[Federal Register Volume 62, Number 178 (Monday, September 15, 1997)]
[Notices]
[Pages 48272-48276]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 97-24346]


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DEPARTMENT OF ENERGY

Western Area Power Administration


Transmission and Ancillary Services Rates, Pick-Sloan Missouri 
Basin, Eastern Division

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of proposed rate adjustments.

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SUMMARY: The Western Area Power Administration (Western) is proposing 
transmission service and ancillary service rate adjustments for Pick-
Sloan Missouri Basin Program, Eastern Division (P-SMBP-ED). The 
proposed formula rates will provide sufficient revenue to repay all 
annual costs and assigned investment within the allowable time periods. 
The proposed formula rates are scheduled to go into effect May 1, 1998. 
This Federal Register notice continues the procedure for public 
participation in the transmission and ancillary service rate 
adjustments, which began with Western's Advance Announcement dated 
March 28, 1997.

DATES: The consultation and comment period for the proposed 
transmission service and ancillary service rates will end November 14, 
1997. Written comments should be received by Western by the end of the 
comment period to be assured consideration. Western will present a 
detailed explanation of the proposed rate at the public information 
forums which will be held at the following dates and times:
    1. October 16, 1997--9 a.m. MDT, Billings, Montana.
    2. October 17, 1997--9 a.m. CDT, Sioux Falls, South Dakota.
    Western will receive written and oral comments at the public 
comment forums which will be held at the following times:
    3. November 13, 1997--9 a.m. MST, Billings, Montana.
    4. November 14, 1997--9 a.m. CST, Sioux Falls, South Dakota.

ADDRESSES: Western's public information forums will be held at the 
following places:
    1. Radisson Northern Hotel, Broadway & 1st Avenue North, Billings, 
Montana.
    2. Howard Johnson, 3300 West Russell Street, Sioux Falls, South 
Dakota.
    Western's public comment forums will be held at the following 
places:
    3. Radisson Northern Hotel, Broadway & 1st Avenue North, Billings, 
Montana.
    4. Howard Johnson, 3300 West Russell Street, Sioux Falls, South 
Dakota.
    Written comments should be sent to: Gerald C. Wegner, Regional 
Manager, Upper Great Plains Region, Western Area Power Administration, 
P.O. Box 35800, Billings, MT 59107-5800.

FOR FURTHER INFORMATION CONTACT: Robert F. Riehl, Rates Manager, Upper 
Great Plains Region (UGPR), Western Area Power Administration, P.O. Box 
35800, Billings, MT 59107-5800, (406) 247-7388. E-mail [email protected] 
or visit UGPR's home page at http://www.wapa.gov/ugp/.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Introduction/Background
II. Western's Proposal
III. Proposed Rates
IV. Cost Shifting
V. Other Options
VI. Authorities

I. Introduction/Background

    Western initiated a public process to establish long-term open 
access transmission and ancillary service rates for the P-SMBP-ED with 
its advance announcement of March 28, 1997. Several options were 
identified and comments and ideas were solicited on these options. 
Forty-five letters were received as a result of the solicitation. The 
letters commented on fourteen issues. The most constant and consistent 
message received from the comments was that Western should choose a 
proposal that would have the least impact upon the P-SMBP-ED firm power 
rate. This Federal Register notice continues that process.

II. Western's Proposal

1. Honor Existing Contract Arrangements

    Western presently has the following transmission and related 
services contract agreements. Western intends to abide by the terms of 
these agreements and sustain the benefits incurred from these 
agreements.
    Basin Electric Power Cooperative (Basin Electric) has a bilateral 
Contract, 90-BAO-415, with Western for Joint Transmission System 
services. The Contract became effective on the first day of the first 
full billing period following the date of its execution, January 5, 
1995, and remains in effect

[[Page 48273]]

through the hour ending 2400 of December 31, 2039. Basin Electric also 
has a Contract, 90-BAO-431, with Western for transmission service on 
the Montana Power Company (MPC) system. The Contract became effective 
on the date of its execution, November 6, 1990, and remains in effect 
through the hour 2400 on December 31, 2033.
    Black Hills Corporation has a bilateral Contract, 88-BAO-320, with 
Western for transmission service. The Contract became effective October 
1, 1988, and terminates at 12:01 a.m., October 1, 1998, as specified by 
the Contract.
    Heartland Consumers Power District (Heartland) has a bilateral 
Contract, 89-BAO-344, with Western for Joint Transmission System 
services. The Contract became effective on the first billing day of the 
first full billing period following the date of its execution, December 
28, 1995, and remains in effect through the hour ending 2400 on 
December 31, 2039.
    Minnkota Power Cooperative, Inc. has a bilateral Contract, 88-BAO-
313, with Western for transmission service. The Contract became 
effective the first day of the first billing period after the date of 
execution, October 6, 1989, and remains in effect through December 31, 
2020, as specified in the Contract.
    Missouri Basin Municipal Power Agency has a bilateral Contract, 8-
07-60-P0002, with Western for use of the Joint Transmission System. The 
Contract became effective on the first day of the November 1977 billing 
period and remains in effect until midnight of December 31, 1997, as 
defined in the Contract.
    Montana-Dakota Utilities Company has a bilateral Contract, 88-BAO-
308, with Western for transmission service. The Contract became 
effective on its date of execution, July 1, 1988, and remains in effect 
until December 31, 2015.
    MPC has a bilateral Contract, 4-07-60-P0228, with Western for 
transmission service. The Contract became effective October 15, 1984. 
Notice to terminate this Contract has been served and the Contract will 
terminate on or about June 30, 1998.
    Northwestern Public Service Company has a bilateral Contract, 4-07-
60-P0223, with Western for transmission service. The Contract became 
effective on April 1, 1984, and remains in effect until December 31, 
2000.
    Northern States Power Company has a Contract, 6-07-60-P0236, with 
Western for transmission service. The Contract became effective on the 
date of its execution, June 2, 1986. Notice to terminate this Contract 
has been served and the Contract will terminate on January 31, 2001.

2. The Integrated System Will Be Used for Transmission Service in All 
New Electric Service Arrangements

    Western, Basin Electric, and Heartland have combined their 
transmission facilities to form an Integrated System (IS) and herein 
developed transmission and ancillary service rates using a Federal 
Energy Regulatory Commission (FERC) approved rate design. Western has 
been designated as the operator of the IS by the other participants. 
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, Colorado, Minnesota, and Missouri 
and in addition include facilities which interconnect with Canada.
    Our approach for formation of the IS was to include facilities 
which followed the spirit and intent of the order and to make the 
system most useful to the transmission requesters. For these reasons we 
included several major facilities which were not a part of the Joint 
Transmission System. We included the second 345-kV transmission line 
between the Antelope Valley and Leland Olds generating stations; which 
follows the definitions used for acceptable transmission facilities in 
other filings. The 230-kV transmission line between Tioga, North 
Dakota, and Boundary Dam, which provides access to loads in Canada, has 
been included in the IS. The Miles City DC Tie, which provides for the 
transmission of electricity between the east-west electrical separation 
of the United States and increases access to transmission on the IS. 
The IS also differs from the Joint Transmission System in that it does 
not include the transmission facilities owned by the joint owners of 
the Laramie River Generating Station, which require the agreement of 
all participants prior to inclusion. Basin Electric, and Heartland do 
not constitute all the owners in the Laramie River Generating Station. 
If they reach agreement, Western, Basin Electric, and Heartland may 
consider inclusion of those facilities in the IS rate and tariff.
    For each of their new electric service arrangements crossing the IS 
facilities, Western, Basin Electric, and Heartland will take service 
under the proposed IS rates. To avoid double charging for transmission 
services, credit will be given for transmission capacity reservations 
in existing Joint Transmission System service contracts for new 
transactions from existing resources. Western, as operator of the IS, 
will bill for service, collect payments, and distribute revenue to each 
participant.

III. Proposed Rates

    The proposed rates conform to the spirit and intent of FERC Order 
Nos. 888 and 888-A. An Open Access Transmission Tariff (Tariff), 
specifying terms and conditions, is being developed under a separate 
process. Once implemented, Western, Basin Electric, Heartland, and 
others will take service under the proposed Tariff and rates for all 
new transmission and/or electric sales arrangements. Western is 
requesting public comment on a proposed rate formula that would be 
adjusted annually, on or about May 1 of each year, by inserting the 
previous year's data into the formula. The data herein is fiscal year 
1996 data. These rates will support Western's Tariff and conform with 
the spirit and intent of FERC Order Nos. 888 and 888-A. Supporting 
information and impacts of these rates are detailed in a rate brochure 
available to all interested parties.

1. Proposed Revenue Requirement for IS Transmission Service

    The proposed rate for IS transmission service (Network and Point to 
Point) is based on a revenue requirement that recovers: (i) The IS 
investment and interest cost for Western, Basin Electric, and Heartland 
facilities associated with providing IS transmission service; and (ii) 
the operation, maintenance, administrative and general cost for 
Western, Basin Electric and Heartland allocated to IS transmission 
service. This revenue requirement is offset by appropriate transmission 
revenues. Rates will be recalculated every year on or about May 1 based 
on the previous year's data. The previous year's data to be used in the 
recalculation will be made available for review 30 days before the new 
rates are implemented. Firm and Non-Firm Point to Point transmission 
service rates will be offered on an up-to basis to promote maximum 
usage and transmission revenues from the IS.

2. Proposed Rate for Network IS Transmission Service

    The proposed rate for monthly Network IS transmission service is 
the product of the network customer's load

[[Page 48274]]

ratio share times one-twelfth (\1/12\) of the annual network 
transmission revenue requirement. The network transmission revenue 
requirement is derived by annualizing the IS transmission investment, 
and adding transmission related annual costs, including operation, 
maintenance, interest, administrative and general costs. The annual 
costs are reduced by revenue credit for the Non-Firm transmission 
service. The load ratio share is based on the network customer's hourly 
load coincident with the IS monthly transmission system peak minus the 
coincident peak for all IS Firm Point-to-Point transmission service 
plus the point-to-point reservations. The Network rate includes the 
cost for scheduling, system control, and dispatch service needed to 
provide transmission service.

3. Proposed Rate for Firm Point-to-Point IS Transmission Service

    The proposed Firm Point-to-Point IS rate is based on a revenue 
requirement derived by annualizing the IS transmission investment, and 
adding transmission related annual costs. These transmission related 
annual costs include operation, maintenance, interest, administrative 
and general costs. The annual costs are reduced by revenue credits for 
Non-Firm transmission. The resultant net annual cost to be recovered is 
divided by the capacity reservation needed for the annual average 
monthly IS transmission load. Using 1996 data, this methodology 
produced a charge of $3.07/kW-month for Firm Point-to-Point 
transmission service. This proposed rate may be adjusted each year on 
or about May 1, by a recalculation based on the previous years data 
using the formula: (Total Annual Revenue Requirement--Non Firm Revenue 
Credits)/Annual Average Transmission System Monthly Peak Load/12 
months. The point-to-point rate includes the cost for scheduling, 
system control, and dispatch service needed to provide transmission 
service.

4. Proposed Rate for Non-Firm Point-to-Point Service

    The proposed rate for Non-Firm Point-to-Point IS transmission 
service is an energy rate up-to but never higher than the Firm Point-
to-Point rate. This rate will remain in effect concurrently with the 
Firm Point-to-Point rate. The Non-Firm Point-to-Point rate includes the 
cost for scheduling, system control, and dispatch service needed to 
provide transmission service.

5. Proposed Rates for Ancillary Services

    Western will provide ancillary services, subject to availability, 
as described below and as listed in Table 1. The rates are designed to 
recover only the costs incurred for providing the service(s).

6. Proposed Rate for Scheduling, System Control and Dispatch Service

    Western's annualized costs 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 annual cost for scheduling, 
system control and dispatch service is then divided by the number of 
daily schedules in FY 1996. Using 1996 data, this methodology for 
determining the scheduling, system control and dispatch service rate 
has produced a charge of $54.50/schedule/day. This rate and rate design 
is recovering only Western's revenue requirement.

7. Proposed Rate for Reactive Supply and Voltage Control Service

    Western's annualized cost for reactive supply and voltage control 
is determined by multiplying the total P-SMBP-ED generation net plant 
by the generation fixed charge rate. The annualized cost is multiplied 
by the capability used for reactive support to determine Western's 
reactive service revenue requirement. Basin Electric's and Heartland's 
annual revenue requirements are based upon the annualized cost of 
equipment installed on their generators to provide this service. 
Western's, Basin Electric's, and Heartland's revenue requirements are 
summed for the total revenue requirement. The reactive supply and 
voltage control service charge is then derived by dividing the revenue 
requirement by the total load in Western's control area. The annual 
cost is then divided by 12 months to obtain a monthly charge. Using 
1996 data, this methodology for determining the rate for reactive 
supply and voltage control has produced a charge of $0.08/kW-month for 
transmission capacity reserved.

8. Proposed Rate for 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 
Engineers (Corps) facilities. The Corps generation fixed charge rate is 
applied to Oahe and Fort Peck net plant costs producing an annual 
generation revenue requirement for the Oahe and Fort Peck power plants. 
This revenue requirement is divided by the capacity at the plants to 
derive a dollar per kilowatt charge for Oahe's and Fort Peck's 
installed capacity. This dollar per kilowatt charge is then applied to 
capacity used at Oahe and Fort Peck for regulation and frequency 
response service in the control area. The capacity used for regulation 
and frequency response service has been determined to be 4 percent of 
the annual peak load. The 4 percent value was derived by averaging the 
incremental change in hourly load in the control area for the calendar 
year. The annual revenue requirement for regulation and frequency 
response service is determined by applying the dollar per kilowatt 
charge to the capacity used for regulation and frequency response. The 
regulation and frequency response service charge is then determined by 
dividing the revenue requirement by Western's load in the control area. 
The annual cost is then divided by 12 months to obtain a monthly 
charge. Using 1996 data, this methodology for determining the rate for 
regulation and frequency response produced a charge of $0.09/kW-month 
of load for which Western is providing this service. This rate and rate 
design is recovering Western's revenue requirement only. Credit will be 
given to those transmission customers who provide Western with 
Automatic Generation Control (AGC) of generation facilities capable of 
providing this service.

9. Proposed Rate for Energy Imbalance Service

    This service is not intended to provide backup for generation 
supply. Energy shall be returned with like energy (on peak with on 
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

10. Proposed Rate for Reserves

    Western's annualized cost for reserves is determined by multiplying 
the P-SMBP-ED generation net plant costs by the generation fixed charge 
rate. The cost/kW-year is determined by dividing the plant costs by the 
plant capacity. The capacity used for reserves is determined by 
multiplying the peak IS load in the control area by the MAPP

[[Page 48275]]

operating reserve requirement. The cost/kW-year is multiplied by the 
capacity used for reserves to determine the annual cost of reserves. 
The annual cost of reserves is divided by Western's peak load in the 
control area to calculate the annual charge. The annual cost is then 
divided by 12 months to obtain a monthly charge. Using 1996 data, this 
methodology for determining the reserve rate has produced a charge of 
$0.12/kW-month of customer load. This rate and rate design is 
recovering only Western's revenue requirement. If energy is taken under 
this service the energy charge will be the MAPP Rate for Emergency 
Energy, which is currently 30 mills/kWh.

                          Table 1.--Proposed Service Rate Formulas for New Transactions                         
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               Service                       Rate formula              1996 data         Rate based on 1996 data
----------------------------------------------------------------------------------------------------------------
Network Transmission.................  Customer's Load Ratio    Customer's Load Ratio    For comparison estimate
                                        Share * 1/12 * (Annual   Share * 1/12 *           at $3.07/kW-Mo.       
                                        Transmission Revenue     ($116.4M--$12.6M).                             
                                        Requirement--Non-Firm                                                   
                                        Revenue Credits).                                                       
Firm Point-to-Point Transmission.....  (Total Annual Revenue    ($116.4M--$12.6M)/2,819  $3.07/kW-Mo.           
                                        Requirement--Non-Firm    MW/12 months.                                  
                                        Revenue Credits)/                                                       
                                        Annual Average                                                          
                                        Transmission System                                                     
                                        Monthly Peak Load/12                                                    
                                        months.                                                                 
Non-Firm Point-to-Point Transmission.  Firm Point-to-Point      $3.07/kW--Mo/730 hours/  4.20 Mills/kWh.        
                                        rate/730 hours per       month.                                         
                                        month.                                                                  
Scheduling, System Control, and        Transmission fixed       20.59% * $6.86M/25,915   $54.50/schedule/day.   
 Dispatch.                              charge rate* ((.4137 *   daily schedules per                            
                                        Watertown net plant) +   year.                                          
                                        (.384 * communications                                                  
                                        net plant))/number of                                                   
                                        daily schedules per                                                     
                                        year.                                                                   
Reactive Supply and Voltage Control..  ((Generation fixed       ((12.3%* $613.2M *       $0.08/kW-Mo.           
                                        charge rate *            2.02%) + $1M)/2,532 MW-                        
                                        generation net plant     yr/12 months.                                  
                                        cost * capability used                                                  
                                        for reactive support)                                                   
                                        + Basin Electric and                                                    
                                        Heartland revenue                                                       
                                        requirement)/load in                                                    
                                        control area/12 months.                                                 
Regulation and Frequency Response....  COE fixed charge rate *  10.4% * $251.6M/937 MW   $0.09/kW-Mo.           
                                        COE generation net       * 64.6 MW/1,615 MW/12                          
                                        plant cost/plant         months.                                        
                                        capacity * capacity                                                     
                                        used for regulation/                                                    
                                        Western's load in                                                       
                                        control area/12 months.                                                 
Energy Imbalance.....................  Penalty................  100 mills/kWh charge     .......................
                                                                 for under deliveries                           
                                                                 outside 3% bandwidth(+/                        
                                                                 -1.5%). Over                                   
                                                                 deliveries outside 3%                          
                                                                 bandwidth forfeited to                         
                                                                 the control area.                              
Reserves.............................  Generation fixed charge  12.3% * $613.2M/2,517    $0.12/kW-Mo.           
                                        rate * generation net    MW * 80.75 MW/1,615 MW/                        
                                        plant cost/plant         12 months.                                     
                                        capacity * capacity                                                     
                                        used for reserves/                                                      
                                        Western's load in                                                       
                                        control area/12 months.                                                 
----------------------------------------------------------------------------------------------------------------

IV. Cost Shifting

    There is no immediate impact to the P-SMBP-ED firm power rate. In 
the first few years as new electric service arrangements move to the 
IS, costs will shift between the IS participants. Western will incur 
approximately $1 million/year of additional transmission cost, 
Heartland will incur approximately $200,000/year of additional 
transmission cost and Basin Electric's costs will be reduced 
approximately $2.4 million/year, based upon average Pick-Sloan 
generation. Western's increased transmission costs will have minimal 
impact to the P-SMBP-ED firm power rate. Although it is difficult to 
project cost shifting among the IS participants beyond the first few 
years following the implementation of this proposal, additional usage, 
and increased revenues should occur as existing transmission contracts 
terminate and are reformulated. This should mitigate the impact to the 
participants. Transition payments among the IS participants may be 
considered to mitigate impacts or cost shifts if in this public process 
the impacts are determined to be too severe.

V. Other Options

    All other options mentioned in the Advance Announcement are 
evaluated in the customer rate brochure. The additional comment item of 
generation based rates is also examined in the customer rate brochure.

VI. Authorities

    Transmission and ancillary services rates for the P-SMBP-ED are 
being established pursuant to the Department of Energy 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, 
particularly section 9(c) of the Reclamation Project Act of 1939 (43 
U.S.C. 485h(c)) and section 5 of the Flood Control Act of 1944 (16 
U.S.C. 825s) and other acts specifically applicable to the projects 
involved.
    By Amendment No. 3 to Delegation Order No. 0204-108, published 
November 10, 1993 (58 FR 59716), the Secretary of DOE delegated (1) the 
authority to develop long-term power and transmission rates on a 
nonexclusive basis to the Administrator of Western; (2) the authority 
to confirm, approve, and place such rates into effect

[[Page 48276]]

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 FERC. Existing DOE procedures for 
public participation in power rate adjustments are found at 10 CFR part 
903.

Regulatory Flexibility Analysis

    Pursuant to the Regulatory Flexibility Act of 1980 (5 U.S.C. 601, 
et. seq.), each agency, when required 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 adjustments are related 
to non-regulatory services provided by Western at particular rates. 
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 services are of 
limited applicability, no flexibility analysis is required.

Environmental Compliance

    Western will conduct an environmental evaluation of the proposed 
rates and develop the appropriate level of environmental documentation 
pursuant to the National Environmental Policy Act (NEPA) of 1969 (42 
U.S.C. 4321 et. seq.); the Council on Environmental Quality Regulations 
for implementing NEPA (40 CFR parts 1500 through 1508); and the DOE 
NEPA Implementing Procedures and Guidelines (10 CFR part 1021).

Review Under the Paperwork Reduction Act

    In accordance with the Paperwork Reduction Act of 1980, (44 U.S.C. 
3501 et. seq.), Western has received approval from the Office of 
Management and Budget for the collection of customer information in 
this rule, under control number 1910-0100.

Determination Under Executive Order 12866

    DOE has determined that this is not a significant regulatory action 
because it does not meet the criteria of Executive Order 12866, 58 FR 
51735. Western has an exemption from centralized regulatory review 
under Executive Order 12866; accordingly, no clearance of this notice 
by Office of Management and Budget is required.

Availability of Information

    All brochures, studies, comments, letters, memoranda, or other 
documents made or kept by Western for developing the proposed rates, 
will be made available for inspection and copying at the Upper Great 
Plains Regional Office, located at 2900 4th Avenue North, Billings, MT 
59107-5800, during normal business hours.

    Dated: September 5, 1997.
Michael S. Hacskaylo,
Acting Administrator.
[FR Doc. 97-24346 Filed 9-12-97; 8:45 am]
BILLING CODE 6450-01-P