[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 riehl@wapa.gov
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
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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.
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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
