Western Area Power Administration, DOE.
Notice of Proposed Transmission and Ancillary Services Formula Rates.
The Western Area Power Administration (Western) is proposing to update its Loveland Area Projects (LAP) Transmission and Western Area Colorado Missouri (WACM) Balancing Authority Ancillary Services formula rates. Current formula rates, under Rate Schedules L-FPT1, L-NFPT1, L-NT1, L-AS1, L-AS2, L-AS3, L-AS4, L-AS5, L-AS6 and L-AS7, have been extended and will expire on February 28, 2013. Pursuant to Western's revised Open Access Transmission Tariff (OATT), which was effective December 1, 2009, Western is also proposing new formula rates for Generator Imbalance Service and Unreserved Use Penalties. Western has prepared a brochure that provides detailed information on the proposed formula rates to all interested parties. If adopted, the proposed formula rates, under Rate Schedules L-FPT1, L-NFPT1, L-NT1, L-AS1, L-AS2, L-AS3, L-AS4, L-AS5, L-AS6, L-AS7, L-AS9 and L-AS10, would be in effect from October 1, 2011, through September 30, 2016, or until superseded. Publication of this Federal Register notice begins the formal process for consideration of the proposed formula rates.
The consultation and comment period begins today and will end April 28, 2011. Western will present a detailed explanation of the proposed formula rates at a public information forum that will be held on March 9, 2011, at 9 a.m. MST. Western will accept oral and written comments at a public comment forum that will be held on March 9, 2011, from 1 p.m. to no later than 2:30 p.m. MST. Western will accept written comments any time during the consultation and comment period.
The location for both the public information forum and the public comment forum is the Budweiser Events Center, 5290 Arena Circle, Loveland, Colorado. Send written comments to Mr. Bradley S. Warren, Regional Manager, Rocky Mountain Region, Western Area Power Administration, 5555 East Crossroads Boulevard, Loveland, CO 80538-8986, e-mail LAPTransAdj@wapa.gov. Western will post information about the rate process, as well as comments received via letter and e-mail, on its Web site at http://www.wapa.gov/rm/ratesRM/2012/default.htm. Written comments must be received by the end of the consultation and comment period to be considered by Western in its decision process.Start Further Info
FOR FURTHER INFORMATION CONTACT:
Mrs. Sheila D. Cook, Rates Manager, Rocky Mountain Region, Western Area Power Administration, 5555 East Crossroads Boulevard, Loveland, CO 80538-8986, telephone (970) 461-7211, e-mail firstname.lastname@example.org.End Further Info End Preamble Start Supplemental Information
The existing formula-based rates approved under Rate Order WAPA-106  became effective on March 1, 2004, with an expiration date of February 28, 2009. The rate schedules, with the exception of Rate Schedule L-AS3, Regulation and Frequency Response, were extended through February 28, 2011, under Rate Order No. WAPA-141. Rate Schedule L-AS3 was revised and approved under Rate Order No. WAPA-118, which became effective June 1, 2006, with an expiration date of May 31, 2011. All Transmission and Ancillary Services rate schedules, including the Regulation and Frequency Response Service schedule, were extended through February 28, 2013, under Rate Order No. Start Printed Page 5149WAPA-154. The current rate schedules contain formula-based rates that are recalculated annually using updated financial and load information. The proposed rates continue this approach. If adopted, these proposed formula-based rates would be in effect October 1, 2011, through September 30, 2016. This Federal Register notice describes each service and contains a Rate Comparison Table for quick reference.
Proposed Formula Rate for Network Transmission Service
The proposed formula for calculating the Network Transmission Service rate, Rate Schedule L-NT1 is unchanged from the current formula:
Monthly Charge = 1/12 × Annual Transmission Revenue Requirement × Customer Load Ratio Share
The load ratio share is based on the 12-month average of the network customer's hourly load coincident with the LAP monthly transmission system peak. See discussion below on the calculation of the Annual Transmission Revenue Requirement (ATRR).
Proposed Formula Rate for Firm Point-to-Point Transmission Service
Western proposes no change in the rate formula for Firm Point-to-Point Transmission Service, Rate Schedule L-FPT1. The monthly rate is 1/12 of the ATRR divided by the 12-month average of the system peak load of the LAP transmission system.
Proposed Formula Rate for Non-Firm Point-to-Point Transmission Service
Western proposes no change in the rate formula for Non-Firm Point-to-Point Transmission Service, Rate Schedule L-NFPT1. The proposed monthly Non-Firm Point-to-Point Transmission Service rate formula is the same as the monthly Firm Point-to-Point Transmission Service rate. Non-Firm Point-to-Point Transmission Service is available for periods ranging from 1 hour to 1 month.
Proposed Annual Transmission Revenue Requirement
The proposed ATRR would be applicable to both Network and Point-to-Point Transmission Service. The formula for calculating the ATRR would be unchanged from the current formula:
The Annual Transmission Cost is the ratio of Net Investment Cost for Transmission Facilities to Net Investment Cost for All Facilities multiplied by the Total Annual Costs for All Facilities. Total Annual Costs include operations and maintenance, interest and depreciation expenses. The calculation is:
This represents a change in how the inputs for the rate are developed. Currently, the Annual Transmission Cost is derived by multiplying the Net Investment Cost for Transmission Facilities by a fixed charge rate.
The Net Investment Cost for Transmission Facilities would be determined by an analysis of the LAP Transmission System. Each LAP facility is classified by function: transmission, sub-transmission, distribution, or generation-related. The facilities identified as performing the function of transmission include all transmission lines that are normally operated in a continuously-looped manner and the associated substations and switchyard facilities. In the LAP Transmission System, these are primarily the 115-kV and the 230-kV transmission lines. In addition, a portion of the communication and maintenance facilities is included in the investment costs for transmission. Only the investment costs of the facilities identified as “transmission”, including allocated costs for communication and maintenance facilities, are used in developing the Annual Transmission Cost. The investment costs of facilities identified as “sub-transmission” and “distribution” are excluded from the ATRR, as the LAP sub-transmission and distribution systems are used primarily for delivery of Federal power to Federal customers. If a transmission customer requires the use of the sub-transmission or distribution systems, an additional facility-use charge will be assessed. All costs of the Fryingpan-Arkansas Project are considered generation-related and, therefore, are excluded from the ATRR.
The transmission expenses which increase transmission system capacity would continue to include payments made to others for their systems' augmentation of the LAP Transmission System. Miscellaneous Revenue Credits and Revenue Credits for Existing Contracts would include, but not be limited to, non-firm, discounted firm, and short- and long-term firm transmission sales; Scheduling, System Control, and Dispatch (SSCD) Service; Unreserved Use Penalties; and facility charges for transmission facility investments included in the revenue requirement.
Proposed Change to Forward-Looking Transmission Rates
Western proposes to change the method it uses to calculate the ATRR to recover transmission expenses and investments on a current basis rather than a historical basis. The change Western proposes would allow it to more accurately match cost recovery with cost incurrence. Western would use projections to estimate transmission costs and load for the upcoming year in the annual rate calculation. Currently, the rate calculation for a year uses actual data from 2 years prior to that year. The proposed method would be a change in the manner in which the inputs for the rate are developed, rather Start Printed Page 5150than a change to the formula rate itself. When actual cost information for a year becomes available, Western would calculate the actual revenue requirement. Revenue collected in excess of Western's actual revenue requirement would be included as a credit in the ATRR in a subsequent year. Similarly, any under-collection of the revenue requirement would be recovered in a subsequent year. This true-up procedure would ensure that Western recovers no more and no less than the actual transmission costs for the year. For example, as FY 2012 actual financial data becomes available during FY 2013, the under- or over-collection of revenue during FY 2012 can be determined. When the rates are recalculated for FY 2014, the implemented rates would include an adjustment for revenue under- or over-collected in FY 2012.
Proposed Penalty Rate for Unreserved Use of Transmission Service
Unreserved Use of Transmission Service (Unreserved Use) under the proposed Rate Schedule L-AS10 is provided when a transmission customer uses transmission service it has not reserved or that exceeds its reserved capacity. Western proposes to assess Unreserved Use Penalties against a transmission customer that has not secured reserved capacity or exceeds its reserved capacity at any point of receipt or any point of delivery.
Western proposes that a transmission customer that engages in Unreserved Use be assessed a penalty charge of 200 percent of Western's approved transmission service rate for Point-to-Point Transmission Service as follows:
(i) The Unreserved Use Penalty for a single hour of Unreserved Use would be based upon the rate for daily Firm Point-to-Point Service.
(ii) The Unreserved Use Penalty for more than one assessment for a given duration (e.g., daily) would increase to the next longest duration (e.g., weekly).
(iii) The Unreserved Use Penalty charge for multiple instances of Unreserved Use (e.g., more than one hour) within a day would be based on the rate for daily Firm Point-to-Point Service. Multiple instances of Unreserved Use isolated to one 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 one week during a calendar month would be based on the charge for monthly Firm Point-to-Point Service.
A transmission customer that exceeds its firm reserved capacity at any point of receipt or point of delivery, or an eligible customer that uses transmission service at a point of receipt or point of delivery that it has not reserved, would be required to pay for all ancillary services identified in Western's OATT based on the amount of transmission service it used and did not reserve.
Unreserved Use Penalties collected over and above the base Point-to-Point Transmission Service charge would be credited against the LAP ATRR in a subsequent year.
Proposed Rate Schedule for Transmission Losses Service
The proposed rate schedule for Transmission Losses Service, Rate Schedule L-AS7, is unchanged, except that losses settled financially would use WACM pricing rather than LAP pricing. The loss rate is updated periodically and posted on the Rocky Mountain Region (RMR) Open Access Same Time Information System Web site. Transmission Losses are assessed for all real-time and prescheduled transactions on transmission facilities managed by RMR or inside the WACM Balancing Authority. Transmission Customers are allowed the option of financial settlement or energy repayment. Energy repayment is either concurrently or 7 days later. Financial settlement is based on WACM pricing.
Proposed Formula Rate for Scheduling, System Control and Dispatch Service
The proposed formula for SSCD Service, Rate Schedule L-AS1, would be as follows:
This formula represents a change from the prior formula. In the past, RMR included some salaries, facility costs, and information technology support costs for the Automatic Generation Control, Switching, Transmission Planning and Operations Management groups in the formula, viewing the rate as encompassing all of system control and dispatch. Under the proposed formula, the Annual Cost of Scheduling Personnel and Related Costs would capture costs primarily for scheduling but would exclude costs for system control and dispatch. Those costs would be captured in other rates. The change in the formula reflects the philosophy that this rate should recover only the costs of providing scheduling/tagging service. The denominator would continue to be the yearly total of daily tags which result in a schedule. However, Schedules for delivery of Transmission Losses would no longer be included in the calculation of the rate, nor would they be invoiced. This would allow customers to submit an unlimited number of loss tags, which permits the Balancing Authority to relate the loss tags to their specific scheduled transactions, without the customers being charged for these separate tags.
Western is also proposing a change in the implementation of this rate. As SSCD Service is one that transmission providers must obtain from the Balancing Authority, Western would allocate the cost of each schedule equally among all transmission providers listed on the tag that are inside the WACM Balancing Authority. Western would charge all non-Federal transmission providers for their allocated costs. Any Federal transmission segment would be exempt from billing, as costs for these segments would be included in the LAP Transmission Service. Currently, the last transmission provider inside the WACM Balancing Authority is charged for the entire cost of the tag unless one of the transmission segments is Federal transmission. In that case, no charge is assessed.
Proposed Formula Rate for Reactive Supply and Voltage Control From Generation or Other Sources Service (VAR Support)
The proposed formula for calculating the revenue requirement for VAR service, Rate Schedule L-AS2, is unchanged from Western's current formula:Start Printed Page 5151
TARRG = Total Annual Revenue Requirement for Generation
% of Resource = Percentage of Resource Capacity Used for VAR Support
The numerator captures the percentage of annual generation plant costs which are used for this service. Net generation plant costs are multiplied by a fixed charge rate for generation to determine the TARRG. The percentage of TARRG which is included in the revenue requirement would be based on the nameplate capability of the generating units with regard to reactive and real power production. The TARRG would be multiplied by the complement of the weighted average power factor rating for generating units. For example, if the weighted average power factor is 98 percent, the numerator would include 2 percent of the TARRG. This is a change in the process for collecting data inputs to the formula rate. In the current formula rate, the percentage of resource for a unit is calculated by measuring actual production of volt-amperes reactive and dividing by the unit nameplate power capability. The rate is applicable to all transmission transactions inside the WACM Balancing Authority in excess of any Federal entitlement. The charge for transmission of a customer's Federal entitlement would be included in the customers' firm electric service charges. Credit may be given to those customers with generators providing the WACM Balancing Authority with VAR support.
Proposed Formula Rate for Regulation and Frequency Response Service (Regulation Service)
The proposed formula for Regulation Service, Rate Schedule L-AS3, would have 4 components:
(1) Load-based Assessment.
The rate applies to all entities' auxiliary load (total metered load less Federal entitlements) plus the nameplate of intermittent resources serving load inside the WACM Balancing Authority. Restricting this service to intermittent resources serving load inside the WACM Balancing Authority is a change from the current rate. See “Exporting Intermittent Resource Requirement” below. Otherwise, the formula is unchanged.
The revenue requirement will include such costs as plant costs, purchases of a regulation product, purchases of power in support of the units' ability to regulate, purchases of transmission for regulating units that are trapped geographically inside another balancing authority, purchases of transmission required to relocate energy due to regulation/load following issues, and lost sales opportunities resulting from the requirement to generate at night to permit units to have `down' regulating capability.
The methodology for determining annual plant costs is unchanged. First, the annual costs for plants used to regulate is calculated by multiplying the net plant costs by the fixed charge rate for generation. Then, the annual cost per unit of capacity for regulating plants is calculated by dividing the annual plant costs by the capacity of those plants. Next, the portion of the total annual plant costs to be recovered in the Regulation Service Rate is calculated by multiplying the annual unit cost by the amount of capacity required for regulation. The capacity required for regulation is subject to re-evaluation every year.
(2) Exporting Intermittent Resource Requirement. An entity that exports the output from an intermittent resource to another balancing authority will be required to dynamically meter or dynamically schedule that resource out of the WACM Balancing Authority to another balancing authority. An intermittent resource is a generator that is not dispatchable and cannot store its fuel source and, therefore, cannot respond to changes in system demand or to transmission security constraints.
Western supports the installation of renewable sources of energy but recognizes that certain operational constraints exist in managing the significant fluctuations that are a normal part of their operation. Western has marketed the maximum practical amount of power from its projects, leaving little flexibility for additional balancing authority services. Consequently, Western will not regulate for the difference between the output of an intermittent generator located inside the WACM Balancing Authority and a delivery schedule from that generator serving load located outside the WACM Balancing Authority.
(3) Self-Provision Using Automatic Generation Control (AGC). Western allows entities with automatic or manual generation control to self-provide for all or a portion of their loads. Entities with generation control are known as Sub-Balancing Authorities (SBA) and must meet all of the following criteria: A well-defined boundary, with revenue-quality metering that is approved by the WACM Balancing Authority, accurate as defined by NERC, and which includes megawatt (MW) flow data availability at 6-second or smaller intervals; AGC capability; and Demonstrated Regulation Service capability.
Self-provision would be measured by use of the entity's 1-minute average Area Control Error (ACE) to determine the amount of Self-provision. The assessment would be calculated every hour and the value of ACE would be used to calculate Regulation Service charges as follows:
a. If the entity's 1-minute average ACE is ≤ than 0.5 percent of the entity's hourly average load, no Regulation Service charges would be assessed by the WACM Balancing Authority.
b. If the entity's 1-minute average ACE is > 1.5 percent of the entity's hourly average load, the WACM Balancing Authority would assess Regulation Service charges to the entity's entire load, using the Load-based Regulation Service rate.Start Printed Page 5152
c. If the entity's 1-minute average ACE is > 0.5 percent of the entity's hourly average load, but < 1.5 percent of the entity's hourly average load, the WACM Balancing Authority would assess Regulation Service charges based on linear interpolation of zero charge and full charge, using the Load-based Regulation Service rate.
This represents a change from the current formula. Under the current formula rate, the customer has the option of measuring Self-provision by use of either the 1-minute average of its ACE or the 1-minute average of the first derivative of its ACE.
Western will monitor the entity's Self-provision on a regular basis. If Western determines that the entity has not been attempting to self-regulate, Western will, upon notification, employ the Load-based Assessment described in (1) above.
(4) Other Self- or Third-party Supply. Western may allow an entity to supply some or all of its required regulation or contract with a third party to do so, even without well-defined boundary metering. The WACM Balancing Authority will evaluate the entity's metering, telecommunications and regulating resource, as well as the required level of regulation, and determine whether the entity qualifies to Self-supply under this provision. This is a new provision under the proposed formula rate.
Proposed Formula Rate for Energy Imbalance Service
Western proposes to revise its formula rate for Energy Imbalance Service, Rate Schedule L-AS4, to be more consistent with Federal Energy Regulatory Commission (FERC) guidelines. Currently, Western calculates imbalances in two deviation bands and assesses a 25 percent penalty for hourly deviations in excess of 5 percent of metered load. Western proposes to implement a penalty and bandwidth structure with 3 deviation bands as follows:
(1) Imbalances of less than or equal to 1.5 percent of metered load (or 4 MW, whichever is greater) would be settled financially at 100 percent of the WACM Balancing Authority pricing for that hour. Each hour will stand on its own—there will be no monthly netting. There is no change in the use of pricing. If the WACM Balancing Authority aggregate imbalance is a net over-delivery, sales pricing will be used; if the aggregate imbalance is a net under-delivery, purchase pricing will be used.
(2) Imbalances between 1.5 percent and 7.5 percent of metered load (or 4 to 10 MW, whichever is greater) would be settled financially at 90 percent of the WACM Balancing Authority hourly sales price for over-scheduling imbalances or 110 percent of the WACM Balancing Authority hourly purchase price for under-scheduling imbalances.
(3) Imbalances greater than 7.5 percent of metered load (or 10 MW, whichever is greater) would be settled financially at 75 percent of the WACM Balancing Authority hourly sales price for over-scheduling imbalances or 125 percent of the WACM Balancing Authority hourly purchase price for under-scheduling imbalances.
Western is proposing to assess an administrative charge on each monthly settlement under this service. Western would establish a pool of costs to be recovered to include, but not be limited to, salaries for personnel administering this service. Western would then calculate the ratio of this amount to the absolute value of all Energy Imbalance Service settlements for the most current year for which data is available. This percentage will be applied to the amount of each monthly settlement, reducing payments and increasing charges to the customer.
Proposed Formula Rate for Generator Imbalance Service
Western is proposing a new Generator Imbalance Service Formula Rate, Rate Schedule L-AS9, pursuant to FERC guidelines. This service would be provided to the following customers:
(1) Multi-party generators whose output is shared by several entities. If the operator of the generator prefers, the generator's output will be allocated among the unit participants and included in the Energy Imbalance Service calculations for those participants.
(2) Intermittent resources serving load inside the WACM Balancing Authority.
An entity's solely-owned non-intermittent resource inside the WACM Balancing Authority would be included in the entity's Energy Imbalance Service calculation.
Western has marketed the maximum amount of capacity from its projects, leaving little flexibility for additional WACM Balancing Authority services. Consequently, Western will not regulate for the difference between the output of an intermittent generator located within the WACM Balancing Authority and a delivery schedule from that generator serving load located outside the WACM Balancing Authority. Intermittent generators serving load outside the WACM Balancing Authority would be required to dynamically meter or dynamically schedule their generation to another balancing authority. An intermittent resource is a generator that is not dispatchable and cannot store its fuel source and, therefore, cannot respond to changes in system demand or to transmission security constraints (see discussion on the proposed formula rate for Regulation Service).
The formula rate for Generator Imbalance Service would be identical to that for Energy Imbalance Service, with the following exceptions:
(1) Bandwidths would be calculated as a percentage of metered generation, since there is no load.
(2) Intermittent resources would be exempt from the outer bandwidth. All deviations greater than 1.5 percent of metered generation will be subject only to a 10 percent penalty.
In any hour, Western may charge a customer a penalty for either Generator Imbalance Service under Rate Schedule L-AS9 or Energy Imbalance Service under Rate Schedule L-AS4, but not both, unless the imbalances aggravate rather than offset each other.
Generator Imbalance Service calculations would be included with Energy Imbalance Service calculations in the allocation of a single pool of administrative costs.
Proposed Rate Schedules for Operating Reserves Service—Spinning and Supplemental
The proposed rate schedules for Spinning and Supplemental Reserves, Rate Schedules L-AS5 and L-AS6 are unchanged. The WACM Balancing Authority has no reserves available for sale. However, at a customer's request, the WACM Balancing Authority will purchase reserves and, if necessary, activation energy and pass the cost, plus a fee for administration, through to the customer. For all reserves purchased, the customer will be responsible for purchasing adequate transmission to support the purchase.
Following is a table which compares the proposed formula rates for FY 2012 with the current formula rates for FY 2011:Start Printed Page 5153
|Class of service||Proposed Rate Schedule and estimated rate effective October 1, 2011 1 (FY 2012)||Existing Rate Schedule and rate effective October 1, 2010 (FY 2011)|
|Network Transmission Service||L-NT1 Load ratio share of 1/12 of the revenue requirement of $56,146,133||L-NT1. Load ratio share of 1/12 of the revenue requirement of $48,000,660.|
|Firm Point-to-Point Transmission Service||L-FPT1 $3.45/kW-month||L-FPT1. $3.18/kW-month Unauthorized Use Penalty of 150% of demand charge, with a maximum of monthly service.|
|Non-Firm Point-to-Point Transmission Service||L-NFPT1 Maximum of 4.73 mills/kWh||L-NFPT1. Maximum of 4.17 mills/kWh Unauthorized Use Penalty of 150% of demand charge, with a maximum of monthly service.|
|Scheduling, System Control, and Dispatch Service||L-AS1 $24.03 per schedule per day for non-transmission customers.||L-AS1. $38.30 per tag per day for non- transmission customers.|
|Reactive Supply and Voltage Control from Generation or Other Sources Service||L-AS2 $0.318/kW-month||L-AS2. $0.180/kW-month.|
|Regulation and Frequency Response Service||L-AS3 $0.322/kW-month||L-AS3. $0.339/kW-month.|
|Energy Imbalance Service||L-AS4 —Imbalances less than or equal to 1.5% (minimum 4 MW) of metered load settled using WACM hourly pricing with no penalty. —Imbalances 1.5% to 7.5% (minimum 4 MW to 10 MW) of metered load settled using WACM hourly pricing with a 10% penalty. —Imbalances greater than 7.5% (minimum 10 MW) of metered load settled using WACM hourly pricing with a 25% penalty. —Administrative fee charged on every settlement.||L-AS4. —Imbalances less than or equal to 5% (minimum 4 MW) of metered load settled using WACM pricing with no penalty. —Imbalances greater than 5% of metered load settled using WACM pricing with a 10% penalty.|
|Operating Reserves Service—Spinning and Supplemental||L-AS5, L-AS6 Long-term reserves are not available from WACM. Reserves may be provided on a pass-though cost, plus an amount for administration.||L-AS5, L-AS6. Long-term reserves are not available from WACM. Reserves may be provided on a pass-though cost, plus an amount for administration.|
|Transmission Losses Service||L-AS7 Transmission losses may be settled either financially or with energy. Insufficient losses supplied will be settled financially by default All customers will have the option to return the loss obligation for both prescheduled and real-time transactions 7 days later, same profile Pricing used is WACM weighted average hourly purchase price.||L-AS7 Transmission losses may be settled either financially or with energy. Insufficient losses supplied will be settled financially by default. All customers will have the option to return the loss obligation for both prescheduled and real-time transactions 7 days later, same profile. Pricing used is LAP weighted average hourly purchase price.|
|Generator Imbalance Service||L-AS9 —Imbalances less than or equal to 1.5% (minimum 4 MW) of metered generation settled using WACM hourly pricing with no penalty. —Imbalances 1.5% to 7.5% (minimum 4 MW to 10 MW) of metered generation settled using WACM hourly pricing with a 10% penalty. —Imbalances greater than 7.5% (minimum 10 MW) of metered generation settled using WACM hourly pricing with a 25% penalty. —Intermittent Resources not subject to 3rd band penalties. —Administrative fee charged on every settlement.||Provided Under Rate Schedule L-AS4.|
|Penalty Rate for Unreserved Use of Transmission Service||L-AS10 Penalized 200% of demand charge, with a maximum of monthly service.||Provided Under Rate Schedules L-FPT1 and L-NFPT1.|
|1 Rates effective October 1, 2011, are preliminary and are subject to change upon publication of final formula rates.|
Because the proposed formula rates constitute a major rate adjustment as defined by 10 CFR part 903, Western will hold both a public information forum and a public comment forum. After review of public comments, Western will take further action on the proposed formula rates consistent with 10 CFR part 903.
Western is proposing LAP Transmission and WACM Ancillary Start Printed Page 5154Services formula rates under the Department of Energy (DOE) Organization Act (42 U.S.C. 7152); 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. 485h(c)); section 5 of the Flood Control Act of 1944 (16 U.S.C. 825s); and other acts specifically applicable to the projects involved.
By Delegation Order No. 00-037.00, effective December 6, 2001, the Secretary of Energy delegated: (1) The authority to develop power and transmission rates to 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.
Availability of Information
All brochures, studies, comments, letters, memorandums, or other documents that Western initiates or uses to develop the proposed formula rates are available for inspection and copying at the Rocky Mountain Regional Office, located at 5555 East Crossroads Boulevard, Loveland CO. Many of these documents and supporting information are also available on Western's Web site under the 2012 Rate Adjustment—Transmission and Ancillary Services section located at http://www.wapa.gov/rm/ratesRM/2012/default.htm.
Ratemaking Procedure Requirements
In compliance with the National Environmental Policy Act of 1969 (NEPA) (42 U.S.C. 4321-4347), Council on Environmental Quality Regulations (40 CFR parts 1500-1508), and DOE NEPA Regulations (10 CFR part 1021), Western is in the process of determining whether an environmental assessment or an environmental impact statement should be prepared or if this action can be categorically excluded from those requirements.
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.Start Signature
Dated: January 21, 2011.
Timothy J. Meeks,
1. WAPA-106 was approved by FERC on a final basis on January 31, 2005, in Docket No. EF-04-5182-000 (110 FERC ¶ 62,084).Back to Citation
2. WAPA-141 Extension of Rate Order No. WAPA 106, 2-year extension through February 28, 2011. 73 FR 48382, August 19, 2008.Back to Citation
3. WAPA-118 was approved by FERC on a final basis on November 17, 2006, in Docket No. EF-06-5182-000 (117 FERC ¶ 62,163).Back to Citation
[FR Doc. 2011-1894 Filed 1-27-11; 8:45 am]
BILLING CODE 6450-01-P