76 Fed. Reg. 127 (Jan. 3, 2011)

The Central Valley Project, the California-Oregon Transmission Project, the Pacific Alternating Current Intertie, and Path 15 Transmission-Rate Order No. WAPA-156

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Federal RegisterJan 3, 2011

76 Fed. Reg. 127 (Jan. 3, 2011)

AGENCY:

Western Area Power Administration, DOE.

ACTION:

Notice of Proposed Power, Transmission, and Ancillary Services Rates.

SUMMARY:

The Western Area Power Administration (Western) is proposing new and revised formula rates and information for the following: Western power, the Central Valley Project (CVP) transmission, the California-Oregon Transmission Project (COTP) transmission, the Pacific Alternating Current Intertie (PACI) transmission, ancillary services, custom product power, and information on Path 15 transmission upgrade. In addition to these existing rates for services, Western also is proposing to implement two new rates and services: Unreserved Use Penalties and Generator Imbalance Services (GI).

Western is not proposing any changes to its existing formula rate methodologies. The proposed rates will provide sufficient revenue to pay all annual costs including interest expense, investments, and aid to irrigation within the allowable time periods. Western's rate brochure providing detailed information on the proposed formula rates will be available January 11, 2011, to all interested parties upon request.

The current rates for existing services expire on September 30, 2011. If approved, the proposed rates would become effective on October 1, 2011, and remain in effect through September 30, 2016, or until superseded by another rate schedule. Publication of this Federal Register notice begins the formal process for the proposed rate adjustments.

See Rate Order No. WAPA-139, 73 FR 48381 (August 19, 2008).

DATES:

The consultation and comment period will begin on the date of publication of the Federal Register notice and will end April 4, 2011. Western will present a detailed explanation of the proposed rates at a public information forum. The public information forum date is: January 25, 2011, 1 p.m. Pacific Standard Time, Folsom, CA.

Western will accept written comments anytime during the consultation and comment period. In addition, Western will accept oral and written comments at a public comment forum. The public comment forum date is: March 1, 2011, 1 p.m. Pacific Standard Time, Folsom, CA.

ADDRESSES:

Send written comments to Mr. Thomas R. Boyko, Regional Manager, or Mr. Charles J. Faust, Rates Manager, Sierra Nevada Customer Service Region, Western Area Power Administration, 114 Parkshore Drive, Folsom, CA 95630-4710, or e-mail comments to SNR-FY12RateCase@wapa.gov.

Western will accept written comments anytime during the consultation and comment period. Western will post comments it receives on Western's Web site at http://www.wapa.gov/sn/marketing/rates/ratesprocess/formalProcess/index.asp. Western must receive written comments by the end of the consultation and comment period to ensure consideration.

Western will host both the public information and public comment forums at: Lake Natoma Inn, 702 Gold Lake Drive, Folsom, CA 95630-2559, telephone number (916) 351-1500.

FOR FURTHER INFORMATION CONTACT:

Mr. Charles J. Faust, Rates Manager, Sierra Nevada Customer Service Region, Western Area Power Administration, 114 Parkshore Drive, Folsom, CA 95630-4710, telephone (916) 353-4468, or e-mail SNR-FY12RateCase@wapa.gov.

SUPPLEMENTARY INFORMATION:

This Federal Register notice initiates the formal public process to replace the Federal Energy Regulatory Commission's (FERC) approved rate schedules effective beginning January 1, 2005, ending September 30, 2011.

The following discussion provides an overview of the proposed formula rates and components, including a rate comparison, rate recovery, and applicability. Western held 14 public Informal Rate meetings beginning June 2008 through April 2010. Based on stakeholders' comments and Western's analysis, Western is not proposing any changes to existing rate methodologies. Western proposes adding new rate schedules for unreserved use penalties and generator imbalance services. Western will continue to operate as a Sub-Balancing Authority (SBA) under contract with the Sacramento Municipal Utility District, who operates the Host Balancing Authority (HBA).

Prior to the start of each fiscal year (FY), Western will calculate and publish an annual Power Revenue Requirement (PRR) to determine the total cost of power to be allocated to preference customers. For example, by October 1, 2011, Western will publish the PRR for FY 2012, which begins October 1, 2011, and ends September 30, 2012. As part of the rate development, Western prepares a Power Repayment Study (PRS) each FY to determine if 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 operation and maintenance (O&M) expenses, purchased power for Project Use and First Preference (FP) customers' loads, interest and other expenses (including any other statutorily-required costs or charges), investment repayment, and the Washoe Project annual PRR that remains after project use loads are met. Revenues from project use, transmission, ancillary services, and other services are offset against expenses in the PRR; and the remainder is collected from Base Resource (BR) and FP customers. The PRR is reviewed during March of each year; and if such review results in a change of $5 million or more, the PRR is adjusted for the remaining 6-month period. The PRR is an estimate of revenues and costs including investment and repayment projections from the PRS. Any deviation from estimate to actual will increase or decrease annual project repayment. Project repayment is measured over the long term to ensure repayment is met and to maintain rate stability.

The PRR is allocated to Western's preference customers, namely, FP customers based on their FP percentages, and the remaining amount to BR customers based on their BR allocation, adjusted for programs, such as, hourly exchange. The Trinity River Division Act of 1955 (69 Stat. 719) and the Flood Control Act of 1962 (76 Stat. 1173, 1191-1192) accorded first preference to CVP power to customers in Trinity, Tuolumne, and Calaveras Counties. A BR customer, under the 2004 Marketing Plan, is an entity that has executed a BR contract and is allocated a percentage of the BR.

In order for Western to meet the load requirements, beyond delivered BR, for Full Load Service (FLS) customers and Variable Resource (VR) customers, Western may make supplemental power (SP) purchases, pursuant to the Custom Product Power (CPP) rate schedule. FLS and VR customers who contract with Western for such service will pay all SP costs. FLS customers pay a portfolio management charge pursuant to their contract, whereas VR customers pay a scheduling charge pursuant to the proposed rate schedule.

At least annually, Western will publish the CVP transmission rates for point-to-point and network integration transmission service, the seasonal COTP and PACI transmission rates, and CVP regulation and frequency response service rates. Western prepares a detailed cost-of-service 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 cost-of-service 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 RR. Third-party transmission service costs are passed through directly to each requesting customer.

Spinning and supplemental reserves are charged the price consistent with the California Independent System Operator's (CAISO) market price plus all costs incurred for the sale of these reserves. Customers who have a contractual obligation to provide spinning and supplemental reserves and do not fulfill their obligation will be assessed a penalty equal to the greater of Western's actual cost or 150 percent of the market price. Similarly, for Energy Imbalance (EI) service, customers outside of their contractual bandwidth (under delivery) will pay the greater of 150 percent of the market price or Western's actual cost. Given Western's EI customers are and will continue to operate under existing agreements, Western will continue its existing rate methodology for EI. During the applicable rate period, Western will review FERC Order No. 890 pro forma approach, as well as Western's existing settlements and billing processes and will reconsider a transition to FERC's pro forma tariff methodology during Western's next rate process or earlier if deemed appropriate.

Finally, based on the requirements under FERC's Order No. 890, Western proposes adding two new rate schedules to be effective during the new rate period: Unreserved Use Penalties and GI. Western proposes the Unreserved Use Penalties be assessed at 150 percent of the effective point-to-point transmission rate when transmission service is used and not reserved or when used in excess of reservation. Western proposes the GI rate use the same tiered methodology as Western's existing and proposed EI service rate and any subsequent changes. Note, currently Western has no customers subject to this proposed GI rate.

Information on Path 15 Transmission Upgrade

The Path 15 Transmission Upgrade was completed in 2005. Western has turned over the operational control of Western's Path 15 Upgrade to the CAISO. Western maintains the lines and is compensated by Atlantic Path 15, LLC for the Operation and Maintenance work costs. The CAISO charges for use on the Path 15 Upgrade as part of its rates. Western does not charge a separate rate for Path 15. 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.

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 Federal Energy Regulatory Commission Docket No. ER03-407-000.

Proposed Rate Schedules and Discussion

Proposed Rate Schedule Cv-F13 (Supersedes CV-F12)

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 Sierra Nevada Customer Service Region (SNR).

Applicable: To the BR and 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 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: Western will develop the PRR prior to the start of each FY. The PRR will be divided into two 6-month periods, October through March and April through September. A monthly PRR will be calculated by dividing each 6-month PRR by six. 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 for the April-through-September period will be recalculated. The PRR is allocated to FP and BR customers based on the formula rates.

Example of Power Revenue Requirement Allocation to First Preference and Base Resource

Component	Formula	Allocation
Annual PRR		$70,000,000
FP Customer Allocation (Total FP % = 5%)	$70,000,000 × 5%	3,500,000
Remaining PRR Allocated to BR	$70,000,000−$3,500,000	66,500,000
Note: This example is intended to show the PRR allocation to the customer groups and is not adjusted for billing or midyear adjustments.

First Preference Power Formula Rate: The annual FP customer allocation is equal to the annual PRR multiplied by the relevant FP percentage.

Component 1:

Where:

FP Customer Load = An FP customer's forecasted annual load in megawatthours (MWh).

Gen = The forecasted annual CVP and Washoe generation (MWh).

Power Purchases = Power purchases for project use and FP loads (MWh).

Project Use = The forecasted annual project use loads (MWh).

MRR = Monthly Power Revenue Requirement.

Western will develop the FP customer 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 the FP customer's percentage of more than one-half of one percent, the percentage will be revised for the April-through-September period.

The percentages in the table below are the maximum percentages for each FP customer that will be effective 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's charges for more than 1 year, Western will evaluate their percentage from the formula rate versus the maximum percentage and make adjustments as appropriate.

First Preference's Actual Maximum Percentages Effective Rate Period

FP customers	Maximum FP customer's percentage applied to the MRR (%)
Sierra Conservation Center	1.58
Calaveras Public Power Agency	3.81
Trinity Public Utilities District	11.99
Tuolumne Public Power Agency	3.16
Total	20.54

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

Example—First Preference Monthly Customer Charge Calculation

Numerator:
FP Customer Load—MWh	10,000
Denominator:
Washoe Generation—MWh	2,500
CVP Generation—MWh	3,700,000
Project Use Load—MWh	(1,200,000)
Project Use Purchase—MWh	47,000
Calculated Percentage:
FP Customer Percentage	0.39%
Monthly Power Revenue Requirement (MRR)	$3,333,333
FP Customer Monthly Charge = (FP % × MRR)	$13,000

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 body will be passed on to each relevant customer. The FERC's or other regulatory body's 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 body's accepted or approved charges or credits in the same manner Western is charged or credited. If FERC's or other regulatory body's 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.

BR Formula Rate: The annual BR allocation is equal to the annual PRR less the annual FP customer allocation.

Component 1:

BR Customer Allocation =(BR RR × BR %)

Where:

BR RR = BR Monthly Revenue Requirement (RR)

BR % = BR percentage for each customer as indicated in the BR contract after adjustments for programs, such as hourly exchange, if applicable.

After the FP customers' share of the annual PRR has been determined, the remainder of the annual PRR is recovered from the BR 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.

A 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 Hourly Exchange (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 Base Resource Percentage Adjustments for Hourly Exchange Energy

BR customer	BR % from contract	Hourly BR = 30 MWh	Customer's BR > load	Customers receiving HE	BR delivered (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

Billing: Billing for BR and FP power will occur monthly using the respective formula rate.

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 RR 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 Comparison

Comparison of the existing to the proposed RR results in a change in costs and not a rate methodology change. The 0.86 percent PRR increase is due to an inflationary change to O&M, as well as increased interest expense. Those costs are offset by increased transmission revenue due to the anticipated completion of assets supporting the transmission function. The table below compares the existing RRs (FY 2011) to the estimated RRs (FY 2012) under the proposed formula rates.

Comparison of Existing to Proposed Power Revenue Requirement, and Allocation to First Preference and Base Resource Customers

Service	Existing RRs	Estimated RRs for the proposed formula rate (effective FY 2012)	Percent change (%)
PRR	$75,751,929	$76,401,847	0.86
FP RR	3,636,093	3,644,368	0.02
BR RR	72,115,836	72,757,479	0.89

The table below compares the FP percentages as well as their maximum percentages for the two periods.

First Preference Percentage Comparison, and Actual Maximum Percentages Effective Rate Period

FP Customers	FP percentages	Maximum FP customer's percentage applied to the MRR
Existing (%)	Estimated (%)	Existing (%)	Estimated (%)
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	11.99
Tuolumne Public Power Agency	0.73	0.70	3.42	3.16
Total	4.80	4.76	17.51	20.54

The change in FP percentages is due to changes in generation and FP customer loads not a rate methodology change. The increase in FP maximum percentage is due to a collective increase in FP customer loads not a rate methodology change.

During the effective rate period, if deemed appropriate, Western will reevaluate the FP maximum percentage based on new data.

Rate Recovery and Application

The formula rates for CVP FP power and BR power are based on a PRR that recovers: (1) O&M expense allocated to power; (2) CVP network transmission; (3) annual investment and replacement repayment; (4) aid-to-irrigation costs; (5) interest expense; (6) power purchases for firming BR; (7) Washoe project annual costs after project use loads are met; (8) other miscellaneous expenses allocated to power, such as, settlements, California-Oregon Intertie (COI) path operator costs, etc.; (9) the pass through of FERC's or other regulatory body's accepted or approved charges or credits; (10) the pass through of the HBA's charges or credits; (11) any other statutorily-required costs or charges; and (12) any other costs associated with BR or FP power service including uncollectible debt.

Expenses are offset by revenues from project use energy, transmission revenue, ancillary service revenue, scheduling coordinator, portfolio management and VR charge administrative fees, all pass through revenue, and any other miscellaneous revenue.

The PRR will be allocated first to FP customers based on their percentages, subject to the maximum cap, then the remaining amount to BR customers based on their BR allocation percentages, 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 mid-year review reflects a change of $5 million or more, the annual PRR will be revised. The FP percentages are also reviewed at mid-year. If the mid-year review reflects a change to a FP customer's percentage of more than one half of one percent, that customer's percentage will be revised for the remainder of the FY.

The formula rates apply to CVP BR and FP power customers. The estimated rates are subject to change prior to the rates taking effect. The rates will be finalized by Western on or before October 1, 2011.

Proposed Formula Rate for Custom Product Power and Effective Rate for Variable Resource Schedules

Rate Schedule CPP-2 (Supersedes CPP-1)

Effective: October 1, 2011, through September 30, 2016.

Available: Within the marketing area served by SNR.

Applicable: To customers that contract with Western for CPP.

To 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.

Formula Rate: The formula rate for CPP includes three components:

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, SP and 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 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 RR is $780). The CPP RR of $780 is reduced by the sale of 1 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 Custom Product Power Cost Recovery With Proceeds From Sales of Surplus Custom Product Power Use of Receipts, Federal Reimbursable, or Appropriations Authority

[If Western made a CPP purchase of 13 MW for the hour @ $60/MWh = $780]

	CPP purchased (MWh)	CPP USED (MWh)	CPP Costs	Surplus CPP sold	Proceeds from excess CPP sales	CPP customer charges
Customer A	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 $38.22 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 $38.22 per schedule charge to the estimated number of schedules.

The table below depicts the VR customers charge per schedule for the effective rate period.

Variable Resource Customers Effective Rate Per Schedule

FY	2012	2013	2014	2015	2016
VR Charge Per Schedule	$38.22	$39.36	$40.54	$41.76	$43.01

Billing: Billing for CPP and VR customers' 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.

Rate Comparison

Effective October 1, 2011, the CPP cost recovery is not changing from the existing methodology and remains 100 percent pass through under this rate schedule.

Under the proposed formula rate, Component 1, the VR customer's scheduling charge is adjusted to $38.22 per schedule. This is a 23-percent increase from the January 1, 2005, VR customer's charge of $31.07 per schedule. This increase is based on a percentage change in O&M from the 2005 rate case through FY 2010. The FY 2013 VR customer's charge increases 3 percent each year through FY 2016 to reflect inflationary increases. The rate increase is due to inflationary costs not a rate methodology change.

Rate Recovery and Application

The CPP cost recovery methodology is not changing and remains 100 percent pass through under this rate schedule. The formula rate for CPP applies to power supplied by Western to meet a customer's load. The VR customer charge is to recover Western's cost for scheduling VR customer's CPP service.

Proposed Formula Rate for CVP Transmission

Proposed Rate Schedule CV-T3 (Supersedes CV-T2)

Central Valley Project; Schedule of Rate for Firm and Non-Firm Point-to-Point Transmission Service

Effective: October 1, 2011, through September 30, 2016.

Available: Within the marketing area served by SNR.

Applicable: To customers receiving CVP 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 CVP firm and non-firm point-to-point transmission includes three components:

Component 1:

Where:

CVP TRR = Transmission Revenue Requirement (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 Total Transmission Capacity is the total transmission capacity under long-term contract between Western and other parties.

NITSc = The Network Integration Transmission Service Capacity 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 (kWmonth). Rate change notifications will be posted on Western's Open Access Same-Time Information System (OASIS).

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.

Rate Comparison

Under the proposed formula rate, Component 1, the estimated firm and non-firm point-to-point rate effective October 1, 2011, is $1.32 per kWmonth. This is a 22-percent increase from the October 1, 2010, CVP firm and non-firm point-to-point rate of $1.08 per kWmonth. The rate increase is due to the anticipated completion of assets supporting the transmission function not a rate methodology change.

Rate Recovery and Application

The 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) costs include O&M costs, cost of capital or interest expense, depreciation expense, and other miscellaneous costs; (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 body's 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 formula rate applies to CVP firm point-to-point transmission service, existing CVP firm pre-Open Access Transmission Tariff (OATT) transmission service, and CVP non-firm transmission service. 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.

Proposed Rate Schedule CV-NWT5 (Supersedes Schedule CV-NWT4)

Proposed Formula Rate for CVP NITS

Effective: October 1, 2011, through September 30, 2016.

Available: Within the marketing area served by SNR.

Applicable: To customers receiving CVP 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 RR is the result of the CVP TRR less the CVP firm point-to-point TRR. Each NITS customer's allocation is based on the following formula:

NITS customer's monthly demand charge = NITS customer's load ratio share times one-twelfth (1/12) of the Annual Network TRR.

Where:

NITS customer's load ratio share = The NITS customer's usage, 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.

Annual Network TRR = The total CVP TRR, less revenues from long-term contracts for the CVP transmission between Western and other parties.

The Annual Network TRR will be revised when the rate from Component 1 of the CVP transmission rate under Rates Schedule CV-T3 is revised.

Rate Comparison

Effective October 1, 2011, the estimated monthly NITS RR is $2,237,158. This rate is a 23-percent increase from the October 1, 2010, monthly NITS RR of $1,824,170. The rate increase is due to the anticipated completion of assets supporting the CVP transmission function not a rate methodology change.

The formula rate applies to CVP NITS. The estimated NITS monthly RR, resulting from the formula rate, may change prior to the rates taking effect based on the final CVP TRR. The NITS monthly RR will be finalized by Western on or before October 1, 2011.

Rate Recovery and Application

The 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) costs include O&M cost, cost of capital or interest expense, depreciation expense, and other miscellaneous costs; (4) the cost for transmission scheduling, system control and dispatch; (5) the pass through of FERC's or other regulatory body's 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 formula rate applies to CVP NITS transmission service. 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.

Proposed Rate Schedule COTP-T3 (Supersedes Schedule COTP-T2)

Formula Rate for COTP Point-to-Point Transmission Service

Effective: October 1, 2011, through September 30, 2016.

Available: Within the marketing area served by SNR.

Applicable: To customers receiving COTP firm and/or non-firm point-to-point transmission service.

Formula Rate: The formula rate for COTP firm and non-firm point-to-point transmission service includes three components:

Component 1:

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.

Western will update the formula rate from Component 1 for COTP firm and non-firm point-to-point transmission service at least 15 days before the start of each COI rating season. Rate change notifications will be posted on the OASIS Web site.

Rate Comparison

A comparison of the estimated rates resulting from Component 1 of the proposed formula rate for COTP firm point-to-point transmission service to the existing COTP firm point-to-point transmission service rates are shown in the table below.

Table—Comparison of Existing Rates to Estimated Rates From the Proposed Formula Rate for COTP Firm and Non-Firm Point-to-Point Transmission Service

Season	Existing rates	Estimated rates from proposed formula rate	Percent increase
Spring	$2.74 $/MWh	$2.80 $/MWh	1.02
Summer	$2.73 $/MWh	$2.79 $/MWh	1.02
Winter	$2.77 $/MWh	$2.83 $/MWh	1.02

The estimated firm point-to-point COTP transmission service rate increased primarily due to an inflationary increase of costs not a rate methodology change.

Rate Recovery and Application

The proposed formula rate for COTP firm and non-firm point-to-point 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) the cost of scheduling system control and dispatch service associated with COTP transmission; (4) the pass through of FERC's or other regulatory body's 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 proposed firm and non-firm formula rate includes Western's cost for transmission scheduling, and system control and dispatch service associated with COTP transmission. The proposed formula rate applies to COTP point-to-point transmission service. The rates resulting from Component 1 of the proposed formula rate may be discounted for short-term sales and revenue from COTP unreserved use penalties.

The estimated rates resulting from the proposed formula rate are subject to change prior to the rates taking effect. The rates resulting from the proposed formula rate for the winter season will be finalized by Western on or before October 15, 2011.

Proposed Rate Schedule PACI-T3 (Supersedes Schedule PACI-T2)

Proposed Formula Rate for PACI Point-to-Point Transmission Service

Effective: October 1, 2011, through September 30, 2016.

Available: Within the marketing area served by SNR.

Applicable: To customers receiving PACI firm and/or non-firm point-to-point transmission service.

Formula Rate: The proposed formula rate for PACI firm and non-firm transmission includes three components:

Component 1:

Where:

PACI TRR = PACI Seasonal TRR includes Western's costs associated with facilities that support the transfer capability of the PACI.

Western's PACI Seasonal Capacity = Western's share of PACI capacity (subject to curtailment) under the current COI transfer capability for the season. The three seasons are defined as follows: Summer—June through October; Winter—November through March; and Spring—April through May.

Western will update the formula rate resulting from Component 1 at least 15 days before the start of each COI rating season. Rate change notifications will be posted on the OASIS.

The proposed formula rate for PACI non-firm transmission includes the same three components used in the proposed formula rate for PACI firm transmission.

Rate Comparison

The estimated firm and non-firm point-to-point rates resulting from Component 1 of the proposed formula rate for PACI transmission service are shown in the example below.

Example—Comparison of Existing Rates to Estimated Rates of the Proposed Formula Rate for PACI Firm and Non-Firm Point-To-Point Transmission Service

Season	Existing firm rate	Estimated firm rate	Rate change (percent)
Spring	$1.14 ($/MWh)	$1.16 ($/MWh)	1.02
Summer	$1.13 ($/MWh)	$1.16 ($/MWh)	1.02
Winter	$1.15 ($/MWh)	$1.17 ($/MWh)	1.02

The estimated firm, point-to-point PACI transmission service rate increased slightly due to an inflationary increase of costs not a rate methodology change.

Rate Recovery and Application

The proposed 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) the pass through of FERC's or other regulatory body's accepted or approved charges or credits; (4) the pass through of the HBA's charges or credits; (5) any other statutorily-required costs or charges; and (6) any other costs associated with transmission service including uncollectible debt.

The proposed formula rate includes Western's cost for transmission scheduling, system control and dispatch service. The proposed formula rate applies to PACI firm and non-firm point-to-point transmission service. The rates resulting from Component 1 of the proposed formula rate may be discounted for short-term sales and revenue from PACI unreserved use penalties. The estimated rates resulting from the proposed formula rate are subject to change prior to the rates taking effect. The rates resulting from the proposed formula rate for the winter season will be finalized by Western on or before October 15, 2011.

Proposed Rate Schedule CV-TPT7 (Supersedes CV-TPT6)

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 SNR.

Applicable: To Western's power service customers who require transmission service by a third party to receive power sold by Western.

Formula Rate: The proposed 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.

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 shall be the responsibility of the customer that received the power.

Rate Comparison

Effective October 1, 2011, the cost of this service is not changing from the existing methodology and all costs are pass through under this rate schedule.

Rate Recovery and Application

These costs are fully recovered from the beneficiaries receiving this service, and this is not changing from the existing rate methodology.

Proposed Rate Schedule CV-UUP1 (New Rate Schedule)

Schedule of Rate for Unreserved Use Penalties

Effective: October 1, 2011, through September 30, 2016.

Available: Within the marketing area served by SNR.

Applicable: To transmission customers using transmission not reserved or in excess of reservation.

Summary

Western proposes to add a penalty rate for unreserved use of transmission for the CVP, COTP, and PACI in a new rate schedule, Rate Schedule CV-UUP1.

Penalty Rate

The rate for Unreserved Use Penalties service is 150 percent of the approved transmission service rate for point-to-point transmission service assessed as described above, plus 100 percent of the approved ancillary service rates if applicable.

Component 1: Unreserved Use Penalties service is provided when a transmission customer uses transmission service that it has not reserved or uses transmission service in excess of its reserved capacity. A transmission customer that has not secured reserved capacity or exceeds its firm or non-firm reserved capacity at any point of receipt or any point of delivery will be assessed Unreserved Use Penalties.

The penalty charge for a transmission customer who engages in unreserved use is 150 percent of Western's approved transmission service rate for point-to-point transmission service assessed as follows: (1) The Unreserved Use Penalty for a single hour of unreserved use will be based upon the rate for daily firm point-to-point service; (2) the Unreserved Use Penalty for more than one assessment for a given duration (e.g., daily) will increase to the next longest duration (e.g., weekly); and (3) the Unreserved Use Penalty for multiple instances of unreserved use (e.g., more than 1 hour) within a day will be based on the rate for daily firm point-to-point service. The penalty charge for multiple instances of unreserved use isolated to 1 calendar week would result in a penalty based on the charge for weekly firm point-to-point service. The penalty charge for multiple instances of unreserved use during more than 1 week within a calendar month is based on the charge for monthly firm point-to-point service.

Unreserved Use Penalties will not apply to transmission customers utilizing point-to-point 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 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 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.

Unreserved Use Penalties collected over and above the base firm or non-firm point-to-point charge will be distributed to customers as a credit on future TRRs.

Rate Comparison

This is a new rate schedule effective October 1, 2011, through September 30, 2016.

Rate Recovery and Applicability

The 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 TRRs. The penalty rate is applicable for all unreserved use of transmission and transmission in excess of reservation except, as may be determined by Western, in emergencies or reserve sharing activations. Western will provide written notification 30 days in advance to its transmission customers prior to implementing this penalty rate and will also post a notification on its OASIS Web site indicating the implementation of Unreserved Use Penalties.

Proposed Rates for Ancillary Services

This section includes proposed rates for the following 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.

Proposed Rate Schedule CV-SPR4 (Supersedes Schedule CV-SPR3)

Proposed Formula Rate for Spinning Reserve Service

Effective: October 1, 2011, through September 30, 2016.

Available: Within the marketing area served by SNR.

Applicable: To customers receiving spinning reserve service.

Character and Conditions of Service: Spinning reserve service supplies capacity that is available immediately to take 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 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 to Western and do not fulfill that obligation, the penalty for non-performance is the greater of actual cost or 150 percent of the market price.

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 treatment for repayment and cash flow management.

Rate Comparison

Western is not proposing a change to the existing formula rate methodology for spinning reserve service.

Rate Recovery and Application

The spinning reserve charge is calculated for each hour during the month in order to derive the total monthly charge. The proposed formula rate for spinning reserve service is as follows: (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 body's 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 to Western and do not fulfill that obligation, the penalty for non-performance is the greater of actual cost or 150 percent of the market price.

The cost for spinning reserve required to firm CVP generation for the current hour and the following hour is included in the PRR. Spinning reserves surplus to those required to support the SBA and firm CVP generation may be sold. Surplus spinning reserves will be sold at prices consistent with the CAISO markets. 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.

Proposed Rate Schedule CV-SUR4 (Supersedes Schedule CV-SUR3)

Proposed Formula Rate for Supplemental Reserve Service

Effective: October 1, 2011, through September 30, 2016.

Available: Within the marketing area served by SNR.

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 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 actual cost or 150 percent of the market price.

Billing: The formula rate above will be applied to the amount of supplemental reserve service sold. Billing will occur monthly.

Rate Comparison

Western is not proposing a change to the existing formula rate methodology for supplemental reserve service.

Rate Recovery and Application

The formula rate for supplemental reserve service is as follows: (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 body's 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 actual cost of generation or 150 percent of the 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. Supplemental reserve service surplus to those required to support the SBA and firm CVP generation may be sold. Surplus supplemental reserves will be sold at prices consistent with the CAISO markets. Revenues from the sale of supplemental reserves will offset the PRR. The supplemental reserve formula rate will apply to SBA customers who contract with Western to provide this service.

Proposed Rate Schedule CV-RFS4 (Supersedes Schedule CV-RFS3)

Proposed Formula Rate for Regulation and Frequency Response Service

Effective: October 1, 2011, through September 30, 2016.

Available: Within the marketing area served by SNR.

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 proposed formula rate for Regulation includes three components:

Component 1:

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 nonperformance by an SBA customer who has committed to self-provision for their regulating capacity requirement will be the greater of 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 kWmonth.

Rate Comparison

Western is not proposing a change to the existing formula rate methodology. The Regulation rate effective October 1, 2010, is $4.65 per kWmonth. Based on the existing threshold for a rate change of $0.25, we do not expect the rate to change effective October 1, 2011.

Rate Recovery and Application

The annual RR includes: (1) The CVP generation costs associated with providing Regulation; and (2) the non-facility costs allocated to Regulation.

The Regulation RR will be recovered from SBA customers that have contracted with Western for this service. The revenues from Regulation service will be applied to the PRR. The estimated RR resulting from the proposed formula rate is subject to change prior to the rates taking effect. The RR will be finalized by Western on or before October 1, 2011.

Proposed Rate Schedule CV-EID4 (Supersedes Schedule CV-EID3)

Proposed Formula Rate for Energy Imbalance Service

Effective: October 1, 2011, through September 30, 2016.

Available: Within the marketing area served by SNR.

Applicable: To customers receiving 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 SBA over an hour or in accordance with approved policies and procedures. The deviation, in MW, 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 (IOA).

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; 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 actual cost; and (3) positive deviations (over delivery), outside the deviation bandwidth, will be lost to the system.

Deviations which 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.

Billing: Billing for negative deviations outside the bandwidth will occur monthly.

Rate Comparison

Western is not proposing a change to the existing formula rate methodology. Any changes to EI charges result from changes to actual cost or market prices.

Rate Recovery and Application

Western is proposing to maintain its existing tier methodology for EI. While FERC Order No. 890 defines a three-tier methodology, it allows alternatives to pro forma design if the rate schedule follows the intent of the three principles: (1) Charges based on incremental cost or some multiple thereof; (2) charges must provide incentive for accurate scheduling; and (3) provisions address intermittent renewable resources (wind/solar) limited forecasting abilities by waiver of the most punitive penalties.

Western's existing EI rate schedule follows the intent by: (1) Charges under a tiered methodology where, 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 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 proposes eliminating the 150 percent of market price factor for under deliveries. Western will charge the greater of market price or Western's actual cost.

Given that Western's customers will be operating under existing agreements during the applicable rate period, Western will review FERC Order No. 890 pro forma approach, as well as Western's existing settlements and billing processes and will consider a transition to FERC's pro forma tariff 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 market price or 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 body's 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. The revenues from EI service will be applied to the PRR. 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.

Energy Imbalance 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	12 MW
Contractual Bandwidth	8 MW
Energy Imbalance 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 multiplied by 150 percent and Western's actual cost for that same hour. The higher of the two is applied to derive the EI charge. EI 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	Actual < 150% of Market	N/A	N/A
Real Time CAISO price ($21.84 * 150%) applied per rate schedule	32.76	150% Market > Actual	4	$131.04
Note: EI charge for October 1, HE 1, is calculated as follows: 4 MW * $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.

To the extent that an entity incorporates variable resources, treatment of such will be determined in the associated contract.

Proposed Rate Schedule CV-GID1 (New Rate Schedule)

Schedule of Rate for Generator Imbalance Service

Effective: October 1, 2011, through September 30, 2016.

Available: Within the marketing area served by SNR.

Applicable: To generators receiving 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 SBA, over an hour, or in accordance with approved policies and procedures. The deviation in MW 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 to be established in the service agreement or IOA.

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; 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 actual cost; and (3) positive deviations (over delivery), outside the deviation bandwidth, will be lost to the system.

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; 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; and (3) positive deviations (over delivery), outside the deviation bandwidth, will be lost to the system.

Billing: Billing for negative deviations outside the bandwidth will occur monthly.

Rate Comparison

This is a new rate schedule effective October 1, 2011, through September 30, 2016.

Rate Recovery and Application

Western is proposing to adopt its existing EI methodology for GI. Similar to EI, FERC Order No. 890 defines a three-tier methodology for GI. The order allows alternatives to pro forma design if the rate schedule follows the intent of the three principles: (1) Charges based on incremental cost or some multiple thereof; (2) charges must provide incentive for good scheduling practice; and (3) provisions address intermittent renewable resources (wind/solar) to waive punitive penalties.

Similar to Western's existing EI rate schedule, GI will follow the intent by: (1) Charges under a tiered methodology; where, 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 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 proposes eliminating the 150 percent of market price factor for under deliveries. Western will charge the greater of market price or Western's actual cost.

Currently, Western has no existing customers under GI. Western will review FERC Order No. 890 pro forma approach, as well as Western's existing settlements and billing processes and will consider a transition to FERC's pro forma tariff 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 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 body's accepted or approved charges or credits, and any other statutorily required costs or charges.

The GI charge will be recovered from SBA customers that have contracted with Western for this service. The revenues from GI will be applied to the PRR. 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.

Generation Imbalance 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 Generation (under delivery)	12 MW
Contractual Bandwidth	8 MW
Generator Imbalance 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 multiplied by 150 percent and Western's actual cost for that same hour. The greater 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	Actual < 150% of Market	N/A	N/A
Real Time CAISO price ($21.84 * 150%) applied per rate schedule	32.76	150% Market > Actual	4	$131.04
Note: GI charge for October 1, HE 1 is calculated as follows: 4 MW * $32.76 = $131.04

GI charges will not apply as a result of action taken to support reliability. Such actions include reserve activations or uncontrolled event response as directed by the responsible reliability authority, such as, SBA, HBA, Reliability Coordinator, or Transmission Operator.

To the extent that an entity incorporates VRs, treatment of such will be determined in the associated contract.

GI and EI service charges/energy accounting will be netted within the hour, or in accordance with approved policies and procedures, with charges for both services allowable only when the imbalances for both are deficit rather than offsetting (note that this only applies to netting within the bandwidth).

Potential Example of an Addition Presented above:

Transmission Provider or SBA can charge customer for both GI and EI service in the same hour, but not if the imbalances offset each other.

Example of Offsetting:

For example—Customer A

⟩⟩ GI:-10MW deficit

⟩⟩ EI service: 5MW surplus

⟩⟩ Customer A charged: 5MW (GI charge)

Example of Aggravating (increasing—absolute value)

For example—Customer B

⟩⟩ GI Service:-10MW deficit

⟩⟩ EI service:-10MW deficit

⟩⟩ Customer A charged:-10MW for GI charge plus -10MW for EI charge

Legal Authority

These proposed rates for COTP, PACI, CVP transmission, Western power, and related services are being established pursuant to the DOE Organization Act (42 U.S.C. 7101-7352); the Reclamation Act of 1902 (ch. 1093, 32 Stat. 388), as amended and supplemented by subsequent enactments, particularly section 9(c) of the Reclamation Project Act of 1939 (43 U.S.C. 485(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 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 (50 FR 37835).

Availability of Information

All brochures, studies, comments, letters, memorandums, or other documents made or kept by Western for developing the proposed rates are available for inspection and copying at the Sierra Nevada Regional Office, located at 114 Parkshore Drive, Folsom, California.

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.

Dated: December 22, 2010.

Timothy J. Meeks,

Administrator.

[FR Doc. 2010-33108 Filed 12-30-10; 8:45 am]

BILLING CODE 6450-01-P