Pick-Sloan Missouri Basin Program-Eastern Division Transmission and Ancillary Services-Rate Order No. WAPA-122, 55821-55834 [05-19039]
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Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices
DEPARTMENT OF ENERGY
Western Area Power Administration
Pick-Sloan Missouri Basin Program—
Eastern Division Transmission and
Ancillary Services-Rate Order No.
WAPA–122
Western Area Power
Administration, DOE.
ACTION: Notice of Order Concerning
Transmission and Ancillary Services
Rates.
AGENCY:
SUMMARY: The Deputy Secretary of
Energy confirmed and approved Rate
Order No. WAPA–122 and Rate
Schedules UGP–FPT1, UGP–NFPT1,
UGP–NT1, UGP–AS1, UGP–AS2, UGP–
AS3, UGP–AS4, UGP–AS5, and UGP–
AS6 placing the Integrated System (IS)
Transmission and Ancillary Services
rate into effect on an interim basis. The
provisional rates will be in effect until
the Federal Energy Regulatory
Commission (Commission) confirms,
approves, and places them into effect on
a final basis or until they are replaced
by other rates. The provisional rates will
provide sufficient revenue to pay all
annual costs, including interest
expense, and repayment of required
investment, within the allowable
periods.
Rate Schedules UGP–FPT1,
UGP–NFPT1, UGP–NT1, UGP–AS1,
UGP–AS2, UGP–AS3, UGP–AS4, UGP–
AS5, and UGP–AS6 will be placed into
effect on an interim basis on the first
day of the first full billing period
beginning on or after October 1, 2005,
and will be in effect until the
Commission confirms, approves, and
places the rate schedules in effect on a
final basis through September 30, 2010,
or until the rate schedules are
superseded. These new rate schedules
dated October 2005, supersede the
similarly titled rate schedules dated
1998.
DATES:
FOR FURTHER INFORMATION CONTACT:
Mr.
Robert J. Harris, Upper Great Plains
Regional Manager, Western Area Power
Administration, 2900 4th Avenue North,
Billings, MT 59101–1266, telephone
(406) 247–7405, or Mr. Jon R. Horst,
Rates Manager, Upper Great Plains
Region, Western Area Power
Administration, 2900 4th Avenue North,
Billings, MT 59101–1266, telephone
(406) 247–7444, e-mail horst@wapa.gov.
SUPPLEMENTARY INFORMATION: The
Deputy Secretary of Energy approved
existing Rate Schedules UGP–FPT1,
UGP–NFPT1, UGP–NT1, UGP–AS1,
UGP–AS2, UGP–AS3, UGP–AS4, UGP–
AS5, and UGP–AS6 for IS Transmission
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and Ancillary Service rates on August 1,
1998, in Rate Order No. WAPA–79. The
Commission confirmed and approved
the rate schedules on November 25,
1998, in FERC Docket No. EF98–5031–
000. These rate schedules were then
extended through September 30, 2005,
by Rate Order No. WAPA–100, which
was confirmed and approved by the
Commission on December 16, 2003,
under FERC Docket No. EF03–5032–
000. The rate schedules for Rate Order
No. WAPA–79 and Rate Order No.
WAPA–100 contained formulary rates
that were recalculated yearly using the
fixed charge rate methodology. The
provisional formula rates will continue
to use the fixed charge rate methodology
and will continue to be recalculated
yearly from updated financial and load
data. However, the Generator Step Up
Transformers are to be removed from
the annual revenue requirement for IS.
After the approval of the original
Transmission and Ancillary Service
rates for the IS, the Commission decided
that Generator Step Up Transformers
should not be included in transmission
rates for jurisdictional utilities.
Consistent with Western’s goal to
observe Commission precedent to the
extent consistent with its mission and
permitted by law and regulation, the IS
Transmission and Ancillary Service
rates are being modified.
The existing IS Long-Term Firm and
Short-Term Firm Point-to-Point
Transmission Service Rate Schedule is
superseded by Rate Schedule UGP–
FPT1, dated October 2005. The 2004–
2005 existing rate for IS Long-Term
Firm and Short-Term Firm Point-toPoint Transmission Service is $2.72 per
kilowattmonth (kWmonth). The
provisional rate for IS Long-Term Firm
and Short-Term Firm Point-to-Point
Transmission Service is $2.69/
KWmonth. Under Rate Schedule UGP–
NFPT1, the existing rate calculation for
IS Non-Firm Point-to-Point
Transmission Service is 3.73 mills per
kilowatthour (mills/kWh). The
provisional rate for IS Non-Firm Pointto Point Transmission Service is 3.68
mills/kWh. Under Rate Schedule UGP–
NT1 the existing annual revenue
requirement for IS Network Integration
Transmission Service is $128,017,923.
The provisional annual revenue
requirement for IS Network Integration
Transmission Service is $126,741,576.
Under Rate Schedule UGP–AS1, the
existing rate for Scheduling System
Control and Dispatch (Scheduling and
Dispatch) Service is $49.29/schedule/
day. The provisional rate for Scheduling
and Dispatch is $49.77/schedule/day.
Under Rate Schedule UGP–AS2, the
existing rate for Reactive Supply and
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55821
Voltage Control from Generation
Sources Service (Reactive Service) is
$0.06/kWmonth. The provisional rate
for Reactive Service is $0.07/kWmonth.
Under Rate Schedule UGP–AS3, the
provisional rate calculated for
Regulation and Frequency Response
Service is unchanged from the existing
rate of $0.04/kWmonth. Under Rate
Schedule UGP–AS4, there is no change
in the rate for Energy Imbalance Service
between the existing and the proposed
rates. Under Rate Schedules UGP–AS5
and UGP–AS6, the rate for Spinning and
Supplemental Reserves is $0.11/
kWmonth. The provisional rate
calculated for Spinning and
Supplemental Reserves is $0.12/
kWmonth.
By Delegation Order No. 00–037.00,
effective December 6, 2001, the
Secretary of Energy delegated: (1) The
authority to develop power and
transmission rates to Western’s
Administrator, (2) the authority to
confirm, approve, and place such rates
into effect on an interim basis to the
Deputy Secretary of Energy, and (3) the
authority to confirm, approve, and place
into effect on a final basis, to remand or
to disapprove such rates to the
Commission. Existing DOE procedures
for public participation in power rate
adjustments (10 CFR part 903) were
published on September 18, 1985.
Under Delegation Order Nos. 00–
037.00 and 00–001.00A, 10 CFR part
903, and 18 CFR part 300, I hereby
confirm, approve, and place Rate Order
No. WAPA–122, the proposed IS Firm
and Non-Firm Transmission and
Ancillary Service rates into effect on an
interim basis. The new Rate Schedules
UGP–FPT1, UGP–NFPT1, UGP–NT1,
UGP–AS1, UGP–AS2, UGP–AS3, UGP–
AS4, UGP–AS5, and UGP–AS6 for IS
Transmission and Ancillary Service
rates will be promptly submitted to the
Commission for confirmation and
approval on a final basis.
Dated: September 13, 2005.
Clay Sell,
Deputy Secretary.
[Rate Order No. WAPA–122]
In the matter of: Western Area Power
Administration Rate Adjustment for the PickSloan Missouri Basin Program—Eastern
Division Transmission and Ancillary
Services; Order Confirming, Approving, and
Placing the Pick-Sloan Missouri Basin
Program—Eastern Division Transmission and
Ancillary Services Formula Rates Into Effect
on an Interim Basis
This rate was established in
accordance with section 302 of the
Department of Energy (DOE)
Organization Act (42 U.S.C. 7152). This
Act transferred to and vested in the
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Secretary of Energy the power marketing
functions of the Secretary of the
Department of the Interior and the
Bureau of Reclamation under the
Reclamation Act of 1902 (ch. 1093, 32
Stat. 388), as amended and
supplemented by subsequent laws,
particularly section 9(c) of the
Reclamation Project Act of 1939 (43
U.S.C. 485h(c)), section 5 of the Flood
Control Act of 1944 (16 U.S.C. 825s),
and other Acts that specifically apply to
the project involved.
By Delegation Order No. 00–037.00,
effective December 6, 2001, the
Secretary of Energy delegated: (1) The
authority to develop power and
transmission rates to Western’s
Administrator, (2) the authority to
confirm, approve, and place such rates
into effect on an interim basis to the
Deputy Secretary of Energy, and (3) the
authority to confirm, approve, and place
into effect on a final basis, to remand or
to disapprove such rates to the
Commission. Existing DOE procedures
for public participation in power rate
adjustments (10 CFR part 903) were
published on September 18, 1985.
Acronyms and Definitions
As used in this Rate Order, the
following acronyms and definitions
apply:
$/kWmonth: Monthly charge for
capacity (i.e., $ per kilowatt (kW) per
month).
12-cp: 12-month coincident peak
average.
Administrator: The Administrator of
the Western Area Power
Administration.
Ancillary Services: Those services
necessary to support the transfer of
electricity while maintaining reliable
operation of the transmission system in
accordance with standard utility
practice.
A&GE: Administrative and general
expense.
Balancing Authority: An electric
system or systems, bounded by
interconnection metering and telemetry,
capable of controlling generation to
maintain its interchange schedule with
other Balancing Authorities and
contributing to frequency regulation of
the Interconnection. Formerly known as
control area.
Basin Electric: Basin Electric Power
Cooperative.
Capacity: The electric capability of a
generator, transformer, transmission
circuit, or other equipment. It is
expressed in kilowatts.
Capacity Rate: The rate which sets
forth the charges for capacity. It is
expressed in $/kWmonth.
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Commission: Federal Energy
Regulatory Commission.
Corps of Engineers: U.S. Army Corps
of Engineers.
Customer: An entity with a contract
that is receiving service from Western’s
UGPR.
DOE: United States Department of
Energy.
DOE Order RA 6120.2: An order
outlining power marketing
administration financial reporting and
ratemaking procedures.
Energy: Measured in terms of the
work capacity over a period of time. It
is expressed in kilowatthours.
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.
Energy Rate: The rate which sets forth
the charges for energy. It is expressed in
mills per kilowatthour and applied to
each kilowatthour delivered to each
customer.
FERC: The Commission (to be used
when referencing Commission Orders).
FERC Order No. 888: FERC Order
Nos. 888, 888–A, 888–B and 888–C
unless otherwise noted.
Firm: A type of product and/or service
available at the time requested by the
customer.
Firm Point-to-Point: Service that is
reserved and/or scheduled between
Points of Receipt and Delivery.
FRN: Federal Register notice.
FY: Fiscal year; October 1 to
September 30.
GSU: Generator Step Up Transformer.
GWh: Gigawatthour—the electrical
unit of energy that equals 1 billion
watthours or 1 million kWh.
Heartland: Heartland Consumers
Power District.
IS: Integrated System.
ISO: Independent System Operator.
JTS: Joint Transmission System.
kW: Kilowatt—the electrical unit of
capacity that equals 1,000 watts.
kWh: Kilowatthour—the electrical
unit of energy that equals 1,000 watts in
1 hour.
kWmonth: Kilowattmonth—the
electrical unit of the monthly amount of
capacity.
kWyear: Kilowattyear—the electrical
unit of the yearly amount of capacity.
Load: The amount of electric power or
energy delivered or required at any
specified point(s) on a system.
Load-ratio share: Ratio of the Network
Transmission Customer’s coincident
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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
reservation with at least 12 consecutive
equal monthly amounts.
MAPP: Mid-Continent Area Power
Pool.
MBMPA: Missouri Basin Municipal
Power Agency.
Mill: A monetary denomination of the
United States that equals one tenth of a
cent or one thousandth of a dollar.
Mills/kWh: Mills per kilowatthour—
the unit of charge for energy.
MVAR: Megavar, equal to 1,000,000
VARs.
MW: Megawatt—the electrical unit of
capacity that equals 1 million watts or
1,000 kilowatts.
NERC: North American Electric
Reliability Council.
Net Revenue: Revenue remaining after
paying all annual expenses.
Network Customer: An entity
receiving Transmission Service under
the terms of the Transmission Provider’s
Network Integration Transmission
Service of the Tariff.
Non-Firm Point-to-Point: Point-toPoint 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.
OASIS: Open Access Same-Time
Information System—provides access to
information on transmission pricing and
availability for potential transmission
customers.
OM&R: Operation, Maintenance &
Replacement.
P–SMBP: Pick-Sloan Missouri Basin
Program.
P–SMBP—ED: Pick-Sloan Missouri
Basin Program—Eastern Division.
Point-to-Point: The reservation and
transmission of capacity and energy on
either a firm or non-firm basis from
designated Point(s) of Receipt to
designated Point(s) of Delivery.
Power: Capacity and energy.
Provisional Rate: A rate which has
been confirmed, approved, and placed
into effect on an interim basis by the
Deputy Secretary.
Rate Brochure: An April 2005
document explaining the rationale and
background for the rate proposal
contained in this Rate Order.
Reclamation: United States
Department of the Interior, Bureau of
Reclamation.
Reclamation Law: A series of Federal
laws. Viewed as a whole, these laws
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create the framework under which
Western markets power.
Reactive Supply and Voltage Control
from Generating Sources Service: A
service which provides reactive supply
through changes to generator reactive
output to maintain transmission line
voltage and facilitate electricity
transfers.
Regulation and Frequency Response
Service: A service which provides for
following the moment-to-moment
variations in the demand or supply in
a Balancing Authority and maintaining
scheduled interconnection frequency.
Reserve Services: Spinning Reserve
Service and Supplemental Reserve
Service.
Revenue Requirement: The revenue
required to recover annual expenses
(such as O&M, purchase power,
transmission service expenses, interest,
and deferred expenses) and repay
Federal investments, and other assigned
costs.
SCADA: Supervisory Control and Data
Acquisition.
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 Balancing Authority(ies)
involved in the transaction.
Scheduling, System Control and
Dispatch Service: A service which
provides for (a) scheduling, (b)
confirming and implementing an
interchange schedule with other
balancing authorities, including
intermediary balancing authorities
providing transmission service, and (c)
ensuring operational security during the
interchange transaction.
Service Agreement: The initial
agreement and any amendments or
supplements entered into by the
Transmission Customer and Western for
service under the Tariff.
Short-Term Firm Point-to-Point: Firm
Point-to-Point Transmission Service
with service duration of less than one
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 Balancing Authority. The
Transmission Customer must either
purchase this service from the
Transmission Provider or make
alternative comparable arrangements to
satisfy its Spinning Reserve Service
obligation.
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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 generation 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 Balancing
Authority. 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: A
compilation of data and documents that
support the Rate Brochure and the rate
proposal.
System: An interconnected
combination of generation, transmission
and/or distribution components
comprising an electric utility,
independent power producer(s) (IPP), or
group of utilities and IPP(s).
Tariff: Western Area Power
Administration Open Access
Transmission Service Tariff, originally
approved in Docket No. NJ98–1–000, 99
FERC ¶ 61,062 (2002) and amended in
Docket No. NJ05–1–000, 112 FERC
¶ 61,044 (2005).
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 to transmit electric energy in
interstate commerce. The 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 Load: The
12-cp peak for Network Transmission
Service plus reserved capacity for all
Firm Point-to-Point Transmission
Service.
UGPR: The Upper Great Plains
Customer Service Region of the Western
Area Power Administration. In some
places in this order, UGPR maybe
referenced generically as Western.
VAR: A unit of reactive power.
WAUGP: The NERC acronym for the
Western Area Upper Great Plains
Balancing Authority. This balancing
authority is also known as the
Watertown Balancing Authority.
Watertown Operation Office: Western
Area Power Administration Upper Great
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Plains Customer Service Region,
Operations Office, 1330 41st Street SE.,
Watertown, South Dakota.
Western: United States Department of
Energy, Western Area Power
Administration.
Western Regions: Customer service
regions of the Western Area Power
Administration.
Western’s Tariff: Western’s Open
Access Transmission Service Tariff.
Effective Date
The new interim rates will take effect
on the first day of the first full billing
period beginning on or after October 1,
2005, and will remain in effect until
September 30, 2010, pending approval
by the Commission on a final basis.
Public Notice and Comment
Western followed the Procedures for
Public Participation in Power and
Transmission Rate Adjustments and
Extensions, 10 CFR part 903, for a minor
rate adjustment in developing these
rates. The steps Western took to involve
interested parties in the rate process
were:
1. The proposed rate adjustment
process began February 9, 2005, when
Western mailed a notice announcing an
informal customer meeting to all IS
Transmission Customers and interested
parties. The meeting was held on March
22, 2005, in Sioux Falls, South Dakota.
At this informal meeting, Western
explained the rationale for the rate
adjustment, presented rate designs and
methodologies, and answered questions.
2. A Federal Register notice
published on April 18, 2005, (70 FR
20119), announced the proposed rates
for P–SMBP—ED Transmission and
Ancillary Service rates, and began a
public consultation and comment
period.
3. On April 28, 2005, Western mailed
letters to all IS Transmission Customers
and interested parties transmitting the
Federal Register notice published on
April 18, 2005, and directing them to
the rate brochure on Western’s Web site.
4. Western received no comment
letters during the consultation and
comment period, which ended May 18,
2005.
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, 890, Pub. L. 78–534).
It was later renamed the 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
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production for the entire Missouri River
Basin. Multipurpose projects have been
developed on the Missouri River and its
tributaries in Colorado, Montana,
Nebraska, North Dakota, South Dakota,
and Wyoming.
The UGPR markets significant
quantities of Federally-generated
hydroelectric power from the P–
SMBP—ED. Western owns and operates
an extensive system of high-voltage
transmission facilities which the 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. The UGPR uses 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 and
South Dakota, eastern Nebraska, western
Iowa, and western Minnesota.
Integrated System Description
Using a single system, joint-planning
concept, the UGPR, Basin Electric, and
Heartland combined their transmission
facilities to form the IS and developed
Transmission and Ancillary Service
rates for transmission over the IS. This
action was necessary because the 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 IS Transmission System.
The UGPR is designated as the operator
of the other participants’ transmission
facilities and as such contracts for
service, determines and posts the
available transmission capacity on the
OASIS, bills for service, collects
payments, and distributes revenues to
each IS participant. 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, Iowa, Minnesota,
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 the
most useful to all transmission
requesters. The ‘‘seven-factor test’’
defined in FERC Order No. 888 was
used to determine the distribution
facilities that were excluded from the IS
Transmission System. Several major
facilities are included in the IS. The
second 345-kV transmission line
between the Antelope Valley and
Leland Olds generation stations, which
meets the standards for acceptable
transmission facilities set in the
Commission rulings on filings by other
transmission entities, is included. The
230-kV transmission line between
Tioga, North Dakota, and Boundary
Dam, which provides access to
generation and loads in Canada, is
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.
P–SMBP—ED Transmission and
Ancillary Service Rates Study
Western prepared a Transmission and
Ancillary Service rates study to ensure
that Transmission and Ancillary Service
rates are based on the cost of service of
the IS Transmission System. This study
includes all IS Transmission and
Ancillary Service expenses and
associated offsetting revenues. Western
charges IS Transmission Service rates
separately to entities receiving
transmission-only services over the IS
Transmission System.
The UGPR is proposing to continue
using an annual fixed charge formula
that will determine how much revenue
must be recovered from the IS
Transmission and Ancillary Service
rates. The annual revenue requirements
include O&M expenses, administrative
and general expenses, interest expense,
and depreciation expense. This
methodology is applied annually using
the most recent historical test year.
These revenue requirements are offset
by appropriate IS revenues.
Integrated System Transmission
Service
Western will offer Network, Firm
Point-to-Point, and Non-Firm Point-toPoint 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 Service 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
Western’s Customers continues to be
bundled in the firm electric power
service rate under existing contracts that
expire in 2020.
The UGPR prepared a transmission
service study to ensure that the formula
IS Transmission and Ancillary Service
rates are based on the cost of service to
the IS. The UGPR seeks approval of
formula rates for calculating Point-toPoint IS Transmission Rates, the
Network Annual Revenue Requirement
for IS Transmission Service, and
ancillary service rates. Western requests
the Commission confirm that these rates
are not arbitrary, capricious, or in
violation of the law. The rates will be
recalculated every year, effective May 1,
based on the approved formula rates
and updated financial and load data.
The UGPR will provide customers
notice of changes in the Transmission
and Ancillary Service rates no later than
April 1 of each year.
IS Transmission System Total Load
The IS Transmission System Total
Load is the 12-cp system peak for IS
Network Transmission Service plus the
reserved capacity for all IS Long-Term
Firm Point-to-Point Transmission
Service.
The IS Transmission System Total
Load is calculated as follows based
upon the most recent historical data
available at the time of the initial rate
proposal. This included both 2003 and
2004 data:
IS Network Transmission Load .................................................................................................................................................
Long-Term Firm Point-to-Point Reserved Capacity ..................................................................................................................
3,185,000 kW
743,000 kW
IS Transmission System Total Load ..........................................................................................................................................
3,928,000 kW
Annual Costs
Western calculated the annual costs of
providing the various IS Transmission
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and Ancillary Services using a
Commission-recognized methodology
for annual cost calculation with fixed
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charge rates for various cost
components. The cost components
applicable to Western include O&M,
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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
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fixed charge rate calculation for the
various IS 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
the IS Transmission Service or one of
the Ancillary Services, the total fixed
charge rate is applied to the net
investment allocated to the service:
Total fixed charge rate × Net
investment = Annual cost of providing
service.
The source for the 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 RegionPick Sloan Missouri Basin. 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 annual revenue requirement for
IS Transmission Service is based upon
the most recent historical data available
at the time of the initial rate proposal.
This data is used in a test year and uses
an annual fixed charge methodology.
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 the IS Transmission Service
plus any facility credit paid to the IS
Transmission Customers. The annual
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
+ Annual IS Transmission Costs Basin Electric and Heartland
+ Transmission Customer Facility Credits
¥ Transmission Revenue Credits
Annual Revenue Requirement for IS Transmission Service
Transmission Customer Facility
Credits are credits paid to IS
Transmission Customers for facilities
that are integrated with the IS and
increase both the capability and the
reliability of the IS. The credits are
addressed in individual agreements and
appropriate adjustments are made in
subsequent rate calculations. The IS
participants will evaluate requests for
facility credits consistent with the
Commission’s guidance in the FERC
Order No. 888, other relevant
Commission policy, and the terms of the
Tariff.
Transmission Revenue Credits
include revenue from sales of Non-Firm,
discounted IS Firm and Short-Term
Firm Point-to-Point Transmission
Service; revenue from existing
transmission agreements; and revenue
from Scheduling, System Control and
Dispatch Services.
IS Network Transmission Service
The proposed rate for IS Network
Transmission Service is a formula
calculation based upon the annual
revenue requirement for IS
Transmission Service then in effect, as
determined by the annual fixed charge
methodology. The monthly charge for IS
Network Transmission Service is as
follows:
Network Customer’s Load-ratio share
× Annual Revenue Requirement for IS Transmission
÷ 12 months
Monthly IS Network Transmission Service Charge
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
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on a rolling 12-cp basis. The proposed
rate formula would be effective October
1, 2005, through September 30, 2010.
IS Firm Point-to-Point Transmission
Service
The rate for IS Firm Point-to-Point
Transmission Service is the annual
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revenue requirement for IS
Transmission Service divided by the IS
Transmission System Total Load in kW,
to derive a cost per kilowattyear
(kWyear). The formula for the monthly
rate is as follows:
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55826
Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices
Annual Revenue Requirement for IS Transmission
÷ IS Transmission System Total Load
÷ 12 months
Monthly IS Firm Point-to-Point Transmission Rate
The rate formula is applied annually
by using the most current historical data
available. The proposed rate formula
would be effective October 1, 2005,
through September 30, 2010.
IS Non-Firm Point-to-Point
Transmission Service
The proposed rate for IS Non-Firm
Point-to-Point Transmission Service is a
mills/kWh rate, based upon the current
firm point-to-point rate and may be
discounted. The formula rate is as
follows:
Monthly IS Firm Point-to-Point Transmission Rate
÷ 730 hours/month
× 1000 mills per dollar
IS Non-Firm Point-to-Point Transmission Rate
This rate will remain in effect for the
same period as the IS Firm Point-toPoint Transmission Service rate and
will also be reviewed annually. The IS
Non-Firm Point-to-Point Transmission
Service will be offered at hourly, daily,
and monthly rates. The IS Transmission
Service availability will be posted on
the UGPR OASIS.
Ancillary Services
In accordance with the Tariff, Western
will offer to all customers the six
ancillary services defined by the
Commission, two of which IS
Transmission Customers are required to
purchase: (1) Scheduling, System
Control, and Dispatch Service, and (2)
Reactive Supply and Voltage Control
from Generation Sources Service. The
remaining four ancillary services are: (3)
Regulation and Frequency Response
Service, (4) Energy Imbalance Service,
(5) Spinning Reserve Service, and (6)
Supplemental Reserve 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.
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. In
accordance with the Tariff, 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, including an administrative
charge to the customer.
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:
Annual Revenue Requirement for
Scheduling, System Control and Dispatch Service
÷ Annual Number of Daily Schedules
Scheduling, System Control and Dispatch Rate
This rate and rate design only recovers
Western’s revenue requirement for
Scheduling, System Control, and
Dispatch Service.
Reactive Supply and Voltage Control
from Generation Sources Service
Western’s annual cost of providing
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 and
Heartland’s annual revenue requirement
is based on the annual cost of
equipment installed on its generators to
provide this service. Western’s, Basin
Electric’s, and Heartland’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 total annual revenue
requirement by the load requiring
reactive service. The annual rate is then
divided by 12 months to obtain a
monthly rate. The Reactive Supply and
Voltage Control rate calculation is
summarized in the following formula:
Annual Reactive Revenue Requirement
+ Load Requiring Reactive Service
÷ 12 months
Monthly Reactive Rate
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Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices
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 Service in the balancing
authority. 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
yearly peak condensing as percentage of
load for five years. Western’s 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
Regulation and Frequency Response
Service
Regulation and Frequency Response
Service in the east side of the balancing
authority is provided primarily by Oahe
generation and in the west side of the
balancing authority by Fort Peck
generation, both of which are Corps of
Engineer facilities. To calculate the
annual cost of providing Regulation and
Frequency Response Service, the Corps
of Engineers’ 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
55827
Service. Basin Electric’s and Heartland’s
annual revenue requirement is based on
the annual cost of equipment installed
on its generators to provide this service.
Western’s, Basin Electric’s, and
Heartland’s annual revenue
requirements are summed for the total
revenue requirement for this service.
Annual rate for Regulation and
Frequency Response Service is then
determined by dividing the total
revenue requirement by the total load in
the Balancing Authority. The annual
rate is then divided by 12 months to
obtain a monthly rate. The Regulation
and Frequency Response Service rate
calculation is summarized in the
following formula:
Annual Revenue Requirement for Regulation
+ Load in the Balancing Authority Requiring Regulation
÷ 12 months
Monthly Regulation and Frequency Response Rate
Energy Imbalance Service
Reserve Services
This service is not intended to
provide backup for generation supply.
Energy shall be returned in like time
frames (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 bandwidth
will be forfeited to the balancing
authority.
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. This rate and rate design
recovers only Western’s revenue
requirement associated with Reserve
Services. If energy is taken under these
services, the energy charge will be the
MAPP or its successors rate for
emergency energy. The Regulation and
Frequency Response Service rate
calculation is summarized in the
following formula:
Annual Revenue Requirement for Reserves
÷ Load Requiring Reserves
÷ 12 months
Monthly Reserve Service Rate
Existing and Provisional Rates
values are outlined in the following
table. These rates are calculated
comparing the Existing Revenue
Requirement to the Revenue
The revenue requirements for the
individual services and comparison
Requirement based upon the most
recent historical data available at the
time of the initial rate proposal.
TABLE 1
Existing revenue
requirement
Service
Transmission ............................................................................................................................
Scheduling, System Control and Dispatch ..............................................................................
Reactive Supply and Voltage Control from Generation Sources ............................................
Regulation and Frequency Control ..........................................................................................
Reserves ..................................................................................................................................
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$128,017,923
3,373,281
2,736,253
1,065,771
1,895,268
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23SEN1
Provisional
revenue
requirement
$126,741,576
3,406,102
3,065,568
1,075,623
2,009,276
Percentage
change
¥0.997
¥0.973
12.035
0.924
6.015
55828
Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices
Certification of Rates
Western’s Administrator certifies that
the IS Transmission and Ancillary
Service rates placed into effect on an
interim basis are the lowest possible
rates consistent with sound business
principles. The provisional formula
rates were developed following
administrative policies and applicable
laws.
IS Transmission Service Discussion
Western proposes continuing the
annual fixed charge formula to
determine the Annual Revenue
Requirement for IS Transmission
Service. The annual revenue
requirement for IS Transmission Service
includes O&M expense, A&GE, interest
expense, and depreciation expense from
the most recent historical test year. This
annual revenue requirement for IS
Transmission Service is offset by
appropriate revenue credits.
The IS Transmission System includes
the transmission facilities owned by
Western, Basin Electric, Heartland and
others in which the IS has contractual
rights. The costs paid to others for
contractual rights on their transmission
lines are included in the costs recovered
by the annual revenue requirement for
IS Transmission Service.
Western will continue to offer
Network, Firm Point-to-Point, and NonFirm Point-to-Point Transmission
Service on the IS Transmission System.
The service offered is the transmission
of energy and capacity from Points of
Receipt to Points of Delivery on the IS.
The IS Transmission Service 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.
The provisional IS Transmission
Service rates will be applied to
customers who purchase transmission
services. Western, Basin Electric, and
Heartland will take IS Transmission
Service. The IS Transmission Service to
the UGPR’s Customers will continue to
be bundled in the firm electric service
rate under existing contracts that expire
in 2020.
IS Transmission System Total Load
The IS Transmission System Total
Load is the 12-cp system peak for
Network IS Transmission Service plus
the reserved capacity for all IS LongTerm Firm Point-to-Point Transmission
Service. For the provisional rate, the IS
Transmission System Total Load will be
unchanged at 3,968,000 kW.
Annual Costs
Western will continue to use a
Commission-recognized methodology
for annual cost calculation with fixed
charge rates for various cost components
approved by the Commission in WAPA–
79 and WAPA–100. The change in the
provisional rate is that the costs
associated with the GSUs are no longer
included in the net plant investment for
transmission or the various expenses.
The investment and costs for GSUs are
now in the generation fixed charge
calculation in support of ancillary
services. The proposed methodology
will continue to be an annual fixed
charge formula that will determine the
annual revenue requirement to be
recovered from transmission services.
Annual Revenue Requirement for IS
Transmission
A change in the costs that comprise
the annual revenue requirement for IS
Transmission is being proposed. The
proposed transmission rate
methodology is different from the
current transmission rate methodology
in one area. The GSU investments are
removed from the transmission
investments and placed in the
generation investments. This also moves
the corresponding costs of GSUs from
transmission costs to generation costs.
The existing annual revenue
requirement for IS Transmission Service
is $128,017,923. The provisional
Annual Revenue Requirement for IS
Transmission Service is $126,741,576.
Network
The current IS Network Transmission
Service schedule expires on September
30, 2005. The provisional annual
revenue requirement for IS
Transmission Service will be used in
the provisional rate formula for IS
Network Transmission Service. The
provisional charge for the monthly
demand for IS Network Transmission
Service will be the product of the
network customer’s load ratio share
times one-twelfth (1/12) of the annual
revenue requirement for IS
Transmission Service. The load ratio
share will be based on the network
customer’s hourly load (including its
designated network load not physically
interconnected with Western),
coincident with the IS monthly
transmission system peak, which will be
calculated on a rolling 12-cp basis.
Western’s transmission system peak
includes the sum of capacity reserved
for IS Point-to-Point Transmission
Service, 12-cp monthly entitlements for
firm power customers, and the average
12-cp monthly system peak for IS
Network Transmission Service. The
provisional rate formula is to be
effective beginning October 1, 2005,
through September 30, 2010.
Firm Point-to-Point
The current IS Firm Point-to-Point
Transmission Service rate for 2004–
2005 is $2.72 and expires September 30,
2005. The provisional formula rate will
continue to be the Annual Revenue
Requirement for IS Transmission
Service divided by the IS Transmission
System Total Load. The provisional rate
for IS Firm Point-to-Point Transmission
Service is $2.69 per kWmonth for 2004–
2005.
Non-Firm Point-to-Point
The current IS Non-Firm
Transmission Service rate expires
September 30, 2005. The provisional
rate for IS Non-Firm Transmission
Service is expressed in mills/kWh and
is based on the current IS Firm Pointto-Point Transmission Service rate and
may be discounted. The provisional IS
Non-Firm Point-to-Point Transmission
Service rate will be the IS Firm Pointto-Point Transmission Service rate
divided by 730 hours per month and
multiplied by 1000 mills per dollar. The
provisional IS Non-Firm Transmission
Service rate for 2004–2005 is 3.68 mills/
kWh.
The following table summarizes the
difference in calculations between the
current IS Transmission Service rates
and the provisional IS Transmission
Service rates. It compares the change in
the average annual projections used in
the 2004–2005 transmission and
ancillary services study and the
provisional IS Transmission Service
rates for this rate adjustment based upon
the most recent historical data available
at the time of the initial rate proposal.
COMPARISON OF ANNUAL REVENUES
Item
Existing rate
Annual IS Costs .......................................................................................................................
Transmission Customer Facility Credits ..................................................................................
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$137,088,496
2,482,447
E:\FR\FM\23SEN1.SGM
23SEN1
Provisional rate
$136,289,145
2,482,647
Percent
change
¥0.577
0.000
55829
Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices
COMPARISON OF ANNUAL REVENUES—Continued
Item
Existing rate
Transmission Revenue Credits ...............................................................................................
Annual Revenue Requirement for IS Transmission Service ...................................................
The change in annual revenue
requirement for IS Transmission Service
is primarily a result of a revision in the
allocation of expenses and investments.
The revenue change between the
existing rate and the provisional rate is
<1 percent and, therefore, this is a
minor rate adjustment.
Basis for Rate Development
The existing rates for IS Network,
Firm and Non-Firm Transmission
Service in Rate Schedules UGP–NT1,
UGP–FPT1, and UGP–NFPT1, expire
September 30, 2005. This rate
adjustment contains rates that replace
existing rates. The adjusted rates reflect
changes in costs. The provisional rates
will provide sufficient revenue to pay
all annual costs, including interest
expense, and repay investment within
the allowable period. The provisional IS
Transmission Service rates, detailed in
Rate Schedules UGP–NT1, UGP–FPT1,
and UGP–NFPT1, will take effect on
October 1, 2005 to correspond with the
start of the Federal fiscal year and
remain in effect through September 30,
2010, or until replaced.
The proposed rates for IS
Transmission Service include a
provision to pass through electric
industry restructuring costs associated
with providing transmission service.
These costs will be passed through to
each appropriate IS Transmission
Customer.
Comments
Western did not receive any
comments or responses regarding the IS
Transmission Service rate adjustment.
Ancillary Services Discussion
The IS will continue to offer six
ancillary services. These are (1)
Scheduling, system control, and
dispatch service, (2) reactive supply and
voltage control service, (3) regulation
and frequency response service, (4)
energy imbalance service, (5) spinning
reserve service, and (6) supplemental
reserve service. The first two are
required services: (1) Scheduling,
system control, and dispatch service
9,454,494
128,017,923
Percent
change
Provisional rate
9,454,494
126,741,576
0.000
¥0.997
and (2) reactive supply and voltage
control service. All these ancillary
services are listed in Western’s Tariff.
The provisional rates for ancillary
services are designed to recover only the
costs associated with providing the
service(s). The formula for calculating
the rates will remain the same but the
GSUs will be included in the
investment and costs for the generation
fixed charge in support of ancillary
services. The costs for providing
Scheduling, System Control, and
Dispatch Service are included in the
provisional IS Transmission Service
rates.
The following table summarizes the
difference in calculations between the
current IS Ancillary Service rates and
the provisional IS Ancillary Service
rates. It compares the change in the
average annual projections used in the
2004–2005 transmission and ancillary
services study and the provisional IS
Transmission and Ancillary Service
rates for this rate adjustment based upon
the most recent historical data available
at the time of the initial rate proposal.
COMPARISON OF ANCILLARY SERVICE RATES
Item
Unit
Scheduling, System Control and Dispatch Service .................................
Reactive Supply and Voltage Control ......................................................
Regulation and Frequency Response ......................................................
Energy Imbalance ....................................................................................
Reserves ..................................................................................................
schedule/day .........
kWmonth ...............
kWmonth ...............
n/a .........................
kWmonth ...............
Existing rate
$49.29
0.06
0.04
n/a
0.11
Provisional
rate
Percent
change
$49.77
0.07
0.04
n/a
0.12
0.974
16.667
0.000
n/a
9.091
Basis for Rate Development
Comments
Regulatory Procedure Requirements
The existing rates for IS Ancillary
Services in Rate Schedules UGP–AS1,
UGP–AS2, UGP–AS3, UGP–AS4, UGP–
AS5, and UGP–AS6, expire September
30, 2005. The rate adjustment contains
rates that replace existing rates. The
adjusted rates reflect a revised
methodology and changes in costs. The
provisional rates will provide sufficient
revenue to pay all annual costs,
including interest expense, and
repayment of required power
investment within the allowable period.
The provisional rates will take effect on
October 1, 2005, to correspond with the
start of the Federal fiscal year and
remain in effect through September 30,
2010.
Western did not receive any
comments or responses regarding the IS
Ancillary Services rate adjustment.
Regulatory Flexibility Analysis
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Availability of Information
Information about this rate
adjustment, including studies,
brochures, comments, letters,
memorandums, and other supporting
material made or kept by Western, used
to develop the provisional rates, is
available for public review in the Upper
Great Plains Regional Office, 2900 4th
Avenue North, Billings, Montana.
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The Regulatory Flexibility Act of 1980
(5 U.S.C. 601, et seq.) requires Federal
agencies to perform a regulatory
flexibility analysis if a final rule is likely
to have a significant economic impact
on a substantial number of small entities
and there is a legal requirement to issue
a general notice of proposed
rulemaking. Western has determined
that this action does not require a
regulatory flexibility analysis since it is
a rulemaking of particular applicability
involving rates or services applicable to
public property.
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55830
Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices
Environmental Compliance
In compliance with the National
Environmental Policy Act (NEPA) of
1969 (42 U.S.C. 4321, et seq.); Council
on Environmental Quality Regulations
(40 CFR parts 1500–1508); and DOE
NEPA Regulations (10 CFR part 1021),
Western has determined that this action
is categorically excluded from preparing
an environmental assessment or an
environmental impact statement.
Determination Under Executive Order
12866
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.
Small Business Regulatory Enforcement
Fairness Act
Western has determined that this rule
is exempt from congressional
notification requirements under 5 U.S.C.
801 because the action is a rulemaking
of particular applicability relating to
rates or services and involves matters of
procedure.
Submission to the Federal Energy
Regulatory Commission
The interim rates herein confirmed,
approved, and placed into effect,
together with supporting documents,
will be submitted to the Commission for
confirmation and final approval.
Order
In view of the foregoing and under the
authority delegated to me, I confirm and
approve on an interim basis, effective
October 1, 2005, formula rates for the IS
Transmission and Ancillary Services
under Rate Schedules UGP–FPT1, UGP–
NFPT1, UGP–NT1, UGP–AS1, UGP–
AS2, UGP–AS3, UGP–AS4, UGP–AS5,
and UGP–AS6. The rate schedules shall
remain in effect on an interim basis,
pending the Commission’s confirmation
and approval of them or substitute rates
on a final basis through September 30,
2010.
Dated: September 13, 2005.
Clay Sell,
Deputy Secretary.
Rate Schedule UGP–AS1; October 1, 2005;
Supersedes 1998 Schedule
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 October 1,
2005, through September 30, 2010, or
until superseded by another rate
schedule.
Applicable
This service is required to schedule
the movement of power through, out of,
within, or into the Western Area Upper
Great Plains Balancing Authority
(WAUGP). The charges for Scheduling,
System Control, and Dispatch Service
are to be based on the rate outlined
below. The formula rate used to
calculate the charges for service under
this schedule was developed and may
be modified under applicable Federal
laws, regulations, and policies.
The rate will be applied to all
schedules for WAUGP nonTransmission 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
developed under applicable Federal
laws, regulations, and policies and
made part of the applicable
Transmission Customer’s Service
Agreement.
The Upper Great Plains Region
(UGPR) shall charge the nonTransmission Customer under the rate
then in effect.
Formula Rate
Annual Revenue Requirement for Scheduling, System Control, and Dispatch Service
Rate per
Schedule per Day =
Number of Daily Schedules per Year
A recalculated rate will go into effect
every May 1 based on the above formula
and data. The UGPR will notify the
customer annually of the recalculated
rate on or before April 1.
Rate Schedule UGP–AS2; October 1, 2005;
Supersedes 1998 Schedule
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 October 1,
2005, through September 30, 2010, or
until superseded by another rate
schedule.
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Applicable
To maintain transmission voltages on
all transmission facilities within
acceptable limits, generation facilities
under the control of the Western Area
Upper Great Plains balancing authority
(WAUGP) are operated to produce or
absorb reactive power. Thus, Reactive
Supply and Voltage Control from
Generation Sources Service (Reactive
Service) must be provided for each
transaction on the transmission
facilities. The amount of Reactive
Service that must be supplied with
respect to the Transmission Customer’s
transaction will be determined based on
the Reactive Service 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
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Transmission Provider. The charges for
such service will be based upon the rate
outlined below. The formula rate used
to calculate the charges for service
under this schedule was developed and
may be modified under applicable
Federal laws, regulations, and policies.
The charges for Reactive Service may
be modified upon written notice to the
Transmission Customer. Any change to
the charges for Reactive Service shall be
as set forth in a revision to this rate
schedule developed under applicable
Federal laws, regulations, and policies
and made part of the applicable
Transmission Customer’s Service
Agreement. The Upper Great Plains
Region (UGPR) shall charge the
Transmission Customer under the rate
then in effect.
Those Transmission Customers with
generators in the balancing authority
providing WAUGP with adequate
E:\FR\FM\23SEN1.SGM
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EN23SE05.060</MATH>
Rate
Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices
Reactive Service will not be charged for
this service. Any waiver of this charge
or any crediting arrangements for
Reactive Service must be documented in
the Transmission Customer’s Service
Agreement.
55831
Formula Rate
Formula Rate
WAUGP
Annual Revenue Requirement for Reactive Service
Reactive Service =
Load Requiring Reactive Service
Rate
Rate
A recalculated rate will go into effect
every May 1 based on the above formula
and updated financial and load data.
The UGPR will notify the Transmission
Customer annually of the recalculated
rate on or before April 1.
Rate Schedule UGP–AS3; October 1, 2005;
Supersedes 1998 Schedule
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 October 1,
2005, through September 30, 2010, or
until superseded by another rate
schedule.
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
balancing authority (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 outlined below. The amount of
Regulation will be set forth in the
applicable Transmission Customer’s
Service Agreement.
The formula rate used to calculate the
charges for service under this schedule
was developed and may be modified
under 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
developed under applicable Federal
laws, regulations, and policies and
made part of the applicable
Transmission Customer’s Service
Agreement. The Upper Great Plains
Region (UGPR) shall charge the
Transmission Customer under the rate
then in effect.
Transmission Customers will not be
charged for this service if they receive
Regulation from another source, or selfsupply 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
WAUGP
Annual Revenue Requirement for Regulation
Regulation =
Load in the Balancing Authority Requiring Regulation
Rate
Upper Great Plains Region Integrated
System: Energy Imbalance Service
Effective
The first day of the first full billing
period beginning on or after October 1,
2005, through September 30, 2010, or
until superseded by another rate
schedule.
VerDate Aug<31>2005
15:21 Sep 22, 2005
Jkt 205001
Energy Imbalance Service is provided
when a difference occurs between
scheduled and actual delivery of energy
to a load located within the Western
Area Upper Great Plains Balancing
Authority (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 developed and may be modified
PO 00000
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Fmt 4703
Sfmt 4703
under 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
developed under applicable Federal
laws, regulations, and policies and
made part of the applicable
Transmission Customer’s Service
Agreement. The Upper Great Plains
Region (UGPR) shall charge the
Transmission Customer under the rate
then in effect.
Formula Rate
The UGPR reserves the right to
implement the following upon
providing notice to the Transmission
Customer.
E:\FR\FM\23SEN1.SGM
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EN23SE05.062</MATH>
Rate Schedule UGP–AS4; October 1, 2005;
Supersedes 1998 Schedule
Applicable
EN23SE05.061</MATH>
Rate
A recalculated rate will go into effect
every May 1 based on the above formula
and updated financial and load data.
The 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, the UGPR will offer
to purchase the Regulation and pass
through the costs, plus an amount for
administration, to the Transmission
Customer.
55832
Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices
For negative excursions (under
deliveries) outside the bandwidth, the
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 balancing authority.
Rate
The bandwidth in effect October 1,
2005, through September 30, 2006, is 3
percent (+/¥1.5 percent hourly
deviation).
Rate Schedule UGP–AS5; October 1, 2005;
Supersedes 1998 Schedule
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 October 1,
2005, through September 30, 2010, or
until superseded by another rate
schedule.
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 the Western
Area Upper Great Plains balancing
authority (WAUGP) or make alternative
comparable arrangements to satisfy its
Reserves obligation. The charges for
Reserves are outlined below. The
amount of Reserves will be set forth in
the applicable Transmission Customer’s
Service Agreement.
The formula rate used to calculate the
charges for service under this schedule
was promulgated and may be modified
under 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
developed pursuant to applicable
Federal laws, regulations, and policies
and made part of the applicable
Transmission Customer’s Service
Agreement. The Upper Great Plains
Region (UGPR) shall charge the
Transmission Customer under the rate
then in effect.
Formula Rate
WAUGP
Annual Revenue Requirement for Regulation
Regulation =
Load in the Balancing Authority Requiring Regulation
Rate
Rate Schedule UGP–AS6; October 1, 2005;
Supersedes 1998 Schedule
Rate
A recalculated rate will go into effect
every May 1 based on the above formula
and updated financial and load data.
The 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, the UGPR will offer
to purchase the Reserves and pass
through the costs, plus an amount for
administration, to the Transmission
Customer.
In the event that Reserves are called
upon for emergency use, 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 transmission
service to get the Reserves to its
destination.
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 October 1,
2005, through September 30, 2010, or
until superseded by another rate
schedule.
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 the Western Area Upper
Great Plains Balancing Authority
(WAUGP) or make alternative
comparable arrangements to satisfy its
Reserves obligation. The charges for
Reserves are outlined below. The
amount of Reserves will be set forth in
the applicable Transmission Customer’s
Service Agreement.
The formula rate used to calculate the
charges for service under this schedule
was developed and may be modified
under 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
developed under 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 under the rate
then in effect.
Formula Rate
A recalculated rate will go into effect
every May 1 based on the above formula
and updated financial and load data.
The UGPR will notify the Transmission
VerDate Aug<31>2005
15:21 Sep 22, 2005
Jkt 205001
Customer annually of the recalculated
rate on or before April 1.
If resources are not available from a
WAUGP resource, the UGPR will offer
to purchase the Reserves and pass
PO 00000
Frm 00018
Fmt 4703
Sfmt 4703
through the costs, plus an amount for
administration, to the Transmission
Customer.
In the event Reserves are called upon
for Emergency Energy, the UGPR will
E:\FR\FM\23SEN1.SGM
23SEN1
EN23SE05.063</MATH>
Rate
EN23SE05.064</MATH>
WAUGP
Annual Revenue Requirement for Reserves
Reserves =
Load Requiring Reserves
Rate
Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices
55833
Rate Schedule UGP–FPT1; October 1, 2005;
Supersedes 1998 Schedule
Upper Great Plains Region Integrated
System: Long-Term Firm and ShortTerm Firm Point-to-Point Transmission
Service
Effective
The first day of the first full billing
period beginning on or after October 1,
2005, through September 30, 2010, or
until superseded by another rate
schedule.
Applicable
The Transmission Customer shall
compensate the Upper Great Plains
Region (UGPR) each month for Reserved
Capacity under the applicable Firm
Point-to-Point Transmission Service
Agreement and rates outlined below.
The formula rates used to calculate the
charges for service under this schedule
were developed and may be modified
under applicable Federal laws,
regulations, and policies.
The 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
developed under applicable Federal
laws, regulations, and policies and
made part of the applicable
Transmission Customer’s Service
Agreement. The UGPR shall charge the
Transmission Customer under the rate
then in effect.
follows: (1) Any offer of a discount
made by the 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, the 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.
Discounts
Three principal requirements apply to
discounts for transmission service as
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 transmission
service to get the Reserves to its
destination.
Formula Rate
i
Firm Point-to-Point = Annual IS Transmission Service Revenue Requirement
Transmission Rate
a
IS Transmission System Total Load
Discounts
Three principal requirements apply to
discounts for transmission service as
Rate Schedule UGP–NFPT1; October 1,
2005; Supersedes 1998 Schedule
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 October 1,
2005, through September 30, 2010, or
until superseded by another rate
schedule.
Formula Rate
Maximum Non-Firm
730 hours
Point-to-Point
= Firm Point-to-Point ÷ per month × 1000 mills
Transmission Rate
per dollar
Transmission Rate
VerDate Aug<31>2005
15:21 Sep 22, 2005
Jkt 205001
PO 00000
Frm 00019
Fmt 4703
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E:\FR\FM\23SEN1.SGM
23SEN1
EN23SE05.066</MATH>
The Transmission Customer shall
compensate the Upper Great Plains
Region (UGPR) for Non-Firm Point-to-
A recalculated rate will go into effect
every May 1 based on the above formula
and updated financial and load data.
The UGPR will notify the Transmission
Customer annually of the recalculated
rate on or before April 1.
follows: (1) Any offer of a discount
made by the 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, the 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.
EN23SE05.065</MATH>
Applicable
Point Transmission Service under the
applicable Non-Firm Point-to-Point
Transmission Service Agreement and
rate outlined below. The formula rates
used to calculate the charges for service
under this schedule were developed and
may be modified under applicable
Federal laws, regulations, and policies.
The 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
developed under applicable Federal
laws, regulations, and policies and
made part of the applicable
Transmission Customer’s Service
Agreement. The UGPR shall charge the
Transmission Customer under the rate
then in effect.
Rate
55834
Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices
Rate
A recalculated rate will go into effect
every May 1 based on the above formula
and updated financial and load data.
The UGPR will notify the Transmission
Customer annually of the recalculated
rate on or before April 1.
Rate Schedule UGP–NT1; October 1, 2005;
Supersedes 1998 Schedule
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 October 1,
The Transmission Customer shall
compensate the Upper Great Plains
Region (UGPR) each month for Network
Transmission Service under the
applicable Network Integration
Transmission Service Agreement and
annual revenue requirement outlined
below. The formula for the annual
revenue requirement used to calculate
the charges for this service under this
schedule was developed and may be
modified under applicable Federal laws,
regulations, and policies.
Formula Rate
(Transmission Customer’s Load-Ratio Share × Annual Revenue Requirment for IS Transmission Service)
12 months
Annual Revenue Requirement
A recalculated annual revenue
requirement will go into effect every
May 1 based on updated financial data.
The UGPR will notify the Transmission
Customer annually of the recalculated
annual revenue requirement on or
before April 1.
[FR Doc. 05–19039 Filed 9–22–05; 8:45 am]
BILLING CODE 6450–01–P
ENVIRONMENTAL PROTECTION
AGENCY
[ER–FRL–6667–7]
Environmental Impact Statements and
Regulations; Availability of EPA
Comments
Availability of EPA comments
prepared pursuant to the Environmental
Review Process (ERP), under section
309 of the Clean Air Act and Section
102(2)(c) of the National Environmental
Policy Act as amended. Requests for
copies of EPA comments can be directed
to the Office of Federal Activities at
202–564–7167. An explanation of the
ratings assigned to draft environmental
impact statements (EISs) was published
in the Federal Register dated April 1,
2005 (70 FR 16815).
Draft EISs
EIS No. 20050187, ERP No. D–SFW–
F64005–00, Upper Mississippi
National Wildlife and Fish Refuge
Comprehensive Conservation Plan
(CCP) Implementation, MN, WI, IL
and IA.
Summary: EPA has no objections to
the Preferred Alternative, and
recommends that the Final EIS address
VerDate Aug<31>2005
Applicable
The 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 developed under
applicable Federal laws, regulations,
and policies and made part of the
applicable Transmission Customer’s
Service Agreement. The UGPR shall
charge the Transmission Customer
under the revenue requirement then in
effect.
15:21 Sep 22, 2005
Jkt 205001
how the plan will be integrated with the
Upper Mississippi River Navigation
Ecosystem Sustainability Program.
Rating LO.
EIS No. 20050209, ERP No. D–NPS–
J65442–WY, Grand Teton National
Park Transportation Plan,
Implementation, Grand Teton
National Park, Teton County, WY.
Summart: EPA expressed concerns
about wetland mitigation and storm
water impacts. Rating EC2.
EIS No. 20050259, ERP No. D–FHW–
C40166–NY, Southtowns Connector/
Buffalo Outer Harbor Project,
Improvements on the NYS Route 5
Corridor from Buffalo Skyway Bridge
to NYS Route 179, in the City of
Buffalo, City of Lackawanna and
Town of Hamburg, Erie County, NY.
Summary: EPA expressed concerns
about assessment of cumulative
impacts. Rating EC2.
EIS No. 20050274, ERP No. D–AFS–
J61107–ND, NE McKenzie Allotment
Management Plan Revisions, Proposes
to Continue Livestock Grazing on 28
Allotments, Dakota Prairie Grasslands
Land and Resource Management Plan,
Dakota Prairie Grasslands, McKenzie
Ranger District, McKenzie County,
ND.
Summary: EPA expressed concerns
about potential water quality impacts
from sediment, fecal coliform and
temperature modification in streams
and other surface waters, and
recommended reducing water quality
impacts near aquatic/riparian resources
by working with permittees and other
stakeholders, and develop adaptive
management monitoring. Rating EC2.
EIS No. 20050281, ERP No. D–AFS–
K65287–CA, North Fork Eel Grazing
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Frm 00020
Fmt 4703
Sfmt 4703
Allotment Management Project,
Proposing to Authorize Cattle Grazing
on Four Allotment, Six Rivers
National Forest, Mad River Ranger
District, North Fork Eel River and
Upper Mad River, Trinity County, CA.
Summary: EPA has no objection to the
proposed action. Rating LO.
EIS No. 20050306, ERP No. D–FHW–
H40185–00, U.S. Highway 34,
Plattsmouth Bridge Study, over the
Missouri River between U.S. 75 and I–
29, Funding, Coast Guard Permit, U.S.
Army COE 10 and 404 Permits, Cass
County, NE and Mills County, IA.
Summary: EPA expressed concerns
about potential wetland, floodplain,
stream, and cumulative impacts. Rating
EC2.
EIS No. 20050311, ERP No. D–NPS–
H65025–NE, Niobrara National Scenic
River General Management Plan,
Implementation, Brown, Cherry, Keya
Paha and Rock Counties, NE.
Summary: EPA has no objection to the
proposed action. Rating LO.
EIS No. 20050294, ERP No. DR–COE–
K11114–CA, Mare Island Reuse of
Dredged Material Disposal Ponds as a
Confirmed Updated Dredged Material
Disposal Facility, Issuing Section 404
Permit Clean Water Act and Section
10 Permit Rivers and Harbor Act, San
Francisco Bay Area, City of Vallejo,
Solando County, CA.
Summary: Many of EPA’s objections
to the original Draft EIS were addressed
in this revised document. However, EPA
continues to have concerns about the
delegation of responsibility for site
operations and associated
environmental safeguards, as well as
implementation of wetlands restoration
measures. Rating EC2.FINAL EISs.
E:\FR\FM\23SEN1.SGM
23SEN1
EN23SE05.067</MATH>
Monthly Charge =
2005, through September 30, 2010, or
until superseded by another rate
schedule.
]]>Agencies
[Federal Register Volume 70, Number 184 (Friday, September 23, 2005)]
[Notices]
[Pages 55821-55834]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 05-19039]
[[Page 55821]]
-----------------------------------------------------------------------
DEPARTMENT OF ENERGY
Western Area Power Administration
Pick-Sloan Missouri Basin Program--Eastern Division Transmission
and Ancillary Services-Rate Order No. WAPA-122
AGENCY: Western Area Power Administration, DOE.
ACTION: Notice of Order Concerning Transmission and Ancillary Services
Rates.
-----------------------------------------------------------------------
SUMMARY: The Deputy Secretary of Energy confirmed and approved Rate
Order No. WAPA-122 and Rate Schedules UGP-FPT1, UGP-NFPT1, UGP-NT1,
UGP-AS1, UGP-AS2, UGP-AS3, UGP-AS4, UGP-AS5, and UGP-AS6 placing the
Integrated System (IS) Transmission and Ancillary Services rate into
effect on an interim basis. The provisional rates will be in effect
until the Federal Energy Regulatory Commission (Commission) confirms,
approves, and places them into effect on a final basis or until they
are replaced by other rates. The provisional rates will provide
sufficient revenue to pay all annual costs, including interest expense,
and repayment of required investment, within the allowable periods.
DATES: Rate Schedules UGP-FPT1, UGP-NFPT1, UGP-NT1, UGP-AS1, UGP-AS2,
UGP-AS3, UGP-AS4, UGP-AS5, and UGP-AS6 will be placed into effect on an
interim basis on the first day of the first full billing period
beginning on or after October 1, 2005, and will be in effect until the
Commission confirms, approves, and places the rate schedules in effect
on a final basis through September 30, 2010, or until the rate
schedules are superseded. These new rate schedules dated October 2005,
supersede the similarly titled rate schedules dated 1998.
FOR FURTHER INFORMATION CONTACT: Mr. Robert J. Harris, Upper Great
Plains Regional Manager, Western Area Power Administration, 2900 4th
Avenue North, Billings, MT 59101-1266, telephone (406) 247-7405, or Mr.
Jon R. Horst, Rates Manager, Upper Great Plains Region, Western Area
Power Administration, 2900 4th Avenue North, Billings, MT 59101-1266,
telephone (406) 247-7444, e-mail horst@wapa.gov.
SUPPLEMENTARY INFORMATION: The Deputy Secretary of Energy approved
existing Rate Schedules UGP-FPT1, UGP-NFPT1, UGP-NT1, UGP-AS1, UGP-AS2,
UGP-AS3, UGP-AS4, UGP-AS5, and UGP-AS6 for IS Transmission and
Ancillary Service rates on August 1, 1998, in Rate Order No. WAPA-79.
The Commission confirmed and approved the rate schedules on November
25, 1998, in FERC Docket No. EF98-5031-000. These rate schedules were
then extended through September 30, 2005, by Rate Order No. WAPA-100,
which was confirmed and approved by the Commission on December 16,
2003, under FERC Docket No. EF03-5032-000. The rate schedules for Rate
Order No. WAPA-79 and Rate Order No. WAPA-100 contained formulary rates
that were recalculated yearly using the fixed charge rate methodology.
The provisional formula rates will continue to use the fixed charge
rate methodology and will continue to be recalculated yearly from
updated financial and load data. However, the Generator Step Up
Transformers are to be removed from the annual revenue requirement for
IS. After the approval of the original Transmission and Ancillary
Service rates for the IS, the Commission decided that Generator Step Up
Transformers should not be included in transmission rates for
jurisdictional utilities. Consistent with Western's goal to observe
Commission precedent to the extent consistent with its mission and
permitted by law and regulation, the IS Transmission and Ancillary
Service rates are being modified.
The existing IS Long-Term Firm and Short-Term Firm Point-to-Point
Transmission Service Rate Schedule is superseded by Rate Schedule UGP-
FPT1, dated October 2005. The 2004-2005 existing rate for IS Long-Term
Firm and Short-Term Firm Point-to-Point Transmission Service is $2.72
per kilowattmonth (kWmonth). The provisional rate for IS Long-Term Firm
and Short-Term Firm Point-to-Point Transmission Service is $2.69/
KWmonth. Under Rate Schedule UGP-NFPT1, the existing rate calculation
for IS Non-Firm Point-to-Point Transmission Service is 3.73 mills per
kilowatthour (mills/kWh). The provisional rate for IS Non-Firm Point-to
Point Transmission Service is 3.68 mills/kWh. Under Rate Schedule UGP-
NT1 the existing annual revenue requirement for IS Network Integration
Transmission Service is $128,017,923. The provisional annual revenue
requirement for IS Network Integration Transmission Service is
$126,741,576.
Under Rate Schedule UGP-AS1, the existing rate for Scheduling
System Control and Dispatch (Scheduling and Dispatch) Service is
$49.29/schedule/day. The provisional rate for Scheduling and Dispatch
is $49.77/schedule/day. Under Rate Schedule UGP-AS2, the existing rate
for Reactive Supply and Voltage Control from Generation Sources Service
(Reactive Service) is $0.06/kWmonth. The provisional rate for Reactive
Service is $0.07/kWmonth. Under Rate Schedule UGP-AS3, the provisional
rate calculated for Regulation and Frequency Response Service is
unchanged from the existing rate of $0.04/kWmonth. Under Rate Schedule
UGP-AS4, there is no change in the rate for Energy Imbalance Service
between the existing and the proposed rates. Under Rate Schedules UGP-
AS5 and UGP-AS6, the rate for Spinning and Supplemental Reserves is
$0.11/kWmonth. The provisional rate calculated for Spinning and
Supplemental Reserves is $0.12/kWmonth.
By Delegation Order No. 00-037.00, effective December 6, 2001, the
Secretary of Energy delegated: (1) The authority to develop power and
transmission rates to Western's Administrator, (2) the authority to
confirm, approve, and place such rates into effect on an interim basis
to the Deputy Secretary of Energy, and (3) the authority to confirm,
approve, and place into effect on a final basis, to remand or to
disapprove such rates to the Commission. Existing DOE procedures for
public participation in power rate adjustments (10 CFR part 903) were
published on September 18, 1985.
Under Delegation Order Nos. 00-037.00 and 00-001.00A, 10 CFR part
903, and 18 CFR part 300, I hereby confirm, approve, and place Rate
Order No. WAPA-122, the proposed IS Firm and Non-Firm Transmission and
Ancillary Service rates into effect on an interim basis. The new Rate
Schedules UGP-FPT1, UGP-NFPT1, UGP-NT1, UGP-AS1, UGP-AS2, UGP-AS3, UGP-
AS4, UGP-AS5, and UGP-AS6 for IS Transmission and Ancillary Service
rates will be promptly submitted to the Commission for confirmation and
approval on a final basis.
Dated: September 13, 2005.
Clay Sell,
Deputy Secretary.
[Rate Order No. WAPA-122]
In the matter of: Western Area Power Administration Rate
Adjustment for the Pick-Sloan Missouri Basin Program--Eastern
Division Transmission and Ancillary Services; Order Confirming,
Approving, and Placing the Pick-Sloan Missouri Basin Program--
Eastern Division Transmission and Ancillary Services Formula Rates
Into Effect on an Interim Basis
This rate was established in accordance with section 302 of the
Department of Energy (DOE) Organization Act (42 U.S.C. 7152). This Act
transferred to and vested in the
[[Page 55822]]
Secretary of Energy the power marketing functions of the Secretary of
the Department of the Interior and the Bureau of Reclamation under the
Reclamation Act of 1902 (ch. 1093, 32 Stat. 388), as amended and
supplemented by subsequent laws, particularly section 9(c) of the
Reclamation Project Act of 1939 (43 U.S.C. 485h(c)), section 5 of the
Flood Control Act of 1944 (16 U.S.C. 825s), and other Acts that
specifically apply to the project involved.
By Delegation Order No. 00-037.00, effective December 6, 2001, the
Secretary of Energy delegated: (1) The authority to develop power and
transmission rates to Western's Administrator, (2) the authority to
confirm, approve, and place such rates into effect on an interim basis
to the Deputy Secretary of Energy, and (3) the authority to confirm,
approve, and place into effect on a final basis, to remand or to
disapprove such rates to the Commission. Existing DOE procedures for
public participation in power rate adjustments (10 CFR part 903) were
published on September 18, 1985.
Acronyms and Definitions
As used in this Rate Order, the following acronyms and definitions
apply:
$/kWmonth: Monthly charge for capacity (i.e., $ per kilowatt (kW)
per month).
12-cp: 12-month coincident peak average.
Administrator: The Administrator of the Western Area Power
Administration.
Ancillary Services: Those services necessary to support the
transfer of electricity while maintaining reliable operation of the
transmission system in accordance with standard utility practice.
A&GE: Administrative and general expense.
Balancing Authority: An electric system or systems, bounded by
interconnection metering and telemetry, capable of controlling
generation to maintain its interchange schedule with other Balancing
Authorities and contributing to frequency regulation of the
Interconnection. Formerly known as control area.
Basin Electric: Basin Electric Power Cooperative.
Capacity: The electric capability of a generator, transformer,
transmission circuit, or other equipment. It is expressed in kilowatts.
Capacity Rate: The rate which sets forth the charges for capacity.
It is expressed in $/kWmonth.
Commission: Federal Energy Regulatory Commission.
Corps of Engineers: U.S. Army Corps of Engineers.
Customer: An entity with a contract that is receiving service from
Western's UGPR.
DOE: United States Department of Energy.
DOE Order RA 6120.2: An order outlining power marketing
administration financial reporting and ratemaking procedures.
Energy: Measured in terms of the work capacity over a period of
time. It is expressed in kilowatthours.
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.
Energy Rate: The rate which sets forth the charges for energy. It
is expressed in mills per kilowatthour and applied to each kilowatthour
delivered to each customer.
FERC: The Commission (to be used when referencing Commission
Orders).
FERC Order No. 888: FERC Order Nos. 888, 888-A, 888-B and 888-C
unless otherwise noted.
Firm: A type of product and/or service available at the time
requested by the customer.
Firm Point-to-Point: Service that is reserved and/or scheduled
between Points of Receipt and Delivery.
FRN: Federal Register notice.
FY: Fiscal year; October 1 to September 30.
GSU: Generator Step Up Transformer.
GWh: Gigawatthour--the electrical unit of energy that equals 1
billion watthours or 1 million kWh.
Heartland: Heartland Consumers Power District.
IS: Integrated System.
ISO: Independent System Operator.
JTS: Joint Transmission System.
kW: Kilowatt--the electrical unit of capacity that equals 1,000
watts.
kWh: Kilowatthour--the electrical unit of energy that equals 1,000
watts in 1 hour.
kWmonth: Kilowattmonth--the electrical unit of the monthly amount
of capacity.
kWyear: Kilowattyear--the electrical unit of the yearly amount of
capacity.
Load: The amount of electric power or energy delivered or required
at any specified point(s) on a system.
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 reservation with at least 12 consecutive equal monthly amounts.
MAPP: Mid-Continent Area Power Pool.
MBMPA: Missouri Basin Municipal Power Agency.
Mill: A monetary denomination of the United States that equals one
tenth of a cent or one thousandth of a dollar.
Mills/kWh: Mills per kilowatthour--the unit of charge for energy.
MVAR: Megavar, equal to 1,000,000 VARs.
MW: Megawatt--the electrical unit of capacity that equals 1 million
watts or 1,000 kilowatts.
NERC: North American Electric Reliability Council.
Net Revenue: Revenue remaining after paying all annual expenses.
Network Customer: An entity receiving Transmission Service under
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.
OASIS: Open Access Same-Time Information System--provides access to
information on transmission pricing and availability for potential
transmission customers.
OM&R: Operation, Maintenance & Replacement.
P-SMBP: Pick-Sloan Missouri Basin Program.
P-SMBP--ED: Pick-Sloan Missouri Basin Program--Eastern Division.
Point-to-Point: The reservation and transmission of capacity and
energy on either a firm or non-firm basis from designated Point(s) of
Receipt to designated Point(s) of Delivery.
Power: Capacity and energy.
Provisional Rate: A rate which has been confirmed, approved, and
placed into effect on an interim basis by the Deputy Secretary.
Rate Brochure: An April 2005 document explaining the rationale and
background for the rate proposal contained in this Rate Order.
Reclamation: United States Department of the Interior, Bureau of
Reclamation.
Reclamation Law: A series of Federal laws. Viewed as a whole, these
laws
[[Page 55823]]
create the framework under which Western markets power.
Reactive Supply and Voltage Control from Generating Sources
Service: A service which provides reactive supply through changes to
generator reactive output to maintain transmission line voltage and
facilitate electricity transfers.
Regulation and Frequency Response Service: A service which provides
for following the moment-to-moment variations in the demand or supply
in a Balancing Authority and maintaining scheduled interconnection
frequency.
Reserve Services: Spinning Reserve Service and Supplemental Reserve
Service.
Revenue Requirement: The revenue required to recover annual
expenses (such as O&M, purchase power, transmission service expenses,
interest, and deferred expenses) and repay Federal investments, and
other assigned costs.
SCADA: Supervisory Control and Data Acquisition.
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
Balancing Authority(ies) involved in the transaction.
Scheduling, System Control and Dispatch Service: A service which
provides for (a) scheduling, (b) confirming and implementing an
interchange schedule with other balancing authorities, including
intermediary balancing authorities providing transmission service, and
(c) ensuring operational security during the interchange transaction.
Service Agreement: The initial agreement and any amendments or
supplements entered into by the Transmission Customer and Western for
service under the Tariff.
Short-Term Firm Point-to-Point: Firm Point-to-Point Transmission
Service with service duration of less than one 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
Balancing Authority. The Transmission Customer must either purchase
this service from the Transmission Provider or make alternative
comparable arrangements to satisfy its Spinning Reserve Service
obligation.
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 generation 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 Balancing
Authority. 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: A compilation of data and documents that
support the Rate Brochure and the rate proposal.
System: An interconnected combination of generation, transmission
and/or distribution components comprising an electric utility,
independent power producer(s) (IPP), or group of utilities and IPP(s).
Tariff: Western Area Power Administration Open Access Transmission
Service Tariff, originally approved in Docket No. NJ98-1-000, 99 FERC ]
61,062 (2002) and amended in Docket No. NJ05-1-000, 112 FERC ] 61,044
(2005).
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 to transmit electric energy in interstate commerce. The
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 Load: The 12-cp peak for Network
Transmission Service plus reserved capacity for all Firm Point-to-Point
Transmission Service.
UGPR: The Upper Great Plains Customer Service Region of the Western
Area Power Administration. In some places in this order, UGPR maybe
referenced generically as Western.
VAR: A unit of reactive power.
WAUGP: The NERC acronym for the Western Area Upper Great Plains
Balancing Authority. This balancing authority is also known as the
Watertown Balancing Authority.
Watertown Operation Office: Western Area Power Administration Upper
Great Plains Customer Service Region, Operations Office, 1330 41st
Street SE., Watertown, South Dakota.
Western: United States Department of Energy, Western Area Power
Administration.
Western Regions: Customer service regions of the Western Area Power
Administration.
Western's Tariff: Western's Open Access Transmission Service
Tariff.
Effective Date
The new interim rates will take effect on the first day of the
first full billing period beginning on or after October 1, 2005, and
will remain in effect until September 30, 2010, pending approval by the
Commission on a final basis.
Public Notice and Comment
Western followed the Procedures for Public Participation in Power
and Transmission Rate Adjustments and Extensions, 10 CFR part 903, for
a minor rate adjustment in developing these rates. The steps Western
took to involve interested parties in the rate process were:
1. The proposed rate adjustment process began February 9, 2005,
when Western mailed a notice announcing an informal customer meeting to
all IS Transmission Customers and interested parties. The meeting was
held on March 22, 2005, in Sioux Falls, South Dakota. At this informal
meeting, Western explained the rationale for the rate adjustment,
presented rate designs and methodologies, and answered questions.
2. A Federal Register notice published on April 18, 2005, (70 FR
20119), announced the proposed rates for P-SMBP--ED Transmission and
Ancillary Service rates, and began a public consultation and comment
period.
3. On April 28, 2005, Western mailed letters to all IS Transmission
Customers and interested parties transmitting the Federal Register
notice published on April 18, 2005, and directing them to the rate
brochure on Western's Web site.
4. Western received no comment letters during the consultation and
comment period, which ended May 18, 2005.
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,
890, Pub. L. 78-534). It was later renamed the 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
[[Page 55824]]
production for the entire Missouri River Basin. Multipurpose projects
have been developed on the Missouri River and its tributaries in
Colorado, Montana, Nebraska, North Dakota, South Dakota, and Wyoming.
The UGPR markets significant quantities of Federally-generated
hydroelectric power from the P-SMBP--ED. Western owns and operates an
extensive system of high-voltage transmission facilities which the 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. The
UGPR uses 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 and South Dakota, eastern Nebraska, western Iowa, and western
Minnesota.
Integrated System Description
Using a single system, joint-planning concept, the UGPR, Basin
Electric, and Heartland combined their transmission facilities to form
the IS and developed Transmission and Ancillary Service rates for
transmission over the IS. This action was necessary because the 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 IS Transmission
System. The UGPR is designated as the operator of the other
participants' transmission facilities and as such contracts for
service, determines and posts the available transmission capacity on
the OASIS, bills for service, collects payments, and distributes
revenues to each IS participant. 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, Iowa,
Minnesota, 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 the most useful to all transmission requesters. The
``seven-factor test'' defined in FERC Order No. 888 was used to
determine the distribution facilities that were excluded from the IS
Transmission System. Several major facilities are included in the IS.
The second 345-kV transmission line between the Antelope Valley and
Leland Olds generation stations, which meets the standards for
acceptable transmission facilities set in the Commission rulings on
filings by other transmission entities, is included. The 230-kV
transmission line between Tioga, North Dakota, and Boundary Dam, which
provides access to generation and loads in Canada, is 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.
P-SMBP--ED Transmission and Ancillary Service Rates Study
Western prepared a Transmission and Ancillary Service rates study
to ensure that Transmission and Ancillary Service rates are based on
the cost of service of the IS Transmission System. This study includes
all IS Transmission and Ancillary Service expenses and associated
offsetting revenues. Western charges IS Transmission Service rates
separately to entities receiving transmission-only services over the IS
Transmission System.
The UGPR is proposing to continue using an annual fixed charge
formula that will determine how much revenue must be recovered from the
IS Transmission and Ancillary Service rates. The annual revenue
requirements include O&M expenses, administrative and general expenses,
interest expense, and depreciation expense. This methodology is applied
annually using the most recent historical test year. These revenue
requirements are offset by appropriate IS revenues.
Integrated System Transmission Service
Western will offer Network, Firm Point-to-Point, and Non-Firm
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 Service 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 Western's Customers continues to be
bundled in the firm electric power service rate under existing
contracts that expire in 2020.
The UGPR prepared a transmission service study to ensure that the
formula IS Transmission and Ancillary Service rates are based on the
cost of service to the IS. The UGPR seeks approval of formula rates for
calculating Point-to-Point IS Transmission Rates, the Network Annual
Revenue Requirement for IS Transmission Service, and ancillary service
rates. Western requests the Commission confirm that these rates are not
arbitrary, capricious, or in violation of the law. The rates will be
recalculated every year, effective May 1, based on the approved formula
rates and updated financial and load data. The UGPR will provide
customers notice of changes in the Transmission and Ancillary Service
rates no later than April 1 of each year.
IS Transmission System Total Load
The IS Transmission System Total Load is the 12-cp system peak for
IS Network Transmission Service plus the reserved capacity for all IS
Long-Term Firm Point-to-Point Transmission Service.
The IS Transmission System Total Load is calculated as follows
based upon the most recent historical data available at the time of the
initial rate proposal. This included both 2003 and 2004 data:
IS Network Transmission Load........................ 3,185,000 kW
Long-Term Firm Point-to-Point Reserved Capacity..... 743,000 kW
-------------------
IS Transmission System Total Load................... 3,928,000 kW
Annual Costs
Western calculated the annual costs of providing the various IS
Transmission and Ancillary Services using a Commission-recognized
methodology for annual cost calculation with fixed charge rates for
various cost components. The cost components applicable to Western
include O&M,
[[Page 55825]]
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 IS
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 the IS Transmission Service
or one of the Ancillary Services, the total fixed charge rate is
applied to the net investment allocated to the service:
Total fixed charge rate x Net investment = Annual cost of providing
service.
The source for the 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 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 annual revenue requirement for IS Transmission Service is based
upon the most recent historical data available at the time of the
initial rate proposal. This data is used in a test year and uses an
annual fixed charge methodology. 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 the IS Transmission Service plus any facility
credit paid to the IS Transmission Customers. The annual 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
+ Annual IS Transmission Costs Basin Electric and Heartland
+ Transmission Customer Facility Credits
- Transmission Revenue Credits
----------------------------------------------------------------------------------------
Annual Revenue Requirement for IS Transmission Service
Transmission Customer Facility Credits are credits paid to IS
Transmission Customers for facilities that are integrated with the IS
and increase both the capability and the reliability of the IS. The
credits are addressed in individual agreements and appropriate
adjustments are made in subsequent rate calculations. The IS
participants will evaluate requests for facility credits consistent
with the Commission's guidance in the FERC Order No. 888, other
relevant Commission policy, and the terms of the Tariff.
Transmission Revenue Credits include revenue from sales of Non-
Firm, discounted IS Firm and Short-Term Firm Point-to-Point
Transmission Service; revenue from existing transmission agreements;
and revenue from Scheduling, System Control and Dispatch Services.
IS Network Transmission Service
The proposed rate for IS Network Transmission Service is a formula
calculation based upon the annual revenue requirement for IS
Transmission Service then in effect, as determined by the annual fixed
charge methodology. The monthly charge for IS Network Transmission
Service is as follows:
Network Customer's Load-ratio share
x Annual Revenue Requirement for IS Transmission
/ 12 months
----------------------------------------------------------------------------------
Monthly IS Network Transmission Service Charge
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. The proposed rate formula would be effective October 1,
2005, through September 30, 2010.
IS Firm Point-to-Point Transmission Service
The rate for IS Firm Point-to-Point Transmission Service is the
annual revenue requirement for IS Transmission Service divided by the
IS Transmission System Total Load in kW, to derive a cost per
kilowattyear (kWyear). The formula for the monthly rate is as follows:
[[Page 55826]]
Annual Revenue Requirement for IS Transmission
/ IS Transmission System Total Load
/ 12 months
------------------------------------------------------------------------------------
Monthly IS Firm Point-to-Point Transmission Rate
The rate formula is applied annually by using the most current
historical data available. The proposed rate formula would be effective
October 1, 2005, through September 30, 2010.
IS Non-Firm Point-to-Point Transmission Service
The proposed rate for IS Non-Firm Point-to-Point Transmission
Service is a mills/kWh rate, based upon the current firm point-to-point
rate and may be discounted. The formula rate is as follows:
Monthly IS Firm Point-to-Point Transmission Rate
/ 730 hours/month
x 1000 mills per dollar
------------------------------------------------------------------------------------
IS Non-Firm Point-to-Point Transmission Rate
This rate will remain in effect for the same period as the IS Firm
Point-to-Point Transmission Service rate and will also be reviewed
annually. The IS Non-Firm Point-to-Point Transmission Service will be
offered at hourly, daily, and monthly rates. The IS Transmission
Service availability will be posted on the UGPR OASIS.
Ancillary Services
In accordance with the Tariff, Western will offer to all customers
the six ancillary services defined by the Commission, two of which IS
Transmission Customers are required to purchase: (1) Scheduling, System
Control, and Dispatch Service, and (2) Reactive Supply and Voltage
Control from Generation Sources Service. The remaining four ancillary
services are: (3) Regulation and Frequency Response Service, (4) Energy
Imbalance Service, (5) Spinning Reserve Service, and (6) Supplemental
Reserve 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.
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. In accordance with
the Tariff, 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, including an administrative charge to the
customer.
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:
Annual Revenue Requirement for
Scheduling, System Control and Dispatch Service
/ Annual Number of Daily Schedules
------------------------------------------------------------------------------------
Scheduling, System Control and Dispatch Rate
This rate and rate design only recovers Western's revenue requirement
for Scheduling, System Control, and Dispatch Service.
Reactive Supply and Voltage Control from Generation Sources Service
Western's annual cost of providing 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 and Heartland's annual revenue
requirement is based on the annual cost of equipment installed on its
generators to provide this service. Western's, Basin Electric's, and
Heartland'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 total annual revenue requirement by the load requiring
reactive service. The annual rate is then divided by 12 months to
obtain a monthly rate. The Reactive Supply and Voltage Control rate
calculation is summarized in the following formula:
Annual Reactive Revenue Requirement
+ Load Requiring Reactive Service
/ 12 months
-------------------------------------------------------------
[[Page 55827]]
Regulation and Frequency Response Service
Regulation and Frequency Response Service in the east side of the
balancing authority is provided primarily by Oahe generation and in the
west side of the balancing authority by Fort Peck generation, both of
which are Corps of Engineer facilities. To calculate the annual cost of
providing Regulation and Frequency Response Service, the Corps of
Engineers' 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
Service in the balancing authority. 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 yearly peak condensing as percentage of load for five years.
Western's 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. Basin Electric's and Heartland's annual revenue requirement is
based on the annual cost of equipment installed on its generators to
provide this service. Western's, Basin Electric's, and Heartland's
annual revenue requirements are summed for the total revenue
requirement for this service. Annual rate for Regulation and Frequency
Response Service is then determined by dividing the total revenue
requirement by the total load in the Balancing Authority. The annual
rate is then divided by 12 months to obtain a monthly rate. The
Regulation and Frequency Response Service rate calculation is
summarized in the following formula:
Annual Revenue Requirement for Regulation
+ Load in the Balancing Authority Requiring Regulation
/ 12 months
-------------------------------------------------------------------------------------
Monthly Regulation and Frequency Response Rate
Energy Imbalance Service
This service is not intended to provide backup for generation
supply. Energy shall be returned in like time frames (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 bandwidth will be forfeited to the balancing authority.
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. This rate and rate design recovers only
Western's revenue requirement associated with Reserve Services. If
energy is taken under these services, the energy charge will be the
MAPP or its successors rate for emergency energy. The Regulation and
Frequency Response Service rate calculation is summarized in the
following formula:
Annual Revenue Requirement for Reserves
/ Load Requiring Reserves
/ 12 months
----------------------------------------------------------------
Existing and Provisional Rates
The revenue requirements for the individual services and comparison
values are outlined in the following table. These rates are calculated
comparing the Existing Revenue Requirement to the Revenue Requirement
based upon the most recent historical data available at the time of the
initial rate proposal.
Table 1
----------------------------------------------------------------------------------------------------------------
Provisional
Service Existing revenue revenue Percentage
requirement requirement change
----------------------------------------------------------------------------------------------------------------
Transmission................................................... $128,017,923 $126,741,576 -0.997
Scheduling, System Control and Dispatch........................ 3,373,281 3,406,102 -0.973
Reactive Supply and Voltage Control from Generation Sources.... 2,736,253 3,065,568 12.035
Regulation and Frequency Control............................... 1,065,771 1,075,623 0.924
Reserves....................................................... 1,895,268 2,009,276 6.015
----------------------------------------------------------------------------------------------------------------
[[Page 55828]]
Certification of Rates
Western's Administrator certifies that the IS Transmission and
Ancillary Service rates placed into effect on an interim basis are the
lowest possible rates consistent with sound business principles. The
provisional formula rates were developed following administrative
policies and applicable laws.
IS Transmission Service Discussion
Western proposes continuing the annual fixed charge formula to
determine the Annual Revenue Requirement for IS Transmission Service.
The annual revenue requirement for IS Transmission Service includes O&M
expense, A&GE, interest expense, and depreciation expense from the most
recent historical test year. This annual revenue requirement for IS
Transmission Service is offset by appropriate revenue credits.
The IS Transmission System includes the transmission facilities
owned by Western, Basin Electric, Heartland and others in which the IS
has contractual rights. The costs paid to others for contractual rights
on their transmission lines are included in the costs recovered by the
annual revenue requirement for IS Transmission Service.
Western will continue to offer Network, Firm Point-to-Point, and
Non-Firm Point-to-Point Transmission Service on the IS Transmission
System. The service offered is the transmission of energy and capacity
from Points of Receipt to Points of Delivery on the IS. The IS
Transmission Service 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.
The provisional IS Transmission Service rates will be applied to
customers who purchase transmission services. Western, Basin Electric,
and Heartland will take IS Transmission Service. The IS Transmission
Service to the UGPR's Customers will continue to be bundled in the firm
electric service rate under existing contracts that expire in 2020.
IS Transmission System Total Load
The IS Transmission System Total Load is the 12-cp system peak for
Network IS Transmission Service plus the reserved capacity for all IS
Long-Term Firm Point-to-Point Transmission Service. For the provisional
rate, the IS Transmission System Total Load will be unchanged at
3,968,000 kW.
Annual Costs
Western will continue to use a Commission-recognized methodology
for annual cost calculation with fixed charge rates for various cost
components approved by the Commission in WAPA-79 and WAPA-100. The
change in the provisional rate is that the costs associated with the
GSUs are no longer included in the net plant investment for
transmission or the various expenses. The investment and costs for GSUs
are now in the generation fixed charge calculation in support of
ancillary services. The proposed methodology will continue to be an
annual fixed charge formula that will determine the annual revenue
requirement to be recovered from transmission services.
Annual Revenue Requirement for IS Transmission
A change in the costs that comprise the annual revenue requirement
for IS Transmission is being proposed. The proposed transmission rate
methodology is different from the current transmission rate methodology
in one area. The GSU investments are removed from the transmission
investments and placed in the generation investments. This also moves
the corresponding costs of GSUs from transmission costs to generation
costs. The existing annual revenue requirement for IS Transmission
Service is $128,017,923. The provisional Annual Revenue Requirement for
IS Transmission Service is $126,741,576.
Network
The current IS Network Transmission Service schedule expires on
September 30, 2005. The provisional annual revenue requirement for IS
Transmission Service will be used in the provisional rate formula for
IS Network Transmission Service. The provisional charge for the monthly
demand for IS Network Transmission Service will be the product of the
network customer's load ratio share times one-twelfth (1/12) of the
annual revenue requirement for IS Transmission Service. The load ratio
share will be based on the network customer's hourly load (including
its designated network load not physically interconnected with
Western), coincident with the IS monthly transmission system peak,
which will be calculated on a rolling 12-cp basis. Western's
transmission system peak includes the sum of capacity reserved for IS
Point-to-Point Transmission Service, 12-cp monthly entitlements for
firm power customers, and the average 12-cp monthly system peak for IS
Network Transmission Service. The provisional rate formula is to be
effective beginning October 1, 2005, through September 30, 2010.
Firm Point-to-Point
The current IS Firm Point-to-Point Transmission Service rate for
2004-2005 is $2.72 and expires September 30, 2005. The provisional
formula rate will continue to be the Annual Revenue Requirement for IS
Transmission Service divided by the IS Transmission System Total Load.
The provisional rate for IS Firm Point-to-Point Transmission Service is
$2.69 per kWmonth for 2004-2005.
Non-Firm Point-to-Point
The current IS Non-Firm Transmission Service rate expires September
30, 2005. The provisional rate for IS Non-Firm Transmission Service is
expressed in mills/kWh and is based on the current IS Firm Point-to-
Point Transmission Service rate and may be discounted. The provisional
IS Non-Firm Point-to-Point Transmission Service rate will be the IS
Firm Point-to-Point Transmission Service rate divided by 730 hours per
month and multiplied by 1000 mills per dollar. The provisional IS Non-
Firm Transmission Service rate for 2004-2005 is 3.68 mills/kWh.
The following table summarizes the difference in calculations
between the current IS Transmission Service rates and the provisional
IS Transmission Service rates. It compares the change in the average
annual projections used in the 2004-2005 transmission and ancillary
services study and the provisional IS Transmission Service rates for
this rate adjustment based upon the most recent historical data
available at the time of the initial rate proposal.
Comparison of Annual Revenues
----------------------------------------------------------------------------------------------------------------
Percent
Item Existing rate Provisional rate change
----------------------------------------------------------------------------------------------------------------
Annual IS Costs................................................ $137,088,496 $136,289,145 -0.577
Transmission Customer Facility Credits......................... 2,482,447 2,482,647 0.000
[[Page 55829]]
Transmission Revenue Credits................................... 9,454,494 9,454,494 0.000
Annual Revenue Requirement for IS Transmission Service......... 128,017,923 126,741,576 -0.997
----------------------------------------------------------------------------------------------------------------
The change in annual revenue requirement for IS Transmission
Service is primarily a result of a revision in the allocation of
expenses and investments. The revenue change between the existing rate
and the provisional rate is <1 percent and, therefore, this is a minor
rate adjustment.
Basis for Rate Development
The existing rates for IS Network, Firm and Non-Firm Transmission
Service in Rate Schedules UGP-NT1, UGP-FPT1, and UGP-NFPT1, expire
September 30, 2005. This rate adjustment contains rates that replace
existing rates. The adjusted rates reflect changes in costs. The
provisional rates will provide sufficient revenue to pay all annual
costs, including interest expense, and repay investment within the
allowable period. The provisional IS Transmission Service rates,
detailed in Rate Schedules UGP-NT1, UGP-FPT1, and UGP-NFPT1, will take
effect on October 1, 2005 to correspond with the start of the Federal
fiscal year and remain in effect through September 30, 2010, or until
replaced.
The proposed rates for IS Transmission Service include a provision
to pass through electric industry restructuring costs associated with
providing transmission service. These costs will be passed through to
each appropriate IS Transmission Customer.
Comments
Western did not receive any comments or responses regarding the IS
Transmission Service rate adjustment.
Ancillary Services Discussion
The IS will continue to offer six ancillary services. These are (1)
Scheduling, system control, and dispatch service, (2) reactive supply
and voltage control service, (3) regulation and frequency response
service, (4) energy imbalance service, (5) spinning reserve service,
and (6) supplemental reserve service. The first two are required
services: (1) Scheduling, system control, and dispatch service and (2)
reactive supply and voltage control service. All these ancillary
services are listed in Western's Tariff.
The provisional rates for ancillary services are designed to
recover only the costs associated with providing the service(s). The
formula for calculating the rates will remain the same but the GSUs
will be included in the investment and costs for the generation fixed
charge in support of ancillary services. The costs for providing
Scheduling, System Control, and Dispatch Service are included in the
provisional IS Transmission Service rates.
The following table summarizes the difference in calculations
between the current IS Ancillary Service rates and the provisional IS
Ancillary Service rates. It compares the change in the average annual
projections used in the 2004-2005 transmission and ancillary services
study and the provisional IS Transmission and Ancillary Service rates
for this rate adjustment based upon the most recent historical data
available at the time of the initial rate proposal.
Comparison of Ancillary Service Rates
----------------------------------------------------------------------------------------------------------------
Provisional
Item Unit Existing rate rate Percent change
----------------------------------------------------------------------------------------------------------------
Scheduling, System Control and schedule/day................ $49.29 $49.77 0.974
Dispatch Service.
Reactive Supply and Voltage kWmonth..................... 0.06 0.07 16.667
Control.
Regulation and Frequency Response. kWmonth..................... 0.04 0.04 0.000
Energy Imbalance.................. n/a......................... n/a n/a n/a
Reserves.......................... kWmonth..................... 0.11 0.12 9.091
----------------------------------------------------------------------------------------------------------------
Basis for Rate Development
The existing rates for IS Ancillary Services in Rate Schedules UGP-
AS1, UGP-AS2, UGP-AS3, UGP-AS4, UGP-AS5, and UGP-AS6, expire September
30, 2005. The rate adjustment contains rates that replace existing
rates. The adjusted rates reflect a revised methodology and changes in
costs. The provisional rates will provide sufficient revenue to pay all
annual costs, including interest expense, and repayment of required
power investment within the allowable period. The provisional rates
will take effect on October 1, 2005, to correspond with the start of
the Federal fiscal year and remain in effect through September 30,
2010.
Comments
Western did not receive any comments or responses regarding the IS
Ancillary Services rate adjustment.
Availability of Information
Information about this rate adjustment, including studies,
brochures, comments, letters, memorandums, and other supporting
material made or kept by Western, used to develop the provisional
rates, is available for public review in the Upper Great Plains
Regional Office, 2900 4th Avenue North, Billings, Montana.
Regulatory Procedure Requirements
Regulatory Flexibility Analysis
The Regulatory Flexibility Act of 1980 (5 U.S.C. 601, et seq.)
requires Federal agencies to perform a regulatory flexibility analysis
if a final rule is likely to have a significant economic impact on a
substantial number of small entities and there is a legal requirement
to issue a general notice of proposed rulemaking. Western has
determined that this action does not require a regulatory flexibility
analysis since it is a rulemaking of particular applicability involving
rates or services applicable to public property.
[[Page 55830]]
Environmental Compliance
In compliance with the National Environmental Policy Act (NEPA) of
1969 (42 U.S.C. 4321, et seq.); Council on Environmental Quality
Regulations (40 CFR parts 1500-1508); and DOE NEPA Regulations (10 CFR
part 1021), Western has determined that this action is categorically
excluded from preparing an environmental assessment or an environmental
impact statement.
Determination Under Executive Order 12866
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.
Small Business Regulatory Enforcement Fairness Act
Western has determined that this rule is exempt from congressional
notification requirements under 5 U.S.C. 801 because the action is a
rulemaking of particular applicability relating to rates or services
and involves matters of procedure.
Submission to the Federal Energy Regulatory Commission
The interim rates herein confirmed, approved, and placed into
effect, together with supporting documents, will be submitted to the
Commission for confirmation and final approval.
Order
In view of the foregoing and under the authority delegated to me, I
confirm and approve on an interim basis, effective October 1, 2005,
formula rates for the IS Transmission and Ancillary Services under Rate
Schedules UGP-FPT1, UGP-NFPT1, UGP-NT1, UGP-AS1, UGP-AS2, UGP-AS3, UGP-
AS4, UGP-AS5, and UGP-AS6. The rate schedules shall remain in effect on
an interim basis, pending the Commission's confirmation and approval of
them or substitute rates on a final basis through September 30, 2010.
Dated: September 13, 2005.
Clay Sell,
Deputy Secretary.
Rate Schedule UGP-AS1; October 1, 2005; Supersedes 1998 Schedule
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 October 1, 2005, through September 30, 2010, or until superseded
by another rate schedule.
Applicable
This service is required to schedule the movement of power through,
out of, within, or into the Western Area Upper Great Plains Balancing
Authority (WAUGP). The charges for Scheduling, System Control, and
Dispatch Service are to be based on the rate outlined below. The
formula rate used to calculate the charges for service under this
schedule was developed and may be modified under 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 developed under
applicable Federal laws, regulations, and policies and made part of the
applicable Transmission Customer's Service Agreement.
The Upper Great Plains Region (UGPR) shall charge the non-
Transmission Customer under the rate then in effect.
Formula Rate
[GRAPHIC] [TIFF OMITTED] TN23SE05.060
Rate
A recalculated rate will go into effect every May 1 based on the
above formula and data. The UGPR will notify the customer annually of
the recalculated rate on or before April 1.
Rate Schedule UGP-AS2; October 1, 2005; Supersedes 1998 Schedule
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 October 1, 2005, through September 30, 2010, or until superseded
by another rate schedule.
Applicable
To maintain transmission voltages on all transmission facilities
within acceptable limits, generation facilities under the control of
the Western Area Upper Great Plains balancing authority (WAUGP) are
operated to produce or absorb reactive power. Thus, Reactive Supply and
Voltage Control from Generation Sources Service (Reactive Service) must
be provided for each transaction on the transmission facilities. The
amount of Reactive Service that must be supplied with respect to the
Transmission Customer's transaction will be determined based on the
Reactive Service 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 outlined below. The formula rate used to calculate the charges
for service under this schedule was developed and may be modified under
applicable Federal laws, regulations, and policies.
The charges for Reactive Service may be modified upon written
notice to the Transmission Customer. Any change to the charges for
Reactive Service shall be as set forth in a revision to this rate
schedule developed under applicable Federal laws, regulations, and
policies and made part of the applicable Transmission Customer's
Service Agreement. The Upper Great Plains Region (UGPR) shall charge
the Transmission Customer under the rate then in effect.
Those Transmission Customers with generators in the balancing
authority providing WAUGP with adequate
[[Page 55831]]
Reactive Service will not be charged for this service. Any waiver of
this charge or any crediting arrangements for Reactive Service must be
documented in the Transmission Customer's Service Agreement.
Formula Rate
[GRAPHIC] [TIFF OMITTED] TN23SE05.061
Rate
A recalculated rate will go into effect every May 1 based on the
above formula and updated financial and load data. The UGPR will notify
the Transmission Customer annually of the recalculated rate on or
before April 1.
Rate Schedule UGP-AS3; October 1, 2005; Supersedes 1998 Schedule
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 October 1, 2005, through September 30, 2010, or until superseded
by another rate schedule.
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 balancing authority (WAUGP)
operator. The Transmission Customer must either purchase this service
from WAUGP or make alternative comparable arrangements to satisfy its
Regulation obligation.
