service

bandwidth simultaneously with the transmission service rate to allow a

transition period; whereby, customers may improve their equipment and

revise their scheduling practices. Effective April 1, 1998, the

bandwidth will be set at 6 percent (+/-3 percent deviation); effective

October 1, 1998, the percentage bandwidth will drop to 5 percent (+/-

2.5 percent deviation); and effective October 1, 1999, the percentage

bandwidth will be in compliance with the FERC-endorsed bandwidth of 3

percent (+/-1.5 percent deviation).

Regarding participation in the provision of Energy Imbalance

Service by others in WACM, RMR asks that any proposals submitted to RMR

demonstrate the benefits to the control area in terms of Energy

Imbalance Service (deviation, inadvertent flow, and losses), and

reliability for operation of the control area.

Comment: A commentor recommends that the provision limiting

schedule changes be eliminated. They also recommend a more rigorous

definition of the term ``schedule'' as it is applied in this rate. The

commentor noted that it may be worthwhile to consider an exhibit to the

service agreement that would identify billable schedules.

Response: In its initial rate design, RMR developed its Scheduling,

System Control, and Dispatch Service rate and limited the number of

schedule changes to five times per day before any additional scheduling

charge would be assessed. Schedule changes equate to the use of

personnel and associated cost, and RMR was trying to both accommodate

the customer and recover the cost of doing business.

However, RMR has recognized that any limit on the number of

schedule changes per day may penalize entities trying to follow their

loads closely. Therefore, RMR will accept any reasonable number of

schedule changes over the course of the day without additional charges.

RMR's definition of a ``schedule'' is a specific request for energy

or transmission through, into, within, or out of WACM, per day. The

entity requesting the schedule is generally the entity responsible for

the scheduling charge, unless other arrangements are made.

The comment concerning inclusion of an exhibit to the individual

service agreements is outside the rate adjustment process; however, RMR

will consider the inclusion of this exhibit to the individual service

agreements identifying billable schedules.

Comment: A commentor asks that RMR and Upper Great Plains Region

(UGPR) be consistent on policy for Energy Imbalance Service.

Response: RMR and UGPR are separate regional offices of Western

within separate control areas, and as such, have disparate operational

requirements. Additionally, the UGPR operates with basically one

drainage basin, while LAP has five basins within its operational

control.

LAP's five basins allow for greater operational flexibility than

UGPR's main-stem system; e.g., during high water conditions, WACM would

be less likely to be forced to spill and potentially lose energy. RMR

has indicated that it would credit the customer for 50 percent of the

regional average monthly price for non-firm purchases in a scheduled

over delivery; however, RMR will reserve the right to eliminate credits

during times when over deliveries would impinge upon WACM operations.

RMR has revised its Energy Imbalance Service rate language accordingly.

Comment: A commentor expresses concern that care be taken to see

that all revenues for ancillary services are credited back to the firm

electric service rate.

Response: Western is developing procedures for proper accounting

classification of Open Access Transmission revenues. RMR will assure

that all revenues, including ancillary services, are incorporated in

the P-SMBP Power Repayment Study, and revenues will be applied pursuant

to DOE Order No. RA 6120.2.

Comment: A commentor wants to ensure that RMR views the ancillary

services as an integral component of the Federal Government's power

allocation. It is the commentor's position that the provision of any

generation-related ancillary services which interfere with the

statutory obligations of Western to dedicate its generation resources

to Federal Customers is statutorily prohibited. Specifically,

concerning Regulation and Reserves, Western should limit itself to

providing these services to non-Federal customers only after first

offering the resource to its Federal Customers. Otherwise, Western

should limit the offer of these services to the brokering of ancillary

services from third-party providers. Further, concerning Reserves and

the selling of short-term Reserves when available, Western should

affirm that if and when such Reserves are available on a short-term

basis, they will be offered to Federal Customers first.

[[Page 16792]]

Response: Western views the ancillary services as an integral

component of the Federal Government's power allocation and is not

changing this viewpoint with the advent of FERC Order No. 888. Western

will not take any actions that would compromise its ability to meet its

contractual obligations to its Federal Customers. RMR will continue to

provide all of the services so designated as approved in the Marketing

Plan.

While ancillary services were not specifically defined or offered

in the Marketing Plan, those services are presumed to be included in

the allocation and delivery of RMR's firm power resource. RMR has fully

allocated all firm resources through the Marketing Plan and currently

provides all of the required ancillary services for the Federal

Customers.

As stated previously, the RMR Post-1999 Resource Study ascertained

that there are no long-term Reserves available from WACM resources

beyond WACM internal requirements. Historically, when Western has had

non-firm, short-term, or surplus resources available for sale, they

have been sold on the open market. RMR has offered surplus energy first

to those with Firm Electric Service Contracts, but it is an option that

surplus energy be sold on the open market, as Western's UGPR and

Colorado River Storage Project Customer Service Center have done. The

Marketing Plan allows the sale of non-firm, short-term, or surplus

resources in Section B.3.c., Marketing Considerations.

RMR has engaged in the marketing of ancillary services prior to

this filing, as evidenced by RMR's provision of interconnected

operation service (shaping and storage service) for RMGC, and RMR's

provision of Regulation service for Black Hills. These products have

been offered to both preference and non-preference customers.

Comment: A commentor applauded RMR's stance that only the ancillary

services that are surplus to those required to meet Western's statutory

requirements would be offered for sale. The commentor agreed with RMR's

position regarding the purchase and pass through of costs for ancillary

services, when not available from a control area resource.

Response: RMR appreciates the comment.

Regulatory Flexibility Analysis

Pursuant to the Regulatory Flexibility Act of 1980 (5 U.S.C. 601-

612), each agency, when required by 5 U.S.C. 553 to publish a proposed

rule, is further required to prepare and make available for public

comment an initial regulatory flexibility analysis to describe the

impact of the proposed rule on small entities. In this instance, the

initiation of the LAP transmission rate and ancillary service rate

adjustment is related to non-regulatory services provided by Western at

a particular rate. Under 5 U.S.C. 601(2), rules of particular

applicability relating to rates or services are not considered rules

within the meaning of the Act. Since the LAP transmission rates and

ancillary service rates are of limited applicability, no flexibility

analysis is required.

Environmental Evaluation

In compliance with the National Environmental Policy Act (NEPA) of

1969, 42 U.S.C. 4321 et seq.; the 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

DOE has determined that this is not a significant regulatory action

because it does not meet the criteria of Executive Order 12866, 58 FR

51735. Western has an exemption from centralized regulatory review

under Executive Order 12866; accordingly, no clearance of this notice

by the Office of Management and Budget is required.

Submission to Federal Energy Regulatory Commission

The formula 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, approve, and place into

effect on an interim basis, effective April 1, 1998, formula rates for

transmission and ancillary service under Rate Schedules L-NT1, L-FPT1,

L-NFPT1, L-AS1, L-AS2, L-AS3, L-AS4, L-AS5, and L-AS6. These schedules,

in total, supersede Rate Schedules L-T3 and L-T4. The rate schedules

shall remain in effect on an interim basis, pending FERC confirmation

and approval of them or substitute formula rates on a final basis

through March 31, 2003.

Dated: March 23, 1998.

Elizabeth A. Moler,

Deputy Secretary.

Rocky Mountain Region, Loveland Area Projects--Rate Schedule L-AS1

(Supersedes L-T3) Schedule 1 to Tariff April 1, 1998

Scheduling, System Control, and Dispatch Service

Applicable

This service is required to schedule the movement of power through,

out of, within, or into the Western Area Colorado Missouri control area

(WACM). The charges for Scheduling, System Control, and Dispatch

Service are to be based on the rate referred to below. The formula rate

used to calculate the charges for service under this schedule was

promulgated and may be modified pursuant to applicable Federal laws,

regulations, and policies.

The rate will be applied to all schedules for WACM non-transmission

customers. The Rocky Mountain Region (RMR) will accept any reasonable

number of schedule changes over the course of the day without any

additional charge.

The Loveland Area Projects charges for Scheduling, System Control,

and Dispatch Service may be modified upon written notice to the

customer. Any change to the charges for the Scheduling, System Control,

and Dispatch Service shall be as set forth in a revision to this rate

schedule promulgated pursuant to applicable Federal laws, regulations,

and policies and made part of the applicable service agreement. RMR

shall charge the non-transmission customer in accordance with the rate

then in effect.

Effective

The first day of the first full billing period beginning on or

after April 1, 1998, through March 31, 2003.

Formula Rate

[GRAPHIC] [TIFF OMITTED] TN06AP98.009

[[Page 16793]]

* * * * *

Rate

The rate to be in effect April 1, 1998, through September 30, 1998,

is $25.71 per schedule per day. This rate is based on the above formula

and on FY 1996 data. A recalculated rate will go into effect every

October based on the above formula and data.

Rate Schedule L-AS2 (Supersedes L-T3 and L-T4) Schedule 2 to Tariff

April 1, 1998

Reactive Supply and Voltage Control from Generation Sources Service

Applicable

In order to maintain transmission voltages on all transmission

facilities within acceptable limits, generation facilities under the

control of the Western Area Colorado Missouri control area (WACM) are

operated to produce or absorb reactive power. Thus, Reactive Supply and

Voltage Control from Generation Sources Service (VAR Support) must be

provided for each transaction on the transmission facilities. The

amount of VAR Support that must be supplied with respect to the

Customer's (Loveland Area Projects (LAP) Transmission Customers and

customers on others' transmission systems within the WACM) transaction

will be determined based on the VAR Support necessary to maintain

transmission voltages within limits that are generally accepted in the

region and consistently adhered to by WACM.

The Customer must purchase this service from the WACM operator. The

charges for such service will be based upon the rate referred to below.

The formula rate used to calculate the charges for service under

this schedule was promulgated and may be modified pursuant to

applicable Federal laws, regulations, and policies.

The LAP charges for VAR Support may be modified upon written notice

to the Customer. Any change to the charges for VAR Support shall be as

set forth in a revision to this rate schedule promulgated pursuant to

applicable Federal laws, regulations, and policies and made part of the

applicable service agreement. The Rocky Mountain Region shall charge

the Customer in accordance with the rate then in effect.

Credit may be given to those Customers with generators in the

control area providing WACM with VAR Support. Any crediting

arrangements must be documented in the customer's service agreement.

Effective

The first day of the first full billing period beginning on or

after April 1, 1998, through March 31, 2003.

Formula Rate

[GRAPHIC] [TIFF OMITTED] TN06AP98.010

* * * * *

Rate

The rate to be in effect April 1, 1998, through September 30, 1998,

is:

Monthly: $0.112/kW-month

Weekly: $0.026/kW-week

Daily: $0.004/kW-day

Hourly: 0.154 mills/kWh

This rate is based on the above formula and on FY 1996 financial

and load data. A recalculated rate will go into effect every October

based on the above formula and updated financial and load data.

Rate Schedule L-AS3 (Supersedes L-T3) Schedule 3 to Tariff April 1,

1998

Regulation and Frequency Response Service

Applicable

Regulation and Frequency Response Service (Regulation) 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). Regulation is

accomplished by committing on-line generation whose output is raised or

lowered, predominantly through the use of automatic generating control

equipment, as necessary to follow the moment-by-moment changes in load.

The obligation to maintain this balance between resources and load lies

with the Western Area Colorado Missouri control area (WACM) operator.

The Customer (Loveland Area Projects (LAP) Transmission Customers and

customers on others' transmission systems within WACM) must either

purchase this service from WACM or make alternative comparable

arrangements to satisfy its Regulation obligation. The charges for

Regulation are referred to below. The amount of Regulation will be set

forth in the service agreement.

The formula rate used to calculate the charges for service under

this schedule was promulgated and may be modified pursuant to

applicable Federal laws, regulations, and policies.

The LAP charges for Regulation may be modified upon written notice

to the Customer. Any change to the Regulation charges shall be as set

forth in a revision to this rate schedule promulgated pursuant to

applicable Federal laws, regulations, and policies and made part of the

applicable service agreement. The Rocky Mountain Region (RMR) shall

charge the Customer in accordance with the rate then in effect.

Customers will receive a credit for Regulation on their power bill

if they receive Regulation from another source, or self-supply it for

their own load. Credit will also be given to those Customers who

provide WACM with Regulation. These types of crediting arrangements

must be documented in the customer's service agreement.

Effective

The first day of the first full billing period beginning on or

after April 1, 1998, through March 31, 2003.

Formula Rate

* * * * *

[GRAPHIC] [TIFF OMITTED] TN06AP98.011

[[Page 16794]]

Rate

The rate to be in effect April 1, 1998, through September 30, 1998,

is:

Monthly: $0.147/kW-month

Weekly: $0.034/kW-week

Daily: $0.005/kW-day

This rate is based on the above formula and on FY 1996 financial

and load data. A recalculated rate will go into effect every October

based on the above formula and updated financial and load data.

If resources are not available from a WACM resource, RMR will offer

to purchase the Regulation and pass through the costs to the Customer,

plus an amount for administration.

Rate Schedule L-AS4, (Supersedes L-T3), Schedule 4 to Tariff, April 1,

1998.

Energy Imbalance Service

Applicable

Energy Imbalance Service is provided when a difference occurs

between the scheduled and the actual delivery of energy to a load

located within the Western Area Colorado Missouri control area (WACM)

over a single hour. The Customer (Loveland Area Projects (LAP)

Transmission Customers and customers on others' transmission system

within WACM) must either obtain this service from WACM or make

alternative comparable arrangements to satisfy its Energy Imbalance

Service obligation.

The WACM shall establish a deviation band of +/-3.0 percent (with a

minimum of 2 MW) of the scheduled transaction to be applied hourly to

any energy imbalance that occurs as a result of the Customer's

scheduled transaction(s). Deviation accounting will be completed

monthly on an hour-to-hour basis.

The formula rate used to calculate the charges for service under

this schedule was promulgated and may be modified pursuant to

applicable Federal laws, regulations, and policies.

The Energy Imbalance Service compensation may be modified upon

written notice to the Customer. Any change to the Customer compensation

for Energy Imbalance Service shall be as set forth in a revision to

this schedule promulgated pursuant to applicable Federal laws,

regulations, and policies and made part of the applicable service

agreement. The Rocky Mountain Region (RMR) shall charge the Customer in

accordance with the rate then in effect.

Effective

The first day of the first full billing period beginning on or

after April 1, 1998, through March 31, 2003.

Formula Rate

For negative excursions (under deliveries) outside the bandwidth

and occurring more than five times per month, RMR reserves the right to

assess a penalty charge of 100 mills/kWh.

For positive excursions (over deliveries) outside the bandwidth,

the Customer will be credited on the customer's bill, lagged by 1

month. The credit will be 50 percent of the regional average monthly

price for non-firm purchases, provided the over deliveries do not

impinge upon WACM operations. For example, during times of high water

or operating constraints, RMR reserves the right to eliminate credits

for over deliveries.

* * * * *

Rate

The bandwidth in effect April 1, 1998, through September 30, 1998,

is 6 percent (+/-3 percent hourly deviation).

Rate Schedule L-AS5 (Supersedes L-T3), Schedule 5 to Tariff, April 1,

1998.

Operating Reserve--Spinning Reserve Service

Applicable

Spinning Reserve Service (Reserves) is needed to serve load

immediately in the event of a system contingency. Reserves may be

provided by generating units that are on-line and loaded at less than

maximum output. The Customer (Loveland Area Projects (LAP) Transmission

Customers and customers on others' transmission system within Western

Area Colorado Missouri control area (WACM)) must either purchase this

service from WACM or make alternative comparable arrangements to

satisfy its Reserves obligation. The charges for Reserves are referred

to below. The amount of Reserves will be set forth in the service

agreement.

Effective

The first day of the first full billing period beginning on or

after April 1, 1998, through March 31, 2003.

Formula Rate

No long-term Reserves are available beyond internal WACM

requirements.

* * * * * *

Rate

There are no long-term Reserves available from WACM. An offer will

be made to purchase Reserves for a Customer and pass through the cost,

plus an amount for administration.

In the event that Reserves are called upon for Emergency Use, the

Rocky Mountain Region (RMR) will assess a charge for energy used, at

the greater of 30 mills/kWh or the prevailing market energy rate in the

region. The Customer would be responsible for providing the

transmission to get the Reserves to its destination.

Rate Schedule L-AS6 (Supersedes L-T3) Schedule 6 to Tariff April 1,

1998

Operating Reserve--Supplemental Reserve Service

Applicable

Supplemental Reserve Service (Reserves) is needed to serve load in

the event of a system contingency; however, it is not available

immediately to serve load but rather within a short period of time.

Reserves may be provided by generating units that are on-line but

unloaded, by quick-start generation or by interruptible load. The

Customer (Loveland Area Projects' Transmission Customers and customers

on others' transmission system within Western Area Colorado Missouri

control area (WACM)) must either purchase this service from WACM or

make alternative comparable arrangements to satisfy its Reserves

obligation. The charges for Reserves are referred to below. The amount

of Reserves will be set forth in the service agreement.

Effective

The first day of the first full billing period beginning on or

after April 1, 1998, through March 31, 2003.

Formula Rate

No long-term Reserves are available beyond internal WACM

requirements.

* * * * *

Rate

There are no long-term Reserves available from WACM. An offer will

be made to purchase Reserves for a Customer and pass through the cost,

plus an amount for administration.

In the event that Reserves are called upon for Emergency Use, the

Rocky Mountain Region will assess a charge for energy used, at the

greater of 30 mills/kWh or the prevailing market energy rate in the

region. The Customer would be responsible for providing the

transmission to get the Reserves to its destination.

Rate Schedule L-FPT1 (Supersedes L-T3) Schedule 7 to Tariff April 1,

1998

Long-Term Firm and Short-Term Point-to-Point Transmission Service

Applicable

The Transmission Customer shall compensate Rocky Mountain Region

(RMR) each month for Reserved Capacity pursuant to the applicable

[[Page 16795]]

Firm Point-to-Point Transmission Service Agreement and rates referred

to below. The formula rates used to calculate the charges for service

under this schedule were promulgated and may be modified pursuant to

applicable Federal laws, regulations, and policies.

RMR may modify the charges for Firm Point-to-Point Transmission

Service upon written notice to the Transmission Customer. Any change to

the charges to the Transmission Customer for Firm Point-to-Point

Transmission Service shall be as set forth in a revision to this rate

schedule promulgated pursuant to applicable Federal laws, regulations,

and policies and made part of the applicable service agreement. RMR

shall charge the Transmission Customer in accordance with the rate then

in effect.

Discounts

Three principal requirements apply to discounts for transmission

service as follows: (1) any offer of a discount made by RMR must be

announced to all Eligible Customers solely by posting on the Open

Access Same-Time Information System (OASIS), (2) any Customer-initiated

requests for discounts, including requests for use by one's wholesale

merchant or an affiliate's use, must occur solely by posting on the

OASIS, and (3) once a discount is negotiated, details must be

immediately posted on the OASIS. For any discount agreed upon for

service on a path, from Point(s) of Receipt to Point(s) of Delivery,

RMR must offer the same discounted transmission service rate for the

same time period to all Eligible Customers on all unconstrained

transmission paths that go to the same point(s) of delivery on the

Transmission System.

Effective

The first day of the first full billing period beginning on or

after April 1, 1998, through March 31, 2003.

Formula Rate

If a Transmission Customer requires use of subtransmission

facilities, a specific facility use charge will be assessed in addition

to this formula rate.

* * * * *

[GRAPHIC] [TIFF OMITTED] TN06AP98.012

Rate

The rate to be in effect April 1, 1998, through September 30, 1998,

is as follows.

Maximum of:

Yearly: $27.84/kW of reserved capacity per year

Monthly: $2.32/kW of reserved capacity per month

Weekly: $0.54/kW of reserved capacity per week

Daily: $0.08/kW of reserved capacity per day

This rate is based on the above formula and FY 1996 data. A

recalculated rate will go into effect every October based on the above

formula and updated financial and load data.

Rate Schedule L-NFPT1 (Supersedes L-T4) Schedule 8 to Tariff April 1,

1998

Non-Firm Point-to-Point Transmission Service

Applicable

The Transmission Customer shall compensate Rocky Mountain Region

(RMR) for Non-Firm Point-to-Point Transmission Service pursuant to the

applicable Non-Firm Point-to-Point Transmission Service Agreement and

rate referred to below. The formula rates used to calculate the charges

for service under this schedule were promulgated and may be modified

pursuant to applicable Federal laws, regulations, and policies.

RMR may modify the charges for Non-Firm Point-to-Point Transmission

Service upon written notice to the Transmission Customer. Any change to

the charges to the Transmission Customer for Non-Firm Point-to-Point

Transmission Service shall be as set forth in a revision to this rate

schedule promulgated pursuant to applicable Federal laws, regulations,

and policies and made part of the applicable service agreement. RMR

shall charge the Transmission Customer in accordance with the rate then

in effect.

Discounts

Three principal requirements apply to discounts for transmission

service as follows: (1) any offer of a discount made by RMR must be

announced to all Eligible Customers solely by posting on the Open

Access Same-Time Information System (OASIS), (2) any Customer-initiated

requests for discounts, including requests for use by one's wholesale

merchant or an affiliate's use, must occur solely by posting on the

OASIS, and (3) once a discount is negotiated, details must be

immediately posted on the OASIS. For any discount agreed upon for

service on a path, from Point(s) of Receipt to Point(s) of Delivery,

RMR must offer the same discounted transmission service rate for the

same time period to all Eligible Customers on all unconstrained

transmission paths that go to the same point(s) of delivery on the

Transmission System.

Effective

The first day of the first full billing period beginning on or

after April 1, 1998, through March 31, 2003.

Formula Rate

* * * * *

[GRAPHIC] [TIFF OMITTED] TN06AP98.013

Rate

The rate to be in effect April 1, 1998, through September 30, 1998,

is:

Maximum of:

Monthly: $2.32/kW of reserved capacity per month

Weekly: $0.54/kW of reserved capacity per week

Daily: $0.08/kW of reserved capacity per day

Hourly: 3.33 mills/kWh

This rate is based on the above formula and FY 1996 data. A

recalculated rate will go into effect every October based on the above

formula and updated financial and load data.

Rate Schedule L-NT1 (Supersedes L-T3) Attachment H to Tariff April 1,

1998

Annual Transmission Revenue Requirement for Network Integration

Transmission Service

Applicable

The Transmission Customer shall compensate the Rocky Mountain

Region (RMR) each month for Network Transmission Service pursuant to

the applicable Network Integration Service Agreement and annual revenue

requirement referred to below. The formula for the annual revenue

requirement used to calculate the charges for this service under this

[[Page 16796]]

schedule was promulgated and may be modified pursuant to applicable

Federal laws, regulations, and policies.

RMR may modify the charges for Network Integration Transmission

Service upon written notice to the Transmission Customer. Any change to

the charges to the Transmission Customer for Network Integration

Transmission Service shall be as set forth in a revision to this rate

schedule promulgated pursuant to applicable Federal laws, regulations,

and policies and made part of the applicable service agreement. RMR

shall charge the Transmission Customer in accordance with the revenue

requirement then in effect.

Effective

The first day of the first full billing period beginning on or

after April 1, 1998, through March 31, 2003.

Formula Rate

[GRAPHIC] [TIFF OMITTED] TN06AP98.014

If a Transmission Customer requires use of subtransmission

facilities, a specific facility use charge will be assessed in addition

to this formula rate.

If an existing Transmission Customer elects to retain its

Transmission Contract and the contract terms are payment on an energy

basis, the capacity-unit rate under the formula rate will be converted

to an energy-unit rate based on the individual customer's total load

factor.

* * * * *

Rate

The revenue requirement in effect April 1, 1998, through September

30, 1998, is $31,555,162. This revenue requirement is based on the

above formula and FY 1996 data. A recalculated revenue requirement will

go into effect every October based on the above formula and updated

financial and load data.

[FR Doc. 98-8938 Filed 4-3-98; 8:45 am]

BILLING CODE 6450-01-P