[Federal Register Volume 63, Number 65 (Monday, April 6, 1998)]
[Notices]
[Pages 16778-16796]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-8938]


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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