Pick-Sloan Missouri Basin Program-Eastern Division-Rate Order Nos. WAPA-144 and WAPA-148, 68820-68839 [E9-30827]
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Federal Register / Vol. 74, No. 248 / Tuesday, December 29, 2009 / Notices
at a later date to discuss any projectrelated effects to archaeological,
historic, or traditional cultural
properties.
Meeting Objectives
At the scoping meetings, staff will: (1)
Summarize the environmental issues
tentatively identified for analysis in the
EA; (2) solicit from meeting participants
all available information, especially
quantifiable data, on the resources at
issues; (3) encourage statements from
experts and the public on issues that
should be analyzed in the EA, including
viewpoints in opposition to, or in
support of, the staff’s preliminary views;
(4) determine the resource issues to be
addressed in the EA; and (5) identify
those issues that require a detailed
analysis, as well as those issues that do
not require a detailed analysis.
Meeting Procedures
Scoping meetings will be recorded by
a stenographer and will become part of
the Commission’s formal record for this
proceeding.
Individuals, organizations, and
agencies with environmental expertise
and concerns are encouraged to attend
the meetings and to assist staff in
defining and clarifying the issues to be
addressed in the EA.
Kimberly D. Bose,
Secretary.
[FR Doc. E9–30811 Filed 12–28–09; 8:45 am]
BILLING CODE 6717–01–P
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
[Docket No. PR10–4–000]
Cranberry Pipeline Corporation; Notice
of Petition for Rate Approval
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December 22, 2009.
Take notice that on December 15,
2009, Cranberry Pipeline Corporation
(Cranberry) filed pursuant to section
284.123(b)(2) of the Commission’s
regulations, a petition requesting that
the Commission approve its request to
retain its existing interruptible
transportation rate and firm and
interruptible storage rates pursuant to
section 311 of the Natural Gas Policy
Act of 1978. Further, Cranberry requests
approval to retain its existing fuel and
lost and unaccounted for percentage for
transportation and services.
Any person desiring to participate in
this rate proceeding must file a motion
to intervene or to protest this filing must
file in accordance with Rules 211 and
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214 of the Commission’s Rules of
Practice and Procedure (18 CFR 385.211
and 385.214). Protests will be
considered by the Commission in
determining the appropriate action to be
taken, but will not serve to make
protestants parties to the proceeding.
Any person wishing to become a party
must file a notice of intervention or
motion to intervene, as appropriate.
Such notices, motions, or protests must
be filed on or before the date as
indicated below. Anyone filing an
intervention or protest must serve a
copy of that document on the Applicant.
Anyone filing an intervention or protest
on or before the intervention or protest
date need not serve motions to intervene
or protests on persons other than the
Applicant.
The Commission encourages
electronic submission of protests and
interventions in lieu of paper using the
‘‘eFiling’’ link at https://www.ferc.gov.
Persons unable to file electronically
should submit an original and 14 copies
of the protest or intervention to the
Federal Energy Regulatory Commission,
888 First Street, NE., Washington, DC
20426.
This filing is accessible on-line at
https://www.ferc.gov, using the
‘‘eLibrary’’ link and is available for
review in the Commission’s Public
Reference Room in Washington, DC.
There is an ‘‘eSubscription’’ link on the
Web site that enables subscribers to
receive e-mail notification when a
document is added to a subscribed
docket(s). For assistance with any FERC
Online service, please e-mail
FERCOnlineSupport@ferc.gov, or call
(866) 208–3676 (toll free). For TTY, call
(202) 502–8659.
Comment Date: 5 p.m. Eastern time,
Monday, January 4, 2010.
Kimberly D. Bose,
Secretary.
[FR Doc. E9–30812 Filed 12–28–09; 8:45 am]
BILLING CODE 6717–01–P
DEPARTMENT OF ENERGY
Western Area Power Administration
Pick-Sloan Missouri Basin Program—
Eastern Division-Rate Order Nos.
WAPA–144 and WAPA–148
AGENCY: Western Area Power
Administration, DOE.
ACTION: Notice of Order Concerning
Transmission and Ancillary Services
Rates and Transmission Service Penalty
Rate for Unreserved Use.
SUMMARY: The Deputy Secretary of
Energy confirmed and approved Rate
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Order Nos. WAPA–144 and WAPA–148
and Rate Schedules UGP–NT1, UGP–
FPT1, UGP–NFPT1, UGP–AS1, UGP–
AS2, UGP–AS3, UGP–AS4, UGP–AS5,
UGP–AS6, UGP–AS7 and UGP–TSP1 on
an interim basis. The provisional rates
will be in effect until the Federal Energy
Regulatory Commission (FERC)
confirms, approves, and places them
into effect on a final basis or until they
are superseded. The provisional rates
will provide sufficient revenue to pay
all annual costs, including interest
expenses, and repay required
investments within the allowable
periods.
DATES: Rate Schedules UGP–NT1, UGP–
FPT1, UGP–NFPT1, UGP–AS1, UGP–
AS2, UGP–AS3, UGP–AS4, UGP–AS5,
and UGP–AS6 and will be placed into
effect on an interim basis on January 1,
2010, and will be in effect until FERC
confirms, approves, and places the rate
schedules in effect on a final basis
through December 31, 2014, or until the
rate schedules are superseded. The
revised Rate Schedules UGP–NT1,
UGP–FPT1, UGP–NFPT1, UGP–AS1,
UGP–AS2, UGP–AS3, UGP–AS4, UGP–
AS5 and UGP–AS6 dated January 1,
2010, supersede the similarly titled rate
schedules dated October 1, 2005. Rate
Schedule UGP–AS7 will be placed into
effect on an interim basis on January 1,
2010; however, Rate Schedule UGP–
AS7 will not be charged until such time
as Western’s OATT is revised to provide
for Generator Imbalance Service. Rate
Schedule UGP–AS7 will remain in
effect through December 31, 2014, or
until superseded, to coincide with the
other ancillary service rates in this rate
order. Rate Schedule UGP–TSP1 will be
placed into effect on an interim basis on
January 1, 2010; however, Rate
Schedule UGP–TSP1 will not be
charged until such time as Western’s
Open Access Transmission Tariff
(OATT) is revised to provide for
unreserved use of transmission service
penalties. Rate schedule UGP–TSP1 will
also remain in effect through December
31, 2014, or until superseded, to
coincide with the other rates in this rate
order. Western will post notice on its
Open Access Same-Time Information
System (OASIS) Web site of its intent to
initiate charging for Rate Schedule
UGP–AS7 or UGP–TSP1.
FOR FURTHER INFORMATION CONTACT: Mr.
Robert J. Harris, Regional Manager,
Upper Great Plains Region, Western
Area Power Administration, 2900 4th
Avenue North, Billings, MT 59101–1266
or Ms. Linda Cady-Hoffman, Rates
Manager, Upper Great Plains Region,
Western Area Power Administration,
2900 4th Avenue North, Billings, MT
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59101–1266, telephone (406) 247–7439,
e-mail cady@wapa.gov.
SUPPLEMENTARY INFORMATION: The
transmission facilities in the Pick-Sloan
Missouri Basin Program—Eastern
Division (P–SMBP—ED) are integrated
with transmission facilities of Basin
Electric Power Cooperative (Basin) and
Heartland Consumers Power District
(Heartland) such that transmission
services are provided over an Integrated
System (IS), and the rates are sometimes
referred to as IS Rates. Western acts as
the administrator of the IS and monitors
service under the OATT.1 As owners of
the IS, Western, Basin, and Heartland
may be referred to as IS Partners. The
Deputy Secretary of Energy approved
the current Rate Schedules UGP–NT1,
UGP–FPT1, UGP–NFPT1, UGP–AS1,
UGP–AS2, UGP–AS3, UGP–AS4, UGP–
AS5, and UGP–AS6 for P–SMBP—ED
firm and non-firm transmission rates
and ancillary services rates through
September 30, 2010.2 The current rate
schedules contain formula-based rates
that are recalculated annually. The
provisional formula rates will continue
to be recalculated annually from
financial and load information.
Provisional rates will go into effect
January 1, 2010, and recalculated rates
annually on January 1 thereafter. The
provisional rate for Generator Imbalance
Service, under UGP–AS7, will go into
effect January 1, 2010, but will not be
charged until Western’s OATT is
revised to provide for Generator
Imbalance Service. The provisional
Penalty Rate for Unreserved Use of
Transmission Service, under UGP–TSP1
will go into effect on January 1, 2010,
but will not be charged until Western’s
OATT is revised to provide for
unreserved use penalties. Western will
post notice on its Open Access SameTime Information System (OASIS) Web
site of its intent to initiate charging for
Rate Schedule UGP–AS7 or UGP–TSP1.
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
1 Western’s OATT was most recently approved by
FERC on June 28, 2007, in Docket No. NJ07–2–000,
119 FERC 61,329 (2007) and the FERC’s letter order
issued on September 6, 2007, in Docket No. NJ07–
2–001.
2 Rate Order No. WAPA–122, 70 FR 55821,
September 23, 2005, and the FERC confirmed and
approved the rate schedules on May 30, 2006,
under FERC Docket No. EF05–5031–000, 115 FERC
¶ 62,230.
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into effect on a final basis, to remand,
or to disapprove such rates to FERC.
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 00–001.00C, 10 CFR part
903, and 18 CFR part 300, I hereby
confirm, approve, and place Rate Order
Nos. WAPA–144, the proposed P–
SMBP—ED Integrated System firm and
non-firm transmission rates and
ancillary services and WAPA–148, the
proposed Transmission Service Penalty
Rate for Unreserved Use into effect on
an interim basis. The new Rate
Schedules UGP–NT1, UGP–FPT1, UGP–
NFPT1, UGP–AS1, UGP–AS2, UGP–
AS3, UGP–AS4, UGP–AS5, UGP–AS6,
UGP–AS7 and UGP–TSP1 will be
promptly submitted to the Commission
for confirmation and approval on a final
basis.
Dated: December 23, 2009.
Daniel B. Poneman,
Deputy Secretary.
Department of Energy Deputy Secretary
Rate Order Nos. WAPA–144 and
WAPA–148
In the matter of: Western Area Power
Administration Rate Adjustment for the
Pick-Sloan Missouri Basin Program—
Eastern Division; Order Confirming,
Approving, and Placing the Pick-Sloan
Missouri Basin Program—Eastern
Division Transmission and Ancillary
Services and Transmission Service
Penalty for Unreserved Use 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
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
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authority to confirm, approve, and place
into effect on a final basis, to remand or
to disapprove such rates to the Federal
Energy Regulatory Commission (FERC).
Existing 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.
ATRR: Annual Transmission Revenue
Requirement.
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.
Control Area: An electric power
system or combination of electric power
systems to which a common automatic
generation control scheme is applied in
order to: (1) Match, at all times, the
power output of the generators within
the electric system(s) and capacity and
energy purchased from entities outside
the electric power system(s) with load
within the electric power system(s); (2)
maintain scheduled interchange with
other Control Areas, within the limits of
Good Utility Practice; (3) maintain the
frequency of the electric power
system(s) within reasonable limits in
accordance with Good Utility Practice;
and (4) provide sufficient generating
capacity to maintain operating reserves
in accordance with Good Utility
Practice.
Corps of Engineers: U.S. Army Corps
of Engineers.
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Customer: An entity with a contract
that is receiving service from Western
Area Power Administration’s Upper
Great Plains Region.
DOE: United States Department of
Energy.
Energy: Power produced or delivered
over a period of time. 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 Federal Energy Regulatory
Commission.
FERC Order No. 888: FERC Order
Nos. 888, 888–A, 888–B and 888–C
unless otherwise noted.
FERC Order No. 890: FERC Order
Nos. 890, 890–A, 890–B and 890–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.
GWh: Gigawatthour—the electrical
unit of energy that equals 1 billion
watthours or 1 million kilowatt-hours.
Heartland: Heartland Consumers
Power District.
Integrated System: Transmission
system combining assets of Western,
Basin Electric, and Heartland.
IS: Integrated System.
Intermittent Resource: An electric
generator that is not dispatchable and
cannot store its fuel source and,
therefore, cannot respond to changes in
demand or respond to transmission
security constraints.
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.
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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.
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.
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.
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: Documents explaining
the rationale and background for the
rate proposals contained in this Rate
Order.
Reclamation: United States
Department of the Interior, Bureau of
Reclamation.
Reactive Supply and Voltage Control
Service: A service which provides
reactive supply through changes to
generator reactive output to maintain
transmission line voltage and facilitate
electricity transfers.
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Regulation and Frequency Response
Service: A service which provides for
following the moment-to- moment
variations in the demand or supply in
a Control Area and maintaining
scheduled interconnection frequency.
Reserve Services: Spinning Reserve
Service and Supplemental Reserve
Service.
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.
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
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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 Documents: 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,
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 Upper Great
Plains Region, 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.
Unreserved Use: Use of transmission
service in excess of reserved capacity at
any point of receipt or any point of
delivery.
VAR: A unit of reactive power.
WAUE: Western Area Power Upper
Great Plains Region East Control Area.
WAUW: Western Area Power Upper
Great Plains Region West Control Area.
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.
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Western Regions: Customer service
regions of the Western Area Power
Administration.
Western’s Tariff: Western’s Open
Access Transmission Service Tariff.
Effective Date
The provisional rates will take effect
on January 1, 2010, and will remain in
effect through December 31, 2014,
pending approval by FERC on a final
basis. Rate schedules UGP–AS7 and
UGP–TSP1 will be placed into effect on
an interim basis on January 1, 2010, but
will not be charged until Western’s
Open Access Transmission Tariff
(OATT) is revised to provide for
Generator Imbalance Service and/or
Transmission Service Penalty Rate for
Unreserved Use. Western will post
notice on its Open Access Same-Time
Information System (OASIS) Web site of
its intent to initiate charging for Rate
Schedule UGP–AS7 or UGP–TSP1.
Public Notice and Comment
Western followed the Procedures for
Public Participation in Power and
Transmission Rate Adjustments and
Extensions, 10 CFR part 903, in
developing these rates. The steps
Western took to involve interested
parties in the rate process were:
1. The rate adjustment process began
when Western’s UGPR mailed a notice
announcing an Advance Announcement
of Rate Adjustment public meeting to all
IS Transmission Customers and
interested parties. The meeting was held
on June 10, 2008, in Sioux Falls, South
Dakota. At the Advance Announcement
of Rate Adjustment meeting, Western
provided pertinent information relevant
to the rate adjustment and answered
questions.
2. A Federal Register notice
published on June 3, 2009 (74 FR
26682), announced the proposed rate
adjustments for P–SMBP–ED
Transmission and Ancillary Service
rates. This publication began a public
consultation and comment period and
announced the public information and
the public comment forums.
3. A Federal Register notice
published on June 26, 2009 (74 FR
30567), announced the proposed
Transmission Service Penalty Rate for
Unreserved Use. This publication began
a public consultation and comment
period and announced the public
information and the public comment
forums.
4. On June 5, 2009, Western mailed
letters to all IS Transmission Customers
and interested parties transmitting the
Federal Register notice published on
June 3, 2009, and directing them to the
rate brochure for the Transmission and
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Ancillary Services Rate Adjustment on
Western’s Web site. On June 26, 2009,
Western mailed letters to all IS
Transmission Customers and interested
parties transmitting the Federal Register
notice published on June 26, 2009, and
directing them to the rate brochure for
the Transmission Service Penalty Rate
for Unreserved Use on Western’s Web
site.
5. On June 24, 2009, beginning at 9
a.m., Western held a public information
forum at the Holiday Inn City Center in
Sioux Falls, South Dakota. Western
provided detailed explanations of the
proposed Transmission and Ancillary
Service Rates. Western provided Rate
Brochures, informational handouts and
answered questions at this meeting.
6. On July 28, 2009, beginning at 8
a.m., Western held a public information
forum at the Holiday Inn City Center
Sioux Falls, South Dakota. Western
provided detailed explanations of the
proposed Transmission Service Penalty
Rate for Unreserved Use. Western
provided Rate Brochures, informational
handouts, and answered questions at
this meeting.
7. On July 28, 2009, beginning at 9
a.m., Western held a public comment
forum at the Holiday Inn City Center
Sioux Falls, South Dakota, to give the
public the opportunity to comment for
the record on the proposed
Transmission and Ancillary Services
Rates and the Transmission Service
Penalty Rate for Unreserved Use.
8. Western received one comment
letter during the consultation and
comment period for proposed rates for
P–SMBP–ED Transmission and
Ancillary Service rates, which ended on
October 1, 2009. Western received two
comment letters during the consultation
and comment period for proposed
Transmission Service Penalty Rate for
Unreserved Use, which ended on
September 24, 2009. All formally
submitted comments have been
considered in preparing this Rate Order.
Comments
Representatives of the following
organization made oral comments
pertaining to the proposed P–SMBP–ED
Transmission and Ancillary Service
rates:
Missouri River Energy Services
The following organizations
submitted written comments pertaining
to the proposed P–SMBP–ED
Transmission and Ancillary Service
rates:
Missouri River Energy Services
The following organizations
submitted written comments pertaining
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to the proposed P–SMBP–ED
Transmission Service Penalty Rate for
Unreserved Use rate:
Midwest ISO Transmission Owners
ITC Holdings Corp.
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. No. 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 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 power plants
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, Western, 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 Converter Station
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
requestors. 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.
P–SMBP–ED Transmission and
Ancillary Services Rates Study
Western prepared a Transmission and
Ancillary Service rates study to ensure
that Formula IS 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.
In the past, rates have been based on
the most recently available historical
test year data. In preparing the current
rates study, projections for the various
revenue requirement components were
used to develop the forward looking
(projected) rate. The annual revenue
requirements include O&M expenses,
administrative and general expenses,
interest expense, and depreciation
expense. These revenue requirements
are offset by appropriate estimated
revenues. Annual audited financial data
will be used to true-up the estimates
used to project the forward looking rate
to the actual expenses and load
incurred.
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 Provisional Revenue
Requirement based upon the most
recent historical data available at the
time of the initial rate proposal.
COMPARISON OF EXISTING AND PROVISIONAL INTEGRATED SYSTEM TRANSMISSION AND ANCILLARY SERVICES
Existing
revenue
requirement
Service
Transmission ..............................................................................................................................
Scheduling, System Control, and Dispatch ...............................................................................
Reactive Supply and Voltage Control .......................................................................................
Regulation and Frequency Control ............................................................................................
Reserves ....................................................................................................................................
Energy Imbalance ......................................................................................................................
Generator Imbalance .................................................................................................................
Transmission Service Penalty Rate for Unreserved Use ..........................................................
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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
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administrative policies and applicable
laws.
Integrated System Transmission
Service Rates Discussion
Western offers Network Integration
Transmission, Firm Point-to-Point and
Non-firm Point-to-Point Transmission,
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Provisional
revenue
requirement
$155,056,530
3,649,053
4,496,498
1,362,791
2,569,924
N/A
N/A
N/A
$163,521,251
3,649,053
2,376,635
1,362,791
3,384,360
N/A
N/A
N/A
Percentage
change
5.46
0.00
¥47.14
0.00
31.69
N/A
N/A
N/A
Scheduling, System Control, and
Dispatch Service, Reactive Supply and
Voltage Control Service, Regulation and
Frequency Response Service, Energy
Imbalance Service, and Reserve Service
on the IS. The rate schedules for the IS
were initially placed into effect by Rate
Order No. WAPA–79 on August 1, 1998,
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and were effective through July 31,
2003. The FERC order to confirm these
rate schedules was issued on November
25, 1998. These rate schedules were
then extended by Rate Order No.
WAPA–100 through September 30,
2005. Rate Order No. WAPA–122
removed the Generator Step Up
Transformers from transmission and
placed them in generation in the
formula rate calculations. The rate
schedules placed into effect by Rate
Order No. WAPA–122 were effective on
October 1, 2005, and will remain in
effect until September 30, 2010, or until
superseded.
The provisional formula rates include
revisions to the Network Integration,
Firm and Non-firm Transmission, and
Ancillary Service Rates as described in
Rate Schedules UGP–NT1, UGP–FPT1,
UGP–NFPT1, UGP–AS1, UGP–AS2,
UGP–AS3, UGP–AS4, UGP–AS5, and
UGP–AS6. These revisions will utilize
estimates of transmission costs for the
upcoming year to calculate annual
revenue requirements, update formulas
utilized in the formula rate calculations,
change the effective date for rates
resulting from the annual recalculation,
provide a rate recalculation review/
comment period, and standardize input
data requirements.
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 their firm electric service
under existing contracts that expire in
2020.
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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 is
estimated to be 4,605,000 kW.
Revenue Requirement for IS
Transmission Service
The current rates for the IS
Transmission Service are based on a
revenue requirement that recovers the
annual costs of Western, Basin Electric,
Heartland, and approved customer
facility credits associated with
providing IS Transmission Service. The
annual costs are offset by appropriate
transmission revenue credits to avoid
over recovery of costs.
Western is changing the method of
developing the revenue requirement for
Network, Firm Point-to-Point, and Non-
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Firm Point-to-Point transmission
services. Western is changing the
implementation of the formula rates to
recover expenses and investments in
transmission on a current (forward
looking) rather than a lagging basis. This
change will allow Western to more
accurately match cost recovery with cost
incurrence. To implement this change,
Western will utilize estimates of the IS
transmission system costs and load for
the upcoming year in the formula rate
recalculation. Western will true-up the
estimates based on IS actual costs and
actual load. Rates will continue to be
recalculated every year. Revenue
collected in excess of Western’s, Basin
Electric’s, Heartland’s, and entities’
receiving customer facility credits actual
net revenue requirements will be
returned to customers through a
reduction in revenue requirement in a
subsequent year. Actual revenues that
are less than the net revenue
requirement would likewise be
recovered by an increase in a
subsequent year’s revenue requirement.
The true-up procedure ensures the IS
will recover no more and no less than
its actual transmission costs.
Revenue Requirement Calculation
Templates
Western will initiate the use of
standardized revenue requirement
calculation templates by those entities
submitting financial data for the annual
rate recalculation to aid in the revenue
requirement/rate recalculation and
review processes. These revenue
requirement templates will gather
required financial information and data
from IS partners and other entities for
the calculation of revenue requirements
and facility credits. Western will review
requests to utilize other or modified
templates for appropriateness and
conduct a public process prior to
granting approval for use. Western will
accept use of a FERC approved template
for a particular entity without
conducting a public process prior to
granting approval for use provided that
the following conditions are met: (1)
The template addresses all the
transmission facilities owned by the
entity; (2) the template includes a
separate allocation for IS qualifying
facilities; and (3) it is the latest FERC
approved template for this entity.
Review of Annual Revenue Requirement
and Rate Recalculation
Western will determine the IS net
projected revenue requirement and load
for each year in accordance with
applicable IS rate schedules. Western
will make the IS net projected revenue
requirement available to customers
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including projected costs of plant in the
rate base, transmission O&M expense,
transmission administrative and general
expense, transmission depreciation
expense, load, and resulting rates
incorporating any True-up Adjustment.
All data will be provided in sufficient
detail to identify the components of
Western’s net revenue requirement.
Western has conducted an annual IS
rate recalculation utilizing the previous
year’s data with the recalculated rate
effective May 1 of each year. With the
implementation of the provisional
formula rates resulting from this process
effective on January 1, 2010, Western
will conduct future rate recalculations
with an effective date of January 1.
Western will provide the results of
this annual rate recalculation to
customers on or about September 1 of
each year and will provide customers
the opportunity to discuss and comment
on the recalculated rates by October 31
of each year. Western will respond to
customer comments prior to or at the
time of the implementation of the
recalculated revenue requirements and/
or rates. For the provisional rates going
into effect on January 1, 2010, the
Annual Revenue Requirement for IS
Transmission Service is $163,521,251.
Should Western find that any
comment concerning the rate formula
bears merit, Western reserves the right
to make adjustments to the revenue
requirements and/or rates consistent
with proper application of the Formula
Rate. Western’s determination
concerning the proper application of the
Formula Rate will be final.
True-Up Procedures
Under the true-up procedures, any
differences between estimated revenue
requirements and actual revenue
requirements in any given year are
identified based on Revenue
Requirement Templates utilizing actual
financial data and actual load data for
the preceding year. Revenue collected in
excess of the actual net revenue
requirement will be returned to
customers through a reduction in
revenue requirement in the subsequent
year following the calculation of the
true-up. Revenues that are less than the
forecast net revenue requirement would
likewise be recovered in the IS rates for
the subsequent year.
Actual Net Revenue Requirement
(calculated in accordance with
Western’s Rate Recalculation process)
for the previous year as provided in the
revenue requirement templates for
Western IS partners and entities
receiving revenue credits shall be
compared to the projections made for
the same year (True-up Year). The
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comparison of actual net revenue to
projected net revenue determines the
excess or shortfall in the projected
revenue requirement used for billing
purposes in the True-up Year. In
addition, actual divisor loads (12-cp
average) will be compared to projected
divisor loads and the difference
multiplied by the rate actually billed to
determine any excess or shortfall in
collection due to volume. The sum of
the excess or shortfall due to the actual
versus projected revenue requirement
and the excess or shortfall due to
volume shall constitute the True-up
Adjustment. The True-up Adjustment
and related calculations shall be posted
to Western’s OASIS no later than July 1
following the issuance of financial
statements for the previous year.
Western will provide an explanation of
the True-up Adjustment in response to
customer inquiries and will post on the
OASIS information regarding frequently
asked questions.
The Net Revenue Requirement for
transmission services for the following
year will be the sum of the projected
revenue requirement for the following
year, plus or minus the True-Up
Adjustment and any other adjustments
from the previous year.
current year formula rate which
involves a change to the manner in
which the inputs are developed rather
than a change in the formula itself. The
charge for monthly Network IS
Transmission Service is the product of
the network customer’s load ratio share
times one-twelfth (1/12) of the annual
Network Transmission Revenue
Requirement. The Network
Transmission Revenue Requirement is
the annual cost associated with
providing transmission service less
revenue credits for Non-Firm
Transmission Service. The Network
Transmission Revenue Requirement
will be based on estimates for costs to
provide transmission service for the upcoming year. The load ratio share is the
network customer’s hourly load
coincident with the IS monthly
Transmission System peak minus the
coincident peak for all IS Firm Point-toPoint Transmission Service plus the
Firm Point-to-Point reservations. The
Network rate includes costs for
scheduling, system control, and
dispatch service needed to provide
transmission service.
Formula Rate for Network IS
Transmission Service
While Western is changing the
method for developing annual revenue
requirements, the formula for
calculating the Network Transmission
Service rate is unchanged from
Western’s previously approved filing
with the FERC. Western will use a
The monthly rate for Firm Point-toPoint IS Transmission Service is 1/12
the annual cost associated with
providing transmission service less
revenue credits for Non-Firm
Transmission Service divided by the
capacity reservation needed to support
the average monthly IS Transmission
System load. As with Network
Formula Rate for Firm Point-to-Point IS
Transmission Service
Transmission Service, Western will be
using a current year formula rate which
involves a change to the manner in
which the inputs are developed rather
than a change in the formula itself. This
rate may be summarized with the
following formula: ISFPTP = (Total
Annual Revenue Requirement—Non
Firm Revenue Credits)/12 months/
Average Transmission System Monthly
Peak Load. Firm Point-to-Point
Transmission Service will be offered on
an up to basis at daily, weekly, monthly,
and yearly rates.
Formula Rate for Non-Firm Point-toPoint Transmission
Western will not change the rate
formula for Non Firm Point-to-Point
Transmission Service other than
utilizing cost projections as data inputs
to determine the annual revenue
requirement as described above. The
Non Firm Point-to-Point Transmission
Service rate formula remains: Monthly
IS Firm Point-to-Point Transmission
Service rate divided by 730 hours per
month times 1000 mills per dollar.
The following table summarizes the
difference between the current IS
Transmission Service rates and the
provisional IS Transmission Service
rates. It compares the change in the
projections for the 2009–2010
transmission and ancillary services
study and the provisional IS
Transmission Service rates for this rate
adjustment based on the most recent
historical data and estimated data
available at the time of the initial rate
proposal.
COMPARISON OF ANNUAL REVENUES
Item
Existing rate
Annual IS Cost (Net of Revenue Credits) .................................................................................
Transmission Customer Facility Credits ....................................................................................
Annual Revenue Requirement for IS Transmission Service .....................................................
Adjustment for Prior Year ..........................................................................................................
Annual Transmission Revenue Requirement ............................................................................
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Basis for Rate Development
The current IS Network, Firm Pointto-Point and Non-Firm Point-to-Point
Transmission Service formula rates are
scheduled to expire on September 1,
2010. The current Network, Firm Pointto-Point and Non-Firm Point-to-Point
Transmission Service formula rates do
not capture new investment costs until
they have been in service for up to 2
years. The proposed rates are forward
looking and include estimates for
investments being placed in service,
annual operation and maintenance
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expenses, depreciation, interest, and
administrative and general costs. In the
past, rates were recalculated in April
and were effective on May 1. The rates
implemented in this process will be
available for review on or about
September 1 and placed into effect on
January 1.
Integrated System Ancillary Services
Rates Discussion
The IS will continue to offer the
following six ancillary services: (1)
Scheduling system control, and
dispatch service; (2) reactive supply and
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$147,038,956
8,541,224
155,580,180
523,417
155,056,530
Provisional rate
$154,900,362
8,620,889
163,521,251
N/A
163,521,251
Percentage
change
5.35
0.93
5.10
N/A
5.46
voltage control from generation sources
service; (3) regulation and frequency
response service; (4) energy imbalance
service; (5) spinning reserve service and
(6) supplemental reserve service; and
will add a seventh ancillary service; (7)
generator imbalance service.
Western has already marketed the
maximum practical amount of power
from each of its projects, based on a
reasonable level of risk, leaving little or
no Federal hydroelectric power
resources available for ancillary
services. Changes in water conditions
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frequently affect the ability of the
hydroelectric projects to meet
obligations on a short-term basis. The
unique characteristics of the hydro
resource, Western’s existing long-term
power commitments, and the
limitations of the resource due to
changing water conditions limit
Western’s ability to provide
Transmission Customers generationrelated ancillary services and redispatch
using Federal hydro resources.
Consequently, Western will provide
ancillary services by purchasing power
resources whenever necessary and pass
through these costs to the customer.
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Formula Rate for 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 the communications facilities
net plant associated with Scheduling,
System Control, and Dispatch Service
by the transmission fixed charge rate. In
the past, the annual revenue
requirement for Scheduling, System
Control, and Dispatch Service has been
divided by the number of daily
schedules in the calculation year.
Western is changing this formula.
Instead of dividing the annual revenue
requirement for Scheduling, System
Control, and Dispatch Service by the
number of daily schedules in the
calculation year, Western will divide
the annual revenue requirement for
Scheduling, System Control, and
Dispatch Service by the number of daily
tags in the calculation year. This rate
and rate design is recovering only
Western’s revenue requirement.
Formula Rate for Reactive Supply and
Voltage Control Services From
Generation Sources Service
Western’s current formula for
Reactive Supply and Voltage Control
from Generation Sources (RSVC) 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 five (5) year
average peak monthly percentage of
Western’s generation operating in a
synchronous condenser mode to
determine Western’s reactive service
revenue requirement. Western’s, Basin
Electric’s, Heartland’s, and Missouri
River Energy Services’ revenue
requirements for RSVC Service are
summed to get the total revenue
requirement for this service. The RSVC
Service rate is then derived by dividing
the total annual revenue requirement by
the load requiring RSVC Service. The
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annual cost is then divided by 12
months to obtain a monthly rate. In this
formula, Western is only compensated
for providing RSVC Service based upon
the cost of Western’s generation
operating outside the 0.95 leading to
0.95 lagging power factor bandwidth,
while Basin, Heartland, and Missouri
River Energy Services are compensated
based on costs for generation operating
within this power factor bandwidth.
Western is changing its rate for RSVC
Service by removing costs of any
generation associated with operation
within the bandwidth from the total
revenue requirement for this service.
Under Western’s current rate, Western is
not compensated for providing RSVC
Service from its own generators
operating inside the bandwidth while
non-Federal generators are receiving
compensation for providing RSVC
Service within the bandwidth. Western
believes that both Federal and nonFederal generators should be treated
comparably when they provide RSVC
Service within the bandwidth.
Therefore, Western is discontinuing
payment for all other generators
providing RSVC Service within the 0.95
leading to 0.95 lagging power factor
bandwidth.
Western will continue to collect its
RSVC Service cost, for its generators
operating within the bandwidth, in the
firm power revenue requirement under
the then appropriate firm power rate
schedule and not from Transmission
Customers under its OATT. Therefore,
only Federal preference power
customers will pay the RSVC costs of
the Federal generators operating within
the bandwidth. This change will result
in transmission service customers
paying for RSVC Service based only
upon costs for generators operating
outside the bandwidth. Excluding RSVC
Service costs associated with generator
operation within the bandwidth from
the RSVC Service revenue requirement
will require all other non-Federal
generator owners to recover their RSVC
Service costs, for operation within the
bandwidth, elsewhere.
Western’s Federal generation is
required to operate in synchronous
condenser mode (i.e., outside the power
factor bandwidth) to maintain system
voltages and meet reliability criteria
and, therefore consistent with the
previous practice, Western will include
its costs to provide RSVC Service for
Federal generators operating outside the
bandwidth. Western will include costs
associated with other non-Federal
generators required to operate outside
the power factor bandwidth to maintain
system voltages and meet reliability
criteria (e.g., other generators that
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68827
operate as synchronous condensers, or
generators that are requested by Western
to operate outside the bandwidth as
noted in Western’s generator
interconnection procedures and
agreements).
The following provisional rate
formula will apply: Western’s total P–
SMBP–ED generation net plant
multiplied by the generation fixed
charge rate (in percent) equals Western’s
annual cost. Western’s annual cost is
multiplied by the five (5) year average
peak monthly percentage of Western’s
Federal synchronous condensing
generation to determine Western’s
outside the bandwidth reactive service
revenue requirement. Western’s revenue
requirement plus any revenue
requirement or costs incurred from
other non-Federal generators required
by Western to operate outside the
bandwidth is the total annual revenue
requirement for RSVC Service. This
total annual revenue requirement is
then divided by the total load (kWyear)
in Western’s Control Areas.3 The
product is then divided by 12 months to
obtain a monthly charge.
Formula Rate for Regulation and
Frequency Response Service
Western will continue the current
formula-based rate methodology for
Regulation and Frequency Response
Service as described below. Regulation
and Frequency Response Service in the
east side of the Control Area is provided
primarily by Oahe generation and in the
west side of the Control Area by Fort
Peck, both of which are Corps of
Engineers (Corps) facilities. The Corps
generation fixed charge rate (in percent)
is applied to Oahe and Fort Peck net
plant investment, producing an annual
Corps generation cost for the Oahe and
Fort Peck power plants. This cost is
divided by the capacity at the plants
(937,000 kW) to derive a dollar per
kilowatt amount for Oahe’s and Fort
Peck’s installed capacity (kWYear). This
dollar per kilowatt amount is then
3 Western has retained the term ‘‘Control Area’’ in
this document maintaining consistency with usage
of the term in FERC’s pro forma tariff and Western’s
current OATT. As defined in Western’s OATT, a
Control Area is: An electric power system or
combination of electric power systems to which a
common automatic generation control scheme is
applied in order to: (1) Match, at all times, the
power output of the generators within the electric
system(s) and capacity and energy purchased from
entities outside the electric power system(s), with
load within the electric power system(s); (2)
maintain scheduled interchange with other Control
Areas, within the limits of Good Utility Practice; (3)
maintain the frequency of the electric power
system(s) within reasonable limits in accordance
with Good Utility Practice; and (4) provide
sufficient generating capacity to maintain operating
reserves in accordance with Good Utility Practice.
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applied to the capacity (in kW) of Oahe
and Fort Peck generation reserved for
regulation and frequency response in
the Control Area. Western’s annual
revenue requirement for Regulation and
Frequency Response Service is
determined by applying the dollar per
kilowatt charge to the capacity used for
Regulation and Frequency Response
Service plus the cost of any additional
resources acquired to support regulation
requirements for intermittent renewable
resources serving load within Western’s
Control Areas. The total Regulation and
Frequency Response Revenue
Requirement is determined by adding
Western’s, Basin Electric’s, and
Heartland’s Regulation and Frequency
Response Revenue Requirements. The
Regulation and Frequency Response
Service charge is then determined by
dividing the total revenue requirement
by the total load in the Control Area
(kWYear). The result is then divided by
12 months to obtain a monthly charge.
Western supports the installation of
renewable sources of energy but
recognizes that certain operational
constraints exist in managing the
significant fluctuations that are a normal
part of their operation. When Western
purchases power resources to provide
Regulation and Frequency Response
Service to intermittent renewable
generation resources serving load within
Western’s Control Areas, costs for these
regulation resources will become part of
Western’s Regulation and Frequency
Response Service charges. However,
Western has marketed the maximum
practical amount of power from each of
its projects leaving little or no flexibility
for provision of additional power
services. Consequently, Western will
not regulate for the difference between
the output of an intermittent generator
located within Western’s Control Area
and a delivery schedule from that
generator serving load located outside of
Western’s Control Area. Intermittent
generators serving load outside
Western’s Control Area will be required
to pseudo-tie or dynamically schedule
their generation to another Control Area.
Rate for Energy Imbalance Service
Western is changing its rate for Energy
Imbalance Service to be consistent with
the rules promulgated by FERC to the
extent that it is consistent with
Western’s mission and is permitted by
law and regulations. Currently penalty
charges apply only 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 while over
deliveries outside the bandwidth are
forfeited.
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Western proposes charges be modified
and based on the deviation bands as
follows: Deviations within +/¥ 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 Transmission
Customer’s scheduled transaction(s)
will be netted on a monthly basis and
settled financially, at the end of the
month, at 100 percent of the average
incremental cost for the month.
Deviations greater than +/¥ 1.5 percent
up to 7.5 percent (or greater than 2 MW
up to 10 MW) of the scheduled
transaction to be applied hourly to any
energy imbalance that occurs as a result
of Transmission Customer’s scheduled
transaction(s) will be settled financially,
at the end of each month, at 110 percent
of incremental cost when energy taken
by the Transmission Customer in a
schedule hour is greater than the energy
scheduled or 90 percent of incremental
cost when energy taken by a
Transmission Customer in a schedule
hour is less than the scheduled amount.
Deviations greater than +/¥ 7.5 percent
(or 10 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) will be settled financially,
at the end of each month, at 125 percent
of the incremental cost for energy taken
by the Transmission Customer in a
scheduled hour that is greater than the
energy scheduled, or 75 percent of the
incremental cost for that hour when
energy taken by a Transmission
Customer is less than the scheduled
amount.
Western’s incremental cost will be
based upon a representative hourly
energy index or combination of indexes.
The index to be used will be posted on
Western’s OASIS https://
www.oatioasis.com/wapa/ at
least 30 days prior to use for
determining Western’s incremental cost
and will not be changed more often than
once per year unless Western
determines that the existing index is no
longer a reliable price index.
Formula Rates for Operating Reserves
Service—Spinning and Supplemental
Western will continue the current
formula-based rate methodology for
Spinning Reserve Service and
Supplemental Reserve Service (Reserve
Services), except that Western will
substitute the reserve requirement of the
current reserve sharing group of which
Western and the IS Partners are
members or will substitute Western’s
and the IS Partners’ own operating
reserve requirement for that of the Mid-
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Continent Area Power Pool (MAPP)
requirement.
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/kWyear is
determined by dividing the annual cost
of generation by the plant capacity. The
capacity used for Reserve Services is
determined by multiplying the peak IS
load by either the operating reserve
requirement of the current reserve
sharing group of which Western and the
IS Partners are members or their own
operating reserve requirement. The cost/
kWyear is multiplied by the capacity
used for Reserve Services to obtain the
annual revenue requirement. 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 design recovers
only Western’s revenue requirement
associated with Reserve Services.
Western has no long-term reserves
available beyond its own internal
requirements. At a customer’s request,
Western will acquire needed resources
and pass the costs on to the requesting
customer. The customer is responsible
to provide the transmission to deliver
these reserves.
Rate for Generator Imbalance Service
Western is adding a Generator
Imbalance Service rate under a new Rate
Schedule, UGP–AS7, to be consistent
with rules promulgated by FERC to the
extent consistent with Western’s
mission and permitted by law and
regulations. However, if Western does
not also implement a Generator
Imbalance Service in a revised OATT,
this rate will not be utilized.
Generator Imbalance Service is
provided when a difference occurs
between the output of a generator
located within the Transmission
Provider’s Control Area and a delivery
schedule from that generator to (1)
another Control Area or (2) a load
within the Transmission Provider’s
Control Area over a single hour.
Western will offer this service, to the
extent that it is feasible to do so from
its own resources or from resources
available to it, when Transmission
Service is used to deliver energy from a
generator located within its Control
Area. The Transmission Customer must
either purchase this service from
Western or make alternative comparable
arrangements, which may include use of
non-generation resources capable of
providing this service, to satisfy its
Generator Imbalance Service obligation.
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Western may charge a Transmission
Customer a penalty for either hourly
generator imbalances under this
Schedule UGP–AS7 or hourly energy
imbalances under Rate Schedule UGP–
AS4 for imbalances occurring during the
same hour, but not both, unless the
imbalances aggravate rather than offset
each other.
Western bases the rate on deviation
bands as follows: Deviations within
+/¥ 1.5 percent (with a minimum of 2
MW) of the scheduled transaction to be
applied hourly to any generator
imbalance that occurs as a result of
Transmission Customer’s scheduled
transaction(s) will be netted on a
monthly basis and settled financially, at
the end of the month, at 100 percent of
the average incremental cost. Deviations
greater than +/¥ 1.5 percent up to 7.5
percent (or greater than 2 MW up to
10 MW) of the scheduled transaction to
be applied hourly to any generator
imbalance that occurs as a result of
Transmission Customer’s scheduled
transaction(s) will be settled financially,
at the end of each month. When energy
delivered in a schedule hour from the
generation resource is less than the
energy scheduled, the charge is 110
percent of incremental cost. When
energy delivered from the generation
resource is greater than the scheduled
amount, the credit is 90 percent of the
incremental cost. Deviations greater
than +/¥ 7.5 percent (or 10 MW) of the
scheduled transaction to be applied
hourly to any generator imbalance that
occurs as a result of the Transmission
Customer’s scheduled transaction(s)
will be settled at 125 percent of
Western’s incremental cost when energy
delivered in a schedule hour is less than
the energy scheduled or 75 percent of
Western’s daily incremental cost for that
hour when energy delivered from the
generation resource is greater than the
scheduled amount. As an exception, an
intermittent resource will be exempt
from this deviation band and will pay
the deviation band charges for all
deviations greater than the larger of 1.5
percent or 2 MW.
Deviations from scheduled
transactions in order to respond to
directives by the Transmission Provider,
a balancing authority, or a reliability
coordinator shall not be subject to the
deviation bands identified above and,
instead, shall be settled financially, at
the end of the month, at 100 percent of
68829
incremental cost. Such directives may
include instructions to correct
frequency decay, respond to a reserve
sharing event, or change output to
relieve congestion.
Western’s incremental cost will be
based upon a representative hourly
energy index or combination of indexes.
The index to be used will be posted on
Western’s OASIS https://
www.oatioasis.com/wapa/ at
least 30 days prior to use for
determining the Western incremental
cost and will not be changed more often
than once per year unless Western
determines that the existing index is no
longer a reliable price index.
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
2009–2010 transmission and ancillary
services study and the provisional IS
Transmission and Ancillary Service
rates for this rate adjustment based on
the most recent historical and estimated
data available at the time of the rate
estimate.
COMPARISON OF ANCILLARY SERVICE RATES
Percentage
change
Item
Unit
Existing rate
Provisional rate
Scheduling, System Control,
and Dispatch Service.
Reactive Supply and Voltage
Control.
Regulation and Frequency Response.
Energy Imbalance ...................
Reserves .................................
Generator Imbalance ..............
Schedule/Tag .........................
$44.59/Schedule/day ..............
$44.59/Tag/day .......................
0.00
kWmonth ................................
0.09 .........................................
0.05 .........................................
¥44.44
kWmonth ................................
0.05 .........................................
0.05 .........................................
0.00
Deviation Bands as Described
kWmonth ................................
Deviation Bands as Described
N/A ..........................................
0.14 .........................................
N/A ..........................................
N/A ..........................................
0.18 .........................................
N/A ..........................................
N/A
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Basis for Rate Development
The current IS Ancillary Service
formula rates are scheduled to expire on
September 30, 2010. The current IS
Ancillary Service formula rates do not
capture new investments costs until
they have been in service for up to 2
years. In the past, rates were
recalculated in April and were effective
on May 1. The rates implemented in this
process will be available for review on
or about September 1 and placed into
effect on January 1. In addition the
provisional rates alter the deviation
bands for energy imbalance and define
incremental costs for energy imbalance
based on an index price. A similar
service for generator imbalance is
introduced. The rate for RSVC Service
will no longer include the costs of any
generation associated with operation
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within the 0.95 leading and 0.95 lagging
power factor bandwidth from the total
revenue requirement for this service.
Rates for Spinning Reserve Service and
Supplemental Reserve Service (Reserve
Services) will be based on the reserve
requirement of the current reserve
sharing group of which Western and the
IS Partners are members or will
substitute Western’s and the IS Partners’
own operating reserve requirement.
Comments
The comments and responses below
regarding the transmission and ancillary
services rates are paraphrased for
brevity when not affecting the meaning
of the statement(s). Direct quotes from
oral or written comments are used for
clarification when necessary.
1. Comment: Western received both
oral and written comments that the need
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for an Energy Imbalance Rate Schedule
would be eliminated if Western
participated in an organized market
such as the Midwest Independent
System Operator (MISO) market.
Response: This comment is not
directly related to the proposed rate
action and is outside the scope of this
rate process. However, Western has and
will continue to evaluate this and other
options based on the cost and benefit to
Western’s customers.
2. Comment: Western received
comments that introducing an Energy
Imbalance Service and a Generator
Imbalance Service to mitigate
imbalances create an arbitrarily punitive
structure for deviations while at the
same time ignoring whether or not one
party’s deviation may actually off-set
another party’s deviation and eliminate
the net deviation.
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Response: Western disagrees that
introducing the Energy Imbalance and
Generator Imbalance Services creates an
arbitrarily punitive structure for
deviations. In establishing its Energy
Imbalance and Generator Imbalance
Services, Western is implementing the
deviation structure as delineated in the
FERC’s Order 890 and Orders 890A
through C. It is Western’s intent that
imbalance charges should provide
appropriate incentives to keep
schedules accurate and that the tiered
structure recognizes the link between
escalating deviations and potential
reliability impacts on the system.
Western believes that to net one party’s
deviation against another party’s
deviation, absent formal agreements
among the parties, would not
necessarily provide an appropriate
incentive for either party to accurately
schedule. Western recognizes that, other
than the first deviation band, there is no
netting of energy; however, there is
financial netting in the financial
settlement process.
3. Comment: Western received a
comment advocating that the Imbalance
Services be applicable to all network
customers independent of their
respective marketing arrangements.
Response: Western disagrees that
Imbalance Services be applicable to all
transmission customers regardless of
their respective marketing
arrangements. If a group of transmission
customers create a formal marketing
arrangement between them and agree to
share imbalances (i.e., essentially self
supplying) Western will allow that
group of transmission customers to be
treated as a single entity in regard to
Western’s application of imbalance
charges. Western believes that this is
reasonable if the group of transmission
customers has formal arrangements to
provide imbalance service to each other.
To the extent that the overall group is
assigned an imbalance charge by
Western, the group would assign the
responsibility for such charges within
the group based upon their formal
marketing arrangements. Western would
assign imbalance charges to the group in
a similar manner that it assigns
imbalance charges to an individual
transmission customer that relies only
on the balancing authority to make up
for its imbalances. Western will allow
any group of transmission customers to
utilize formal marketing arrangements
to meet its imbalance obligations on a
comparable manner.
4. Comment: Western received oral
and written comments that if the
Integrated System proceeds with
implementation of the Energy Imbalance
and Generator Imbalance schedules, that
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it should introduce steps to offset
deviations from the individual network
customers and then consider the net
impact to the Control Area.
Response: Western disagrees with the
comment that it should offset
imbalances between individual network
customers without any formal
arrangements between those
transmission customers. To do so would
allow individual transmission
customers to improperly take delivery
from other transmission customers
without any arrangements or agreement
by other transmission customers to
allow such deliveries. Western’s
proposed imbalance schedules are
intended to incent individual
transmission customers or formal
groups of transmission customers to
meet their individual or group
responsibilities to accurately schedule
and not rely on the control area or other
transmission customers with which it
has no arrangements. Western believes
that it is necessary to net the various
transmission deliveries of each
individual transmission customer or
formal group of transmission customers
(e.g., multiple Point-to-Point deliveries)
to assign imbalance charges to that
individual customer or formal group of
transmission customers based upon
their overall impact to Western’s control
area(s).
5. Comment: Western received a
comment that revenue generated from
the Energy and Generator Imbalance
schedules should credit Western’s
transmission customers on a load ratio
share basis so as not to incent Western
from continuing with this service in lieu
of participating in an organized market
such as MISO.
Response: Western’s Energy and
Generator Imbalance revenue in excess
of its incremental costs will reduce
future annual transmission revenue
requirements. Participation in an
organized market such as MISO is not
directly related to the proposed rate
action and is outside the scope of this
rate process.
6. Comment: Western received both
oral and written comments concerning
utilizing price indexes in its Energy and
Generator Imbalance rate schedules.
Comments advocated utilizing a single
index for each of the eastern and
western interconnections rather than the
higher of the two. Barring using a price
index for each interconnection,
commenter advocated use of a ratio of
index prices and provided suggestions
for ratio formula. Also received was a
written suggestion that Western utilize
hourly pricing instead of the highest
daily price as a method to allocate costs.
Commenter also questioned what the
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two index prices will be based on, why
the highest daily price is used for the
+/¥7.5% band, and if the index prices
are negative if Western is prepared to
credit the customer for the deviation.
Response: Western disagrees with the
comments received that it should utilize
individual indexes or a weighted index
based upon its eastern and western
interconnection control areas based
upon the argument that its transmission
customers may only be participating in
one market (east or west). Western
operates its combined system as one
system, and utilizes both east and west
resources to provide for ancillary
services across its entire system under
its tariff. Therefore, if a transmission
customer creates an imbalance due to its
operations in the east market, Western
may need to utilize resources from its
west side to provide for the imbalance
service required by the transmission
customer. Western does, however, agree
with the suggestion that Western utilize
hourly pricing instead of the highest
daily price as a method to allocate costs
in the +/¥ 7.5% band. Western also
clarifies that it will limit the selected
index to a minimum of zero in the case
where index prices may become
negative and does not expect that will
be an issue based upon its proposal to
utilize the higher of the eastern and
western interconnection price index.
7. Comment: Western received two
comments expressing concern for the
method of measuring the energy taken
on an hourly basis and how
supplemental or co-supplier energy
imbalance would be determined for
customers with a fixed Contract Rate of
Delivery and supplemental supplier(s).
Response: Western thanks commenter
for addressing these issues. Western
recognizes that these issues will need to
be resolved prior to charging for Energy
or Generator Imbalance Service.
Consequently, Western will delay
charging until such time as these issues
can be resolved. Western will
collaborate closely with its customers
affected by these issues and resolve
them. These issues are billing related
rather than rate related; therefore, the
rate will become effective as scheduled.
However, Western will not implement
these schedules until the billing issues
are resolved. Upon completing
arrangements with its customers
concerning the method(s) to be used in
calculating energy and generator
imbalance charges, Western will post
notice on its OASIS Web site providing
30 days notice to customers prior to
initiating charging/billing for Energy or
Generator Imbalance Service. Similar to
the process for allowing review of
annual revenue data submittals
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discussed below, Western is committed
to providing customers with a forum to
address implementation issues related
to Energy and Generator Imbalance
schedules that are outside the rate
schedules themselves.
8. Comment: A comment was received
by Western questioning the point in
Energy Imbalance and Generator
Imbalance Service where charges were
rounded and if the rounding was done
for each hour.
Response: Western will round energy
and generator imbalance calculations to
the nearest cent on an hourly basis with
the exception of the first deviation tier.
In the first deviation band, deviations
will be netted and settled financially at
the end of the month.
9. Comment: A comment was received
by Western expressing concern for the
billing process for energy and generator
imbalance calculations.
Response: Western anticipates billing
procedures for Energy Imbalance and
Generator Imbalance will be similar to
billing for any other service and that
customer bills will provide sufficient
data to verify charges. Western’s policy
for correction of billing errors will apply
for these charges as it does for all other
services.
10. Comment: Western received a
comment expressing concern that
implementing Generator Imbalance
Service would further deter
development of renewable generation
such as wind fueled generation.
Response: This comment is not
directly related to the proposed rate
action and is outside the scope of this
rate process.
11. Comment: Western received oral
and written comments requesting
Western delay implementation of Rate
Schedule UGP–AS2 pending provision
of additional information concerning
compensation of generators requested
by Western to operate outside the
identified bandwidth in providing
Reactive Supply and Voltage Support.
Response: Western disagrees that it
should delay the implementation of
Rate Schedule UGP–AS2 pending
providing additional information
concerning its procedures for
compensation of generators for
providing reactive support outside the
bandwidth identified in its Large and
Small Generator Interconnection
Procedures (LGIP/SGIP) and
Agreements (LGIA/SGIA). Western has
included such provisions and currently
has a requirement to provide
compensation for requesting an
interconnection customer to operate its
generation outside the standard power
factor bandwidth indentified in its tariff.
For example, Western will provide
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compensation to a large generator as
outlined in its LGIA Sections 9.6.3 and
11.6. Western will request the
interconnection customer to identify its
appropriate costs or rate schedule for it
providing reactive support to the
transmission provider and will
compensate the interconnection
customer based upon the agreed upon
methodology between the parties.
12. Comment: Western received oral
and written comments recommending
that the IS accept any annual
transmission revenue requirement
template specifically approved by the
FERC for an individual party without
approval via a public process.
Response: Western’s UGPR agrees
with the commenter that a party should
be able to utilize a FERC approved
template for a particular party, provided
that the following conditions are met:
(1) the template addresses all the
transmission facilities owned by the
party; (2) the template includes a
separate allocation for IS qualifying
facilities; and (3) it is the latest FERC
approved template for this party.
13. Comment: A comment received by
Western expressed understanding for
the implementation of the forward
looking rates with annual true-up in an
era of tremendous transmission
expansions.
Response: Western appreciates
commenter’s understanding of
Western’s need and efforts to match cost
recovery to cost incurrence through the
forward looking rate with annual trueup.
14. Comment: Western received a
comment suggesting a forum for
customers to provide comments and ask
questions concerning rate adjustments
needed for prior year over/under
collections.
Response: Western recognizes that an
annual customer meeting or forum to
discuss application of the true-up of the
revenue requirement(s) based on actual,
audited financial data is necessary and
beneficial. Accordingly, Western has
committed to making data for annual
rate recalculations and true-ups of prior
year over/under collections available to
customers on or about September 1 of
each year and to providing a forum
during which customers can ask
questions concerning the data utilized
in rate recalculations and the annual
revenue requirement true-up calculation
prior to October 31.
15. Comment: Western received a
comment concerning revenue
requirement review for reasonableness
and providing answers to customer
questions.
Response: Western agrees with
commenter concerning the need to
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68831
review revenue requirements for
reasonableness. Western has committed
to making data for annual rate
recalculations and true-ups of prior year
over/under collections available to
customers on or about September 1 of
each year and to providing a forum
during which customers can ask
questions concerning the data utilized
in rate recalculations and the annual
revenue requirement true-up calculation
prior to October 31.
16. Comment: A comment was
received that Western should add a
statement to its rate schedules that use
of a standard template or formula does
not remove the obligation of
transmission owners to substantiate
accuracy of financial data with audited
financial statements, FERC Form 1, or
other publically available information.
Response: Western agrees that
accurate financial data is necessary and
will require entities submitting financial
data in support of revenue requirements
or facility credits to provide appropriate
substantiation.
17. Comment: Western received a
comment advocating that an interest
rate apply to any over collection of
funds.
Response: Every effort will be made to
accurately forecast costs and load in an
effort to minimize any over or under
collection of annual revenue
requirements. Western intends to
closely monitor collections and will
make or insist upon appropriate revenue
requirement adjustments. Western does
not believe assessing interest on over
collections while not assessing interest
on under collections to be equitable.
18. Comment: Western received a
comment that Western and other IS
owners should continue to provide
detailed facility information on existing
and new facilities included in
transmission rates similar to what is
done today.
Response: Western agrees with this
comment and will continue to provide
facility information.
Penalty Rate for Unreserved Use of
Transmission Service
Unreserved Use of Transmission
Service is provided when a
Transmission Customer uses
transmission service that it has not
reserved or uses transmission service in
excess of its reserved capacity. A
Transmission Customer that has not
secured reserved capacity or exceeds its
firm or non-firm reserved capacity at
any point of receipt or any point of
delivery will be assessed penalties for
Unreserved Use of Transmission Service
under new Rate Schedule UGP–TSP1.
Western has not concluded
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modifications to its OATT required as a
result of FERC Order 890. Consequently,
charges for unreserved use will not be
implemented until such time as
Western’s revised OATT is effective.
However, by establishing its Penalty
Rate for Unreserved Use of
Transmission Service in this process,
Western will avoid the need and cost for
a separate public process to develop this
rate at a later date. Western will provide
written notification to its Transmission
Customers prior to implementing the
penalty rate for unreserved use and will
also post a notification on its OASIS
web site indicating the implementation
of Transmission Service Penalty Rate for
Unreserved Use.
The penalty charge for a Transmission
Customer that engages in unreserved
use is 200 percent of Western’s
approved transmission service rate for
point-to-point transmission service
assessed as follows: the Unreserved Use
Penalty for a single hour of unreserved
use will be based upon the rate for daily
firm point-to-point service. The
Unreserved Use Penalty for more than
one assessment for a given duration
(e.g., daily) will increase to the next
longest duration (e.g., weekly). The
Unreserved Use Penalty charge for
multiple instances of unreserved use
(for example, more than 1 hour) within
a day will be based on the rate for daily
firm point-to-point service. The penalty
charge for multiple instances of
unreserved use isolated to 1 calendar
week would result in a penalty based on
the charge for weekly firm point-topoint service. The penalty charge for
multiple instances of unreserved use
during more than 1 week during a
calendar month is based on the charge
for monthly firm point-to-point service.
A Transmission Customer that
exceeds its firm reserved capacity at any
Point of Receipt or Point of Delivery or
an Eligible Customer that uses
Transmission Service at a Point of
Receipt or Point of Delivery that it has
not reserved is required to pay for all
Ancillary Services identified in
Western’s OATT that were provided by
Western and associated with the
unreserved service on the IS system.
The Transmission Customer or Eligible
Customer will pay for Ancillary
Services based on the amount of
transmission service it used but did not
reserve. Unreserved Use Penalties
collected over and above the base pointto-point transmission service charge
will be credited against the IS Annual
Transmission Revenue Requirement
(ATRR).
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Basis for Rate Development
The provisional penalty rate provides
payment for transmission and ancillary
services at the current rates for these
services thereby contributing to the
revenues required to pay all annual
costs, including interest, and repay
investments within the allowable
periods. The penalty portion of the rate
will be returned to customers via credits
to future transmission revenue
requirement.
Comments
The comments and responses below
regarding the Transmission Service
Penalty Rate for Unreserved Use rate are
paraphrased for brevity when not
affecting the meaning of the
statement(s). Direct quotes from oral or
written comments are used for
clarification when necessary.
1. Comment: Western received a
comment that Western should provide
details to several issues associated with
the determination of unreserved use and
billing for unreserved use. Specifically,
commenter states that while Western
provides a general description of what
it will consider unreserved use, it does
not furnish information about the
methods that will be utilized to
determine that unreserved use has
occurred and that Western should
explain how it will identify that the
unreserved use is a result of exceeding
reserved capacity rather than loop flows
due to system conditions. Commenter
continues to express the desire to have
the specific methods for determining
unreserved use identified ahead of time
so that all parties know what to expect
and can plan accordingly. Commenter
further asks that Western develop a
method and make that method for
determining which flows are from
insufficient capacity and which are loop
flows publicly available.
Response: Western disagrees that it is
necessary to identify in advance all
specific methods for determining
unreserved use but intends to provide
such detailed information to any party
that it proposes to charge under this
rate. Western has indicated that it does
not charge for loop flow but does expect
its neighboring transmission providers
to have adequate transmission capacity
on its own system to provide the
transmission service that it provides
without improperly using Western’s
transmission system. The determination
of adequate transmission capability
likely needs to be determined on a caseby-case basis. To the extent that a party
disagrees with Western’s specific
methodologies to base its unreserved
use charge, such party has recourses
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outlined in Western’s tariff to dispute
such charge, including ultimately
seeking feedback from the Federal
Energy Regulatory Commission.
2. Comment: Western received a
comment that Western should explain
how the method of determining whether
insufficient capacity exists is consistent
with the Congestion Management
Process as Western takes Interconnected
Operations and Congestion Management
Service under Part II of Module F of the
Midwest ISO Tariff. Commenter
requests Western commit that any
process it develops will not be in
conflict with the Congestion
Management Process.
Response: Western has previously
filed comments with the Commission
noting that its charge for transmission
service based upon a party not having
sufficient transmission capacity to meet
its obligations without utilizing
Western’s transmission system is not in
conflict with its Seams agreement with
the Midwest ISO. Western’s Seams
agreement with the Midwest ISO does
not provide for uncompensated use of
each other’s system and specifically
notes that each party to that agreement
will respect their own transmission
capability in providing transmission
service under their separate tariffs.
Western’s current implementation and
proposed changes to its implementation
of unreserved use charges will be
consistent with any provisions of Seams
agreements that it enters into with its
neighboring interconnected
transmission providers, including the
Midwest ISO.
3. Comment: Western received a
comment that the Federal Register
notice lacks detail regarding who will be
billed for unreserved use penalty
charges and asks if Western intends to
send bills monthly and which entities
will be billed.
Response: Western will bill
unreserved use (including the newly
proposed penalty charge) to the party
that utilizes Western transmission
system without making proper
arrangements for the transmission
service that it is taking. Western bills on
a monthly basis; however, to the extent
that Western determines that an entity
is improperly taking transmission
service without reserving such, Western
may contact such entity prior to the
normal monthly billing cycle to notify
such entity that it intends to send that
party a bill for service. The appropriate
party to be billed will be determined on
a case-by-case basis.
4. Comment: Western received a
comment requesting that commenter be
informed of the FERC actions
concerning the unreserved use rate.
E:\FR\FM\29DEN1.SGM
29DEN1
Federal Register / Vol. 74, No. 248 / Tuesday, December 29, 2009 / Notices
Response: Western will post FERC
actions on its web sites at https://
www.wapa.gov/ugp/ and https://
www.oatioasis.com/wapa/.
effect, together with supporting
documents, will be submitted to FERC
for confirmation and final approval.
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 Plans Regional Office, 2900 4th
Avenue North, Billings, Montana.
Ratemaking Procedure Requirements
Environmental Compliance
In compliance with the National
Environmental Policy Act (NEPA) of
1969 (42 U.S.C. 4321–4347); 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.
In view of the foregoing and under the
authority delegated to me, I confirm and
approve on an interim basis, effective
January 1, 2010, rates for the IS
Transmission and Ancillary Services
under Rate Schedules UGP–NT1, UGP–
FPT1, UGP–NFPT1, UGP–AS1, UGP–
AS2, UGP–AS3, UGP–AS4, UGP–AS5,
UGP–AS6, UGP–AS7 and UGP–TSP1.
The rate schedules shall remain in effect
on an interim basis, pending FERC’s
confirmation and approval of them or
substitute rates on a final basis through
December 31, 2014.
Daniel B. Poneman
Deputy Secretary
Rate Schedule UGP–NT1
January 1, 2010
Supersedes 2005 Schedule
United States Department of Energy
Western Area Power Administration
Upper Great Plains Region Integrated
System
January 1, 2010, through December
31, 2014, or until superseded by another
rate schedule.
Formula Rate
Rate Schedule UGP–FPT1
January 1, 2010
Supersedes 2005 Schedule
United States Department of Energy
Western Area Power Administration
Upper Great Plains Region Integrated
System
Long-Term Firm and Short-Term Firm
Point-To-Point Transmission Service
Effective
January 1, 2010, through December
31, 2014, or until superseded by another
rate schedule.
Applicable
The Transmission Customer shall
compensate the Upper Great Plains
Region (UGPR) each month for Reserved
19:02 Dec 28, 2009
Jkt 220001
PO 00000
Frm 00058
Fmt 4703
Sfmt 4703
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.
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. UGPR shall charge
the Transmission Customer under the
rate then in effect.
E:\FR\FM\29DEN1.SGM
29DEN1
EN29DE09.005
Transmission Customer’s Load-Ratio Share × Annual Revenue Requirement for IS Transmission Service
12 months
2
A recalculated annual revenue
requirement will go into effect every
January 1 based on updated financial
data. UGPR will notify the Transmission
Customer annually of the recalculated
annual revenue requirement on or
before September 1.
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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.
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
developed under applicable Federal
laws, regulations, and policies and
made part of the applicable
Transmission Customer’s Service
Agreement. UGPR shall charge the
Transmission Customer under the
revenue requirement then in effect.
Annual Transmission Revenue
Requirement for Network Integration
Transmission Service
Annual Revenue Requirement
VerDate Nov<24>2008
Applicable
Effective
Submission to the Federal Energy
Regulatory Commission
The provisional rates herein
confirmed, approved, and placed into
Monthly Charge =
Order
68833
68834
Federal Register / Vol. 74, No. 248 / Tuesday, December 29, 2009 / Notices
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
Firm Point-to-Point Transmission Rate =
Rate Schedule UGP–NFPT1
January 1, 2010
Supersedes 2005 Schedule
United States Department of Energy
Western Area Power Administration
Upper Great Plains Region Integrated
System
Non-Firm Point-To-Point Transmission
Service
Effective
January 1, 2010, through December
31, 2014, or until superseded by another
rate schedule.
Applicable
The Transmission Customer shall
compensate Upper Great Plains Region
Annual IS Transmission Service Revenue Requirement
s
IS Transmission System Total Load
t
(UGPR) for Non-Firm Point-to-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.
UGPR may modify the rate for NonFirm 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. UGPR shall charge the
Transmission Customer under the rate
then in effect.
follows: (1) Any offer of a discount
made by UGPR must be announced to
all eligible Transmission Customers
solely by posting on the Open Access
Same-Time Information System
(OASIS); (2) any Transmission
Customer-initiated requests for
discounts, including requests for use by
one’s wholesale merchant or an
affiliate’s use, must occur solely by
posting on the OASIS; and (3) once a
discount is negotiated, details must be
immediately posted on the OASIS. For
any discount agreed upon for service on
a path, from Point(s) of Receipt to
Point(s) of Delivery, UGPR must offer
the same discounted transmission
service rate for the same time period to
all eligible Transmission Customers on
all unconstrained transmission paths
that go to the same point(s) of delivery
on the Transmission System.
Discounts
Three principal requirements apply to
discounts for transmission service as
Formula Rate
Maximum Non-Firm Point-to-Point =
Firm Point-to-Point Transmission Rate × 1000 Mills/$
s
730 hours/month
Rate
Rate Schedule UGP–AS1
A recalculated rate will go into effect
every January 1 based on the above
formula and updated financial and load
data. UGPR will notify the Transmission
Customer annually of the recalculated
rate on or before September 1.
January 1, 2010
Supersedes 2005 Schedule
United States Department of Energy
Western Area Power Administration
Upper Great Plains Region Integrated
System
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Scheduling, System Control, and
Dispatch Service
Effective
January 1, 2010, through December
31, 2014, or until superseded by another
rate schedule.
VerDate Nov<24>2008
19:02 Dec 28, 2009
Jkt 220001
Formula Rate
PO 00000
Frm 00059
Fmt 4703
Sfmt 4703
Applicable
This service is required to schedule
the movement of power through, out of,
within, or into the Western Area Upper
Great Plains Balancing Authorities
(WAUE and WAUW). 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 IS non-Transmission
Customers. Western will accept any
reasonable number of schedule changes
over the course of the day without any
additional charge.
E:\FR\FM\29DEN1.SGM
29DEN1
EN29DE09.007
A recalculated rate will go into effect
every January 1 based on the above
formula and updated financial and load
data. UGPR will notify the Transmission
Customer annually of the recalculated
rate on or before September 1.
Point(s) of Delivery, UGPR must offer
the same discounted transmission
service rate for the same time period to
all eligible Transmission Customers on
all unconstrained transmission paths
that go to the same point(s) of delivery
on the Transmission System.
EN29DE09.006
Discounts
Three principal requirements apply to
discounts for transmission service as
follows: (1) Any offer of a discount
made by UGPR must be announced to
all eligible Transmission Customers
solely by posting on the Open Access
Same-Time Information System
(OASIS); (2) any Transmission
Federal Register / Vol. 74, No. 248 / Tuesday, December 29, 2009 / Notices
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
Applicable
A recalculated rate will go into effect
every January 1 based on the above
formula and data. UGPR will notify the
customer annually of the recalculated
rate on or before September 1.
To maintain transmission voltages on
all transmission facilities within
acceptable limits, generation facilities
under the control of the Western Area
Upper Great Plains balancing authorities
(WAUE and WAUW) 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
Western.
The Transmission Customer must
purchase this service from the
Transmission Provider. The charges for
January 1, 2010
Supersedes 2005 Schedule
United States Department of Energy
Western Area Power Administration
Upper Great Plains Region Integrated
System
Reactive Supply and Voltage Control
From Generation Sources Service
Effective
January 1, 2010, through December
31, 2014, or until superseded by another
rate schedule.
Reactive Service Rate =
Applicable
A recalculated rate will go into effect
every January 1 based on the above
formula and updated financial and load
data. UGPR will notify the Transmission
Customer annually of the recalculated
rate on or before September 1.
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 authorities (WAUE and
WAUW) operator. The Transmission
Customer must either purchase this
service from Western or make
alternative comparable arrangements to
satisfy its Regulation obligation. The
charges for Regulation are outlined
January 1, 2010
Supersedes 2005 Schedule
United States Department of Energy
Western Area Power Administration
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Upper Great Plains Region Integrated
System
Regulation And Frequency Response
Service
Effective
January 1, 2010, through December
31, 2014, or until superseded by another
rate schedule.
Jkt 220001
PO 00000
Formula Rate
Annual Revenue Requirement for VAR Support
Load Requiring VAR Support
Rate
Rate Schedule UGP–AS3
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 to applicable
Federal laws, regulations, and policies
and made part of the applicable
Transmission Customer’s Service
Agreement. Upper Great Plains Region
(UGPR) shall charge the Transmission
Customer under the rate then in effect.
Any waiver of this charge or any
crediting arrangements for Reactive
Service must be documented in the
Transmission Customer’s Service
Agreement.
Frm 00060
Fmt 4703
Sfmt 4703
below. The amount of Regulation will
be set forth in the applicable
Transmission Customer’s Service
Agreement.
Western supports the installation of
renewable sources of energy but
recognizes that certain operational
constraints exist in managing the
significant fluctuations that are a normal
part of their operation. When Western
purchases power resources to provide
Regulation and Frequency Response
Service to intermittent renewable
generation resources serving load within
Western’s Control Areas, costs for these
regulation resources will become part of
Western’s Regulation and Frequency
Response Service charges. However,
Western has marketed the maximum
practical amount of power from each of
its projects leaving little or no flexibility
for provision of additional power
services. Consequently, Western will
not regulate for the difference between
E:\FR\FM\29DEN1.SGM
29DEN1
EN29DE09.009
Rate Schedule UGP–AS2
19:02 Dec 28, 2009
Formula Rate
Annual Revenue Requirement for Scheduling, System Control, and Dispatch Service
d
Number of Daily Tags per Year
l
Rate
VerDate Nov<24>2008
Upper Great Plains Region (UGPR)
shall charge the non-Transmission
Customer under the rate then in effect.
EN29DE09.008
Rate per Tag per Day =
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.
68835
68836
Federal Register / Vol. 74, No. 248 / Tuesday, December 29, 2009 / Notices
respond to transmission security
constraints.
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
Regulation Rate =
Rate
A recalculated rate will go into effect
every January 1 based on the above
formula and updated financial and load
data. UGPR will notify the Transmission
Customer annually of the recalculated
rate on or before September 1.
If resources are not available from a
Western resource, the UGPR will offer to
purchase the Regulation and pass
through the costs, plus an amount for
administration, to the Transmission
Customer.
Rate Schedule UGP–AS4
January 1, 2010
Supersedes 2005 Schedule
United States Department of Energy
Western Area Power Administration
Upper Great Plains Region Integrated
System
Energy Imbalance Service
Effective
January 1, 2010, through December
31, 2014, or until superseded by another
rate schedule.
pwalker on DSK8KYBLC1PROD with NOTICES
Applicable
Energy Imbalance Service is provided
when a difference occurs between
scheduled and actual delivery of energy
to a load located within Western’s
Control Areas over a single hour. The
Transmission Customer must either
obtain this service from Western or
make alternative comparable
arrangements to satisfy its Energy
Imbalance Service obligation.
Western may charge a Transmission
Customer a penalty for either hourly
energy imbalances under this Schedule
UG–AS4 or hourly generator imbalances
under Rate Schedule UGP–AS7 for
imbalances occurring during the same
VerDate Nov<24>2008
19:02 Dec 28, 2009
Jkt 220001
Formula Rate
Annual Revenue Requirement for Regulation
n
Load in the Control Area Requiring Regulation
hour, but not both, unless the
imbalances aggravate rather than offset
each other.
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 Energy Imbalance
Service may be modified upon written
notice to the Transmission Customer.
Any change to the charges for Energy
Imbalance 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.
Upper Great Plains Region (UGPR) shall
charge the Transmission Customer
under the rate then in effect.
Formula Rate
For deviations within +/¥ 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 Transmission
Customer’s scheduled transaction(s)
will be netted on a monthly basis and
settled financially, at the end of the
month, at 100 percent of the average
incremental cost.
Deviations greater than +/¥ 1.5
percent up to 7.5 percent (or greater
than 2 MW up to 10 MW) of the
scheduled transaction to be applied
hourly to any energy imbalance that
occurs as a result of Transmission
Customer’s scheduled transaction(s)
will be settled financially, at the end of
each month. When energy taken in a
schedule hour is greater than the energy
scheduled, the charge is 110 percent of
incremental cost. When energy taken is
less than the scheduled amount, the
credit is 90 percent of the incremental
cost.
PO 00000
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.
Frm 00061
Fmt 4703
Sfmt 4703
Deviations greater than +/¥ 7.5
percent (or 10 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) will be settled
at 125 percent of Western’s incremental
cost when energy taken in a schedule
hour is greater than the energy
scheduled or 75 percent of Western’s
incremental cost when energy taken by
a Transmission Customer is less than
the scheduled amount.
Western’s incremental cost will be
based upon a representative hourly
energy index or combination of indexes.
The index to be used will be posted on
Western’s OASIS https://
www.oatioasis.com/wapa/ at
least 30 days prior to use for
determining the Western incremental
cost and will not be changed more often
than once per year unless Western
determines that the existing index is no
longer a reliable price index.
Rate
The pricing and penalty for deviations
in the above deviation bandwidths is as
specified above.
Rate Schedule UGP–AS5
January 1, 2010
Supersedes 2005 Schedule
United States Department of Energy
Western Area Power Administration
Upper Great Plains Region Integrated
System
Operating Reserve—Spinning Reserve
Service
Effective
January 1, 2010, through December
31, 2014, or until superseded by another
rate schedule.
E:\FR\FM\29DEN1.SGM
29DEN1
EN29DE09.010
the output of an intermittent generator
located within Western’s Control Area
and a delivery schedule from that
generator serving load located outside of
Western’s Control Area. Intermittent
generators serving load outside
Western’s Control Area will be required
to pseudo-tie or dynamically schedule
their generation to another Control Area.
An intermittent resource, for the
limited purpose of these Rate
Schedules, is an electric generator that
is not dispatchable and cannot store its
fuel source and, therefore, cannot
respond to changes in demand or
Federal Register / Vol. 74, No. 248 / Tuesday, December 29, 2009 / Notices
Reserves Rate =
Rate Schedule UGP–AS6
A recalculated rate will go into effect
every January 1 based on the above
formula and updated financial and load
data. UGPR will notify the Transmission
Customer annually of the recalculated
rate on or before September 1.
If resources are not available from a
Western resource, 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, UGPR will
assess a charge for energy used at 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.
January 1, 2010
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Rate
A recalculated rate will go into effect
every January 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 September
1.
If resources are not available from a
Western resource, UGPR will offer to
purchase the Reserves and pass through
the costs, plus an amount for
administration, to the Transmission
Customer.
In the event Reserves are called upon
for Emergency Energy, UGPR will assess
VerDate Nov<24>2008
19:02 Dec 28, 2009
Jkt 220001
Supersedes 2005 Schedule
United States Department of Energy
Western Area Power Administration
Upper Great Plains Region Integrated
System
Operating Reserve—Supplemental
Reserve Service
Effective
January 1, 2010, through December
31, 2014, 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 Western 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. Upper Great Plains Region
(UGPR) shall charge the Transmission
Customer under the rate then in effect.
Formula Rate
Annual Revenue Requirement for Reserves
Load Requiring Reserves
d
a charge for energy used at 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.
PO 00000
Formula Rate
Annual Revenue Requirement for Reserves
Load Requiring Reserves
d
Rate
Reserves Rate =
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. Upper Great Plains Region
(UGPR) shall charge the Transmission
Customer under the rate then in effect.
Rate Schedule UGP–AS7
January 1, 2010
United States Department of Energy
Western Area Power Administration
Upper Great Plains Region Integrated
System
Generator Imbalance Service
Effective
January 1, 2010, through December
31, 2014, or until superseded by another
rate schedule. Western will not charge
for Generator Imbalance Service until
Western’s OATT is revised to provide
for Generator Imbalance Service.
Frm 00062
Fmt 4703
Sfmt 4703
E:\FR\FM\29DEN1.SGM
29DEN1
EN29DE09.012
Spinning Reserve Service (Reserves)
is needed to serve load immediately in
the event of a system contingency.
Reserves may be provided by generating
units that are on-line and loaded at less
than maximum output. The
Transmission Customer must either
purchase this service from Western 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
EN29DE09.011
Applicable
68837
68838
Federal Register / Vol. 74, No. 248 / Tuesday, December 29, 2009 / Notices
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Applicable
Generator Imbalance Service is
provided when a difference occurs
between the output of a generator
located within the Transmission
Provider’s Control Area and a delivery
schedule from that generator to (1)
another Control Area or (2) a load
within the Transmission Provider’s
Control Area over a single hour.
Western will offer this service, to the
extent that it is feasible to do so from
its own resources or from resources
available to it, when Transmission
Service is used to deliver energy from a
generator located within its Control
Area. The Transmission Customer must
either purchase this service from
Western or make alternative comparable
arrangements, which may include use of
non-generation resources capable of
providing this service, to satisfy its
Generator Imbalance Service obligation.
Western may charge a Transmission
Customer a penalty for either hourly
generator imbalances under this
Schedule UG–AS7 or hourly energy
imbalances under Rate Schedule UGP–
AS4 for imbalances occurring during the
same hour, but not both, unless the
imbalances aggravate rather than offset
each other. Intermittent generators
serving load outside Western’s Control
Area will be required to pseudo-tie or
dynamically schedule their generation
to another Control Area.
An intermittent resource, for the
limited purpose of these Rate
Schedules, is an electric generator that
is not dispatchable and cannot store its
fuel source and, therefore, cannot
respond to changes in demand or
respond to transmission security
constraints.
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 Generator Imbalance
Service may be modified upon written
notice to the Transmission Customer.
Any change to the charges for Generator
Imbalance 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.
Upper Great Plains Region (UGPR) shall
charge the Transmission Customer
under the rate then in effect.
Formula Rate
Western bases the rate on deviation
bands as follows: deviations within +/¥
1.5 percent (with a minimum of 2 MW)
of the scheduled transaction to be
applied hourly to any generator
VerDate Nov<24>2008
19:02 Dec 28, 2009
Jkt 220001
imbalance that occurs as a result of
Transmission Customer’s scheduled
transaction(s) will be netted on a
monthly basis and settled financially, at
the end of the month, at 100 percent of
the average incremental cost. Deviations
greater than +/¥ 1.5 percent up to 7.5
percent (or greater than 2 MW up to 10
MW) of the scheduled transaction to be
applied hourly to any generator
imbalance that occurs as a result of
Transmission Customer’s scheduled
transaction(s) will be settled financially,
at the end of each month. When energy
delivered in a schedule hour from the
generation resource is less than the
energy scheduled, the charge is 110
percent of incremental cost. When
energy delivered from the generation
resource is greater than the scheduled
amount, the credit is 90 percent of the
incremental cost. Deviations greater
than +/¥ 7.5 percent (or 10 MW) of the
scheduled transaction to be applied
hourly to any generator imbalance that
occurs as a result of the Transmission
Customer’s scheduled transaction(s)
will be settled at 125 percent of
Western’s highest incremental cost for
the day when energy delivered in a
schedule hour is less than the energy
scheduled or 75 percent of Western’s
lowest daily incremental cost when
energy delivered from the generation
resource is greater than the scheduled
amount. As an exception, an
intermittent resource will be exempt
from this deviation band and will pay
the deviation band charges for all
deviations greater than the larger of 1.5
percent or 2 MW. An intermittent
resource, for the limited purpose of
these schedules, is an electric generator
that is not dispatchable and cannot store
its fuel source and therefore cannot
respond to transmission security
constraints.
Deviations from scheduled
transactions responding to directives by
the Transmission Provider, a balancing
authority, or a reliability coordinator
shall not be subject to the deviation
bands identified above and, instead,
shall be settled financially, at the end of
the month, at 100 percent of
incremental cost. Such directives may
include instructions to correct
frequency decay, respond to a reserve
sharing event, or change output to
relieve congestion.
Western’s incremental cost will be
based upon a representative hourly
energy index or combination of indexes.
The index to be used will be posted on
Western’s OASIS https://
www.oatioasis.com/wapa/ at
least 30 days prior to use for
determining the Western incremental
cost and will not be changed more often
PO 00000
Frm 00063
Fmt 4703
Sfmt 4703
than once per year unless Western
determines that the existing index is no
longer a reliable price index.
Rate
The pricing and penalty for deviations
in the above deviation bandwidths is as
specified above.
Rate Schedule UGP–TSP1
January 1, 2010
United States Department of Energy
Western Area Power Administration
Upper Great Plains Region Integrated
System
Transmission Service Penalty Rate for
Unreserved Use
Effective
January 1, 2010, through December
31, 2014, or until superseded by another
rate schedule.
Applicable
The Transmission Customer shall
compensate the Upper Great Plains
Region (UGPR) each month for
Unreserved Use of Transmission Service
under the applicable Transmission
Service rates as outlined below. The
formula for the transmission service rate
used to calculate the charges for this
service under this schedule was
developed and may be modified under
applicable Federal laws, regulations,
and policies.
UGPR may modify the charges for
Unreserved Use of Transmission Service
upon written notice to the Transmission
Customer. Any change to the charges to
the Transmission Customer for
Unreserved Use of 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. UGPR shall charge
the Transmission Customer under the
applicable transmission service rate
then in effect.
Penalty Rate
Unreserved Use of Transmission
Service is provided when a
Transmission Customer uses
transmission service that it has not
reserved or uses transmission service in
excess of its reserved capacity. A
Transmission Customer that has not
secured reserved capacity or exceeds its
firm or non-firm reserved capacity at
any point of receipt or any point of
delivery will be assessed Unreserved
Use Penalties under new Rate Schedule
UGP–TSP1. Charges for Unreserved Use
will be implemented when Western’s
revised OATT becomes effective.
E:\FR\FM\29DEN1.SGM
29DEN1
Federal Register / Vol. 74, No. 248 / Tuesday, December 29, 2009 / Notices
Western will provide written
notification to its Transmission
Customers prior to implementing the
Penalty Rate for Unreserved Use and
will also post a notification on its
OASIS web site indicating the
implementation of Transmission Service
Penalty Rate for Unreserved Use.
The penalty charge for a Transmission
Customer that engages in Unreserved
Use is 200 percent of Western’s
approved transmission service rate for
point-to-point transmission service
assessed as follows: The Unreserved Use
Penalty for a single hour of unreserved
use will be based upon the rate for daily
firm point-to-point service. The
Unreserved Use Penalty for more than
one assessment for a given duration
(e.g., daily) will increase to the next
longest duration (e.g., weekly). The
Unreserved Use Penalty charge for
multiple instances of unreserved use
(for example, more than 1 hour) within
a day will be based on the rate for daily
firm point-to-point service. The penalty
charge for multiple instances of
unreserved use isolated to 1 calendar
week would result in a penalty based on
the charge for weekly firm point-topoint service. The penalty charge for
multiple instances of unreserved use
during more than 1 week during a
calendar month is based on the charge
for monthly firm point-to-point service.
A Transmission Customer that
exceeds its firm reserved capacity at any
Point of Receipt or Point of Delivery or
an Eligible Customer that uses
Transmission Service at a Point of
Receipt or Point of Delivery that it has
not reserved is required to pay for all
Ancillary Services identified in
Western’s OATT that were provided by
Western and associated with the
unreserved service on the IS system.
The Transmission Customer or Eligible
Customer will pay for Ancillary
Services based on the amount of
transmission service it used, but did not
reserve.
pwalker on DSK8KYBLC1PROD with NOTICES
Rate
The rate for Unreserved Use of
Transmission Service is 200 percent of
the approved transmission service rate
for point-to-point transmission service
assessed as described above.
[FR Doc. E9–30827 Filed 12–28–09; 8:45 am]
BILLING CODE 6450–01–P
Regulation at (202) 502–8525 for
technical information, or Anthony
Barracchini, Office of the Executive
Director, (202) 502–8920 for software
information, or send an e-mail to
ETariff@ferc.gov.
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
[Docket No. RM01–5–000]
Electronic Tariff Filings; Notice of
Revised Implementation Guide for
Electronic Filing
December 18, 2009.
19:02 Dec 28, 2009
Jkt 220001
PO 00000
Frm 00064
Fmt 4703
Kimberly D. Bose,
Secretary.
[FR Doc. E9–30808 Filed 12–28–09; 8:45 am]
BILLING CODE 6717–01–P
In Order No. 714,1 the Commission
adopted regulations requiring tariff and
tariff related filings to be made
electronically starting April 1, 2010.
Instructions on how to assemble an
electronic filing are provided in
Implementation Guide for Electronic
Filing of Parts 35, 154, 284, 300, and
341 Tariff Filings, located at https://
www.ferc.gov/docs-filing/etariff.asp.
Take notice that the Implementation
Guide has been revised as follows
(changes are marked by redline in the
document):
1. The date to be used by filers that
are not proposing a specific effective
date has been changed from 12/31/9999
to 12/31/9998 due to Commission
software constraints.
2. The Implementation Guide as been
revised to clarify the usage of the
‘‘Withdraw Type of Filing Category’’
and the ‘‘Withdraw Record Change
Type’’.
a. The description of the ‘‘Withdraw
Type of Filing’’ category has been
modified to reflect §§ 35.17(a) and
154.205(a) of the Commission’s
regulations, as adopted in Order No.
714. The revision clarifies that the Type
of Filing category of ‘‘Withdraw’’ is the
equivalent of a request to withdraw the
complete associated tariff filing, not
individual components of thereof.
b. The description of the ‘‘Withdraw
Record Change Type’’ has been
modified to reflect the ability to
withdraw a specific tariff record without
withdrawing the entire filing.
3. Discussion of the Company
Identifier and password have been
coordinated with the October 23, 2009
Notice regarding Company Registration
and related Instructions for Company
Registration. These instructions are
located at https://www.ferc.gov/docsfiling/company-reg.asp. The revisions
reflect the October 23, 2009 Notice’s
implementation of Company Identifiers
and passwords, and the treatment of the
Company Identifiers as public
information.
For more information, please contact
Keith Pierce, Office of Energy Market
1 Electronic Tariff Filings, Order No. 714, 73 FR
57,515 (Oct. 3, 2008), 124 FERC ¶ 61,270, FERC
Stats. & Regs [Regulations Preambles] ¶ 31,276
(2008) (Sept. 19, 2008).
VerDate Nov<24>2008
68839
Sfmt 4703
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
Notice of FERC Staff Attendance at
Southwest Power Pool Regional State
Committee Meeting and Southwest
Power Pool Board of Directors Meeting
December 22, 2009.
The Federal Energy Regulatory
Commission hereby gives notice that
members of its staff may attend the
meetings of the Southwest Power Pool
(SPP) Regional State Committee, and
SPP Board of Directors, as noted below.
Their attendance is part of the
Commission’s ongoing outreach efforts.
SPP Regional State Committee Meeting
January 25, 2010 (1 p.m.–5 p.m. CST),
Sheraton New Orleans Hotel, 500
Canal Street, New Orleans, LA 70130,
504–525–2500.
SPP Board of Directors Meeting
January 26, 2010 (8 a.m.–3 p.m. CST),
Sheraton New Orleans Hotel, 500 Canal
Street, New Orleans, LA 70130, 504–
525–2500.
The discussions may address matters
at issue in the following proceedings:
Docket No. EL09–40, Southwest Power
Pool, Inc.
Docket No. ER06–451, Southwest Power
Pool, Inc.
Docket No. ER08–923, Xcel Energy
Services, Inc.
Docket No. ER08–1307, Southwest
Power Pool, Inc.
Docket No. ER08–1308, Southwest
Power Pool, Inc.
Docket No. ER08–1357, Southwest
Power Pool, Inc.
Docket No. ER08–1358, Southwest
Power Pool, Inc.
Docket No. ER08–1359, Southwest
Power Pool, Inc.
Docket No. ER08–1419, Southwest
Power Pool, Inc.
Docket No. ER09–35, Tallgrass
Transmission LLC.
Docket No. ER09–36, Prairie Wind
Transmission LLC.
Docket No. ER09–1397, Southwest
Power Pool, Inc.
E:\FR\FM\29DEN1.SGM
29DEN1
Agencies
[Federal Register Volume 74, Number 248 (Tuesday, December 29, 2009)]
[Notices]
[Pages 68820-68839]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E9-30827]
-----------------------------------------------------------------------
DEPARTMENT OF ENERGY
Western Area Power Administration
Pick-Sloan Missouri Basin Program--Eastern Division-Rate Order
Nos. WAPA-144 and WAPA-148
AGENCY: Western Area Power Administration, DOE.
ACTION: Notice of Order Concerning Transmission and Ancillary Services
Rates and Transmission Service Penalty Rate for Unreserved Use.
-----------------------------------------------------------------------
SUMMARY: The Deputy Secretary of Energy confirmed and approved Rate
Order Nos. WAPA-144 and WAPA-148 and Rate Schedules UGP-NT1, UGP-FPT1,
UGP-NFPT1, UGP-AS1, UGP-AS2, UGP-AS3, UGP-AS4, UGP-AS5, UGP-AS6, UGP-
AS7 and UGP-TSP1 on an interim basis. The provisional rates will be in
effect until the Federal Energy Regulatory Commission (FERC) confirms,
approves, and places them into effect on a final basis or until they
are superseded. The provisional rates will provide sufficient revenue
to pay all annual costs, including interest expenses, and repay
required investments within the allowable periods.
DATES: Rate Schedules UGP-NT1, UGP-FPT1, UGP-NFPT1, UGP-AS1, UGP-AS2,
UGP-AS3, UGP-AS4, UGP-AS5, and UGP-AS6 and will be placed into effect
on an interim basis on January 1, 2010, and will be in effect until
FERC confirms, approves, and places the rate schedules in effect on a
final basis through December 31, 2014, or until the rate schedules are
superseded. The revised Rate Schedules UGP-NT1, UGP-FPT1, UGP-NFPT1,
UGP-AS1, UGP-AS2, UGP-AS3, UGP-AS4, UGP-AS5 and UGP-AS6 dated January
1, 2010, supersede the similarly titled rate schedules dated October 1,
2005. Rate Schedule UGP-AS7 will be placed into effect on an interim
basis on January 1, 2010; however, Rate Schedule UGP-AS7 will not be
charged until such time as Western's OATT is revised to provide for
Generator Imbalance Service. Rate Schedule UGP-AS7 will remain in
effect through December 31, 2014, or until superseded, to coincide with
the other ancillary service rates in this rate order. Rate Schedule
UGP-TSP1 will be placed into effect on an interim basis on January 1,
2010; however, Rate Schedule UGP-TSP1 will not be charged until such
time as Western's Open Access Transmission Tariff (OATT) is revised to
provide for unreserved use of transmission service penalties. Rate
schedule UGP-TSP1 will also remain in effect through December 31, 2014,
or until superseded, to coincide with the other rates in this rate
order. Western will post notice on its Open Access Same-Time
Information System (OASIS) Web site of its intent to initiate charging
for Rate Schedule UGP-AS7 or UGP-TSP1.
FOR FURTHER INFORMATION CONTACT: Mr. Robert J. Harris, Regional
Manager, Upper Great Plains Region, Western Area Power Administration,
2900 4th Avenue North, Billings, MT 59101-1266 or Ms. Linda Cady-
Hoffman, Rates Manager, Upper Great Plains Region, Western Area Power
Administration, 2900 4th Avenue North, Billings, MT
[[Page 68821]]
59101-1266, telephone (406) 247-7439, e-mail cady@wapa.gov.
SUPPLEMENTARY INFORMATION: The transmission facilities in the Pick-
Sloan Missouri Basin Program--Eastern Division (P-SMBP--ED) are
integrated with transmission facilities of Basin Electric Power
Cooperative (Basin) and Heartland Consumers Power District (Heartland)
such that transmission services are provided over an Integrated System
(IS), and the rates are sometimes referred to as IS Rates. Western acts
as the administrator of the IS and monitors service under the OATT.\1\
As owners of the IS, Western, Basin, and Heartland may be referred to
as IS Partners. The Deputy Secretary of Energy approved the current
Rate Schedules UGP-NT1, UGP-FPT1, UGP-NFPT1, UGP-AS1, UGP-AS2, UGP-AS3,
UGP-AS4, UGP-AS5, and UGP-AS6 for P-SMBP--ED firm and non-firm
transmission rates and ancillary services rates through September 30,
2010.\2\ The current rate schedules contain formula-based rates that
are recalculated annually. The provisional formula rates will continue
to be recalculated annually from financial and load information.
Provisional rates will go into effect January 1, 2010, and recalculated
rates annually on January 1 thereafter. The provisional rate for
Generator Imbalance Service, under UGP-AS7, will go into effect January
1, 2010, but will not be charged until Western's OATT is revised to
provide for Generator Imbalance Service. The provisional Penalty Rate
for Unreserved Use of Transmission Service, under UGP-TSP1 will go into
effect on January 1, 2010, but will not be charged until Western's OATT
is revised to provide for unreserved use penalties. Western will post
notice on its Open Access Same-Time Information System (OASIS) Web site
of its intent to initiate charging for Rate Schedule UGP-AS7 or UGP-
TSP1.
---------------------------------------------------------------------------
\1\ Western's OATT was most recently approved by FERC on June
28, 2007, in Docket No. NJ07-2-000, 119 FERC 61,329 (2007) and the
FERC's letter order issued on September 6, 2007, in Docket No. NJ07-
2-001.
\2\ Rate Order No. WAPA-122, 70 FR 55821, September 23, 2005,
and the FERC confirmed and approved the rate schedules on May 30,
2006, under FERC Docket No. EF05-5031-000, 115 FERC ] 62,230.
---------------------------------------------------------------------------
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 FERC. 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 00-001.00C, 10 CFR part
903, and 18 CFR part 300, I hereby confirm, approve, and place Rate
Order Nos. WAPA-144, the proposed P-SMBP--ED Integrated System firm and
non-firm transmission rates and ancillary services and WAPA-148, the
proposed Transmission Service Penalty Rate for Unreserved Use into
effect on an interim basis. The new Rate Schedules UGP-NT1, UGP-FPT1,
UGP-NFPT1, UGP-AS1, UGP-AS2, UGP-AS3, UGP-AS4, UGP-AS5, UGP-AS6, UGP-
AS7 and UGP-TSP1 will be promptly submitted to the Commission for
confirmation and approval on a final basis.
Dated: December 23, 2009.
Daniel B. Poneman,
Deputy Secretary.
Department of Energy Deputy Secretary
Rate Order Nos. WAPA-144 and WAPA-148
In the matter of: Western Area Power Administration Rate Adjustment
for the Pick-Sloan Missouri Basin Program--Eastern Division; Order
Confirming, Approving, and Placing the Pick-Sloan Missouri Basin
Program--Eastern Division Transmission and Ancillary Services and
Transmission Service Penalty for Unreserved Use 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 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 Federal Energy Regulatory Commission
(FERC). 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.
ATRR: Annual Transmission Revenue Requirement.
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.
Control Area: An electric power system or combination of electric
power systems to which a common automatic generation control scheme is
applied in order to: (1) Match, at all times, the power output of the
generators within the electric system(s) and capacity and energy
purchased from entities outside the electric power system(s) with load
within the electric power system(s); (2) maintain scheduled interchange
with other Control Areas, within the limits of Good Utility Practice;
(3) maintain the frequency of the electric power system(s) within
reasonable limits in accordance with Good Utility Practice; and (4)
provide sufficient generating capacity to maintain operating reserves
in accordance with Good Utility Practice.
Corps of Engineers: U.S. Army Corps of Engineers.
[[Page 68822]]
Customer: An entity with a contract that is receiving service from
Western Area Power Administration's Upper Great Plains Region.
DOE: United States Department of Energy.
Energy: Power produced or delivered over a period of time. 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 Federal Energy Regulatory Commission.
FERC Order No. 888: FERC Order Nos. 888, 888-A, 888-B and 888-C
unless otherwise noted.
FERC Order No. 890: FERC Order Nos. 890, 890-A, 890-B and 890-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.
GWh: Gigawatthour--the electrical unit of energy that equals 1
billion watthours or 1 million kilowatt-hours.
Heartland: Heartland Consumers Power District.
Integrated System: Transmission system combining assets of Western,
Basin Electric, and Heartland.
IS: Integrated System.
Intermittent Resource: An electric generator that is not
dispatchable and cannot store its fuel source and, therefore, cannot
respond to changes in demand or respond to transmission security
constraints.
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.
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.
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.
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: Documents explaining the rationale and background
for the rate proposals contained in this Rate Order.
Reclamation: United States Department of the Interior, Bureau of
Reclamation.
Reactive Supply and Voltage Control 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 Control Area 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.
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
[[Page 68823]]
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 Documents: 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, 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
Upper Great Plains Region, 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.
Unreserved Use: Use of transmission service in excess of reserved
capacity at any point of receipt or any point of delivery.
VAR: A unit of reactive power.
WAUE: Western Area Power Upper Great Plains Region East Control
Area.
WAUW: Western Area Power Upper Great Plains Region West Control
Area.
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 provisional rates will take effect on January 1, 2010, and will
remain in effect through December 31, 2014, pending approval by FERC on
a final basis. Rate schedules UGP-AS7 and UGP-TSP1 will be placed into
effect on an interim basis on January 1, 2010, but will not be charged
until Western's Open Access Transmission Tariff (OATT) is revised to
provide for Generator Imbalance Service and/or Transmission Service
Penalty Rate for Unreserved Use. Western will post notice on its Open
Access Same-Time Information System (OASIS) Web site of its intent to
initiate charging for Rate Schedule UGP-AS7 or UGP-TSP1.
Public Notice and Comment
Western followed the Procedures for Public Participation in Power
and Transmission Rate Adjustments and Extensions, 10 CFR part 903, in
developing these rates. The steps Western took to involve interested
parties in the rate process were:
1. The rate adjustment process began when Western's UGPR mailed a
notice announcing an Advance Announcement of Rate Adjustment public
meeting to all IS Transmission Customers and interested parties. The
meeting was held on June 10, 2008, in Sioux Falls, South Dakota. At the
Advance Announcement of Rate Adjustment meeting, Western provided
pertinent information relevant to the rate adjustment and answered
questions.
2. A Federal Register notice published on June 3, 2009 (74 FR
26682), announced the proposed rate adjustments for P-SMBP-ED
Transmission and Ancillary Service rates. This publication began a
public consultation and comment period and announced the public
information and the public comment forums.
3. A Federal Register notice published on June 26, 2009 (74 FR
30567), announced the proposed Transmission Service Penalty Rate for
Unreserved Use. This publication began a public consultation and
comment period and announced the public information and the public
comment forums.
4. On June 5, 2009, Western mailed letters to all IS Transmission
Customers and interested parties transmitting the Federal Register
notice published on June 3, 2009, and directing them to the rate
brochure for the Transmission and Ancillary Services Rate Adjustment on
Western's Web site. On June 26, 2009, Western mailed letters to all IS
Transmission Customers and interested parties transmitting the Federal
Register notice published on June 26, 2009, and directing them to the
rate brochure for the Transmission Service Penalty Rate for Unreserved
Use on Western's Web site.
5. On June 24, 2009, beginning at 9 a.m., Western held a public
information forum at the Holiday Inn City Center in Sioux Falls, South
Dakota. Western provided detailed explanations of the proposed
Transmission and Ancillary Service Rates. Western provided Rate
Brochures, informational handouts and answered questions at this
meeting.
6. On July 28, 2009, beginning at 8 a.m., Western held a public
information forum at the Holiday Inn City Center Sioux Falls, South
Dakota. Western provided detailed explanations of the proposed
Transmission Service Penalty Rate for Unreserved Use. Western provided
Rate Brochures, informational handouts, and answered questions at this
meeting.
7. On July 28, 2009, beginning at 9 a.m., Western held a public
comment forum at the Holiday Inn City Center Sioux Falls, South Dakota,
to give the public the opportunity to comment for the record on the
proposed Transmission and Ancillary Services Rates and the Transmission
Service Penalty Rate for Unreserved Use.
8. Western received one comment letter during the consultation and
comment period for proposed rates for P-SMBP-ED Transmission and
Ancillary Service rates, which ended on October 1, 2009. Western
received two comment letters during the consultation and comment period
for proposed Transmission Service Penalty Rate for Unreserved Use,
which ended on September 24, 2009. All formally submitted comments have
been considered in preparing this Rate Order.
Comments
Representatives of the following organization made oral comments
pertaining to the proposed P-SMBP-ED Transmission and Ancillary Service
rates:
Missouri River Energy Services
The following organizations submitted written comments pertaining
to the proposed P-SMBP-ED Transmission and Ancillary Service rates:
Missouri River Energy Services
The following organizations submitted written comments pertaining
[[Page 68824]]
to the proposed P-SMBP-ED Transmission Service Penalty Rate for
Unreserved Use rate:
Midwest ISO Transmission Owners
ITC Holdings Corp.
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. No. 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 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
power plants 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, Western, 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 Converter Station
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 requestors. 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.
P-SMBP-ED Transmission and Ancillary Services Rates Study
Western prepared a Transmission and Ancillary Service rates study
to ensure that Formula IS 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.
In the past, rates have been based on the most recently available
historical test year data. In preparing the current rates study,
projections for the various revenue requirement components were used to
develop the forward looking (projected) rate. The annual revenue
requirements include O&M expenses, administrative and general expenses,
interest expense, and depreciation expense. These revenue requirements
are offset by appropriate estimated revenues. Annual audited financial
data will be used to true-up the estimates used to project the forward
looking rate to the actual expenses and load incurred.
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 Provisional Revenue
Requirement based upon the most recent historical data available at the
time of the initial rate proposal.
Comparison of Existing and Provisional Integrated System Transmission and Ancillary Services
----------------------------------------------------------------------------------------------------------------
Existing Provisional
Service revenue revenue Percentage
requirement requirement change
----------------------------------------------------------------------------------------------------------------
Transmission.................................................... $155,056,530 $163,521,251 5.46
Scheduling, System Control, and Dispatch........................ 3,649,053 3,649,053 0.00
Reactive Supply and Voltage Control............................. 4,496,498 2,376,635 -47.14
Regulation and Frequency Control................................ 1,362,791 1,362,791 0.00
Reserves........................................................ 2,569,924 3,384,360 31.69
Energy Imbalance................................................ N/A N/A N/A
Generator Imbalance............................................. N/A N/A N/A
Transmission Service Penalty Rate for Unreserved Use............ N/A N/A N/A
----------------------------------------------------------------------------------------------------------------
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.
Integrated System Transmission Service Rates Discussion
Western offers Network Integration Transmission, Firm Point-to-
Point and Non-firm Point-to-Point Transmission, Scheduling, System
Control, and Dispatch Service, Reactive Supply and Voltage Control
Service, Regulation and Frequency Response Service, Energy Imbalance
Service, and Reserve Service on the IS. The rate schedules for the IS
were initially placed into effect by Rate Order No. WAPA-79 on August
1, 1998,
[[Page 68825]]
and were effective through July 31, 2003. The FERC order to confirm
these rate schedules was issued on November 25, 1998. These rate
schedules were then extended by Rate Order No. WAPA-100 through
September 30, 2005. Rate Order No. WAPA-122 removed the Generator Step
Up Transformers from transmission and placed them in generation in the
formula rate calculations. The rate schedules placed into effect by
Rate Order No. WAPA-122 were effective on October 1, 2005, and will
remain in effect until September 30, 2010, or until superseded.
The provisional formula rates include revisions to the Network
Integration, Firm and Non-firm Transmission, and Ancillary Service
Rates as described in Rate Schedules UGP-NT1, UGP-FPT1, UGP-NFPT1, UGP-
AS1, UGP-AS2, UGP-AS3, UGP-AS4, UGP-AS5, and UGP-AS6. These revisions
will utilize estimates of transmission costs for the upcoming year to
calculate annual revenue requirements, update formulas utilized in the
formula rate calculations, change the effective date for rates
resulting from the annual recalculation, provide a rate recalculation
review/comment period, and standardize input data requirements.
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 their
firm electric service 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 is estimated to be
4,605,000 kW.
Revenue Requirement for IS Transmission Service
The current rates for the IS Transmission Service are based on a
revenue requirement that recovers the annual costs of Western, Basin
Electric, Heartland, and approved customer facility credits associated
with providing IS Transmission Service. The annual costs are offset by
appropriate transmission revenue credits to avoid over recovery of
costs.
Western is changing the method of developing the revenue
requirement for Network, Firm Point-to-Point, and Non-Firm Point-to-
Point transmission services. Western is changing the implementation of
the formula rates to recover expenses and investments in transmission
on a current (forward looking) rather than a lagging basis. This change
will allow Western to more accurately match cost recovery with cost
incurrence. To implement this change, Western will utilize estimates of
the IS transmission system costs and load for the upcoming year in the
formula rate recalculation. Western will true-up the estimates based on
IS actual costs and actual load. Rates will continue to be recalculated
every year. Revenue collected in excess of Western's, Basin Electric's,
Heartland's, and entities' receiving customer facility credits actual
net revenue requirements will be returned to customers through a
reduction in revenue requirement in a subsequent year. Actual revenues
that are less than the net revenue requirement would likewise be
recovered by an increase in a subsequent year's revenue requirement.
The true-up procedure ensures the IS will recover no more and no less
than its actual transmission costs.
Revenue Requirement Calculation Templates
Western will initiate the use of standardized revenue requirement
calculation templates by those entities submitting financial data for
the annual rate recalculation to aid in the revenue requirement/rate
recalculation and review processes. These revenue requirement templates
will gather required financial information and data from IS partners
and other entities for the calculation of revenue requirements and
facility credits. Western will review requests to utilize other or
modified templates for appropriateness and conduct a public process
prior to granting approval for use. Western will accept use of a FERC
approved template for a particular entity without conducting a public
process prior to granting approval for use provided that the following
conditions are met: (1) The template addresses all the transmission
facilities owned by the entity; (2) the template includes a separate
allocation for IS qualifying facilities; and (3) it is the latest FERC
approved template for this entity.
Review of Annual Revenue Requirement and Rate Recalculation
Western will determine the IS net projected revenue requirement and
load for each year in accordance with applicable IS rate schedules.
Western will make the IS net projected revenue requirement available to
customers including projected costs of plant in the rate base,
transmission O&M expense, transmission administrative and general
expense, transmission depreciation expense, load, and resulting rates
incorporating any True-up Adjustment. All data will be provided in
sufficient detail to identify the components of Western's net revenue
requirement.
Western has conducted an annual IS rate recalculation utilizing the
previous year's data with the recalculated rate effective May 1 of each
year. With the implementation of the provisional formula rates
resulting from this process effective on January 1, 2010, Western will
conduct future rate recalculations with an effective date of January 1.
Western will provide the results of this annual rate recalculation
to customers on or about September 1 of each year and will provide
customers the opportunity to discuss and comment on the recalculated
rates by October 31 of each year. Western will respond to customer
comments prior to or at the time of the implementation of the
recalculated revenue requirements and/or rates. For the provisional
rates going into effect on January 1, 2010, the Annual Revenue
Requirement for IS Transmission Service is $163,521,251.
Should Western find that any comment concerning the rate formula
bears merit, Western reserves the right to make adjustments to the
revenue requirements and/or rates consistent with proper application of
the Formula Rate. Western's determination concerning the proper
application of the Formula Rate will be final.
True-Up Procedures
Under the true-up procedures, any differences between estimated
revenue requirements and actual revenue requirements in any given year
are identified based on Revenue Requirement Templates utilizing actual
financial data and actual load data for the preceding year. Revenue
collected in excess of the actual net revenue requirement will be
returned to customers through a reduction in revenue requirement in the
subsequent year following the calculation of the true-up. Revenues that
are less than the forecast net revenue requirement would likewise be
recovered in the IS rates for the subsequent year.
Actual Net Revenue Requirement (calculated in accordance with
Western's Rate Recalculation process) for the previous year as provided
in the revenue requirement templates for Western IS partners and
entities receiving revenue credits shall be compared to the projections
made for the same year (True-up Year). The
[[Page 68826]]
comparison of actual net revenue to projected net revenue determines
the excess or shortfall in the projected revenue requirement used for
billing purposes in the True-up Year. In addition, actual divisor loads
(12-cp average) will be compared to projected divisor loads and the
difference multiplied by the rate actually billed to determine any
excess or shortfall in collection due to volume. The sum of the excess
or shortfall due to the actual versus projected revenue requirement and
the excess or shortfall due to volume shall constitute the True-up
Adjustment. The True-up Adjustment and related calculations shall be
posted to Western's OASIS no later than July 1 following the issuance
of financial statements for the previous year. Western will provide an
explanation of the True-up Adjustment in response to customer inquiries
and will post on the OASIS information regarding frequently asked
questions.
The Net Revenue Requirement for transmission services for the
following year will be the sum of the projected revenue requirement for
the following year, plus or minus the True-Up Adjustment and any other
adjustments from the previous year.
Formula Rate for Network IS Transmission Service
While Western is changing the method for developing annual revenue
requirements, the formula for calculating the Network Transmission
Service rate is unchanged from Western's previously approved filing
with the FERC. Western will use a current year formula rate which
involves a change to the manner in which the inputs are developed
rather than a change in the formula itself. The charge for monthly
Network IS Transmission Service is the product of the network
customer's load ratio share times one-twelfth (1/12) of the annual
Network Transmission Revenue Requirement. The Network Transmission
Revenue Requirement is the annual cost associated with providing
transmission service less revenue credits for Non-Firm Transmission
Service. The Network Transmission Revenue Requirement will be based on
estimates for costs to provide transmission service for the up-coming
year. The load ratio share is the network customer's hourly load
coincident with the IS monthly Transmission System peak minus the
coincident peak for all IS Firm Point-to-Point Transmission Service
plus the Firm Point-to-Point reservations. The Network rate includes
costs for scheduling, system control, and dispatch service needed to
provide transmission service.
Formula Rate for Firm Point-to-Point IS Transmission Service
The monthly rate for Firm Point-to-Point IS Transmission Service is
1/12 the annual cost associated with providing transmission service
less revenue credits for Non-Firm Transmission Service divided by the
capacity reservation needed to support the average monthly IS
Transmission System load. As with Network Transmission Service, Western
will be using a current year formula rate which involves a change to
the manner in which the inputs are developed rather than a change in
the formula itself. This rate may be summarized with the following
formula: ISFPTP = (Total Annual Revenue Requirement--Non Firm Revenue
Credits)/12 months/Average Transmission System Monthly Peak Load. Firm
Point-to-Point Transmission Service will be offered on an up to basis
at daily, weekly, monthly, and yearly rates.
Formula Rate for Non-Firm Point-to-Point Transmission
Western will not change the rate formula for Non Firm Point-to-
Point Transmission Service other than utilizing cost projections as
data inputs to determine the annual revenue requirement as described
above. The Non Firm Point-to-Point Transmission Service rate formula
remains: Monthly IS Firm Point-to-Point Transmission Service rate
divided by 730 hours per month times 1000 mills per dollar.
The following table summarizes the difference between the current
IS Transmission Service rates and the provisional IS Transmission
Service rates. It compares the change in the projections for the 2009-
2010 transmission and ancillary services study and the provisional IS
Transmission Service rates for this rate adjustment based on the most
recent historical data and estimated data available at the time of the
initial rate proposal.
Comparison of Annual Revenues
----------------------------------------------------------------------------------------------------------------
Provisional Percentage
Item Existing rate rate change
----------------------------------------------------------------------------------------------------------------
Annual IS Cost (Net of Revenue Credits)......................... $147,038,956 $154,900,362 5.35
Transmission Customer Facility Credits.......................... 8,541,224 8,620,889 0.93
Annual Revenue Requirement for IS Transmission Service.......... 155,580,180 163,521,251 5.10
Adjustment for Prior Year....................................... 523,417 N/A N/A
Annual Transmission Revenue Requirement......................... 155,056,530 163,521,251 5.46
----------------------------------------------------------------------------------------------------------------
Basis for Rate Development
The current IS Network, Firm Point-to-Point and Non-Firm Point-to-
Point Transmission Service formula rates are scheduled to expire on
September 1, 2010. The current Network, Firm Point-to-Point and Non-
Firm Point-to-Point Transmission Service formula rates do not capture
new investment costs until they have been in service for up to 2 years.
The proposed rates are forward looking and include estimates for
investments being placed in service, annual operation and maintenance
expenses, depreciation, interest, and administrative and general costs.
In the past, rates were recalculated in April and were effective on May
1. The rates implemented in this process will be available for review
on or about September 1 and placed into effect on January 1.
Integrated System Ancillary Services Rates Discussion
The IS will continue to offer the following six ancillary services:
(1) Scheduling system control, and dispatch service; (2) reactive
supply and voltage control from generation sources service; (3)
regulation and frequency response service; (4) energy imbalance
service; (5) spinning reserve service and (6) supplemental reserve
service; and will add a seventh ancillary service; (7) generator
imbalance service.
Western has already marketed the maximum practical amount of power
from each of its projects, based on a reasonable level of risk, leaving
little or no Federal hydroelectric power resources available for
ancillary services. Changes in water conditions
[[Page 68827]]
frequently affect the ability of the hydroelectric projects to meet
obligations on a short-term basis. The unique characteristics of the
hydro resource, Western's existing long-term power commitments, and the
limitations of the resource due to changing water conditions limit
Western's ability to provide Transmission Customers generation-related
ancillary services and redispatch using Federal hydro resources.
Consequently, Western will provide ancillary services by purchasing
power resources whenever necessary and pass through these costs to the
customer.
Formula Rate for 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 the communications
facilities net plant associated with Scheduling, System Control, and
Dispatch Service by the transmission fixed charge rate. In the past,
the annual revenue requirement for Scheduling, System Control, and
Dispatch Service has been divided by the number of daily schedules in
the calculation year. Western is changing this formula. Instead of
dividing the annual revenue requirement for Scheduling, System Control,
and Dispatch Service by the number of daily schedules in the
calculation year, Western will divide the annual revenue requirement
for Scheduling, System Control, and Dispatch Service by the number of
daily tags in the calculation year. This rate and rate design is
recovering only Western's revenue requirement.
Formula Rate for Reactive Supply and Voltage Control Services From
Generation Sources Service
Western's current formula for Reactive Supply and Voltage Control
from Generation Sources (RSVC) 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 five (5) year average peak
monthly percentage of Western's generation operating in a synchronous
condenser mode to determine Western's reactive service revenue
requirement. Western's, Basin Electric's, Heartland's, and Missouri
River Energy Services' revenue requirements for RSVC Service are summed
to get the total revenue requirement for this service. The RSVC Service
rate is then derived by dividing the total annual revenue requirement
by the load requiring RSVC Service. The annual cost is then divided by
12 months to obtain a monthly rate. In this formula, Western is only
compensated for providing RSVC Service based upon the cost of Western's
generation operating outside the 0.95 leading to 0.95 lagging power
factor bandwidth, while Basin, Heartland, and Missouri River Energy
Services are compensated based on costs for generation operating within
this power factor bandwidth.
Western is changing its rate for RSVC Service by removing costs of
any generation associated with operation within the bandwidth from the
total revenue requirement for this service. Under Western's current
rate, Western is not compensated for providing RSVC Service from its
own generators operating inside the bandwidth while non-Federal
generators are receiving compensation for providing RSVC Service within
the bandwidth. Western believes that both Federal and non-Federal
generators should be treated comparably when they provide RSVC Service
within the bandwidth. Therefore, Western is discontinuing payment for
all other generators providing RSVC Service within the 0.95 leading to
0.95 lagging power factor bandwidth.
Western will continue to collect its RSVC Service cost, for its
generators operating within the bandwidth, in the firm power revenue
requirement under the then appropriate firm power rate schedule and not
from Transmission Customers under its OATT. Therefore, only Federal
preference power customers will pay the RSVC costs of the Federal
generators operating within the bandwidth. This change will result in
transmission service customers paying for RSVC Service based only upon
costs for generators operating outside the bandwidth. Excluding RSVC
Service costs associated with generator operation within the bandwidth
from the RSVC Service revenue requirement will require all other non-
Federal generator owners to recover their RSVC Service costs, for
operation within the bandwidth, elsewhere.
Western's Federal generation is required to operate in synchronous
condenser mode (i.e., outside the power factor bandwidth) to maintain
system voltages and meet reliability criteria and, therefore consistent
with the previous practice, Western will include its costs to provide
RSVC Service for Federal generators operating outside the bandwidth.
Western will include costs associated with other non-Federal generators
required to operate outside the power factor bandwidth to maintain
system voltages and meet reliability criteria (e.g., other generators
that operate as synchronous condensers, or generators that are
requested by Western to operate outside the bandwidth as noted in
Western's generator interconnection procedures and agreements).
The following provisional rate formula will apply: Western's total
P-SMBP-ED generation net plant multiplied by the generation fixed
charge rate (in percent) equals Western's annual cost. Western's annual
cost is multiplied by the five (5) year average peak monthly percentage
of Western's Federal synchronous condensing generation to determine
Western's outside the bandwidth reactive service revenue requirement.
Western's revenue requirement plus any revenue requirement or costs
incurred from other non-Federal generators required by Western to
operate outside the bandwidth is the total annual revenue requirement
for RSVC Service. This total annual revenue requirement is then divided
by the total load (kWyear) in Western's Control Areas.\3\ The product
is then divided by 12 months to obtain a monthly charge.
---------------------------------------------------------------------------
\3\ Western has retained the term ``Control Area'' in this
document maintaining consistency with usage of the term in FERC's
pro forma tariff and Western's current OATT. As defined in Western's
OATT, a Control Area is: An electric power system or combination of
electric power systems to which a common automatic generation
control scheme is applied in order to: (1) Match, at all times, the
power output of the generators within the electric system(s) and
capacity and energy purchased from entities outside the electric
power system(s), with load within the electric power system(s); (2)
maintain scheduled interchange with other Control Areas, within the
limits of Good Utility Practice; (3) maintain the frequency of the
electric power system(s) within reasonable limits in accordance with
Good Utility Practice; and (4) provide sufficient generating
capacity to maintain operating reserves in accordance with Good
Utility Practice.
---------------------------------------------------------------------------
Formula Rate for Regulation and Frequency Response Service
Western will continue the current formula-based rate methodology
for Regulation and Frequency Response Service as described below.
Regulation and Frequency Response Service in the east side of the
Control Area is provided primarily by Oahe generation and in the west
side of the Control Area by Fort Peck, both of which are Corps of
Engineers (Corps) facilities. The Corps generation fixed charge rate
(in percent) is applied to Oahe and Fort Peck net plant investment,
producing an annual Corps generation cost for the Oahe and Fort Peck
power plants. This cost is divided by the capacity at the plants
(937,000 kW) to derive a dollar per kilowatt amount for Oahe's and Fort
Peck's installed capacity (kWYear). This dollar per kilowatt amount is
then
[[Page 68828]]
applied to the capacity (in kW) of Oahe and Fort Peck generation
reserved for regulation and frequency response in the Control Area.
Western's annual revenue requirement for Regulation and Frequency
Response Service is determined by applying the dollar per kilowatt
charge to the capacity used for Regulation and Frequency Response
Service plus the cost of any additional resources acquired to support
regulation requirements for intermittent renewable resources serving
load within Western's Control Areas. The total Regulation and Frequency
Response Revenue Requirement is determined by adding Western's, Basin
Electric's, and Heartland's Regulation and Frequency Response Revenue
Requirements. The Regulation and Frequency Response Service charge is
then determined by dividing the total revenue requirement by the total
load in the Control Area (kWYear). The result is then divided by 12
months to obtain a monthly charge.
Western supports the installation of renewable sources of energy
but recognizes that certain operational constraints exist in managing
the significant fluctuations that are a normal part of their operation.
When Western purchases power resources to provide Regulation and
Frequency Response Service to intermittent renewable generation
resources serving load within Western's Control Areas, costs for these
regulation resources will become part of Western's Regulation and
Frequency Response Service charges. However, Western has marketed the
maximum practical amount of power from each of its projects leaving
little or no flexibility for provision of additional power services.
Consequently, Western will not regulate for the difference between the
output of an intermittent generator located within Western's Control
Area and a delivery schedule from that generator serving load located
outside of Western's Control Area. Intermittent generators serving load
outside Western's Control Area will be required to pseudo-tie or
dynamically schedule their generation to another Control Area.
Rate for Energy Imbalance Service
Western is changing its rate for Energy Imbalance Service to be
consistent with the rules promulgated by FERC to the extent that it is
consistent with Western's mission and is permitted by law and
regulations. Currently penalty charges apply only 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
while over deliveries outside the bandwidth are forfeited.
Western proposes charges be modified and based on the deviation
bands as follows: Deviations within +/- 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 Transmission Customer's scheduled
transaction(s) will be netted on a monthly basis and settled
financially, at the end of the month, at 100 percent of the average
incremental cost for the month. Deviations greater than +/- 1.5 percent
up to 7.5 percent (or greater than 2 MW up to 10 MW) of the scheduled
transaction to be applied hourly to any energy imbalance that occurs as
a result of Transmission Customer's scheduled transaction(s) will be
settled financially, at the end of each month, at 110 percent of
incremental cost when energy taken by the Transmission Customer in a
schedule hour is greater than the energy scheduled or 90 percent of
incremental cost when energy taken by a Transmission Customer in a
schedule hour is less than the scheduled amount. Deviations greater
than +/- 7.5 percent (or 10 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) will be settled
financially, at the end of each month, at 125 percent of the
incremental cost for energy taken by the Transmission Customer in a
scheduled hour that is greater than the energy scheduled, or 75 percent
of the incremental cost for that hour when energy taken by a
Transmission Customer is less than the scheduled amount.
Western's incremental cost will be based upon a representative
hourly energy index or combination of indexes. The index to be used
will be posted on Western's OASIS https://www.oatioasis.com/wapa/ at least 30 days prior to use for determining Western's
incremental cost and will not be changed more often than once per year
unless Western determines that the existing index is no longer a
reliable price index.
Formula Rates for Operating Reserves Service--Spinning and Supplemental
Western will continue the current formula-based rate methodology
for Spinning Reserve Service and Supplemental Reserve Service (Reserve
Services), except that Western will substitute the reserve requirement
of the current reserve sharing group of which Western and the IS
Partners are members or will substitute Western's and the IS Partners'
own operating reserve requirement for that of the Mid-Continent Area
Power Pool (MAPP) requirement.
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/kWyear is determined
by dividing the annual cost of generation by the plant capacity. The
capacity used for Reserve Services is determined by multiplying the
peak IS load by either the operating reserve requirement of the current
reserve sharing group of which Western and the IS Partners are members
or their own operating reserve requirement. The cost/kWyear is
multiplied by the capacity used for Reserve Services to obtain the
annual revenue requirement. 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 design recovers only Western's revenue
requirement associated with Reserve Services.
Western has no long-term reserves available beyond its own internal
requirements. At a customer's request, Western will acquire needed
resources and pass the costs on to the requesting customer. The
customer is responsible to provide the transmission to deliver these
reserves.
Rate for Generator Imbalance Service
Western is adding a Generator Imbalance Service rate under a new
Rate Schedule, UGP-AS7, to be consistent with rules promulgated by FERC
to the extent consistent with Western's mission and permitted by law
and regulations. However, if Western does not also implement a
Generator Imbalance Service in a revised OATT, this rate will not be
utilized.
Generator Imbalance Service is provided when a difference occurs
between the output of a generator located within the Transmission
Provider's Control Area and a delivery schedule from that generator to
(1) another Control Area or (2) a load within the Transmission
Provider's Control Area over a single hour. Western will offer this
service, to the extent that it is feasible to do so from its own
resources or from resources available to it, when Transmission Service
is used to deliver energy from a generator located within its Control
Area. The Transmission Customer must either purchase this service from
Western or make alternative comparable arrangements, which may include
use of non-generation resources capable of providing this service, to
satisfy its Generator Imbalance Service obligation.
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Western may charge a Transmission Customer a penalty for either hourly
generator imbalances under this Schedule UGP-AS7 or hourly energy
imbalances under Rate Schedule UGP-AS4 for imbalances occurring during
the same hour, but not both, unless the imbalances aggravate rather
than offset each other.
Western bases the rate on deviation bands as follows: Deviations
within +/- 1.5 percent (with a minimum of 2 MW) of the scheduled
transaction to be applied hourly to any generator imbalance that occurs
as a result of Transmission Customer's scheduled transaction(s) will be
netted on a monthly basis and settled financially, at the end of the
month, at 100 percent of the average incremental cost. Deviations
greater than +/- 1.5 percent up to 7.5 percent (or greater than 2 MW up
to 10 MW) of the scheduled transaction to be applied hourly to any
generator imbalance that occurs as a result of Transmission Customer's
scheduled transaction(s) will be settled financially, at the end of
each month. When energy delivered in a schedule hour from the
generation resource is less than the energy scheduled, the charge is
110 percent of incremental cost. When energy delivered from the
generation resource is greater than the scheduled amount, the credit is
90 percent of the incremental cost. Deviations greater than +/- 7.5
percent (or 10 MW) of the scheduled transaction to be applied hourly to
any generator imbalance that occurs as a result of the Transmission
Customer's scheduled transaction(s) will be settled at 125 percent of
Western's incremental cost when energy delivered in a schedule hour is
less than the energy scheduled or 75 percent of Western's daily
incremental cost for that hour when energy delivered from the
generation resource is greater than the scheduled amount. As an
exception, an intermittent resource will be exempt from this deviation
band and will pay the deviation band charges for all deviations greater
than the larger of 1.5 percent or 2 MW.
Deviations from scheduled transactions in order to respond to
directives by the Transmission Provider, a balancing authority, or a
reliability coordinator shall not be subject to the deviation bands
identified above and, instead, shall be settled financially, at the end
of the month, at 100 percent of incremental cost. Such directives may
include instructions to correct frequency decay, respond to a reserve
sharing event, or change output to relieve congestion.
Western's incremental cost will be based upon a representative
hourly energy index or combination of indexes. The index to be used
will be posted on Western's OASIS https://www.oatioasis.com/wapa/ at least 30 days prior to use for determining the Western
incremental cost and will not be changed more often than once per year
unless Western determines that the existing index is no longer a
reliable price index.
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 2009-2010 transmission and ancillary services
study and the provisional IS Transmission and Ancillary Service rates
for this rate adjustment based on the most recent historical and
estimated data available at the time of the rate estimate.
Comparison of Ancillary Service Rates
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Percentage