[Federal Register Volume 76, Number 178 (Wednesday, September 14, 2011)]
[Notices]
[Pages 56906-56936]
From the Federal Register Online via the Government Publishing 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.

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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until superseded.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 [email protected].

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).
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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.
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    \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: http://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 http://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: http://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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \20\ See 76 Stat. 1173, 1191 (1962).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \21\ See 78 Stat. 756 (1964).
    \22\ See 98 Stat. 403 (1984).
    \23\ See 115 Stat. 174 (2001).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \24\ See 64 FR 34417 (1999).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \25\ See 75 FR 76975 (2010).
---------------------------------------------------------------------------

    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 http://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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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
                                         -----------------------------------------------------------------------
    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 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 
miscellaneous expenses allocated to power, such as settlements, 
California-Oregon 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 statutorily-
required 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, 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 12-month 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 one-half 
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

[[Page 56915]]

change prior to the rates taking effect for FY 2012. The RRs will be 
finalized by Western on or before October 1, 2011.

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 
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-of-service (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 support the generation capability of the CVP 
system (including generation tie-lines 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:
    [GRAPHIC] [TIFF OMITTED] TN14SE11.007
    
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 
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. 
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 x \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

[[Page 56916]]

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    Estimated COTP
                          Season                              rates FY 2011     rates FY 2012    Percent change
                                                                 ($/MWh)           ($/MWh)             (%)
----------------------------------------------------------------------------------------------------------------
Spring....................................................             $2.74             $2.70            (1.46)
Summer....................................................              2.73              2.69            (1.47)
Winter....................................................              2.77              2.72            (1.81)
----------------------------------------------------------------------------------------------------------------

The existing and provisional formula rate for COTP PTP transmission 
service consists of three components.
    Component 1:
    [GRAPHIC] [TIFF OMITTED] TN14SE11.008
    
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 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 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.

[[Page 56917]]



 Comparison of Existing Rates to Estimated Provisional Rates for PACI Firm and Non-Firm PTP Transmission Service
----------------------------------------------------------------------------------------------------------------
                                             Existing PACI    Estimated PACI
                  Season                     rates FY 2011     rates FY 2012             Percent change
                                                ($/MWh)           ($/MWh)
----------------------------------------------------------------------------------------------------------------
Spring...................................             $1.21             $1.21  No change.
Summer...................................              1.21              1.21  No change.
Winter...................................              1.15              1.22  6.09
----------------------------------------------------------------------------------------------------------------

    The existing and provisional formula rate for PACI transmission 
service consists of three components:
    Component 1:
    [GRAPHIC] [TIFF OMITTED] TN14SE11.009
    
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.

    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 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.
 Transmission of Western Power by Others
    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 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

[[Page 56918]]

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 non-performance of self provision; (4) spinning reserve 
penalty portion for non-performance; and (5) supplemental reserve 
penalty portion for non-performance. 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-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 non-performance 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 non-performance 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.
    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 non-performance 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

[[Page 56919]]

factors being equal. The provisional formula rate for this service is 
comprised of three components.
    Component 1:
    [GRAPHIC] [TIFF OMITTED] TN14SE11.010
    
    The annual RR includes: (1) The CVP generation costs associated 
with providing regulation, and (2) the non-facility costs allocated to 
regulation.
    The annual regulating capacity is one-half 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 non-facility 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
    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-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...................  90 MW
Actual Net Interchange......................  102 MW
Actual Energy in excess of Scheduled Energy.  12 MW
Contractual Bandwidth.......................  8 MW
EI for HE 1.................................  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

[[Page 56920]]

charge for October 1, HE 1, is calculated as follows:

----------------------------------------------------------------------------------------------------------------
         October 1, hour ending 1              Price            Price comparison             MW         Charge
----------------------------------------------------------------------------------------------------------------
Western's Calculated Actual Cost ($18.27 x       $27.40  150% Actual < 150% of Market.          N/A          N/A
 150%) applied per rate schedule.
Real-Time CAISO price ($21.84 x 150%)             32.76  150% Market > Actual.........            4      $131.04
 applied per rate schedule.
----------------------------------------------------------------------------------------------------------------
Note: EI charge for October 1, HE 1, is calculated as follows: 4 MW x $32.76 = $131.04.

    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.
    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...................  102 MW
Actual Net Interchange......................  90 MW
Scheduled Generation in excess of Actual      12 MW
 Generation (under-delivery).
Contractual Bandwidth.......................  8 MW
GI for HE 1.................................  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:

----------------------------------------------------------------------------------------------------------------
         October 1, hour ending 1              Price            Price comparison             MW         Charge
----------------------------------------------------------------------------------------------------------------
Western's Calculated Actual Cost ($18.27 x       $27.40  150% of Actual < 150% of               N/A          N/A
 150%) applied per rate schedule.                         Market.

[[Page 56921]]

 
Real-Time CAISO price ($21.84 x 150%)            $32.76  150% Market > Actual.........            4      $131.04
 applied per rate schedule.
----------------------------------------------------------------------------------------------------------------
Note: GI charge for October 1, HE 1 is calculated as follows: 4 MW x $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)
   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   Provisional Rate
                Revenue or Expense Category                  Period FY 2006-   Period FY 2012-     Differences
                                                                 FY 2010           FY 2016
----------------------------------------------------------------------------------------------------------------
Total Revenue.............................................        $1,563,274        $1,955,569          $392,295
                                                            ................  ................  ................
Revenue Distribution......................................
 
Expenses:
    O&M...................................................           411,204           496,505            85,301
    Purchase Power & Transmission.........................           875,402         1,180,215           304,812
    Interest Expense......................................            26,371            50,881            24,510
    Other Expense (inc. wheeling).........................           177,817           173,331           (4,486)
                                                           -----------------------------------------------------
        Total Expenses....................................         1,490,794         1,900,931           410,137
                                                           -----------------------------------------------------
Principal Payments:
    Capitalized Expenses (deficits).......................             4,890                 0           (4,890)
    Original Project and Additions........................            51,075            52,644             1,569
    Replacements..........................................            14,521                 0          (14,521)
    Aid to Irrigation.....................................                 0                 0                 0
    Power Rights..........................................             1,994             1,994                 0
                                                           -----------------------------------------------------
        Total Principal Payments..........................            72,480            54,638          (17,842)
                                                           -----------------------------------------------------
        Total Revenue Distribution........................         1,563,275         1,955,569           392,294
----------------------------------------------------------------------------------------------------------------

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 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: http://www.wapa.gov/sn/marketing/rates/ratesProcess/formalProcess/CIL2011/index.asp.
    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

[[Page 56922]]

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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                      Year 1 FP and BR
                                             Year 1 FP % (based on     Year 1 FP and BR       Year 1 actual FP %           actual          Difference
               FP Customer                         estimate)            PRR  allocation   (determined during year 2)   (adjusted)  PRR  (applied in year
                                                                                                                         allocation            3)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Customer A..............................  0.35%......................          $262,500  0.38%......................          $285,000           $22,500
Customer B..............................  0.90%......................           675,000  0.85%......................           637,500          (37,500)
Customer C..............................  2.80%......................         2,100,000  2.90%......................         2,175,000            75,000
Customer D..............................  0.75%......................           562,500  0.75%......................           562,500                 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
----------------------------------------------------------------------------------------------------------------
                                                                                PY FP true-up
            FP Customer                 Year 3 est. FP %    Year 3 estimated   (Year 1 true-up    Total year 3
                                                               PRR payment         amount)            bill
----------------------------------------------------------------------------------------------------------------
Customer A.........................  0.35%................          $255,500           $22,500          $278,000
Customer B.........................  0.90%................           657,000          (37,500)           619,500
Customer C.........................  2.85%................         2,080,500            75,000         2,155,500
Customer D.........................  0.77%................           562,100                 0           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).............  .....................        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 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 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.

[[Page 56923]]

    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 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 
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 in-depth 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.

[[Page 56924]]

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 Sacramento-area 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 system-wide 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.
    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 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.
---------------------------------------------------------------------------

    \31\ See Transmission Planning and Cost Allocation by 
Transmission Owning and Operating Public Utilities, 131 FERC ] 
61,253 (2010).
---------------------------------------------------------------------------

    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

[[Page 56925]]

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 10-year 
transmission plan annually, and posts meeting notifications, documents, 
and plans on its OASIS at http://www.oatioasis.com/wasn/index.html. 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 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 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 self-
provide.
    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

[[Page 56926]]

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: http://www.wapa.gov/sn/marketing/rates/.

Ratemaking Procedure Requirements

Environmental Compliance

    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.

Determination Under Executive Order 12866

    Western has an exemption from centralized regulatory review under 
Executive Order 12866; accordingly, no clearance of this notice by the 
Office of Management and Budget is required.

Submission to the 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.

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.

Dated: September 2, 2011.
Daniel B. Poneman
Deputy Secretary
Rate Schedule CV-F13
(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, 
three-phase, 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 March-
through-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.......................  ...................       $70,000,000
FP Customers' Allocation (Total    $70,000,000 x 5%...         3,500,000
 FP % = 5%).
Remaining PRR Allocated to BR....  $70,000,000--$3,500        66,500,000
                                    ,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.

    FP Power Formula Rate:
    The annual FP customer allocation is equal to the annual PRR 
multiplied by the relevant FP percentage. The formula rate for FP power 
has three components.
    Component 1:
    [GRAPHIC] [TIFF OMITTED] TN14SE11.011
    
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.

    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, 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.

[[Page 56927]]



                                         Table 1--Estimated and Actual Year 1 PRR Allocation Due to FP % True-up
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                      Year 1 FP and BR
                                             Year 1 FP % (based on     Year 1 FP and BR       Year 1 actual FP %           actual          Difference
               FP Customer                         estimate)            PRR  allocation   (determined during year 2)   (adjusted)  PRR  (applied in year
                                                                                                                         allocation            3)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Customer A..............................  0.35%......................          $262,500  0.38%......................          $285,000           $22,500
Customer B..............................  0.90%......................           675,000  0.85%......................           637,500          (37,500)
Customer C..............................  2.80%......................         2,100,000  2.90%......................         2,175,000            75,000
Customer D..............................  0.75%......................           562,500  0.75%......................           562,500                 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
----------------------------------------------------------------------------------------------------------------
                                                                                PY FP true-up
            FP customer                 Year 3 est. FP %    Year 3 estimated   (year 1 true-up    Total year 3
                                                               PRR payment         amount)            bill
----------------------------------------------------------------------------------------------------------------
Customer A.........................  0.35%................          $255,500           $22,500          $278,000
Customer B.........................  0.90%................           657,000          (37,500)           619,500
Customer C.........................  2.85%................         2,080,500            75,000         2,155,500
Customer D.........................  0.77%................           562,100                 0           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).............  .....................        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 the 
maximum percentage and make adjustments as appropriate.

 FP Actual Maximum Percentages Effective Rate Period FY 2012 through FY
                                  2016
------------------------------------------------------------------------
                                                           Maximum FP
                                                            customer
                      FP customer                          percentage
                                                         applied to the
                                                           MRR percent
------------------------------------------------------------------------
Sierra Conservation Center............................              1.58
Calaveras Public Power Agency.........................              3.81
Trinity Public Utilities District.....................             12.01
Tuolumne Public Power Agency..........................              3.16
    Total.............................................             20.56
------------------------------------------------------------------------

    Below is a sample calculation for an FP customer's monthly charge 
for power.

             Example: FP Monthly Customer Charge Calculation
------------------------------------------------------------------------
 
------------------------------------------------------------------------
Numerator:
  FP Customer's Load--MWh...............................          10,000
Denominator:
  Washoe Generation--MWh................................           2,500
  CVP Generation--MWh...................................       3,700,000
  PU Load--MWh..........................................     (1,200,000)
  PU Purchase--MWh......................................          47,000
Calculated Percentage:
  FP Customer's Percentage..............................           0.39%
------------------------------------------------------------------------
Monthly Power Revenue Requirement (MRR).................      $3,333,333
------------------------------------------------------------------------
FP Customer Monthly Charge = (FP % x MRR)...............         $13,000
------------------------------------------------------------------------


[[Page 56928]]

    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 x 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    Hourly BR = 30   Customer's BR     Customers     BR delivered
                       BR Customer                           contract           MWh           > load       receiving HE   (adj'd for HE)   Revised BR %
--------------------------------------------------------------------------------------------------------------------------------------------------------
Customer A..............................................             20%               6               3               0               3           10.0%
Customer B..............................................             10%               3               0               1               4           13.3%
Customer C..............................................             70%              21               0               2              23           76.7%
                                                         -----------------------------------------------------------------------------------------------
    Total...............................................            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 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-by-case basis to determine the appropriate treatment for 
repayment and cash flow management.
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, 
three-phase, 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:

[[Page 56929]]

    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
---------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                           Proceeds from
                                                          CPP  Purchased     CPP USED       CPP  costs      Surplus CPP     excess CPP     CPP customer
                                                               (MWh)           (MWh)                           sold            sales          charges
--------------------------------------------------------------------------------------------------------------------------------------------------------
Customer A..............................................               5               5  ..............               0  ..............            $283
Customer B..............................................               4               4  ..............               0  ..............             226
Customer C..............................................               4               3  ..............               1  ..............             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            2013            2014            2015            2016
----------------------------------------------------------------------------------------------------------------
VR Scheduling Charge Per                  $37.91          $39.04          $40.21          $41.42          $42.66
 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 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: 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-by-case basis to determine the appropriate treatment for 
repayment and cash flow management.

[[Page 56930]]

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 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:
    [GRAPHIC] [TIFF OMITTED] TN14SE11.012
    
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 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-by-case basis to determine the appropriate treatment for 
repayment and cash flow management.
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).
    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 x 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 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'

[[Page 56931]]

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: 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-by-case basis to determine the appropriate treatment for 
repayment and cash flow management.
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.
    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-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 COTP firm and non-firm PTP 
transmission service includes three components:
    Component 1:
    [GRAPHIC] [TIFF OMITTED] TN14SE11.013
    
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.

Western will update the rate from Component 1 for COTP firm and non-
firm 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 Same-Time 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 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 schedule will be evaluated on 
a case-by-case 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-to-point 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:

[[Page 56932]]

[GRAPHIC] [TIFF OMITTED] TN14SE11.014

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.

    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.
    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-by-case basis to determine the appropriate treatment for 
repayment and cash flow management.
Rate Schedule CV-TPT7
(Supersedes Schedule CV-TPT6)

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 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-by-case 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,

[[Page 56933]]

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.
    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.
    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 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 
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-by-case basis to determine the appropriate

[[Page 56934]]

treatment for repayment and cash flow management.
Rate Schedule CV-SUR4
(Supersedes Schedule CV-SUR3)

Central Valley Project

Schedule of Rate for Supplemental 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 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-by-case basis to determine the appropriate treatment for 
repayment and cash flow management.
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:
    [GRAPHIC] [TIFF OMITTED] TN14SE11.015
    
    The annual revenue requirement includes: (1) The Central Valley 
Project generation costs associated with providing regulation, and (2) 
the non-facility costs allocated to regulation.
    The annual regulating capacity is one-half 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-

[[Page 56935]]

case basis to determine the appropriate treatment for repayment and 
cash flow management.
Rate Schedule CV-EID4
(Supersedes Schedule CV-EID3)

Central Valley Project

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) 
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-by-case 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 Sub-Balancing 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 
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

[[Page 56936]]

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 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-case 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