The Central Valley Project, the California-Oregon Transmission Project, the Pacific Alternating Current Intertie, and Information on the Path 15 Transmission Upgrade-Rate Order No. WAPA-156, 56906-56936 [2011-23339]
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Federal Register / Vol. 76, No. 178 / Wednesday, September 14, 2011 / Notices
DEPARTMENT OF ENERGY
Western Area Power Administration
The Central Valley Project, the
California-Oregon Transmission
Project, the Pacific Alternating Current
Intertie, and Information on the Path 15
Transmission Upgrade—Rate Order
No. WAPA–156
Western Area Power
Administration, DOE.
ACTION: Notice of Rate Order.
AGENCY:
The Deputy Secretary of
Energy confirmed and approved Rate
Order No. WAPA–156 and Rate
Schedules CV–F13, CPP–2, CV–T3, CV–
NWT5, COTP–T3, PACI–T3, CV–TPT7,
CV–UUP1, CV–SPR4, CV–SUR4, CV–
RFS4, CV–EID4, and CV–GID1, placing
formula rates for power, transmission,
and ancillary services for the Central
Valley Project (CVP), transmission
service on the California-Oregon
Transmission Project (COTP),
transmission service on the Pacific
Alternating Current Intertie (PACI), and
third-party transmission service into
effect on an interim basis. The Rate
Order also provides information on the
Western Area Power Administration’s
(Western) transmission capacity
entitlement on the Path 15 Transmission
Upgrade. 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
superseded. The provisional formula
rates will provide sufficient revenue to
pay all annual costs, including interest
expense, repayment of power
investments and aid to irrigation, within
the allowable periods.
DATES: Rate Schedules CV–F13, CPP–2,
CV–T3, CV–NWT5, COTP–T3, PACI–
T3, CV–TPT7, CV–UUP1, CV–SPR4,
CV–SUR4, CV–RFS4, CV–EID4, and
CV–GID1 will be placed into effect on
an interim basis on the first day of the
first full billing period beginning
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rate schedules are superseded.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. Thomas R. Boyko, Regional
Manager, Sierra Nevada Customer
Service Region, Western Area Power
Administration, 114 Parkshore Drive,
Folsom, CA 95630–4710, (916) 353–
4418, or Ms. Regina Rieger, Rates
Manager, Sierra Nevada Customer
Service Region, Western Area Power
Administration, 114 Parkshore Drive,
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SUMMARY:
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Folsom, CA 95630–4710, (916) 353–
4629, e-mail rieger@wapa.gov.
SUPPLEMENTARY INFORMATION: This
Federal Register notice (FRN) replaces
the existing formula rates for power,
transmission, and ancillary services
under Rate Order No. 115, noticed on
November 22, 2004,1 as amended under
Rate Order No. 128, noticed on July 26,
2006,2 and as extended by Rate Order
No. 139, noticed on August 12, 2008.3
These rate schedules (CV–F12, CPP–1,
CV–T2, CV–NWT4, COTP–T2, PACI–
T2, CV–TPT6, CV–SPR3, CV–SUR3,
CV–RFS3, and CV–EID3) expire on
September 30, 2011. The Deputy
Secretary of Energy, under Delegation
Order No. 00–037.00 and 00–001.00c,
10 CFR 903 and 18 CFR part 300,
confirms, approves, and places into
effect on October 1, 2011, on an interim
basis, Rate Order WAPA–156, which
includes rate schedules CV–F13, CPP–2,
CV–T3, CV–NWT5, COTP–T3, PACI–
T3, CV–TPT7, CV–UUP1, CV–SPR4,
CV–SUR4, CV–RFS4, CV–EID4, and
CV–GID1. The provisional formula rates
shall be in effect until FERC confirms,
approves, and places them into effect on
a final basis through September 30,
2016, or until they are superseded.
Changes From Existing Rates
After considering all comments
submitted during the public
consultation and comment period,
Western determined that the provisional
rates should continue the existing
formula rate methodologies for power;
CVP, COTP, and PACI transmission;
transmission of Western power by
others; Custom Product Power (CPP);
and ancillary services with the
following summarized exceptions:
1. Two new rate schedules:
Unreserved Use Penalties (UUP) and
Generator Imbalance (GI);
2. Annual true-up for First Preference
(FP) percentages;
3. In addition to the existing 150
percent penalty on the California
Independent System Operator’s (CAISO)
market price, Western will adopt a 150
percent penalty on Western’s actual cost
when charging for ancillary services and
will charge the greater of the two;
4. Costs incurred under Energy
Imbalance (EI)/GI when disposing of
surplus energy, including negative
pricing of such energy, will be charged
to the responsible party;
5. For intermittent resources
interconnected to Western’s system,
Western will not charge the 150 percent
penalty and will charge the greater of
69 FR 70510 (2004).
71 FR 45821 (2006).
3 See 73 FR 48381 (2008).
CAISO market price or Western’s actual
cost;
6. Western added Components 2 and
3, standard cost recovery language, to
CPP formula rate; and
7. Rate Schedules include
miscellaneous language changes and
billing clarifications.
Detailed explanations of changes to
the provisional formula rate
methodologies are described in the rate
order below.
Provisional Power Rates
Under the provisional formula rates,
prior to the start of each fiscal year (FY),
Western calculates and publishes an
annual Power Revenue Requirement
(PRR) to determine the total cost of
power to be allocated to Preference
Customers. As part of the rate
development, Western prepares a Power
Repayment Study (PRS) each FY to
determine if the expected revenue will
be sufficient to repay, within the
required time periods, all costs assigned
to the commercial power function.
Repayment criteria are based on
legislation and applicable policies,
including DOE Order RA 6120.2.
Generally, the PRR includes estimated
operation and maintenance (O&M)
expenses, purchase power for Project
Use (PU) and FP Customers’ loads,
interest, and other expenses (including
any other statutorily-required costs or
charges), investment repayment, and the
Washoe Project annual costs that remain
after project use loads are met. Revenues
from PU, transmission, ancillary
services, and other services are offset
against expenses in the PRR. The
remainder is collected from Base
Resource (BR) and FP Customers. The
PRR is reviewed during March of each
year; and if the review results in a
change of $5 million or more, the PRR
is adjusted. The PRR is an estimate of
revenue and costs including investment
and repayment projections from the
PRS. Any deviation from estimate to
actual will increase or decrease capital
project repayment. Project repayment is
analyzed and measured over the long
term to ensure repayment is met and to
maintain rate stability.
The PRR is allocated first to FP
Customers then to BR Customers. The
FP Customers are defined in the Trinity
River Division Act of 1955 4 and the
Flood Control Act of 1962.5 Western
provides first preference of CVP power
to customers in Trinity, Tuolumne, and
Calaveras Counties, as provided under
those acts and as implemented under
Western’s 2004 Marketing Plan. A BR
1 See
2 See
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5 See
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69 Stat. 719 (1955).
76 Stat. 1173, 1191–1192 (1962).
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Customer, under the 2004 Marketing
Plan, is an entity that has executed a BR
contract and is allocated a percentage of
the BR. The FP percentages are
reviewed during March of each year;
and if the review results in a change of
one-half of 1 percent for any FP
Customer, the PRR obligation is
reallocated to both FP and BR
Customers. Based on customer
comments received during this rate
process, Western agreed to perform an
annual true-up of FP percentages and
adjust FP and BR revenue requirements
each October.
In order for Western to meet the loads
of Full Load Service (FLS) Customers or
any portion of the loads of Variable
Resource (VR) Customers not met by BR,
Western may make supplemental power
purchases pursuant to the CPP rate
schedule. The FLS and VR Customers
who contract with Western for such
service pay all supplemental power
costs. The FLS Customers pay a
portfolio management charge pursuant
to their FLS contract, whereas VR
Customers pay a scheduling charge for
any CPP pursuant to the provisional rate
schedule.
Provisional Transmission and
Ancillary Service Rates
At least annually, Western will
publish the CVP transmission rates for
point-to-point (PTP) and network
integration transmission service (NITS),
the seasonal COTP and PACI
transmission rates, and CVP regulation
and frequency response service rates.
Rates are based on a cost-of-service
(COS) study to determine the costs, by
project, that support the transfer
capability of each transmission system
and the costs that support the
generation capability of the CVP system.
Generally, the costs allocated through
the COS study for the transmission
systems include O&M, interest, and
depreciation expenses. Western’s costs
for scheduling, system control and
dispatch service associated with CVP,
COTP, and PACI transmission service
are included and recovered through the
respective transmission system’s
revenue requirements (RR). Third-party
transmission service costs are passed
through directly to each customer.
Spinning and supplemental reserve
services are priced consistent with the
CAISO market price plus all costs
incurred for the sale of these reserves.
Customers who have a contractual
obligation to self-provide spinning and
supplemental reserves, and do not fulfill
their obligation, will be assessed a
penalty equal to the greater of 150
percent of Western’s actual cost or 150
percent of the market price. Similarly,
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for EI service, customers operating
outside of their contractual bandwidth
(under-delivery) will pay the greater of
150 percent of Western’s actual cost or
150 percent of the market price. Given
that Western’s EI Customers are and will
continue to operate under existing
agreements, Western will continue its
existing rate methodology for EI. During
or after the applicable rate period,
Western will review FERC Order No.
890, as well as Western’s existing
settlements and billing processes, and
will reconsider transitioning to FERC’s
methodology.
Finally, in response to FERC’s Order
No. 890, Western added two new rate
schedules to be effective during the new
rate period: UUP and GI. The UUP will
be assessed at 200 percent of the
effective PTP transmission rate when
transmission service is used and not
reserved or when used in excess of
reservation. The GI rate will use the
same methodology as Western’s EI
service rate. Currently, Western has no
customers subject to this provisional GI
rate.
Information on Path 15 Transmission
Upgrade
The Path 15 Transmission Upgrade
was completed in 2005. Western turned
over the operational control of
Western’s Path 15 Transmission
Upgrade to the CAISO. Western
maintains the transmission line and is
compensated by Atlantic Path 15, LLC
for maintenance costs. The CAISO
charges for use of the Path 15
Transmission Upgrade in accordance
with the CAISO tariff. Western does not
sell transmission capacity on Path 15
Transmission Upgrade. Western collects
revenues from the CAISO under its
agreements with the CAISO. Under
Amendment No. 48, the CAISO remits
to Western, wheeling, congestion, and
Congestion Revenue Rights revenues
associated with Western’s rights on the
Path 15 Transmission Upgrade.
Confirmation, Approval, and Placing
Rate Order WAPA–156 in Place
By Delegation Order No. 00–037.00,
effective December 6, 2001, the
Secretary of Energy delegated: (1) The
authority to develop power and
transmission rates to Western’s
Administrator; (2) the authority to
confirm, approve, and place such rates
into effect on an interim basis to the
Deputy Secretary of Energy; and (3) the
authority to confirm, approve, and place
into effect on a final basis, to remand or
to disapprove such rates to FERC.
Existing DOE procedures for public
participation in power rate adjustments
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(10 CFR part 903) were published on
September 18, 1985.
Under Delegation Order Nos. 00–
037.00 and 00–001.00C, 10 CFR part
903, and 18 CFR part 300, I hereby
confirm, approve, and place into effect
on October 1, 2011, on an interim basis,
Rate Order No. WAPA–156, which
includes Rate Schedules CV–F13, CPP–
2, CV–T3, CV–NWT5, COTP–T3, PACI–
T3, CV–TPT7, CV–UUP1, CV–SPR4,
CV–SUR4, CV–RFS4, CV–EID4, and
CV–GID1, for the CVP, COTP, and PACI
of Western. 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 a
rate for a new service. The provisional
rates shall be in effect until FERC
confirms, approves, and places the rates
in effect on a final basis through
September 30, 2016, or until the rates
are superseded.
Dated: September 2, 2011.
Daniel B. Poneman,
Deputy Secretary.
DEPARTMENT OF ENERGY
Deputy Secretary
Rate Order No. WAPA–156
In the matter of: Western Area Power
Administration Rate Adjustment for the
Central Valley Project, the CaliforniaOregon Transmission Project, and the
Pacific Alternating Current Intertie
These power, transmission, and
ancillary services formula rates are
established in accordance with section
302 of the Department of Energy (DOE)
Organization Act (42 U.S.C. 7152). This
Act transferred to and vested in the
Secretary of Energy the power marketing
functions of the Secretary of the
Department of the Interior (DOI) 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 Project Act of 1939,
(43 U.S.C. 485h(c)), and other acts that
specifically apply to the project
involved.
By Delegation Order No. 00–037.00,
effective December 6, 2001, the
Secretary of Energy delegated: (1) The
authority to develop power and
transmission rates to the Administrator
of Western Area Power Administration
(Western); (2) the authority to confirm,
approve, and place such rates into effect
on an interim basis to the Deputy
Secretary 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 Federal
Energy Regulatory Commission (FERC).
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Existing DOE procedures for public
participation in power rate adjustments
(10 CFR 903) were published on
September 18, 1985.
Acronyms and Definitions
As used in this Rate Order, the
following acronyms and definitions
apply:
2004 Power Marketing Plan: The 2004
Central Valley Project (CVP) Power
Marketing Plan effective January 1,
2005.6 The final marketing program
for the Sierra Nevada Region (SNR)
power after 2004 established through
a public process and published in the
Federal Register at 64 FR 34417.
Administrator: Administrator for the
Western Area Power Administration
(Western)
Ancillary Services: Those services
necessary to support the transfer of
electricity while maintaining reliable
operation of the transmission
provider’s transmission system in
accordance with standard utility
practice. Ancillary services are
generally described in Federal Energy
Regulatory Commission (FERC)
Orders 888 and 890, including:
spinning reserve, supplemental
reserve, regulation, Energy Imbalance
(EI), and Generator Imbalance (GI).
Balancing Authority (BA): The
responsible entity that integrates
resource plans ahead of time,
maintains load-interchangegeneration balance within a BA area,
and supports interconnection
frequency in real-time.
Balancing Authority of Northern
California (BANC): A joint power
agency composed of Sacramento
Municipal Utility District (SMUD),
Redding Electric Utility, Roseville
Electric, and Modesto Irrigation
District. The BANC is a legal
structure, and it contracts SMUD to
act as the BA operator for the BANC
as of May 1, 2011.
Base Resource (BR): The Central Valley
and Washoe Project power output and
existing power purchase contracts
extending beyond 2004 as determined
by Western to be available for
marketing after meeting the
requirements of Project Use (PU) and
First Preference (FP) Customers, and
any adjustments for maintenance,
reserves, transformation losses, and
certain ancillary services. The BR, as
defined above, will include CVP and
Washoe Project generation supported
by certain power purchases.
BR%: Base Resource Percentage.
California Independent System
Operator (CAISO): The FERC6 See
64 FR 34417 (1999).
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regulated, state-chartered, non-profit
corporation, independent system
operator and BA area of most of
California’s transmission grid.
California-Oregon Intertie (COI):
Consists of three 500-kilovolt (kV)
lines linking California and Oregon,
the California Oregon Transmission
Project, and the Pacific Alternating
Current Intertie (PACI) (two lines).
The Western Electricity Coordinating
Council (WECC) establishes the
seasonal transfer capability for the
COI.
California-Oregon Transmission Project
(COTP): A 500-kV transmission
project stretching from Captain Jack
Substation to Tesla Substation in
which Western has part ownership.
Capacity: The electric capability of a
generator, transformer, transmission
circuit, or other equipment expressed
in kilowatt (kW).
Central Valley Project (CVP): A
multipurpose Federal water
development project extending from
the Cascade Range in northern
California to the plains along the Kern
River south of the city of Bakersfield,
California.
CFR: Code of Federal Regulations.
COI Rating Seasons: Consists of
summer, June through October;
winter, November through March; and
spring, April through May.
Component 1: A part of a formula rate.
Component 1 is the variable portion
of Western’s rate schedules.
Component 1 is the methodology used
to determine revenue requirements or
rates that recover the costs for a
specific service or product.
Component 2: A part of a formula rate.
Component 2 is a pass-through
provision of Western’s rate schedules.
The language is the same in each rate
schedule.
Component 3: A part of a formula rate.
Component 3 is a pass-through
provision of Western’s rate schedules.
The language is the same in each rate
schedule.
Contract 2948A: Contract No. 14–06–
200–2948A was the Integration
Contract between PG&E and the
United States of America, which
expired on December 31, 2004. The
contract provided for integrating
Western’s resources with Pacific Gas
and Electric’s (PG&E) and required
PG&E to serve the combined PG&E/
Western load with the integrated
resource.
COS: Cost of Service.
Custom Product Power (CPP): Refers to
power purchased by Western to meet
a customer’s load.
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Customer: An entity with a contract that
receives service from the Western’s
SNR.
DOE: United States Department of
Energy.
DOE Order RA 6120.2: A DOE order
outlining power marketing
administration financial reporting and
ratemaking procedures.
EI: Energy Imbalance.
Federal Energy Regulatory Commission
(FERC): Referred to as the FERC.
FERC is an independent agency that
regulates the interstate transmission
of electricity.
First Preference (FP): Refers to an entity
qualified to use Preference Power
within a county of origin (Trinity,
Calaveras, and Tuolumne) as
specified under the Trinity River
Division Act of August 12, 1955 (69
Stat. 719) and the Flood Control Act
of 1962 (76 Stat. 1173, 1191–1192).
Fiscal Year (FY): Refers to the Federal
Fiscal Year, October 1 through
September 30.
Full Load Service (FLS): The BR
customer that will have its entire load
at the delivery point(s) met with
Western power and Third-Party
Power, and whose Portfolio
Management functions for said
delivery will be performed by
Western.
GI: Generator Imbalance.
HE: Hourly Exchange.
Host Balancing Authority (HBA):
Confirms and implements
transactions that operate generation or
serves customers directly within the
BA’s metered boundaries. The BA
within whose metered boundaries a
jointly-owned unit is physically
located. Western operates as a SubBalancing Authority (SBA) under the
BANC which operates the HBA.
Kilovolt (kV): The electrical unit of
measure of electric potential that
equals 1,000 volts.
Kilowatt (kW): The electrical unit of
capacity that equals 1,000 watts.
Kilowatthour (kWh): The electrical unit
of energy that equals 1,000 watts
produced or delivered in 1 hour.
Kilowattmonth (kWmonth): The
electrical unit equal to one kW
produced or delivered for 1 month.
Load: The amount of electric power or
energy delivered or required at any
specified point(s) on a transmission or
distribution system.
Megawatt (MW): The electrical unit of
capacity that equals one million watts
or 1,000 kW.
Megawatt hour (MWh): The electrical
unit of energy that equals 1,000,000
watts produced or delivered for 1
hour.
MRR: Monthly Revenue Requirement.
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NERC: The North American Electric
Reliability Corporation’s (NERC) is
the electric reliability organization
certified by FERC to establish and
enforce reliability standards for the
bulk-power system.
NEPA: National Environmental Policy
Act.
Network Integration Transmission
Service (NITS): Firm transmission
service for the delivery of capacity
and energy from designated network
resources to designated network loads
not using one specific path.
Open Access Same Time Information
System (OASIS): The information
system and standards of conduct
contained in Part 37 of FERC’s
regulations that Western utilized in
developing its electronic posting
system for transmission access data.
Open Access Transmission Tariff
(OATT): Western’s open access
transmission tariff accepted by the
FERC, as it may be amended and
supplemented.
O&M: Operations and Maintenance.
Pacific Alternating Current Intertie
(PACI): A 500-kV transmission project
of which Western owns a portion of
the facilities.
PG&E: Pacific Gas and Electric
Company.
Power: Capacity and energy, and it is
measured in watts and often
expressed in kW or MW.
Power Repayment Study (PRS): The PRS
is used to calculate how much
revenue is needed to meet annual
investment obligations, O&M
expenses, and repayment
requirements (including repayment
periods).
Preference: Refers to the provisions of
Reclamation Law that requires
Western to first make Federal power
available to certain entities. For
example, section 9(c) of the
Reclamation Project Act of 1939 states
that preference in the sale of Federal
power shall be given to municipalities
and other public corporations or
agencies and also to cooperatives and
other non-profit organizations
financed in whole or in part by loans
made under the Rural Electrification
Act of 1936 (43 U.S.C. 485h(c)).
Project Use (PU): Power designated by
Reclamation Law to be used to
operate CVP and Washoe Project
facilities.
Provisional Rate: A rate which has been
confirmed, approved, and placed into
effect on an interim basis by the
Deputy Secretary.
PRR: Power Revenue Requirement.
PTP: Point-to-Point.
Reclamation: The U.S. Department of
the Interior, Bureau of Reclamation.
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Reclamation Law: A series of Federal
laws. Viewed as a whole, these laws
create the originating framework
under which Western markets power.
Regulation and Frequency Response:
The ancillary service under which a
BA maintains moment-by-moment
load interchange-generation balance
with the BA area and supports
interconnection frequency.
RR: Revenue Requirement.
SMUD: Sacramento Municipal Utility
District.
SNR: Sierra Nevada Customer Service
Region.
Sub-Balancing Authority (SBA):
Western’s contract-based BA within
the SMUD’s BA, now BANC.
Supplemental Power: The firm capacity
and energy, provided by Western, that
a customer(s) needs in addition to its
BR for use in meeting its load.
Transmission: The movement or transfer
of electric energy between points of
supply and points at which it is
transformed for delivery to customers
or is delivered to other electric
systems.
Transmission Service Provider (TSP):
The entity that administers the
transmission tariff and provides
transmission service to transmission
customers under applicable
transmission service agreements.
TRR: Transmission Revenue
Requirement.
UUP: Unreserved Use Penalties.
VR: Variable Resource.
Western: Western Area Power
Administration.
Washoe Project: A Reclamation project
located in the Lahontan Basin in westcentral Nevada and east-central
California.
WECC: The Western Electricity
Coordinating Council (WECC) is the
regional entity responsible for
coordinating and promoting bulk
electric system reliability in the
Western Interconnection.
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 the Federal Energy
Regulatory Commission (FERC) on a
final basis.
Public Notice and Comment
Western Area Power Administration
(Western) has followed the Procedures
for Public Participation in Power and
Transmission Rate Adjustments and
Extensions, 10 CFR 903, in developing
these formula rates and schedules. The
steps Western took to involve interested
parties in the rate process were:
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1. The rate adjustment process began
June 10, 2008, when Western mailed a
notice announcing an informal meeting
to all Sierra Nevada Region (SNR)
Preference Customers and interested
parties.
2. Western held 14 public informal
rate meetings beginning June 2008
through April 2010, in Folsom,
California, to discuss the formula rate
methodologies, components, and
rationale for formula rates, to discuss
possible formula rate changes, and to
answer questions and seek customer
input or proposed changes. Meeting
agendas, notes, and handouts are posted
on Western’s Web site: https://
www.wapa.gov/sn/marketing/rates/
ratesProcess/informalProcess/index.asp.
3. A Federal Register notice (FRN)
published on January 3, 2011,7 which
announced the proposed rates for
Central Valley Project (CVP), CaliforniaOregon Transmission Project (COTP),
and Pacific Alternating Current Intertie
(PACI), began the public consultation
and comment period and set forth the
dates and location of public information
and public comment forums.
4. On January 5, 2011, Western sent
an e-mail notification to all SNR
Preference Customers and interested
parties transmitting the FRN and
reiterating the dates and locations of the
public information and comment
forums.
5. On January 14, 2011, Western sent
an e-mail notification to all SNR
Preference Customers and interested
parties that the 2012 Rates Brochure for
Proposed Rates was available upon
request and posted on Western’s Web
site at https://www.wapa.gov/sn/
marketing/rates/.
6. On January 14, 2011, Western sent
an e-mail notification to all SNR
Preference Customers and interested
parties reminding them of the January
25, 2011, Public Information Forum
(PIF).
7. On January 25, 2011, Western held
a PIF at the Lake Natoma Inn in Folsom,
California. Western provided
explanations of the proposed rates for
CVP, COTP, PACI, and Path 15
information, responded to questions,
and explained the differences between
the existing and the proposed rates.
Western provided rate brochures and
informational handouts.
8. On February 8, 2011, Western sent
an e-mail notification to all SNR
Preference Customers and interested
parties announcing the location of
Western’s Web site to view all
comments received during the comment
period. That Web site also contained
7 See
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information on how to obtain a copy of
the PIF transcript.
9. On February 23, 2011, Western sent
an e-mail notification to all SNR
Preference Customers and interested
parties reminding them of the March 1,
2011, Public Comment Forum (PCF).
10. On March 1, 2011, Western held
a PCF to give Preference Customers and
interested parties an opportunity to
comment for the record. Three
individuals commented at this forum.
11. On March 23, 2011, Western sent
e-mail notification to all SNR Preference
Customers and interested parties that
the PCF transcript was received and a
Summary of Comments from the PCF
was posted on Western’s Web site. In
addition to comments received at
Western’s PCF, Western received 17
comment letters during the consultation
and comment period, which ended on
April 4, 2011. All comments received
prior to the close of the consultation and
comment period have been considered
in preparing this Rate Order. All written
comments received are posted on
Western’s Web site: https://
www.wapa.gov/sn/marketing/rates/
ratesProcess/formalProcess/CIL2011/
index.asp.
12. On April 12, 2011, Western sent
an e-mail notification to all SNR
Preference Customers and interested
parties announcing the end of the public
consultation and comment period.
Comments
Written comments were received from
the following organizations: Alameda
Municipal Power, California; Bay Area
Rapid Transit, California; Calaveras
Public Power Agency, California;
Calpine Corporation, California; City of
Biggs, California; City of Lodi,
California; City of Palo Alto, California;
City of Santa Clara (dba Silicon Valley
Power), California; Eastside Power
Authority, California; Northern
California Power Agency (representing
the Bay Area Rapid Transit District,
Truckee-Donner Public Utility District,
the Plumas-Sierra Rural Electric
Cooperative, the Port of Oakland, and
the cities of Alameda, Biggs, Fallon,
Gridley, Healdsburg, Lodi, Lompoc,
Palo Alto, Redding, Roseville, and
Ukiah), California; Plumas-Sierra Rural
Electric Cooperative, California; Power
and Water Resources Pooling Authority
(representing the Arvin-Edison Water
Storage District, Banta-Carbona
Irrigation District, Byron-Bethany
Irrigation District,8 Cawelo Water
District, Glenn-Colusa Irrigation District,
8 Byron Bethany Irrigation District withdrew from
the Power and Water Resources Pooling Authority
effective June 30, 2011.
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James Irrigation District, Lower Tule
River Irrigation District, Provident/
Princeton Irrigation District,
Reclamation District 108, Santa Clara
Valley Water District, Sonoma County
Water Agency, West Side Irrigation
District, West Stanislaus Irrigation
District, and the Westlands Water
District), California; Redding Electric
Utility, California; Roseville Electric,
California: Sacramento Municipal
Utility District, California; Trinity
Public Utility District, California;
Tuolumne Public Power Agency,
California.
Representatives of the following
organizations made oral comments:
Calpine Corporation, California.
Northern California Power Agency
(representing the Bay Area Rapid
Transit District, Truckee-Donner Public
Utility District, the Plumas-Sierra Rural
Electric Cooperative, the Port of
Oakland, and the cities of Alameda,
Biggs, Fallon, Gridley, Healdsburg, Lodi,
Lompoc, Palo Alto, Redding, Roseville,
and Ukiah), California
Redding Electric Utility, California.
Project Description
A. History and Description of the CVP,
PACI, and COTP
The CVP is located within the Central
Valley and Trinity River basins of
California. The CVP includes 18
constructed dams and reservoirs with a
total storage capacity of 13 million acre
feet. The system includes 615 miles of
canals, five pumping facilities, and ten
power plants with a maximum
operating capability of about 2,113
megawatts (MW), approximately 865
circuit-miles of high-voltage
transmission lines, 22 substations, and
19 communication sites. The Bureau of
Reclamation (Reclamation) operates the
water control and delivery system and
all of the power plants with the
exception of the San Luis PumpGenerator (also known as W.R. Gianelli),
which is operated by the State of
California for Reclamation.
The Emergency Relief Appropriations
Act of 1935 initially authorized the
CVP.9 Congress reauthorized the CVP in
1937 in the Rivers and Harbors Act.10
As part of the CVP, Congress authorized
Reclamation to construct the Shasta
Dam on the Sacramento River and
Friant Dam on the San Joaquin River.
Between the two dams are the Tracy
Pumping Plant and the Delta-Mendota
Canal, the Contra Costa Canal, the
Friant-Kern Canal, the Madera Canal,
9 See
49 Stat. 115 (1935).
50 Stat. 844, 850 (1937).
10 See
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and the Delta Cross Channel.11 Power
plants at Shasta and Keswick Dams
were also included in the authorization,
along with high-voltage transmission
lines designed to transmit power from
Shasta and Keswick Power Plants to the
Tracy pumps and to integrate the
Federal hydropower into other electric
systems.12 Through various acts,
Congress authorized the construction
and integration of numerous other
facilities into the CVP. For instance, in
1944, Congress authorized the American
River Division (Division) to be
constructed by the United States Army
Corps of Engineers (Corps).13 In 1949,
the Division was reauthorized for
integration into the CVP.14 The Division
included Folsom Dam and Power Plant,
Nimbus Dam and Power Plant, and the
Sly Park Unit, all located on the
American River.15 In 1955, Congress
authorized the Trinity River Division
(Trinity Division) to include Trinity
Dam and Power Plant, Lewiston Dam
and Power Plant, and the Lewiston Fish
Facilities, all located on the Trinity
River.16 The Trinity Division also
includes Judge Francis Carr Power
Plant, Whiskeytown Dam, and the
Spring Creek Power Plant. In 1960,
Congress authorized the San Luis Unit,
including the B.F. Sisk San Luis Dam
and San Luis Reservoir, San Luis Canal,
Coalinga Canal, O’Neill and Dos Amigos
Pumping Plants, and William R.
Gianelli Pump-Generator.17 In 1965,
Congress authorized construction of the
Auburn-Folsom South Unit (Unit) as an
addition to the CVP.18 This Unit
included four sub-units, three of which
have been constructed: Foresthill,
Folsom-Malby, and Folsom South Canal
sub-units. Congress has not authorized
funding to complete the construction of
the Auburn Dam, which is part of the
fourth sub-unit. Congress authorized the
San Felipe Division in 1967.19
Three Corps projects—Buchanan,
Hidden, and New Melones—were
authorized for integration into the CVP
in 1962.20 The Black Butte Integration
Act added Black Butte, another Corps
project completed in the 1960’s, to the
CVP in 1970.
In 1964, Congress authorized
construction of the 500-kilovolt (kV)
11 See Plans set forth in Rivers and Harbors
Committee Document Numbered 35, 75th Cong., as
adopted in 49 Stat. 1028, 1038 (1935).
12 See Id.
13 See 58 Stat. 887, 901 (1944).
14 See 63 Stat. 852 (1949).
15 See Id.
16 See 69 Stat. 719 (1955).
17 See 74 Stat. 156 (1960).
18 See 79 Stat. 615 (1965).
19 See 81 Stat. 173 (1967).
20 See 76 Stat. 1173, 1191 (1962).
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emcdonald on DSK4SPTVN1PROD with NOTICES2
Pacific Northwest-Pacific Southwest
Intertie (Intertie). In northern California,
Western owns the Malin to Round
Mountain portion of the PACI.21 In
1984, Congress authorized Western to
construct or participate in the
construction of the COTP.22 In 2001,
Congress authorized Western to
complete the Path 15 portion originally
authorized under the COTP.23 Western,
in marketing the Federal hydroelectric
power generated from the CVP, has
approximately 47 wholesale customers
serving an estimated two million
people. Western power customers
include four First Preference (FP)
Customers, public utility districts, state
agencies, Federal agencies, irrigation
districts, municipalities, and Native
American tribes.
B. The 2004 Marketing Plan
Western’s SNR markets hydropower
generation of the CVP and Washoe
Projects. From 1967 through 2004,
under the terms of Contract 14–06–200–
2948A (Contract 2948A) with the Pacific
Gas and Electric Company (PG&E), the
CVP resources, along with other
Western resources, were integrated with
PG&E resources. PG&E served the
combined Western/PG&E load with the
integrated resource. Under this contract,
PG&E delivered power to both the
Project Use (PU) and Preference Power
Customers. Contract 2948A expired on
December 31, 2004, and PG&E informed
Western it intended not to extend the
contract beyond that date. As a result of
the pending termination, Western
worked with its customers to develop
and implement the 2004 Power
Marketing Plan (Marketing Plan).
Western published the Marketing Plan
in the Federal Register on June 25,
1999.24 It established the criteria for
marketing CVP and Washoe Project
power output for a 20-year period from
January 1, 2005, through December 31,
2024.
The Base Resource (BR) is a
fundamental component and the
primary power product marketed under
this Marketing Plan. Under previous
marketing plans, customers received a
fixed capacity and load factor energy
allocation. Under the Marketing Plan,
Preference Customers (other than FP)
receive an allocated percentage of the
BR. Each BR Customer signed a BR
contract under the Marketing Plan.25
The Marketing Plan acknowledges the
BR may vary widely on an hourly, daily,
21 See
78 Stat. 756 (1964).
98 Stat. 403 (1984).
23 See 115 Stat. 174 (2001).
24 See 64 FR 34417 (1999).
25 See 75 FR 76975 (2010).
22 See
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weekly, monthly, and annual basis
depending on hydrological conditions
and other constraints that govern CVP
operations. CVP generation must be
adjusted for PU, FP entitlements,
operations, maintenance, reserves,
transformation losses, and certain
ancillary services before determining
the net CVP generation amount
available for marketing. During some
months, purchases may be required to
meet PU and FP Customers’ obligations,
and only a negligible amount, if any, of
BR will be available during some hours
of such months.
According to the Marketing Plan,
Western markets the BR separately or in
combination with custom products.
These custom products could include
Western acting on behalf of a customer
to: (1) Purchase some level of firming
power; (2) manage a portfolio of power
resources; (3) provide scheduling
services per balancing authority (BA)
operator protocols; and (4) procure
ancillary services. For those BR
Customers desiring custom products,
Western developed additional contracts
detailing these requirements.
Western classified customers who
contract for custom products into two
different customer groups: Variable
Resource (VR) and Full Load Service
(FLS) Customers. VR Customers
schedule their Federal power from
Western into their own ‘‘resource
portfolios’’ to meet their load
requirements. The FLS Customers are
those who require some additional
products and services to meet their fullload requirements and who contracted
with Western for such service.
The Marketing Plan also stipulated
that Western would establish and
manage an exchange program to allow
all customers to fully and efficiently use
their power allocations. Western
developed both hourly and seasonal
exchange programs. Further specifics
and stipulations of this program are
available in Exhibit B of the BR contract.
Pursuant to the Marketing Plan, BR
Customers pay for CVP network
transmission service with their BR.
Western also provides operating
reserves to its customers per the BA area
operator’s protocols to support BR, PU,
and FP deliveries. For all other
products, such as a custom product,
separate transmission arrangements
must be made by the applicable
customer with the appropriate
transmission service provider (TSP).
Customers interested in acquiring
transmission service from the CVP
system above that provided for BR
deliveries will need to request
transmission through Western’s Open
Access Transmission Tariff (OATT). A
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56911
copy of the OATT can be obtained at
Western’s Web site at https://
www.wapa.gov/transmission/oatt.htm.
To the extent possible, if Western has
sufficient transmission rights, Western’s
merchant will use its rights to meet
custom product transmission
requirements.
C. Path 15 Information
In May 2001, DOE released its
National Energy Policy recommending
Western take action to explore relieving
the constraints on Path 15. Western
analyzed the feasibility to construct the
Path 15 Transmission Upgrade Project
which included building a third
transmission line and other upgrades
that would allow about 1,500 MW of
additional electricity to be transmitted
across the state. The path upgrade was
intended to relieve constraints on the
existing north-south transmission lines.
In order to increase the path rating,
Western determined a new 84-mile long,
500-kV transmission line was needed
between PG&E’s Los Banos and Gates
Substations. Additionally, the Los
Banos and Gates Substations needed to
be modified to accommodate the new
equipment and a second 230-kV circuit
between Gates and Midway.
Western and the Path 15 participants
completed the Path 15 Transmission
Upgrade in 2005. Western turned over
the operational control of Western’s
Path 15 Transmission Upgrade to the
California Independent System Operator
(CAISO). Western maintains the
transmission lines and is compensated
by Atlantic Path 15, LLC, for the
maintenance work costs. The CAISO
charges for use on the Path 15
Transmission Upgrade as part of its
rates. Western does not sell
transmission capacity on the Path 15
Transmission Upgrade. Western collects
revenues from the CAISO under its
agreements with the CAISO. Under
Amendment No. 48, the CAISO remits
revenue to Western from wheeling,
congestion, and Congestion Revenue
Rights associated with Western’s rights
on the Path 15.26
Power Repayment Study
Western prepares a power repayment
study (PRS) each fiscal year (FY) to
determine if revenues will be sufficient
to repay, within the required time, all
costs assigned to the commercial power
26 Amendment No. 48 amended CAISO’s tariff to
provide congestion revenues, wheeling revenues,
and firm transmission rights auction revenues to
entities other than CAISO’s Participating
Transmission Owners, if any such entities fund
transmission facility upgrades on the CAISO grid.
See generally Federal Energy Regulatory
Commission Docket No. ER03–407–000.
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function. Repayment criteria are based
on law, applicable policies (including
DOE Order RA 6120.2), and authorizing
legislation.
Existing and Provisional Rates
The Deputy Secretary of Energy
approved the existing formula rates for
power, transmission, and ancillary
services under Rate Order No. 115 on
November 22, 2004.27 FERC confirmed
and approved the rates and placed them
into effect on a final basis on October 4,
2005.28 The rates were amended by Rate
Order No. 128 on July 26, 2006 29 and
extended by Rate Order No. 139 on
August 12, 2008.30 The existing formula
rates expire on September 30, 2011. The
provisional rates continue the existing
formula rate methodologies for power;
CVP, COTP, and PACI transmission;
transmission of Western power by
others: Custom Product Power (CPP):
and ancillary services. The only changes
between the provisional rates and the
existing rates are described in more
detail in the section titled ‘‘Rate
Discussion.’’ The tables below compare
the current rates (FY 2011) for power,
transmission, and ancillary services
under the existing rate formulas to
estimated rates (FY 2012) under the
provisional rate formula methodologies
as well as any changes to the formula
rate methodology. All rates are subject
to change prior to October 1, 2011.
RATE COMPARISON
Actual
FY 2011
Service
Percent
change
(%)
Estimated
FY 2012
Financial change
Methodology change
Power Service Rates
PRR ...............................
$75,751,929 .................
$73,468,299 .................
(3.01) ...........
FP Percentage ..............
4.80% ...........................
4.77% ...........................
(0.63) ...........
Maximum FP Allocation
17.51% .........................
20.54% .........................
17.30 ...........
FP RR ............................
$3,636,093 ...................
$3,504,438 ...................
(3.62) ...........
BR RR ...........................
$72,115,836 .................
$69,963,861 .................
(2.98) ...........
CPP ...............................
Pass through ...............
Pass through ...............
N/A ..............
Forecasted financial
and/or operational
data.
Change due to forecasted operational
data.
Change due to forecasted operational
data.
Change due to forecasted financial and/
or operational data.
Change due to forecasted financial and/
or operational data.
N/A ...............................
VR Scheduling Charge
(per schedule).
$31.07 ..........................
$37.91 ..........................
22.01 ...........
Updated financial data
None, billing clarification only.
Adopt a FP% true-up.
None.
Adopt a FP% true-up.
Adopt a FP% true-up.
Added Components 2
and 3.
None, charges set for
5-year rate period.
Transmission & Ancillary Services
$1.04 (April 2011) ........
$1.31 ............................
25.96 ...........
CVP NITS ($/monthly) ...
$1,783,441 ...................
$2,247,754 ...................
26.03 ...........
CVP PTP Transmission
($/MWh).
$2.74 (Spring) ..............
$2.72 (Winter) ..............
(0.37) ...........
PACI PTP Transmission
($/MWh).
$1.21 (Spring) ..............
$1.22 (Winter) ..............
0.83 .............
COTP PTP Transmission ($/MWh).
emcdonald on DSK4SPTVN1PROD with NOTICES2
CVP PTP Transmission
($/kW—Month).
$2.74 (Spring) ..............
$2.72 (Winter) ..............
(0.73) ...........
Third-Party Transmission.
Unreserved Use Penalties.
Regulation and Frequency Response ($/
kW-month).
Pass through ...............
Pass through ...............
N/A ...............................
$4.33 ............................
27 See
69 FR 70510 (2004).
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N/A ..............
Rate change due to the
anticipated completion of new assets
that support transmission function.
Rate change due to anticipated completion
of new assets that
support transmission
function.
Rate decrease due to
estimated change in
financial data.
Rate increase due to
estimated change in
financial data.
Rate decrease due to
estimated change in
financial data.
N/A ...............................
None.
200% ............................
New .............
New penalty charge .....
New.
$4.05 ............................
(6.47) ...........
Decrease due to
change in financial
data.
If self-provided, the
penalty charge is the
greater of 150% of
actual or 150% of
market.
28 See Western Area Power Admin., 113 FERC
¶ 61,026 (2005).
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29 See
30 See
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None.
None.
None.
None.
None.
71 FR 45821 (2006).
73 FR 48381 (2008).
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56913
RATE COMPARISON—Continued
Actual
FY 2011
Percent
change
(%)
Estimated
FY 2012
Financial change
Methodology change
If self-provided, the
penalty charge is the
greater of 150% of
actual or 150% of
market.
Charge greater of
150% of actual or
150% of market.
Variable rate.
New tiered methodology similar to EI.
Spinning/Supplemental
Reserves.
Price consistent with
CAISO.
Price consistent with
CAISO.
N/A ..............
N/A ...............................
EI Service ......................
Tiered ...........................
Tiered ...........................
N/A ..............
N/A ...............................
GI Service ......................
NA ................................
New ..............................
New .............
New ..............................
Certification of Rates
Western’s Administrator certified that
the provisional rates, Rate Schedules
CV–F13, CPP–2, CV–T3, CV–NWT5,
COTP–T3, PACI–T3, CV–TPT7, CV–
UUP1, CV–SPR4, CV–SUR4, CV–RFS4,
CV–EID4, and CV–GID1, for CVP firm
power, transmission, and ancillary
services are at the lowest possible rates
consistent with sound business
principles. The provisional rates were
developed following administrative
policies and applicable laws.
emcdonald on DSK4SPTVN1PROD with NOTICES2
Rates Discussion
Following is a discussion comparing
the existing formula rates to the
provisional formula rates. Unless
otherwise noted, the formula rate
methodologies for power; CVP, COTP,
and PACI transmission; transmission of
Western power by others; CPP; and
ancillary services have not changed. The
percentage differences in rates noted in
the table above are due to estimated or
forecasted data factors (costs,
investments, generation, load, etc.) and
not due to a change to the formula rate
methodology. All FY 2012 rates are
estimates and subject to change prior to
publication of the final FY 2012 rate.
Having considered all comments
Where:
FP Customer Load = An FP Customer’s
forecasted annual load in megawatthours
(MWh).
Gen = The forecasted annual CVP and
Washoe generation (MWh).
Power Purchases = Power purchases for PU
and FP loads (MWh).
PU = The forecasted annual PU loads (MWh).
MRR = Monthly PRR.
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submitted during the public
consultation and comment period, the
current rate action adopts existing
formula rate methodologies for power;
CVP, COTP, and PACI transmission;
transmission of Western power by
others; CPP; and ancillary services with
the following exceptions:
1. Two new rate schedules:
Unreserved Use Penalties (UUP) and
Generator Imbalance (GI);
2. Annual true-up for FP percentages;
3. In addition to the existing 150
percent penalty on the CAISO market
price, Western will adopt a 150 percent
penalty on Western’s actual cost when
charging for ancillary services and will
charge the greater of the two;
4. Costs incurred under Energy
Imbalance (EI)/GI when disposing of
surplus energy, including negative
pricing of such energy, will be charged
to the responsible party;
5. For intermittent resources
interconnected to Western’s system,
Western will not charge the 150 percent
penalty, and charge the greater of
CAISO market price or Western’s actual
cost;
6. Added Components 2 and 3,
standard cost recovery language, to CPP
formula rate; and
7. Rate Schedules include
miscellaneous language changes and
billing clarifications. Formula rates
methodologies are included in the
attached provisional rate schedules. All
the formula rates contain three
components. Component 1 is the
methodology used to develop the rate
and is specific to each rate. Components
2 and 3 are applicable to all rate
formulas.
The formula rate also contains
Components 2 and 3.
Both the existing formula rate and the
provisional rate for BR consist of three
components:
Component 1:
BR% = BR percentage for each customer as
indicated in the BR contract after
adjustments for programs, such as hourly
exchange (HE), if applicable.
BR Customer Allocation = (BR RR × BR%)
Where:
BR RR = BR Monthly RR.
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A. Power Rate Discussion FP and BR
The difference in the forecasted FY
2012 revenue requirement (RR) and the
existing RR is the result of a change in
projected revenue and expenses and not
a formula rate methodology change. The
only change to this formula rate is the
adoption of an annual FP percentage
true-up. A change resulting from the FP
percentage prior period true-up will
impact both FP and BR RR to ensure full
recovery of the Power Revenue
Requirement (PRR).
Both the existing formula rate and the
provisional formula rate for FP
Customers consist of three components:
Component 1:
The formula rate also contains
Components 2 and 3.
The table below compares the existing
RR for FY 2011 to the estimated RR for
FY 2012 under the provisional formula
rates.
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COMPARISON OF EXISTING TO PROVISIONAL PRR, AND ALLOCATION TO FP AND BR CUSTOMERS
Existing RR
FY 2011
Service
PRR .................................................................................................................................
FP RR ..............................................................................................................................
BR RR ..............................................................................................................................
The 3.01 percent forecasted decrease
in the PRR is due primarily to a
decrease in other expenses and increase
in transmission revenues, which offsets
expenses in the PRR. The increase in
transmission revenue is driven by the
anticipated completion of assets
supporting the transmission function.
As indicated in the current rate
structure, the power rates are published
annually by September 30 and reviewed
during March of each year. The annual
PRR is allocated to FP Customers based
Estimated RR for
the provisional
formula rate
(effective FY
2012)
Percent Change
$73,468,299
3,504,438
69,963,861
(3.01)
(3.62)
(2.98)
$75,751,929
3,636,093
72,115,836
on each FP Customer’s percentage, as
adjusted for prior period true-up, and
the remainder to BR Customers based on
their contractual percentage.
Western will continue to maintain its
current policy and perform a FP
percentage midyear review and adjust
the FP percentages if necessary. Any
adjustment to the FP percentages at
midyear will be applied to the annual
PRR and billed during the remainder of
the FY. In addition, Western is adopting
an annual true-up methodology for each
FP customer’s percentage to ensure FP
Customers pay their proportionate share
of the annual PRR. Following the
completion of the true-up, Western will
allocate the charge or credit through the
PRR at the beginning of the following
FY. Also, according to current policy,
FP maximum percentage changes will
be established once at the beginning of
each 5-year rate period.
The table below compares the FP
percentages as well as their maximum
percentages for the two periods.
FP PERCENTAGE COMPARISON, AND ACTUAL MAXIMUM PERCENTAGES FOR EFFECTIVE RATE PERIOD
FP percentages
(annual)
FP Customers
Existing
FY 2011
(%)
Maximum FP customer percentage
applied to the RR
Estimated
FY 2012
(%)
Existing
(FY 2005–2011)
(%)
Actual
(FY 2012–2016)
(%)
0.37
0.90
2.80
0.73
0.37
0.90
2.80
0.70
1.39
3.49
9.21
3.42
1.58
3.81
12.01
3.16
Total ..........................................................................................
emcdonald on DSK4SPTVN1PROD with NOTICES2
Sierra Conservation Center .............................................................
Calaveras Public Power Agency .....................................................
Trinity Public Utilities District ...........................................................
Tuolumne Public Power Agency .....................................................
4.80
4.77
17.51
20.56
The change in FP percentages is due
to changes in generation and FP
customer loads and not a formula rate
methodology change. The increase in FP
maximum percentage is due to a
collective increase in FP customer
loads.
During the effective rate period, if
deemed appropriate, Western will
reevaluate the FP maximum percentage
based on new data.
As stated above, the BR RR is the
remainder of the PRR less FP RR. When
the FP percentage is adjusted for a prior
period true-up, the BR will also be
adjusted. An example calculation is
shown in the comments section as well
as in the rate schedule.
The provisional formula rates for the
PRR as allocated to BR and FP
Customers includes: (1) Operations and
maintenance (O&M) expense; (2) annual
investment and replacement repayment;
(3) aid-to-irrigation costs; (4) interest
expense; (5) power purchases for
firming BR; (6) Washoe Project annual
costs after PU loads are met; (7) other
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miscellaneous expenses allocated to
power, such as settlements, CaliforniaOregon Intertie (COI) path operator
costs, etc.; (8) the pass through of
FERC’s or other regulatory bodies’
accepted or approved charges or credits;
(9) the pass through of the Host
Balancing Authority’s (HBA) charges or
credits; (10) any other statutorilyrequired costs or charges; and (11) any
other costs including uncollectible debt.
Expenses are offset by revenues from
PU energy, transmission revenue,
ancillary service revenue, scheduling
coordinator (SC), portfolio management
(PM) and VR charge administrative fees
or scheduling charge, all pass-through
revenue, and any other miscellaneous
revenue.
The PRR will be allocated first to FP
Customers based on their percentages
and prior year true-up, subject to the
maximum cap, then the remaining PRR
amount will be allocated to BR
Customers based on their BR allocation
percentages and prior year FP true-up,
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as adjusted for programs, such as HE if
applicable.
The BR RR will be collected in two,
6-month periods: 25 percent for October
through March and 75 percent for April
through September. However, the FP RR
is not subject to the 25/75 percent split;
and it will be collected evenly over a 12month period.
The formula rates will be effective at
the beginning of each FY and reviewed
in March of each year. If the March
midyear review reflects a change of $5
million or more, the annual PRR will be
revised. The FP percentages are also
reviewed at midyear. If the midyear
review reflects a change to a FP
customer’s percentage of more than onehalf of 1 percent, that customer’s
percentage will be revised for the entire
FY. Also, any adjustments as a result of
the FP true-up will be incorporated in
the PRR each October following the
true-up.
The formula rates apply to CVP BR
and FP Customers. The estimated RRs
and FP percentages are subject to
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B. CPP
Under the CPP provisional rate, the
CPP cost recovery does not change from
the existing formula rate methodology
and remains 100 percent pass through.
The provisional formula rate also added
Component 2 and Component 3. The
provisional formula rate for CPP applies
to power supplied by Western to meet
a customer’s load. CPP may include
long- and short-term purchases at
various rates. As more fully described in
the rate schedule, the CPP provisional
formula rate is comprised of three
components. All costs associated with
CPP will be recovered through
Component 1 of the formula rate that
passes through the cost of the purchase
to a specific customer(s). Such costs
could include Western’s scheduling
costs as well as the cost of the power.
The VR scheduling charge is to
recover Western’s cost for scheduling
VR customer’s CPP service. Under the
provisional formula rate, Component 1,
the VR customer’s scheduling charge for
FY 2012 is $37.91 per schedule. This is
a 22 percent increase from the January
1, 2005, through September 30, 2011,
VR scheduling charge of $31.07 per
emcdonald on DSK4SPTVN1PROD with NOTICES2
Where:
CVP TRR = TRR is the cost associated with
facilities that support the transfer
capability of the CVP transmission
system excluding generation facilities
and radial lines.
TTc = The TTc is the total transmission
capacity under long-term contract
between Western and other parties.
NITSc = The NITSc is the 12-month average
coincident peaks of Network Integrated
Transmission Service (NITS) Customers
at the time of the monthly CVP
transmission system peak. For rate
design purposes, Western’s use of the
transmission system to meet its statutory
obligations is treated as NITS
This formula rate also contains
Components 2 and 3.
The provisional formula rate for CVP
transmission service is based on a RR
that recovers: (1) The CVP transmission
system costs for facilities associated
with providing transmission service; (2)
the non-facility costs allocated to
transmission service; (3) O&M costs,
cost of capital or interest expense,
depreciation expense, and other
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Jkt 223001
schedule. This increase is based on a
percentage change in O&M from the
2005 rate case. For FY 2013 through FY
2016 VR scheduling charge increases 3
percent each year to reflect inflationary
cost increases.
C. Transmission
Cost-of-Service Study
Western is using the same
methodology to allocate costs to the
transmission RRs and regulation and
frequency response RR for both the
existing and provisional formula rates.
Western prepared a detailed cost-ofservice (COS) study to determine the RR
that will be recovered through the CVP
regulation and frequency response
service formula rate and the CVP, COTP,
and PACI transmission service formula
rates. The costs allocated through the
COS study generally include O&M,
interest, and depreciation expenses.
This combined COS study integrates all
three transmission systems. Each CVP,
COTP, and PACI facility was researched
in order to determine its functional use.
The costs for CVP, COTP, and PACI
facilities that support the transfer
capability of the transmission system
(excluding generation tie-lines and
radial lines) are included in the
respective transmission system’s RR;
whereas, the cost for facilities that
miscellaneous costs associated with
providing transmission services; (4) the
cost for transmission scheduling, system
control and dispatch service is included
in O&M; (5) the pass through of FERC’s
or other regulatory bodies’ accepted or
approved charges or credits; (6) the pass
through of the HBA’s charges or credits;
(7) any other statutorily-required costs
or charges; and (8) any other costs
associated with transmission service
including uncollectible debt. Revenues
from the sales of short-term, non-firm
transmission will offset the TRR.
Revenue from unreserved use of
transmission penalties exceeding
transmission service cost will be
applied as an offset to the TRR.
The estimated rates resulting from the
formula rate are subject to change prior
to the rates taking effect. The rates will
be finalized by Western on or before
October 1, 2011.
CVP NITS
The NITS provisional formula rate
applies to CVP NITS Customers.
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support the generation capability of the
CVP system (including generation tielines and radial lines) are included in
the CVP generation RR and are used in
the regulation and frequency response
service RR. The costs associated with
the CVP are allocated to the
transmission and generation functions
based on a ratio of transmission or
generation plant to total plant.
CVP Firm and Non-Firm Point-to-Point
The provisional formula rate applies
to CVP firm point-to-point (PTP)
transmission service, existing CVP firm
pre-OATT transmission service, and
CVP non-firm transmission service.
Under the provisional formula rate, the
estimated rate for Component 1 for firm
and non-firm PTP service effective
October 1, 2011, is $1.31 per kilowatt
(kW) month. This is a 26 percent
increase from the April 1, 2011, CVP
firm and non-firm PTP rate of $1.04 per
kW month. The increase is primarily
due to the anticipated completion of
assets supporting the transmission
function and not a formula rate
methodology change. Both the existing
formula rate and the provisional
formula rate for CVP firm and non-firm
PTP services are comprised of three
components:
Component 1:
Effective October 1, 2011, the estimated
monthly NITS RR is $2,247,754. This
RR is a 26 percent increase from the
April 1, 2011, monthly NITS RR of
$1,783,441. The increase is primarily
due to the anticipated completion of
assets supporting the CVP transmission
function and not a rate methodology
change. Both the existing and
provisional formula rates for this service
are comprised of three components:
Component 1:
NITS customer’s monthly demand
charge = NITS customer’s load ratio
share × 1⁄12 of the Annual Network
TRR.
Where:
NITS customer’s load ratio share = The NITS
customer’s load, hourly, or in accordance
with approved policies or procedures,
(including behind the meter generation
minus the NITS customer’s adjusted BR)
coincident with the monthly CVP
transmission system peak, averaged over
a 12-month rolling period, expressed as
a ratio.
Annual Network TRR = The total CVP TRR
less revenue from long-term contracts for
E:\FR\FM\14SEN2.SGM
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change prior to the rates taking effect for
FY 2012. The RRs will be finalized by
Western on or before October 1, 2011.
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the CVP transmission between Western
and other parties.
This formula rate also contains
Components 2 and 3.
The provisional formula rate for CVP
NITS is based on a RR that recovers: (1)
The CVP transmission system costs for
facilities associated with providing
transmission service; (2) the non-facility
costs allocated to transmission service;
(3) O&M cost, cost of capital or interest
expense, depreciation expense, and
other miscellaneous costs associated
with providing transmission service; (4)
the cost for transmission scheduling,
system control and dispatch service; (5)
the pass through of FERC’s or other
regulatory bodies’ accepted or approved
charges or credits; (6) the pass through
of the HBA’s charges or credits; (7) any
other statutorily-required costs or
charges; and (8) any other costs
associated with transmission service
including uncollectible debt. Revenues
from the sales of short-term, non-firm
transmission will offset the TRR.
Revenue exceeding cost from
unreserved use of transmission
penalties will also be applied as an
offset to the TRR.
The estimated rates resulting from the
formula rate are subject to change prior
to the rates taking effect. The rates will
be finalized by Western on or before
October 1, 2011.
COTP PTP Transmission
The provisional formula rate applies
to COTP PTP transmission service. A
comparison of the estimated rates
resulting from Component 1 of the
provisional formula rate for COTP firm
PTP transmission service to the existing
COTP firm PTP transmission service
rates are shown in the table below.
COMPARISON OF EXISTING RATES TO ESTIMATED PROVISIONAL RATES FOR COTP FIRM AND NON-FIRM PTP
TRANSMISSION SERVICE
Existing COTP
rates
FY 2011
$/MWh)
Season
Spring ...............................................................................................................................
Summer ...........................................................................................................................
Winter ...............................................................................................................................
emcdonald on DSK4SPTVN1PROD with NOTICES2
Where:
COTP TRR = COTP Seasonal TRR (Western’s
costs associated with facilities that
support the transfer capability of the
COTP).
Western’s COTP Seasonal Capacity =
Western’s share of COTP capacity
(subject to curtailment) under the current
COI transfer capability for the season.
The three seasons are defined as follows:
Summer–June through October; Winter–
November through March; and Spring–
April through May.
This formula rate also contains
Components 2 and 3.
The estimated COTP PTP
transmission service rate decreased
despite a forecasted 3 percent O&M
inflationary increase, because interest
expense is forecasted to decrease. There
is no formula rate methodology change.
The provisional formula rate for
COTP firm and non-firm PTP
transmission service is based on a RR
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$2.74
2.73
2.77
$2.70
2.69
2.72
Percent change
(%)
(1.46)
(1.47)
(1.81)
Component 1:
that recovers: (1) The COTP
transmission system costs for facilities
associated with providing transmission
service; (2) the non-facility costs
allocated to transmission service; (3)
O&M costs, interest expense,
depreciation expense, and other
miscellaneous costs associated with
providing transmission services; (4) the
cost of scheduling system control and
dispatch service associated with COTP
transmission; (5) the pass through of
FERC’s or other regulatory bodies’
accepted or approved charges or credits;
(6) the pass through of the HBA’s
charges or credits; (7) any other
statutorily-required costs or charges;
and (8) any other costs associated with
transmission service including
uncollectible debt.
The rates resulting from Component 1
of the provisional formula rate may be
discounted for short-term sales and
PO 00000
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Sfmt 4703
revenue from COTP unreserved use
penalties. The estimated rates resulting
from the provisional formula rate are
subject to change prior to the rates
taking effect. The last month of the
summer seasonal rate (October) is in the
new rate period. Western will publish a
rate for October 2011 before September
15, 2011. The rates resulting from the
provisional formula rate for the winter
season will be finalized by Western on
or before October 15, 2011, and effective
November 1, 2011.
PACI PTP Transmission
The provisional formula rate applies
to PACI firm and non-firm PTP
transmission service. The estimated firm
and non-firm PTP rates resulting from
Component 1 of the provisional formula
rate for PACI transmission service are
shown below.
E:\FR\FM\14SEN2.SGM
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The existing and provisional formula
rate for COTP PTP transmission service
consists of three components.
Estimated COTP
rates
FY 2012
($/MWh)
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COMPARISON OF EXISTING RATES TO ESTIMATED PROVISIONAL RATES FOR PACI FIRM AND NON-FIRM PTP
TRANSMISSION SERVICE
Existing PACI
rates
FY 2011
$/MWh)
Season
Spring ................................................................................................................................
Summer ............................................................................................................................
Winter ................................................................................................................................
emcdonald on DSK4SPTVN1PROD with NOTICES2
penalties. The estimated rates resulting
from the provisional formula rate are
subject to change prior to the rates
taking effect. The last month of the
summer seasonal rate (October) is in the
new rate period. Western will publish a
rate for October 2011 before September
15, 2011. The rates resulting from the
provisional formula rate for the winter
season will be finalized by Western on
or before October 15, 2011, and effective
November 1, 2011.
This formula rate also contains
Components 2 and 3.
The estimated PACI PTP transmission
service rate remains unchanged, despite
a 3 percent inflationary cost increase
because of a forecasted decrease in
interest expense. The change in the
winter rate is due to actual costs
exceeding forecasted costs. There is no
formula rate methodology change.
The formula rate for PACI
transmission service is based on a RR
that recovers: (1) The PACI transmission
system costs for facilities associated
with providing transmission service; (2)
the non-facility costs allocated to
transmission service; (3) O&M costs,
interest expense, depreciation expense,
and other miscellaneous costs
associated with providing transmission
services; (4) the cost of scheduling
system control and dispatch service
associated with PACI transmission; (5)
the pass through of FERC’s or other
regulatory bodies’ accepted or approved
charges or credits; (6) the pass through
of the HBA’s charges or credits; (7) any
other statutorily-required costs or
charges; and (8) any other costs
associated with transmission service
including uncollectible debt.
The rates resulting from Component 1
of the provisional formula rate may be
discounted for short-term sales and
revenue from PACI unreserved use
Transmission of Western Power by
Others
19:22 Sep 13, 2011
Jkt 223001
$1.21
1.21
1.22
No change.
No change.
6.09
Component 1:
Where:
PACI TRR = PACI Seasonal TRR includes
Western’s costs associated with facilities
that support the transfer capability of the
PACI.
Western’s PACI Seasonal Capacity =
Western’s share of PACI capacity (subject
to curtailment) under the current COI
transfer capability for the season. The
three seasons are defined as follows:
Summer—June through October;
Winter—November through March; and
Spring—April through May.
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$1.21
1.21
1.15
Percent change
Effective October 1, 2011, the formula
rate methodology for this service does
not change from the existing
methodology, and all costs are passed
through under this rate schedule. The
existing and provisional formula rates
consist of three components:
Component 1: When Western uses
transmission facilities other than its
own in supplying Western power and
costs are incurred by Western for the
use of such facilities, the customer will
pay all costs, including transmission
losses incurred in the delivery of such
power. This formula rate also contains
Components 2 and 3.
These costs are fully recovered from
the beneficiaries receiving this service,
and there is no change in the existing
formula rate methodology.
UUP
This is a new rate schedule effective
on October 1, 2011, through September
30, 2016. The UUP service is provided
when a transmission customer uses
transmission service that it has not
reserved or uses transmission service in
excess of its reserved capacity. A
transmission customer that has not
reserved capacity or exceeds its firm or
non-firm reserved capacity at any point
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Fmt 4701
Sfmt 4703
of receipt or any point of delivery will
be assessed UUP. The penalty will be
assessed at 200 percent of the firm PTP
applicable rate when transmission is
used and not reserved except where
noted in the rate schedule.
The provisional formula rate consists
of three components:
Component 1: The penalty charge for
a transmission customer who engages in
unreserved use is 200 percent of
Western’s approved transmission
service rate for PTP transmission service
assessed as follows: (1) The UUP for a
single hour of unreserved use will be
based upon the rate for daily firm PTP
service; (2) the UUP for more than one
assessment for a given duration (e.g.,
daily) will increase to the next longest
duration (e.g., weekly); and (3) the UUP
for multiple instances of unreserved use
(e.g., more than 1 hour) within a day
will be based on the rate for daily firm
PTP service. The penalty charge for
multiple instances of unreserved use
isolated to one-calendar week would
result in a penalty based on the charge
for weekly firm PTP service. The
penalty charge for multiple instances of
unreserved use during more than one
week within a calendar month is based
on the charge for monthly firm PTP
service.
The UUP will not apply to
transmission customers utilizing PTP
transmission service under Western’s
OATT as a result of action taken to
support reliability. Such actions include
reserve activations or uncontrolled
event response as directed by the
responsible reliability authority such as
Sub-Balancing Authority (SBA), HBA,
Reliability Coordinator, or Transmission
Operator.
A transmission customer that exceeds
its firm or non-firm reserved capacity is
required to pay for all ancillary services
E:\FR\FM\14SEN2.SGM
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The existing and provisional formula
rate for PACI transmission service
consists of three components:
Estimated PACI
rates
FY 2012
($/MWh)
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emcdonald on DSK4SPTVN1PROD with NOTICES2
identified in Western’s OATT associated
with the unreserved use of transmission
service. The transmission customer or
eligible customer will pay for ancillary
services based on the amount of
transmission service it used but did not
reserve. No penalty will be applied to
the ancillary service charges.
This formula rate also contains
Components 2 and 3.
The provisional rate recovers the cost
of transmission and applies a penalty
for such unreserved use. The revenue
resulting from the penalty portion will
be distributed as a credit to the relevant
TRR. The penalty rate is applicable for
all unreserved use of transmission and
transmission in excess of reservation
except, as may be determined by
Western; for example, in emergencies or
reserve sharing activations.
D. Ancillary Services
This section includes provisional
formula rates for the following ancillary
services: spinning reserve, supplemental
reserve, regulation and frequency
response, EI, and GI. Western’s costs for
providing transmission scheduling,
system control and dispatch service,
and reactive supply and voltage control
are included in the appropriate
transmission or BR and FP power
formula rates.
Provisional formula rates are not
changing from existing rate
methodologies, except where noted. GI
is a new service effective October 1,
2011. As it pertains to ancillary services
rate schedules, in order to encourage
good scheduling practices, Western is
adopting the 150 percent penalty on
actual cost in addition to the existing
150 percent penalty on market price,
and will assess the greater of the two.
The penalty will be applicable to the
following rate schedules: (1) EI service;
(2) GI service; (3) regulation and
frequency response penalty for nonperformance of self provision; (4)
spinning reserve penalty portion for
non-performance; and (5) supplemental
reserve penalty portion for nonperformance. Also, any costs incurred
under EI/GI when disposing of surplus
energy, including negative pricing, will
be assessed to the responsible party.
Finally, to the extent that an entity
incorporates intermittent resources,
Western will eliminate the 150 percent
penalty; and Western will charge the
greater of the CAISO market price or
Western’s actual cost.
Spinning Reserve Service
Western is not proposing a change to
the existing formula rate methodology
for spinning reserve service, with the
exception of the penalty for non-
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Jkt 223001
performance, which will be charged the
greater of 150 percent of market or 150
percent of actual cost.
The spinning reserve charge is
calculated for each hour during the
month in order to derive the total
monthly charge. The provisional
formula rate for spinning reserve service
is comprised of three components as
follows:
The formula rate for spinning reserve
service is the price consistent with the
CAISO’s market plus all costs incurred
as a result of the sale of spinning
reserves, such as Western’s scheduling
costs.
For customers that have a contractual
obligation to provide spinning reserve
service to Western and do not fulfill that
obligation, the penalty for nonperformance is the greater of 150
percent of Western’s actual cost or 150
percent of the market price.
This formula rate also contains
Components 2 and 3.
The provisional rate formula includes:
(1) A price consistent with the CAISO’s
market price; (2) all costs incurred as a
result of the sale of spinning reserves,
such as Western’s scheduling costs; (3)
the cost of energy, capacity, or
generation that supports spinning
reserve service; (4) the pass through of
FERC’s or other regulatory bodies’
accepted or approved charges or credits;
(5) the pass through of the HBA’s
charges or credits; and (6) any other
statutorily-required costs or charges. For
customers that have a contractual
obligation to provide spinning reserve
service to Western and do not fulfill that
obligation, the penalty for nonperformance is the greater of 150
percent of actual cost or 150 percent of
the CAISO market price.
The cost for spinning reserve service
required to firm CVP generation for the
current hour and the following hour is
included in the PRR. Any surplus
spinning reserves may be sold at prices
consistent with the CAISO market price.
Revenues from the sale of surplus
spinning reserves will offset the PRR.
The spinning reserve formula rate will
apply to SBA Customers who contract
with Western to provide this service.
Supplemental Reserve Service
Western is not proposing a change to
the existing formula rate methodology
for supplemental reserve service, except
for customers that have a contractual
obligation to provide supplemental
reserve service to Western and do not
fulfill that obligation, the penalty for
non-performance will be charged the
greater of 150 percent of market or 150
percent of actual cost.
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Fmt 4701
Sfmt 4703
The formula rate for supplemental
reserve service is comprised of three
components as follows:
Component 1: The formula rate for
supplemental reserve service is the
price consistent with the CAISO’s
market plus all costs incurred as a result
of the sale of supplemental reserves
such as Western’s scheduling costs. For
customers that have a contractual
obligation to provide supplemental
reserve service to Western and do not
fulfill that obligation, the penalty for
non-performance is the greater of 150
percent of Western’s actual cost or 150
percent of the CAISO market price. This
formula rate also contains Components
2 and 3.
The provisional rate formula includes:
(1) A price consistent with the CAISO’s
market price; (2) all costs incurred as a
result of the sale of supplemental
reserve service such as Western’s
scheduling costs; (3) the cost of energy,
capacity, or generation that supports
supplemental reserve service; (4) the
pass through of the HBA’s charges or
credits; (5) the pass through of FERC’s
or other regulatory bodies’ accepted or
approved charges or credits; and (6) any
other statutorily-required costs or
charges.
For customers that have a contractual
obligation to provide supplemental
reserve to Western and do not fulfill that
obligation, the penalty for nonperformance is equal to the greater of
150 percent of actual cost of generation
or 150 percent of the CAISO market
price.
The cost for supplemental reserves
required to firm CVP generation for the
current hour and the following hour is
included in the PRR. Any supplemental
reserves may be sold at prices consistent
with the CAISO market price. Revenues
from the sale of supplemental reserves
will offset the PRR. The supplemental
reserve service formula rate will apply
to SBA Customers who contract with
Western to provide this service.
Regulation and Frequency Response
Service
Western is not proposing a change to
the existing formula rate methodology
with the exception of the self-provision
penalty, which will be charged the
greater of 150 percent of actual or 150
percent of market price. The regulation
rate effective April 1, 2011, was $4.33
per kWmonth. The rate effective during
the FY 2012 rate period under the
provisional formula rate is estimated at
$4.05 per kWmonth. The forecasted rate
decrease is primarily due to the
anticipated completion of assets
supporting transmission, which results
in a decrease to cost of regulation, other
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formula rate for this service is
comprised of three components.
The annual RR includes: (1) The CVP
generation costs associated with
providing regulation, and (2) the nonfacility costs allocated to regulation.
The annual regulating capacity is onehalf of the total regulating capacity
bandwidths provided by Western under
the interconnected operations
agreements with SBA members.
The penalty for non-performance by
an SBA customer who has committed to
self-provision for their regulating
capacity requirement will be the greater
of 150 percent of Western’s actual costs
or 150 percent of the CAISO market
price.
Western will revise the formula rate
resulting from Component 1 based on
either of the following two conditions:
(1) Updated financial data available in
March of each year, or (2) a change in
the numerator or denominator that
results in a rate change of at least $0.25
per kW month. This formula also
includes Components 2 and 3.
This provisional formula rate for
regulation and frequency response is
based on an annual RR that recovers: (1)
The CVP generation costs associated
with providing regulation; (2) the nonfacility costs allocated to regulation; (3)
O&M costs, interest expense,
depreciation expense, and other
miscellaneous costs; (4) the pass
through of FERC’s or other regulatory
bodies’ accepted or approved charges or
credits; (5) the pass through of the
HBA’s charges or credits; (6) any other
statutorily required costs or charges; and
(7) any other costs associated with
transmission service including
uncollectible debt.
The regulation RR will be recovered
from SBA Customers that have
contracted with Western for this service.
To the extent that an entity incorporates
variable resources, treatment of such
will be determined in the associated
interconnected operations agreement
contract. The revenues from regulation
service will be applied to the PRR. The
estimated regulation RR resulting from
the provisional formula rate is subject to
change prior to the rate taking effect for
FY 2012. The regulation RR will be
finalized by Western on or before
October 1, 2011.
To the extent that an entity
incorporates intermittent resources,
treatment of such will be determined in
the associated contract.
EI Service
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Western is not proposing a change to
the existing formula rate methodology
with the exception that: (1) The EI
charge will be the greater of 150 percent
of market or 150 percent of actual cost
for under-deliveries outside the
bandwidth, and (2) any costs incurred
under EI when disposing of surplus
energy, including negative pricing, will
be assessed to the responsible party.
Any changes to EI charges result from
changes to actual cost or market prices.
The provisional rate for EI services is
comprised of three components:
Component 1:
EI service is applied to deviations as
follows: (1) For deviations within the
contractual bandwidth, there will be no
financial settlement unless otherwise
dictated by contract or policy, rather, EI
will be tracked and settled with energy;
(2) negative deviations (under-delivery),
outside the deviation bandwidth, will
be charged the greater of 150 percent of
market price or 150 percent of Western’s
actual cost; and (3) positive deviations
(over-delivery) outside the deviation
bandwidth will be lost to the system,
except for any hour where Western
incurs a cost, then that cost will be
borne by the responsible party.
Deviations that occur as a result of
actions taken to support reliability will
be resolved in accordance with existing
contractual requirements. Such actions
include reserve activations or
uncontrolled event responses as
directed by the responsible reliability
authority, such as SBA, HBA, RC, or
TOP. The formula rate also contains
Components 2 and 3.
Western will maintain its existing
tiered methodology for EI as defined by
contractual agreements. While FERC
Order No. 890 defines a three-tier
methodology, it allows alternatives to
the design if the rate schedule follows
the intent of these principles: (1)
Charges based on incremental cost or
some multiple thereof, and (2) charges
must provide incentive for accurate
scheduling.
Western’s existing EI rate schedule
follows FERC’s intent as follows: (1) For
deviations within the bandwidth,
energy is returned; for deviations
outside the bandwidth, over-deliveries
are lost to the system; and under-
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Component 1:
deliveries are charged the greater of 150
percent of the CAISO market price or
150 percent of Western’s actual cost,
and (2) Western charges penalties
outside the bandwidth as an incentive
for good scheduling practices.
Given that Western’s customers will
be operating under existing agreements
during the applicable rate period,
Western will revisit FERC Order No.
890’s approach as well as Western’s
existing settlements and billing
processes and will consider a transition
to FERC’s methodology during
Western’s next rate process or earlier if
deemed appropriate.
Accordingly, for deviations outside of
the bandwidth, the EI service charge is
recovered using the greater of 150
percent of the CAISO market price or
150 percent of Western’s actual cost.
The actual cost is calculated using CVP
generation RR and associated energy.
Additional costs subject to recovery
include HBA’s charges or credits,
FERC’s or other regulatory bodies’
accepted or approved charges or credits,
and any other statutorily required costs
or charges.
The EI service charge will be
recovered from SBA Customers that
have contracted with Western for this
service. Since the actual cost is
calculated based on Western’s cost of
generation, it is subject to change prior
to the effective rate period.
Below is an example of how the EI
charge is calculated using Component 1:
EI CHARGE EXAMPLE CALCULATION
(COMPONENT 1)
On October 1, HE 1, Customer A has:
Scheduled Net Interchange ............
Actual Net Interchange ...................
Actual Energy in excess of Scheduled Energy.
Contractual Bandwidth ....................
EI for HE 1 ......................................
90 MW
102 MW
12 MW
8 MW
4 MW
To derive the total monthly charge for
Customer A, the EI is calculated for each
hour that it occurs during the month.
The EI charge is based upon a
comparison between the real-time
energy pricing from the CAISO for each
hour and Western’s actual cost, both
multiplied by 150 percent, for that same
hour. The higher of the two is applied
to derive the EI charge. Therefore, the EI
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factors being equal. The provisional
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charge for October 1, HE 1, is calculated
as follows:
October 1, hour ending 1
Price
Western’s Calculated Actual Cost ($18.27 × 150%) applied per
rate schedule.
Real-Time CAISO price ($21.84 × 150%) applied per rate schedule.
Price comparison
$27.40
150% Actual < 150% of Market
32.76
MW
150% Market > Actual ...............
Charge
N/A
N/A
4
$131.04
Note: EI charge for October 1, HE 1, is calculated as follows: 4 MW × $32.76 = $131.04.
emcdonald on DSK4SPTVN1PROD with NOTICES2
Imbalances that occur as a result of
action taken by the generator, at
Western’s request, to support reliability
will not be subject to penalties. Such
actions include directives by SBA, HBA,
Reliability Coordinators, or reserve
activations and frequency correction
initiatives.
Service
This is a new rate schedule effective
on October 1, 2011, through September
30, 2016. Western is proposing to adopt
its existing EI formula rate methodology
for GI. The provisional rate for this
service is comprised of three
components:
Component 1: GI is applied to
deviations as follows: (1) For deviations
within the bandwidth, there will be no
financial settlement, unless otherwise
dictated by contract; rather, GI will be
tracked and settled with energy; (2)
negative deviations (under-delivery),
outside the deviation bandwidth, will
be charged the greater of 150 percent of
market price or 150 percent of Western’s
actual cost; and (3) positive deviations
(over-delivery), outside the deviation
bandwidth, will be lost to the system,
except for any hour where Western
incurs a cost, then that cost will be
borne by the responsible party.
Deviations that occur as a result of
actions taken to support reliability will
be resolved in accordance with existing
contractual requirements. Such actions
include reserve activations or
uncontrolled event responses as
directed by the responsible reliability
authority such as SBA, HBA, Reliability
Coordinator, or Transmission Operator.
To the extent that an entity
incorporates intermittent resources,
deviations will be charged the same as
defined above except for negative
deviations outside the bandwidth
(under-delivery) will not be charged the
penalty, only the greater of actual cost
or market price. Intermittent generators
serving load outside of SNR’s SBA will
be required to dynamically schedule or
dynamically meter their generation to
another BA. An intermittent resource for
the limited purpose of these rate
schedules is an electric generator that is
not dispatchable and cannot store its
output, and therefore, cannot respond to
changes in demand or respond to
transmission security constraints.
This formula rate also contains
Components 2 and 3.
Similar to EI, FERC Order No. 890
defines a three-tier methodology for GI.
The order allows alternatives to designs
if the rate schedule follows the intent of
the three principles: (1) Charges are
based on incremental cost or some
multiple thereof; (2) charges must
provide incentives for good scheduling
practices; and (3) provisions should
address intermittent renewable
resources (wind/solar) and waive
punitive penalties.
Similar to Western’s existing EI rate
schedule, GI will follow FERC intent by:
(1) Establishing a tiered methodology;
within the bandwidth, energy is
exchanged, over-deliveries are lost to
the system, and under-deliveries are
charged the greater of 150 percent of the
CAISO market price or 150 percent of
Western’s actual cost; (2) penalties
outside the bandwidth also provide
incentives for good scheduling
practices; and (3) to the extent that an
entity incorporates intermittent
resources, Western will eliminate the
150 percent of market price and actual
cost factor for under-deliveries and will
charge the greater of market price or
Western’s actual cost.
Currently, Western has no existing
customers subject to GI. Western will
revisit FERC Order No. 890’s approach
as well as Western’s existing settlements
and billing processes and will consider
a transition to FERC’s methodology
during Western’s next rate process or
earlier if deemed appropriate.
October 1, hour ending 1
Price
Western’s Calculated Actual Cost ($18.27 × 150%) applied per
rate schedule.
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Sfmt 4703
Accordingly, for deviations outside of
the bandwidth, the GI charge is
recovered using the greater of 150
percent of the market price or 150
percent of Western’s actual cost. The
actual cost is calculated using CVP
generation RR and associated energy.
Additional costs subject to recovery
include: (1) HBA’s charges or credits; (2)
FERC’s or other regulatory bodies’
accepted or approved charges or credits;
and (3) any other statutorily required
costs or charges.
The GI charge will be recovered from
SBA Customers that have contracted
with Western for this service. Since the
actual cost is calculated based on
Western’s cost of generation, it is subject
to change prior to the effective rate
period.
Below is an example of how the GI
charge is calculated using Component 1.
GI SERVICE CHARGE EXAMPLE
CALCULATION (COMPONENT 1)
If, on October 1, HE 1, Customer A
has:
Scheduled Net Interchange ............
Actual Net Interchange ...................
Scheduled Generation in excess of
Actual Generation (under-delivery).
Contractual Bandwidth ....................
GI for HE 1 ......................................
102 MW
90 MW
12 MW
8 MW
4 MW
To derive the total monthly charge for
Customer A, the GI is calculated for
each hour that it occurs during the
month. The GI charge is based upon a
comparison between the real-time
energy pricing from the CAISO for each
hour and Western’s actual cost, both
multiplied by 150 percent, for that same
hour. The higher of the two is applied
to derive the GI charge.
The following table is an example of
how Western determines the GI charge
related to the GI in the table above:
Price comparison
150% of Actual < 150% of Market.
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Charge
N/A
N/A
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October 1, hour ending 1
Price
Real-Time CAISO price ($21.84 × 150%) applied per rate schedule.
$32.76
Price comparison
MW
150% Market > Actual ...............
Charge
4
$131.04
Note: GI charge for October 1, HE 1 is calculated as follows: 4 MW × $32.76 = $131.04.
GI charges will not apply as a result
of action taken to support reliability.
Such actions include reserve activations
or uncontrolled event response as
directed by the responsible reliability
authority, such as SBA, HBA, Reliability
Coordinator, or Transmission Operator.
To the extent that an entity
incorporates intermittent resources,
treatment of such will be determined in
the associated contract.
Relationship between EI and GI
EI and GI service charges and energy
accounting will be netted within the
hour, or in accordance with approved
procedures, with charges for both
services allowable only when the
imbalances for both are deficit, rather
than offsetting—one deficit and one
surplus. Note—this only applies to
netting within the bandwidth.
EXAMPLE OF RELATIONSHIP BETWEEN
EI AND GI
Transmission Provider or SBA can charge
customers for both EI and GI service in the
same hour, but not if the imbalances offset
each other.
Example of Offsetting:
• For example—Customer A
>> GI: ¥10 MW deficit
>> EI service: 5 MW surplus
>> Customer A charged: 5 MW (GI
charge)
Example of Aggravating (increasing—absolute value)
EXAMPLE OF RELATIONSHIP BETWEEN
EI AND GI—Continued
• For example—Customer B
<< GI Service: ¥10 MW deficit
<< EI service: ¥10 MW deficit
<< Customer A charged: ¥10 MW for
GI charge plus ¥10MW for EI charge
Statement of Revenue and Related
Expenses
The following table provides a
summary of projected revenues and
expenses for the rates through the 5-year
provisional rate approval period. The
table includes comparison of existing
rate data to estimated rate data and the
difference.
SUMMARY TABLE OF REVENUES AND EXPENSES
Rate Recovery CVP, COTP, and PACI—5-Year Rate Comparison Existing (FY 2006–FY 2010) to Provisional Rate Period (FY 2012–FY 2016)
Total Revenue and Expenses (in thousands)
Existing Rate Period FY 2006–FY
2010
Provisional Rate
Period FY 2012–
FY 2016
Differences
Total Revenue .................................................................................................................
..........................................................................................................................................
Revenue Distribution.
Expenses:
O&M ..........................................................................................................................
Purchase Power & Transmission .............................................................................
Interest Expense .......................................................................................................
Other Expense (inc. wheeling) .................................................................................
$1,563,274
............................
$1,955,569
............................
$392,295
............................
411,204
875,402
26,371
177,817
496,505
1,180,215
50,881
173,331
85,301
304,812
24,510
(4,486)
Total Expenses ..................................................................................................
1,490,794
1,900,931
410,137
Principal Payments:
Capitalized Expenses (deficits) ................................................................................
Original Project and Additions ..................................................................................
Replacements ...........................................................................................................
Aid to Irrigation .........................................................................................................
Power Rights ............................................................................................................
4,890
51,075
14,521
0
1,994
0
52,644
0
0
1,994
(4,890)
1,569
(14,521)
0
0
Total Principal Payments ..................................................................................
72,480
54,638
(17,842)
Total Revenue Distribution ................................................................................
1,563,275
1,955,569
392,294
Revenue or Expense Category
emcdonald on DSK4SPTVN1PROD with NOTICES2
Basis for Rate Development
The existing formula rate
methodologies expire on September 30,
2011. Western considered all comments
received during its public consultation
and comment period. The comments
and responses, paraphrased for brevity
when not affecting the meaning of the
statement(s), are discussed below. Direct
quotes from comment letters or the
public comment forum are used for
clarity where necessary. The comments
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and responses discussed below are: (1)
BR and FP power; (2) CVP transmission;
(3) ancillary services; and (4) other
comments. Also, questions received
from customers during the public
consultation and comment period were
answered and resolved and are not
discussed below. Those questions and
responses are posted at Western’s Web
site located at: https://www.wapa.gov/sn/
marketing/rates/ratesProcess/
formalProcess/CIL2011/index.asp.
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Several customers expressed
appreciation for Western’s efforts during
the comprehensive informal and formal
rate process and support maintaining
the existing formula rate methodologies.
BR and FP Power Comments
A. Comment: During the formal
process, the FP Customers stated
Western should consider the following
in its final rate filing: (1) Perform a FP
percentage true-up each year; (2)
maintain a maximum percentage
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threshold; (3) any increases at midyear
be collected over remaining months of
the FY versus collected in one month;
(4) include a requirement that Western
consider input from FP Customers prior
to publishing percentages; (5) provide
an explanation for any difference
between FP and PU payment obligation;
and (6) provide customers with advance
notice (6 months to 1 year) if changes
to maximum percentages are
anticipated.
Response: Western considered
customer comments and is adopting a
true-up methodology for FP Customers
each year in order to ensure FP
Customers pay their proportionate share
of the PRR. The FP percent true-up
calculation will be based on actual data
for the FY being adjusted. Changes to
PRR based on FP percentage true-up
calculations will be incorporated in the
PRR at the beginning of each FY as
shown in the example below, and will
be applied to both FP and BR Customers
to ensure full cost recovery of the PRR.
As shown in Table 1, the total PRR for
Year 1, as published on October 1, is
$75,000,000, and the estimated payment
is allocated to customers based on their
estimated FP and BR percentages.
Following a true-up of FP percentages in
Year 2, the difference between estimated
and actual will be reflected in the PRR
in Year 3.
TABLE 1—ESTIMATED AND ACTUAL YEAR 1 PRR ALLOCATION DUE TO FP % TRUE-UP
Customer
Customer
Customer
Customer
A
B
C
D
........................
........................
.......................
.......................
Year 1 FP and
BR PRR
allocation
Year 1 FP % (based on
estimate)
FP Customer
0.35%
0.90%
2.80%
0.75%
Year 1 actual FP %
(determined during year 2)
Year 1 FP and
BR actual
(adjusted)
PRR allocation
Difference
(applied in year
3)
...............................
...............................
...............................
...............................
$262,500
675,000
2,100,000
562,500
0.38%
0.85%
2.90%
0.75%
...............................
...............................
...............................
...............................
$285,000
637,500
2,175,000
562,500
$22,500
(37,500)
75,000
0
Total ............................
4.80% ...............................
3,600,000
4.88% ...............................
3,660,000
60,000
BR Customers ............
Contractual % ...................
71,400,000
Contractual % ...................
71,340,000
(60,000)
Total PRR (Year 1) ....
...........................................
75,000,000
Total PRR .........................
75,000,000
0
Beginning in Year 3, the PRR, as
published on October 1, is $73,000,000.
Based on the true-up methodology, the
adjustment (difference seen in Table 1)
from Year 1 is factored in the PRR for
Year 3, and payment obligations for
both FP and BR Customers are
appropriately adjusted as shown in the
Table 2 below.
TABLE 2—FP % ADJUSTMENT FROM YEAR 1 (ACTUAL TO ESTIMATED PAYMENT) APPLIED IN YEAR 3
FP Customer
A
B
C
D
...............................................
...............................................
...............................................
...............................................
0.35%
0.90%
2.85%
0.77%
PY FP true-up
(Year 1 true-up
amount)
Total year 3 bill
.......................................................
.......................................................
.......................................................
.......................................................
$255,500
657,000
2,080,500
562,100
$22,500
(37,500)
75,000
0
$278,000
619,500
2,155,500
562,100
Total ...................................................
4.87% .......................................................
3,555,100
60,000
3,615,100
BR Customers ...................................
Contractual % ...........................................
69,444,900
(60,000)
69,384,900
Total PRR (Year 3) ............................
emcdonald on DSK4SPTVN1PROD with NOTICES2
Customer
Customer
Customer
Customer
Year 3 estimated
PRR payment
Year 3 est. FP %
...................................................................
73,000,000
0
73,000,000
Based on the true-up adjustment from
Year 1, the PRR is appropriately
allocated to both FP and BR Customers
in Year 3.
Western will continue to: (1) Maintain
its maximum percentage methodology
so that during periods of low hydrology
there is limited PRR financial obligation
for FP Customers; (2) collect costs from
changes at midyear over remaining
months in FY; and (3) maintain its
current communication procedures
including receiving input during
development of percentages. Western
currently notifies and receives input
from the FP Customers when
developing the FP percentages prior to
finalizing the FP percentage at the start
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of the FY and during the midyear FP
percentage review. Western intends on
continuing with this communication
effort. Western is adopting a true-up for
the FP Customers’ allocation of the PRR;
therefore, the FP Customers will pay
their proportionate share of the PRR up
to the maximum FP percentage. Western
is changing the language in the BR and
FP power rate schedule to reflect the
annual FP true-up procedure. Also,
according to current policy, FP
maximum percentages are established
once at the beginning of each 5-year rate
adjustment period, and generally do not
change. While changes are not
anticipated, if Western deems a review
of the FP Customers’ maximum
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percentage appropriate, Western will
notify the customers. Finally, as
discussed during informal rate
meetings, while both FP and PU load
obligations are statutory, cost recovery
obligations vary. Western, in concert
with Reclamation and customers,
established a cost recovery policy for
PU, namely, the PU cost sub-allocation
methodology, and recovers PU costs
annually. Alternatively, FP Customers’
cost recovery methodology was
established through Western’s rate
adjustment procedures. Further, FP
Customers are power customers and
more closely aligned with Western’s
Preference Customers than
Reclamation’s water customers.
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B. Comment: A customer suggested
that Western consider publishing the
final PRR by September 15, rather than
by September 30, to aid customers in
their budgeting process.
Response: Western’s PRR developed
prior to the start of each FY is
dependent on the timing and receipt of
other data that impacts the PRR, such as
transmission and regulation RRs, FP
load projections, power purchases, and
other financial or operational data.
Western may require time beyond
September 15 to finalize the PRR and
other rates. In response to customers’
budgeting needs, Western plans to
publish a PRR forecast during May of
each year to provide rate information to
customers for budgeting and other
purposes. Additionally, Western will
continue to strive for rate stability and
predictability. While Western will
attempt to publish the PRR by
September 15, it will maintain its
current publication date of September
30. There will be no change to the rate
schedule.
C. Comment: Several customers
suggested that Western establish a
trigger or safety valve in the formula rate
to defer or terminate costs when
Western’s rates are uneconomic due to
extended periods of low generation or
operational constraints.
Response: Western has a statutory
obligation to recover its costs within
certain prescribed periods. Western also
ensures its costs are the lowest cost
possible consistent with sound business
principles. Additionally, Western
continues to strive for rate stability.
Western’s recent PRR forecast exhibits
stable, level rates. From the comments,
Western understands the customer rate
volatility is primarily driven by
Reclamation’s Restoration Fund costs,
hydrology, market conditions, pumping
or biological restrictions, or other factors
outside of Western’s control. While
these items are outside the scope of the
rate process, Western understands the
customers’ position that if the project
becomes uneconomic due to these types
of external factors, project repayment
could be impacted. Deferring Western’s
costs from one period to a future period
or periods, however, introduces external
and unpredictable volatility to an
otherwise stable PRR. Additionally,
generation triggers are not fully known
until the April-through-June time frame;
therefore, a change to an annual PRR
could not be perfected until as late as
June creating cash-flow concerns.
Western previously responded to
customers’ concerns to align power
recovery more closely with generation
by billing 75 percent of the BR RR in the
period where the most benefit is
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received. Finally, while the factors
discussed above are outside of
Western’s control, Western will
continue to work with other agencies,
when possible, in an attempt to address
the factors, such as working with
Reclamation in an effort to stabilize the
Restoration Fund. Given legal and
policy constraints and the fact the
decisions are made by other agencies,
outside factors or markets, Western
cannot guarantee any outcomes.
D. Comment: Several customers
suggested that the HE program should
be adjusted annually based on a formula
(PRR/forecasted BR) with a true-up
provision.
Response: Western’s current HE
methodology ensures the cost of BR and
HE energy is valued the same in the
month the energy is used. Valuing the
HE energy based on derived annual
costs and BR energy based on derived
monthly costs creates inequities for
energy in similar periods. Western’s
analysis of the customers’ proposal
revealed that assessing HE monthly,
rather than yearly, has a cumulative
minimal monetary effect. The HE
program is voluntary, and Western will
continue to support the program in the
current form.
E. Comment: A customer suggested
the HE program should be allocated 50
percent on the number of participants
and 50 percent on BR percentage.
Response: As Western stated in
comment D above, valuing the HE
energy differently than BR energy
creates inequities. Currently, in
accordance with Western’s BR contracts,
HE is generally allocated 100 percent
based on the number of participants.
Here, a customer requested a change to
the HE program allocation methodology,
which is contractual and not part of the
rate process. The HE program is
voluntary, and Western will continue to
support the program in the current form.
F. Comment: A customer commented
that Western should clarify the general
power contract provision (GPCP) 11
meaning of ‘‘date of a rate change’’ and
if it allows a preference customer to
terminate its Federal power allocation
each time a new PRR is developed and
implemented.
Response: While GPCPs are outside
the scope of the rate process, GPCP 11
is intended to provide an opportunity to
allow a customer to terminate a contract
when Western adjusts the rates through
the formal rate adjustment proceedings.
A rate adjustment is defined by
regulation. The regulations state that a
change in a monetary charge that results
from a formula is not a rate adjustment.
G. Comment: Several customers’
suggested the VR scheduling charge
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56923
increase should be based on actual costs
versus the set 3 percent per year
increase.
Response: Western considered
customers comments and re-analyzed its
VR scheduling charge rate development
and confirmed that its results are still
valid for the rate period. Western’s O&M
expense for the period of 2005 through
2010 increased, on average, 4 percent
annually. Western’s O&M for the
relevant rate period is expected to
increase 3 percent annually, partially
because FY 2011 and FY 2012 have no
cost-of-living adjustments to payroll.
The prospective annual rate and cost
recovery for this service totals
approximately $30,000. A 3 percent
inflationary increase on $30,000 is $900.
Because the VR scheduling charge is
primarily driven by labor costs, Western
believes its charge is supported by
history and future projections, and
outweighs the cost of performing annual
adjustments.
H. Comment: A customer commented
that Scheduling Coordinator (SC) and
Portfolio Management (PM) charges for
Full Load Service Customers should be
reviewed and adjusted annually based
on actual costs.
Response: The SC and PM charges are
established in the scheduling
coordinator and FLS contracts and are
outside the scope of this public process.
However, to provide clarity on these
comments, when Western revised the
SC and PM charges, it performed an indepth analysis that considered all of the
elements that contribute to the cost of
providing SC and PM services. Findings
from, and an explanation of the
methodology used to conduct the study,
were presented to the customers at the
October 29, 2009, Informal Rates
meeting. At that meeting, Western stated
costs for performing its CVP legislative
and statutory requirements and
scheduling those requirements are
appropriately included in O&M. The
information presented at the meeting
showed that Western’s cost for
providing the necessary SC and PM
services as related to meeting these
requirements are paid for by all of the
CVP power customers. The costs for
providing additional and separate SC
and PM services are paid for by those
entities requesting such services, at no
additional cost to other CVP power
customers.
As discussed in the October 29, 2009,
Informal Rates meeting, Western did
increase future SC and PM rates for
inflation and salary increases and
committed to review the charges on an
ongoing basis.
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CVP Transmission Comments
I. Comment: A customer commented
that Western should waive UUP for
unscheduled use of the system related
to a contingency event, such as reserve
activation, and clarify in the appropriate
rate schedule to protect reserve sharing
agreements.
Response: Western exempts the
assessment of UUP to customers for
actions taken by Western to support
reliability, such as reserve activations or
an uncontrolled event response. Reserve
activation from reserve sharing
agreements in response to a said event
will be exempt from UUP. However, an
exemption from the assessment of UUP
does not relieve customers from paying
for unscheduled or unreserved
transmission and ancillary services, if
used.
J. Comment: Several customers
commented that Western’s transmission
cost allocation methodology, as it relates
to the Sacramento Area Voltage Support
(SVS) Project, is unreasonable and
Western should consider: (1) Allocating
costs based on proportional benefits; (2)
allocating costs using incremental
pricing; (3) allocating costs directly to
beneficiary; or (4) excluding costs from
rates.
Response: Western considered the
customers’ comments, reviewed its rate
methodology and alternatives, and
determined that its existing and
provisional cost allocation methodology
is consistent with Western’s statutory
rate recovery obligations. Western began
planning, in collaboration with its
customers, to mitigate the diminishing
reliability operation margins of its
transmission network in the Sacramento
region as early as 2001. As part of
Western’s SVS Program Draft
Supplemental Environmental Impact
Statement, Western identified the
purpose and need for the SVS Project.
Western’s CVP transmission system is
affected by voltage stability, reliability,
and security of the greater Sacramentoarea transmission system. The
transmission studies performed in 2006
and 2007 continued to show that the
existing transmission lines in the greater
Sacramento area had reached their
maximum power transfer limits. As a
result, load-serving entities and utilities
in the area have taken interim measures
to avoid potential uncontrolled systemwide outages; however, in an effort to
avoid load shedding and potential
rotating blackouts and in order to ensure
the continued reliable operation of
Western’s system and to meet its
contractual and statutory obligations,
Western determined it was necessary to
construct the SVS Project.
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During the informal rate process,
Western engaged customers and sought
input and comments regarding its
formula rates. Additionally, during the
June 25, 2010, Informal Rates meeting,
Western provided a forecast of its
transmission rates based on currently
planned and funded projects. Western
also published on its Open Access Same
Time Information System (OASIS) and
Rates Web site, transmission rate
forecasts on May 20, 2010, and
November 22, 2010, to include the rate
impact of the SVS and other
transmission projects.
The SVS Project is a network upgrade,
as defined under Western’s OATT, for
the continued reliable operation and
support of Western’s CVP transmission
system; and, as a result, all of Western’s
network customers receive benefits from
the SVS Project. Western’s existing and
provisional formula rate methodologies
are the same and allocate network
upgrade costs to Western’s transmission
customers based on system usage and
reserved capacity. Therefore, in this
case the application of incremental
pricing or other pricing methodology for
the SVS Project is inappropriate.
Further, Western cannot exclude the
costs of the SVS Project from its rates.
Unless specifically authorized by
Congress, Western must recover all of its
costs. Western does not have
Congressional authority to exclude the
costs of SVS, and Western must recover
those costs.
As part of the formal rate process,
Western gave the customers an
opportunity to provide any information
on other authorities that would allow
Western to capture transmission costs
for a single facility under both
embedded costs and incremental costs
or under an alternative methodology.
While Western develops its rates under
DOE orders and is not bound by pricing
policies of others, Western believes it is
important to understand other
authorities, such as FERC policies, and
evaluate them.
One customer commented that
pursuant to FERC’s June 17, 2010,
Notice of Proposed Rulemaking
(NOPR),31 FERC now requires that cost
be allocated roughly in proportion to
benefits. Under the NOPR, the customer
implied that if a customer receives no
benefits from a network upgrade, the
customer should not be allocated any
costs for the network upgrade or at least,
the customer only should be allocated
costs in proportion to the benefits.
While Western appreciates the
31 See Transmission Planning and Cost Allocation
by Transmission Owning and Operating Public
Utilities, 131 FERC ¶ 61,253 (2010).
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customer’s research into the matter,
Western is concerned about adopting a
pricing methodology that would allocate
specific network upgrade costs
commensurate to individual benefits.
Such an approach would be difficult
and costly to administer. Under such an
approach, any customer could argue the
benefits it receives are not
commensurate to its costs. Such an
approach could require Western to
evaluate each and every line and
determine how much each and every
customer benefits. The process would
require Western to determine how to
allocate the costs for reliability benefits.
Furthermore, it becomes difficult to
determine, over time, which users
benefit from which upgrades. Some
upgrades are made possible by others—
some are required because of others.
Western also recognizes the limitations
of establishing rate-making policy based
on a NOPR, which is not yet final. In
some instances, FERC’s final decision
has varied from its NOPR. Because of
the uncertainties associated with
utilizing a benefit pricing model at this
time, Western does not believe it is
prudent to adopt such a model.
Western also evaluated the ‘‘and’’
pricing model suggested by earlier
comments. Western does not believe it
is equitable to charge both the
embedded cost and incremental cost to
certain users of the grid. Such a pricing
policy would place an undue and
discriminatory burden on a small group
of customers.
One customer referencing Western’s
OATT, Attachment P, stated that
Western has the ability to allocate costs
of new transmission on a case-by-case
basis. Western’s OATT, Attachment P,
sets forth the provisions for cost
allocation related to transmission
planning and not transmission rates.
Western remains committed to an open
and transparent transmission planning
process.
For the reasons discussed above,
Western believes the application of
incremental transmission pricing or
other transmission pricing methodology
recommended by customers for the SVS
Project is inappropriate at this time and
will not implement either.
K. Comment: Western should reflect
the full 270 MW of incremental capacity
for SVS in its rate.
Response: As stated in Western’s
response on February 23, 2011, Western
estimated 126 MW of new transmission
capacity from SVS for the purpose of
forecasting its 2012 rate. The actual
capacity would be based on Western’s
system study results at the time the SVS
Project became commercially
operational and, subsequently, be used
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in determining the effective rate under
the provisional transmission formula
rate. Study results completed in April
2011 indicated that 165 MW of
additional transfer capability into the
Sacramento area would be available;
therefore, 165 MW will be used in
calculating Western’s forecasted CVP
transmission rate.
L. Comment: A customer stated that it
receives no benefit from the network
upgrade and further requested
clarification of the extent to which the
transmission upgrade will reduce or
eliminate the need for Western to rely
on Sutter Energy Center (Sutter) for
voltage support.
Response: Western’s transmission
customers benefit from the addition of
network upgrades that improve reliable
operation of the network. As described
in the response to Comment ‘‘J’’ above,
Western constructed the SVS Project as
a network upgrade to ensure the
continued reliable operations of the CVP
Federal transmission system. The SVS
Project will also reduce the reliance
upon remedial action schemes (RAS)
(including the RAS for Sutter). Sutter’s
obligation to provide voltage support as
a function of NERC/WECC reliability
requirements will not change as a result
of the SVS transmission project.
M. Comment: A customer commented
that intermittent resources should not
degrade or compromise existing
reliability of the CVP; additions or
integration of renewable resources
should be fully studied and costs should
be appropriately allocated.
Additionally, customers requested
Western involve all rate payers on all
proposed future expansion of CVP
transmission network.
Response: Western agrees intermittent
resources should not degrade or
compromise the reliability of the CVP.
Western’s future transmission planning
processes are outside the scope of this
process. Western’s OATT, Attachment
P, delineates Western’s transmission
planning process. Western reminds its
customers and others that Western
typically holds quarterly transmission
meetings, prepares and presents its 10year transmission plan annually, and
posts meeting notifications, documents,
and plans on its OASIS at https://
www.oatioasis.com/wasn/.
As intermittent resource entities request
interconnection to Western’s system,
Western incorporates such requests into
its process and ensures costs are
appropriately allocated.
Ancillary Services Comments
N. Comment: A customer suggested
that Western apply 150 percent penalty
to market and actual cost rather than
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just market cost for deviations outside
the bandwidth for EI, GI, and when
customers self-provide but fail to
perform for spinning and supplemental
reserves and regulation, respectively.
Response: Western agrees with the
customer’s suggestion that the 150
percent penalty should be applied to
both the market price and Western’s
actual cost. Currently, Western applies
the 150 percent penalty on the market
price only and is adopting the 150
percent penalty for the actual cost.
Without a penalty on Western’s actual
cost, there is no penalty. Because the
penalty is intended to incent good
scheduling, or encourage customers
with a requirement to self-provide
ancillary services to perform their
obligation, Western concluded the
penalty should also apply to its actual
cost. This will be applicable to the
following rate schedules: (1) EI service;
(2) GI service; (3) regulation and
frequency response service (penalty for
non-performance); (4) spinning reserve
service (penalty for non-performance);
and (5) supplemental reserve service
(penalty for non-performance).
O. Comment: A customer suggested
that Western charge any costs incurred
under EI and GI, including negative
pricing, when disposing of surplus
energy to the responsible party.
Response: Pursuant to Western’s EI
and GI rate schedules, positive
deviations (over-delivery), outside the
bandwidth, are lost to the system.
However, Western agrees with the
commenter that Western should charge
costs to responsible parties in instances
where Western incurs a cost for
disposing of surplus energy, and
Western will charge accordingly.
P. Comment: A customer asked that
Western consider reinstating
compensation to generators, including
Sutter, for reactive power supplied to
support the Sacramento region,
particularly to the SMUD and Roseville
service areas.
Response: Western reviewed the
history of removing reactive power from
its TRR, analyzed its current operations
and FERC comparability rules, and
determined that conditions and
limitations existing during our Rate
Order WAPA–128 filing continue to
exist today. Therefore, based on the
reasons previously articulated in
Western’s Rate Order WAPA–128, and
to continue to adhere to FERC
comparability standards, Western is not
changing from its current methodology.
Q. Comment: Several customers
commented that Western should
restructure regulation and frequency
response services to be consistent with
how services are provided for spinning
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56925
and supplemental reserves. Customers
also commented that CVP generation
should not be reserved for a subset of
customers, but rather should be made
available for all CVP Preference
Customers. Alternatively, customers
requiring regulation should (1) Use their
BR, if available, and (2) if not, Western
should procure on their behalf, or (3)
those requiring regulation should selfprovide.
Response: The marketing of regulation
and frequency response service is
outside the scope of this rates process.
Western will continue to follow the
terms of its 2004 Marketing Plan, which
states that CVP generation must be
adjusted for reserves, as well as other
obligations, such as project use and
losses, before CVP generation is
available for marketing. Western’s
policy-decision and rate methodology
used to recover the cost from entities
requiring regulation has been in place
since 2005 and has generated annual
revenue averaging approximately $1.2
million. That revenue reduces the
overall cost in the PRR.
Other Comments
R. Comment: A customer commented
that Western should include Restoration
Fund costs in the generation RR.
Response: Western is a billing agent
for Reclamation, and the Restoration
Fund is not a part of Western’s costs.
The billing requirements for the
Restoration Fund were set in a separate
public process, and thus are outside the
scope of this public process.
S. Comment: A customer suggested
that Western should offer a policy to
challenge costs in the Restoration Fund.
Response: Western, as the Restoration
Fund billing agent for Reclamation, will
continue to work with Reclamation to
examine and explain Restoration Fund
costs. This and other Restoration Fund
comments should be addressed in a
Restoration Fund public process and are
outside the scope of this public process.
T. Comment: A customer suggested
that the Restoration Fund be recovered
on a moving-average basis to avoid rate
shock.
Response: Western, as the billing
agent, will continue to work with
Reclamation to examine the Restoration
Fund. This and other Restoration Fund
comments should be addressed in a
Restoration Fund public process and are
outside the scope of this public process.
Availability of Information
Information about this rate
adjustment, including PRS, rate
brochure, studies, comments, letters,
memorandums, and other supporting
material made or kept by Western and
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Federal Register / Vol. 76, No. 178 / Wednesday, September 14, 2011 / Notices
In compliance with the National
Environmental Policy Act of 1969
(NEPA) (42 U.S.C. 4321, et seq.), the
Council on Environmental Quality
Regulations for implementing NEPA (40
CFR parts 1500–1508), and DOE NEPA
Implementing Procedures and
Guidelines (10 CFR part 1021), Western
has determined that this action is
categorically excluded from further
NEPA analysis.
Order
In view of the foregoing and under the
authority delegated to me, I confirm,
approve, and place into effect on
October 1, 2011, on an interim basis,
Rate Order WAPA–156, which includes
Rate Schedules CV–F13, CPP–2, CV–T3,
CV–NWT5, COTP–T3, PACI–T3, CV–
TPT7, CV–UUP1, CV–SPR4, CV–SUR4,
CV–RFS4, CV–EID4, and CV–GID1, for
the CVP, COTP, and PACI of Western.
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 a rate for a
new service. 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, or until superseded.
Determination Under Executive Order
12866
Dated: September 2, 2011.
Daniel B. Poneman
Deputy Secretary
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.
Rate Schedule CV–F13
used to develop the provisional formula
rates, is available for public review at
the SNR office, located at 114 Parkshore
Drive, Folsom, California, 95630, or
where available at the following Web
site: https://www.wapa.gov/sn/
marketing/rates/.
Ratemaking Procedure Requirements
Environmental Compliance
Submission to the FERC
The provisional 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.
(Supersedes Schedule CV–F12)
Central Valley Project
Schedule of Rates For Base Resource
and First Preference Power
Effective: October 1, 2011, through
September 30, 2016.
Available: Within the marketing area
served by the Western Area Power
Administration (Western), Sierra
Nevada Customer Service Region.
Applicable: To the Base Resource (BR)
and First Preference (FP) Power
Customers.
Character and Conditions of Service:
Alternating current, 60-hertz, threephase, delivered and metered at the
voltages and points established by
contract. This service includes the
Central Valley Project (CVP)
transmission (to include reactive supply
and voltage control from Federal
generation sources needed to support
the transmission service), spinning
reserve service, and supplemental
reserve service.
Power Revenue Requirement (PRR):
Western will develop the PRR prior to
the start of each fiscal year (FY). The
PRR will be divided in two 6-month
periods, October through March and
April through September, based on FP
and BR percentages. The PRR for the
April-through-September period will be
reviewed in March of each year. The
review will analyze financial data from
the October-through-February period, to
the extent information is available, as
well as forecasted data for the Marchthrough-September period. If there is a
change of $5 million or more, the PRR
will be recalculated for the entire FY.
The PRR is allocated to FP Customers
and BR Customers based on formula
rates, as adjusted for Hourly Exchange
(HE), FP true-up calculation, and
midyear adjustments.
EXAMPLE OF PRR ALLOCATION TO FP AND BR
Component
Formula
Allocation
Annual PRR ..............................................................................
FP Customers’ Allocation (Total FP % = 5%) ..........................
Remaining PRR Allocated to BR ..............................................
...................................................................................................
$70,000,000 × 5% ....................................................................
$70,000,000—$3,500,000 ........................................................
$70,000,000
3,500,000
66,500,000
Note: This example is intended to show the PRR allocation to the customer groups and is not adjusted for billing, midyear adjustments or FP
true-up calculation.
the relevant FP percentage. The formula
rate for FP power has three components.
Component 1:
Where:
FP Customer Load = An FP Customer’s
forecasted annual load in megawatthours
(MWh).
Gen = The forecasted annual CVP and
Washoe generation (MWh).
Power Purchases = Power purchases for
Project Use and FP loads (MWh).
Project Use = The forecasted annual Project
Use loads (MWh).
MRR = Monthly PRR.
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Western will develop each FP
customer’s percentage prior to the start
of each FY. During March of each FY,
each FP customer’s percentage will be
reviewed. If, as a result of the review,
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there is a change in a FP customer’s
percentage of more than one-half of 1
percent, the percentage will be revised
for the April-through-September period
and billing adjustments made for the
October-through-March period to reflect
the revised percentage.
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FP Power Formula Rate:
The annual FP customer allocation is
equal to the annual PRR multiplied by
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Federal Register / Vol. 76, No. 178 / Wednesday, September 14, 2011 / Notices
TABLE 1—ESTIMATED AND ACTUAL YEAR 1 PRR ALLOCATION DUE TO FP % TRUE-UP
Customer
Customer
Customer
Customer
A
B
C
D
........................
........................
.......................
.......................
Year 1 FP and
BR PRR
allocation
Year 1 FP % (based on
estimate)
FP Customer
0.35%
0.90%
2.80%
0.75%
Year 1 actual FP %
(determined during year 2)
Year 1 FP and
BR actual
(adjusted)
PRR allocation
Difference
(applied in year
3)
...............................
...............................
...............................
...............................
$262,500
675,000
2,100,000
562,500
0.38%
0.85%
2.90%
0.75%
...............................
...............................
...............................
...............................
$285,000
637,500
2,175,000
562,500
$22,500
(37,500)
75,000
0
Total ............................
4.80% ...............................
3,600,000
4.88% ...............................
3,660,000
60,000
BR Customers ............
Contractual % ...................
71,400,000
Contractual % ...................
71,340,000
(60,000)
Total PRR (Year 1) ....
...........................................
75,000,000
Total PRR .........................
75,000,000
0
In addition, Western is adopting a
true-up methodology for FP Customers
each year in order to ensure FP
Customers pay their proportionate share
of the PRR. The FP percentage true-up
calculation will use actual data for the
FY being adjusted. Changes to the PRR
based on FP percentage true-up
calculations will be incorporated in the
PRR at the beginning of each FY as
shown in the example below. As shown
in the example in Table 1, the total PRR
for Year 1, on October 1, is $75 million,
and estimated revenue requirements are
allocated to customers based on their
estimated FP and BR percentages. A
true-up of each FP percentage for Year
1 occurs in Year 2 and the difference
between the estimated and actual will
be reflected in the PRR in Year 3.
Beginning in Year 3, the PRR, as
published on October 1, is $73,000,000.
Based on the true-up methodology, the
adjustment (difference seen in Table 1)
from Year 1 is factored in the PRR for
Year 3, and payment obligations for
both FP and BR Customers are
appropriately adjusted as shown in the
Table 2 below.
TABLE 2—FP % ADJUSTMENT FROM YEAR 1 (ACTUAL TO ESTIMATED) APPLIED IN YEAR 3
FP customer
A
B
C
D
...............................................
...............................................
...............................................
...............................................
0.35%
0.90%
2.85%
0.77%
PY FP true-up
(year 1 true-up
amount)
Total year 3 bill
.......................................................
.......................................................
.......................................................
.......................................................
$255,500
657,000
2,080,500
562,100
$22,500
(37,500)
75,000
0
$278,000
619,500
2,155,500
562,100
Total ...................................................
4.87% .......................................................
3,555,100
60,000
3,615,100
BR Customers ...................................
Contractual % ...........................................
69,444,900
(60,000)
69,384,900
Total PRR (Year 3) ............................
emcdonald on DSK4SPTVN1PROD with NOTICES2
Customer
Customer
Customer
Customer
Year 3 estimated
PRR payment
Year 3 est. FP %
...................................................................
73,000,000
0
73,000,000
Based on the true-up adjustment from
Year 1, the adjusted PRR for Year 3 is
appropriately allocated to both FP and
BR Customers.
The percentages in the table below are
the maximum percentages for each FP
customer that will be applied to the
MRR during the rate period October 1,
2011, through September 30, 2016. The
maximum percentages were determined
based on a critically dry year where
there are hydrologic conditions that
result in low CVP generation and,
consequently, low levels of BR. An FP
percentage cannot exceed the maximum
except in instances where individual FP
customer percentages increase due to
load growth. If these maximum
percentages are used for determining the
FP customer charges for more than one
year, Western will evaluate customer
percentages from the formula rate versus
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Below is a sample calculation for an
FP customer’s monthly charge for
power.
the maximum percentage and make
adjustments as appropriate.
FP ACTUAL MAXIMUM PERCENTAGES
EFFECTIVE RATE PERIOD FY 2012
THROUGH FY 2016
Fmt 4701
3.16
20.56
Monthly Power Revenue Requirement (MRR) ..............
$3,333,333
FP Customer Monthly
Charge = (FP % x MRR) ..
Sierra Conservation Center ..................................
Calaveras Public Power
Agency ..........................
Trinity Public Utilities District ................................
Tuolumne Public Power
Agency ..........................
Total ...........................
Frm 00023
12.01
Numerator:
FP Customer’s Load—
MWh ..............................
Denominator:
Washoe Generation—
MWh ..............................
CVP Generation—MWh ....
PU Load—MWh ................
PU Purchase—MWh .........
Calculated Percentage:
FP Customer’s Percentage
$13,000
Maximum FP
customer
percentage
applied to the
MRR percent
FP customer
PO 00000
EXAMPLE: FP MONTHLY CUSTOMER
CHARGE CALCULATION
Sfmt 4703
1.58
3.81
E:\FR\FM\14SEN2.SGM
14SEN2
10,000
2,500
3,700,000
(1,200,000)
47,000
0.39%
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Component 2: Any charges or credits
associated with the creation,
termination, or modification to any
tariff, contract, or rate schedule
accepted or approved by the Federal
Energy Regulatory Commission (FERC)
or other regulatory bodies will be passed
on to each relevant customer. The
FERC’s or other regulatory bodies’
accepted or approved charges or credits
apply to the service to which this rate
methodology applies. When possible,
Western will pass through directly to
the relevant customer FERC’s or other
regulatory bodies’ accepted or approved
charges or credits in the same manner
Western is charged or credited. If
FERC’s or other regulatory bodies’
accepted or approved charges or credits
cannot be passed through directly to the
relevant customer in the same manner
Western is charged or credited, the
charges or credits will be passed
through using Component 1 of the
formula rate.
Component 3: Any charges or credits
from the Host Balancing Authority
(HBA) applied to Western for providing
this service will be passed through
directly to the relevant customer in the
same manner Western is charged or
credited to the extent possible. If the
HBA’s costs or credits cannot be passed
through to the relevant customer in the
same manner Western is charged or
credited, the charges or credits will be
passed through using Component 1 of
the formula rate.
BR Formula Rate: The annual BR
allocation is equal to the annual PRR
less the annual FP customer allocation.
The formula rate for BR has three
components.
Component 1:
BR Customer Allocation = (BR RR ×
BR%)
Where:
BR RR = BR Monthly Revenue Requirement
(RR)
BR% = BR percentage for each customer as
indicated in the BR contract after
adjustments for programs, such as HE, if
applicable.
After the FP Customers’ share of the
annual PRR has been determined,
including a prior period true-up from
the FP formula rate, the remainder of
the annual PRR is recovered from the
BR Customers. BR Customers’ allocation
will also be adjusted by the amount of
under- or overpayment by FP
Customers. The BR RR will be collected
in two 6-month periods. For October
through March, 25 percent of the BR RR
will be collected. For April through
September, 75 percent of the BR RR will
be collected. The monthly BR RR is
calculated by dividing the BR 6-month
RR by six. The revenues from the sale
of surplus BR will be applied to the
annual BR RR for the following FY.
An example of a reallocation program
is the HE program. BR Customers pay
for exchange energy, hourly or
seasonally, by adjusting the BR
percentage that is applied to the BR RR.
Adjustments to a customer’s BR
percentage for seasonal exchanges will
be reflected in the customer’s BR
contract.
An illustration of the adjustment to a
customer’s BR percentage for HE energy
is shown in the example below.
EXAMPLE OF BR PERCENTAGE ADJUSTMENTS FOR HE ENERGY
BR % from
contract
BR Customer
Hourly BR =
30 MWh
Customer’s
BR > load
Customers
receiving HE
BR delivered
(adj’d for HE)
Revised BR %
20%
10%
70%
6
3
21
3
0
0
0
1
2
3
4
23
10.0%
13.3%
76.7%
Total ..................................................
emcdonald on DSK4SPTVN1PROD with NOTICES2
Customer A ..............................................
Customer B ..............................................
Customer C ..............................................
100%
30
3
3
30
100.0%
Component 2: Any charges or credits
associated with the creation,
termination, or modification to any
tariff, contract, or rate schedule
accepted or approved by FERC or other
regulatory bodies will be passed on to
each relevant customer. The FERC’s or
other regulatory bodies’ accepted or
approved charges or credits apply to the
service to which this rate methodology
applies. When possible, Western will
pass through directly to the relevant
customer FERC’s or other regulatory
bodies’ accepted or approved charges or
credits in the same manner Western is
charged or credited. If FERC’s or other
regulatory bodies’ accepted or approved
charges or credits cannot be passed
through directly to the relevant
customer in the same manner Western
is charged or credited, the charges or
credits will be passed through using
Component 1 of the formula rate.
Component 3: Any charges or credits
from the HBA applied to Western for
providing this service will be passed
through directly to the relevant
customer in the same manner Western
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is charged or credited to the extent
possible. If the HBA’s costs or credits
cannot be passed through to the relevant
customer in the same manner Western
is charged or credited, the charges or
credits will be passed through using
Component 1 of the formula rate.
Billing: Billing for BR and FP power
will occur monthly using the respective
formula rate. Any adjustment made at
midyear is applicable to the entire FY
and billed over the remainder the FY.
Adjustment for Losses: Losses will be
accounted for under this rate schedule
as stated in the service agreement.
Adjustment for Audit Adjustments:
Financial audit adjustments that apply
to the formula rate under this rate
schedule will be evaluated on a case-bycase basis to determine the appropriate
treatment for repayment and cash flow
management.
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Rate Schedule CPP–2
(Supersedes Schedule CPP–1)
Central Valley Project
Schedule of Rates for Custom Product
Power
Effective: October 1, 2011, through
September 30, 2016.
Available: Within the marketing area
served by the Western Area Power
Administration (Western), Sierra
Nevada Customer Service Region.
Applicable: To customers that
contract with Western for Custom
Product Power (CPP).
To Variable Resources (VR) Customers
requesting scheduling for this service.
VR Customers will pay a scheduling
charge to recover Western’s cost for
scheduling VR CPP service.
Character and Conditions of Service:
Alternating current, 60-hertz, threephase, delivered and metered at the
voltages and points established by
contract, in accordance with approved
policies and procedures.
Formula Rate: The formula rate for
CPP includes three components:
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Component 1: The customer will pay
all costs incurred in the provision of
CPP. These costs will be passed through
to the customer. The methodology used
to calculate the amount of the pass
through will be based on the type of
funding used to purchase the CPP. The
CPP includes, but is not limited to,
supplemental power and Base Resource
(BR) firming power. If in the event
customer advance funding is used to
purchase CPP, then allocation of surplus
CPP sales will be determined based on
customer’s account status.
If the CPP is funded through
appropriations, Federal reimbursable, or
use of receipts authority, the cost of the
CPP is passed through to the
customer(s) for whom Western has
made the purchase. The CPP funded
through appropriations, Federal
reimbursable, or use of receipts
authority that is surplus to the load
requirements of the customer(s) will be
sold. Proceeds from the sale of surplus
CPP funded through use of receipts,
Federal reimbursable, or appropriations
authority will be applied to the CPP
purchase cost for the customer(s) to the
extent possible. If the cost of the CPP is
fully recovered and proceeds remain
from the sale of surplus CPP, the
remaining proceeds will be used to
reduce the Power Revenue Requirement
(PRR).
The table below illustrates the pass
through of the CPP costs to each
customer and the treatment of proceeds
from the sale of surplus CPP funded
through appropriations, Federal
reimbursable, or use of receipts
authority. As shown below, customers
A, B, and C are responsible for paying
the full costs of the CPP purchase made
by Western (total CPP revenue
requirement (RR) is $780). The CPP RR
of $780 is reduced by the sale of 1
megawatthour (MWh) at $45, which
reduces the CPP RR to $735. Therefore,
the reduced CPP RR of $735 is prorated
to each customer based on the amount
of CPP purchased on their behalf.
EXAMPLE: CPP COST RECOVERY WITH PROCEEDS FROM SALES OF SURPLUS CPP USE OF RECEIPTS, FEDERAL
REIMBURSABLE, OR APPROPRIATIONS AUTHORITY
If Western made a CPP purchase of 13 MW for the hour @ $60/MWh = $780
CPP
Purchased
(MWh)
CPP USED
(MWh)
CPP
costs
Surplus CPP
sold
Proceeds from
excess CPP
sales
CPP customer
charges
Customer A ..............................................
Customer B ..............................................
Customer C ..............................................
5
4
4
5
4
3
........................
........................
........................
0
0
1
........................
........................
........................
$283
226
226
Total ..................................................
13
12
$780
1
$45
735
NOTES:
1. Western sold 1 MWh of CPP at $45/MWh = $45.
2. Proceeds from the sale of surplus CPP reduce the CPP costs prorated based on the amount of CPP purchased.
Effective October 1, 2011, Western
will charge $37.91 per schedule per day
to cover its administrative costs for
procuring and scheduling CPP if the
customer has not contracted with
Western for this type of service through
other agreements. If the actual number
of schedules for the month is not
available, Western will estimate the
number of schedules for the month and
apply the $37.91 per schedule charge to
the estimated number of schedules.
The table below depicts the VR
scheduling charge per schedule for the
effective rate period.
VR SCHEDULING CHARGE (PER SCHEDULE) EFFECTIVE RATE FY 2012 THROUGH FY 2016
FY
2012
emcdonald on DSK4SPTVN1PROD with NOTICES2
VR Scheduling Charge Per Schedule .................................
Component 2: Any charges or credits
associated with the creation,
termination, or modification to any
tariff, contract, or rate schedule
accepted or approved by the Federal
Energy Regulatory Commission (FERC)
or other regulatory bodies will be passed
on to each relevant customer. The
FERC’s or other regulatory bodies’
accepted or approved charges or credits
apply to the service to which this rate
methodology applies. When possible,
Western will pass through directly to
the relevant customer FERC’s or other
regulatory bodies’ accepted or approved
charges or credits in the same manner
Western is charged or credited. If
FERC’s or other regulatory bodies’
accepted or approved charges or credits
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2013
$37.91
$39.04
cannot be passed through directly to the
relevant customer in the same manner
Western is charged or credited, the
charges or credits will be passed
through using Component 1 of the
formula rate.
Component 3: Any charges or credits
from the Host Balancing Authority
(HBA) applied to Western for providing
this service will be passed through
directly to the relevant customer in the
same manner Western is charged or
credited to the extent possible. If the
HBA’s costs or credits cannot be passed
through to the relevant customer in the
same manner Western is charged or
credited, the charges or credits will be
passed through using Component 1 of
the formula rate.
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2014
2015
$40.21
$41.42
2016
$42.66
Billing: Billing for CPP and VR
scheduling charge occurs monthly using
the formula rate.
Adjustments for Losses: All losses
incurred for delivery of CPP under this
rate schedule shall be the responsibility
of the customer that has contracted for
this service.
Adjustment for Audit Adjustments:
Financial audit adjustments that apply
to the formula rate under this rate
schedule will be evaluated on a case-bycase basis to determine the appropriate
treatment for repayment and cash flow
management.
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Rate Schedule CV–T3
(Supersedes Schedules CV–T2)
Central Valley Project
Schedule of Rate for Point-to-Point
Transmission Service
Effective: October 1, 2011, through
September 30, 2016.
Available: Within the marketing area
served by the Western Area Power
emcdonald on DSK4SPTVN1PROD with NOTICES2
Where:
CVP TRR = TRR is the cost associated with
facilities that support the transfer
capability of the CVP transmission
system excluding generation facilities
and radial lines.
TTc = The TTc is the total transmission
capacity under a long-term contract
between Western and other parties.
NITSc = The NITSc is the 12-month average
coincident peaks of Network Integrated
Transmission Service (NITS) customers
at the time of the monthly CVP
transmission system peak. For rate
design purposes, Western’s use of the
transmission system to meet its statutory
obligations is treated as NITS.
Western may revise the rate from
Component 1 based on either of the
following conditions: (1) Updated
financial data available in March of each
year; or (2) a change in the numerator
or denominator that results in a rate
change of at least $0.05 per kilowatt
month (kW month). Rate change
notifications will be posted on
Western’s Open Access Same-Time
Information System.
Component 2: Any charges or credits
associated with the creation,
termination, or modification to any
tariff, contract, or rate schedule
accepted or approved by the Federal
Energy Regulatory Commission (FERC)
or other regulatory bodies will be passed
on to each relevant customer. The
FERC’s or other regulatory bodies’
accepted or approved charges or credits
apply to the service to which this rate
methodology applies. When possible,
Western will pass through directly to
the relevant customer FERC’s or other
regulatory bodies’ accepted or approved
charges or credits in the same manner
Western is charged or credited. If
FERC’s or other regulatory bodies’
accepted or approved charges or credits
cannot be passed through directly to the
relevant customer in the same manner
Western is charged or credited, the
charges or credits will be passed
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Administration (Western), Sierra
Nevada Customer Service Region.
Applicable: To customers receiving
Central Valley Project (CVP) firm and/or
non-firm Point-to-Point (PTP)
transmission service.
Character and Conditions of Service:
Transmission service for three-phase,
alternating current at 60-hertz, delivered
and metered at the voltages and points
of delivery or receipt, adjusted for
losses, and delivered to points of
delivery. This service includes
scheduling and system control and
dispatch service needed to support the
transmission service.
Formula Rate: The formula rate for
CVP firm and non-firm PTP
transmission includes three
components:
Component 1:
through using Component 1 of the
formula rate.
Component 3: Any charges or credits
from the Host Balancing Authority
(HBA) applied to Western for providing
this service will be passed through
directly to the relevant customer in the
same manner Western is charged or
credited to the extent possible. If the
HBA’s costs or credits cannot be passed
through to the relevant customer in the
same manner Western is charged or
credited, the charges or credits will be
passed through using Component 1 of
the formula rate.
Billing: The formula rate above
applies to the maximum amount of
capacity reserved for periods ranging
from 1 hour to 1 month, payable
whether used or not. Billing will occur
monthly.
Adjustment for Losses: Losses
incurred for service under this rate
schedule will be accounted for as agreed
to by the parties in accordance with the
service agreements.
Adjustment for Audit Adjustments:
Financial audit adjustments that apply
to the formula rate under this rate
schedule will be evaluated on a case-bycase basis to determine the appropriate
treatment for repayment and cash flow
management.
Character and Conditions of Service:
Transmission service for three-phase,
alternating current at 60-hertz, delivered
and metered at the voltages and points
of delivery or receipt, adjusted for
losses, and delivered to points of
delivery. This service includes
scheduling and system control and
dispatch service needed to support the
transmission service.
Formula Rate: The formula rate for
CVP NITS includes three components:
Component 1: The NITS revenue
requirement equals the CVP
transmission revenue requirement (TRR)
less the CVP firm point-to-point
revenue. Each NITS customer’s
allocation is based on the following
formula:
NITS customer’s monthly demand
charge = NITS customer’s load ratio
share × 1/12 of the Annual Network
TRR.
Rate Schedule CV–NWT5
(Supersedes Schedule CV–NWT4)
Central Valley Project
Schedule of Rate for Network
Integration Transmission Service
Effective: October 1, 2011, through
September 30, 2016.
Available: Within the marketing area
served by the Western Area Power
Administration (Western), Sierra
Nevada Customer Service Region.
Applicable: To customers receiving
Central Valley Project (CVP) Network
Integration Transmission Service
(NITS).
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Sfmt 4703
Where:
NITS customer’s load ratio share = The NITS
customer’s load, hourly, or in accordance
with approved policies or procedures,
(including behind the meter generation
minus the NITS customer’s adjusted
Base Resource) coincident with the
monthly CVP transmission system peak,
averaged over a 12-month rolling period,
expressed as a ratio.
Annual Network TRR = The total CVP TRR
less revenue from long-term contracts for
the CVP transmission between Western
and other parties.
The Annual Network TRR will be
revised when the formula rate from
Component 1 of the CVP Transmission
Rate under Rates Schedule CV–T3 is
revised.
Component 2: Any charges or credits
associated with the creation,
termination, or modification to any
tariff, contract, or rate schedule
accepted or approved by the Federal
Energy Regulatory Commission (FERC)
or other regulatory bodies will be passed
on to each relevant customer. The
FERC’s or other regulatory bodies’
E:\FR\FM\14SEN2.SGM
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Federal Register / Vol. 76, No. 178 / Wednesday, September 14, 2011 / Notices
Western is charged or credited. If
FERC’s or other regulatory bodies’
accepted or approved charges or credits
cannot be passed through directly to the
relevant customer in the same manner
Western is charged or credited, the
charges or credits will be passed
through using Component 1 of the
formula rate.
Component 3: Any charges or credits
from the Host Balancing Authority
(HBA) applied to Western for providing
this service will be passed through
directly to the relevant customer in the
same manner Western is charged or
credited to the extent possible. If the
HBA’s costs or credits cannot be passed
through to the relevant customer in the
same manner Western is charged or
credited, the charges or credits will be
passed through using Component 1 of
the formula rate.
Billing: The formula rate above
applies to the maximum amount of
capacity reserved for periods ranging
from 1 hour to 1 month, payable
whether used or not. Billing will occur
monthly.
Adjustment for Losses: Losses
incurred for service under this rate
schedule will be accounted for as agreed
to by the parties in accordance with the
service agreement.
Adjustment for Audit Adjustments:
Financial audit adjustments that apply
to the formula rate under this rate
Western will update the rate from
Component 1 for COTP firm and nonfirm PTP transmission service at least 15
days before the start of each COI rating
season. Rate change notifications will be
posted on Western’s Open Access SameTime Information System Web site.
Component 2: Any charges or credits
associated with the creation,
termination, or modification to any
tariff, contract, or rate schedule
accepted or approved by the Federal
Energy Regulatory Commission (FERC)
or other regulatory bodies will be passed
on to each relevant customer. The
FERC’s or other regulatory bodies’
accepted or approved charges or credits
apply to the service to which this rate
methodology applies. When possible,
Western will pass through directly to
the relevant customer FERC’s or other
regulatory bodies’ accepted or approved
charges or credits in the same manner
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Rate Schedule COTP–T3
(Supersedes Schedule COTP–T2)
California-Oregon Transmission Project
Schedule of Rate for Point-to-Point
Transmission Service
Effective: October 1, 2011, through
September 30, 2016.
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Available: Within the marketing area
served by the Western Area Power
Administration (Western), Sierra
Nevada Customer Service Region.
Applicable: To customers receiving
California-Oregon Transmission Project
(COTP) firm and/or non-firm point-topoint (PTP) transmission service.
Character and Conditions of Service:
Transmission service for three-phase,
alternating current at 60-hertz, delivered
and metered at the voltages and points
of delivery or receipt, adjusted for
losses, and delivered to points of
delivery. This service includes
scheduling and system control and
dispatch service needed to support the
transmission service.
Formula Rate: The formula rate for
COTP firm and non-firm PTP
transmission service includes three
components:
Component 1:
schedule will be evaluated on a case-bycase basis to determine the appropriate
treatment for repayment and cash flow
management.
Rate Schedule PACI–T3
(Supersedes Schedule PACI–T2)
Pacific Alternating Current Intertie
Project
Schedule of Rate For Point-to-Point
Transmission Service
Effective: October 1, 2011, through
September 30, 2016.
Available: Within the marketing area
served by the Western Area Power
Administration (Western), Sierra
Nevada Customer Service Region (SNR).
Applicable: To customers receiving
Pacific Alternating Current Intertie
(PACI) firm and/or non-firm point-topoint transmission service.
Character and Conditions of Service:
Transmission service for three-phase,
alternating current at 60-hertz, delivered
and metered at the voltages and points
of delivery or receipt, adjusted for
losses, and delivered to points of
delivery. This service includes
scheduling and system control and
dispatch service needed to support the
transmission service.
Formula Rate: The formula rate for
PACI firm and non-firm transmission
includes three components:
Component 1:
E:\FR\FM\14SEN2.SGM
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credited, the charges or credits will be
passed through using Component 1 of
the formula rate.
Billing: NITS will be billed monthly
under the formula rate.
Adjustment for Losses: Losses
incurred for service under this rate
schedule will be accounted for as agreed
to by the parties in accordance with the
service agreement.
Adjustment for Audit Adjustments:
Financial audit adjustments that apply
to the formula rate under this rate
schedule will be evaluated on a case-bycase basis to determine the appropriate
treatment for repayment and cash flow
management.
Where:
COTP TRR = COTP Seasonal TRR (Western’s
costs associated with facilities that
support the transfer capability of the
COTP).
Western’s COTP Seasonal Capacity =
Western’s share of COTP capacity
(subject to curtailment) under the current
California-Oregon Intertie (COI) transfer
capability for the season. The three
seasons are defined as follows:
Summer—June through October;
Winter—November through March; and
Spring—April through May.
emcdonald on DSK4SPTVN1PROD with NOTICES2
accepted or approved charges or credits
apply to the service to which this rate
methodology applies. When possible,
Western will pass through directly to
the relevant customer FERC’s or other
regulatory bodies’ accepted or approved
charges or credits in the same manner
Western is charged or credited. If
FERC’s or other regulatory bodies’
accepted or approved charges or credits
cannot be passed through directly to the
relevant customer in the same manner
Western is charged or credited, the
charges or credits will be passed
through using Component 1 of the
formula rate.
Component 3: Any charges or credits
from the Host Balancing Authority
(HBA) applied to Western for providing
this service will be passed through
directly to the relevant customer in the
same manner Western is charged or
credited to the extent possible. If the
HBA’s costs or credits cannot be passed
through to the relevant customer in the
same manner Western is charged or
56931
Federal Register / Vol. 76, No. 178 / Wednesday, September 14, 2011 / Notices
emcdonald on DSK4SPTVN1PROD with NOTICES2
Where:
PACI TRR = PACI Seasonal TRR includes
Western’s costs associated with facilities
that support the transfer capability of the
PACI.
Western’s PACI Seasonal Capacity =
Western’s share of PACI capacity (subject
to curtailment) under the current
California-Oregon Intertie (COI) transfer
capability for the season. The three
seasons are defined as follows:
Summer—June through October;
Winter—November through March; and
Spring—April through May.
Adjustment for Losses: Losses
incurred for service under this rate
schedule will be accounted for as agreed
to by the parties in accordance with the
service agreement.
Adjustment for Audit Adjustments:
Financial audit adjustments that apply
to the formula rate under this rate
schedule will be evaluated on a case-bycase basis to determine the appropriate
treatment for repayment and cash flow
management.
Western will update the rate resulting
from Component 1 at least 15 days
before the start of each COI rating
season. Rate change notifications will be
posted on Western’s Open Access Same
Time Information System.
Component 2: Any charges or credits
associated with the creation,
termination, or modification to any
tariff, contract, or rate schedule
accepted or approved by the Federal
Energy Regulatory Commission (FERC)
or other regulatory bodies will be passed
on to each relevant customer. The
FERC’s or other regulatory bodies’
accepted or approved charges or credits
apply to the service to which this rate
methodology applies. When possible,
Western will pass through directly to
the relevant customer FERC’s or other
regulatory bodies’ accepted or approved
charges or credits in the same manner
Western is charged or credited. If
FERC’s or other regulatory bodies’
accepted or approved charges or credits
cannot be passed through directly to the
relevant customer in the same manner
Western is charged or credited, the
charges or credits will be passed
through using Component 1 of the
formula rate.
Component 3: Any charges or credits
from the Host Balancing Authority
(HBA) applied to Western for providing
this service will be passed through
directly to the relevant customer in the
same manner Western is charged or
credited to the extent possible. If the
HBA’s costs or credits cannot be passed
through to the relevant customer in the
same manner Western is charged or
credited, the charges or credits will be
passed through using Component 1 of
the formula rate.
Billing: The formula rate above
applies to the maximum amount of
capacity reserved for periods ranging
from 1 hour to 1 month, payable
whether used or not. Billing will occur
monthly.
(Supersedes Schedule CV–TPT6)
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Rate Schedule CV–TPT7
Central Valley Project
Schedule of Rate for Transmission of
Western Power by Others
Effective: October 1, 2011, through
September 30, 2016.
Available: Within the marketing area
served by the Western Area Power
Administration (Western), Sierra
Nevada Customer Service Region.
Applicable: To Western’s power
service customers who require
transmission service by a third party to
receive power sold by Western.
Character and Conditions of Service:
Transmission service for three-phase,
alternating current at 60-hertz, delivered
and metered at the voltages and points
of delivery or receipt, adjusted for
losses, and delivered to points as agreed
to by the parties.
Formula Rate: The formula rate for
transmission of Western’s power by
others includes three components.
Component 1: When Western uses
transmission facilities other than its
own in supplying Western power and
costs are incurred by Western for the
use of such facilities, the customer will
pay all costs, including transmission
losses, incurred in the delivery of such
power.
Component 2: Any charges or credits
associated with the creation,
termination, or modification to any
tariff, contract, or rate schedule
accepted or approved by the Federal
Energy Regulatory Commission (FERC)
or other regulatory bodies will be passed
on to each relevant customer. The
FERC’s or other regulatory bodies’
accepted or approved charges or credits
apply to the service to which this rate
methodology applies. When possible,
Western will pass through directly to
the relevant customer FERC’s or other
regulatory bodies’ accepted or approved
charges or credits in the same manner
Western is charged or credited. If
PO 00000
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Fmt 4701
Sfmt 4703
FERC’s or other regulatory bodies’
accepted or approved charges or credits
cannot be passed through directly to the
relevant customer in the same manner
Western is charged or credited, the
charges or credits will be passed
through using Component 1 of the
formula rate.
Component 3: Any charges or credits
from the Host Balancing Authority
(HBA) applied to Western for providing
this service will be passed through
directly to the relevant customer in the
same manner Western is charged or
credited to the extent possible. If the
HBA’s costs or credits cannot be passed
through to the relevant customer in the
same manner Western is charged or
credited, the charges or credits will be
passed through using Component 1 of
the formula rate.
Billing: Third-party transmission will
be billed monthly under the formula
rate.
Adjustments for losses: All losses
incurred for delivery of power under
this rate schedule will be the
responsibility of the customer that
received the power.
Adjustment for Audit Adjustments:
Financial audit adjustments that apply
to the formula rate under this rate
schedule will be evaluated on a case-bycase basis to determine the appropriate
treatment for repayment and cash flow
management.
New Rate Schedule CV–UUP1
Central Valley Project
Schedule of Rate for Unreserved Use
Penalties
Effective: October 1, 2011, through
September 30, 2016.
Available: Within the marketing area
served by the Western Area Power
Administration (Western), Sierra
Nevada Customer Service Region (SNR).
Applicable: Western added this
penalty rate for unreserved use of
transmission service for the Central
Valley Project, California-Oregon
Transmission Project, and Pacific
Alternating Current Intertie effective
October 1, 2011. This penalty is
applicable to point-to-point (PTP)
transmission customers using
transmission not reserved or in excess of
reservation or network customers when
they schedule delivery of off-system
non-designated purchases using
transmission capacity reserved for
designated network resources.
Character and Conditions of Service:
Transmission service for three-phase,
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56932
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alternating current at 60-hertz, delivered
and metered at the voltages and points
of delivery or receipt, adjusted for
losses, and delivered to points of
delivery. This service includes
scheduling and system control and
dispatch service needed to support the
transmission service.
Penalty Rate: The formula rate for
Unreserved Use Penalty (UPP) has three
components.
Component 1: The UUP service is
provided when a transmission customer
uses transmission service that it has not
reserved or uses transmission service in
excess of its reserved capacity. A
transmission customer that has not
reserved capacity or exceeds its firm or
non-firm reserved capacity at any point
of receipt or any point of delivery will
be assessed UUP.
The penalty charge for a transmission
customer who engages in unreserved
use is 200 percent of Western’s
approved transmission service rate for
PTP transmission service assessed as
follows: (1) The UUP for a single hour
of unreserved use will be based upon
the rate for daily firm PTP service; (2)
the UUP for more than one assessment
for a given duration (e.g., daily) will
increase to the next longest duration
(weekly); and (3) the UUP for multiple
instances of unreserved use (e.g., more
than 1 hour) within a day will be based
on the rate for daily firm PTP service.
The penalty charge for multiple
instances of unreserved use isolated to
one-calendar week would result in a
penalty based on the charge for weekly
firm PTP service. The penalty charge for
multiple instances of unreserved use
during more than one week within a
calendar month is based on the charge
for monthly firm PTP service.
The UUP will not apply to
transmission customers utilizing PTP
transmission service under Western’s
Open Access Transmission Tariff
(OATT) as a result of action taken to
support reliability. Such actions include
reserve activations or uncontrolled
event response as directed by the
responsible reliability authority such as
Sub-Balancing Authority, Host
Balancing Authority (HBA), Reliability
Coordinator, or Transmission Operator.
A transmission customer that exceeds
its firm or non-firm reserved capacity is
required to pay for all ancillary services
identified in Western’s OATT associated
with the unreserved use of transmission
service. The transmission customer or
eligible customer will pay for ancillary
services, in accordance with existing
rate schedules, based on the amount of
transmission service it used but did not
reserve.
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The UUP collected over and above the
base PTP rate will be distributed to
customers as a credit on future
transmission revenue requirements.
Component 2: Any charges or credits
associated with the creation,
termination, or modification to any
tariff, contract, or rate schedule
accepted or approved by the Federal
Energy Regulatory Commission (FERC)
or other regulatory bodies will be passed
on to each relevant customer. The
FERC’s or other regulatory bodies’
accepted or approved charges or credits
apply to the service to which this rate
methodology applies. When possible,
Western will pass through directly to
the relevant customer FERC’s or other
regulatory bodies’ accepted or approved
charges or credits in the same manner
Western is charged or credited. If
FERC’s or other regulatory bodies’
accepted or approved charges or credits
cannot be passed through directly to the
relevant customer in the same manner
Western is charged or credited, the
charges or credits will be passed
through using Component 1 of the
penalty rate.
Component 3: Any charges or credits
from the HBA applied to Western for
providing this service will be passed
through directly to the relevant
customer in the same manner Western
is charged or credited to the extent
possible. If the HBA’s costs or credits
cannot be passed through to the relevant
customer in the same manner Western
is charged or credited, the charges or
credits will be passed through using
Component 1 of the penalty rate.
Billing: The UUP will be billed
monthly under the formula rate.
Adjustments for losses: All losses
incurred for delivery of power under
this rate schedule shall be the
responsibility of the customer that
received the power.
Adjustment for Audit Adjustments:
Financial audit adjustments that apply
to the formula rate will be evaluated on
a case-by-case basis to determine the
appropriate treatment for repayment
and cash flow management.
Rate Schedule CV–SPR4
(Supersedes Schedule CV–SPR3)
Central Valley Project
Schedule of Rate for Spinning Reserve
Service
Effective: October 1, 2011, through
September 30, 2016.
Available: Within the marketing area
served by the Western Area Power
Administration (Western), Sierra
Nevada Customer Service Region.
Applicable: To customers receiving
spinning reserve service.
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56933
Character and Conditions of Service:
Spinning reserve service supplies
capacity that is available immediately to
serve load and is synchronized with the
power system.
Formula Rate: The formula rate for
spinning reserve includes three
components:
Component 1: The formula rate for
spinning reserve service is the price
consistent with the California
Independent System Operator’s market
plus all costs incurred as a result of the
sale of spinning reserves, such as
Western’s scheduling costs.
For customers that have a contractual
obligation to provide spinning reserve to
Western and do not fulfill that
obligation, the penalty for nonperformance is the greater of 150
percent of Western’s actual cost or 150
percent of the market price.
Component 2: Any charges or credits
associated with the creation,
termination, or modification to any
tariff, contract, or rate schedule
accepted or approved by the Federal
Energy Regulatory Commission (FERC)
or other regulatory bodies will be passed
on to each relevant customer. The
FERC’s or other regulatory bodies’
accepted or approved charges or credits
apply to the service to which this rate
methodology applies. When possible,
Western will pass through directly to
the relevant customer FERC’s or other
regulatory bodies’ accepted or approved
charges or credits in the same manner
Western is charged or credited. If
FERC’s or other regulatory bodies’
accepted or approved charges or credits
cannot be passed through directly to the
relevant customer in the same manner
Western is charged or credited, the
charges or credits will be passed
through using Component 1 of the
formula rate.
Component 3: Any charges or credits
from the Host Balancing Authority
(HBA) applied to Western for providing
this service will be passed through
directly to the relevant customer in the
same manner Western is charged or
credited to the extent possible. If the
HBA’s costs or credits cannot be passed
through to the relevant customer in the
same manner Western is charged or
credited, the charges or credits will be
passed through using Component 1 of
the formula rate.
Billing: The formula rate above will be
applied to the amount of spinning
reserve sold. Billing will occur monthly.
Adjustment for Audit Adjustments:
Financial audit adjustments that apply
to the formula rate under this rate
schedule will be evaluated on a case-bycase basis to determine the appropriate
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Federal Register / Vol. 76, No. 178 / Wednesday, September 14, 2011 / Notices
Effective: October 1, 2011, through
September 30, 2016.
Available: Within the marketing area
served by the Western Area Power
Administration (Western), Sierra
Nevada Customer Service Region.
Applicable: To customers receiving
supplemental reserve service.
Character and Conditions of Service:
Supplemental reserve service supplies
capacity that is available within the first
10 minutes to take load and is
synchronized with the power system.
Formula Rate: The formula rate for
supplemental reserve service includes
three components:
Component 1: The formula rate for
supplemental reserve service is the
price consistent with the California
Independent System Operator’s market
plus all costs incurred as a result of the
sale of supplemental reserves, such as
Western’s scheduling costs.
For customers that have a contractual
obligation to provide supplemental
reserve service to Western and do not
fulfill that obligation, the penalty for
non-performance is the greater of 150
percent of Western’s actual cost or 150
percent of the market price.
Component 2: Any charges or credits
associated with the creation,
termination, or modification to any
tariff, contract, or rate schedule
accepted or approved by the Federal
Energy Regulatory Commission (FERC)
or other regulatory bodies will be passed
on to each relevant customer. The
FERC’s or other regulatory bodies’
accepted or approved charges or credits
apply to the service to which this rate
methodology applies. When possible,
Western will pass through directly to
the relevant customer FERC’s or other
regulatory bodies’ accepted or approved
charges or credits in the same manner
Western is charged or credited. If
FERC’s or other regulatory bodies’
accepted or approved charges or credits
cannot be passed through directly to the
relevant customer in the same manner
Western is charged or credited, the
charges or credits will be passed
through using Component 1 of the
formula rate.
Component 3: Any charges or credits
from the Host Balancing Authority
(HBA) applied to Western for providing
this service will be passed through
directly to the relevant customer in the
same manner Western is charged or
credited to the extent possible. If the
HBA’s costs or credits cannot be passed
through to the relevant customer in the
same manner Western is charged or
credited, the charges or credits will be
passed through using Component 1 of
the formula rate.
Billing: The formula rate above will be
applied to the amount of supplemental
reserve service sold. Billing will occur
monthly.
Adjustment for Audit Adjustments:
Financial audit adjustments that apply
to the formula rate under this rate
schedule will be evaluated on a case-bycase basis to determine the appropriate
treatment for repayment and cash flow
management.
The annual revenue requirement
includes: (1) The Central Valley Project
generation costs associated with
providing regulation, and (2) the nonfacility costs allocated to regulation.
The annual regulating capacity is onehalf of the total regulating capacity
bandwidths provided by Western under
the Interconnected Operations
Agreements with Sub-Balancing
Authority (SBA) members.
The penalty for non-performance by
an SBA customer who has committed to
self-provision for their regulating
capacity requirement will be the greater
of 150 percent of Western’s actual costs
or 150 percent of the market price.
Western will revise the formula rate
resulting from Component 1 based on
either of the following two conditions:
(1) Updated financial data available in
March of each year; or (2) a change in
the numerator or denominator that
results in a rate change of at least $0.25
per kW month.
Component 2: Any charges or credits
associated with the creation,
termination, or modification to any
tariff, contract, or rate schedule
accepted or approved by the Federal
Energy Regulatory Commission (FERC)
or other regulatory bodies will be passed
on to each relevant customer. The
FERC’s or other regulatory bodies’
accepted or approved charges or credits
apply to the service to which this rate
methodology applies. When possible,
Western will pass through directly to
the relevant customer FERC’s or other
regulatory bodies’ accepted or approved
charges or credits in the same manner
Western is charged or credited. If
FERC’s or other regulatory bodies’
accepted or approved charges or credits
cannot be passed through directly to the
relevant customer in the same manner
Western is charged or credited, the
charges or credits will be passed
through using Component 1 of the
formula rate.
Component 3: Any charges or credits
from the Host Balancing Authority
(HBA) applied to Western for providing
this service will be passed through
directly to the relevant customer in the
same manner Western is charged or
credited to the extent possible. If the
HBA’s costs or credits cannot be passed
through to the relevant customer in the
same manner Western is charged or
credited, the charges or credits will be
passed through using Component 1 of
the formula rate.
Billing: The formula rate above will be
applied to the regulating capacity
bandwidth contained in the service
agreement. Billing will occur monthly.
Adjustment for Audit Adjustments:
Financial audit adjustments that apply
to the formula rate under this rate
schedule will be evaluated on a case-by-
Rate Schedule CV–SUR4
(Supersedes Schedule CV–SUR3)
Central Valley Project
emcdonald on DSK4SPTVN1PROD with NOTICES2
Schedule of Rate for Supplemental
Reserve Service
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Rate Schedule CV–RFS4
(Supersedes Schedule CV–RFS3)
Central Valley Project
Schedule of Rate for Regulation and
Frequency Response Service
Effective: October 1, 2011, through
September 30, 2016.
Available: Within the marketing area
served by the Western Area Power
Administration (Western), Sierra
Nevada Customer Service Region.
Applicable: To customers receiving
Regulation and Frequency Response
Service (regulation).
Character and Conditions of Service:
Regulation is necessary to provide for
the continuous balancing of resources
and interchange with load and for
maintaining scheduled interconnection
frequency at 60-cycles per second.
Formula Rate: The formula rate for
regulation includes three components:
Component 1:
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treatment for repayment and cash flow
management.
Federal Register / Vol. 76, No. 178 / Wednesday, September 14, 2011 / Notices
case basis to determine the appropriate
treatment for repayment and cash flow
management.
Rate Schedule CV–EID4
(Supersedes Schedule CV–EID3)
Central Valley Project
emcdonald on DSK4SPTVN1PROD with NOTICES2
Schedule of Rate for Energy Imbalance
Service
Effective: October 1, 2011, through
September 30, 2016.
Available: Within the marketing area
served by the Western Area Power
Administration (Western), Sierra
Nevada Customer Service Region.
Applicable: To customers receiving
Energy Imbalance (EI) service.
Character and Conditions of Service:
EI is provided when a difference occurs
between the scheduled and the actual
delivery of energy to a load within the
Sub-Balancing Authority (SBA) over an
hour or in accordance with approved
policies and procedures. The deviation,
in megawatts, is the net scheduled
amount of energy minus the net metered
(actual delivered) amount.
EI service uses the deviation
bandwidth that is established in the
service agreement or Interconnected
Operations Agreements.
Formula Rate: The formula rate for EI
service includes three components:
Component 1: EI service is applied to
deviations as follows: (1) For deviations
within the bandwidth, there will be no
financial settlement, unless otherwise
dictated by contract or policy; rather, EI
will be tracked and settled with energy;
(2) negative deviations (under-delivery),
outside the deviation bandwidth, will
be charged the greater of 150 percent of
the California Independent System
Operator market price or 150 percent of
Western’s actual cost; and (3) positive
deviations (over-delivery), outside the
deviation bandwidth, will be lost to the
system, except for any hour when
Western incurs a cost to dispose of the
energy, then that cost will be borne by
the responsible party.
Deviations that occur as a result of
actions taken to support reliability will
be resolved in accordance with existing
contractual requirements. Such actions
include reserve activations or
uncontrolled event responses as
directed by the responsible reliability
authority such as SBA, Host Balancing
Authority (HBA), Reliability
Coordinator, or Transmission Operator.
Component 2: Any charges or credits
associated with the creation,
termination, or modification to any
tariff, contract, or rate schedule
accepted or approved by the Federal
Energy Regulatory Commission (FERC)
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19:22 Sep 13, 2011
Jkt 223001
or other regulatory bodies will be passed
on to each relevant customer. The
FERC’s or other regulatory bodies’
accepted or approved charges or credits
apply to the service to which this rate
methodology applies. When possible,
Western will pass through directly to
the relevant customer FERC’s or other
regulatory bodies’ accepted or approved
charges or credits in the same manner
Western is charged or credited. If
FERC’s or other regulatory bodies’
accepted or approved charges or credits
cannot be passed through directly to the
relevant customer in the same manner
Western is charged or credited, the
charges or credits will be passed
through using Component 1 of the
formula rate.
Component 3: Any charges or credits
from the HBA applied to Western for
providing this service will be passed
through directly to the relevant
customer in the same manner Western
is charged or credited to the extent
possible. If the HBA’s costs or credits
cannot be passed through to the relevant
customer in the same manner Western
is charged or credited, the charges or
credits will be passed through using
Component 1 of the formula rate.
Billing: Billing for negative deviations
outside the bandwidth, or as otherwise
required, will occur monthly.
Adjustment for Audit Adjustments:
Financial audit adjustments that apply
to the formula rate under this rate
schedule will be evaluated on a case-bycase basis to determine the appropriate
treatment for repayment and cash flow
management.
New Rate Schedule CV–GID1
Central Valley Project
Schedule of Rate for Generator
Imbalance Service
Effective: October 1, 2011, through
September 30, 2016.
Available: Within the marketing area
served by the Western Area Power
Administration (Western), Sierra
Nevada Customer Service Region (SNR).
Applicable: To generators receiving
Generator Imbalance Service (GI).
Character and Conditions of Service:
GI is provided when a difference occurs
between the scheduled and actual
delivery of energy from an eligible
generation resource within the SubBalancing Authority (SBA), over an
hour, or in accordance with approved
policies. The deviation in megawatts is
the net scheduled amount of generation
minus the net metered output from the
generator’s (actual generation) amount.
GI is subject to the deviation
bandwidth established in the service
PO 00000
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Fmt 4701
Sfmt 4703
56935
agreement or Interconnected Operations
Agreements.
Formula Rate: The formula rate for
the GI has three components:
Component 1: GI is applied to
deviations as follows: (1) For deviations
within the bandwidth, there will be no
financial settlement, unless otherwise
dictated by contract or policy; rather, GI
will be tracked and settled with energy;
(2) negative deviations (under-delivery),
outside the deviation bandwidth, will
be charged the greater of 150 percent of
the California Independent System
Operator market price or 150 percent of
Western’s actual cost; and (3) positive
deviations (over-delivery), outside the
deviation bandwidth, will be lost to the
system, except for any hour when
Western incurs a cost to dispose of the
energy, then that cost will be borne by
the responsible party.
Deviations that occur as a result of
actions taken to support reliability will
be resolved in accordance with existing
contractual requirements. Such actions
include reserve activations or
uncontrolled event responses as
directed by the responsible reliability
authority such as Sub-Balancing
Authority, Host Balancing Authority
(HBA), Reliability Coordinator, or
Transmission Operator.
To the extent that an entity
incorporates intermittent resources,
deviations will be charged as follows:
(1) For deviations within the
bandwidth, there will be no financial
settlement, unless otherwise dictated by
contract or policy; rather, GI will be
tracked and settled with energy; (2)
negative deviations (under-delivery),
outside the deviation bandwidth, will
be charged the greater of market price or
actual cost (no penalty); and (3) positive
deviations (over-delivery), outside the
deviation bandwidth, will be lost to the
system, except for any hour where
Western incurs a cost, then that cost
will be borne by the responsible party.
Intermittent generators serving load
outside of SNR’s SBA will be required
to dynamically schedule or dynamically
meter their generation to another
Balancing Authority. An intermittent
resource, for the limited purpose of
these rate schedules, is an electric
generator that is not dispatchable and
cannot store its output, and therefore,
cannot respond to changes in demand or
respond to transmission security
constraints.
Component 2: Any charges or credits
associated with the creation,
termination, or modification to any
tariff, contract, or rate schedule
accepted or approved by the Federal
Energy Regulatory Commission (FERC)
or other regulatory bodies will be passed
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Federal Register / Vol. 76, No. 178 / Wednesday, September 14, 2011 / Notices
emcdonald on DSK4SPTVN1PROD with NOTICES2
on to each relevant customer. The
FERC’s or other regulatory bodies’
accepted or approved charges or credits
apply to the service to which this rate
methodology applies. When possible,
Western will pass through directly to
the relevant customer FERC’s or other
regulatory bodies’ accepted or approved
charges or credits in the same manner
Western is charged or credited. If
FERC’s or other regulatory bodies’
accepted or approved charges or credits
cannot be passed through directly to the
relevant customer in the same manner
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19:22 Sep 13, 2011
Jkt 223001
Western is charged or credited, the
charges or credits will be passed
through using Component 1 of the
formula rate.
Component 3: Any charges or credits
from the HBA applied to Western for
providing this service will be passed
through directly to the relevant
customer in the same manner Western
is charged or credited to the extent
possible. If the HBA’s costs or credits
cannot be passed through to the relevant
customer in the same manner Western
is charged or credited, the charges or
PO 00000
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Fmt 4701
Sfmt 9990
credits will be passed through using
Component 1 of the formula rate.
Billing: Billing for negative deviations
outside the bandwidth will occur
monthly.
Adjustment for Audit Adjustments:
Financial audit adjustments that apply
to the formula rate under this rate
schedule will be evaluated on a case-bycase basis to determine the appropriate
treatment for repayment and cash flow
management.
[FR Doc. 2011–23339 Filed 9–13–11; 8:45 am]
BILLING CODE 6450–01–P
E:\FR\FM\14SEN2.SGM
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[Federal Register Volume 76, Number 178 (Wednesday, September 14, 2011)]
[Notices]
[Pages 56906-56936]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-23339]
[[Page 56905]]
Vol. 76
Wednesday,
No. 178
September 14, 2011
Part III
Department of Energy
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Western Area Power Administration
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The Central Valley Project, the California-Oregon Transmission
Project, the Pacific Alternating Current Intertie, and Information on
the Path 15 Transmission Upgrade--Rate Order No. WAPA-156; Notice
Federal Register / Vol. 76, No. 178 / Wednesday, September 14, 2011 /
Notices
[[Page 56906]]
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DEPARTMENT OF ENERGY
Western Area Power Administration
The Central Valley Project, the California-Oregon Transmission
Project, the Pacific Alternating Current Intertie, and Information on
the Path 15 Transmission Upgrade--Rate Order No. WAPA-156
AGENCY: Western Area Power Administration, DOE.
ACTION: Notice of Rate Order.
-----------------------------------------------------------------------
SUMMARY: The Deputy Secretary of Energy confirmed and approved Rate
Order No. WAPA-156 and Rate Schedules CV-F13, CPP-2, CV-T3, CV-NWT5,
COTP-T3, PACI-T3, CV-TPT7, CV-UUP1, CV-SPR4, CV-SUR4, CV-RFS4, CV-EID4,
and CV-GID1, placing formula rates for power, transmission, and
ancillary services for the Central Valley Project (CVP), transmission
service on the California-Oregon Transmission Project (COTP),
transmission service on the Pacific Alternating Current Intertie
(PACI), and third-party transmission service into effect on an interim
basis. The Rate Order also provides information on the Western Area
Power Administration's (Western) transmission capacity entitlement on
the Path 15 Transmission Upgrade. 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 superseded. The provisional formula rates will provide sufficient
revenue to pay all annual costs, including interest expense, repayment
of power investments and aid to irrigation, within the allowable
periods.
DATES: Rate Schedules CV-F13, CPP-2, CV-T3, CV-NWT5, COTP-T3, PACI-T3,
CV-TPT7, CV-UUP1, CV-SPR4, CV-SUR4, CV-RFS4, CV-EID4, and CV-GID1 will
be placed into effect on an interim basis on the first day of the first
full billing period beginning 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. Thomas R. Boyko, Regional Manager,
Sierra Nevada Customer Service Region, Western Area Power
Administration, 114 Parkshore Drive, Folsom, CA 95630-4710, (916) 353-
4418, or Ms. Regina Rieger, Rates Manager, Sierra Nevada Customer
Service Region, Western Area Power Administration, 114 Parkshore Drive,
Folsom, CA 95630-4710, (916) 353-4629, e-mail rieger@wapa.gov.
SUPPLEMENTARY INFORMATION: This Federal Register notice (FRN) replaces
the existing formula rates for power, transmission, and ancillary
services under Rate Order No. 115, noticed on November 22, 2004,\1\ as
amended under Rate Order No. 128, noticed on July 26, 2006,\2\ and as
extended by Rate Order No. 139, noticed on August 12, 2008.\3\ These
rate schedules (CV-F12, CPP-1, CV-T2, CV-NWT4, COTP-T2, PACI-T2, CV-
TPT6, CV-SPR3, CV-SUR3, CV-RFS3, and CV-EID3) expire on September 30,
2011. The Deputy Secretary of Energy, under Delegation Order No. 00-
037.00 and 00-001.00c, 10 CFR 903 and 18 CFR part 300, confirms,
approves, and places into effect on October 1, 2011, on an interim
basis, Rate Order WAPA-156, which includes rate schedules CV-F13, CPP-
2, CV-T3, CV-NWT5, COTP-T3, PACI-T3, CV-TPT7, CV-UUP1, CV-SPR4, CV-
SUR4, CV-RFS4, CV-EID4, and CV-GID1. The provisional formula rates
shall be in effect until FERC confirms, approves, and places them into
effect on a final basis through September 30, 2016, or until they are
superseded.
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\1\ See 69 FR 70510 (2004).
\2\ See 71 FR 45821 (2006).
\3\ See 73 FR 48381 (2008).
---------------------------------------------------------------------------
Changes From Existing Rates
After considering all comments submitted during the public
consultation and comment period, Western determined that the
provisional rates should continue the existing formula rate
methodologies for power; CVP, COTP, and PACI transmission; transmission
of Western power by others; Custom Product Power (CPP); and ancillary
services with the following summarized exceptions:
1. Two new rate schedules: Unreserved Use Penalties (UUP) and
Generator Imbalance (GI);
2. Annual true-up for First Preference (FP) percentages;
3. In addition to the existing 150 percent penalty on the
California Independent System Operator's (CAISO) market price, Western
will adopt a 150 percent penalty on Western's actual cost when charging
for ancillary services and will charge the greater of the two;
4. Costs incurred under Energy Imbalance (EI)/GI when disposing of
surplus energy, including negative pricing of such energy, will be
charged to the responsible party;
5. For intermittent resources interconnected to Western's system,
Western will not charge the 150 percent penalty and will charge the
greater of CAISO market price or Western's actual cost;
6. Western added Components 2 and 3, standard cost recovery
language, to CPP formula rate; and
7. Rate Schedules include miscellaneous language changes and
billing clarifications.
Detailed explanations of changes to the provisional formula rate
methodologies are described in the rate order below.
Provisional Power Rates
Under the provisional formula rates, prior to the start of each
fiscal year (FY), Western calculates and publishes an annual Power
Revenue Requirement (PRR) to determine the total cost of power to be
allocated to Preference Customers. As part of the rate development,
Western prepares a Power Repayment Study (PRS) each FY to determine if
the expected revenue will be sufficient to repay, within the required
time periods, all costs assigned to the commercial power function.
Repayment criteria are based on legislation and applicable policies,
including DOE Order RA 6120.2. Generally, the PRR includes estimated
operation and maintenance (O&M) expenses, purchase power for Project
Use (PU) and FP Customers' loads, interest, and other expenses
(including any other statutorily-required costs or charges), investment
repayment, and the Washoe Project annual costs that remain after
project use loads are met. Revenues from PU, transmission, ancillary
services, and other services are offset against expenses in the PRR.
The remainder is collected from Base Resource (BR) and FP Customers.
The PRR is reviewed during March of each year; and if the review
results in a change of $5 million or more, the PRR is adjusted. The PRR
is an estimate of revenue and costs including investment and repayment
projections from the PRS. Any deviation from estimate to actual will
increase or decrease capital project repayment. Project repayment is
analyzed and measured over the long term to ensure repayment is met and
to maintain rate stability.
The PRR is allocated first to FP Customers then to BR Customers.
The FP Customers are defined in the Trinity River Division Act of 1955
\4\ and the Flood Control Act of 1962.\5\ Western provides first
preference of CVP power to customers in Trinity, Tuolumne, and
Calaveras Counties, as provided under those acts and as implemented
under Western's 2004 Marketing Plan. A BR
[[Page 56907]]
Customer, under the 2004 Marketing Plan, is an entity that has executed
a BR contract and is allocated a percentage of the BR. The FP
percentages are reviewed during March of each year; and if the review
results in a change of one-half of 1 percent for any FP Customer, the
PRR obligation is reallocated to both FP and BR Customers. Based on
customer comments received during this rate process, Western agreed to
perform an annual true-up of FP percentages and adjust FP and BR
revenue requirements each October.
---------------------------------------------------------------------------
\4\ See 69 Stat. 719 (1955).
\5\ See 76 Stat. 1173, 1191-1192 (1962).
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In order for Western to meet the loads of Full Load Service (FLS)
Customers or any portion of the loads of Variable Resource (VR)
Customers not met by BR, Western may make supplemental power purchases
pursuant to the CPP rate schedule. The FLS and VR Customers who
contract with Western for such service pay all supplemental power
costs. The FLS Customers pay a portfolio management charge pursuant to
their FLS contract, whereas VR Customers pay a scheduling charge for
any CPP pursuant to the provisional rate schedule.
Provisional Transmission and Ancillary Service Rates
At least annually, Western will publish the CVP transmission rates
for point-to-point (PTP) and network integration transmission service
(NITS), the seasonal COTP and PACI transmission rates, and CVP
regulation and frequency response service rates. Rates are based on a
cost-of-service (COS) study to determine the costs, by project, that
support the transfer capability of each transmission system and the
costs that support the generation capability of the CVP system.
Generally, the costs allocated through the COS study for the
transmission systems include O&M, interest, and depreciation expenses.
Western's costs for scheduling, system control and dispatch service
associated with CVP, COTP, and PACI transmission service are included
and recovered through the respective transmission system's revenue
requirements (RR). Third-party transmission service costs are passed
through directly to each customer. Spinning and supplemental reserve
services are priced consistent with the CAISO market price plus all
costs incurred for the sale of these reserves. Customers who have a
contractual obligation to self-provide spinning and supplemental
reserves, and do not fulfill their obligation, will be assessed a
penalty equal to the greater of 150 percent of Western's actual cost or
150 percent of the market price. Similarly, for EI service, customers
operating outside of their contractual bandwidth (under-delivery) will
pay the greater of 150 percent of Western's actual cost or 150 percent
of the market price. Given that Western's EI Customers are and will
continue to operate under existing agreements, Western will continue
its existing rate methodology for EI. During or after the applicable
rate period, Western will review FERC Order No. 890, as well as
Western's existing settlements and billing processes, and will
reconsider transitioning to FERC's methodology.
Finally, in response to FERC's Order No. 890, Western added two new
rate schedules to be effective during the new rate period: UUP and GI.
The UUP will be assessed at 200 percent of the effective PTP
transmission rate when transmission service is used and not reserved or
when used in excess of reservation. The GI rate will use the same
methodology as Western's EI service rate. Currently, Western has no
customers subject to this provisional GI rate.
Information on Path 15 Transmission Upgrade
The Path 15 Transmission Upgrade was completed in 2005. Western
turned over the operational control of Western's Path 15 Transmission
Upgrade to the CAISO. Western maintains the transmission line and is
compensated by Atlantic Path 15, LLC for maintenance costs. The CAISO
charges for use of the Path 15 Transmission Upgrade in accordance with
the CAISO tariff. Western does not sell transmission capacity on Path
15 Transmission Upgrade. Western collects revenues from the CAISO under
its agreements with the CAISO. Under Amendment No. 48, the CAISO remits
to Western, wheeling, congestion, and Congestion Revenue Rights
revenues associated with Western's rights on the Path 15 Transmission
Upgrade.
Confirmation, Approval, and Placing Rate Order WAPA-156 in Place
By Delegation Order No. 00-037.00, effective December 6, 2001, the
Secretary of Energy delegated: (1) The authority to develop power and
transmission rates to Western's Administrator; (2) the authority to
confirm, approve, and place such rates into effect on an interim basis
to the Deputy Secretary of Energy; and (3) the authority to confirm,
approve, and place into effect on a final basis, to remand or to
disapprove such rates to FERC. Existing DOE procedures for public
participation in power rate adjustments (10 CFR part 903) were
published on September 18, 1985.
Under Delegation Order Nos. 00-037.00 and 00-001.00C, 10 CFR part
903, and 18 CFR part 300, I hereby confirm, approve, and place into
effect on October 1, 2011, on an interim basis, Rate Order No. WAPA-
156, which includes Rate Schedules CV-F13, CPP-2, CV-T3, CV-NWT5, COTP-
T3, PACI-T3, CV-TPT7, CV-UUP1, CV-SPR4, CV-SUR4, CV-RFS4, CV-EID4, and
CV-GID1, for the CVP, COTP, and PACI of Western. 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 a rate for a
new service. The provisional rates shall be in effect until FERC
confirms, approves, and places the rates in effect on a final basis
through September 30, 2016, or until the rates are superseded.
Dated: September 2, 2011.
Daniel B. Poneman,
Deputy Secretary.
DEPARTMENT OF ENERGY
Deputy Secretary
Rate Order No. WAPA-156
In the matter of: Western Area Power Administration Rate Adjustment for
the Central Valley Project, the California-Oregon Transmission Project,
and the Pacific Alternating Current Intertie
These power, transmission, and ancillary services formula rates are
established in accordance with section 302 of the Department of Energy
(DOE) Organization Act (42 U.S.C. 7152). This Act transferred to and
vested in the Secretary of Energy the power marketing functions of the
Secretary of the Department of the Interior (DOI) 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 Project Act of 1939, (43
U.S.C. 485h(c)), and other acts that specifically apply to the project
involved.
By Delegation Order No. 00-037.00, effective December 6, 2001, the
Secretary of Energy delegated: (1) The authority to develop power and
transmission rates to the Administrator of Western Area Power
Administration (Western); (2) the authority to confirm, approve, and
place such rates into effect on an interim basis to the Deputy
Secretary 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 Federal Energy Regulatory Commission (FERC).
[[Page 56908]]
Existing DOE procedures for public participation in power rate
adjustments (10 CFR 903) were published on September 18, 1985.
Acronyms and Definitions
As used in this Rate Order, the following acronyms and definitions
apply:
2004 Power Marketing Plan: The 2004 Central Valley Project (CVP) Power
Marketing Plan effective January 1, 2005.\6\ The final marketing
program for the Sierra Nevada Region (SNR) power after 2004 established
through a public process and published in the Federal Register at 64 FR
34417.
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\6\ See 64 FR 34417 (1999).
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Administrator: Administrator for the Western Area Power Administration
(Western)
Ancillary Services: Those services necessary to support the transfer of
electricity while maintaining reliable operation of the transmission
provider's transmission system in accordance with standard utility
practice. Ancillary services are generally described in Federal Energy
Regulatory Commission (FERC) Orders 888 and 890, including: spinning
reserve, supplemental reserve, regulation, Energy Imbalance (EI), and
Generator Imbalance (GI).
Balancing Authority (BA): The responsible entity that integrates
resource plans ahead of time, maintains load-interchange-generation
balance within a BA area, and supports interconnection frequency in
real-time.
Balancing Authority of Northern California (BANC): A joint power agency
composed of Sacramento Municipal Utility District (SMUD), Redding
Electric Utility, Roseville Electric, and Modesto Irrigation District.
The BANC is a legal structure, and it contracts SMUD to act as the BA
operator for the BANC as of May 1, 2011.
Base Resource (BR): The Central Valley and Washoe Project power output
and existing power purchase contracts extending beyond 2004 as
determined by Western to be available for marketing after meeting the
requirements of Project Use (PU) and First Preference (FP) Customers,
and any adjustments for maintenance, reserves, transformation losses,
and certain ancillary services. The BR, as defined above, will include
CVP and Washoe Project generation supported by certain power purchases.
BR%: Base Resource Percentage.
California Independent System Operator (CAISO): The FERC-regulated,
state-chartered, non-profit corporation, independent system operator
and BA area of most of California's transmission grid.
California-Oregon Intertie (COI): Consists of three 500-kilovolt (kV)
lines linking California and Oregon, the California Oregon Transmission
Project, and the Pacific Alternating Current Intertie (PACI) (two
lines). The Western Electricity Coordinating Council (WECC) establishes
the seasonal transfer capability for the COI.
California-Oregon Transmission Project (COTP): A 500-kV transmission
project stretching from Captain Jack Substation to Tesla Substation in
which Western has part ownership.
Capacity: The electric capability of a generator, transformer,
transmission circuit, or other equipment expressed in kilowatt (kW).
Central Valley Project (CVP): A multipurpose Federal water development
project extending from the Cascade Range in northern California to the
plains along the Kern River south of the city of Bakersfield,
California.
CFR: Code of Federal Regulations.
COI Rating Seasons: Consists of summer, June through October; winter,
November through March; and spring, April through May.
Component 1: A part of a formula rate. Component 1 is the variable
portion of Western's rate schedules. Component 1 is the methodology
used to determine revenue requirements or rates that recover the costs
for a specific service or product.
Component 2: A part of a formula rate. Component 2 is a pass-through
provision of Western's rate schedules. The language is the same in each
rate schedule.
Component 3: A part of a formula rate. Component 3 is a pass-through
provision of Western's rate schedules. The language is the same in each
rate schedule.
Contract 2948A: Contract No. 14-06-200-2948A was the Integration
Contract between PG&E and the United States of America, which expired
on December 31, 2004. The contract provided for integrating Western's
resources with Pacific Gas and Electric's (PG&E) and required PG&E to
serve the combined PG&E/Western load with the integrated resource.
COS: Cost of Service.
Custom Product Power (CPP): Refers to power purchased by Western to
meet a customer's load.
Customer: An entity with a contract that receives service from the
Western's SNR.
DOE: United States Department of Energy.
DOE Order RA 6120.2: A DOE order outlining power marketing
administration financial reporting and ratemaking procedures.
EI: Energy Imbalance.
Federal Energy Regulatory Commission (FERC): Referred to as the FERC.
FERC is an independent agency that regulates the interstate
transmission of electricity.
First Preference (FP): Refers to an entity qualified to use Preference
Power within a county of origin (Trinity, Calaveras, and Tuolumne) as
specified under the Trinity River Division Act of August 12, 1955 (69
Stat. 719) and the Flood Control Act of 1962 (76 Stat. 1173, 1191-
1192).
Fiscal Year (FY): Refers to the Federal Fiscal Year, October 1 through
September 30.
Full Load Service (FLS): The BR customer that will have its entire load
at the delivery point(s) met with Western power and Third-Party Power,
and whose Portfolio Management functions for said delivery will be
performed by Western.
GI: Generator Imbalance.
HE: Hourly Exchange.
Host Balancing Authority (HBA): Confirms and implements transactions
that operate generation or serves customers directly within the BA's
metered boundaries. The BA within whose metered boundaries a jointly-
owned unit is physically located. Western operates as a Sub-Balancing
Authority (SBA) under the BANC which operates the HBA.
Kilovolt (kV): The electrical unit of measure of electric potential
that equals 1,000 volts.
Kilowatt (kW): The electrical unit of capacity that equals 1,000 watts.
Kilowatthour (kWh): The electrical unit of energy that equals 1,000
watts produced or delivered in 1 hour.
Kilowattmonth (kWmonth): The electrical unit equal to one kW produced
or delivered for 1 month.
Load: The amount of electric power or energy delivered or required at
any specified point(s) on a transmission or distribution system.
Megawatt (MW): The electrical unit of capacity that equals one million
watts or 1,000 kW.
Megawatt hour (MWh): The electrical unit of energy that equals
1,000,000 watts produced or delivered for 1 hour.
MRR: Monthly Revenue Requirement.
[[Page 56909]]
NERC: The North American Electric Reliability Corporation's (NERC) is
the electric reliability organization certified by FERC to establish
and enforce reliability standards for the bulk-power system.
NEPA: National Environmental Policy Act.
Network Integration Transmission Service (NITS): Firm transmission
service for the delivery of capacity and energy from designated network
resources to designated network loads not using one specific path.
Open Access Same Time Information System (OASIS): The information
system and standards of conduct contained in Part 37 of FERC's
regulations that Western utilized in developing its electronic posting
system for transmission access data.
Open Access Transmission Tariff (OATT): Western's open access
transmission tariff accepted by the FERC, as it may be amended and
supplemented.
O&M: Operations and Maintenance.
Pacific Alternating Current Intertie (PACI): A 500-kV transmission
project of which Western owns a portion of the facilities.
PG&E: Pacific Gas and Electric Company.
Power: Capacity and energy, and it is measured in watts and often
expressed in kW or MW.
Power Repayment Study (PRS): The PRS is used to calculate how much
revenue is needed to meet annual investment obligations, O&M expenses,
and repayment requirements (including repayment periods).
Preference: Refers to the provisions of Reclamation Law that requires
Western to first make Federal power available to certain entities. For
example, section 9(c) of the Reclamation Project Act of 1939 states
that preference in the sale of Federal power shall be given to
municipalities and other public corporations or agencies and also to
cooperatives and other non-profit organizations financed in whole or in
part by loans made under the Rural Electrification Act of 1936 (43
U.S.C. 485h(c)).
Project Use (PU): Power designated by Reclamation Law to be used to
operate CVP and Washoe Project facilities.
Provisional Rate: A rate which has been confirmed, approved, and placed
into effect on an interim basis by the Deputy Secretary.
PRR: Power Revenue Requirement.
PTP: Point-to-Point.
Reclamation: The U.S. Department of the Interior, Bureau of
Reclamation.
Reclamation Law: A series of Federal laws. Viewed as a whole, these
laws create the originating framework under which Western markets
power.
Regulation and Frequency Response: The ancillary service under which a
BA maintains moment-by-moment load interchange-generation balance with
the BA area and supports interconnection frequency.
RR: Revenue Requirement.
SMUD: Sacramento Municipal Utility District.
SNR: Sierra Nevada Customer Service Region.
Sub-Balancing Authority (SBA): Western's contract-based BA within the
SMUD's BA, now BANC.
Supplemental Power: The firm capacity and energy, provided by Western,
that a customer(s) needs in addition to its BR for use in meeting its
load.
Transmission: The movement or transfer of electric energy between
points of supply and points at which it is transformed for delivery to
customers or is delivered to other electric systems.
Transmission Service Provider (TSP): The entity that administers the
transmission tariff and provides transmission service to transmission
customers under applicable transmission service agreements.
TRR: Transmission Revenue Requirement.
UUP: Unreserved Use Penalties.
VR: Variable Resource.
Western: Western Area Power Administration.
Washoe Project: A Reclamation project located in the Lahontan Basin in
west-central Nevada and east-central California.
WECC: The Western Electricity Coordinating Council (WECC) is the
regional entity responsible for coordinating and promoting bulk
electric system reliability in the Western Interconnection.
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 the Federal Energy Regulatory Commission (FERC) on a final basis.
Public Notice and Comment
Western Area Power Administration (Western) has followed the
Procedures for Public Participation in Power and Transmission Rate
Adjustments and Extensions, 10 CFR 903, in developing these formula
rates and schedules. The steps Western took to involve interested
parties in the rate process were:
1. The rate adjustment process began June 10, 2008, when Western
mailed a notice announcing an informal meeting to all Sierra Nevada
Region (SNR) Preference Customers and interested parties.
2. Western held 14 public informal rate meetings beginning June
2008 through April 2010, in Folsom, California, to discuss the formula
rate methodologies, components, and rationale for formula rates, to
discuss possible formula rate changes, and to answer questions and seek
customer input or proposed changes. Meeting agendas, notes, and
handouts are posted on Western's Web site: https://www.wapa.gov/sn/marketing/rates/ratesProcess/informalProcess/index.asp.
3. A Federal Register notice (FRN) published on January 3, 2011,\7\
which announced the proposed rates for Central Valley Project (CVP),
California-Oregon Transmission Project (COTP), and Pacific Alternating
Current Intertie (PACI), began the public consultation and comment
period and set forth the dates and location of public information and
public comment forums.
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\7\ See 76 FR 127 (2011).
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4. On January 5, 2011, Western sent an e-mail notification to all
SNR Preference Customers and interested parties transmitting the FRN
and reiterating the dates and locations of the public information and
comment forums.
5. On January 14, 2011, Western sent an e-mail notification to all
SNR Preference Customers and interested parties that the 2012 Rates
Brochure for Proposed Rates was available upon request and posted on
Western's Web site at https://www.wapa.gov/sn/marketing/rates/.
6. On January 14, 2011, Western sent an e-mail notification to all
SNR Preference Customers and interested parties reminding them of the
January 25, 2011, Public Information Forum (PIF).
7. On January 25, 2011, Western held a PIF at the Lake Natoma Inn
in Folsom, California. Western provided explanations of the proposed
rates for CVP, COTP, PACI, and Path 15 information, responded to
questions, and explained the differences between the existing and the
proposed rates. Western provided rate brochures and informational
handouts.
8. On February 8, 2011, Western sent an e-mail notification to all
SNR Preference Customers and interested parties announcing the location
of Western's Web site to view all comments received during the comment
period. That Web site also contained
[[Page 56910]]
information on how to obtain a copy of the PIF transcript.
9. On February 23, 2011, Western sent an e-mail notification to all
SNR Preference Customers and interested parties reminding them of the
March 1, 2011, Public Comment Forum (PCF).
10. On March 1, 2011, Western held a PCF to give Preference
Customers and interested parties an opportunity to comment for the
record. Three individuals commented at this forum.
11. On March 23, 2011, Western sent e-mail notification to all SNR
Preference Customers and interested parties that the PCF transcript was
received and a Summary of Comments from the PCF was posted on Western's
Web site. In addition to comments received at Western's PCF, Western
received 17 comment letters during the consultation and comment period,
which ended on April 4, 2011. All comments received prior to the close
of the consultation and comment period have been considered in
preparing this Rate Order. All written comments received are posted on
Western's Web site: https://www.wapa.gov/sn/marketing/rates/ratesProcess/formalProcess/CIL2011/index.asp.
12. On April 12, 2011, Western sent an e-mail notification to all
SNR Preference Customers and interested parties announcing the end of
the public consultation and comment period.
Comments
Written comments were received from the following organizations:
Alameda Municipal Power, California; Bay Area Rapid Transit,
California; Calaveras Public Power Agency, California; Calpine
Corporation, California; City of Biggs, California; City of Lodi,
California; City of Palo Alto, California; City of Santa Clara (dba
Silicon Valley Power), California; Eastside Power Authority,
California; Northern California Power Agency (representing the Bay Area
Rapid Transit District, Truckee-Donner Public Utility District, the
Plumas-Sierra Rural Electric Cooperative, the Port of Oakland, and the
cities of Alameda, Biggs, Fallon, Gridley, Healdsburg, Lodi, Lompoc,
Palo Alto, Redding, Roseville, and Ukiah), California; Plumas-Sierra
Rural Electric Cooperative, California; Power and Water Resources
Pooling Authority (representing the Arvin-Edison Water Storage
District, Banta-Carbona Irrigation District, Byron-Bethany Irrigation
District,\8\ Cawelo Water District, Glenn-Colusa Irrigation District,
James Irrigation District, Lower Tule River Irrigation District,
Provident/Princeton Irrigation District, Reclamation District 108,
Santa Clara Valley Water District, Sonoma County Water Agency, West
Side Irrigation District, West Stanislaus Irrigation District, and the
Westlands Water District), California; Redding Electric Utility,
California; Roseville Electric, California: Sacramento Municipal
Utility District, California; Trinity Public Utility District,
California; Tuolumne Public Power Agency, California.
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\8\ Byron Bethany Irrigation District withdrew from the Power
and Water Resources Pooling Authority effective June 30, 2011.
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Representatives of the following organizations made oral comments:
Calpine Corporation, California.
Northern California Power Agency (representing the Bay Area Rapid
Transit District, Truckee-Donner Public Utility District, the Plumas-
Sierra Rural Electric Cooperative, the Port of Oakland, and the cities
of Alameda, Biggs, Fallon, Gridley, Healdsburg, Lodi, Lompoc, Palo
Alto, Redding, Roseville, and Ukiah), California
Redding Electric Utility, California.
Project Description
A. History and Description of the CVP, PACI, and COTP
The CVP is located within the Central Valley and Trinity River
basins of California. The CVP includes 18 constructed dams and
reservoirs with a total storage capacity of 13 million acre feet. The
system includes 615 miles of canals, five pumping facilities, and ten
power plants with a maximum operating capability of about 2,113
megawatts (MW), approximately 865 circuit-miles of high-voltage
transmission lines, 22 substations, and 19 communication sites. The
Bureau of Reclamation (Reclamation) operates the water control and
delivery system and all of the power plants with the exception of the
San Luis Pump-Generator (also known as W.R. Gianelli), which is
operated by the State of California for Reclamation.
The Emergency Relief Appropriations Act of 1935 initially
authorized the CVP.\9\ Congress reauthorized the CVP in 1937 in the
Rivers and Harbors Act.\10\ As part of the CVP, Congress authorized
Reclamation to construct the Shasta Dam on the Sacramento River and
Friant Dam on the San Joaquin River. Between the two dams are the Tracy
Pumping Plant and the Delta-Mendota Canal, the Contra Costa Canal, the
Friant-Kern Canal, the Madera Canal, and the Delta Cross Channel.\11\
Power plants at Shasta and Keswick Dams were also included in the
authorization, along with high-voltage transmission lines designed to
transmit power from Shasta and Keswick Power Plants to the Tracy pumps
and to integrate the Federal hydropower into other electric
systems.\12\ Through various acts, Congress authorized the construction
and integration of numerous other facilities into the CVP. For
instance, in 1944, Congress authorized the American River Division
(Division) to be constructed by the United States Army Corps of
Engineers (Corps).\13\ In 1949, the Division was reauthorized for
integration into the CVP.\14\ The Division included Folsom Dam and
Power Plant, Nimbus Dam and Power Plant, and the Sly Park Unit, all
located on the American River.\15\ In 1955, Congress authorized the
Trinity River Division (Trinity Division) to include Trinity Dam and
Power Plant, Lewiston Dam and Power Plant, and the Lewiston Fish
Facilities, all located on the Trinity River.\16\ The Trinity Division
also includes Judge Francis Carr Power Plant, Whiskeytown Dam, and the
Spring Creek Power Plant. In 1960, Congress authorized the San Luis
Unit, including the B.F. Sisk San Luis Dam and San Luis Reservoir, San
Luis Canal, Coalinga Canal, O'Neill and Dos Amigos Pumping Plants, and
William R. Gianelli Pump-Generator.\17\ In 1965, Congress authorized
construction of the Auburn-Folsom South Unit (Unit) as an addition to
the CVP.\18\ This Unit included four sub-units, three of which have
been constructed: Foresthill, Folsom-Malby, and Folsom South Canal sub-
units. Congress has not authorized funding to complete the construction
of the Auburn Dam, which is part of the fourth sub-unit. Congress
authorized the San Felipe Division in 1967.\19\
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\9\ See 49 Stat. 115 (1935).
\10\ See 50 Stat. 844, 850 (1937).
\11\ See Plans set forth in Rivers and Harbors Committee
Document Numbered 35, 75th Cong., as adopted in 49 Stat. 1028, 1038
(1935).
\12\ See Id.
\13\ See 58 Stat. 887, 901 (1944).
\14\ See 63 Stat. 852 (1949).
\15\ See Id.
\16\ See 69 Stat. 719 (1955).
\17\ See 74 Stat. 156 (1960).
\18\ See 79 Stat. 615 (1965).
\19\ See 81 Stat. 173 (1967).
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Three Corps projects--Buchanan, Hidden, and New Melones--were
authorized for integration into the CVP in 1962.\20\ The Black Butte
Integration Act added Black Butte, another Corps project completed in
the 1960's, to the CVP in 1970.
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\20\ See 76 Stat. 1173, 1191 (1962).
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In 1964, Congress authorized construction of the 500-kilovolt (kV)
[[Page 56911]]
Pacific Northwest-Pacific Southwest Intertie (Intertie). In northern
California, Western owns the Malin to Round Mountain portion of the
PACI.\21\ In 1984, Congress authorized Western to construct or
participate in the construction of the COTP.\22\ In 2001, Congress
authorized Western to complete the Path 15 portion originally
authorized under the COTP.\23\ Western, in marketing the Federal
hydroelectric power generated from the CVP, has approximately 47
wholesale customers serving an estimated two million people. Western
power customers include four First Preference (FP) Customers, public
utility districts, state agencies, Federal agencies, irrigation
districts, municipalities, and Native American tribes.
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\21\ See 78 Stat. 756 (1964).
\22\ See 98 Stat. 403 (1984).
\23\ See 115 Stat. 174 (2001).
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B. The 2004 Marketing Plan
Western's SNR markets hydropower generation of the CVP and Washoe
Projects. From 1967 through 2004, under the terms of Contract 14-06-
200-2948A (Contract 2948A) with the Pacific Gas and Electric Company
(PG&E), the CVP resources, along with other Western resources, were
integrated with PG&E resources. PG&E served the combined Western/PG&E
load with the integrated resource. Under this contract, PG&E delivered
power to both the Project Use (PU) and Preference Power Customers.
Contract 2948A expired on December 31, 2004, and PG&E informed Western
it intended not to extend the contract beyond that date. As a result of
the pending termination, Western worked with its customers to develop
and implement the 2004 Power Marketing Plan (Marketing Plan). Western
published the Marketing Plan in the Federal Register on June 25,
1999.\24\ It established the criteria for marketing CVP and Washoe
Project power output for a 20-year period from January 1, 2005, through
December 31, 2024.
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\24\ See 64 FR 34417 (1999).
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The Base Resource (BR) is a fundamental component and the primary
power product marketed under this Marketing Plan. Under previous
marketing plans, customers received a fixed capacity and load factor
energy allocation. Under the Marketing Plan, Preference Customers
(other than FP) receive an allocated percentage of the BR. Each BR
Customer signed a BR contract under the Marketing Plan.\25\
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\25\ See 75 FR 76975 (2010).
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The Marketing Plan acknowledges the BR may vary widely on an
hourly, daily, weekly, monthly, and annual basis depending on
hydrological conditions and other constraints that govern CVP
operations. CVP generation must be adjusted for PU, FP entitlements,
operations, maintenance, reserves, transformation losses, and certain
ancillary services before determining the net CVP generation amount
available for marketing. During some months, purchases may be required
to meet PU and FP Customers' obligations, and only a negligible amount,
if any, of BR will be available during some hours of such months.
According to the Marketing Plan, Western markets the BR separately
or in combination with custom products. These custom products could
include Western acting on behalf of a customer to: (1) Purchase some
level of firming power; (2) manage a portfolio of power resources; (3)
provide scheduling services per balancing authority (BA) operator
protocols; and (4) procure ancillary services. For those BR Customers
desiring custom products, Western developed additional contracts
detailing these requirements.
Western classified customers who contract for custom products into
two different customer groups: Variable Resource (VR) and Full Load
Service (FLS) Customers. VR Customers schedule their Federal power from
Western into their own ``resource portfolios'' to meet their load
requirements. The FLS Customers are those who require some additional
products and services to meet their full-load requirements and who
contracted with Western for such service.
The Marketing Plan also stipulated that Western would establish and
manage an exchange program to allow all customers to fully and
efficiently use their power allocations. Western developed both hourly
and seasonal exchange programs. Further specifics and stipulations of
this program are available in Exhibit B of the BR contract.
Pursuant to the Marketing Plan, BR Customers pay for CVP network
transmission service with their BR. Western also provides operating
reserves to its customers per the BA area operator's protocols to
support BR, PU, and FP deliveries. For all other products, such as a
custom product, separate transmission arrangements must be made by the
applicable customer with the appropriate transmission service provider
(TSP). Customers interested in acquiring transmission service from the
CVP system above that provided for BR deliveries will need to request
transmission through Western's Open Access Transmission Tariff (OATT).
A copy of the OATT can be obtained at Western's Web site at https://www.wapa.gov/transmission/oatt.htm. To the extent possible, if Western
has sufficient transmission rights, Western's merchant will use its
rights to meet custom product transmission requirements.
C. Path 15 Information
In May 2001, DOE released its National Energy Policy recommending
Western take action to explore relieving the constraints on Path 15.
Western analyzed the feasibility to construct the Path 15 Transmission
Upgrade Project which included building a third transmission line and
other upgrades that would allow about 1,500 MW of additional
electricity to be transmitted across the state. The path upgrade was
intended to relieve constraints on the existing north-south
transmission lines. In order to increase the path rating, Western
determined a new 84-mile long, 500-kV transmission line was needed
between PG&E's Los Banos and Gates Substations. Additionally, the Los
Banos and Gates Substations needed to be modified to accommodate the
new equipment and a second 230-kV circuit between Gates and Midway.
Western and the Path 15 participants completed the Path 15
Transmission Upgrade in 2005. Western turned over the operational
control of Western's Path 15 Transmission Upgrade to the California
Independent System Operator (CAISO). Western maintains the transmission
lines and is compensated by Atlantic Path 15, LLC, for the maintenance
work costs. The CAISO charges for use on the Path 15 Transmission
Upgrade as part of its rates. Western does not sell transmission
capacity on the Path 15 Transmission Upgrade. Western collects revenues
from the CAISO under its agreements with the CAISO. Under Amendment No.
48, the CAISO remits revenue to Western from wheeling, congestion, and
Congestion Revenue Rights associated with Western's rights on the Path
15.\26\
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\26\ Amendment No. 48 amended CAISO's tariff to provide
congestion revenues, wheeling revenues, and firm transmission rights
auction revenues to entities other than CAISO's Participating
Transmission Owners, if any such entities fund transmission facility
upgrades on the CAISO grid. See generally Federal Energy Regulatory
Commission Docket No. ER03-407-000.
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Power Repayment Study
Western prepares a power repayment study (PRS) each fiscal year
(FY) to determine if revenues will be sufficient to repay, within the
required time, all costs assigned to the commercial power
[[Page 56912]]
function. Repayment criteria are based on law, applicable policies
(including DOE Order RA 6120.2), and authorizing legislation.
Existing and Provisional Rates
The Deputy Secretary of Energy approved the existing formula rates
for power, transmission, and ancillary services under Rate Order No.
115 on November 22, 2004.\27\ FERC confirmed and approved the rates and
placed them into effect on a final basis on October 4, 2005.\28\ The
rates were amended by Rate Order No. 128 on July 26, 2006 \29\ and
extended by Rate Order No. 139 on August 12, 2008.\30\ The existing
formula rates expire on September 30, 2011. The provisional rates
continue the existing formula rate methodologies for power; CVP, COTP,
and PACI transmission; transmission of Western power by others: Custom
Product Power (CPP): and ancillary services. The only changes between
the provisional rates and the existing rates are described in more
detail in the section titled ``Rate Discussion.'' The tables below
compare the current rates (FY 2011) for power, transmission, and
ancillary services under the existing rate formulas to estimated rates
(FY 2012) under the provisional rate formula methodologies as well as
any changes to the formula rate methodology. All rates are subject to
change prior to October 1, 2011.
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\27\ See 69 FR 70510 (2004).
\28\ See Western Area Power Admin., 113 FERC ] 61,026 (2005).
\29\ See 71 FR 45821 (2006).
\30\ See 73 FR 48381 (2008).
Rate Comparison
--------------------------------------------------------------------------------------------------------------------------------------------------------
Service Actual FY 2011 Estimated FY 2012 Percent change (%) Financial change Methodology change
--------------------------------------------------------------------------------------------------------------------------------------------------------
Power Service Rates
--------------------------------------------------------------------------------------------------------------------------------------------------------
PRR................................ $75,751,929........... $73,468,299.......... (3.01)................ Forecasted financial None, billing
and/or operational clarification only.
data.
FP Percentage...................... 4.80%................. 4.77%................ (0.63)................ Change due to Adopt a FP% true-up.
forecasted
operational data.
Maximum FP Allocation.............. 17.51%................ 20.54%............... 17.30................. Change due to None.
forecasted
operational data.
FP RR.............................. $3,636,093............ $3,504,438........... (3.62)................ Change due to Adopt a FP% true-up.
forecasted financial
and/or operational
data.
BR RR.............................. $72,115,836........... $69,963,861.......... (2.98)................ Change due to Adopt a FP% true-up.
forecasted financial
and/or operational
data.
CPP................................ Pass through.......... Pass through......... N/A................... N/A.................. Added Components 2
and 3.
VR Scheduling Charge (per schedule) $31.07................ $37.91............... 22.01................. Updated financial None, charges set for
data. 5-year rate period.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Transmission & Ancillary Services
--------------------------------------------------------------------------------------------------------------------------------------------------------
CVP PTP Transmission ($/kW--Month). $1.04 (April 2011).... $1.31................ 25.96................. Rate change due to None.
the anticipated
completion of new
assets that support
transmission
function.
CVP NITS ($/monthly)............... $1,783,441............ $2,247,754........... 26.03................. Rate change due to None.
anticipated
completion of new
assets that support
transmission
function.
CVP PTP Transmission ($/MWh)....... $2.74 (Spring)........ $2.72 (Winter)....... (0.37)................ Rate decrease due to None.
estimated change in
financial data.
PACI PTP Transmission ($/MWh)...... $1.21 (Spring)........ $1.22 (Winter)....... 0.83.................. Rate increase due to None.
estimated change in
financial data.
COTP PTP Transmission ($/MWh)...... $2.74 (Spring)........ $2.72 (Winter)....... (0.73)................ Rate decrease due to None.
estimated change in
financial data.
Third-Party Transmission........... Pass through.......... Pass through......... N/A................... N/A.................. None.
Unreserved Use Penalties........... N/A................... 200%................. New................... New penalty charge... New.
Regulation and Frequency Response $4.33................. $4.05................ (6.47)................ Decrease due to If self-provided, the
($/kW-month). change in financial penalty charge is
data. the greater of 150%
of actual or 150% of
market.
[[Page 56913]]
Spinning/Supplemental Reserves..... Price consistent with Price consistent with N/A................... N/A.................. If self-provided, the
CAISO. CAISO. penalty charge is
the greater of 150%
of actual or 150% of
market.
EI Service......................... Tiered................ Tiered............... N/A................... N/A.................. Charge greater of
150% of actual or
150% of market.
Variable rate.
GI Service......................... NA.................... New.................. New................... New.................. New tiered
methodology similar
to EI.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Certification of Rates
Western's Administrator certified that the provisional rates, Rate
Schedules CV-F13, CPP-2, CV-T3, CV-NWT5, COTP-T3, PACI-T3, CV-TPT7, CV-
UUP1, CV-SPR4, CV-SUR4, CV-RFS4, CV-EID4, and CV-GID1, for CVP firm
power, transmission, and ancillary services are at the lowest possible
rates consistent with sound business principles. The provisional rates
were developed following administrative policies and applicable laws.
Rates Discussion
Following is a discussion comparing the existing formula rates to
the provisional formula rates. Unless otherwise noted, the formula rate
methodologies for power; CVP, COTP, and PACI transmission; transmission
of Western power by others; CPP; and ancillary services have not
changed. The percentage differences in rates noted in the table above
are due to estimated or forecasted data factors (costs, investments,
generation, load, etc.) and not due to a change to the formula rate
methodology. All FY 2012 rates are estimates and subject to change
prior to publication of the final FY 2012 rate. Having considered all
comments submitted during the public consultation and comment period,
the current rate action adopts existing formula rate methodologies for
power; CVP, COTP, and PACI transmission; transmission of Western power
by others; CPP; and ancillary services with the following exceptions:
1. Two new rate schedules: Unreserved Use Penalties (UUP) and
Generator Imbalance (GI);
2. Annual true-up for FP percentages;
3. In addition to the existing 150 percent penalty on the CAISO
market price, Western will adopt a 150 percent penalty on Western's
actual cost when charging for ancillary services and will charge the
greater of the two;
4. Costs incurred under Energy Imbalance (EI)/GI when disposing of
surplus energy, including negative pricing of such energy, will be
charged to the responsible party;
5. For intermittent resources interconnected to Western's system,
Western will not charge the 150 percent penalty, and charge the greater
of CAISO market price or Western's actual cost;
6. Added Components 2 and 3, standard cost recovery language, to
CPP formula rate; and
7. Rate Schedules include miscellaneous language changes and
billing clarifications. Formula rates methodologies are included in the
attached provisional rate schedules. All the formula rates contain
three components. Component 1 is the methodology used to develop the
rate and is specific to each rate. Components 2 and 3 are applicable to
all rate formulas.
A. Power Rate Discussion FP and BR
The difference in the forecasted FY 2012 revenue requirement (RR)
and the existing RR is the result of a change in projected revenue and
expenses and not a formula rate methodology change. The only change to
this formula rate is the adoption of an annual FP percentage true-up. A
change resulting from the FP percentage prior period true-up will
impact both FP and BR RR to ensure full recovery of the Power Revenue
Requirement (PRR).
Both the existing formula rate and the provisional formula rate for
FP Customers consist of three components:
Component 1:
[GRAPHIC] [TIFF OMITTED] TN14SE11.006
Where:
FP Customer Load = An FP Customer's forecasted annual load in
megawatthours (MWh).
Gen = The forecasted annual CVP and Washoe generation (MWh).
Power Purchases = Power purchases for PU and FP loads (MWh).
PU = The forecasted annual PU loads (MWh).
MRR = Monthly PRR.
The formula rate also contains Components 2 and 3.
Both the existing formula rate and the provisional rate for BR
consist of three components:
Component 1:
BR Customer Allocation = (BR RR x BR%)
Where:
BR RR = BR Monthly RR.
BR% = BR percentage for each customer as indicated in the BR
contract after adjustments for programs, such as hourly exchange
(HE), if applicable.
The formula rate also contains Components 2 and 3.
The table below compares the existing RR for FY 2011 to the
estimated RR for FY 2012 under the provisional formula rates.
[[Page 56914]]
Comparison of Existing to Provisional PRR, and Allocation to FP and BR Customers
----------------------------------------------------------------------------------------------------------------
Estimated RR for
the provisional
Service Existing RR FY formula rate Percent Change
2011 (effective FY
2012)
----------------------------------------------------------------------------------------------------------------
PRR....................................................... $75,751,929 $73,468,299 (3.01)
FP RR..................................................... 3,636,093 3,504,438 (3.62)
BR RR..................................................... 72,115,836 69,963,861 (2.98)
----------------------------------------------------------------------------------------------------------------
The 3.01 percent forecasted decrease in the PRR is due primarily to
a decrease in other expenses and increase in transmission revenues,
which offsets expenses in the PRR. The increase in transmission revenue
is driven by the anticipated completion of assets supporting the
transmission function. As indicated in the current rate structure, the
power rates are published annually by September 30 and reviewed during
March of each year. The annual PRR is allocated to FP Customers based
on each FP Customer's percentage, as adjusted for prior period true-up,
and the remainder to BR Customers based on their contractual
percentage.
Western will continue to maintain its current policy and perform a
FP percentage midyear review and adjust the FP percentages if
necessary. Any adjustment to the FP percentages at midyear will be
applied to the annual PRR and billed during the remainder of the FY. In
addition, Western is adopting an annual true-up methodology for each FP
customer's percentage to ensure FP Customers pay their proportionate
share of the annual PRR. Following the completion of the true-up,
Western will allocate the charge or credit through the PRR at the
beginning of the following FY. Also, according to current policy, FP
maximum percentage changes will be established once at the beginning of
each 5-year rate period.
The table below compares the FP percentages as well as their
maximum percentages for the two periods.
FP Percentage Comparison, and Actual Maximum Percentages for Effective Rate Period
----------------------------------------------------------------------------------------------------------------
FP percentages (annual) Maximum FP customer percentage
------------------------------------ applied to the RR
FP Customers -----------------------------------
Existing FY Estimated FY Existing (FY Actual (FY 2012-
2011 (%) 2012 (%) 2005-2011) (%) 2016) (%)
----------------------------------------------------------------------------------------------------------------
Sierra Conservation Center.............. 0.37 0.37 1.39 1.58
Calaveras Public Power Agency........... 0.90 0.90 3.49 3.81
Trinity Public Utilities District....... 2.80 2.80 9.21 12.01
Tuolumne Public Power Agency............ 0.73 0.70 3.42 3.16
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Total............................... 4.80 4.77 17.51 20.56
----------------------------------------------------------------------------------------------------------------
The change in FP percentages is due to changes in generation and FP
customer loads and not a formula rate methodology change. The increase
in FP maximum percentage is due to a collective increase in FP customer
loads.
During the effective rate period, if deemed appropriate, Western
will reevaluate the FP maximum percentage based
