[Federal Register Volume 63, Number 155 (Wednesday, August 12, 1998)]
[Notices]
[Pages 43158-43175]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-21600]


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DEPARTMENT OF ENERGY

Western Area Power Administration


Pick-Sloan Missouri Basin Program, Eastern Division--Rate Order 
No. WAPA-79

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-79 
and Rate Schedules UGP-AS1, UGP-AS2, UGP-AS3, UGP-AS4, UGP-AS5, UGP-
AS6, UGP-FPT1, UGP-NFPT1, and UGP-NT1 placing formula rates into effect 
on an interim basis for firm and non-firm transmission on the 
Integrated System (IS) and ancillary services in Western Area Power 
Administration's (Western) Watertown control area.
    The charges for the transmission and ancillary services will be 
implemented on August 1, 1998. 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 reserved capacity on the 
Transmission System. The charges for ancillary services will be based 
on the cost of resources used to provide these services.

FOR FURTHER INFORMATION CONTACT: Mr. Robert F. Riehl, Rates Manager, 
Upper Great Plains Customer Service Region, Western Area Power 
Administration, P.O. Box 35800, Billings, MT 59107-5800, (406) 247-
7388, 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 (Secretary) 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

[[Page 43159]]

on a final basis, to remand, or to disapprove such rates to the Federal 
Energy Regulatory Commission (FERC).
    Rate Order No. WAPA-79, confirming, approving, and placing the IS 
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. These transmission and ancillary service formula 
rates are established pursuant to section 302 of 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 were 
transferred to, and vested in, the Secretary. Rate Order No. WAPA-79 
was prepared pursuant to Delegation Order No. 0204-108 (Delegation 
Order), existing DOE procedures for public participation in power rate 
adjustments in 10 CFR part 903, and procedures for approving Power 
Marketing Administration rates by the FERC in 18 CFR part 300. In 
addition to seeking final confirmation under the Delegation Order, 
Western requests the FERC review the proposed transmission rates for 
the Upper Great Plains Region (UGPR) for consistency with the standards 
of section 212 (a) of the Federal Power Act 16 U.S.C. 824k (a). In 
doing so, Western asks the FERC to determine that its rates are 
comparable to what it charges other customers and conform to the 
standards under the Delegation Order in a manner similar to the FERC's 
finding in United States Department of Energy-Bonneville Power 
Administration, 80 FERC para. 61,118 (1997).
    Western has separately filed for approval of generally applicable 
terms and conditions under its Open Access Transmission Tariff (Tariff) 
in Docket No. NJ98-1-000. These rate schedules will be utilized under 
the Tariff for service in the UGPR of Western, and they are potentially 
subject to FERC review under the standards of 16 U.S.C. 824k (a). 
Because Western's transmission rates were established in accordance 
with 10 CFR part 903, 18 CFR part 300 and the Delegation Order, if the 
rates submitted by Western are found to violate the statutory 
standards, they must be remanded to the Administrator for further 
proceedings.
    The new Rate Schedules UGP-AS1, UGP-AS2, UGP-AS3, UGP-AS4, UGP-AS5, 
UGP-AS6, UGP-FPT1, UGP-NFPT1, and UGP-NT1 will be promptly submitted to 
the FERC for confirmation and approval on a final basis.

    Dated: July 31, 1998.
Elizabeth A. Moler,
Deputy Secretary.

Order Confirming, Approving, and Placing the Pick-Sloan Missouri 
Basin Program, Eastern Division Transmission and Ancillary Service 
Formula Rates Into Effect on an Interim Basis

August 1, 1998.
    These transmission and ancillary service formula rates are 
established pursuant to the Department of Energy Organization Act (42 
U.S.C. 7101 et seq.), through which the power marketing functions of 
the Secretary of the Interior and the Bureau of Reclamation 
(Reclamation) under the Reclamation Act of 1902 (43 U.S.C. 371 et 
seq.), as amended and supplemented by subsequent enactments, 
particularly section 9(c) of the Reclamation Project Act of 1939 (43 
U.S.C. 485h(c)), and other acts specifically applicable to the project 
involved, were transferred to and vested in the Secretary of Energy 
(Secretary).
    By Amendment No. 3 to Delegation Order No. 0204-108 (Delegation 
Order), 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 Department of Energy (DOE) procedures for public 
participation in power rate adjustments are found in 10 CFR part 903. 
Procedures for approving Power Marketing Administration rates by the 
FERC are found in 18 CFR part 300. In addition to seeking final 
confirmation under the Delegation Order, Western requests the FERC 
review the proposed transmission rates for the Upper Great Plains 
Region (UGPR) for consistency with the standards of section 212 (a) of 
the Federal Power Act (FPA), 16 U.S.C. 824k (a). In doing so, Western 
asks the FERC to determine that its rates are comparable to what it 
charges other customers and conform to the standards under the 
Delegation Order in a manner similar to the FERC's finding in United 
States Department of Energy-Bonneville Power Administration, 80 FERC 
para. 61,118 (1997).
    Western has separately filed for approval of generally applicable 
terms and conditions under its Open Access Transmission Tariff (Tariff) 
in Docket No. NJ98-1-000. These rate schedules will be utilized under 
the Tariff for service in the UGPR of Western, and they are potentially 
subject to FERC review under the standards of 16 U.S.C. 824k(a). 
Because Western's transmission rates were established in accordance 
with 10 CFR part 903, 18 CFR part 300 and the Delegation Order, if the 
rates submitted by Western are found to violate the statutory 
standards, they must be remanded to the Administrator for further 
proceedings.

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........................  12-month coincident peak average.        
Ancillary Services...........  Those services that are necessary to     
                                support the transmission of capacity and
                                energy from resources to loads while    
                                maintaining reliable operation of the   
                                Transmission System in accordance with  
                                good utility practice.                  
A&GE.........................  Administrative and general expense.      
Basin Electric...............  Basin Electric Power Cooperative.        
Control Area.................  An electric system or systems, bounded by
                                interconnection metering and telemetry, 
                                capable of controlling generation to    
                                maintain its interchange schedule with  
                                other Control Areas and contributing to 
                                frequency regulation of the             
                                Interconnection.                        
Corps of Engineers...........  U.S. Army Corps of Engineers.            
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.                       

[[Page 43160]]

                                                                        
Emergency Energy.............  Electric energy purchased by an electric 
                                utility whenever an event on the system 
                                causes insufficient operating capability
                                to cover its own demand requirement.    
Energy Imbalance Service.....  A service which provides energy          
                                correction for any hourly mismatch      
                                between a Transmission Customer's energy
                                supply and the demand served.           
Federal Customers............  Western and Bureau of Reclamation        
                                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          Contracts for the sale of long-term firm 
 Contract.                      energy and capacity to Federal          
                                Customers, with contract rates of       
                                delivery based on an allocation of power
                                from the Federal generation resource.   
Firm Point-to-Point            Transmission service that is reserved and/
 Transmission Service.          or scheduled between Points of Receipt  
                                and Delivery.                           
Heartland....................  Heartland Consumers Power District.      
IS...........................  Integrated System.                       
ISO..........................  Independent System Operator.             
JTS..........................  Joint Transmission System.               
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.     
Load.........................  A customer or an end-use device that     
                                receives power from the Transmission    
                                System.                                 
LRS..........................  Laramie River Station is a coal-fired    
                                generation plant near Laramie, Wyoming. 
                                LRS is a part of the Missouri Basin     
                                Power Project (MBPP).                   
Load-ratio share.............  Ratio of the Network Transmission        
                                Customer's coincident hourly load       
                                (including its designated network load  
                                not physically interconnected with the  
                                Transmission Provider) to the           
                                Transmission Provider's monthly         
                                Transmission System peak, calculated on 
                                a rolling 12-month basis.               
Long-Term Firm Point-to-Point  Firm Point-to-Point Transmission Service 
 Transmission Service.          reservation with at least 12 consecutive
                                equal monthly amounts.                  
MAPP.........................  Mid-Continent Area Power Pool.           
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.                 
MBMPA........................  Missouri Basin Municipal Power Agency.   
MBSG.........................  Missouri Basin Systems Group.            
MVAR.........................  Megavar, equal to 1,000,000 VARs         
MW...........................  Megawatt; equal to 1,000 kW or 1,000,000 
                                watts.                                  
NEPA.........................  National Environmental Policy Act of     
                                1969.                                   
NERC.........................  North American Electric Reliability      
                                Council.                                
Network Customer.............  An entity receiving transmission service 
                                pursuant to the terms of the            
                                Transmission Provider's Network         
                                Integration Transmission Service of the 
                                Tariff.                                 
Non-Firm Point-to-Point......  Point-to-Point Transmission Service under
                                the Tariff that is reserved and         
                                scheduled on an as-available basis and  
                                is subject to interruption for economic 
                                reasons.                                
O&M..........................  Operation and maintenance expense.       
P-SMBP.......................  Pick-Sloan Missouri Basin Program.       
P-SMBP-ED....................  Pick-Sloan Missouri Basin Program-Eastern
                                Division.                               
Point-to-Point Transmission    The reservation and transmission of      
 Service.                       capacity and energy on either a firm or 
                                a non-firm basis from designated        
                                Point(s) of Receipt to designated       
                                Point(s) of Delivery.                   
Provisional Rate Schedule....  A Rate Schedule which has been confirmed,
                                approved, and placed in effect on an    
                                interim basis by the Deputy Secretary of
                                DOE.                                    
Reclamation..................  Bureau of Reclamation, U.S. Department of
                                the Interior.                           
Reactive Supply and Voltage    A service which provides reactive supply 
 Control From Generating        through changes to generator reactive   
 Sources Service.               output to maintain transmission line    
                                voltage and facilitate electricity      
                                transfers.                              
Regulation and Frequency       A service which provides for following   
 Response Service.              the moment-to-moment variations in the  
                                demand or supply in a Control Area and  
                                maintaining scheduled interconnection   
                                frequency.                              
Reserve Services.............  Spinning Reserve Service and Supplemental
                                Reserve Service.                        
Schedule.....................  An agreed-upon transaction size          
                                (megawatts), beginning and ending ramp  
                                times and rate, and type of service     
                                required for delivery and receipt of    
                                power between the contracting parties   
                                and the Control Area(s) involved in the 
                                transaction.                            
Scheduling, System Control,    A service which provides for (a)         
 and Dispatch Service.          scheduling, (b) confirming and          
                                implementing an interchange schedule    
                                with other control areas, including     
                                intermediary control areas providing    
                                transmission service, and (c) ensuring  
                                operational security during the         
                                interchange transaction.                
Service Agreement............  The initial agreement and any amendments 
                                or supplements thereto entered into by  
                                the Transmission Customer and Western   
                                for service under the Tariff.           
Short-Term Firm Point-to-      Firm Point-to-Point Transmission Service 
 Point Transmission Service.    with service of less duration than 1    
                                year.                                   
Spinning Reserve Service.....  Generation capacity needed to serve load 
                                immediately in the event of a system    
                                contingency. Spinning Reserve Service   
                                may be provided by generating units that
                                are on-line and loaded at less than     
                                maximum output. The Transmission        
                                Provider must offer this service when   
                                the transmission service is used to     
                                serve load within its Control Area. The 
                                Transmission Customer must either       
                                purchase this service from the          
                                Transmission Provider or make           
                                alternative comparable arrangements to  
                                satisfy its Spinning Reserve Service    
                                obligation.                             

[[Page 43161]]

                                                                        
Supplemental Reserve Service.  Generation capacity 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. Supplemental Reserve    
                                Service may be provided by generating   
                                units that are on-line but unloaded, by 
                                quick start generation or by            
                                interruptible load. The Transmission    
                                Provider must offer this service when   
                                the transmission service is used to     
                                serve load within its Control Area. The 
                                Transmission Customer must either       
                                purchase this service from the          
                                Transmission Provider or make           
                                alternative comparable arrangements to  
                                satisfy its Supplemental Reserve Service
                                obligation.                             
Supporting Documentation.....  Work papers which support the rate.      
System.......................  An interconnected combination of         
                                generation, transmission and/or         
                                distribution components comprising an   
                                electric utility, independent power     
                                producers(s) (IPP), or group of         
                                utilities and IPP(s).                   
Tariff.......................  Western Area Power Administration Open   
                                Access Transmission Service Tariff,     
                                Docket No. NJ98-1-000.                  
Transmission Customer........  Any eligible customer (or its designated 
                                agent) that receives transmission       
                                service under the Tariff.               
Transmission Provider........  Any utility that owns, operates, or      
                                controls facilities used for the        
                                transmission of electric energy in      
                                interstate commerce. UGPR, as operator  
                                of the IS, is the Transmission Provider 
                                for the purposes of this Federal        
                                Register notice.                        
Transmission System..........  The facilities owned, controlled, or     
                                operated by the Transmission Provider   
                                that are used to provide transmission   
                                service.                                
Transmission System Total      12-cp system peak for Network            
 Load.                          Transmission Service plus reserved      
                                capacity for all Firm Point-to-Point    
                                Transmission Service.                   
UGPR.........................  This is the Upper Great Plains Customer  
                                Service Region of the Western Area Power
                                Administration. Some places herein, UGPR
                                maybe referenced generically as Western.
VAR..........................  A unit of reactive power.                
WAUGP........................  The NERC acronym for the Western Area    
                                Upper Great Plains control area. This   
                                control area is also known as the       
                                Watertown Control Area.                 
Watertown Operations Office..  Western Area Power Administration, Upper 
                                Great Plains Customer Service Region,   
                                Operations Office, 1330 41st Street SE, 
                                Watertown, South Dakota 57201.          
Western......................  This is the Western Area Power           
                                Administration, U.S. Department of      
                                Energy. Some places herein, Western is  
                                represented by the Upper Great Plains   
                                Customer Service Region (UGPR).         
------------------------------------------------------------------------

Effective Date

    The Provisional Formula Rates will become effective on the first 
day of the first full billing period beginning on or after August 1, 
1998, and will be in effect pending the FERC's approval of them or 
substitute formula rates on a final basis through July 31, 2003, or 
until superseded. These formula rates will be applied under Western 
Area Power Administration Open Access Transmission Service Tariff 
(Tariff), Docket No. NJ98-1-000, and conform with the spirit and intent 
of the FERC Order No. 888. These rates are implemented pursuant to 
Schedules 1 through 8 and Attachment H of the Tariff.

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 Rates are for new services. Therefore, they represent 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. On March 28, 1997, UGPR distributed an Advance Announcement of 
Transmission Rate Adjustment to all UGPR customers and interested 
parties. UGPR gathered comments and suggestions on the advance 
announcement through May 2, 1997.
    2. UGPR published a Federal Register notice on September 15, 1997 
(62 FR 48272), officially announcing the proposed open access 
transmission and ancillary service 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 23, 1997, UGPR mailed a copy of the ``Upper Great 
Plains Region Proposed Open Access Transmission and Ancillary Service 
Rates'' brochure to all UGPR Transmission Customers and other 
interested parties. Comments received on the advance announcement were 
addressed in this brochure.
    4. UGPR held public information forums on October 16, 1997, in 
Billings, Montana, and October 17, 1997, in Sioux Falls, South Dakota. 
Western representatives explained the need for the rate adjustment in 
greater detail and answered questions.
    5. UGPR held comment forums on November 13, 1997, in Billings, 
Montana, and November 14, 1997, in Sioux Falls, South Dakota, to 
provide the public an opportunity to comment for the record. 
Representatives from seven organizations made comments at these forums.
    6. Fifty comment letters were submitted during the 90-day 
consultation and comment period. The consultation and comment period 
ended on December 15, 1997. All comments have been considered in the 
preparation of this Rate Order.

Comments

    Representatives of the following organizations made oral comments:


Basin Electric Power Cooperative, Bismarck, North Dakota
City of Sioux Center, Iowa
Minnesota Corn Processors, Marshall, Minnesota
Missouri Basin Municipal Power Agency, Sioux Falls, South Dakota
City of Marshall, Minnesota
Northwestern Public Service Company, Huron, South Dakota
Heartland Consumers Power District, Madison, South Dakota


[[Page 43162]]


    The following individuals and organizations submitted written 
comments:
Jon Christensen, Member of Congress, 2nd District Nebraska
Missouri Basin Municipal Power Agency, Sioux Falls, South Dakota
Doug Bereuter, Member of Congress, 1st District, Nebraska
Bill Barrett, Member of Congress, 3rd District, Nebraska
Basin Electric Power Cooperative, Bismarck, North Dakota
State of South Dakota, Pierre, South Dakota
Minnesota Valley Cooperative, Montevideo, Minnesota
Verendrye Electric Cooperative, Inc., Velva, North Dakota
Douglas Electric Cooperative, Inc., Armour, South Dakota
Charles Mix Electric Association, Inc., Lake Andes, South Dakota
Lake Region Electric, Webster, South Dakota
Union County Electric Cooperative, Inc., Elk Point, South Dakota
Bon Homme Yankton Electric Association, Inc., Tabor, South Dakota
East River Electric Power Cooperative, Madison, South Dakota
Whetstone Valley Electric Cooperative, Inc., Milbank, South Dakota
Renville Sibley Cooperative Power Association, Danube, Minnesota
Codington-Clark Electric Cooperative, Inc., Watertown, South Dakota
Traverse Electric Cooperative, Inc., Wheaton, Minnesota
Intercounty Electric Association, Inc., Mitchell, South Dakota
H-D Electric Cooperative, Inc., Clear Lake, South Dakota
Dakota Energy Cooperative, Inc., Huron, South Dakota
FEM Electric Association, Inc., Ipswich, South Dakota
Tri County Electric Association, Inc., Plankinton, South Dakota
Sioux Valley Southwestern Electric, Colman, South Dakota
McCook Electric Cooperative, Salem, South Dakota
Kingsbury Electric Cooperative, Inc., De Smet, South Dakota
Fort Peck Tribes, Poplar, Montana
Lyon-Lincoln Electric Cooperative, Inc., Tyler, Minnesota.
Central Power Electric Cooperative, Minot, North Dakota
City of Elk Point, South Dakota
Cooperative Power, Eden Prairie, Minnesota
Oahe Electric Cooperative, Inc., Blunt, South Dakota
Powder River Energy Corporation, Sundance, Wyoming
Nishnabotna Valley Rural Electric Cooperative, Harlan, Iowa
Northwest Iowa Power Cooperative, Le Mars, Iowa
Turner-Hutchinson Electric Cooperative, Inc., Marion, South Dakota
Oliver-Mercer Electric Cooperative, Inc., Hazen, North Dakota
Northern Electric Cooperative, Inc., Bath, South Dakota
Minnkota Power Cooperative, Inc., Grand Forks, North Dakota
Lincoln Electric System, Lincoln, Nebraska
Lincoln-Union Electric Company, Alcester, South Dakota
Western Iowa Power Cooperative, Denison, Iowa
Central Montana Electric Power Cooperative, Billings, Montana
Northern States Power Company, Minneapolis, Minnesota
Northwestern Public Service Company, by Law Offices of Wright & 
Talisman, P.C., Washington, DC
Nebraska Public Power District, York, Nebraska
Heartland Consumers Power District, comments submitted by Sutherland, 
Asbill & Brennan, LLP, Washington, DC
Mid-West Electric Consumers Association, Denver, Colorado

Pick-Sloan Missouri Basin Program-Eastern Division Project 
Description

    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. No. 78-534). It was later renamed the Pick-Sloan Missouri 
Basin Program (P-SMBP). The P-SMBP is 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.
    UGPR markets significant quantities of Federally generated 
hydroelectric power from the Pick-Sloan Missouri Basin Program-Eastern 
Division (P-SMBP-ED). Western owns and operates an extensive system of 
high-voltage transmission facilities which UGPR uses to market 
approximately 2,400 MW of capacity from Federal projects within the 
Missouri River Basin. This capacity is generated by eight powerplants 
located in Montana, North Dakota, and South Dakota. UGPR utilizes the 
transmission facilities of Western and others to market this power and 
energy to customers located within the P-SMBP-ED. This marketing area 
includes Montana, east of the Continental Divide, all of North Dakota 
and South Dakota, eastern Nebraska, western Iowa, and western 
Minnesota.

History of Transmission System

    Prior to 1959, Reclamation provided the total power supply needs to 
preference customers in the P-SMBP-ED marketing area. Reclamation 
constructed a Federal transmission system to supply power to those 
preference customers. In 1959, Reclamation notified the preference 
customers that it could no longer meet the total projected power needs 
past the year 1964 and urged these entities to make their own 
arrangements for supplemental power supply. Reclamation and certain 
supplemental power suppliers agreed to construct future transmission 
facilities within the region using a single system, joint planning 
concept.
    In 1963, the Joint Transmission System (JTS) was created when 
Reclamation and Basin Electric Power Cooperative (Basin Electric) 
entered into the Missouri Basin Systems Group (MBSG) Pooling Agreement 
(Agreement). In 1977, Western was established and assumed the 
responsibility for the Reclamation-owned Federal transmission system 
and existing contracts. Heartland Consumers Power District (Heartland) 
and Missouri Basin Municipal Power Agency (MBMPA) were organized in the 
mid-1970's and subsequently signed the MBSG Agreement. Basin Electric, 
Heartland, and MBMPA all supply supplemental power to certain 
preference customers and are commonly referred to as supplemental power 
suppliers. The MBSG Agreement provided for joint planning and operation 
of some, but not all, of the transmission facilities for the JTS 
participants. Since then, the JTS participants have augmented the 
existing Federal transmission system, using a single system, joint 
planning concept, rather than build separate transmission systems 
themselves. Specific JTS rights and obligations are detailed in 
bilateral agreements between Western and the participants.
    The MBSG Agreement also provides a mechanism for sharing the cost 
of the transmission facilities that considers the participants' 
ownership of the transmission facilities that comprise the JTS. The JTS 
cost-sharing method is based upon the concept that the original 
facilities were capable of delivering the Federal generation to load 
plus approximately 200 MW, per studies performed in the 1963 timeframe. 
Basin

[[Page 43163]]

Electric's Leland Olds No. 1 generator was the first generation added 
and was 210 MW.
    The next generation addition did not occur until after 1969. 
Studies for each increment of generation thereafter demonstrated a need 
for transmission additions. Western had sufficient capacity in its 
original system to serve its own load, and since neither its generation 
nor its load was increasing, did not need the additional facilities to 
deliver to its loads. Therefore, it was agreed Western would not share 
in the cost of additional facilities provided by others. However, 
Western would share in the revenues generated by the system to the 
extent Western provided facilities and incurred investment costs after 
1969. The post-1969 additions are the basis for the cost-sharing 
ratios.
    The JTS cost-sharing method is as follows. Costs for the JTS are 
summed for Western, Basin Electric, Heartland, and MBMPA to arrive at a 
total transmission system cost. The total transmission system cost for 
the year is divided by the generation input for the year (4,127,000 kW 
for 1997) to determine the JTS cost per kW-year of generation input. 
The JTS participants, except Western, then pay into the JTS according 
to their generation input. These JTS revenues are then distributed back 
to the participants, including Western, based upon the ratio of costs 
associated with contributed facilities constructed since 1969.

Integrated System Description

    Utilizing the single system, joint planning concept created by 
MBSG, the UGPR, Basin Electric, and Heartland combined their 
transmission facilities to form the Integrated System (IS) and herein 
develop transmission and ancillary service rates for transmission over 
the IS. This action is necessary because UGPR, Basin Electric and 
Heartland, whose facilities are fully integrated, did not have rates 
suitable for long-term open access Transmission Service. The 
transmission facilities included in the IS are transmission lines, 
substations, communication equipment, and facilities related to 
operation, maintenance, and support of the Transmission System. UGPR 
has been designated as the operator of the other participants' 
transmission facilities and as such will contract for service, 
determine and post on the Open Access Same-Time Information System 
available transmission capacity, bill for service, collect payments, 
distribute revenue to each participant, etc. The IS consists of the 
transmission facilities owned by Basin Electric and Heartland east of 
the East-West electrical separation in the United States, the 
transmission facilities owned by Western in the P-SMBP-ED, and the 
Miles City DC Tie owned by Western and Basin Electric. These facilities 
interconnect with utilities in the states of Montana, North Dakota, 
South Dakota, Nebraska, Iowa, Minnesota, and Missouri and in addition 
include facilities which interconnect with Canada.
    The approach for formation of the IS was to include facilities 
which followed the spirit and intent of the FERC Order No. 888 and to 
make the system most useful to all transmission requesters. The ``seven 
factor test'' defined in the FERC Order No. 888 was used to determine 
the distribution facilities that were excluded from the IS Transmission 
System. Several major facilities which were not a part of the JTS have 
been included in the IS. The second 345-kV transmission line between 
the Antelope Valley and Leland Olds generating stations, which meets 
the standards for acceptable transmission facilities set in the FERC 
rulings on filings by other transmission entities, has been included. 
The 230-kV transmission line between Tioga, North Dakota, and Boundary 
Dam, which provides access to generation and loads in Canada, has been 
included in the IS. The IS also includes the Miles City DC Tie, which 
opens the markets between the East-West electrical separation of the 
United States and increases access to other utilities. The IS differs 
from the JTS in that it does not include the Laramie River Station 
(LRS) transmission facilities. These facilities were not considered for 
inclusion in the IS since agreement of all the Missouri Basin Power 
Project (MBPP) participants would be required.

IS Transmission Service

    UGPR will offer Network Integration (Network), Firm Point-to-Point 
and Non-Firm Point-to-Point (Point-to-Point) Transmission Service on 
the IS. The service offered is the transmission of energy and capacity 
from Points of Receipt to Points of Delivery on the IS. The IS 
Transmission Rates include the cost of Scheduling, System Control, and 
Dispatch Service, therefore an additional charge for this ancillary 
service is not required for transmission users.
    Western, Basin Electric, and Heartland will take IS Transmission 
Service. Transmission Service to UGPR's Federal customers will continue 
to be bundled in their Firm Electric Service rate under existing 
contracts which expire in 2020.
    UGPR prepared a cost of service study to develop the formula rates 
for the IS. UGPR is seeking approval of formula rates for calculation 
of Point-to-Point IS Transmission Rates, the Network IS Transmission 
Service revenue requirement, and ancillary service rates. UGPR is 
requesting the FERC to confirm that these rates are not unjust, 
unreasonable, unduly discriminatory, or preferential. The rates will be 
recalculated every year, effective May 1, based on the approved formula 
rates and updated financial and load data. UGPR will provide customers 
notice of changes in rates no later than April 1 of each year.

Ancillary Services

    UGPR will offer to all customers the six ancillary services defined 
by the FERC. The six ancillary services are: (1) Scheduling, System 
Control, and Dispatch Service; (2) Reactive Supply and Voltage Control 
from Generation Sources Service; (3) Regulation and Frequency Response 
Service; (4) Energy Imbalance Service; (5) Spinning Reserves Service; 
and (6) Supplemental Reserves Service. The open access ancillary 
service formula rates are designed to recover only the costs incurred 
for providing the service(s). The charges for ancillary services are 
based on the cost of resources used to provide these services.

Existing and Provisional Rates

    The following is a comparison of existing rates, and the 
Provisional Rates using 1997 data. These rates will be updated annually 
based on the approved formula rates. This is the first transmission 
rate filing made by the P-SMBP-ED. Prior to this, transmission services 
were provided through bilateral contract arrangements, therefore there 
is not an existing rate schedule for comparison.

[[Page 43164]]



          Comparison of Existing and Provisional Formula Rates          
------------------------------------------------------------------------
                                  Existing rate     Rate schedule August
       Class of service         schedule and rate         1, 1998       
------------------------------------------------------------------------
Network Transmission..........  N/A                UGP-NT1, Load-ratio  
                                                    share of 1/12 of the
                                                    Annual Revenue      
                                                    Requirement for IS  
                                                    Transmission Service
                                                    of $95,725,420.     
Firm Point-to-Point             N/A                UGP-FPT1, Maximum of 
 Transmission.                                      $2.87/kW-month.     
Non-Firm Point-to-Point         N/A                UGP-NFPT1, Maximum of
 Transmission.                                      3.93 mills/kWh.     
Scheduling, System Control,     N/A                UGP-AS1, $46.06 per  
 and Dispatch.                                      schedule per day for
                                                    non-transmission    
                                                    customers.          
Reactive Supply and Voltage     N/A                UGP-AS2 $0.07/kW-    
 Control from Generation                            month.              
 Sources.                                                               
Regulation and Frequency        N/A                UGP-AS3, $0.05/kW-   
 Response.                                          month.              
Energy Imbalance..............  N/A                UGP-AS4, For negative
                                                    excursions outside  
                                                    of 3 percent        
                                                    bandwidth UGPR      
                                                    reserves the right  
                                                    to charge 100 mills/
                                                    kWh. Positive       
                                                    excursions outside  
                                                    the bandwidth will  
                                                    be lost to the      
                                                    system.             
Spinning/Supplemental Reserves  N/A                UGP-AS5 and 6, $0.12/
                                                    kW-month of customer
                                                    load.               
------------------------------------------------------------------------

Certification of Rates

    Western's Administrator has certified the transmission and 
ancillary service 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.

IS Transmission Service Discussion

    The formula rates for Network and Point-to-Point Transmission 
Service will be implemented August 1, 1998. The rates will be 
recalculated annually based on updated financial and load data. Network 
service charges will be based on the Transmission Customer's load-ratio 
share of the annual revenue requirement for transmission. Firm Point-
to-Point service will be based on reserved capacity on the Transmission 
System.
    IS Transmission System Total Load: The IS Transmission System Total 
Load is the 12-cp system peak for Network Transmission Service plus the 
reserved capacity for all Long-Term Firm Point-to-Point Transmission 
Service.
    The IS Transmission System Total Load is calculated as follows 
based upon 1997 data:

------------------------------------------------------------------------
                                                                  kW    
------------------------------------------------------------------------
Network Transmission Load..................................    2,447,000
Long-Term Firm Point-to-Point Reserved Capacity............      331,000
                                                            ------------
IS Transmission System Total Load..........................    2,778,000
------------------------------------------------------------------------

    Annual Costs: Western has calculated the annual cost of providing 
the various transmission and ancillary services using a FERC recognized 
methodology for annual cost calculation with fixed charge rates for 
various cost components. The cost components applicable to Western 
include operation and maintenance (O&M), administrative and general 
expense (A&GE), depreciation, and the cost of capital. These components 
are displayed as fixed charge rates or percentages of net investment. 
These fixed charge rates are then summed to arrive at a total fixed 
charge rate associated with the particular service for which a rate is 
being calculated. The fixed charge rate calculation for the various 
transmission and ancillary services can be summarized with the 
following formula:

+ O&M  Net investment
+ A&GE  Net investment
+ Depreciation expense  Net investment
+ Annual interest expense  Unpaid investment balance
= Total fixed charge rate.

    To arrive at the annual cost of providing transmission service or 
one of the ancillary services, the total fixed charged rate is applied 
to the net investment allocated to the service as follows:
    Total fixed charge rate  x  Net investment = Annual cost of 
providing service.
    The source for UGPR's annual O&M, A&GE, depreciation expense, 
interest expense, and investment is the Results of Operations for the 
Upper Great Plains Customer Service Region--Pick-Sloan Missouri Basin. 
The source for unpaid investment balances is the amount reported in the 
Historical Financial Document in Support of the Power Repayment Study 
for the Pick-Sloan Missouri Basin Program. The source for Heartland's 
data is Heartland Consumers Power District Annual Report. The sources 
for Basin Electric's data are Basin Electric's Consolidated Financial 
Statement, Rural Utility Service Form 12, and other accounting records.
    Annual Revenue Requirement for IS Transmission Service: The rates 
for IS Transmission Service (Network and Point-to-Point) are based on a 
revenue requirement that recovers the annual costs of Western, Basin 
Electric, and Heartland associated with providing IS Transmission 
Service plus any facility credits paid to Transmission Customers. The 
revenue requirement for IS Transmission Service includes the cost for 
Scheduling, System Control, and Dispatch Service needed to provide 
transmission service, therefore an additional charge for this ancillary 
service is not required for transmission users. The annual transmission 
costs are offset by appropriate transmission revenue credits to avoid 
over recovery of costs. The Annual Revenue Requirement for IS 
Transmission Service can be summarized with the following formula:
    Annual IS transmission costs of UGPR, Basin Electric, and Heartland

+ Transmission Customer facility credits
- Transmission revenue credits
= Annual Revenue Requirement for IS Transmission Service.

    Using 1997 data, the Annual Revenue Requirement for IS Transmission 
Service is:

$116,340,141
+ $194,444
- $20,809,165
= $95,725,420

    Transmission Customer facility credits are credits paid to 
Transmission Customers for facilities that are integrated with the IS 
and increase both the capability and the reliability of the IS. The 
credits will be addressed in individual agreements, and appropriate 
adjustments will be made in subsequent rate calculations. The IS 
participants will evaluate requests for facility credits consistent 
with the FERC's guidance in the FERC Order No. 888, other relevant FERC 
policy, and the terms of the Tariff.
    Transmission revenue credits include revenue from sales of Non-
Firm,

[[Page 43165]]

discounted Firm, and Short-Term Firm Point-to-Point Transmission 
Service; revenue from existing transmission agreements; revenue from 
Scheduling, System Control, and Dispatch Services; and any facility 
charges for transmission facility investments included in the revenue 
requirement. The following revenue credits have been applied in the IS 
Transmission Rate. The estimated Non-Firm Point-to-Point Transmission 
Service credit of $11,531,175 is based on 1997 non-firm energy sales on 
the IS Transmission System and actual sales of Non-Firm Point-to-Point 
Transmission Service on the IS Transmission System during 1997. Revenue 
from existing transmission agreements was $9,277,990 in 1997.
    Network IS Transmission Service: The monthly charge for Network IS 
Transmission Service is the product of the Network Customer's load-
ratio share times one-twelfth (1/12) of the Annual Revenue Requirement 
for IS Transmission Service of $95,725,420. The load-ratio share is the 
ratio of the Network Customer's coincident hourly load to the monthly 
IS Transmission System peak minus the coincident peak for all IS Firm 
Point-to-Point Transmission Service plus the IS Firm Point-to-Point 
reservations, calculated on a rolling 12-cp basis.
    Firm Point-to-Point IS Transmission Service: The rate for Firm 
Point-to-Point IS Transmission Service is the Annual Revenue 
Requirement for IS Transmission Service divided by the IS Transmission 
System Total Load. The formula for the monthly rate is as follows: 
Annual Revenue Requirement for IS Transmission Service  IS 
Transmission System Total Load  12 months, or, using 1997 data, 
$95,725,420  2,778,000 kW  12 months. The formula 
produces a rate of $2.87/kW-month for Firm Point-to-Point Transmission 
Service. Firm Point-to-Point Transmission Service will be offered on an 
``up to'' basis at daily, weekly, monthly, and yearly rates.
    Non-Firm Point-to-Point IS Transmission Service: Non-Firm Point-to-
Point IS Transmission Service will be offered at a rate up to, but 
never higher than, the Firm Point-to-Point rate. The formula for the 
rate is as follows: Monthly Firm Point-to-Point Rate  730 
hours/month, or using 1997 data, $2.87/kW-month  730 hours/
month. The formula produces a rate of 3.93 mills/kWh. Non-Firm Point-
to-Point IS Transmission Service will be offered at hourly, daily, 
weekly, and monthly rates.

Transmission Service Comments

    The following comments were received during the public comment 
period. UGPR paraphrased and combined comments when it did not affect 
the meaning. UGPR's response follows each comment. Changes were made in 
the formula rates and calculations as a result of the comments noted.
    Comment: UGPR should use the IS to provide open access transmission 
and ancillary services. The following comments were made in support of 
this comment. IS is consistent with the FERC Order No. 888. The system 
is integrated since the facilities are jointly planned, constructed, 
and operated as one system. The system cannot be divided into separate 
systems defined by ownership and still serve its function as a 
reliable, efficient Transmission Provider. One IS rate eliminates 
pancaking of transmission tariffs and maximizes facility usage. IS will 
maintain the postage stamp rate concept of paying once to travel 
anywhere on the system. The IS will minimize revenue shifts.
    Response: Western concurs with these comments.
    Comment: Western should remove any end-use-load-serving substations 
and transmission facilities. UGPR should use the ``seven factor test'' 
to determine the facilities to exclude from the IS.
    Response: UGPR has re-evaluated the facilities to be included in 
the IS using the ``seven factor test'' and made appropriate adjustments 
to the cost. Based upon the re-evaluation, UGPR removed appropriate 
end-use-load-serving substation and transmission line costs from the 
Annual Revenue Requirement for IS Transmission Service.
    Comment: UGPR should explain guidelines used to determine the 
allocation of transmission facility and substation revenue requirements 
to generation versus transmission.
    Response: UGPR evaluated the substations and transmission lines 
based on their usage (generation versus transmission). The substation 
and transmission line costs were then included in their respective 
categories. Watertown Operations Office costs were split based on the 
classification of Full Time Equivalent employees in generation or 
transmission. Communication facilities were split based on 
communication circuit usage.
    Comment: UGPR should exclude the cost of non-Federal facilities and 
develop a ``Western only'' rate. UGPR should remove Western's and Basin 
Electric's generator step-up transformers, West-side facilities, the 
Miles City DC Tie, and Basin Electric's generator outlet lines. UGPR 
should include Heartland's LRS transmission facilities. UGPR should 
consider separate rates for the East and West regions of its system.
    Response: UGPR, Basin Electric, and Heartland facilities are 
integrated. The rate includes each entity's facilities that are 
integrated. Therefore, it is inappropriate to develop a ``Western 
only'' rate.
    The FERC has allowed generator step-up transformers to be included 
in transmission rates. Western's costs include step-up transformers in 
the Corps switchyards which perform a transmission function. Basin 
Electric's costs also include step-up transformers.
    Western, Basin Electric, and Heartland have separated their costs 
between transmission and generation and have included only transmission 
related costs in the Transmission Service revenue requirement. Basin 
Electric's high-voltage lines referred to as ``generator outlet lines'' 
meet the ``seven factor test'' and are, therefore, included in the 
Transmission Service revenue requirement.
    The IS participants did not consider the LRS facilities for 
inclusion in the IS since agreement of all the MBPP participants would 
be required.
    UGPR operates under a unique situation in that it utilizes 
generation and transmission facilities located on both sides of the 
East-West electrical separation in Montana to meet its responsibilities 
in the Mid-Continent Area Power Pool (MAPP). UGPR has always operated 
all of its facilities on a single system basis. UGPR has marketed the 
generation plants on both sides of the electrical separation across the 
entire P-SMBP-ED and integrated deliveries from its resources for 
service to all UGPR power customers. The FERC has held that when an 
entity is able to adjust, second-by-second, the power flows over its 
entire system, including direct current ties, to integrate resources, 
the entity is utilizing its system as a single integrated transmission 
system and has allowed total system costs to be rolled into the IS 
Transmission Rate. The Miles City DC Tie provides some instantaneous 
support to the East-side transmission system and therefore contributes 
to the security aspect of reliability as defined by the North American 
Electric Reliability Council (NERC). The Miles City DC Tie provides 
reliability benefits to MAPP by instantaneously responding to 
disturbances on the East-side transmission systems through MW

[[Page 43166]]

reductions and MVAR support. Therefore, the Miles City DC Tie and the 
transmission facilities in the East and West regions of the UGPR system 
are included in the IS rates.
    Comment: If UGPR changes its rates to the IS rates which recover 
the cost of Basin Electric and Heartland facilities, it will cause 
Western's firm power rate to increase.
    Response: Western has existing bilateral contracts with Basin 
Electric and Heartland. Western will continue the benefits and 
obligations contained in those contracts through their terms. The 
continuation of those benefits will minimize any firm power rate 
impacts which may result from the use of the IS by Western for the 
delivery of firm power.
    Comment: Several comments made in the public process have compared 
the existing JTS rate used in the bilateral agreements between Western, 
Basin Electric, and Heartland to the proposed rate and have stated that 
the JTS rate is either below cost or the IS rates are inflated. Their 
comparisons and arguments are based on a JTS rate of $26.27/kW-year and 
an IS rate of $36.84/kW-year.
    Response: The JTS rate is a cost-based rate for the combined 
facilities of Western, Basin Electric, Heartland, and MBMPA. The rate 
itself is applied to each participants' connected generation and other 
resource inputs. A generation or input based rate, like JTS, includes 
planning reserves (15 percent), losses (approximately 4 percent), 
surplus generation and the load in the billing units for recovery of 
the cost.
    The IS rate is a cost-based rate for the combined facilities of 
Western, Basin Electric, and Heartland. In addition, MBMPA has asked 
and will receive credit for certain facilities at Irv Simmons 
Substation. The rate is applied to the loads on the Transmission 
System. A load-based rate, like the IS rate, includes only the load in 
the billing units for the recovery of cost.
    Input-based billing units and load-based billing units are not 
directly comparable. Although input-based rates (JTS) and load-based 
rates (IS) recover equivalent costs, they have different billing units. 
Therefore, the representation of the rate in $/kW-year is not identical 
and cannot be compared one-for-one. If each rate is applied to the 
correct billing units they both recover the total and appropriate 
costs.
    Comment: UGPR firm power customers should not be required to 
recover Basin Electric's and Heartland's stranded costs.
    Response: The rate design for the IS does not recover the stranded 
costs of any parties (Western, Basin Electric, or Heartland). If costs 
are determined to be stranded they will be addressed in a separate 
contract between the entity holding the stranded costs and the 
Transmission Customer, as described in the Tariff filed by Western in 
Docket No. NJ98-1-000.
    Comment: Who will review the costs for Basin Electric and Heartland 
to determine whether they are appropriate, and what recourse do the 
customers have to question the costs?
    Response: Basin Electric and Heartland have submitted their data as 
a part of this public process. In addition, their data is and will 
continue to be submitted to MAPP, just as any other transmission-owning 
MAPP member.
    On or about April 1 of each year the updated transmission cost data 
for Western, Basin Electric, and Heartland will be available for 
review. At this time a notice will be sent to Transmission Customers of 
changes to the rates that will be effective May 1.
    The Transmission Customers' recourse is similar to any other entity 
in a public process or in the course of MAPP review.
    Comment: Western should ask the FERC to review the Open Access 
Transmission and Ancillary Service Rates for consistency with the 
standards of Section 212 of the FPA.
    Response: In addition to seeking final confirmation under the 
Delegation Order, Western is requesting the FERC review the proposed 
transmission rates for the UGPR for consistency with the standards of 
section 212 (a) of the FPA, 16 U.S.C. 824k (a). In doing so, Western is 
asking the FERC to determine that its rates are comparable to what it 
charges other customers and conform to the standards under the 
Delegation Order in a manner similar to the FERC's finding in United 
States Department of Energy-Bonneville Power Administration, 80 FERC 
para. 61,118 (1997).
    Western has separately filed for approval of generally applicable 
terms and conditions under its Tariff in Docket No. NJ98-1-000. These 
rate schedules will be utilized under the Tariff for service in the 
UGPR of Western, and they are potentially subject to FERC review under 
the standards of 16 U.S.C. 824k (a).
    Comment: Basin Electric's cost of capital calculation should be 
adjusted as follows: (1) the interest expense shown on page 89, line 9, 
column (b) in the brochure should be used in the calculation; (2) a 7 
percent return on equity should be used; (3) Basin Electric's total 
cost of capital should be divided by its total capitalization rather 
than net plant investment to arrive at Basin Electric's weighted cost 
of capital.
    Response: Basin Electric used the interest expense shown on Rural 
Utility Service Form 12a, line 22, column b. This amount is the actual 
interest expense for the year. The interest expense shown on page 89 of 
the brochure is based on an accrual schedule rather than actual 
interest expense.
    Basin Electric has no basis for using a 7 percent return on equity. 
In the revenue requirement calculation in this Federal Register notice, 
Basin Electric utilizes the 10 percent margin for interest it charges 
its members which equates to a return on equity of approximately 9 
percent. Since Basin Electric now uses its margin for interest to 
calculate its cost of capital, issue (3) above is no longer relevant.
    Comment: Heartland should reduce their return on equity from 13 
percent to 7 percent because 13 percent far exceeds the return on 
equity the FERC is allowing investor-owned utilities.
    Response: Heartland has no basis for using a 7 percent return on 
equity. In this Federal Register notice Heartland calculated its cost 
of capital using its bond covenant requirement, similar to Basin 
Electric's margin for interest method. Heartland is required by Section 
8.2 of its Bond Resolution to maintain rates at such levels that when 
revenues from rates are combined with other funds that the total amount 
will be sufficient to meet 1.15 times the debt service coverage 
requirement. Heartland develops rates for its customers on this basis, 
and it therefore uses the same approach here.
    Comment: Basin Electric should allocate A&GE and general plant 
costs between IS transmission facilities and other transmission 
facilities and only include the portion allocated to IS transmission 
facilities in the IS Transmission System revenue requirement.
    Response: UGPR agrees with this comment, and Basin Electric's costs 
have been adjusted accordingly.
    Comment: The IS rate causes some MBMPA members to pay twice for the 
same transmission service.
    Response: The MBMPA members will not pay twice for usage of the IS 
for the same service. Members of MBMPA will pay for transmission and 
ancillary services on the MBMPA resource separately from the service 
they receive from Western in its bundled firm power service.
    Comment: Western is not charging itself for the Basin Electric and 
Heartland costs. Therefore, the rates it charges itself are not 
comparable.

[[Page 43167]]

    Response: Western will be taking all service under the IS rates and 
therefore is charging itself for the Basin Electric and Heartland 
costs. Cost sharing benefits and obligations associated with service 
under existing bilateral contracts will continue until contract 
expiration.
    Comment: The IS should provide for discounted rates.
    Response: Western's Tariff and IS rates allow for ``up to'' rates 
for the Firm and Non-Firm Point-to-Point Transmission Service rates. IS 
rates, including discounts to those rates, will be posted on the MAPP 
Open Access Same-Time Information System (OASIS) and will be available 
under the terms and conditions as posted.
    Comment: Basin Electric Class A member loads and Western's 
preference customer loads should be treated as native load in the 
determination of the IS rates.
    Response: Basin Electric Class A member loads and Western's 
preference customer loads are treated as native load and are included 
in the IS Network load.
    Comment: Western should remove the portion of its power supply and 
marketing expenses associated with power marketing from its O&M 
expenses.
    Response: Western removed purchase power costs from O&M expenses. 
In addition, Western's remaining O&M expenses (including power 
marketing) were split between generation and transmission based on the 
ratio of generation investment to total investment and transmission 
investment to total investment respectively. Only the portion of O&M 
expenses assigned to transmission was included in the transmission 
rate.
    Comment: Western should use actual non-firm sales to calculate the 
revenue credit for Western's use of the Transmission System to make 
non-firm sales.
    Response: Western agrees with this comment and has used actual 1997 
non-firm sales in the calculation of the IS Transmission Rate.
    Comment: The load associated with existing transmission contracts 
should be included in the load denominator rather than as a revenue 
credit.
    Response: Western did not include the transactions covered under 
existing transmission contracts in the IS load because these 
transactions are at discounted rates and including them in the load 
would cause under recovery of the IS revenue requirement. As these 
transmission contracts expire and the loads associated with them are 
converted to Western's Tariff and IS Transmission Rates, they will be 
included in the IS load.
    Comment: Western adjusted Basin Electric's Network load for Western 
peaking power service received, Dakota Gasification Company (DGC) load, 
and Neal IV generation but has not explained or justified these 
adjustments. Western should explain or correct this calculation.
    Response: Firm peaking power service sold to Basin Electric was 
adjusted out of Basin Electric's Network load and included in Western's 
Network load because Western is responsible for transmission of peaking 
power service. DGC load was adjusted out of Basin Electric's Network 
load in the September 15, 1997, proposed IS Transmission Rates. DGC 
load is included in Basin Electric's Network load in the IS 
Transmission Rates in this Federal Register notice. Basin Electric's 
load served by Neal IV generation is adjusted out of Basin Electric's 
Network load because it does not utilize the IS Transmission System.
    Comment: MAPP Service Schedule F payments to the IS participants 
should be shown separately as revenue credits to Western, Basin 
Electric, and Heartland revenue requirements since these revenues are 
received separately.
    Response: In the proposed IS rates, estimates of MAPP Service 
Schedule F payments were shown separately for each IS participant as 
the ``Calculated Value of Non-Firm Point-to-Point Transmission 
Services.'' As the operator of the IS system, Western anticipates 
receiving all MAPP Service Schedule F payments made to the IS 
participants and then distributing these revenues back to the 
participants according to the IS agreement.
    Comment: Several comments were received that Western does not have 
the authority to develop an IS Transmission Rate with Basin Electric 
and Heartland based upon its ratemaking requirements.
    Response: Western's authority to develop an IS Transmission Rate is 
derived from the DOE Organization Act (42 U.S.C. 7101 et. seq.), and 
the Reclamation Act of 1902 (43 U.S.C. 371 et. seq.), as amended and 
supplemented by subsequent enactments. Western's Administrator has been 
given wide discretion in fulfilling those power marketing functions. 
Western's use of the IS rate is also consistent with the DOE policy 
regarding Power Marketing Administration's compliance with the spirit 
and intent of the FERC Order No. 888 and the FERC's preference for 
regional transmission groups.
    Western's role as the operator of the IS is analogous to the 
responsibility it had with the JTS. Western was responsible for 
collection of funds from non-Federal participants and then distributed 
those funds based upon contractual obligations. Western has also 
approved the rate developed pursuant to the contracts between the JTS 
members on a 2-year basis prior to implementation. Western is the 
operator of the JTS and is responsible for establishing whether new 
uses of the JTS could be entertained and meet established reliability 
criteria.
    Western was established pursuant to sections 302(a)(1) (E) and (F) 
and 302(a)(3) of the DOE Organization Act. Section 302(a)(11)(E) 
transferred to Western the power marketing functions of Reclamation, 
including the construction, operation, and maintenance of transmission 
lines, and attendant facilities. Western is complying with the 
expressed ratemaking authority contained in section 9(c) of the 
Reclamation Act of 1939 as well as section 5 of the Flood Control Act 
of 1944. Section 9(c) states that:

    Any sale of electric power or lease of power privileges, made by 
the Secretary in connection with the operation of any project or 
division of a project, shall be for such periods, not to exceed 
forty years and at such rates as in his judgment will produce power 
revenues at least sufficient to cover an appropriate share of the 
annual operation and maintenance cost, * * *

    The IS rate does ensure that Western will recover an appropriate 
share of the investment in the Federal transmission facilities in the 
associated projects.
    Development of the IS Transmission Rate is also consistent with 
section 5 of the Flood Control Act of 1944. Section 5 provides:

    Electric power and energy generated at reservoir projects under 
the control of the War Department and in the opinion of the 
Secretary of War not required in the operation of such projects 
shall be delivered to the Secretary of the Interior, who shall 
transmit and dispose of such power and energy in such manner as to 
encourage the most widespread use thereof at the lowest possible 
rates to consumers consistent with sound business principles, the 
rate schedules to become effective upon confirmation and approval by 
the Federal Power Commission. Rate schedules shall be drawn having 
regard to the recovery (upon the basis of the application of such 
rate schedules to the capacity of the electric facilities of the 
projects) of the cost of producing and transmitting such electric 
energy, including the amortization of the capital investment 
allocated to power over a reasonable period of years. Preference in 
the sale of such power and energy shall be given to public bodies 
and cooperatives. The Secretary of Interior is authorized, from 
funds to be appropriated by the Congress to construct or acquire, by 
purchase or other agreement, only such

[[Page 43168]]

transmission lines and related facilities as may be necessary in 
order to make the power and energy generated at said projects 
available in wholesale quantities for sale on fair and reasonable 
terms and conditions to facilities owned by the Federal government, 
public bodies, cooperatives, and privately owned companies. All 
moneys received from such sales shall be deposited in the Treasury 
of the United States as miscellaneous receipts.

    Development of the IS Transmission Rate by Western is consistent 
with the obligation to transmit and dispose of power and energy while 
encouraging widespread use of the Federal facilities consistent with 
sound business practices. The integration of the Federal facilities 
with the non-Federal facilities enables the marketing of Western's 
resource as well as encouraging the widespread use of the Federal 
transmission facilities in the Missouri River Basin. As stated above, 
this philosophy is repaying the Federal investment through the rate 
schedules as they are recovering the appropriate costs of producing and 
transmitting that resource. This practice is also a sound business 
principle given the current FERC philosophy which encourages widespread 
use of transmission resources.
    Section 5 of the Flood Control Act of 1944 also permits Western to 
construct or acquire transmission lines that are necessary to deliver 
the Federal resource. In order to deliver that resource, including 
sales of surplus generation sold on a non-firm basis, and meet 
Western's contractual obligations, it is necessary to use the IS for 
reliability reasons. This has been confirmed in the Initial Decision in 
Missouri Basin Municipal Power Agency, 82 FERC para. 63,015 (1998).
    Comment: Several comments received stated that Western is violating 
the Anti-Deficiency Act and various fiscal obligations by participating 
in the IS.
    Response: The Anti-Deficiency Act, 31 U.S.C. 1341(a)(1), states 
that an officer of the Federal Government may not involve the 
Government in a contract or obligation requiring the payment of money 
prior to an appropriation unless authorized by law. Western has the 
responsibility to meet all of its contractual obligations that have 
been incurred pursuant to Reclamation Law. Western is annually 
appropriated money to perform its mission, including meeting the 
obligations it has incurred pursuant to its contracting authority. 
Western does utilize the IS to meet these contractual obligations, and 
hence money has been appropriated to carry out the functions as 
described under the DOE Organization Act. In addition, Western's 
contracts contain General Power Contract Provisions which specifically 
state that any activity provided for under those contracts are 
``contingent on appropriations.''
    Comment: Other comments received stated that Federal law prohibits 
``payments to third parties.''
    Response: To the contrary, 16 U.S.C. 833(i) and 825(s) do not state 
that third party payments are unlawful. They do not address third party 
payments at all. They do contain language indicating Congress' 
intention that all money which the United States receives from sales of 
power generated at Fort Peck Project and the Projects under control of 
the War Department (now the Corps operated facilities) are to be 
deposited in Treasury. Western is not violating this statute as a 
result of operating the IS. Western will deposit money it receives for 
debts due the United States for sales of its resource into the Treasury 
in the same manner it has in the past. However, money received on 
behalf of Basin Electric and Heartland will not be received as a result 
of debts owed to the United States, but will be received for debts owed 
Basin Electric and Heartland. Therefore, money received on their behalf 
is not required to be deposited into the Treasury.
    Western has in the past deposited and will continue to deposit all 
money to which the United States is entitled into the Treasury in 
accordance with the above statutes. Western has administered the JTS 
for over 30 years. This administration included the receipt of revenue 
from outside sources and then redistributing that revenue to other 
members of the JTS, Basin Electric, Heartland, and MBMPA. Western has 
also approved the JTS rate prior to implementation.
    Western is obligated under existing contracts to administer the 
transmission facilities of Basin Electric and Heartland. These 
obligations have arisen based upon the initial signing of the MBSG 
Agreement which was signed by Reclamation in 1962 and the initial 
bilateral agreements between Basin Electric and Reclamation which 
created the JTS. The role Western is playing in the IS is analogous to 
the role it played in administering the JTS, and Western is 
contractually obligated to perform those functions.
    Comment: UGPR should continue its rights and obligations detailed 
in the bilateral contracts. In addition it should allow all existing 
loads to stay on the JTS and receive those benefits.
    Response: UGPR agrees and Western, Basin Electric, and Heartland 
will continue the obligations and benefits among themselves as detailed 
in the bilateral agreements.
    Comment: UGPR should continue to participate in the planning of an 
Independent System Operator (ISO).
    Response: UGPR agrees and has several representatives on the MAPP 
committees involved with the planning and development of the MAPP ISO. 
As the proposal is being developed, Western will provide input and data 
to study the impact on the region and Western. Western will continue 
its involvement.

Ancillary Services Discussion

    Six ancillary services will be offered to IS Transmission 
Customers; two of which are required to be purchased by IS Transmission 
Customers. These two are (1) Scheduling, System Control, and Dispatch 
Service and (2) Reactive Supply and Voltage Control Service from 
Generation Sources Service. The remaining four ancillary services--
Regulation and Frequency Response Service, Energy Imbalance Service, 
Spinning Reserve Service, and Supplemental Reserve Service will also be 
offered.
    Sales of Regulation and Frequency Response Service, Energy 
Imbalance Service, Spinning Reserve Service, and Supplemental Reserve 
Service may be limited since Western has allocated its power resources 
to preference entities under long-term commitments. If Western 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.
    Scheduling, System Control, and Dispatch Service: Western's annual 
revenue requirement for Scheduling, System Control, and Dispatch 
Service is determined by multiplying the portion of the Watertown 
Operations Office net plant and communications facilities net plant 
associated with Scheduling, System Control, and Dispatch Service by the 
transmission fixed charge rate. The formula rate for Scheduling, System 
Control, and Dispatch Service is the revenue requirement for this 
service divided by the annual number of daily schedules, or, using 1997 
data, $1,684,495  36,571 daily schedules. Using 1997 data, this 
methodology for determining the rate for Scheduling, System Control, 
and Dispatch Service has produced a rate of $46.06/schedule/day. This 
rate and rate design is only recovering Western's revenue requirement.
    Reactive Supply and Voltage Control from Generation Sources 
Service: Western's annual cost of providing

[[Page 43169]]

Reactive Supply and Voltage Control from Generation Sources Service is 
determined by multiplying the total P-SMBP-ED generation net plant by 
the generation fixed charge rate. The annual cost is multiplied by the 
capability used for reactive support to determine Western's reactive 
service revenue requirement. Basin Electric's annual revenue 
requirement is based upon the annual cost of equipment installed on its 
generators to provide this service. Western's and Basin Electric's 
annual revenue requirements are summed for the total revenue 
requirement for this service. The Reactive Supply and Voltage Control 
Service from Generation Sources Service rate is then derived by 
dividing the annual revenue requirement by the IS Transmission System 
Total Load. The annual rate is then divided by 12 months to obtain a 
monthly rate. Using 1997 data, this methodology for determining the 
rate for Reactive Supply and Voltage Control Service from Generation 
Sources Service has produced a rate of $0.07/kW-month for transmission 
service provided.
    Regulation and Frequency Response Service: Regulation and Frequency 
Response Service in the East side of the control area is provided 
primarily by Oahe generation, and in the West side of the control area 
by Fort Peck, both of which are Corps of Engineer facilities. To 
calculate the annual cost of providing Regulation and Frequency 
Response Service, the Corps of Engineer's generation fixed charge rate 
is applied to Oahe generation and Fort Peck generation net plant 
investment. This cost is divided by the capacity at the plants to 
derive a dollar per kilowatt amount for Oahe and Fort Peck Powerplants' 
installed capacity. This dollar per kilowatt amount is then applied to 
the capacity of Oahe generation and Fort Peck generation reserved for 
regulation and frequency response in the control area. The capacity 
reserved for Regulation and Frequency Response Service has been 
determined to be 2 percent of the annual peak load. The 2 percent value 
was derived by averaging the incremental change in hourly load in the 
control area for the calendar year and dividing this amount in half. 
The annual revenue requirement for Regulation and Frequency Response 
Service is determined by applying the dollar per kilowatt amount to the 
capacity used for Regulation and Frequency Response Service. An annual 
rate for Regulation and Frequency Response Service is then determined 
by dividing the revenue requirement by the total load in the control 
area. The annual rate is then divided by 12 months to obtain a monthly 
rate. Using 1997 data, this methodology for determining the rate for 
Regulation and Frequency Response Service produced a rate of $0.05/kW-
month of load for which Western is providing this service. This rate 
and rate design is recovering only Western's revenue requirement. 
Credit will be given to those Transmission Customers who provide 
Western with Automatic Generation Control (AGC) of generation 
facilities capable of providing this service.
    Energy Imbalance Service: This service is not intended to provide 
backup for generation supply. Energy shall be returned in like 
timeframes (on-peak, off-peak, etc.) and accounts zeroed out monthly. 
Western reserves the right to apply a penalty to energy imbalances 
outside a 3 percent bandwidth (+/-1.5 percent deviation). The penalty 
for under deliveries outside the 3 percent bandwidth is 100 mills/kWh. 
Over deliveries outside the 3 percent bandwidth will be forfeited to 
the control area.
    Reserve Services: Western's annual cost of generation for Reserve 
Services is determined by multiplying the generation fixed charge rate 
by the P-SMBP-ED generation net plant investment. The cost/kW-year is 
determined by dividing the annual cost of generation by the plant 
capacity. The capacity used for Reserve Services is determined by 
multiplying Western's peak IS load by the MAPP operating reserve 
requirement of 5 percent. The cost/kW-year is multiplied by the 
capacity used for Reserve Services to determine the annual revenue 
requirement for Reserve Services. The annual revenue requirement for 
Reserve Services is divided by Western's peak transmission load to 
calculate the annual rate. The annual rate is then divided by 12 months 
to obtain a monthly rate. Using 1997 data, this methodology for 
determining the rate for reserve services has produced a rate of $0.12/
kW-month of customer load. This rate and rate design is recovering only 
Western's revenue requirement associated with Reserve Services. If 
energy is taken under this service, the energy charge will be the MAPP 
Rate for Emergency Energy, which is presently the greater of 30 mills/
kWh or the prevailing market energy rate in the region.

Ancillary Services Comments

    UGPR received written comments concerning the ancillary service 
rates 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. UGPR's response follows each comment.
    Comment: The rate for Reactive Supply and Voltage Control from 
Generation Sources Service is overstated because it includes an 
excessive amount of generation cost. The revenue requirement should be 
determined by estimating the cost of the exciter/generator and then 
allocating that cost between real and reactive power generation. In 
addition, the load used to derive the rate is understated.
    Response: Western estimated the amount of plant costs used to 
provide Reactive Supply and Voltage Control from Generation Sources 
Service by multiplying generation investment by the ratio of condensing 
operation of the generators to total generator operation. When 
Western's hydro units are condensing, they are removing VARs generated 
by line charging on the long transmission lines in the IS. Western 
believes this method is appropriate for allocating costs to Reactive 
Supply and Voltage Control Service from Generation Sources Service.
    The load used in the denominator of the Reactive Supply and Voltage 
Control Service from Generation Sources Service rate has been changed 
from the combined East and West control area coincident peaks to the IS 
Transmission System Total Load to reflect that each unit of 
transmission service will be charged for this service. Entities that 
have existing contracts at this time were not included in the 
denominator because Western cannot charge these entities for this 
service and including them would cause under recovery of costs. In the 
future when these contracts expire and these entities take service 
under the Tariff, their loads will be included in the denominator.
    Comment: The Regulation and Frequency Response Service Rate is 
overstated. The revenue requirement is overstated because Western's 
estimate of the percentage of generation required to provide regulation 
service (4 percent) is too high. In addition, the denominator of 1,615 
MW is too low. Finally, Western should give credit to Transmission 
Customers which purchase regulation service from third parties.
    Response: The 4 percent value was derived by averaging the 
incremental change in hourly load in the control area for the year. In 
accordance with recent FERC rulings related to this service, Western 
has divided the 4 percent value in half. The denominator

[[Page 43170]]

is Western's 12-cp load in its East and West control areas, excluding 
those entities such as Northwestern Public Service Company, Montana-
Dakota Utilities Company, and Montana Power Company that serve load in 
Western's control areas but have existing transmission agreements and/
or provide their own regulation and frequency control service. 
Including these entities' loads in the denominator at this time would 
cause under recovery of costs associated with this service. If these 
entities take this service from Western in the future their loads will 
be included in the denominator.
    Whether Western should provide credit to those preference customers 
who purchase Regulation and Frequency Response Service from third 
parties is outside the scope of this process.
    Comment: Western's combined percentages for Reserve Services (5 
percent) and Regulation and Frequency Response Service (4 percent) are 
too high. Customers should only have to purchase a total of 5 percent 
capacity for both Reserve Services and Regulation and Frequency 
Response Service.
    Response: The MAPP operating reserve requirement is 5 percent. 
Regulation and Frequency Response Service is not included in this 
percentage and must therefore be provided for in addition to operating 
reserves. In this Federal Register notice Western has decreased the 
amount of capacity reserved for Regulation and Frequency Response 
Service from 4 percent to 2 percent.
    Comment: Western should adjust the rates for Reactive Supply and 
Voltage Control from Generation Sources Service and Regulation and 
Frequency Response Service to recover the costs of the facilities of 
Basin Electric and Heartland that contribute to the services provided 
by Western and then provide for appropriate credits.
    Response: The cost of Basin Electric's facilities that contribute 
to Reactive Supply and Voltage Control from Generation Sources Service 
have been included in that rate, and Basin Electric will receive the 
appropriate credit for these facilities. If Basin Electric, Heartland, 
or any other entity provides Western with control of that entity's 
generation facilities and those generation facilities are capable of 
providing adequate Reactive Supply and Voltage Control from Generation 
Sources Service and/or Regulation and Frequency Response Service, that 
entity will be given an appropriate credit.

Regulatory Flexibility Analysis

    Pursuant to the Regulatory Flexibility Act of 1980 (5 U.S.C. 601-
612) (Act), 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 IS 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 IS 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 1500-1508); and DOE NEPA Regulations (10 CFR part 
1021), Western has determined this action is categorically excluded 
from the preparation of an environmental assessment or an environmental 
impact statement.

Executive Order 12866

    DOE has determined 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 the 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 August 1, 1998, formula rates for 
transmission and ancillary services under Rate Schedules UGP-AS1, UGP-
AS2, UGP-AS3, UGP-AS4, UGP-AS5, UGP-AS6, UGP-FPT1, UGP-NFPT1, and UGP-
NT1. The rate schedules shall remain in effect on an interim basis, 
pending the FERC confirmation and approval of them or substitute 
formula rates on a final basis through July 31, 2003.

    Dated: July 31, 1998.
Elizabeth A. Moler,
Deputy Secretary.
Rate Schedule UGP-AS1
Schedule 1 to Tariff
August 1, 1998

United States Department of Energy, Western Area Power Administration, 
Upper Great Plains Region, Integrated System

Scheduling, System Control, and Dispatch Service

Effective

    The first day of the first full billing period beginning on or 
after August 1, 1998, through July 31, 2003.

Applicable

    This service is required to schedule the movement of power through, 
out of, within, or into the Western Area Upper Great Plains control 
area (WAUGP). 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 WAUGP non-
Transmission Customers. The WAUGP will accept any reasonable number of 
schedule changes over the course of the day without any additional 
charge.
    The 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.
    The Upper Great Plains Region (UGPR) shall charge the non-
Transmission Customer in accordance with the rate then in effect.

Formula Rate

[[Page 43171]]

[GRAPHIC] [TIFF OMITTED] TN12AU98.000



Rate

    The rate to be in effect August 1, 1998, through April 30, 1999, is 
$46.06 per schedule per day. This rate is based on the above formula 
and on 1997 data. A recalculated rate will go into effect every May 1 
based on the above formula and data. UGPR will notify the customer 
annually of the recalculated rate on or before April 1.

Rate Schedule UGP-AS2
Schedule 2 to Tariff
August 1, 1998
United States Department of Energy, Western Area Power Administration, 
Upper Great Plains Region, Integrated System

Reactive Supply and Voltage Control From Generation Sources Service

Effective

    The first day of the first full billing period beginning on or 
after August 1, 1998, through July 31, 2003.

Applicable

    In order to maintain transmission voltages on all transmission 
facilities within acceptable limits, generation facilities under the 
control of the Western Area Upper Great Plains control area (WAUGP) 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 
Transmission Customer's 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 
WAUGP.
    The Transmission Customer must purchase this service from the 
Transmission Provider. 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 charges for VAR Support may be modified upon written notice to 
the Transmission 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 Upper Great Plains Region 
(UGPR) shall charge the Transmission Customer in accordance with the 
rate then in effect.
    Those Transmission Customers with generators in the control area 
providing WAUGP with adequate VAR Support will not be charged for this 
service. Any waiver of this charge or any crediting arrangements for 
VAR Support must be documented in the Transmission Customer's Service 
Agreement.

Formula Rate
[GRAPHIC] [TIFF OMITTED] TN12AU98.001

Rate

    The rate to be in effect August 1, 1998, through April 30, 1999, 
is:

Monthly: $0.07/kW-month
Weekly: $0.016/kW-week
Daily: $0.002/kW-day
Hourly: 0.096 mills/kWh

    This rate is based on the above formula and on 1997 financial and 
load data. A recalculated rate will go into effect every May 1 based on 
the above formula and updated financial and load data. UGPR will notify 
the Transmission Customer annually of the recalculated rate on or 
before April 1.

Rate Schedule UGP-AS3
Schedule 3 to Tariff
August 1, 1998
United States Department of Energy, Western Area Power Administration, 
Upper Great Plains Region, Integrated System

Regulation and Frequency Response Service

Effective

    The first day of the first full billing period beginning on or 
after August 1, 1998, through July 31, 2003.

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 60 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 Upper Great Plains control area (WAUGP) operator. 
The Transmission Customer must either purchase this service from WAUGP 
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.
    Charges for Regulation may be modified upon written notice to the 
Transmission 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 Upper Great Plains Region (UGPR) 
shall charge the Transmission Customer in accordance with the rate then 
in effect.
    Transmission Customers will not be charged for this service if they 
receive Regulation from another source, or self-supply it for their own 
load. Any waiver of this charge or any crediting arrangement for 
Regulation must be documented in the Transmission Customer's Service 
Agreement.

Formula Rate

[[Page 43172]]

[GRAPHIC] [TIFF OMITTED] TN12AU98.002



Rate

    The rate to be in effect August 1, 1998, through April 30, 1999, 
is:

Monthly: $0.05/kW-month
Weekly: $0.012/kW-week
Daily: $0.002/kW-day

    This rate is based on the above formula and on 1997 financial and 
load data. A recalculated rate will go into effect every May 1 based on 
the above formula and updated financial and load data. UGPR will notify 
the Transmission Customer annually of the recalculated rate on or 
before April 1.
    If resources are not available from a WAUGP resource, UGPR will 
offer to purchase the Regulation and pass through the costs to the 
Transmission Customer, plus an amount for administration.
Rate Schedule UGP-AS4
Schedule 4 to Tariff
August 1, 1998
United States Department of Energy Western Area Power Administration, 
Upper Great Plains Region, Integrated System

Energy Imbalance Service

Effective

    The first day of the first full billing period beginning on or 
after August 1, 1998, through July 31, 2003.

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 Upper Great Plains control area (WAUGP) 
over a single hour. The Transmission Customer must either obtain this 
service from WAUGP or make alternative comparable arrangements to 
satisfy its Energy Imbalance Service obligation.
    The WAUGP shall establish a deviation band of +/-1.5 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 Transmission 
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 Transmission Customer. Any change to the 
Transmission 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 Upper Great Plains Region (UGPR) 
shall charge the Transmission Customer in accordance with the rate then 
in effect.

Formula Rate

    UGPR reserves the right to implement the following upon providing 
notice to the Transmission Customer.
    For negative excursions (under deliveries) outside the bandwidth, 
WAUGP will assess a penalty charge of 100 mills/kWh.
    For positive excursions (over deliveries) outside the bandwidth, 
over deliveries of energy will be forfeited to the control area.

Rate

    The bandwidth in effect August 1, 1998, through July 31, 2003, is 3 
percent (+/-1.5 percent hourly deviation).
Rate Schedule UGP-AS5
Schedule 5 to Tariff
August 1, 1998
United States Department of Energy Western Area, Power Administration, 
Upper Great Plains Region, Integrated System

Operating Reserve--Spinning Reserve Service

Effective

    The first day of the first full billing period beginning on or 
after August 1, 1998, through July 31, 2003.

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 Transmission Customer must either purchase this 
service from Western Area Upper Great Plains control area (WAUGP) 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.
    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 charges for Reserves may be modified upon written notice to the 
Transmission Customer. Any change to the charges for Reserves 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 Upper Great Plains Region (UGPR) 
shall charge the Transmission Customer in accordance with the rate then 
in effect.

Formula Rate 
[GRAPHIC] [TIFF OMITTED] TN12AU98.003

Rate

    The rate to be in effect August 1, 1998, through April 30, 1999, 
is:

Monthly: $0.12/kW-month
Weekly: $0.028/kW-week
Daily: $0.004/kW-day

    This rate is based on the above formula and on 1997 financial and 
load data. A recalculated rate will go into effect every May 1 based on 
the above formula and updated financial and load data. UGPR will notify 
the Transmission Customer annually of the recalculated rate on or 
before April 1.
    If resources are not available from a WAUGP resource, UGPR will 
offer to purchase the Reserves and pass through the costs to the 
Transmission Customer, plus an amount for administration.
    In the event that Reserves are called upon for Emergency Use, UGPR 
will assess a charge for energy used at the Mid-Continent Area Power 
Pool Rate for Emergency Energy, presently the greater

[[Page 43173]]

of 30 mills/kWh or the prevailing market energy rate in the region. The 
Transmission Customer would be responsible for providing the 
transmission to get the Reserves to its destination.
Rate Schedule UGP-AS6
Schedule 6 to Tariff
August 1, 1998
United States Department of Energy, Western Area Power Administration 
Upper Great Plains Region, Integrated System

Operating Reserve--Supplemental Reserve Service

Effective

    The first day of the first full billing period beginning on or 
after August 1, 1998, through July 31, 2003.

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 
Transmission Customer must either purchase this service from Western 
Area Upper Great Plains control area (WAUGP) 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.
    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 charges for Reserves may be modified upon written notice to the 
Transmission Customer. Any change to the charges for Reserves 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 Upper Great Plains Region (UGPR) 
shall charge the Transmission Customer in accordance with the rate then 
in effect.

Formula Rate
[GRAPHIC] [TIFF OMITTED] TN12AU98.004

Rate

    The rate to be in effect August 1, 1998, through April 30, 1999, 
is:
Monthly: $0.12/kW-month
Weekly: $0.0028/kW-week
Daily: $0.004/kW-day
    This rate is based on the above formula and on 1997 financial and 
load data. A recalculated rate will go into effect every May 1 based on 
the above formula and updated financial and load data. UGPR will notify 
the Transmission Customer annually of the recalculated rate on or 
before April 1.
    If resources are not available from a WAUGP resource, UGPR will 
offer to purchase the Reserves and pass through the costs to the 
Transmission Customer, plus an amount for administration.
    In the event Reserves are called upon for Emergency Energy, the 
UGPR will assess a charge for energy used at the Mid-Continent Area 
Power Pool Rate for Emergency Energy, presently the greater of 30 
mills/kWh or the prevailing market energy rate in the region. The 
Transmission Customer would be responsible for providing the 
transmission to get the Reserves to its destination.
Rate Schedule UGP-FPT1
Schedule 7 to Tariff
August 1, 1998
United States Department Of Energy, Western Area Power Administration, 
Upper Great Plains Region, Integrated System

Long-Term Firm and Short-Term Firm Point-to-Point Transmission 
Service

Effective

    The first day of the first full billing period beginning on or 
after August 1, 1998, through July 31, 2003.

Applicable

    The Transmission Customer shall compensate the Upper Great Plains 
Region (UGPR) each month for Reserved Capacity pursuant to the 
applicable 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.
    UGPR may modify the rate for Firm Point-to-Point Transmission 
Service upon written notice to the Transmission Customer. Any change to 
the rate 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. UGPR 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 UGPR must be 
announced to all eligible Transmission Customers solely by posting on 
the Open Access Same-Time Information System (OASIS), (2) any 
Transmission 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, UGPR must offer the same discounted transmission 
service rate for the same time period to all eligible Transmission 
Customers on all unconstrained transmission paths that go to the same 
point(s) of delivery on the Transmission System.

Formula Rate 
[GRAPHIC] [TIFF OMITTED] TN12AU98.005


[[Page 43174]]



Rate

    The rate to be in effect August 1, 1998, through April 30, 1999, is 
as follows.
    Maximum of:

Yearly: $34.44/kW of reserved capacity per year
Monthly: $ 2.87/kW of reserved capacity per month
Weekly: $ 0.66/kW of reserved capacity per week
Daily: $ 0.094/kW of reserved capacity per day

    This rate is based on the above formula and 1997 data. A 
recalculated rate will go into effect every May 1 based on the above 
formula and updated financial and load data. UGPR will notify the 
Transmission Customer annually of the recalculated rate on or before 
April 1.
Rate Sched. UGP-NFPT1
Schedule 8 to Tariff
August 1, 1998
United States Department of Energy, Western Power Area Administration, 
Upper Great Plains Region Integrated System

Non-Firm Point-to-Point Transmission Service

Effective

    The first day of the first full billing period beginning on or 
after August 1, 1998, through July 31, 2003.

Applicable

    The Transmission Customer shall compensate Upper Great Plains 
Region (UGPR) 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.
    UGPR may modify the rate for Non-Firm Point-to-Point Transmission 
Service upon written notice to the Transmission Customer. Any change to 
the rate 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. UGPR 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 UGPR must be 
announced to all eligible Transmission Customers solely by posting on 
the Open Access Same-Time Information System (OASIS), (2) any 
Transmission 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, UGPR must offer the same discounted transmission 
service rate for the same time period to all eligible Transmission 
Customers on all unconstrained transmission paths that go to the same 
point(s) of delivery on the Transmission System.

Formula Rate
[GRAPHIC] [TIFF OMITTED] TN12AU98.006

Rate

    The rate to be in effect August 1, 1998, through April 30, 1999, 
is:
    Maximum of:

Monthly: $2.87/kW of reserved capacity per month
Weekly: $0.66/kW of reserved capacity per week
Daily: $0.094/kW of reserved capacity per day
Hourly: 3.93 mills/kWh

    This rate is based on the above formula and 1997 data. A 
recalculated rate will go into effect every May 1 based on the above 
formula and updated financial and load data. UGPR will notify the 
Transmission Customer annually of the recalculated rate on or before 
April 1.
Rate Schedule UGP-NT1
Attachment H to Tariff
August 1, 1998
United States Department of Energy, Western Area Power Administration 
Upper Great Plains Region, Integrated System

Annual Transmission Revenue Requirement for Network Integration 
Transmission Service

Effective

    The first day of the first full billing period beginning on or 
after August 1, 1998, through July 31, 2003.

Applicable

    The Transmission Customer shall compensate the Upper Great Plains 
Region (UGPR) 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 
schedule was promulgated and may be modified pursuant to applicable 
Federal laws, regulations, and policies.
    UGPR 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. UGPR 
shall charge the Transmission Customer in accordance with the revenue 
requirement then in effect.

Formula Rate
[GRAPHIC] [TIFF OMITTED] TN12AU98.007


[[Page 43175]]



Annual Revenue Requirement

    The annual revenue requirement in effect August 1, 1998, through 
April 30, 1999, is $95,725,420. This annual revenue requirement is 
based on 1997 data. A recalculated annual revenue requirement will go 
into effect every May 1 based on updated financial data. UGPR will 
notify the Transmission Customer annually of the recalculated annual 
revenue requirement on or before April 1.

[FR Doc. 98-21600 Filed 8-11-98; 8:45 am]
BILLING CODE 6450-01-P