[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 (riehl@wapa.gov).
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:
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Acronym/Term Definition
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$/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
