Loveland Area Projects-Western Area Colorado Missouri Balancing Authority-Rate Order No. WAPA-155, 5148-5154 [2011-1894]

Download as PDF WReier-Aviles on DSKGBLS3C1PROD with NOTICES 5148 Federal Register / Vol. 76, No. 19 / Friday, January 28, 2011 / Notices submersible generator units for a total installed capacity of 2,200 kilowatts; (2) a new 12.47-kilovolt, 1,320-foot-long transmission line; and (3) appurtenant facilities. The project would have an estimated average annual generation of approximately 6,000 megawatt-hours. m. A copy of the application is available for review at the Commission in the Public Reference Room or may be viewed on the Commission’s Web site at https://www.ferc.gov using the ‘‘eLibrary’’ link. Enter the docket number excluding the last three digits in the docket number field to access the document. For assistance, contact FERC Online Support. A copy is also available for inspection and reproduction at the address in item h above. You may also register online at https://www.ferc.gov/docs-filing/ esubscription.asp to be notified via e-mail of new filings and issuances related to this or other pending projects. For assistance, contact FERC Online Support. n. Any qualified applicant desiring to file a competing application must submit to the Commission, on or before the specified intervention deadline date, a competing development application, or a notice of intent to file such an application. Submission of a timely notice of intent allows an interested person to file the competing development application no later than 120 days after the specified intervention deadline date. Applications for preliminary permits will not be accepted in response to this notice. A notice of intent must specify the exact name, business address, and telephone number of the prospective applicant, and must include an unequivocal statement of intent to submit a development application. A notice of intent must be served on the applicant(s) named in this public notice. Anyone may submit a protest or a motion to intervene in accordance with the requirements of Rules of Practice and Procedure, 18 CFR 385.210, 385.211, and 385.214. In determining the appropriate action to take, the Commission will consider all protests filed, but only those who file a motion to intervene in accordance with the Commission’s Rules may become a party to the proceeding. Any protests or motions to intervene must be received on or before the specified deadline date for the particular application. When the application is ready for environmental analysis, the Commission will issue a public notice requesting comments, recommendations, terms and conditions, and prescriptions. VerDate Mar<15>2010 15:05 Jan 27, 2011 Jkt 223001 All filings must (1) bear in all capital letters the title ‘‘PROTEST’’ or ‘‘MOTION TO INTERVENE,’’ ‘‘NOTICE OF INTENT TO FILE COMPETING APPLICATION,’’ or ‘‘COMPETING APPLICATION;’’(2) set forth in the heading the name of the applicant and the project number of the application to which the filing responds; (3) furnish the name, address, and telephone number of the person protesting or intervening; and (4) otherwise comply with the requirements of 18 CFR 385.2001 through 385.2005. Agencies may obtain copies of the application directly from the applicant. A copy of any protest or motion to intervene must be served upon each representative of the applicant specified in the particular application. Kimberly D. Bose, Secretary. [FR Doc. 2011–1716 Filed 1–27–11; 8:45 am] BILLING CODE 6717–01–P DEPARTMENT OF ENERGY Western Area Power Administration Loveland Area Projects—Western Area Colorado Missouri Balancing Authority—Rate Order No. WAPA–155 Western Area Power Administration, DOE. ACTION: Notice of Proposed Transmission and Ancillary Services Formula Rates. AGENCY: 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. SUMMARY: PO 00000 Frm 00019 Fmt 4703 Sfmt 4703 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. ADDRESSES: 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 https:// 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. 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 scook@wapa.gov. SUPPLEMENTARY INFORMATION: The existing formula-based rates approved under Rate Order WAPA–106 1 became effective on March 1, 2004, with an expiration date of February 28, 2009. The rate schedules, with the exception of Rate Schedule L–AS3, Regulation and Frequency Response, were extended through February 28, 2011, under Rate Order No. WAPA–141.2 Rate Schedule L–AS3 was revised and approved under Rate Order No. WAPA–118,3 which became effective 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. DATES: 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). 2 WAPA–141 Extension of Rate Order No. WAPA 106, 2-year extension through February 28, 2011. 73 FR 48382, August 19, 2008. 3 WAPA–118 was approved by FERC on a final basis on November 17, 2006, in Docket No. EF–06– 5182–000 (117 FERC ¶ 62,163). E:\FR\FM\28JAN1.SGM 28JAN1 Federal Register / Vol. 76, No. 19 / Friday, January 28, 2011 / Notices WAPA–154.4 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 formulabased 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 Pointto-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. 5149 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 NonFirm 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 Pointto-Point Transmission Service. The formula for calculating the ATRR would be unchanged from the current formula: 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. 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 4 WAPA–154 Extension of Rate Order Nos. WAPA–106 and WAPA–118. 76 FR 1429, January 10, 2011. VerDate Mar<15>2010 15:05 Jan 27, 2011 Jkt 223001 PO 00000 Frm 00020 Fmt 4703 Sfmt 4703 E:\FR\FM\28JAN1.SGM 28JAN1 EN28JA11.017</GPH> Proposed Change to Forward-Looking Transmission Rates EN28JA11.016</GPH> WReier-Aviles on DSKGBLS3C1PROD with NOTICES The Annual Transmission Cost is the ratio of Net Investment Cost for Transmission Facilities to Net 5150 Federal Register / Vol. 76, No. 19 / Friday, January 28, 2011 / Notices 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. 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-toPoint 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-toPoint 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 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. WReier-Aviles on DSKGBLS3C1PROD with NOTICES Proposed Penalty Rate for Unreserved Use of Transmission Service VerDate Mar<15>2010 15:05 Jan 27, 2011 Jkt 223001 PO 00000 Frm 00021 Fmt 4703 Sfmt 4703 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: 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: E:\FR\FM\28JAN1.SGM 28JAN1 EN28JA11.018</GPH> than 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 overcollected in FY 2012. Federal Register / Vol. 76, No. 19 / Friday, January 28, 2011 / Notices 5151 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. 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 selfprovide 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. VerDate Mar<15>2010 15:05 Jan 27, 2011 Jkt 223001 PO 00000 Frm 00022 Fmt 4703 Sfmt 4703 Proposed Formula Rate for Regulation and Frequency Response Service (Regulation Service) E:\FR\FM\28JAN1.SGM 28JAN1 EN28JA11.020</GPH> The proposed formula for Regulation Service, Rate Schedule L–AS3, would have 4 components: (1) Load-based Assessment. EN28JA11.019</GPH> WReier-Aviles on DSKGBLS3C1PROD with NOTICES 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 5152 Federal Register / Vol. 76, No. 19 / Friday, January 28, 2011 / Notices 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 Selfprovision 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. WReier-Aviles on DSKGBLS3C1PROD with NOTICES 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 VerDate Mar<15>2010 15:05 Jan 27, 2011 Jkt 223001 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 nonintermittent 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 PO 00000 Frm 00023 Fmt 4703 Sfmt 4703 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. Rate Comparison Following is a table which compares the proposed formula rates for FY 2012 with the current formula rates for FY 2011: E:\FR\FM\28JAN1.SGM 28JAN1 Federal Register / Vol. 76, No. 19 / Friday, January 28, 2011 / Notices 5153 FORMULA RATE COMPARISON TABLE 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–FPT1 $3.45/kW-month L–NT1. Load ratio share of 1/12 of the revenue requirement of $48,000,660. L–FPT1. $3.18/kW-month Unauthorized Use Penalty of 150% of demand charge, with a maximum of monthly service. L–NFPT1. Maximum of 4.17 mills/kWh Unauthorized Use Penalty of 150% of demand charge, with a maximum of monthly service. L–AS1. $38.30 per tag per day for non- transmission customers. L–AS2. $0.180/kW-month. Firm Point-to-Point Service. Transmission Non-Firm Point-to-Point mission Service. Trans- Scheduling, System Control, and Dispatch Service. Reactive Supply and Voltage Control from Generation or Other Sources Service. Regulation and Frequency Response Service. Energy Imbalance Service ............... Operating Reserves Service—Spinning and Supplemental. Transmission Losses Service ........... WReier-Aviles on DSKGBLS3C1PROD with NOTICES Generator Imbalance Service ........... Penalty Rate for Unreserved Use of Transmission Service. 1 Rates L–NFPT1 Maximum of 4.73 mills/kWh L–AS1 $24.03 per schedule per day for non-transmission customers. L–AS2 $0.318/kW-month L–AS3 $0.322/kW-month 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–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–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–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. L–AS10 Penalized 200% of demand charge, with a maximum of monthly service. L–AS3. $0.339/kW-month. 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. 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–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. Provided Under Rate Schedule L–AS4. Provided Under Rate Schedules L–FPT1 and L– NFPT1. effective October 1, 2011, are preliminary and are subject to change upon publication of final formula rates. Legal Authority Because the proposed formula rates constitute a major rate adjustment as defined by 10 CFR part 903, Western VerDate Mar<15>2010 15:05 Jan 27, 2011 Jkt 223001 will hold both a public information forum and a public comment forum. After review of public comments, Western will take further action on the PO 00000 Frm 00024 Fmt 4703 Sfmt 4703 proposed formula rates consistent with 10 CFR part 903. Western is proposing LAP Transmission and WACM Ancillary E:\FR\FM\28JAN1.SGM 28JAN1 5154 Federal Register / Vol. 76, No. 19 / Friday, January 28, 2011 / Notices Services 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 https://www.wapa.gov/ rm/ratesRM/2012/default.htm. Ratemaking Procedure Requirements WReier-Aviles on DSKGBLS3C1PROD with NOTICES Environmental Compliance 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. VerDate Mar<15>2010 15:05 Jan 27, 2011 Jkt 223001 Dated: January 21, 2011. Timothy J. Meeks, Administrator. [FR Doc. 2011–1894 Filed 1–27–11; 8:45 am] BILLING CODE 6450–01–P ENVIRONMENTAL PROTECTION AGENCY [FRL–9259–5; Docket ID No. EPA–HQ–ORD– 2010–1077] Availability of Draft Report, Biofuels and the Environment: First Triennial Report to Congress Environmental Protection Agency (EPA). ACTION: Notice of peer review meeting and public comment period. AGENCY: EPA is announcing that it will convene an independent panel of experts to review the external review draft document titled, Biofuels and the Environment: The First Triennial Report to Congress (EPA/600/R–10/183A). The peer review meeting will be organized by Versar, Inc., an EPA contractor for external scientific peer review. The EPA also is announcing a 30-day public comment period for the draft document. The draft document was prepared by the National Center for Environmental Assessment (NCEA) within EPA’s Office of Research and Development. The 2007 Energy Independence and Security Act (EISA) mandates increased production of biofuels (fuels derived from organic materials) from 9 billion gallons per year in 2008 to 36 billion gallons per year by 2022. EISA (Section 204) also requires the U.S. Environmental Protection Agency (EPA) to assess and report to Congress every three years on the current and potential future environmental and resource conservation impacts associated with increased biofuel production and use. Biofuels and the Environment: First Triennial Report to Congress is the first report on this issue. The public comment period and the external peer review meeting are separate processes that provide opportunities for all interested parties to comment on the document. EPA intends to forward public comments that are submitted in accordance with this notice, to the external peer review panel, prior to the meeting for their consideration. When finalizing the draft document, EPA intends to consider any public comments that EPA receives in accordance with this notice. EPA is releasing this draft document solely for the purpose of obtaining public comment and peer review under SUMMARY: PO 00000 Frm 00025 Fmt 4703 Sfmt 4703 applicable information quality guidelines. This document does not represent and should not be construed to represent any Agency policy or determination. EPA, through its Peer Review contractor, Versar, Inc., invites the public to register to attend the peer review meeting. In addition, EPA through Versar, Inc., invites the public to give oral and/or provide written comments during the meeting regarding the draft document under review. The draft document and EPA’s charge to the peer reviewers are available primarily via the Internet on NCEA’s home page under the Recent Additions and Publications menus at https:// www.epa.gov/ncea. In preparing a final report, EPA will consider the comments and recommendations from the external peer review meeting and any public comments that EPA receives in accordance with this notice. DATES: The peer review panel meeting will begin on March 14, 2011, at 9 a.m. and end at 5 p.m. The 30-day public comment period begins January 28, 2011, and ends February 28, 2011. Technical comments should be in writing and must be received by EPA by February 28, 2011. ADDRESSES: The peer review meeting will be held at the Marriott Courtyard Arlington Crystal City/Reagan National Airport, 2899 Jefferson Davis Highway, Arlington, VA 22202, telephone: 703– 549–3434. The EPA contractor, Versar, Inc., is organizing, convening and conducting the peer review meeting. To attend the meeting, register by March 7, 2011, by contacting Versar, Inc. via email: saundkat@versar.com (subject line: Biofuels Report to Congress Peer Review Meeting), by telephone: 703– 750–3000, ext. 545, or toll free at 1–800– 2–VERSAR (1–800–283–7727), ask for Kathy Coon, the Biofuels Report to Congress Meeting Coordinator, or by faxing a registration request to 703–642– 6809 (please reference the Biofuels Report to Congress Peer Review Meeting and include your name, title, affiliation, full address and contact information). Information on Services for Individuals with Disabilities: EPA welcomes the attendance of the public at the Biofuels Report to Congress Peer Review Meeting and will make every effort to accommodate persons with disabilities. For information on access or services for individuals with disabilities, please contact Versar, Inc. via e-mail: saundkat@versar.com (subject line: Biofuels Report to Congress Peer Review Meeting), by telephone: 703–750–3000, ext. 545, or toll free at 1–800–2–VERSAR (1–800– E:\FR\FM\28JAN1.SGM 28JAN1

Agencies

[Federal Register Volume 76, Number 19 (Friday, January 28, 2011)]
[Notices]
[Pages 5148-5154]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-1894]

-----------------------------------------------------------------------

DEPARTMENT OF ENERGY

Western Area Power Administration

Loveland Area Projects--Western Area Colorado Missouri Balancing
Authority--Rate Order No. WAPA-155

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of Proposed Transmission and Ancillary Services Formula
Rates.

-----------------------------------------------------------------------

SUMMARY: 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.

DATES: 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.

ADDRESSES: 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 https://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.

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 scook@wapa.gov.

SUPPLEMENTARY INFORMATION: The existing formula-based rates approved
under Rate Order WAPA-106 \1\ became effective on March 1, 2004, with
an expiration date of February 28, 2009. The rate schedules, with the
exception of Rate Schedule L-AS3, Regulation and Frequency Response,
were extended through February 28, 2011, under Rate Order No. WAPA-
141.\2\ Rate Schedule L-AS3 was revised and approved under Rate Order
No. WAPA-118,\3\ which became effective 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.

[[Page 5149]]

WAPA-154.\4\ 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.
---------------------------------------------------------------------------

\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).
\2\ WAPA-141 Extension of Rate Order No. WAPA 106, 2-year
extension through February 28, 2011. 73 FR 48382, August 19, 2008.
\3\ WAPA-118 was approved by FERC on a final basis on November
17, 2006, in Docket No. EF-06-5182-000 (117 FERC ] 62,163).
\4\ WAPA-154 Extension of Rate Order Nos. WAPA-106 and WAPA-118.
76 FR 1429, January 10, 2011.
---------------------------------------------------------------------------

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\ x Annual Transmission Revenue Requirement x
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:
[GRAPHIC] [TIFF OMITTED] TN28JA11.016

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:
[GRAPHIC] [TIFF OMITTED] TN28JA11.017

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

[[Page 5150]]

than 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:
[GRAPHIC] [TIFF OMITTED] TN28JA11.018

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:

[[Page 5151]]

[GRAPHIC] [TIFF OMITTED] TN28JA11.019

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.
[GRAPHIC] [TIFF OMITTED] TN28JA11.020

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.

[[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.

Rate Comparison

Following is a table which compares the proposed formula rates for
FY 2012 with the current formula rates for FY 2011:

[[Page 5153]]

Formula Rate Comparison Table
----------------------------------------------------------------------------------------------------------------
Proposed Rate Schedule and estimated
Class of service rate effective October 1, 2011 \1\ Existing Rate Schedule and rate
(FY 2012) effective October 1, 2010 (FY 2011)
----------------------------------------------------------------------------------------------------------------
Network Transmission Service..... L-NT1 L-NT1.
Load ratio share of 1/12 of the Load ratio share of 1/12 of the
revenue requirement of $56,146,133 revenue requirement of $48,000,660.
Firm Point-to-Point Transmission L-FPT1 L-FPT1.
Service. $3.45/kW-month $3.18/kW-month
Unauthorized Use Penalty of 150% of
demand charge, with a maximum of
monthly service.
Non-Firm Point-to-Point L-NFPT1 L-NFPT1.
Transmission Service. Maximum of 4.73 mills/kWh Maximum of 4.17 mills/kWh
Unauthorized Use Penalty of 150% of
demand charge, with a maximum of
monthly service.
Scheduling, System Control, and L-AS1 L-AS1.
Dispatch Service. $24.03 per schedule per day for non- $38.30 per tag per day for non-
transmission customers. transmission customers.
Reactive Supply and Voltage L-AS2 L-AS2.
Control from Generation or Other $0.318/kW-month $0.180/kW-month.
Sources Service.
Regulation and Frequency Response L-AS3 L-AS3.
Service. $0.322/kW-month $0.339/kW-month.
Energy Imbalance Service......... L-AS4 L-AS4.
--Imbalances less than or equal to --Imbalances less than or equal to 5%
1.5% (minimum 4 MW) of metered load (minimum 4 MW) of metered load
settled using WACM hourly pricing settled using WACM pricing with no
with no penalty. penalty.
--Imbalances 1.5% to 7.5% (minimum 4 --Imbalances greater than 5% of
MW to 10 MW) of metered load settled metered load settled using WACM
using WACM hourly pricing with a 10% pricing with a 10% penalty.
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.
Operating Reserves Service-- L-AS5, L-AS6 L-AS5, L-AS6.
Spinning and Supplemental. Long-term reserves are not available Long-term reserves are not available
from WACM. Reserves may be provided from WACM. Reserves may be provided
on a pass-though cost, plus an amount on a pass-though cost, plus an
for administration. amount for administration.
Transmission Losses Service...... L-AS7 L-AS7
Transmission losses may be settled Transmission losses may be settled
either financially or with energy. either financially or with energy.
Insufficient losses supplied will be Insufficient losses supplied will be
settled financially by default settled financially by default.
All customers will have the option to All customers will have the option to
return the loss obligation for both return the loss obligation for both
prescheduled and real-time prescheduled and real-time
transactions 7 days later, same transactions 7 days later, same
profile profile.
Pricing used is WACM weighted average Pricing used is LAP weighted average
hourly purchase price. hourly purchase price.
Generator Imbalance Service...... L-AS9 Provided Under Rate Schedule L-AS4.
--Imbalances less than or equal to
1.5% (minimum 4 MW) of metered
generation settled using WACM hourly
pricing with no penalty.
--Imbalances 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.
Penalty Rate for Unreserved Use L-AS10 Provided Under Rate Schedules L-FPT1
of Transmission Service. Penalized 200% of demand charge, with and L-NFPT1.
a maximum of monthly service.
----------------------------------------------------------------------------------------------------------------
\1\ Rates effective October 1, 2011, are preliminary and are subject to change upon publication of final formula
rates.

Legal Authority

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

[[Page 5154]]

Services 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 https://www.wapa.gov/rm/ratesRM/2012/default.htm.

Ratemaking Procedure Requirements

Environmental Compliance

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.

Dated: January 21, 2011.
Timothy J. Meeks,
Administrator.
[FR Doc. 2011-1894 Filed 1-27-11; 8:45 am]
BILLING CODE 6450-01-P

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