[Federal Register Volume 76, Number 191 (Monday, October 3, 2011)]
[Notices]
[Pages 61184-61203]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: R1-2011-23391]
[[Page 61183]]
Vol. 76
Monday,
No. 191
October 3, 2011
Part III
Department of Energy
-----------------------------------------------------------------------
Western Area Power Administration
-----------------------------------------------------------------------
Loveland Area Projects--Western Area Colorado Missouri Balancing
Authority--Rate Order No. WAPA-155; Notice; Republication
Federal Register / Vol. 76 , No. 191 / Monday, October 3, 2011 /
Notices
[[Page 61184]]
-----------------------------------------------------------------------
DEPARTMENT OF ENERGY
Western Area Power Administration
Loveland Area Projects--Western Area Colorado Missouri Balancing
Authority--Rate Order No. WAPA-155
Republication
Editorial Note: FR Doc. 2011-23391 was originally published on
pages 56433-56452 in the issue of Tuesday, September 13, 2011. In
that publication an incorrect version of this document was
published. The corrected document is republished below in its
entirety.
AGENCY: Western Area Power Administration, DOE.
ACTION: Notice of order concerning transmission and ancillary services
formula rates.
-----------------------------------------------------------------------
SUMMARY: The Deputy Secretary of Energy has confirmed and approved Rate
Order No. WAPA-155 and Rate Schedules L-NT1, L-FPT1, L-NFPT1, L-AS1, L-
AS2, L-AS3, L-AS4, L-AS5, L-AS6, L-AS7, L-AS9, and L-UU1, placing
Loveland Area Projects (LAP) transmission and Western Area Colorado
Missouri (WACM) Balancing Authority ancillary services formula rates
into effect on an interim basis. The provisional formula 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 replaced by other formula rates. The provisional formula
rates will provide sufficient revenue to pay all annual costs,
including interest expense, and to repay power investment within the
allowable periods.
DATES: Rate Schedules L-NT1, L-FPT1, L-NFPT1, L-AS1, L-AS2, L-AS3, L-
AS4, L-AS5, L-AS6, L-AS7, L-AS9, and L-UU1 will be placed into effect
on an interim basis on the first day of the first full billing period
beginning on or after October 1, 2011, and will remain in effect until
FERC confirms, approves, and places the rate schedules into effect on a
final basis for a 5-year period ending September 30, 2016, or until the
rate schedules are superseded.
FOR FURTHER INFORMATION CONTACT: Mr. Bradley S. Warren, Regional
Manager, Rocky Mountain Customer Service Region, Western Area Power
Administration, 5555 East Crossroads Boulevard, Loveland, CO 80538-
8986, telephone (970) 461-7201, or Mrs. Sheila D. Cook, Rates Manager,
Rocky Mountain Customer Service Region, Western Area Power
Administration, 5555 East Crossroads Boulevard, Loveland, CO 80538-
8986, telephone (970) 461-7211, e-mail [email protected].
SUPPLEMENTARY INFORMATION: The Deputy Secretary of Energy approved
current Rate Schedules L-NT1, L-FPT1, L-NFPT1, L-AS1, L-AS2, L-AS3, L-
AS4, L-AS5, L-AS6, and L-AS7 on December 30, 2003 (Rate Order No. WAPA-
106, 69 FR 1723, January 12, 2004).\1\ These rates became effective on
March 1, 2004, with an expiration date of February 28, 2009. The rate
schedules, with the exception of Rate Schedule L-AS3, Regulation and
Frequency Response, were extended through February 28, 2011, under Rate
Order No. WAPA-141.\2\ Rate Schedule L-AS3 was revised and approved
under Rate Order No. WAPA-118,\3\ which became effective on June 1,
2006, with an expiration date of May 31, 2011. Under Rate Order No.
WAPA-154,\4\ all LAP transmission and WACM ancillary services rate
schedules, including L-AS3, were extended through February 28, 2013.
---------------------------------------------------------------------------
\1\ WAPA-106 was approved by FERC on a final basis on January
31, 2005, in Docket No. EF2-04-5182-000 (110 FERC ] 62,084).
\2\ WAPA-141, Extension of Rate Order No. WAPA-106 through
February 28, 2011. 73 FR 48382, August 19, 2008.
\3\ WAPA-118 was approved by FERC on a final basis on November
17, 2006, in Docket No. EF-06-5182-000 (117 FERC ] 62,163).
\4\ WAPA-154, Extension of Rate Order Nos. WAPA-106 and WAPA-118
through February 28, 2013. 76 FR 1429, January 10, 2011.
---------------------------------------------------------------------------
LAP Transmission Service
Rate Schedules L-NT1, L-FPT1, and L-NFPT1 for LAP transmission
services are based on a revenue requirement that recovers the LAP
transmission system costs for facilities associated with providing all
transmission services as well as the non-transmission facility costs
allocated to transmission services. These firm and non-firm LAP
transmission service rates include the costs for scheduling, system
control, and dispatch service needed to provide the transmission
service.
Rate Schedule L-UU1, Unreserved Use Penalties, is a new rate
schedule established in accordance with Western's Open Access
Transmission Tariff (Tariff). This rate will recover costs for
transmission service that has not been reserved or has been used in
excess of the amount reserved. Rate Schedule L-UU1 also provides for a
penalty in addition to the base charge for the transmission service
used. Previously, a penalty for unauthorized use of transmission was
included in the Point-to-Point Transmission Service, Rate Schedules L-
FPT1 and L-NFPT1.
Rate Schedule L-AS7, Transmission Losses Service, is designed to
recover losses on all real-time and prescheduled transactions on
transmission facilities inside WACM.
Ancillary Services
Western will provide seven ancillary services pursuant to its
Tariff. These are: (1) Scheduling, System Control, and Dispatch Service
(L-AS1); (2) Reactive Supply and Voltage Control from Generation or
Other Sources Service (L-AS2); (3) Regulation and Frequency Response
Service (L-AS3); (4) Energy Imbalance Service (L-AS4); (5) Spinning
Reserve Service (L-AS5); (6) Supplemental Reserve Service (L-AS6); and
(7) Generator Imbalance Service (L-AS9). Generator Imbalance Service is
also a new rate schedule established under the Tariff. Currently,
Generator Imbalance Service is provided under Rate Schedule L-AS4,
Energy Imbalance Service.
Rates for LAP transmission and ancillary services will be
recalculated each year to incorporate the most recent financial, load,
and schedule information and will be applicable to all transmission and
ancillary services customers.
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 the Administrator of Western; (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 Department of Energy
procedures for public participation in power rate adjustments (10 CFR
903) were published on September 18, 1985 (50 FR 37835).
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 No. WAPA-155, the proposed LAP transmission and WACM ancillary
services formula rates, into effect on an interim basis. By this order,
I am placing the rates into effect in less than 30 days to meet
contract deadlines, to avoid financial difficulties, and to provide
rates for new services. The revised Rate Schedules L-NT1, L-FPT1, L-
NFPT1, L-AS1, L-AS2, L-AS3, L-AS4, L-AS5, L-AS6, L-AS7, L-AS9, and L-
UU1 will be submitted promptly to FERC for confirmation and approval on
a final basis.
[[Page 61185]]
Dated: September 2, 2011.
Daniel B. Poneman,
Deputy Secretary.
Order Confirming, Approving, and Placing the Loveland Area Projects
Transmission and Western Area Colorado Missouri Balancing Authority
Ancillary Services Formula Rates Into Effect on an Interim Basis
These transmission and ancillary services formula rates are
established pursuant to 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 Interior and the Bureau of Reclamation (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 Act of 1939 (43 U.S.C. 485h(c)) and section 5 of the Flood
Control Act of 1944 (16 U.S.C. 825s), and other acts that specifically
apply to the projects 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 the Administrator of Western; (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/Terms and Definitions
As used in this Rate Order, the following acronyms/terms and
definitions apply:
------------------------------------------------------------------------
Acronym/Term Definition
------------------------------------------------------------------------
$/kW-month: Dollars per kilowatt per month.
12-cp: Rolling 12-month average of
customers' loads in excess of
Federal Entitlement, coincident
with the Loveland Area Projects
(LAP) transmission system peak.
Administrator: The Administrator of the Western
Area Power Administration.
Area Control Error (ACE): The instantaneous difference
between a Balancing Authority's
net actual and scheduled
interchange, taking into account
the effects of frequency bias and
correction for meter error.
Ancillary Services: Those services that are necessary
to support the transmission of
capacity and energy from resources
to loads while maintaining
reliable operation of the
Transmission Provider's
transmission system in accordance
with good utility practice.
ATRR: Annual transmission revenue
requirement.
Automatic Generation Control: Equipment that automatically
adjusts generation in a Balancing
Authority area from a central
location to maintain the Balancing
Authority's interchange schedule
plus frequency bias.
Balancing Authority: The responsible entity that
integrates resource plans ahead of
time, maintains load-interchange-
generation balance within a
Balancing Authority area, and
supports interconnection frequency
in real time.
Control Area: The term used for a Balancing
Authority area in Western's Open
Access Transmission Tariff.
CRSP: Colorado River Storage Project.
DOE: Department of Energy.
Energy Imbalance Service: The ancillary service in which the
Balancing Authority corrects
hourly for the difference between
a customer's energy supply and
energy usage.
Federal Customers: LAP customers taking delivery of
long-term firm service under firm
electric service contracts,
project use, and special use
contracts.
Firm Electric Service Contracts: Contracts for the sale of long-term
firm LAP Federal energy and
capacity, pursuant to the Post-
1989 General Power Marketing and
Allocation Criteria (Marketing
Plan).
Firm Point-to-Point Transmission The highest priority transmission
Service: service offered to customers on a
specified path that anticipates no
planned interruption.
Federal Entitlements: The energy and capacity delivered
to Federal Customers under Firm
Electric Service Contracts.
FERC: Federal Energy Regulatory
Commission.
Fry-Ark: Fryingpan-Arkansas Project.
FY: Fiscal Year, October 1 through
September 30.
Generator Imbalance Service: The ancillary service in which the
Balancing Authority corrects
hourly for the difference between
a customer's actual generation and
scheduled generation.
kW: Kilowatt. The electrical unit of
capacity equal to 1,000 watts.
kWh: Kilowatt-hour. The electrical unit
of energy equal to 1 kW produced
or delivered for 1 hour.
kW-month: Kilowatt-month. The electrical unit
of energy equal to 1 kW produced
or delivered for 1 month.
LAP: Loveland Area Projects.
LAP Transmission System or Service: Transmission system operated by, or
service provided by, the Loveland
Area Projects.
LAP Transmission System Total Load: Sum of 12-cp averages for all
customer loads for Network
Integration Transmission Service,
plus 12-month rolling average of
monthly entitlements of Federal
Customers, plus reserved capacity
for all Long-Term Firm Point-to-
Point Transmission Service.
Load ratio share: Network Transmission Customer's 12-
cp load coincident with LAP's
monthly transmission system peak,
expressed as a ratio.
Load Serving Entity (LSE): An entity within the Balancing
Authority that secures energy and
transmission service (and related
interconnected operations
services) to serve the electrical
demand and energy requirements of
its end-use customers.
Long-Term Firm Point-to-Point Firm Point-to-Point Transmission
Transmission Service: Service reservation for a duration
of at least 12 consecutive months.
[[Page 61186]]
Losses: The reduction of power being
delivered as it moves across
transmission lines or other
equipment, due to resistance in
the conducting material.
M&I: Municipal and Industrial.
Mill: Unit of monetary value equal to
.001 of a U.S. dollar; i.e., \1/
10\ of a cent.
Mills/kWh: Mills per kilowatt-hour.
Monthly Entitlements: Maximum capacity to be delivered
each month under Firm Electric
Service Contracts. Each monthly
entitlement is a percentage of the
seasonal contract-rate-of-
delivery.
MW: Megawatt. The unit of electrical
capacity that equals 1,000 kW or
1,000,000 watts.
NERC: North American Electric Reliability
Corporation.
Network Integration Transmission Firm transmission service for the
Service: delivery of capacity and energy
from designated network resources
to designated network loads not
using one specific path.
Non-Firm Point-to-Point Point-to-point transmission service
Transmission Service: reserved on an as-available basis
for periods ranging from 1 hour to
1 year.
Open Access Same Time Information An electronic posting system that
System (OASIS): the Transmission Provider
maintains for transmission access
data that allows all transmission
customers to view the data
simultaneously.
Operating Reserve--Spinning Reserve Generation capacity needed to serve
Service: 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.
Operating Reserve--Supplemental Generation capacity needed to serve
Reserve Service: load in the event of a system
contingency, which capacity 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.
Provisional Formula Rate: A formula rate that has been
confirmed, approved, and placed
into effect on an interim basis by
the Deputy Secretary.
P-SMBP: Pick-Sloan Missouri Basin Program.
P-SMBP--WD: Pick-Sloan Missouri Basin Program--
Western Division.
RMR: Rocky Mountain Customer Service
Region.
Reactive Supply and Voltage Control The ancillary service under which a
from Generation or Other Sources Balancing Authority operates
Service: generation facilities under its
control to produce or absorb
reactive power to maintain
voltages on all transmission
facilities within acceptable
limits.
Reclamation: The United States Bureau of
Reclamation.
Regulation and Frequency Response The ancillary service under which a
Service: Balancing Authority maintains
moment-by-moment load-interchange-
generation balance with the
Balancing Authority area and
supports interconnection
frequency.
Scheduling, System Control, and The ancillary service under which a
Dispatch Service: Balancing Authority sets up an
arrangement for an energy
interchange transaction for
delivery and receipt of energy
between the two entities involved
in the transaction.
Service Agreement: The initial agreement and any
amendments or supplements entered
into by a Transmission Customer
and Western for service under the
Tariff.
Short-Term Firm Point-to-Point Firm Point-to-Point Transmission
Transmission Service: Service for a duration of less
than 12 consecutive months.
Sub-Balancing Authority: An area within a Balancing
Authority area which has its own
boundary metering scheme and for
which an ACE can be measured.
Tariff: Western's revised Open Access
Transmission Service Tariff,
effective December 1, 2009 (Docket
NJ10-1-000).
Transmission Customer: The RMR customer taking Network
Integration Transmission Service
or Point-to-Point Transmission
Service.
Transmission Losses Service: The service provided by the
Balancing Authority to supply
electrical losses on pre-scheduled
and real-time transmission
transactions.
Transmission Provider: An entity that administers a
transmission tariff and provides
transmission service to
transmission customers under
applicable transmission service
agreements.
Unreserved Use Penalties: The use of transmission capacity
that was not reserved, or the use
of transmission in excess of
reserved capacity.
WACM: Western Area Colorado Missouri
Balancing Authority.
WECC: Western Electricity Coordinating
Council.
Western: Western Area Power Administration.
------------------------------------------------------------------------
Effective Date
The Provisional Formula Rates will take effect on the first day of
the first full billing period beginning on or after October 1, 2011,
and will remain in effect through September 30, 2016, pending approval
by FERC on a final basis.
Public Notice and Comment
Western has followed the Procedures for Public Participation in
Power and Transmission Rate Adjustments and Extensions, 10 CFR Part
903, in the development of these formula rates and schedules. The steps
Western took to involve interested parties in the rate process were:
1. On September 29, 2010, Western held an informal meeting with
customers and interested parties to discuss the proposed formula rates
for LAP Transmission and WACM Ancillary Services. Western posted all
information presented at the informal meeting, as well as responses to
questions asked at the meeting, on its Web site at http://www.wapa.gov/rm/ratesRM/2012/default.htm.
2. Western published a Federal Register notice on January 28, 2011
(76 FR 5148), officially announcing the proposed LAP Transmission and
WACM Ancillary Services formula rates adjustment, initiating the public
consultation and comment period, announcing the date and location of
the public information and public comment
[[Page 61187]]
forums, and outlining procedures for public participation.
3. On February 2, 2011, Western sent a letter to all interested
parties providing them with a copy of the Federal Register notice
published on January 28, 2011 (76 FR 5148).
4. On March 9, 2011, Western held its public information forum in
Loveland, Colorado, where Western representatives explained the need
for the formula rates adjustment in detail and answered questions.
5. On March 9, 2011, following the public information forum,
Western held a public comment forum in Loveland, Colorado, to provide
an opportunity for customers and other interested parties to comment
for the record. At this forum, one individual expressed general support
of Western's efforts to communicate with its customers well in advance
of implementation of the proposed rates.
6. Western received one written comment during the 90-day
consultation and comment period, which ended on April 28, 2011. This
comment is addressed below following the ancillary services discussion.
All comments received have been considered in the preparation of
this Rate Order.
Project Descriptions
The Post-1989 General Power Marketing and Allocation Criteria,
published in the Federal Register on January 31, 1986 (51 FR 4012),
integrated the resources of the P-SMBP--WD and Fry-Ark. This
operational and contractual integration, known as LAP, allowed an
increase in marketable resources, simplified contract administration,
and established a blended rate for LAP power sales. WACM offers
Ancillary Services from a combination of all LAP generation resources
and some CRSP generation resources.
P-SMBP--WD
The P-SMBP was authorized by Congress in section 9 of the Flood
Control Act of December 22, 1944 (Pub. L. 534, 58 Stat. 877, 891). This
multipurpose program provides flood control, M&I water supply,
irrigation, navigation, recreation, preservation and enhancement of
fish and wildlife, and hydroelectric power. Multipurpose projects have
been developed on the Missouri River and its tributaries in Colorado,
Montana, Nebraska, North Dakota, South Dakota, and Wyoming.
In addition to the multipurpose water projects authorized by
section 9 of the Flood Control Act of 1944, certain other existing
projects have been integrated with the P-SMBP for power marketing,
operation, and repayment purposes. The Colorado-Big Thompson, Kendrick,
Riverton, and Shoshone Projects were combined with P-SMBP in 1954,
followed by the North Platte Project in 1959. These projects are known
as the ``Integrated Projects'' of the P-SMBP. The Riverton Project was
reauthorized as a unit of the P-SMBP in 1970. Together, the P-SMBP--WD
and the Integrated Projects have 19 power plants.
There are six power plants in P-SMBP--WD: Glendo, Kortes, and
Fremont Canyon power plants on the North Platte River; Boysen and Pilot
Butte power plants on the Wind River; and Yellowtail power plant on the
Big Horn River. The Colorado-Big Thompson Project has six power plants:
Green Mountain power plant on the Blue River is on the West Slope of
the Continental Divide; and Mary's Lake, Estes, Pole Hill, Flatiron,
and Big Thompson power plants along the Big Thompson River are on the
East Slope of the Continental Divide. The Kendrick Project has two
power plants: Alcova and Seminoe power plants on the North Platte
River. Power plants in the Shoshone Project are the Shoshone, Buffalo
Bill, Heart Mountain, and Spirit Mountain plants on the Shoshone River.
The only power plant in the North Platte Project is the Guernsey power
plant, also on the North Platte River.
Fry-Ark
Fry-Ark is a trans-mountain diversion development in southeastern
Colorado authorized by the Act of Congress on August 16, 1962 (Pub. L.
87-590, 76 Stat. 389, as amended by Title XI of the Act of Congress on
October 27, 1974 (Pub. L. 93-493, 88 Stat. 1486, 1497)). The Fry-Ark
diverts water from the Fryingpan River and other tributaries of the
Roaring Fork River in the Colorado River Basin on the West Slope of the
Rocky Mountains to the Arkansas River on the East Slope. The water
diverted from the West Slope, together with regulated Arkansas River
water, provides supplemental irrigation and M&I water supplies and
produces hydroelectric power. Flood control, fish and wildlife
enhancement, and recreation are other important purposes of Fry-Ark.
The only generating facility in Fry-Ark is the Mt. Elbert Pumped-
Storage power plant on the East Slope.
CRSP
CRSP was authorized by the Colorado River Storage Project Act, ch.
203, 70 Stat. 105, on April 11, 1956. The project provides water-use
developments for states in the Upper Basin (Colorado, New Mexico, Utah,
and Wyoming) while still maintaining water deliveries to the states of
the Lower Basin (Arizona, California, and Nevada) as required by the
Colorado River Compact of 1922. CRSP hydroelectric facilities providing
ancillary services for WACM are the Aspinall power plant (formerly
Curecanti) on the Gunnison River, the Flaming Gorge power plant on the
Green River, the Towaoc Power Plant on the Towaoc Canal in southwestern
Colorado, and the Glen Canyon power plant on the Colorado River.
LAP Transmission Service
Transmission formula rates, including those for Firm and Non-Firm
Point-To-Point Transmission Service and Network Integration
Transmission Service, are designed to recover the annual costs of the
LAP Transmission System. The transmission rates include the cost of
Scheduling, System Control, and Dispatch Service. Western will continue
to bundle transmission service for delivery of LAP long-term firm
Federal power to Federal Customers in the firm electric service rate
under existing Firm Electric Service Contracts that expire in 2024.
The penalty for unauthorized use of transmission, currently
assessed under the Point-to-Point Transmission rate schedules, will now
be assessed as a penalty for unreserved use under a separate rate
schedule, L-UU1. Unreserved Use Penalties will include the basic rate
for the transmission service used and not reserved, plus a penalty
equal to the basic rate.
Transmission losses are assessed for all real-time and prescheduled
transactions on transmission facilities inside WACM. The current loss
factor, as posted on the RMR OASIS, is 4.5 percent.
WACM Ancillary Services
Western will offer seven Ancillary Services pursuant to its Tariff.
The seven Ancillary Services are: (1) Scheduling, System Control, and
Dispatch Service (SSCD Service); (2) Reactive Supply and Voltage
Control from Generation or Other Sources Service (VAR Support Service);
(3) Regulation and Frequency Response Service (Regulation Service); (4)
Energy Imbalance Service; (5) Spinning Reserve Service; (6)
Supplemental Reserve Service; and (7) Generator Imbalance Service.
Generator Imbalance Service, currently provided as part of Rate
Schedule L-AS4 for Energy Imbalance Service, is a new service under the
Tariff. The Ancillary Services formula rates are designed to recover
only the
[[Page 61188]]
costs incurred for providing the service(s).
Comparison of Existing and Provisional Formula Rates for Transmission
and Ancillary Services
The following table displays a comparison of existing formula rates
and the Provisional Formula Rates for FY 2012. These rates will be
recalculated annually based on updated financial, schedule, and load
data.
Formula Rate Comparison Table
----------------------------------------------------------------------------------------------------------------
Provisional Formula Rates Effective Existing Formula Rates Effective October
Class of Service October 1, 2011 (FY 2012) 1, 2010 (FY 2011)
----------------------------------------------------------------------------------------------------------------
Network Integration L-NT1 L-NT1
Transmission Service Load ratio share of 1/12 of the revenue Load ratio share of 1/12 of the revenue
requirement of $56,775,913. requirement of $48,000,660.
----------------------------------------------------------------------------------------------------------------
Firm Point-to-Point L-FPT1 L-FPT1
Transmission Service $3.48/kW-month $3.18/kW-month
Unauthorized Use Penalty of 150% of
demand charge, with a maximum of
monthly service.
----------------------------------------------------------------------------------------------------------------
Non-Firm Point-to-Point L-NFPT1 L-NFPT1
Transmission Service Maximum of 4.77 mills/kWh Maximum of 4.17 mills/kWh
Unauthorized Use Penalty of 150% of
demand charge, with a maximum of
monthly service.
----------------------------------------------------------------------------------------------------------------
Unreserved Use Penalties L-UU1 Provided Under Rate Schedules L-FPT1 and
Penalized 200% of demand charge, with a L-NFPT1 as Unauthorized Use.
maximum of monthly service.
----------------------------------------------------------------------------------------------------------------
Transmission Losses Service L-AS7 L-AS7
Transmission losses may be settled Transmission losses may be settled
either financially or with energy. either financially or with energy.
Insufficient losses supplied will be Insufficient losses supplied will be
settled financially by default. settled financially by default.
All customers will have the option to All customers will have the option to
return the loss obligation for both return the loss obligation for both
prescheduled and real-time transactions prescheduled and real-time transactions
7 days later, same profile. 7 days later, same profile.
Pricing used is WACM weighted average Pricing used is LAP weighted average
hourly purchase price. hourly real-time purchase price.
Current loss factor as posted is 4.5%. Current loss factor as posted is 4.5%.
Scheduling, System Control, L-AS1 L-AS1
and Dispatch Service $24.22 per schedule per day for non- $38.30 per tag per day for non-
Federal transmission customers. Not Federal transmission customers.
applicable to schedules for delivery of Applicable to all tags.
Losses to WACM.
----------------------------------------------------------------------------------------------------------------
Reactive Supply and Voltage L-AS2 L-AS2
Control from Generation or $0.305/kW-month $0.180/kW-month
Other Sources Service
----------------------------------------------------------------------------------------------------------------
Regulation and Frequency L-AS3 L-AS3
Response $0.331/kW-month $0.339/kW-month
----------------------------------------------------------------------------------------------------------------
Energy Imbalance Service L-AS4 L-AS4
--Imbalances less than or equal to 1.5% --Imbalances less than or equal to 5%
(minimum 4 MW) of metered load settled (minimum 4 MW) of metered load settled
using WACM hourly pricing with no using WACM hourly pricing with no
penalty. penalty.
--Imbalances between 1.5% and 7.5% --Imbalances greater than 5% of metered
(minimum 4 MW to 10 MW) of metered load load settled using WACM hourly pricing
settled using WACM hourly pricing with with a 10% penalty.
a 10% penalty.
--Imbalances greater than 7.5% (minimum --WACM aggregate imbalance dictates
10 MW) of metered load settled using pricing in no-penalty band. Customer
WACM hourly pricing with a 25% penalty. imbalance dictates pricing in penalty
--WACM aggregate imbalance determines band (surpluses indicate sale pricing,
pricing in all bands--aggregate surplus deficits indicate purchase pricing).
dictates sale pricing, aggregate --Intermittent resources not subject to
deficit dictates purchase pricing. penalties.
----------------------------------------------------------------------------------------------------------------
Operating Reserve Service-- L-AS5, L-AS6 L-AS5, L-AS6
Spinning and Supplemental Long-term Reserves are not available Long-term Reserves are not available
from WACM. Reserves may be acquired and from WACM. Reserves may be acquired and
provided at pass-through cost, plus an provided at pass-through cost, plus an
amount for administration. amount for administration.
----------------------------------------------------------------------------------------------------------------
[[Page 61189]]
Generator Imbalance Service L-AS9 Provided under Rate Schedule L-AS4.
--Imbalances less than or equal to 1.5%
(minimum 4 MW) of metered generation
settled using WACM hourly pricing with
no penalty.
--Imbalances between 1.5% and 7.5%
(minimum 4 MW to 10 MW) of metered
generation settled using WACM hourly
pricing with a 10% penalty.
--Imbalances greater than 7.5% (minimum
10 MW) of metered generation settled
using WACM hourly pricing with a 25%
penalty.
--Intermittent resources not subject to
25% penalties.
--WACM aggregate imbalance determines
pricing in all bands--aggregate surplus
dictates sale pricing, aggregate
deficit dictates purchase pricing.
----------------------------------------------------------------------------------------------------------------
Certification of Rates
Western's Administrator certified that the Provisional Formula
Rates for LAP Transmission and WACM Ancillary Services under Rate
Schedules L-NT1, L-FPT1, L-NFPT1, L-AS1, L-AS2, L-AS3, L-AS4, L-AS5, L-
AS6, L-AS7, L-AS9, and L-UU1 are the lowest possible rates consistent
with sound business principles. The Provisional Formula Rates were
developed following administrative policies and applicable laws.
LAP Transmission Service Discussion
Network Integration Transmission Service
The monthly charge for Network Integration Transmission Service for
the Transmission Customer will be as follows:
[GRAPHIC] [TIFF OMITTED] TN03OC11.000
The customer's load-ratio share is the ratio of its network load to the
LAP Transmission System Total Load at the LAP system peak. This is
calculated on a rolling 12-month average (12 coincident peak average or
12-cp).
Firm Point-to-Point Transmission Service
The formula rate for Firm Point-to-Point Transmission Service is as
follows:
[GRAPHIC] [TIFF OMITTED] TN03OC11.001
The rates for FY 2012 are as follows:
[GRAPHIC] [TIFF OMITTED] TN03OC11.002
Discussions of the ATRR and the LAP Transmission System Total Load
are located below.
Non-Firm Point-to-Point Transmission Service
The maximum Non-Firm Point-to-Point Transmission Service formula
rate is the same as the Firm Point-to-Point Transmission Service rate.
Non-Firm Point-to-Point Transmission Service is available for periods
ranging from 1 hour to 1 year.
Maximum Hourly Non-Firm Rate: 4.77 mills/kW of reserved capacity per
hour
[[Page 61190]]
Annual Transmission Revenue Requirement
The ATRR is applicable to both Network and Point-to-Point
Transmission Service. The ATRR is the annual cost of the LAP
Transmission System, adjusted for revenue credits, costs that increase
the capacity available for transmission, other miscellaneous charges or
credits, and the prior year true-up. The formula, with amounts
calculated for the FY 2012 rate, is as follows:
[GRAPHIC] [TIFF OMITTED] TN03OC11.003
The annual cost of the LAP Transmission System is the ratio of
gross investment cost for transmission facilities to gross investment
cost for all facilities multiplied by the total annual costs for all
facilities. Total annual costs include operations and maintenance,
interest, and depreciation expenses. The calculation, with amounts for
FY 2012, is as follows:
[GRAPHIC] [TIFF OMITTED] TN03OC11.004
The source for the annual costs is the formalized work plans for FY
2012 and the FY 2010 Results of Operations for P-SMBP--WD, with certain
items adjusted for projected asset capitalization or historical trends.
See discussion below on ``Change to Forward-Looking Transmission
Rates.''
The gross investment cost for transmission facilities is determined
by an analysis of the LAP Transmission System. Each LAP facility is
classified by function: transmission, sub-transmission, distribution,
or generation-related. The facilities identified as performing the
function of transmission include all transmission lines that are
normally operated in a continuously-looped manner and the associated
substations and switchyard facilities. In the LAP Transmission System,
these are primarily the 115-kV and the 230-kV transmission lines. In
addition, portions of the communication, maintenance, and
administration facilities are included in the investment costs for
transmission. Only the investment costs of the facilities identified as
``transmission'', including allocated costs for communication,
maintenance, and administration facilities, are used in developing the
annual cost of the transmission system. The investment costs of
facilities identified as ``sub-transmission'' and ``distribution'' are
excluded from the ATRR, as the LAP sub-transmission and distribution
systems are used primarily for delivery of Federal power to Federal
Customers. If a Transmission Customer requires the use of the sub-
transmission or distribution systems, an additional facility-use charge
will be assessed. All Fry-Ark costs are considered generation-related
and, therefore, are excluded from the ATRR.
System augmentation expense includes payments made to others for
their systems' augmentation of the LAP Transmission System.
Miscellaneous charges and credits will include, but will not be limited
to, Unreserved Use Penalties and facility use charges for transmission
facility investments included in the revenue requirement. For a
description of the prior year true-up, see discussion below on ``Change
to Forward-Looking Transmission Rates.''
[[Page 61191]]
Change to Forward-Looking Transmission Rates
Western has changed the method it uses to calculate the ATRR to
recover transmission expenses and investments on a current basis rather
than a historical basis. The change allows Western to more accurately
match cost recovery with cost incurrence. Western will use projections
to estimate transmission costs and load for the upcoming year in the
annual rate calculation, rather than using historical information. The
method is a change in the manner in which the inputs for the rate are
developed, rather than a change to the formula rate itself. When actual
cost information for a year becomes available, Western will calculate
the actual revenue requirement for that year. Revenue collected in
excess of the actual revenue requirement will be included as a credit
in the ATRR in a subsequent year. Similarly, any under-collection of
the revenue requirement will be included as a charge in the ATRR in a
subsequent year. This true-up procedure will ensure that Western
recovers no more and no less than the actual transmission costs for any
year. For example, as FY 2012 actual financial data becomes available
during FY 2013, the under- or over-collection of revenue during FY 2012
can be determined. When the rates are recalculated for FY 2014, the
implemented rates will include an adjustment for revenue under- or
over-collected in FY 2012.
Transmission System Total Load for Point-to-Point Service
The LAP Transmission System Total Load is a 12-month average of the
sum of (1) all Network Integration Transmission Service customer loads
in excess of deliveries of Federal Entitlements, measured at the
monthly LAP Transmission System peak hour, plus (2) the monthly
entitlements of Federal Customers, plus (3) the reserved capacity for
Long-Term Firm Point-to-Point Transmission Service. This load
calculation is prepared once annually and is used to calculate the
point-to-point rates for the entire year.
The LAP Transmission System Total Load is calculated as follows,
based upon data projected for FY 2012:
Federal Customers....................................... 604,639 kW
Network Transmission Customers.......................... 743,818 kW
---------------
Subtotal.............................................. 1,348,457 kW
Point-to-Point Reserved Capacity........................ 9,885 kW
---------------
LAP Transmission System Total Load...................... 1,358,342 kW
Unreserved Use Penalties
Unreserved use of the transmission system (Unreserved Use) occurs
when a Transmission Customer uses transmission service that exceeds its
reserved capacity or an eligible customer uses transmission service
that it has not reserved. Western will assess Unreserved Use Penalties
against a customer that has not secured reserved capacity or exceeds
its reserved capacity at any point of receipt or any point of delivery.
Unreserved Use may also include a Transmission Customer's failure to
curtail transmission when requested.
A customer that engages in Unreserved Use will be assessed a
penalty charge of 200 percent of LAP's approved transmission service
rate for Firm Point-to-Point Transmission Service as follows:
(1) The Unreserved Use penalty for a single hour of Unreserved Use
will be based upon the rate for daily Firm Point-to-Point Service.
(2) 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).
(3) The Unreserved Use penalty charge for multiple instances of
Unreserved Use (e.g., more than one hour) within a day will be based on
the rate for daily Firm Point-to-Point Service. Multiple instances of
Unreserved Use isolated to one calendar week will result in a penalty
based on the charge for weekly Firm Point-to-Point Service. The penalty
charge for multiple instances of Unreserved Use during more than one
week during a calendar month will be 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 will be required to pay, in addition to the
Unreserved Use Penalties, for all applicable Ancillary Services
identified in Western's Tariff based on the amount of transmission
service it used and did not reserve.
Unreserved Use Penalties collected over and above the base Point-
to-Point Transmission Service rate will be included as a credit in the
calculation of the ATRR in a subsequent year.
Transmission Losses Service
Transmission Losses are assessed for all real-time and prescheduled
transactions on transmission facilities inside WACM. In the case of
Network Integration Transmission Service Customers, transmission and
transformer Losses applicable under customers' respective contracts are
calculated as part of the customers' Energy Imbalance Service
settlements. Other customers are allowed the option of financial
settlement or energy repayment. Energy repayment is either concurrently
or 7 days later, to be delivered using the same profile as the related
transmission transaction. When a transmission loss energy obligation is
not provided (or is under-provided) by a customer for a transmission
transaction, the energy still owed for Losses is calculated and a
charge is assessed to the customer, based on the WACM weighted average
hourly purchase price. The loss factor, currently 4.5 percent, is
updated periodically and posted on the RMR OASIS Web site.
Transmission Service Comments
RMR received no comments concerning transmission service,
Unreserved Use Penalties, or Transmission Losses during the public
consultation and comment period.
Ancillary Services Discussion
Pursuant to Western's Tariff, WACM will offer seven Ancillary
Services. Two of these services, SSCD Service and VAR Support Service,
are services that, under Western's Tariff, the Transmission Provider is
required to provide (or offer to arrange with the Balancing Authority
operator) and the Transmission Customer is required to purchase.
The other five Ancillary Services, Regulation Service, Energy
Imbalance Service, Generator Imbalance Service, Operating Reserve--
Spinning Reserve Service, and Operating Reserve--Supplemental Reserve
Service, are services that the Transmission Provider is required to
offer to provide to the Transmission Customer. The Transmission
Customer is required to acquire these Ancillary Services, either from
the Transmission Provider or from a third party, or to self-supply
them.
Scheduling, System Control, and Dispatch Service
The formula for SSCD Service, with amounts shown for FY 2012, is as
follows:
[[Page 61192]]
[GRAPHIC] [TIFF OMITTED] TN03OC11.005
This rate recovers the annual expenses associated with
transmission scheduling. The annual cost of scheduling personnel and
related costs is comprised of annual expenses for personnel,
facilities, equipment, and software, as well as credits representing
fees for agent services and unscheduled flow mitigation services. This
revenue requirement is divided by the number of schedules (excluding
schedules for delivery of losses to WACM) per year to derive a rate per
schedule per day.
Per Schedule 1 of Western's Tariff, ``this service can be provided
only by the operator of the Control Area in which the transmission
facilities used for transmission service are located.'' In cases in
which the Transmission Provider (LAP and/or CRSP) directly provides the
service as the Control Area operator, the costs for this service are
bundled in the respective Federal transmission rate. In cases in which
the Transmission Providers on the schedules are not the operator, WACM
indirectly performs this service for those Transmission Providers'
transmission systems. Western has historically invoiced the last
Transmission Provider that is inside WACM on the schedule. Since all
non-Federal Transmission Providers are indirectly taking this service
from WACM, Western will allocate the cost of each schedule equally
among all Transmission Providers (Federal and non-Federal) listed on
the schedule that are inside WACM. The Federal transmission segments
will be exempt from invoicing, as costs for these segments will
continue to be included in the Federal (LAP and CRSP) transmission
service rates.
Western will not include schedules for delivery of transmission
losses to WACM in the calculation of the rate and will not invoice for
them, so that entities delivering losses may create individual loss
schedules associated with specific transactions without charge. Western
will accept any number of schedule changes over the course of a day,
without additional charge, so that entities attempting to follow their
loads closely may do so without penalty.
Reactive Supply and Voltage Control from Generation or Other Sources
Service
The formula for VAR Support Service is the following:
[GRAPHIC] [TIFF OMITTED] TN03OC11.006
TARRG = Total Annual Revenue Requirement for Generation
% of Resource = Percentage of Resource Used for VAR Support
The numerator captures the percentage of annual generation plant
costs that are used for this service. Most of the LAP generation
plant facilities are owned and operated by Reclamation, but Western
has some facilities that are considered generation-related. Net
generation plant costs are multiplied by a fixed charge rate (FCR)
for generation to determine the TARRG, where
[GRAPHIC] [TIFF OMITTED] TN03OC11.007
The FCR is a methodology used to assign a portion of total expenses to
generation. Applying these formulas to FY 2010 data provides the
following results:
[[Page 61193]]
[GRAPHIC] [TIFF OMITTED] TN03OC11.008
Applying this percentage to the amount of net generation plant
investment results in the TARRG:
TARRG = $334,166,538 x 17.847% = $59,638,020
The percentage of the TARRG that is included in the revenue
requirement is based on the nameplate capability of the generating
units with regard to reactive and real power production. The TARRG is
multiplied by the complement of the weighted average power factor
rating for generating units. The weighted average power factor rating
for the LAP generating units is 94.77 percent, so the revenue
requirement for this rate includes 5.23 percent of the TARRG. The
portion of the revenue requirement contributed by LAP plant costs is as
follows:
LAP Plant Costs = $59,638,020 x 5.2284% = $3,118,089
Plant costs for CRSP plants providing VAR Support Service are
calculated using identical methodology. The contribution to the revenue
requirement from CRSP plants is $1,539,255. The total revenue
requirement, after adjusting for a small amount of VAR Support Service
revenue on point-to-point transmission transactions not in the rate
design, is as follows:
LAP Plant Costs......................................... $3,118,089
CRSP Plant Costs........................................ $1,539,255
PTP Revenue............................................. $(53,525)
---------------
Revenue Requirement..................................... $4,603,819
The load taking this service totals 1,258,524 kW, resulting in a
proposed rate for FY 2012 of:
[GRAPHIC] [TIFF OMITTED] TN03OC11.009
The rate is applicable to all transmission transactions inside WACM
in excess of any Federal Entitlements. For Federal Entitlements, the
cost for this service will be included in the firm electric service
rates. Customers with generators providing WACM with VAR Support
Service may be excluded from the application of this rate. Any such
exclusion must be documented in the customer's Service Agreement.
Regulation and Frequency Response Service
The formula rate for Regulation Service has two different
applications:
1. Load-based Assessment. The formula for the Load-based Assessment
is as follows:
[GRAPHIC] [TIFF OMITTED] TN03OC11.010
The rate applies to all entities' auxiliary load (total metered load
less Federal Entitlements) and also to the installed nameplate capacity
of intermittent generators serving load inside WACM.
The revenue requirement will include costs such as plant costs,
purchases of a regulation product, purchases of power in support of the
generating units' ability to regulate, purchases of transmission for
regulating units that are trapped geographically inside another
balancing authority, purchases of transmission required to relocate
energy due to regulation/load following issues, and lost sales
opportunities resulting from the requirement to generate at night to
permit units to have ``down'' regulating capability.
The methodology for determining annual plant costs is as follows.
First, the annual costs for plants used to regulate is calculated by
multiplying the net plant costs by the FCR for generation.
Annual Costs = 17.847% x $159,716,812
Annual Costs = $28,504,334
Then, the annual cost per unit of capacity for regulating plants is
calculated by dividing the annual costs for regulating plants by the
capacity of those plants:
[[Page 61194]]
[GRAPHIC] [TIFF OMITTED] TN03OC11.011
Next, the portion of the total annual plant costs to be recovered in
the Regulation Service rate is calculated by multiplying the annual
unit cost by the amount of capacity required for regulation. The
capacity required for regulation is subject to re-evaluation every
year. Current analyses indicate that 75 MW of capacity will be required
for WACM Regulation Service for FY 2012. Of this total, 55 MW will be
supplied by LAP plants and 20 MW will be supplied by CRSP plants.
Regulating Plant Costs (LAP) = $60.32 x 55,000 kW
Regulating Plant Costs (LAP) = $3,317,614
CRSP regulating plant costs are calculated in a similar manner.
Inserting this and other financial data for FY 2010 into the formula
results in the following Revenue Requirement:
LAP Plant Costs......................................... $3,317,614
Purchase Power Costs in Support of Regulation........... 5,049,193
Lost Sales Opportunities from having to generate in off- 1,320,110
peak hours.............................................
Transmission Costs for Trapped Regulating Units......... 1,042,800
Purchases of Transmission............................... 52,598
CRSP Plant Costs........................................ 590,429
---------------
Annual Revenue Requirement............................ 11,372,744
The load inside WACM requiring Regulation Service and the installed
nameplate capacity of intermittent resources serving load inside WACM
are 2,791,390 kW and 73,220 kW, respectively.
[GRAPHIC] [TIFF OMITTED] TN03OC11.012
2. Self-Provision Assessment. Western allows entities with AGC to self-
provide for all or a portion of their loads. Entities with AGC are
known as Sub-Balancing Authorities (SBA) and must meet all of the
following criteria:
a. Have a well-defined boundary, with WACM-approved revenue-quality
metering, accurate as defined by NERC, to include MW flow data
availability at 6-second or smaller intervals;
b. Have AGC capability; and
c. Have demonstrated Regulation Service capability.
Self-provision will be measured by use of the entity's 1-minute
average ACE to determine the amount of self-provision. The ACE will be
used to calculate Regulation Service charges every hour as follows:
a. If the entity's 1-minute average ACE for the hour is less than
or equal to 0.5 percent of its hourly average load, no Regulation
Service charges will be assessed by WACM.
b. If the entity's 1-minute average ACE for the hour is greater
than or equal to 1.5 percent of its hourly average load, WACM will
assess full Regulation Service charges using the Load-based Assessment
applied to the entity's 12-cp load for that month.
c. If the entity's 1-minute average ACE for the hour is greater
than 0.5 percent of its hourly average load, but less than 1.5 percent
of its hourly average load, WACM will assess Regulation Service charges
based on linear interpolation of zero charge and full charge, using the
Load-based Assessment applied to the entity's 12-cp load for that
month.
d. Western will monitor the entity's self-provision on a regular
basis. If Western determines that the entity has not been attempting to
self-regulate, Western will, upon notification, employ the full Load-
based Assessment described above.
Alternative Arrangements
1. Exporting Intermittent Resource Requirement: An entity that
exports the output from an intermittent generator to another Balancing
Authority will be required to dynamically meter or dynamically schedule
that resource out of WACM to another Balancing Authority unless
arrangements, satisfactory to Western, are made for that entity to
acquire this service from a third party or self-supply (as outlined
below). An intermittent generator is one that is volatile and variable
due to factors beyond direct operational control and, therefore, is not
dispatchable.
2. Self- or Third-party supply: Western may allow an entity to
supply some or all of its required regulation, or contract with a third
party to do so, even without well-defined boundary metering. This
entity must have revenue quality metering at every load and generation
point, accurate as defined by NERC, to include MW flow data
availability at 6-second or smaller intervals. WACM will evaluate the
entity's metering, telecommunications and regulating resource, as well
as the
[[Page 61195]]
required level of regulation, and determine whether the entity
qualifies to self-supply under this provision. If approved, the entity
will be required to enter into a separate agreement with Western, which
will specify the terms of the self-supply application.
Energy Imbalance Service
WACM provides Energy Imbalance Service using a penalty and
bandwidth structure with three deviation bands as follows. The term
``metered load'' is defined to be ``metered load adjusted for losses.''
1. An imbalance of less than or equal to 1.5 percent of metered
load (or 4 MW, whichever is greater) for any hour will be settled
financially at 100 percent of the WACM weighted average hourly price.
Each hour will stand on its own--there will be no monthly netting.
2. An imbalance between 1.5 percent and 7.5 percent of metered load
(or 4 to 10 MW, whichever is greater) for any hour will be settled
financially at 90 percent of WACM weighted average hourly price when
net energy scheduled exceeds metered load or 110 percent of the WACM
weighted average hourly price when net energy scheduled is less than
metered load.
3. An imbalance greater than 7.5 percent of metered load (or 10 MW,
whichever is greater) for any hour will be settled financially at 75
percent of the WACM weighted average hourly price when net energy
scheduled exceeds metered load or 125 percent of the WACM weighted
average hourly price when net energy scheduled is less than metered
load.
Aggregate Imbalance, Pricing, and Settlement
All Energy Imbalance Service provided by WACM will be accounted for
hourly and settled financially after the end of each month. The WACM
aggregate imbalance will determine the pricing used in all settlements,
including those subject to a penalty. For each hour, the gross energy
imbalance for all entities inside WACM will be totaled/netted to
determine an aggregate energy imbalance for WACM. The sign of the
aggregate energy imbalance will determine whether WACM sale or purchase
pricing will be used for settling imbalances in that hour. A calculated
surplus will dictate the use of sale pricing; a calculated deficit will
dictate the use of purchase pricing.
When there are no real-time sales or purchases within an hour,
pricing defaults will be applied in the following order:
1. Weighted average sale or purchase pricing for the day (on- and
off-peak).
2. Weighted average sale or purchase pricing for the current month
(on- and off-peak).
3. Weighted average sale or purchase pricing for the prior month
(on- and off-peak).
4. Weighted average sale or purchase pricing for the month
immediately prior to the prior month (and continuing in this manner
until sale or purchase pricing is located) (on- and off-peak).
Expansion of the Bandwidth
Expansion of the bandwidth may be done to accommodate the
following: (1) Response to physical resource loss; (2) transition of
large thermal resources. Details are as follows:
1. Western will expand the bandwidth during an event established by
a Western-recognized reserve-sharing group, such as the Rocky Mountain
Reserve Group. A response made by a member of the reserve group will be
accounted for by an after-the-fact schedule. Normally, these events are
1-2 hours in duration. Since the after-the-fact schedule replaces lost
generation, no expansion will be necessary for the entity receiving the
response. The expanded bandwidth will apply to the customer that
increased generation in response to the event and will be based on the
magnitude of that customer's generation response.
2. During transition of large base-load thermal resources (capacity
greater than 200 MW) between off-line and on-line following a reserve
sharing group response, Western may expand the bandwidth to eliminate
all penalties during hours in which the unit generates less than the
predetermined minimum scheduling level. Western may not have access to
information necessary to determine these hours for some generators and
will not have access to information on events for reserve sharing
groups outside RMR. Customers should request bandwidth expansion in
hours in which they believe it to be warranted. Western may request
additional information for its decision as to whether to grant the
request. Bandwidth will not be expanded when ramping services have been
acquired by another entity.
Balancing Authority Operating Constraints
Western reserves the right to offer no credit for Energy Imbalance
Service over-deliveries during times of WACM operating constraints,
such as ``must-run'' hydrologic conditions, or times when WACM cannot
dispose of surplus energy. Due to the unpredictable nature of hour-to-
hour energy imbalances and the very short notice for disposition of
over-deliveries, WACM may experience some hours of zero-value sales and
may eliminate credits in these hours.
If WACM is unable to dispose of the entire net over-delivery and
operating criteria for the Balancing Authority are not met, there may
be financial sanctions to Western from reliability oversight agencies,
such as NERC or WECC. In these cases, credits to customers will be
eliminated and customers over-delivering may share in the cost of the
sanction. Also, there may be conditions under which customers who
under-deliver may share in any sanctions imposed on Western by
reliability oversight agencies.
Generator Imbalance Service
WACM will provide Generator Imbalance Service to the following
customers:
1. Jointly-owned generators whose output is shared by several
entities. At the written request of all entities who jointly own the
generator's output, WACM will accept allocations of the generation
among the participants. In this situation, a participant's share of
actual generation will be included in its separate Energy Imbalance
calculation.
2. Intermittent generators. At the written request of the customer,
WACM will include the intermittent generator(s) in the customer's
Energy Imbalance calculation. The customer makes this choice with the
understanding that the intermittent generator will be subject to 3rd
band (25 percent) penalties (see formula rate details below).
3. Non-intermittent generators serving load only outside WACM.
An entity's solely-owned non-intermittent generator serving load
inside WACM will be included in its Energy Imbalance Service
calculation.
WACM will provide Generator Imbalance Service using a penalty and
bandwidth structure with three deviation bands as follows:
1. An imbalance of less than or equal to 1.5 percent of metered
generation (or 4 MW, whichever is greater) for any hour is settled
financially at 100 percent of the WACM weighted average hourly price.
2. An imbalance between 1.5 percent and 7.5 percent of metered
generation (or 4 to 10 MW, whichever is greater) for any hour is
settled financially at 90 percent of the WACM weighted average hourly
price when actual generation exceeds scheduled generation or 110
percent of the WACM weighted average hourly price when actual
generation is less than scheduled generation.
3. An imbalance greater than 7.5 percent of metered generation (or
10
[[Page 61196]]
MW, whichever is greater) for any hour is settled financially at 75
percent of the WACM weighted average hourly price when actual
generation exceeds scheduled generation or 125 percent of the WACM
weighted average hourly price when actual generation is less than
scheduled generation.
Intermittent generators will be exempt from the 25 percent penalty
band. All imbalances greater than 1.5 percent of metered generation for
an intermittent generator will be subject only to a 10 percent penalty.
The features of Energy Imbalance Service described above under
Aggregate Imbalance, Pricing, and Settlement, Expansion of the
Bandwidth, and Balancing Authority Operating Constraints, also apply to
Generator Imbalance Service.
Penalty Elimination
In any hour, Western will charge a customer a penalty for either
Generator Imbalance Service or Energy Imbalance Service, but not both,
unless the imbalances aggravate rather than offset each other. In an
hour in which penalties on offsetting imbalances would exist based on
the separate imbalance calculations, Western will remove the penalty
from the Generator Imbalance calculation. There will be no penalty
elimination for jointly-owned generators whose participants have a
separate Energy Imbalance calculation.
Administrative Charge
In the Notice of Proposed Rates (76 FR 5148), Western proposed to
assess an administrative charge on each monthly settlement under both
Energy Imbalance and Generator Imbalance Services. After further
analysis and customer input, Western has decided not to implement an
administrative charge under either service.
Operating Reserve--Spinning and Supplemental
WACM has no long-term Reserves available for sale. At a customer's
request, WACM will purchase and pass through the cost of Reserves and
any activation energy, plus a fee for administration. For all Reserves
purchased, the customer will be responsible for providing the
transmission to deliver the Reserves.
Ancillary Services Comments
Western received one written comment concerning the Ancillary
Services during the public consultation and comment period. This
comment has been paraphrased where appropriate, without compromising
the meaning of the comment.
Comment: The customer requested that, for Regulation Service,
rather than requiring an intermittent generator that exports its output
to dynamically meter or dynamically schedule the generation out of
WACM, Western open communications to pursue other options to avoid this
requirement. The customer expressed concern about the cost of
implementing this requirement and the effects the unexpected costs will
have on member municipalities and their customers. The customer also
noted that these additional costs were not known at the inception of
its existing projects when cost analyses were being performed.
Response: Western thanks the customer for its comment. As noted
above under Regulation and Frequency Response Service (Alternative
Arrangements), Western has included as a part of the Regulation Service
rate schedule, a condition under which an exporting intermittent
generator will not have to be dynamically removed from WACM. Under this
condition, the entity must make arrangements, satisfactory to Western,
to acquire Regulation and Frequency Response Service from a third party
or self-supply it. Western believes that this is a reasonable
requirement that will not place an undue burden on existing or
potential customers who will export intermittent generation from WACM,
but will support the concept in Western's Tariff that WACM is required
to provide Ancillary Services only for Load-Serving Entities.
Availability of Information
All brochures, studies, comments, letters, memorandums, or other
documents that Western used to develop the Provisional Formula Rates
are available for inspection and copying at the Rocky Mountain Regional
Office, located at 5555 East Crossroads Boulevard, Loveland, Colorado.
Many of these documents and supporting information are also available
on Western's Web site under the ``2012 Rate Adjustment--Transmission
and Ancillary Services'' section located at http://www.wapa.gov/rm/ratesRM/2012/default.htm.
Ratemaking Procedure Requirements
Environmental Compliance
In compliance with the National Environmental Policy Act (NEPA) of
1969 (42 U.S.C. 4321 et seq.), Council on Environmental Quality
Regulations (40 CFR parts 1500-1508), and DOE NEPA Regulations (10 CFR
part 1021), Western has determined that this action is categorically
excluded from preparing an environmental assessment or an environmental
impact statement.
Determination Under Executive Order 12866
Western has an exemption from centralized regulatory review under
Executive Order 12866; accordingly, no clearance of this notice by the
Office of Management and Budget is required.
Submission to the Federal Energy Regulatory Commission
The formula rates herein confirmed, approved, and placed into
effect on an interim basis, together with supporting documents, will be
submitted to FERC for confirmation and final approval.
Order
In view of the foregoing, and under the authority delegated to me,
I confirm and approve on an interim basis, effective on the first full
billing period on or after October 1, 2011, formula rates for Loveland
Area Projects Transmission and Western Area Colorado Missouri Balancing
Authority Ancillary Services under Rate Schedules L-NT1, L-FPT1, L-
NFPT1, L-AS1, L-AS2, L-AS3, L-AS4, L-AS5, L-AS6, L-AS7, L-AS9, and L-
UU1. By this order, I am placing the rates into effect in less than 30
days to meet contract deadlines, to avoid financial difficulties, and
to provide rates for new services. These rate schedules shall remain in
effect on an interim basis, pending FERC's confirmation and approval of
them or substitute formula rates on a final basis through September 30,
2016.
Dated: September 2, 2011.
Daniel B. Poneman,
Deputy Secretary.
Rate Schedule L-AS1
Schedule 1 to Tariff
October 1, 2011
United States Department of Energy
Western Area Power Administration
Rocky Mountain Region
Western Area Colorado Missouri Balancing Authority
Scheduling, System Control, and Dispatch Service
Applicable
Scheduling, System Control, and Dispatch Service is required to
schedule the movement of power into, out of, inside, or through the
Western Area Colorado Missouri Balancing Authority (WACM). This service
must be purchased from the WACM operator. The rate will be applied to
all
[[Page 61197]]
schedules, except those for the delivery of transmission losses to
WACM.
Unless other arrangements are made with Western, the rate will be
divided equally among the transmission providers displayed in the
schedule that are inside WACM. The charges applicable to non-Federal
transmission will be assessed to those transmission providers. The
charges applicable to Federal transmission will be included in the
Federal transmission service rates.
WACM will accept any number of scheduling changes over the course
of the day without any additional charge.
Effective
The first day of the first full billing period beginning on or
after October 1, 2011, through September 30, 2016.
Formula Rate
[GRAPHIC] [TIFF OMITTED] TN03OC11.013
Rate
The rate to be in effect October 1, 2011, through September 30,
2012, is $24.22 per schedule per day. A revised rate will go into
effect October 1 of each year of the effective rate period based on the
formula above and updated financial and schedule data. Western will
notify the Customer annually of the revised rate before October 1.
Any change to the rate for Scheduling, System Control, and Dispatch
Service will be listed in a revision to this rate schedule issued under
applicable Federal laws, regulations, and policies and made part of the
applicable service agreement.
Rate Schedule L-AS2
Schedule 2 to Tariff
October 1, 2011
United States Department of Energy
Western Area Power Administration
Rocky Mountain Region
Western Area Colorado Missouri Balancing Authority
Reactive Supply and Voltage Control from Generation or Other Sources
Service
Applicable
To maintain transmission voltages on all transmission facilities
within acceptable limits, generation facilities under the control of
the Western Area Colorado Missouri Balancing Authority (WACM) are
operated to produce or absorb reactive power. Thus, Reactive Supply and
Voltage Control from Generation or Other Sources Service (VAR Support
Service) is provided for each transaction on the transmission
facilities. The amount of VAR Support Service supplied to the
Customer's (Federal Transmission Customers and customers on others'
transmission systems inside WACM) transactions will be based on the VAR
Support Service necessary to maintain transmission voltages within
limits that are generally accepted in the region and consistently
adhered to by WACM. The Customer must purchase this service from the
WACM operator.
Customers with generators providing WACM with VAR Support Service
may be excluded from the application of this rate. Any such exclusion
must be documented in the Customer's service agreement.
Effective
The first day of the first full billing period beginning on or
after October 1, 2011, through September 30, 2016.
Formula Rate
[GRAPHIC] [TIFF OMITTED] TN03OC11.014
[[Page 61198]]
Rate
The rate to be in effect October 1, 2011, through September 30,
2012, is:
------------------------------------------------------------------------
------------------------------------------------------------------------
Monthly $0.305/kW-month
Weekly $0.070/kW-week
Daily $0.010/kW-day
Hourly $0.000418/kWh
------------------------------------------------------------------------
A revised rate will go into effect October 1 of each year of the
effective rate period based on the formula above and updated financial
and load data. Western will notify the Customer annually of the revised
rate before October 1.
Any change to the rate for VAR Support Service will be listed in a
revision to this rate schedule issued under applicable Federal laws,
regulations, and policies and made part of the applicable service
agreement.
Rate Schedule L-AS3
Schedule 3 to Tariff
October 1, 2011
United States Department of Energy
Western Area Power Administration
Rocky Mountain Region
Western Area Colorado Missouri Balancing Authority
Regulation and Frequency Response Service
Applicable
Regulation and Frequency Response Service (Regulation Service) is
necessary to provide for the continuous balancing of resources with
obligations, and for maintaining scheduled interconnection frequency at
sixty cycles per second (60 Hz). Regulation Service is accomplished by
committing on-line generation whose output is raised or lowered as
necessary, predominantly through the use of automatic generation
control (AGC) equipment, to follow the moment-by-moment changes in
load. The obligation to maintain this balance between resources and
load lies with the Western Area Colorado Missouri Balancing Authority
(WACM) operator. Customers (Federal Transmission Customers and
customers on others' transmission systems inside WACM) must purchase
this service from WACM or make alternative comparable arrangements to
satisfy their Regulation Service obligations.
Types
There are two different applications of this Formula Rate:
1. Load-based Assessment: The rate for the load-based assessment is
reflected in the Formula Rate section and is applied to entities that
take Regulation Service from WACM. This load-based rate is assessed on
an entity's auxiliary load (total metered load less Federal
entitlements) and is also applied to the installed nameplate capacity
of all intermittent generators serving load inside WACM.
2. Self-provision Assessment: Western allows entities with AGC to
self-provide for all or a portion of their loads. Entities with AGC are
known as Sub-Balancing Authorities (SBA) and must meet all of the
following criteria:
a. Have a well-defined boundary, with WACM-approved revenue-quality
metering, accurate as defined by the North American Electric
Reliability Corporation (NERC), to include MW flow data availability at
6-second or smaller intervals;
b. Have AGC capability;
c. Demonstrate Regulation Service capability; and
d. Execute a contract with WACM:
i. Provide all requested data to WACM.
ii. Meet SBA error criteria as described under section 2.1 below.
2.1. Self-provision is measured by use of the entity's 1-minute average
Area Control Error (ACE) to determine the amount of self-provision. The
ACE is used to calculate the Regulation Service charges every hour as
follows:
a. If the entity's 1-minute average ACE for the hour is less than
or equal to 0.5 percent of its hourly average load, no Regulation
Service charge is assessed by WACM for that hour.
b. If the entity's 1-minute average ACE for the hour is greater
than or equal to 1.5 percent of its hourly average load, WACM assesses
Regulation Service charges to the entity's entire auxiliary load, using
the hourly Load-based Assessment applied to the entity's auxiliary 12-
cp load for that month.
c. If the entity's 1-minute average ACE for the hour is greater
than 0.5 percent of its hourly average load, but less than 1.5 percent
of its hourly average load, WACM assesses Regulation Service charges
based on linear interpolation of zero charge and full charge, using the
hourly Load-based Assessment applied to the entity's auxiliary 12-cp
load for that month.
d. Western monitors the entity's Self-provision on a regular basis.
If Western determines that the entity has not been attempting to self-
regulate, WACM will, upon notification, employ the Load-based
Assessment described in No. 1, above.
Alternative Arrangements
Exporting Intermittent Resource Requirement: An entity that exports
the output from an intermittent generator to another balancing
authority will be required to dynamically meter or dynamically schedule
that resource out of WACM to another balancing authority unless
arrangements, satisfactory to Western, are made for that entity to
acquire this service from a third party or self-supply (as outlined
below). An intermittent generator is one that is volatile and variable
due to factors beyond direct operational control and, therefore, is not
dispatchable.
Self- or Third-party supply: Western may allow an entity to supply
some or all of its required regulation, or contract with a third party
to do so, even without well-defined boundary metering. This entity must
have revenue quality metering at every load and generation point,
accurate as defined by NERC, to include MW flow data availability at 6-
second or smaller intervals. Western will evaluate the entity's
metering, telecommunications and regulating resource, as well as the
required level of regulation, and determine whether the entity
qualifies to self-supply under this provision. If approved, the entity
is required to enter into a separate agreement with Western which will
specify the terms of the self-supply application.
Customer Accommodation
For entities unwilling to take Regulation Service, self-provide it
as described above, or acquire the service from a third party, Western
will assist the entity in dynamically metering its loads/resources to
another balancing authority. Until such time as that meter
configuration is accomplished, the entity will be responsible for
charges assessed by WACM under the rate in effect.
Effective
The first day of the first full billing period beginning on or
after October 1, 2011, through September 30, 2016.
Formula Rate
[[Page 61199]]
[GRAPHIC] [TIFF OMITTED] TN03OC11.015
Rate
The rate to be in effect October 1, 2011, through September 30,
2012, for Nos. 1 and 2, as described above in the ``Types'' section of
this rate schedule, is:
------------------------------------------------------------------------
------------------------------------------------------------------------
Monthly $0.331/kW-month
Weekly $0.076/kW-week
Daily $0.011/kW-day
Hourly $0.000458/kWh
------------------------------------------------------------------------
A revised rate will go into effect October 1 of each year of the
effective rate period based on the formula above and updated financial
and load data. Western will notify the Customer annually of the revised
rate before October 1.
Any change to the rate for Regulation Service will be listed in a
revision to this rate schedule issued under applicable Federal laws,
regulations, and policies and made part of the applicable service
agreement.
Rate Schedule L-AS4
Schedule 4 to Tariff
October 1, 2011
United States Department of Energy
Western Area Power Administration
Rocky Mountain Region
Western Area Colorado Missouri Balancing Authority
Energy Imbalance Service
Applicable
The Western Area Colorado Missouri Balancing Authority (WACM)
provides Energy Imbalance Service when there is a difference between a
Customer's (Federal Transmission Customers and customers on others'
transmission systems inside WACM) resources and obligations. Energy
Imbalance is calculated as resources minus obligations (adjusted for
transmission and transformer losses) for any combination of generation,
scheduled transfers, transactions, or actual load integrated over each
hour. Customers inside WACM must either obtain this service from WACM
or make alternative comparable arrangements to satisfy their Energy
Imbalance Service obligation. This rate applies to all customers with
load inside WACM.
Effective
The first day of the first full billing period beginning on or
after October 1, 2011, through September 30, 2016.
Formula Rate
Imbalances are calculated in three deviation bands as follows. The
term ``metered load'' is defined to be ``metered load adjusted for
losses.''
1. An imbalance of less than or equal to 1.5 percent of metered
load (or 4 MW, whichever is greater) for any hour is settled
financially at 100 percent of the WACM weighted average hourly price.
2. An imbalance between 1.5 percent and 7.5 percent of metered load
(or 4 to 10 MW, whichever is greater) for any hour is settled
financially at 90 percent of the WACM weighted average hourly price
when net energy scheduled exceeds metered load or 110 percent of the
WACM weighted average hourly price when net energy scheduled is less
than metered load.
3. An imbalance greater than 7.5 percent of metered load (or 10 MW,
whichever is greater) for any hour is settled financially at 75 percent
of the WACM weighted average hourly price when net energy scheduled
exceeds metered load or 125 percent of the WACM weighted average hourly
price when net energy scheduled is less than metered load.
All Energy Imbalance Service provided by WACM is accounted for
hourly and settled financially. The WACM aggregate imbalance determines
the pricing used in all deviation bands. A surplus dictates the use of
sale pricing; a deficit dictates the use of purchase pricing. When no
hourly data is available, the pricing defaults for sales and purchase
pricing are applied in the following order:
1. Weighted average sale or purchase pricing for the day (on- and
off-peak).
2. Weighted average sale or purchase pricing for the month (on- and
off-peak).
3. Weighted average sale or purchase pricing for the prior month
(on- and off-peak).
4. Weighted average sale or purchase pricing for the month prior to
the prior month (and continuing until sale or purchase pricing is
located) (on- and off-peak).
Expansion of the bandwidth may be allowed during the following
instances:
Response to the loss of a physical resource.
During transition of large base-load thermal resources
(capacity greater than 200 MW) between off-line and on-line following a
reserve sharing group response, when the unit generates less than the
predetermined minimum scheduling level.
During periods of balancing authority operating constraints,
Western reserves the right to eliminate credits for over-deliveries.
The cost to Western of any penalty assessed by a regulatory authority
due to a violation of operating standards resulting from under- or
over-delivery of energy may be passed through to Energy Imbalance
Service customers.
Rate
The bandwidths, penalties, and pricing described above are in
effect October 1, 2011, through September 30, 2012.
Any change to the rate for Energy Imbalance Service will be listed
in a revision to this rate schedule issued under applicable Federal
laws, regulations, and policies and made part of the applicable service
agreement.
Rate Schedule L-AS5
Schedule 5 to Tariff
October 1, 2011
United States Department of Energy
Western Area Power Administration
Rocky Mountain Region
Western Area Colorado Missouri Balancing Authority
Operating Reserve--Spinning Reserve Service
Applicable
Spinning Reserve Service (Reserves) is needed to serve load
immediately in the event of a system contingency. Reserves may be
provided by generating units that are on-line and loaded at less than
maximum output. The Customers (Federal Transmission Customers and
customers on others' transmission system inside Western Area Colorado
Missouri Balancing Authority (WACM)) must either purchase this service
from WACM or make alternative comparable arrangements to satisfy their
Reserves obligation.
[[Page 61200]]
Effective
The first day of the first full billing period beginning on or
after October 1, 2011, through September 30, 2016.
Formula Rate
WACM has no long-term Reserves available for sale. At a Customer's
request, WACM will purchase Reserves and pass through the cost of
Reserves and any activation energy, plus a fee for administration. The
Customer will be responsible for providing the transmission to deliver
the Reserves.
Rate Schedule L-AS6
Schedule 6 to Tariff
October 1, 2011
United States Department of Energy
Western Area Power Administration
Rocky Mountain Region
Western Area Colorado Missouri Balancing Authority
Operating Reserve--Supplemental Reserve Service
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
Customers (Federal Transmission Customers and customers on others'
transmission system inside Western Area Colorado Missouri Balancing
Authority (WACM)) must either purchase this service from WACM or make
alternative comparable arrangements to satisfy their Reserves
obligation.
Effective
The first day of the first full billing period beginning on or
after October 1, 2011, through September 30, 2016.
Formula Rate
WACM has no long-term Reserves available for sale. At a Customer's
request, WACM will purchase Reserves and pass through the cost of
Reserves and any activation energy, plus a fee for administration. The
Customer will be responsible for providing the transmission to deliver
the Reserves.
Rate Schedule L-AS7
October 1, 2011
United States Department of Energy
Western Area Power Administration
Rocky Mountain Region
Western Area Colorado Missouri Balancing Authority
Transmission Losses Service
Applicable
The Western Area Colorado Missouri Balancing Authority (WACM)
provides Transmission Losses Service to all Transmission Service
Providers who market transmission inside WACM. The loss factor
currently in effect is posted on the Rocky Mountain Region (RMR) Open
Access Same-Time Information System (OASIS) Web site.
Effective
The first day of the first full billing period beginning on or
after October 1, 2011, through September 30, 2016.
Formula Rate
Transmission Losses are assessed for all real-time and prescheduled
transactions on transmission facilities inside WACM. The Customer is
allowed the option of energy repayment or financial repayment. Energy
repayment may be either concurrently or seven days later, to be
delivered using the same profile as the related transmission
transaction. Customers must declare annually their preferred
methodology of energy payback.
When a transmission loss energy obligation is not provided (or is
under-provided) by a Customer for a transmission transaction, the
energy still owed for Transmission Losses is calculated and a charge is
assessed to the Customer, based on the WACM weighted average hourly
purchase price.
Pricing for loss energy due 7 days later, and not received by WACM,
will be priced at the 7-day-later-price based on the WACM weighted
average hourly purchase price.
There will be no financial compensation or energy return to
Customers for over-delivery of Transmission Losses, as there should be
no condition beyond the control of the Customer that results in
overpayment.
Rate
This loss factor, as posted on the RMR OASIS, is in effect October
1, 2011, through September 30, 2012. Customers may settle financially
or with energy. The pricing for this service will be the WACM weighted
average hourly purchase price. When no hourly data is available,
pricing defaults will be applied in the following order:
1. Weighted average purchase pricing for the day (on- and off-
peak).
2. Weighted average purchase pricing for the current month (on- and
off-peak).
3. Weighted average purchase pricing for the prior month (on- and
off-peak).
4. Weighted average purchase pricing for the month prior to the
prior month (and continuing until or purchase pricing is located) (on-
and off-peak).
Any change to the rate for Transmission Losses Service will be listed
in a revision to this rate schedule issued under applicable Federal
laws, regulations, and policies and made part of the applicable service
agreement.
Rate Schedule L-FPT1
Schedule 7 to Tariff
October 1, 2011
United States Department of Energy
Western Area Power Administration
Rocky Mountain Region
Loveland Area Projects
Long-Term Firm and Short-Term Firm Point-To-Point Transmission Service
Applicable
The Transmission Customer shall compensate the Loveland Area
Projects (LAP) each month for Reserved Capacity under the applicable
Firm Point-to-Point Transmission Service Agreement and the rate
outlined herein.
Discounts
Three principal requirements apply to discounts for transmission
service as follows: (1) Any offer of a discount made by LAP must be
announced to all eligible customers solely by posting on the Rocky
Mountain Region's Open Access Same-Time Information System web site
(OASIS); (2) any customer-initiated requests for discounts, including
requests for use by the LAP merchant, 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,
LAP must offer the same discounted transmission service rate for the
same time period to all eligible customers on all unconstrained
transmission paths that go to the same point(s) of delivery on the
transmission system.
[[Page 61201]]
Effective
The first day of the first full billing period beginning on or
after October 1, 2011, through September 30, 2016.
Formula Rate
[GRAPHIC] [TIFF OMITTED] TN03OC11.016
Rate
The rate to be in effect October 1, 2011, through September 30,
2012, is:
------------------------------------------------------------------------
Maximum of
------------------------------------------------------------------------
Yearly $41.80/kW of reserved capacity per
year
Monthly $3.48/kW of reserved capacity per
month
Weekly $0.80/kW of reserved capacity per
week
Daily $0.11/kW of reserved capacity per
day
------------------------------------------------------------------------
A revised rate will go into effect October 1 of each year of the
effective rate period based on the formula above, updated financial and
load projections, and the true-up of previous projections. Western will
notify the Transmission Customer annually of the revised rate before
October 1.
Any change to the rate for Long-Term Firm and Short-Term Firm
Transmission Service will be listed in a revision to this rate schedule
issued under applicable Federal laws, regulations, and policies and
made part of the applicable service agreement.
Rate Schedule L-NFPT1
Schedule 8 to Tariff
October 1, 2011
United States Department of Energy
Western Area Power Administration
Rocky Mountain Region
Loveland Area Projects
Non-Firm Point-To-Point Transmission Service
Applicable
The Transmission Customer will compensate Loveland Area Projects
(LAP) for Non-Firm Point-to-Point Transmission Service under the
applicable Non-Firm Point-to-Point Transmission Service Agreement and
the rate outlined herein.
Discounts
Three principal requirements apply to discounts for transmission
service as follows: (1) Any offer of a discount made by LAP must be
announced to all eligible customers solely by posting on Rocky Mountain
Region's Open Access Same-Time Information System web site (OASIS); (2)
any customer-initiated requests for discounts, including requests for
use by the LAP merchant, 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, LAP must offer the same
discounted transmission service rate for the same time period to all
eligible customers on all unconstrained transmission paths that go to
the same point(s) of delivery on the transmission system.
Effective
The first day of the first full billing period beginning on or
after October 1, 2011, through September 30, 2016.
Formula Rate
[GRAPHIC] [TIFF OMITTED] TN03OC11.017
Rate
The rate to be in effect October 1, 2011, through September 30,
2012, is:
------------------------------------------------------------------------
Maximum of
------------------------------------------------------------------------
Yearly $41.80/kW of reserved capacity per
year
Monthly $3.48/kW of reserved capacity per
month
Weekly $0.80/kW of reserved capacity per
week
Daily $0.11/kW of reserved capacity per
day
Hourly 4.77 mills/kWh
------------------------------------------------------------------------
A revised rate will go into effect October 1 of each year of the
effective rate period based on the formula above, updated financial and
load projections, and the true-up of previous projections. Western will
notify the Transmission Customer annually of the revised rate before
October 1.
Any change to the rate for Non-Firm Point-to-Point Transmission
Service will be listed in a revision to this rate schedule issued under
applicable Federal laws, regulations, and policies and made part of the
applicable service agreement.
Rate Schedule L-NT1
Schedule H to Tariff
October 1, 2011
United States Department of Energy
Western Area Power Administration
Rocky Mountain Region
Loveland Area Projects
Annual Transmission Revenue Requirement for Network Integration
Transmission Service
Applicable
Transmission Customers will compensate the Loveland Area Projects
each month for Network Integration Transmission Service under the
applicable Network Integration Transmission Service Agreement and the
Annual Transmission Revenue Requirement described herein.
[[Page 61202]]
Effective
The first day of the first full billing period beginning on or
after October 1, 2011, through September 30, 2016.
Formula Rate
[GRAPHIC] [TIFF OMITTED] TN03OC11.018
Rate
The Annual Transmission Revenue Requirement in effect October 1,
2011, through September 30, 2012, is $56,775,913.
A revised Annual Transmission Revenue Requirement will go into
effect October 1 of each year of the effective rate period based on
updated financial projections and the true-up of previous projections.
Western will notify the Transmission Customer annually of the revised
Annual Transmission Revenue Requirement before October 1.
Any change to the rate for Network Integration Transmission Service
will be listed in a revision to this rate schedule issued under
applicable Federal laws, regulations, and policies and made part of the
applicable service agreement.
Rate Schedule L-AS9
Schedule 9 to Tariff
October 1, 2011
United States Department of Energy
Western Area Power Administration
Rocky Mountain Region
Western Area Colorado Missouri Balancing Authority
Generator Imbalance Service
Applicable
The Western Area Colorado Missouri (WACM) Balancing Authority
provides Generator Imbalance Service when there is a difference between
a Customer's (Federal Transmission Customers and customers on others'
transmission systems inside WACM) resources and obligations. Generator
Imbalance is calculated as actual generation minus scheduled generation
for each hour. Customers inside WACM must either obtain this service
from WACM or make alternative comparable arrangements to satisfy their
Generator Imbalance Service obligation. This rate applies to all
jointly-owned generators (unless arrangements are made to allocate
actual generation to each individual owner), intermittent generators
(unless arrangements are made to assess the intermittent generator
under Rate Schedule L-AS4), and any non-intermittent generators serving
load only outside WACM.
Effective
The first day of the first full billing period beginning on or
after October 1, 2011, through September 30, 2016.
Formula Rate
Imbalances are calculated in three deviation bands as follows:
1. An imbalance of less than or equal to 1.5 percent of metered
generation (or 4 MW, whichever is greater) for any hour is settled
financially at 100 percent of the WACM weighted average hourly price.
2. An imbalance between 1.5 percent and 7.5 percent of metered
generation (or 4 to 10 MW, whichever is greater) for any hour is
settled financially at 90 percent of the WACM weighted average hourly
price when actual generation exceeds scheduled generation or 110
percent of the WACM weighted average hourly price when actual
generation is less than scheduled generation.
3. An imbalance greater than 7.5 percent of metered generation (or
10 MW, whichever is greater) for any hour is settled financially at 75
percent of the WACM weighted average hourly price when actual
generation exceeds scheduled generation or 125 percent of the WACM
weighted average hourly price when actual generation is less than
scheduled generation.
Intermittent generators are exempt from 25 percent penalties. All
imbalances greater than 1.5 percent of metered generation are subject
only to a 10 percent penalty.
All Generator Imbalance Service provided by WACM is accounted for
hourly and settled financially. The WACM aggregate imbalance determines
the pricing used in all deviation bands. A surplus dictates the use of
sale pricing; a deficit dictates the use of purchase pricing. When no
hourly data is available, the pricing defaults for sales and purchase
pricing are applied in the following order:
1. Weighted average sale or purchase pricing for the day (on- and
off-peak).
2. Weighted average sale or purchase pricing for the current month
(on- and off-peak).
3. Weighted average sale or purchase pricing for the prior month
(on- and off-peak).
4. Weighted average sale or purchase pricing for the month prior to
the prior month (and continuing until sale or purchase pricing is
located) (on- and off-peak).
Expansion of the bandwidth may be allowed during the following
instances:
Response to the loss of a physical resource.
During transition of large base-load thermal resources
(capacity greater than 200 MW) between off-line and on-line following a
reserve sharing group response, when the unit generates less than the
predetermined minimum scheduling level.
During periods of balancing authority operating constraints,
Western reserves the right to eliminate credits for over-deliveries.
The cost to Western of any penalty assessed by a regulatory authority
due to a violation of operating standards resulting from under- or
over-delivery of energy may be passed through to Generator Imbalance
Service customers.
Rate
The bandwidths, penalties, and pricing described above are in
effect October 1, 2011, through September 30, 2012.
Any change to the rate for Generator Imbalance Service will be
listed in a revision to this rate schedule issued under applicable
Federal laws, regulations, and policies and made part of the applicable
service agreement.
[[Page 61203]]
Rate Schedule L-UU1
Schedule 10 to Tariff
October 1, 2011
United States Department of Energy
Western Area Power Administration
Rocky Mountain Region
Loveland Area Projects
Unreserved Use Penalties
Applicable
The Transmission Customer shall compensate the Loveland Area
Projects (LAP) each month for any unreserved use of the transmission
system (Unreserved Use) under the applicable transmission service rates
as outlined herein. Unreserved Use occurs when an eligible customer
uses transmission service that it has not reserved or a Transmission
Customer uses transmission service in excess of its reserved capacity.
Unreserved Use may also include a Customer's failure to curtail
transmission when requested.
Penalty Rate
The penalty rate for a Transmission Customer that engages in
Unreserved Use is 200 percent of LAP's approved rate for firm point-to-
point transmission service assessed as follows: the Unreserved Use
Penalty for a single hour of Unreserved Use is 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) increases to the
next longest duration (e.g., weekly). The Unreserved Use Penalty for
multiple instances of Unreserved Use (e.g., more than one hour) within
a day is based on the rate for daily firm point-to-point service. The
Unreserved Use Penalty for multiple instances of Unreserved Use
isolated to one calendar week is based on the rate for weekly firm
point-to-point service. The Unreserved Use Penalty for multiple
instances of Unreserved Use during more than one week in a calendar
month is based on the rate 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
that were provided by the Western Area Colorado Missouri Balancing
Authority and associated with the Unreserved Use. The Customer will pay
for ancillary services based on the amount of transmission service it
used and did not reserve.
Effective
The first day of the first full billing period beginning on or
after October 1, 2011, through September 30, 2016.
Rate
The rate for Unreserved Use Penalties is 200 percent of LAP's
approved rate for firm point-to-point transmission service assessed as
described above.
Any change to the rate for Unreserved Use Penalties will be listed
in a revision to this rate schedule issued under applicable Federal
laws, regulations, and policies and made part of the applicable service
agreement.
[FR Doc. 2011-23391 Filed 9-12-11; 8:45 am]
Editorial Note: FR Doc. 2011-23391 which was originally
published on pages 56433-56452 in the issue of Tuesday, September
13, 2011 is being republished in its entirety in the issue of
Monday, October 3, 2011 because of editing errors.
[FR Doc. R1-2011-23391 Filed 9-30-11; 8:45 am]
BILLING CODE 6450-01-P