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 Department of Energy Western Area Power Administration
 AGENCY: Western Area Power Administration, DOE.
 ACTION: Notice of order concerning transmission and ancillary services formula rates.
 SUMMARY: The Deputy Secretary of Energy has confirmed and approved Rate Order No. WAPA-155 and Rate Schedules L-NT1, L-FPT1, L-NFPT1, L-AS1, L-AS2, L-AS3, L-AS4, L-AS5, L-AS6, L-AS7, L-AS9, and L-UU1, placing Loveland Area Projects (LAP) transmission and Western Area Colorado Missouri (WACM) Balancing Authority ancillary services formula rates into effect on an interim basis. The provisional formula rates will be in effect until the Federal Energy Regulatory Commission (FERC) confirms, approves, and places them into effect on a final basis or until they are replaced by other formula rates. The provisional formula rates will provide sufficient revenue to pay all annual costs, including interest expense, and to repay power investment within the allowable periods.
 DATES: Rate Schedules L-NT1, L-FPT1, L-NFPT1, L-AS1, L-AS2, L-AS3, L-AS4, L-AS5, L-AS6, L-AS7, L-AS9, and L-UU1 will be placed into effect on an interim basis on the first day of the first full billing period beginning on or after October 1, 2011, and will remain in effect until FERC confirms, approves, and places the rate schedules into effect on a final basis for a 5-year period ending September 30, 2016, or until the rate schedules are superseded.
 FOR FURTHER INFORMATION CONTACT: Mr. Bradley S. Warren, Regional Manager, Rocky Mountain Customer Service Region, Western Area Power Administration, 5555 East Crossroads Boulevard, Loveland, CO 80538-8986, telephone (970) 461-7201, or Mrs. Sheila D. Cook, Rates Manager, Rocky Mountain Customer Service 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 Deputy Secretary of Energy approved current Rate Schedules L-NT1, L-FPT1, L-NFPT1, L-AS1, L-AS2, L-AS3, L-AS4, L-AS5, L-AS6, and L-AS7 on December 30, 2003 (Rate Order No. WAPA-106, 69 FR 1723, January 12, 2004).[1]
                        
                         These rates 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 on June 1, 2006, with an expiration date of May 31, 2011. Under Rate Order No. WAPA-154,[4]
                        
                         all LAP transmission and WACM ancillary services rate schedules, including L-AS3, were extended through February 28, 2013. LAP Transmission Service Rate Schedules L-NT1, L-FPT1, and L-NFPT1 for LAP transmission services are based on a revenue requirement that recovers the LAP transmission system costs for facilities associated with providing all transmission services as well as the non-transmission facility costs allocated to transmission services. These firm and non-firm LAP transmission service rates include the costs for scheduling, system control, and dispatch service needed to provide the transmission service. Rate Schedule L-UU1, Unreserved Use Penalties, is a new rate schedule established in accordance with Western's Open Access Transmission Tariff (Tariff). This rate will recover costs for transmission service that has not been reserved or has been used in excess of the amount reserved. Rate Schedule L-UU1 also provides for a penalty in addition to the base charge for the transmission service used. Previously, a penalty for unauthorized use of transmission was included in the Point-to-Point Transmission Service, Rate Schedules L-FPT1 and L-NFPT1. Rate Schedule L-AS7, Transmission Losses Service, is designed to recover losses on all real-time and prescheduled transactions on transmission facilities inside WACM. Ancillary Services Western will provide seven ancillary services pursuant to its Tariff. These are: (1) Scheduling, System Control, and Dispatch Service (L-AS1); (2) Reactive Supply and Voltage Control from Generation or Other Sources Service (L-AS2); (3) Regulation and Frequency Response Service (L-AS3); (4) Energy Imbalance Service (L-AS4); (5) Spinning Reserve Service (L-AS5); (6) Supplemental Reserve Service (L-AS6); and (7) Generator Imbalance Service (L-AS9). Generator Imbalance Service is also a new rate schedule established under the Tariff. Currently, Generator Imbalance Service is provided under Rate Schedule L-AS4, Energy Imbalance Service. Rates for LAP transmission and ancillary services will be recalculated each year to incorporate the most recent financial, load, and schedule information and will be applicable to all transmission and ancillary services customers. By Delegation Order No. 00-037.00, effective December 6, 2001, the Secretary of Energy delegated (1) the authority to develop power and transmission rates to the Administrator of Western; (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 Department of Energy procedures for public participation in power rate adjustments (10 CFR 903) were published on September 18, 1985 (50 FR 37835). Under Delegation Order Nos. 00-037.00 and 00-001.00C, 10 CFR part 903, and 18 CFR part 300, I hereby confirm, approve, and place Rate Order No. WAPA-155, the proposed LAP transmission and WACM ancillary services formula rates, into effect on an interim basis. By this order, I am placing the rates into effect in less than 30 days to meet contract deadlines, to avoid financial difficulties, and to provide rates for new services. The revised Rate Schedules L-NT1, L-FPT1, L-NFPT1, L-AS1, L-AS2, L-AS3, L-AS4, L-AS5, L-AS6, L-AS7, L-AS9, and L-UU1 will be submitted promptly to FERC for confirmation and approval on a final basis. Dated: September 2, 2011. Daniel B. Poneman, Deputy Secretary.
 Order Confirming, Approving, and Placing the Loveland Area Projects Transmission and Western Area Colorado Missouri Balancing Authority Ancillary Services Formula Rates Into Effect on an Interim Basis These transmission and ancillary services formula rates are established pursuant to section 302 of the Department of Energy (DOE) Organization Act (42 U.S.C. 7152). This act transferred to and vested in the Secretary of Energy the power marketing functions of the Secretary of the Interior and the Bureau of Reclamation (Reclamation) under the Reclamation Act of 1902 (ch. 1093, 32 Stat. 388), as amended and supplemented by subsequent laws, particularly section 9(c) of the Reclamation Act of 1939 (43 U.S.C. 485h(c)) and section 5 of the Flood Control Act of 1944 (16 U.S.C. 825s), and other acts that specifically apply 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 the Administrator of Western; (2) the authority to confirm, approve, and place such rates into effect on an interim basis to the Deputy Secretary of Energy; and (3) the authority to confirm, approve, and place into effect on a final basis, to remand, or to disapprove such rates to the Federal Energy Regulatory Commission (FERC). Existing DOE procedures for public participation in power rate adjustments (10 CFR part 903) were published on September 18, 1985. Acronyms/Terms and Definitions As used in this Rate Order, the following acronyms/terms and definitions apply: Acronym/Term
Definition*$/kW-month:*
Dollars per kilowatt per month.*12-cp:*
Rolling 12-month average of customers' loads in excess of Federal Entitlement, coincident with the Loveland Area Projects (LAP) transmission system peak.*Administrator:*
The Administrator of the Western Area Power Administration.*Area Control Error (ACE):*
The instantaneous difference between a Balancing Authority's net actual and scheduled interchange, taking into account the effects of frequency bias and correction for meter error.*Ancillary Services:*
Those services that are necessary to support the transmission of capacity and energy from resources to loads while maintaining reliable operation of the Transmission Provider's transmission system in accordance with good utility practice.*ATRR:*
Annual transmission revenue requirement.*Automatic Generation Control:*
Equipment that automatically adjusts generation in a Balancing Authority area from a central location to maintain the Balancing Authority's interchange schedule plus frequency bias.*Balancing Authority:*
The responsible entity that integrates resource plans ahead of time, maintains load-interchange-generation balance within a Balancing Authority area, and supports interconnection frequency in real time.*Control Area:*
The term used for a Balancing Authority area in Western's Open Access Transmission Tariff.*CRSP:*
Colorado River Storage Project.*DOE:*
Department of Energy.*Energy Imbalance Service:*
The ancillary service in which the Balancing Authority corrects hourly for the difference between a customer's energy supply and energy usage.*Federal Customers:*
LAP customers taking delivery of long-term firm service under firm electric service contracts, project use, and special use contracts.*Firm Electric Service Contracts:*
Contracts for the sale of long-term firm LAP Federal energy and capacity, pursuant to the Post-1989 General Power Marketing and Allocation Criteria (Marketing Plan).*Firm Point-to-Point Transmission Service:*
The highest priority transmission service offered to customers on a specified path that anticipates no planned interruption.*Federal Entitlements:*
The energy and capacity delivered to Federal Customers under Firm Electric Service Contracts.*FERC:*
Federal Energy Regulatory Commission.*Fry-Ark:*
Fryingpan-Arkansas Project.*FY:*
Fiscal Year, October 1 through September 30.*Generator Imbalance Service:*
The ancillary service in which the Balancing Authority corrects hourly for the difference between a customer's actual generation and scheduled generation.*kW:*
Kilowatt. The electrical unit of capacity equal to 1,000 watts.*kWh:*
Kilowatt-hour. The electrical unit of energy equal to 1 kW produced or delivered for 1 hour.*kW-month:*
Kilowatt-month. The electrical unit of energy equal to 1 kW produced or delivered for 1 month.*LAP:*
Loveland Area Projects.*LAP Transmission System or Service:*
Transmission system operated by, or service provided by, the Loveland Area Projects.*LAP Transmission System Total Load:*
Sum of 12-cp averages for all customer loads for Network Integration Transmission Service, plus   12-month rolling average of monthly entitlements of Federal Customers, plus reserved capacity for all Long-Term Firm Point-to-Point Transmission Service.*Load ratio share:*
Network Transmission Customer's 12-cp load coincident with LAP's monthly transmission system peak, expressed as a ratio.*Load Serving Entity (LSE):*
An entity within the Balancing Authority that secures energy and transmission service (and related interconnected operations services) to serve the electrical demand and energy requirements of its end-use customers.*Long-Term Firm Point-to-Point Transmission Service:*
Firm Point-to-Point Transmission Service reservation for a duration of at least 12 consecutive months.( print page 61186)*Losses:*
The reduction of power being delivered as it moves across transmission lines or other equipment, due to resistance in the conducting material.*M&I:*
Municipal and Industrial.*Mill:*
Unit of monetary value equal to .001 of a U.S. dollar; i.e., 
                                1/10
                                 of a cent.*Mills/kWh:*
Mills per kilowatt-hour.*Monthly Entitlements:*
Maximum capacity to be delivered each month under Firm Electric Service Contracts. Each monthly entitlement is a percentage of the seasonal contract-rate-of-delivery.*MW:*
Megawatt. The unit of electrical capacity that equals 1,000 kW or 1,000,000 watts.*NERC:*
North American Electric Reliability Corporation.*Network Integration Transmission Service:*
Firm transmission service for the delivery of capacity and energy from designated network resources to designated network loads not using one specific path.*Non-Firm Point-to-Point Transmission Service:*
Point-to-point transmission service reserved on an as-available basis for periods ranging from 1 hour to 1 year.*Open Access Same Time Information System (OASIS):*
An electronic posting system that the Transmission Provider maintains for transmission access data that allows all transmission customers to view the data simultaneously.*Operating Reserve—Spinning Reserve Service:*
Generation capacity needed to serve load immediately in the event of a system contingency. Spinning Reserve Service may be provided by generating units that are on-line and loaded at less than maximum output.*Operating Reserve—Supplemental Reserve Service:*
Generation capacity needed to serve load in the event of a system contingency, which capacity is not available immediately to serve load but rather within a short period of time. Supplemental Reserve Service may be provided by generation units that are on-line but unloaded, by quick start generation, or by interruptible load.*Provisional Formula Rate:*
A formula rate that has been confirmed, approved, and placed into effect on an interim basis by the Deputy Secretary.*P-SMBP:*
Pick-Sloan Missouri Basin Program.*P-SMBP—WD:*
Pick-Sloan Missouri Basin Program—Western Division.*RMR:*
Rocky Mountain Customer Service Region.*Reactive Supply and Voltage Control from Generation or Other Sources Service:*
The ancillary service under which a Balancing Authority operates generation facilities under its control to produce or absorb reactive power to maintain voltages on all transmission facilities within acceptable limits.*Reclamation:*
The United States Bureau of Reclamation.*Regulation and Frequency Response Service:*
The ancillary service under which a Balancing Authority maintains moment-by-moment load-interchange-generation balance with the Balancing Authority area and supports interconnection frequency.*Scheduling, System Control, and Dispatch Service:*
The ancillary service under which a Balancing Authority sets up an arrangement for an energy interchange transaction for delivery and receipt of energy between the two entities involved in the transaction.*Service Agreement:*
The initial agreement and any amendments or supplements entered into by a Transmission Customer and Western for service under the Tariff.*Short-Term Firm Point-to-Point Transmission Service:*
Firm Point-to-Point Transmission Service for a duration of less than 12 consecutive months.*Sub-Balancing Authority:*
An area within a Balancing Authority area which has its own boundary metering scheme and for which an ACE can be measured.*Tariff:*
Western's revised Open Access Transmission Service Tariff, effective December 1, 2009 (Docket NJ10-1-000).*Transmission Customer:*
The RMR customer taking Network Integration Transmission Service or Point-to-Point Transmission Service.*Transmission Losses Service:*
The service provided by the Balancing Authority to supply electrical losses on pre-scheduled and real-time transmission transactions.*Transmission Provider:*
An entity that administers a transmission tariff and provides transmission service to transmission customers under applicable transmission service agreements.*Unreserved Use Penalties:*
The use of transmission capacity that was not reserved, or the use of transmission in excess of reserved capacity.*WACM:*
Western Area Colorado Missouri Balancing Authority.*WECC:*
Western Electricity Coordinating Council.*Western:*
Western Area Power Administration.
 Effective Date The Provisional Formula Rates will take effect on the first day of the first full billing period beginning on or after October 1, 2011, and will remain in effect through September 30, 2016, pending approval by FERC on a final basis. Public Notice and Comment Western has followed the Procedures for Public Participation in Power and Transmission Rate Adjustments and Extensions, 10 CFR Part 903, in the development of these formula rates and schedules. The steps Western took to involve interested parties in the rate process were: 1. On September 29, 2010, Western held an informal meeting with customers and interested parties to discuss the proposed formula rates for LAP Transmission and WACM Ancillary Services. Western posted all information presented at the informal meeting, as well as responses to questions asked at the meeting, on its Web site at 
                        *http://www.wapa.gov/​rm/​ratesRM/​2012/​default.htm*. 2. Western published a 
                        **Federal Register**
                         notice on January 28, 2011 (76 FR 5148), officially announcing the proposed LAP Transmission and WACM Ancillary Services formula rates adjustment, initiating the public consultation and comment period, announcing the date and location of the public information and public comment 
                        ( print page 61187)
                        forums, and outlining procedures for public participation. 3. On February 2, 2011, Western sent a letter to all interested parties providing them with a copy of the 
                        **Federal Register**
                         notice published on January 28, 2011 (76 FR 5148). 4. On March 9, 2011, Western held its public information forum in Loveland, Colorado, where Western representatives explained the need for the formula rates adjustment in detail and answered questions. 5. On March 9, 2011, following the public information forum, Western held a public comment forum in Loveland, Colorado, to provide an opportunity for customers and other interested parties to comment for the record. At this forum, one individual expressed general support of Western's efforts to communicate with its customers well in advance of implementation of the proposed rates. 6. Western received one written comment during the 90-day consultation and comment period, which ended on April 28, 2011. This comment is addressed below following the ancillary services discussion. All comments received have been considered in the preparation of this Rate Order. Project Descriptions The Post-1989 General Power Marketing and Allocation Criteria, published in the 
                        **Federal Register**
                         on January 31, 1986 (51 FR 4012), integrated the resources of the P-SMBP—WD and Fry-Ark. This operational and contractual integration, known as LAP, allowed an increase in marketable resources, simplified contract administration, and established a blended rate for LAP power sales. WACM offers Ancillary Services from a combination of all LAP generation resources and some CRSP generation resources. P-SMBP—WD The P-SMBP was authorized by Congress in section 9 of the Flood Control Act of December 22, 1944 (Pub. L. 534, 58 Stat. 877, 891). This multipurpose program provides flood control, M&I water supply, irrigation, navigation, recreation, preservation and enhancement of fish and wildlife, and hydroelectric power. Multipurpose projects have been developed on the Missouri River and its tributaries in Colorado, Montana, Nebraska, North Dakota, South Dakota, and Wyoming. In addition to the multipurpose water projects authorized by section 9 of the Flood Control Act of 1944, certain other existing projects have been integrated with the P-SMBP for power marketing, operation, and repayment purposes. The Colorado-Big Thompson, Kendrick, Riverton, and Shoshone Projects were combined with P-SMBP in 1954, followed by the North Platte Project in 1959. These projects are known as the “Integrated Projects” of the P-SMBP. The Riverton Project was reauthorized as a unit of the P-SMBP in 1970. Together, the P-SMBP—WD and the Integrated Projects have 19 power plants. There are six power plants in P-SMBP—WD: Glendo, Kortes, and Fremont Canyon power plants on the North Platte River; Boysen and Pilot Butte power plants on the Wind River; and Yellowtail power plant on the Big Horn River. The Colorado-Big Thompson Project has six power plants: Green Mountain power plant on the Blue River is on the West Slope of the Continental Divide; and Mary's Lake, Estes, Pole Hill, Flatiron, and Big Thompson power plants along the Big Thompson River are on the East Slope of the Continental Divide. The Kendrick Project has two power plants: Alcova and Seminoe power plants on the North Platte River. Power plants in the Shoshone Project are the Shoshone, Buffalo Bill, Heart Mountain, and Spirit Mountain plants on the Shoshone River. The only power plant in the North Platte Project is the Guernsey power plant, also on the North Platte River. Fry-Ark Fry-Ark is a trans-mountain diversion development in southeastern Colorado authorized by the Act of Congress on August 16, 1962 (Pub. L. 87-590, 76 Stat. 389, as amended by Title XI of the Act of Congress on October 27, 1974 (Pub. L. 93-493, 88 Stat. 1486, 1497)). The Fry-Ark diverts water from the Fryingpan River and other tributaries of the Roaring Fork River in the Colorado River Basin on the West Slope of the Rocky Mountains to the Arkansas River on the East Slope. The water diverted from the West Slope, together with regulated Arkansas River water, provides supplemental irrigation and M&I water supplies and produces hydroelectric power. Flood control, fish and wildlife enhancement, and recreation are other important purposes of Fry-Ark. The only generating facility in Fry-Ark is the Mt. Elbert Pumped-Storage power plant on the East Slope. CRSP CRSP was authorized by the Colorado River Storage Project Act, ch. 203, 70 Stat. 105, on April 11, 1956. The project provides water-use developments for states in the Upper Basin (Colorado, New Mexico, Utah, and Wyoming) while still maintaining water deliveries to the states of the Lower Basin (Arizona, California, and Nevada) as required by the Colorado River Compact of 1922. CRSP hydroelectric facilities providing ancillary services for WACM are the Aspinall power plant (formerly Curecanti) on the Gunnison River, the Flaming Gorge power plant on the Green River, the Towaoc Power Plant on the Towaoc Canal in southwestern Colorado, and the Glen Canyon power plant on the Colorado River. LAP Transmission Service Transmission formula rates, including those for Firm and Non-Firm Point-To-Point Transmission Service and Network Integration Transmission Service, are designed to recover the annual costs of the LAP Transmission System. The transmission rates include the cost of Scheduling, System Control, and Dispatch Service. Western will continue to bundle transmission service for delivery of LAP long-term firm Federal power to Federal Customers in the firm electric service rate under existing Firm Electric Service Contracts that expire in 2024. The penalty for unauthorized use of transmission, currently assessed under the Point-to-Point Transmission rate schedules, will now be assessed as a penalty for unreserved use under a separate rate schedule, L-UU1. Unreserved Use Penalties will include the basic rate for the transmission service used and not reserved, plus a penalty equal to the basic rate. Transmission losses are assessed for all real-time and prescheduled transactions on transmission facilities inside WACM. The current loss factor, as posted on the RMR OASIS, is 4.5 percent. WACM Ancillary Services Western will offer seven Ancillary Services pursuant to its Tariff. The seven Ancillary Services are: (1) Scheduling, System Control, and Dispatch Service (SSCD Service); (2) Reactive Supply and Voltage Control from Generation or Other Sources Service (VAR Support Service); (3) Regulation and Frequency Response Service (Regulation Service); (4) Energy Imbalance Service; (5) Spinning Reserve Service; (6) Supplemental Reserve Service; and (7) Generator Imbalance Service. Generator Imbalance Service, currently provided as part of Rate Schedule L-AS4 for Energy Imbalance Service, is a new service under the Tariff. The Ancillary Services formula rates are designed to recover only the 
                        ( print page 61188)
                        costs incurred for providing the service(s). Comparison of Existing and Provisional Formula Rates for Transmission and Ancillary Services The following table displays a comparison of existing formula rates and the Provisional Formula Rates for FY 2012. These rates will be recalculated annually based on updated financial, schedule, and load data. Formula Rate Comparison Table
Class of Service
Provisional Formula Rates
                                 Effective October 1, 2011 (FY 2012)
Existing Formula Rates
                                 Effective October 1, 2010 (FY 2011)Network Integration Transmission Service
L-NT1
                                 Load ratio share of 1/12 of the revenue requirement of $56,775,913.
L-NT1
                                 Load ratio share of 1/12 of the revenue requirement of $48,000,660.Firm Point-to-Point Transmission Service
L-FPT1
                                 $3.48/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 4.77 mills/kWh
L-NFPT1
                                 Maximum of 4.17 mills/kWh 
                                 Unauthorized Use Penalty of 150% of demand charge, with a maximum of monthly service.Unreserved Use Penalties
L-UU1
                                 Penalized 200% of demand charge, with a maximum of monthly service.
Provided Under Rate Schedules L-FPT1 and L-NFPT1 as Unauthorized Use.Transmission Losses Service
L-AS7
L-AS7Transmission losses may be settled either financially or with energy. Insufficient losses supplied will be settled financially by default.
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.
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.
Pricing used is LAP weighted average hourly real-time purchase price.Current loss factor as posted is 4.5%.
Current loss factor as posted is 4.5%.Scheduling, System Control, and Dispatch Service
L-AS1
                                 $24.22 per schedule per day for non-Federal transmission customers. Not applicable to schedules for delivery of Losses to WACM.
L-AS1
                                 $38.30 per tag per day for non- 
                                 Federal transmission customers. Applicable to all tags.Reactive Supply and Voltage Control from Generation or Other Sources Service
L-AS2
                                 $0.305/kW-month
L-AS2
                                 $0.180/kW-monthRegulation and Frequency Response
L-AS3
                                 $0.331/kW-month
L-AS3
                                 $0.339/kW-monthEnergy Imbalance Service
L-AS4
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 less than or equal to 5% (minimum 4 MW) of metered load settled using WACM hourly pricing with no penalty.—Imbalances between 1.5% and 7.5% (minimum 4 MW to 10 MW) of metered load settled using WACM hourly pricing with a 10% penalty.
—Imbalances greater than 5% 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.
                                 —WACM aggregate imbalance determines pricing in all bands—aggregate surplus dictates sale pricing, aggregate deficit dictates purchase pricing.
—WACM aggregate imbalance dictates pricing in no-penalty band. Customer imbalance dictates pricing in penalty band (surpluses indicate sale pricing, deficits indicate purchase pricing).
                                 —Intermittent resources not subject to penalties.Operating Reserve Service—Spinning and Supplemental
L-AS5, L-AS6
                                 Long-term Reserves are not available from WACM. Reserves may be acquired and provided at pass-through cost, plus an amount for administration.
L-AS5, L-AS6
                                 Long-term Reserves are not available from WACM. Reserves may be acquired and provided at pass-through cost, plus an amount for administration.( print page 61189)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 between 1.5% and 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 25% penalties. 
                                 —WACM aggregate imbalance determines pricing in all bands—aggregate surplus dictates sale pricing, aggregate deficit dictates purchase pricing.
Provided under Rate Schedule L-AS4.
 Certification of Rates Western's Administrator certified that the Provisional Formula Rates for LAP Transmission and WACM Ancillary Services under Rate Schedules L-NT1, L-FPT1, L-NFPT1, L-AS1, L-AS2, L-AS3, L-AS4, L-AS5, L-AS6, L-AS7, L-AS9, and L-UU1 are the lowest possible rates consistent with sound business principles. The Provisional Formula Rates were developed following administrative policies and applicable laws. LAP Transmission Service Discussion Network Integration Transmission Service The monthly charge for Network Integration Transmission Service for the Transmission Customer will be as follows:  The customer's load-ratio share is the ratio of its network load to the LAP Transmission System Total Load at the LAP system peak. This is calculated on a rolling 12-month average (12 coincident peak average or 12-cp). Firm Point-to-Point Transmission Service The formula rate for Firm Point-to-Point Transmission Service is as follows:  The rates for FY 2012 are as follows:  Discussions of the ATRR and the LAP Transmission System Total Load are located below. Non-Firm Point-to-Point Transmission Service The maximum Non-Firm Point-to-Point Transmission Service formula rate is the same as the Firm Point-to-Point Transmission Service rate. Non-Firm Point-to-Point Transmission Service is available for periods ranging from 1 hour to 1 year. Maximum Hourly Non-Firm Rate: 4.77 mills/kW of reserved capacity per hour
                        ( print page 61190) Annual Transmission Revenue Requirement The ATRR is applicable to both Network and Point-to-Point Transmission Service. The ATRR is the annual cost of the LAP Transmission System, adjusted for revenue credits, costs that increase the capacity available for transmission, other miscellaneous charges or credits, and the prior year true-up. The formula, with amounts calculated for the FY 2012 rate, is as follows:  The annual cost of the LAP Transmission System is the ratio of gross investment cost for transmission facilities to gross 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, with amounts for FY 2012, is as follows:  The source for the annual costs is the formalized work plans for FY 2012 and the FY 2010 Results of Operations for P-SMBP—WD, with certain items adjusted for projected asset capitalization or historical trends. See discussion below on “Change to Forward-Looking Transmission Rates.” The gross investment cost for transmission facilities is 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, portions of the communication, maintenance, and administration facilities are included in the investment costs for transmission. Only the investment costs of the facilities identified as “transmission”, including allocated costs for communication, maintenance, and administration facilities, are used in developing the annual cost of the transmission system. 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 Fry-Ark costs are considered generation-related and, therefore, are excluded from the ATRR. System augmentation expense includes payments made to others for their systems' augmentation of the LAP Transmission System. Miscellaneous charges and credits will include, but will not be limited to, Unreserved Use Penalties and facility use charges for transmission facility investments included in the revenue requirement. For a description of the prior year true-up, see discussion below on “Change to Forward-Looking Transmission Rates.”
                        ( print page 61191) Change to Forward-Looking Transmission Rates Western has changed 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 allows Western to more accurately match cost recovery with cost incurrence. Western will use projections to estimate transmission costs and load for the upcoming year in the annual rate calculation, rather than using historical information. The method is a change in the manner in which the inputs for the rate are developed, rather than a change to the formula rate itself. When actual cost information for a year becomes available, Western will calculate the actual revenue requirement for that year. Revenue collected in excess of the actual revenue requirement will be included as a credit in the ATRR in a subsequent year. Similarly, any under-collection of the revenue requirement will be included as a charge in the ATRR in a subsequent year. This true-up procedure will ensure that Western recovers no more and no less than the actual transmission costs for any 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 will include an adjustment for revenue under- or over-collected in FY 2012. Transmission System Total Load for Point-to-Point Service The LAP Transmission System Total Load is a 12-month average of the sum of (1) all Network Integration Transmission Service customer loads in excess of deliveries of Federal Entitlements, measured at the monthly LAP Transmission System peak hour, plus (2) the monthly entitlements of Federal Customers, plus (3) the reserved capacity for Long-Term Firm Point-to-Point Transmission Service. This load calculation is prepared once annually and is used to calculate the point-to-point rates for the entire year. The LAP Transmission System Total Load is calculated as follows, based upon data projected for FY 2012: Federal Customers
604,639 kWNetwork Transmission Customers
743,818 kWSubtotal
1,348,457 kWPoint-to-Point Reserved Capacity
9,885 kWLAP Transmission System Total Load
1,358,342 kW
 Unreserved Use Penalties Unreserved use of the transmission system (Unreserved Use) occurs when a Transmission Customer uses transmission service that exceeds its reserved capacity or an eligible customer uses transmission service that it has not reserved. Western will assess Unreserved Use Penalties against a customer that has not secured reserved capacity or exceeds its reserved capacity at any point of receipt or any point of delivery. Unreserved Use may also include a Transmission Customer's failure to curtail transmission when requested. A customer that engages in Unreserved Use will be assessed a penalty charge of 200 percent of LAP's approved transmission service rate for Firm Point-to-Point Transmission Service as follows: (1) The Unreserved Use penalty for a single hour of Unreserved Use will be based upon the rate for daily Firm Point-to-Point Service. (2) The Unreserved Use penalty for more than one assessment for a given duration (e.g., daily) will increase to the next longest duration (e.g., weekly). (3) The Unreserved Use penalty charge for multiple instances of Unreserved Use (e.g., more than one hour) within a day will be based on the rate for daily Firm Point-to-Point Service. Multiple instances of Unreserved Use isolated to one calendar week will 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 will 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 will be required to pay, in addition to the Unreserved Use Penalties, for all applicable Ancillary Services identified in Western's Tariff 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 rate will be included as a credit in the calculation of the ATRR in a subsequent year. Transmission Losses Service Transmission Losses are assessed for all real-time and prescheduled transactions on transmission facilities inside WACM. In the case of Network Integration Transmission Service Customers, transmission and transformer Losses applicable under customers' respective contracts are calculated as part of the customers' Energy Imbalance Service settlements. Other customers are allowed the option of financial settlement or energy repayment. Energy repayment is either concurrently or 7 days later, to be delivered using the same profile as the related transmission transaction. When a transmission loss energy obligation is not provided (or is under-provided) by a customer for a transmission transaction, the energy still owed for Losses is calculated and a charge is assessed to the customer, based on the WACM weighted average hourly purchase price. The loss factor, currently 4.5 percent, is updated periodically and posted on the RMR OASIS Web site. Transmission Service Comments RMR received no comments concerning transmission service, Unreserved Use Penalties, or Transmission Losses during the public consultation and comment period. Ancillary Services Discussion Pursuant to Western's Tariff, WACM will offer seven Ancillary Services. Two of these services, SSCD Service and VAR Support Service, are services that, under Western's Tariff, the Transmission Provider is required to provide (or offer to arrange with the Balancing Authority operator) and the Transmission Customer is required to purchase. The other five Ancillary Services, Regulation Service, Energy Imbalance Service, Generator Imbalance Service, Operating Reserve—Spinning Reserve Service, and Operating Reserve—Supplemental Reserve Service, are services that the Transmission Provider is required to 
                        *offer*
                         to provide to the Transmission Customer. The Transmission Customer is required to acquire these Ancillary Services, either from the Transmission Provider or from a third party, or to self-supply them. Scheduling, System Control, and Dispatch Service The formula for SSCD Service, with amounts shown for FY 2012, is as follows: 
 
  This rate recovers the annual expenses associated with transmission scheduling. The annual cost of scheduling personnel and related costs is comprised of annual expenses for personnel, facilities, equipment, and software, as well as credits representing fees for agent services and unscheduled flow mitigation services. This revenue requirement is divided by the number of schedules (excluding schedules for delivery of losses to WACM) per year to derive a rate per schedule per day. Per Schedule 1 of Western's Tariff, “this service can be provided only by the operator of the Control Area in which the transmission facilities used for transmission service are located.” In cases in which the Transmission Provider (LAP and/or CRSP) directly provides the service as the Control Area operator, the costs for this service are bundled in the respective Federal transmission rate. In cases in which the Transmission Providers on the schedules are not the operator, WACM indirectly performs this service for those Transmission Providers' transmission systems. Western has historically invoiced the 
                        *last*
                         Transmission Provider that is inside WACM on the schedule. Since all non-Federal Transmission Providers are indirectly taking this service from WACM, Western will allocate the cost of each schedule equally among 
                        *all*
                         Transmission Providers (Federal and non-Federal) listed on the schedule that are inside WACM. The Federal transmission segments will be exempt from invoicing, as costs for these segments will continue to be included in the Federal (LAP and CRSP) transmission service rates. Western will not include schedules for delivery of transmission losses to WACM in the calculation of the rate and will not invoice for them, so that entities delivering losses may create individual loss schedules associated with specific transactions without charge. Western will accept any number of schedule changes over the course of a day, without additional charge, so that entities attempting to follow their loads closely may do so without penalty. Reactive Supply and Voltage Control from Generation or Other Sources Service The formula for VAR Support Service is the following:  TARRG = Total Annual Revenue Requirement for Generation % of Resource = Percentage of Resource Used for VAR Support The numerator captures the percentage of annual generation plant costs that are used for this service. Most of the LAP generation plant facilities are owned and operated by Reclamation, but Western has some facilities that are considered generation-related. Net generation plant costs are multiplied by a fixed charge rate (FCR) for generation to determine the TARRG, where  The FCR is a methodology used to assign a portion of total expenses to generation. Applying these formulas to FY 2010 data provides the following results: 
 
  Applying this percentage to the amount of net generation plant investment results in the TARRG: TARRG = $334,166,538 × 17.847% = $59,638,020 The percentage of the TARRG that is included in the revenue requirement is based on the nameplate capability of the generating units with regard to reactive and real power production. The TARRG is multiplied by the complement of the weighted average power factor rating for generating units. The weighted average power factor rating for the LAP generating units is 94.77 percent, so the revenue requirement for this rate includes 5.23 percent of the TARRG. The portion of the revenue requirement contributed by LAP plant costs is as follows: LAP Plant Costs = $59,638,020 × 5.2284% = $3,118,089 Plant costs for CRSP plants providing VAR Support Service are calculated using identical methodology. The contribution to the revenue requirement from CRSP plants is $1,539,255. The total revenue requirement, after adjusting for a small amount of VAR Support Service revenue on point-to-point transmission transactions not in the rate design, is as follows: LAP Plant Costs
$3,118,089CRSP Plant Costs
$1,539,255PTP Revenue
$(53,525)Revenue Requirement
$4,603,819
 The load taking this service totals 1,258,524 kW, resulting in a proposed rate for FY 2012 of:  The rate is applicable to all transmission transactions inside WACM in excess of any Federal Entitlements. For Federal Entitlements, the cost for this service will be included in the firm electric service rates. Customers with generators providing WACM with VAR Support Service may be excluded from the application of this rate. Any such exclusion must be documented in the customer's Service Agreement. Regulation and Frequency Response Service The formula rate for Regulation Service has two different applications: 1. 
                        *Load-based Assessment.*
                         The formula for the Load-based Assessment is as follows:  The rate applies to all entities' auxiliary load (total metered load less Federal Entitlements) and also to the installed nameplate capacity of intermittent generators serving load inside WACM. The revenue requirement will include costs such as plant costs, purchases of a regulation product, purchases of power in support of the generating 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 as follows. First, the annual costs for plants used to regulate is calculated by multiplying the net plant costs by the FCR for generation. Annual Costs = 17.847% × $159,716,812 Annual Costs = $28,504,334 Then, the annual cost per unit of capacity for regulating plants is calculated by dividing the annual costs for regulating plants 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. Current analyses indicate that 75 MW of capacity will be required for WACM Regulation Service for FY 2012. Of this total, 55 MW will be supplied by LAP plants and 20 MW will be supplied by CRSP plants. Regulating Plant Costs (LAP) = $60.32 × 55,000 kW Regulating Plant Costs (LAP) = $3,317,614 CRSP regulating plant costs are calculated in a similar manner. Inserting this and other financial data for FY 2010 into the formula results in the following Revenue Requirement: LAP Plant Costs
$3,317,614Purchase Power Costs in Support of Regulation
5,049,193Lost Sales Opportunities from having to generate in off-peak hours
1,320,110Transmission Costs for Trapped Regulating Units
1,042,800Purchases of Transmission
52,598CRSP Plant Costs
590,429Annual Revenue Requirement
11,372,744
 The load inside WACM requiring Regulation Service and the installed nameplate capacity of intermittent resources serving load inside WACM are 2,791,390 kW and 73,220 kW, respectively.  2. 
                        *Self-Provision Assessment.*
                         Western allows entities with AGC to self-provide for all or a portion of their loads. Entities with AGC are known as Sub-Balancing Authorities (SBA) and must meet all of the following criteria: a. Have a well-defined boundary, with WACM-approved revenue-quality metering, accurate as defined by NERC, to include MW flow data availability at 6-second or smaller intervals; b. Have AGC capability; and c. Have demonstrated Regulation Service capability. Self-provision will be measured by use of the entity's 1-minute average ACE to determine the amount of self-provision. The ACE will be used to calculate Regulation Service charges every hour as follows: a. If the entity's 1-minute average ACE for the hour is less than or equal to 0.5 percent of its hourly average load, no Regulation Service charges will be assessed by WACM. b. If the entity's 1-minute average ACE for the hour is greater than or equal to 1.5 percent of its hourly average load, WACM will assess full Regulation Service charges using the Load-based Assessment applied to the entity's 12-cp load for that month. c. If the entity's 1-minute average ACE for the hour is greater than 0.5 percent of its hourly average load, but less than 1.5 percent of its hourly average load, WACM will assess Regulation Service charges based on linear interpolation of zero charge and full charge, using the Load-based Assessment applied to the entity's 12-cp load for that month. d. 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 full Load-based Assessment described above. Alternative Arrangements 1. 
                        *Exporting Intermittent Resource Requirement:*
                         An entity that exports the output from an intermittent generator to another Balancing Authority will be required to dynamically meter or dynamically schedule that resource out of WACM to another Balancing Authority unless arrangements, satisfactory to Western, are made for that entity to acquire this service from a third party or self-supply (as outlined below). An intermittent generator is one that is volatile and variable due to factors beyond direct operational control and, therefore, is not dispatchable. 2. 
                        *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. This entity must have revenue quality metering at every load and generation point, accurate as defined by NERC, to include MW flow data availability at 6-second or smaller intervals. WACM will evaluate the entity's metering, telecommunications and regulating resource, as well as the 
                        ( print page 61195)
                        required level of regulation, and determine whether the entity qualifies to self-supply under this provision. If approved, the entity will be required to enter into a separate agreement with Western, which will specify the terms of the self-supply application. Energy Imbalance Service WACM provides Energy Imbalance Service using a penalty and bandwidth structure with three deviation bands as follows. The term “metered load” is defined to be “metered load adjusted for losses.” 1. An imbalance of less than or equal to 1.5 percent of metered load (or 4 MW, whichever is greater) for any hour will be settled financially at 100 percent of the WACM weighted average hourly price. Each hour will stand on its own—there will be no monthly netting. 2. An imbalance between 1.5 percent and 7.5 percent of metered load (or 4 to 10 MW, whichever is greater) for any hour will be settled financially at 90 percent of WACM weighted average hourly price when net energy scheduled exceeds metered load or 110 percent of the WACM weighted average hourly price when net energy scheduled is less than metered load. 3. An imbalance greater than 7.5 percent of metered load (or 10 MW, whichever is greater) for any hour will be settled financially at 75 percent of the WACM weighted average hourly price when net energy scheduled exceeds metered load or 125 percent of the WACM weighted average hourly price when net energy scheduled is less than metered load. Aggregate Imbalance, Pricing, and Settlement All Energy Imbalance Service provided by WACM will be accounted for hourly and settled financially after the end of each month. The WACM aggregate imbalance will determine the pricing used in all settlements, including those subject to a penalty. For each hour, the gross energy imbalance for all entities inside WACM will be totaled/netted to determine an aggregate energy imbalance for WACM. The sign of the aggregate energy imbalance will determine whether WACM sale or purchase pricing will be used for settling imbalances in that hour. A calculated surplus will dictate the use of sale pricing; a calculated deficit will dictate the use of purchase pricing. When there are no real-time sales or purchases within an hour, pricing defaults will be applied in the following order: 1. Weighted average sale or purchase pricing for the day (on- and off-peak). 2. Weighted average sale or purchase pricing for the current month (on- and off-peak). 3. Weighted average sale or purchase pricing for the prior month (on- and off-peak). 4. Weighted average sale or purchase pricing for the month immediately prior to the prior month (and continuing in this manner until sale or purchase pricing is located) (on- and off-peak). Expansion of the Bandwidth Expansion of the bandwidth may be done to accommodate the following: (1) Response to physical resource loss; (2) transition of large thermal resources. Details are as follows: 1. Western will expand the bandwidth during an event established by a Western-recognized reserve-sharing group, such as the Rocky Mountain Reserve Group. A response made by a member of the reserve group will be accounted for by an after-the-fact schedule. Normally, these events are 1-2 hours in duration. Since the after-the-fact schedule replaces lost generation, no expansion will be necessary for the entity receiving the response. The expanded bandwidth will apply to the customer that increased generation in response to the event and will be based on the magnitude of that customer's generation response. 2. During transition of large base-load thermal resources (capacity greater than 200 MW) between off-line and on-line following a reserve sharing group response, Western may expand the bandwidth to eliminate all penalties during hours in which the unit generates less than the predetermined minimum scheduling level. Western may not have access to information necessary to determine these hours for some generators and will not have access to information on events for reserve sharing groups outside RMR. Customers should request bandwidth expansion in hours in which they believe it to be warranted. Western may request additional information for its decision as to whether to grant the request. Bandwidth will not be expanded when ramping services have been acquired by another entity. Balancing Authority Operating Constraints Western reserves the right to offer no credit for Energy Imbalance Service over-deliveries during times of WACM operating constraints, such as “must-run” hydrologic conditions, or times when WACM cannot dispose of surplus energy. Due to the unpredictable nature of hour-to-hour energy imbalances and the very short notice for disposition of over-deliveries, WACM may experience some hours of zero-value sales and may eliminate credits in these hours. If WACM is unable to dispose of the entire net over-delivery and operating criteria for the Balancing Authority are not met, there may be financial sanctions to Western from reliability oversight agencies, such as NERC or WECC. In these cases, credits to customers will be eliminated and customers over-delivering may share in the cost of the sanction. Also, there may be conditions under which customers who under-deliver may share in any sanctions imposed on Western by reliability oversight agencies. Generator Imbalance Service WACM will provide Generator Imbalance Service to the following customers: 1. Jointly-owned generators whose output is shared by several entities. At the written request of all entities who jointly own the generator's output, WACM will accept allocations of the generation among the participants. In this situation, a participant's share of actual generation will be included in its separate Energy Imbalance calculation. 2. Intermittent generators. At the written request of the customer, WACM will include the intermittent generator(s) in the customer's Energy Imbalance calculation. The customer makes this choice with the understanding that the intermittent generator will be subject to 3rd band (25 percent) penalties (see formula rate details below). 3. Non-intermittent generators serving load only outside WACM. An entity's solely-owned non-intermittent generator serving load inside WACM will be included in its Energy Imbalance Service calculation. WACM will provide Generator Imbalance Service using a penalty and bandwidth structure with three deviation bands as follows: 1. An imbalance of less than or equal to 1.5 percent of metered generation (or 4 MW, whichever is greater) for any hour is settled financially at 100 percent of the WACM weighted average hourly price. 2. An imbalance between 1.5 percent and 7.5 percent of metered generation (or 4 to 10 MW, whichever is greater) for any hour is settled financially at 90 percent of the WACM weighted average hourly price when actual generation exceeds scheduled generation or 110 percent of the WACM weighted average hourly price when actual generation is less than scheduled generation. 3. An imbalance greater than 7.5 percent of metered generation (or 10 
                        ( print page 61196)
                        MW, whichever is greater) for any hour is settled financially at 75 percent of the WACM weighted average hourly price when actual generation exceeds scheduled generation or 125 percent of the WACM weighted average hourly price when actual generation is less than scheduled generation. Intermittent generators will be exempt from the 25 percent penalty band. All imbalances greater than 1.5 percent of metered generation for an intermittent generator will be subject only to a 10 percent penalty. The features of Energy Imbalance Service described above under Aggregate Imbalance, Pricing, and Settlement, Expansion of the Bandwidth, and Balancing Authority Operating Constraints, also apply to Generator Imbalance Service. Penalty Elimination In any hour, Western will charge a customer a penalty for either Generator Imbalance Service or Energy Imbalance Service, but not both, unless the imbalances aggravate rather than offset each other. In an hour in which penalties on offsetting imbalances would exist based on the separate imbalance calculations, Western will remove the penalty from the Generator Imbalance calculation. There will be no penalty elimination for jointly-owned generators whose participants have a separate Energy Imbalance calculation. Administrative Charge In the Notice of Proposed Rates (76 FR 5148), Western proposed to assess an administrative charge on each monthly settlement under both Energy Imbalance and Generator Imbalance Services. After further analysis and customer input, Western has decided not to implement an administrative charge under either service. Operating Reserve—Spinning and Supplemental WACM has no long-term Reserves available for sale. At a customer's request, WACM will purchase and pass through the cost of Reserves and any activation energy, plus a fee for administration. For all Reserves purchased, the customer will be responsible for providing the transmission to deliver the Reserves. Ancillary Services Comments Western received one written comment concerning the Ancillary Services during the public consultation and comment period. This comment has been paraphrased where appropriate, without compromising the meaning of the comment. *Comment:*
                         The customer requested that, for Regulation Service, rather than requiring an intermittent generator that exports its output to dynamically meter or dynamically schedule the generation out of WACM, Western open communications to pursue other options to avoid this requirement. The customer expressed concern about the cost of implementing this requirement and the effects the unexpected costs will have on member municipalities and their customers. The customer also noted that these additional costs were not known at the inception of its existing projects when cost analyses were being performed. *Response:*
                         Western thanks the customer for its comment. As noted above under Regulation and Frequency Response Service (Alternative Arrangements), Western has included as a part of the Regulation Service rate schedule, a condition under which an exporting intermittent generator will not have to be dynamically removed from WACM. Under this condition, the entity must make arrangements, satisfactory to Western, to acquire Regulation and Frequency Response Service from a third party or self-supply it. Western believes that this is a reasonable requirement that will not place an undue burden on existing or potential customers who will export intermittent generation from WACM, but will support the concept in Western's Tariff that WACM is required to provide Ancillary Services only for Load-Serving Entities. Availability of Information All brochures, studies, comments, letters, memorandums, or other documents that Western used to develop the Provisional Formula Rates are available for inspection and copying at the Rocky Mountain Regional Office, located at 5555 East Crossroads Boulevard, Loveland, Colorado. 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 Environmental Compliance In compliance with the National Environmental Policy Act (NEPA) of 1969 (42 U.S.C. 4321 et seq.), Council on Environmental Quality Regulations (40 CFR parts 1500-1508), and DOE NEPA Regulations (10 CFR part 1021), Western has determined that this action is categorically excluded from preparing an environmental assessment or an environmental impact statement. Determination Under Executive Order 12866 Western has an exemption from centralized regulatory review under Executive Order 12866; accordingly, no clearance of this notice by the Office of Management and Budget is required. Submission to the Federal Energy Regulatory Commission The formula rates herein confirmed, approved, and placed into effect on an interim basis, together with supporting documents, will be submitted to FERC for confirmation and final approval. Order In view of the foregoing, and under the authority delegated to me, I confirm and approve on an interim basis, effective on the first full billing period on or after October 1, 2011, formula rates for Loveland Area Projects Transmission and Western Area Colorado Missouri Balancing Authority Ancillary Services under Rate Schedules L-NT1, L-FPT1, L-NFPT1, L-AS1, L-AS2, L-AS3, L-AS4, L-AS5, L-AS6, L-AS7, L-AS9, and L-UU1. By this order, I am placing the rates into effect in less than 30 days to meet contract deadlines, to avoid financial difficulties, and to provide rates for new services. These rate schedules shall remain in effect on an interim basis, pending FERC's confirmation and approval of them or substitute formula rates on a final basis through September 30, 2016. Dated: September 2, 2011. Daniel B. Poneman, Deputy Secretary.
 Rate Schedule L-AS1 Schedule 1 to Tariff October 1, 2011 United States Department of Energy Western Area Power Administration Rocky Mountain Region Western Area Colorado Missouri Balancing Authority Scheduling, System Control, and Dispatch Service Applicable Scheduling, System Control, and Dispatch Service is required to schedule the movement of power into, out of, inside, or through the Western Area Colorado Missouri Balancing Authority (WACM). This service must be purchased from the WACM operator. The rate will be applied to all 
                        ( print page 61197)
                        schedules, except those for the delivery of transmission losses to WACM. Unless other arrangements are made with Western, the rate will be divided equally among the transmission providers displayed in the schedule that are inside WACM. The charges applicable to non-Federal transmission will be assessed to those transmission providers. The charges applicable to Federal transmission will be included in the Federal transmission service rates. WACM will accept any number of scheduling changes over the course of the day without any additional charge. Effective The first day of the first full billing period beginning on or after October 1, 2011, through September 30, 2016. Formula Rate  Rate The rate to be in effect October 1, 2011, through September 30, 2012, is $24.22 per schedule per day. A revised rate will go into effect October 1 of each year of the effective rate period based on the formula above and updated financial and schedule data. Western will notify the Customer annually of the revised rate before October 1. Any change to the rate for Scheduling, System Control, and Dispatch Service will be listed in a revision to this rate schedule issued under applicable Federal laws, regulations, and policies and made part of the applicable service agreement. Rate Schedule L-AS2 Schedule 2 to Tariff October 1, 2011 United States Department of Energy Western Area Power Administration Rocky Mountain Region Western Area Colorado Missouri Balancing Authority Reactive Supply and Voltage Control from Generation or Other Sources Service Applicable To maintain transmission voltages on all transmission facilities within acceptable limits, generation facilities under the control of the Western Area Colorado Missouri Balancing Authority (WACM) are operated to produce or absorb reactive power. Thus, Reactive Supply and Voltage Control from Generation or Other Sources Service (VAR Support Service) is provided for each transaction on the transmission facilities. The amount of VAR Support Service supplied to the Customer's (Federal Transmission Customers and customers on others' transmission systems inside WACM) transactions will be based on the VAR Support Service necessary to maintain transmission voltages within limits that are generally accepted in the region and consistently adhered to by WACM. The Customer must purchase this service from the WACM operator. Customers with generators providing WACM with VAR Support Service may be excluded from the application of this rate. Any such exclusion must be documented in the Customer's service agreement. Effective The first day of the first full billing period beginning on or after October 1, 2011, through September 30, 2016. Formula Rate  
 
 Rate The rate to be in effect October 1, 2011, through September 30, 2012, is: Monthly
$0.305/kW-monthWeekly
$0.070/kW-weekDaily
$0.010/kW-dayHourly
$0.000418/kWh
 A revised rate will go into effect October 1 of each year of the effective rate period based on the formula above and updated financial and load data. Western will notify the Customer annually of the revised rate before October 1. Any change to the rate for VAR Support Service will be listed in a revision to this rate schedule issued under applicable Federal laws, regulations, and policies and made part of the applicable service agreement. Rate Schedule L-AS3 Schedule 3 to Tariff October 1, 2011 United States Department of Energy Western Area Power Administration Rocky Mountain Region Western Area Colorado Missouri Balancing Authority Regulation and Frequency Response Service Applicable Regulation and Frequency Response Service (Regulation Service) is necessary to provide for the continuous balancing of resources with obligations, and for maintaining scheduled interconnection frequency at sixty cycles per second (60 Hz). Regulation Service is accomplished by committing on-line generation whose output is raised or lowered as necessary, predominantly through the use of automatic generation control (AGC) equipment, to follow the moment-by-moment changes in load. The obligation to maintain this balance between resources and load lies with the Western Area Colorado Missouri Balancing Authority (WACM) operator. Customers (Federal Transmission Customers and customers on others' transmission systems inside WACM) must purchase this service from WACM or make alternative comparable arrangements to satisfy their Regulation Service obligations. Types There are two different applications of this Formula Rate: 1. 
                        *Load-based Assessment:*
                         The rate for the load-based assessment is reflected in the Formula Rate section and is applied to entities that take Regulation Service from WACM. This load-based rate is assessed on an entity's auxiliary load (total metered load less Federal entitlements) and is also applied to the installed nameplate capacity of all intermittent generators serving load inside WACM. 2. 
                        *Self-provision Assessment:*
                         Western allows entities with AGC to self-provide for all or a portion of their loads. Entities with AGC are known as Sub-Balancing Authorities (SBA) and must meet all of the following criteria: a. Have a well-defined boundary, with WACM-approved revenue-quality metering, accurate as defined by the North American Electric Reliability Corporation (NERC), to include MW flow data availability at 6-second or smaller intervals; b. Have AGC capability; c. Demonstrate Regulation Service capability; and d. Execute a contract with WACM: i. Provide all requested data to WACM. ii. Meet SBA error criteria as described under section 2.1 below. 2.1. Self-provision is measured by use of the entity's 1-minute average Area Control Error (ACE) to determine the amount of self-provision. The ACE is used to calculate the Regulation Service charges every hour as follows: a. If the entity's 1-minute average ACE for the hour is less than or equal to 0.5 percent of its hourly average load, no Regulation Service charge is assessed by WACM for that hour. b. If the entity's 1-minute average ACE for the hour is greater than or equal to 1.5 percent of its hourly average load, WACM assesses Regulation Service charges to the entity's entire auxiliary load, using the hourly Load-based Assessment applied to the entity's auxiliary 12-cp load for that month. c. If the entity's 1-minute average ACE for the hour is greater than 0.5 percent of its hourly average load, but less than 1.5 percent of its hourly average load, WACM assesses Regulation Service charges based on linear interpolation of zero charge and full charge, using the hourly Load-based Assessment applied to the entity's auxiliary 12-cp load for that month. d. Western monitors the entity's Self-provision on a regular basis. If Western determines that the entity has not been attempting to self-regulate, WACM will, upon notification, employ the Load-based Assessment described in No. 1, above. Alternative Arrangements Exporting Intermittent Resource Requirement: An entity that exports the output from an intermittent generator to another balancing authority will be required to dynamically meter or dynamically schedule that resource out of WACM to another balancing authority unless arrangements, satisfactory to Western, are made for that entity to acquire this service from a third party or self-supply (as outlined below). An intermittent generator is one that is volatile and variable due to factors beyond direct operational control and, therefore, is not dispatchable. 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. This entity must have revenue quality metering at every load and generation point, accurate as defined by NERC, to include MW flow data availability at 6-second or smaller intervals. Western 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. If approved, the entity is required to enter into a separate agreement with Western which will specify the terms of the self-supply application. Customer Accommodation For entities unwilling to take Regulation Service, self-provide it as described above, or acquire the service from a third party, Western will assist the entity in dynamically metering its loads/resources to another balancing authority. Until such time as that meter configuration is accomplished, the entity will be responsible for charges assessed by WACM under the rate in effect. Effective The first day of the first full billing period beginning on or after October 1, 2011, through September 30, 2016. Formula Rate 
 
  Rate The rate to be in effect October 1, 2011, through September 30, 2012, for Nos. 1 and 2, as described above in the “Types” section of this rate schedule, is: Monthly
$0.331/kW-monthWeekly
$0.076/kW-weekDaily
$0.011/kW-dayHourly
$0.000458/kWh
 A revised rate will go into effect October 1 of each year of the effective rate period based on the formula above and updated financial and load data. Western will notify the Customer annually of the revised rate before October 1. Any change to the rate for Regulation Service will be listed in a revision to this rate schedule issued under applicable Federal laws, regulations, and policies and made part of the applicable service agreement. Rate Schedule L-AS4 Schedule 4 to Tariff October 1, 2011 United States Department of Energy Western Area Power Administration Rocky Mountain Region Western Area Colorado Missouri Balancing Authority Energy Imbalance Service Applicable The Western Area Colorado Missouri Balancing Authority (WACM) provides Energy Imbalance Service when there is a difference between a Customer's (Federal Transmission Customers and customers on others' transmission systems inside WACM) resources and obligations. Energy Imbalance is calculated as resources minus obligations (adjusted for transmission and transformer losses) for any combination of generation, scheduled transfers, transactions, or actual load integrated over each hour. Customers inside WACM must either obtain this service from WACM or make alternative comparable arrangements to satisfy their Energy Imbalance Service obligation. This rate applies to all customers with load inside WACM. Effective The first day of the first full billing period beginning on or after October 1, 2011, through September 30, 2016. Formula Rate Imbalances are calculated in three deviation bands as follows. The term “metered load” is defined to be “metered load adjusted for losses.” 1. An imbalance of less than or equal to 1.5 percent of metered load (or 4 MW, whichever is greater) for any hour is settled financially at 100 percent of the WACM weighted average hourly price. 2. An imbalance between 1.5 percent and 7.5 percent of metered load (or 4 to 10 MW, whichever is greater) for any hour is settled financially at 90 percent of the WACM weighted average hourly price when net energy scheduled exceeds metered load or 110 percent of the WACM weighted average hourly price when net energy scheduled is less than metered load. 3. An imbalance greater than 7.5 percent of metered load (or 10 MW, whichever is greater) for any hour is settled financially at 75 percent of the WACM weighted average hourly price when net energy scheduled exceeds metered load or 125 percent of the WACM weighted average hourly price when net energy scheduled is less than metered load. All Energy Imbalance Service provided by WACM is accounted for hourly and settled financially. The WACM aggregate imbalance determines the pricing used in all deviation bands. A surplus dictates the use of sale pricing; a deficit dictates the use of purchase pricing. When no hourly data is available, the pricing defaults for sales and purchase pricing are applied in the following order: 1. Weighted average sale or purchase pricing for the day (on- and off-peak). 2. Weighted average sale or purchase pricing for the month (on- and off-peak). 3. Weighted average sale or purchase pricing for the prior month (on- and off-peak). 4. Weighted average sale or purchase pricing for the month prior to the prior month (and continuing until sale or purchase pricing is located) (on- and off-peak). Expansion of the bandwidth may be allowed during the following instances: Response to the loss of a physical resource.
                    During transition of large base-load thermal resources (capacity greater than 200 MW) between off-line and on-line following a reserve sharing group response, when the unit generates less than the predetermined minimum scheduling level. During periods of balancing authority operating constraints, Western reserves the right to eliminate credits for over-deliveries. The cost to Western of any penalty assessed by a regulatory authority due to a violation of operating standards resulting from under- or over-delivery of energy may be passed through to Energy Imbalance Service customers. Rate The bandwidths, penalties, and pricing described above are in effect October 1, 2011, through September 30, 2012. Any change to the rate for Energy Imbalance Service will be listed in a revision to this rate schedule issued under applicable Federal laws, regulations, and policies and made part of the applicable service agreement. Rate Schedule L-AS5 Schedule 5 to Tariff October 1, 2011 United States Department of Energy Western Area Power Administration Rocky Mountain Region Western Area Colorado Missouri Balancing Authority Operating Reserve—Spinning Reserve Service Applicable Spinning Reserve Service (Reserves) is needed to serve load immediately in the event of a system contingency. Reserves may be provided by generating units that are on-line and loaded at less than maximum output. The Customers (Federal Transmission Customers and customers on others' transmission system inside Western Area Colorado Missouri Balancing Authority (WACM)) must either purchase this service from WACM or make alternative comparable arrangements to satisfy their Reserves obligation.
                        ( print page 61200) Effective The first day of the first full billing period beginning on or after October 1, 2011, through September 30, 2016. Formula Rate WACM has no long-term Reserves available for sale. At a Customer's request, WACM will purchase Reserves and pass through the cost of Reserves and any activation energy, plus a fee for administration. The Customer will be responsible for providing the transmission to deliver the Reserves. Rate Schedule L-AS6 Schedule 6 to Tariff October 1, 2011 United States Department of Energy Western Area Power Administration Rocky Mountain Region Western Area Colorado Missouri Balancing Authority Operating Reserve—Supplemental Reserve Service Applicable Supplemental Reserve Service (Reserves) is needed to serve load in the event of a system contingency; however, it is not available immediately to serve load but rather within a short period of time. Reserves may be provided by generating units that are on-line but unloaded, by quick-start generation, or by interruptible load. The Customers (Federal Transmission Customers and customers on others' transmission system inside Western Area Colorado Missouri Balancing Authority (WACM)) must either purchase this service from WACM or make alternative comparable arrangements to satisfy their Reserves obligation. Effective The first day of the first full billing period beginning on or after October 1, 2011, through September 30, 2016. Formula Rate WACM has no long-term Reserves available for sale. At a Customer's request, WACM will purchase Reserves and pass through the cost of Reserves and any activation energy, plus a fee for administration. The Customer will be responsible for providing the transmission to deliver the Reserves. Rate Schedule L-AS7 October 1, 2011 United States Department of Energy Western Area Power Administration Rocky Mountain Region Western Area Colorado Missouri Balancing Authority Transmission Losses Service Applicable The Western Area Colorado Missouri Balancing Authority (WACM) provides Transmission Losses Service to all Transmission Service Providers who market transmission inside WACM. The loss factor currently in effect is posted on the Rocky Mountain Region (RMR) Open Access Same-Time Information System (OASIS) Web site. Effective The first day of the first full billing period beginning on or after October 1, 2011, through September 30, 2016. Formula Rate Transmission Losses are assessed for all real-time and prescheduled transactions on transmission facilities inside WACM. The Customer is allowed the option of energy repayment or financial repayment. Energy repayment may be either concurrently or seven days later, to be delivered using the same profile as the related transmission transaction. Customers must declare annually their preferred methodology of energy payback. When a transmission loss energy obligation is not provided (or is under-provided) by a Customer for a transmission transaction, the energy still owed for Transmission Losses is calculated and a charge is assessed to the Customer, based on the WACM weighted average hourly purchase price. Pricing for loss energy due 7 days later, and not received by WACM, will be priced at the 7-day-later-price based on the WACM weighted average hourly purchase price. There will be no financial compensation or energy return to Customers for over-delivery of Transmission Losses, as there should be no condition beyond the control of the Customer that results in overpayment. Rate This loss factor, as posted on the RMR OASIS, is in effect October 1, 2011, through September 30, 2012. Customers may settle financially or with energy. The pricing for this service will be the WACM weighted average hourly purchase price. When no hourly data is available, pricing defaults will be applied in the following order: 1. Weighted average purchase pricing for the day (on- and off-peak). 2. Weighted average purchase pricing for the current month (on- and off-peak). 3. Weighted average purchase pricing for the prior month (on- and off-peak). 4. Weighted average purchase pricing for the month prior to the prior month (and continuing until or purchase pricing is located) (on- and off-peak). Any change to the rate for Transmission Losses Service will be listed in a revision to this rate schedule issued under applicable Federal laws, regulations, and policies and made part of the applicable service agreement. Rate Schedule L-FPT1 Schedule 7 to Tariff October 1, 2011 United States Department of Energy Western Area Power Administration Rocky Mountain Region Loveland Area Projects Long-Term Firm and Short-Term Firm Point-To-Point Transmission Service Applicable The Transmission Customer shall compensate the Loveland Area Projects (LAP) each month for Reserved Capacity under the applicable Firm Point-to-Point Transmission Service Agreement and the rate outlined herein. Discounts Three principal requirements apply to discounts for transmission service as follows: (1) Any offer of a discount made by LAP must be announced to all eligible customers solely by posting on the Rocky Mountain Region's Open Access Same-Time Information System web site (OASIS); (2) any customer-initiated requests for discounts, including requests for use by the LAP merchant, must occur solely by posting on the OASIS; and (3) once a discount is negotiated, details must be immediately posted on the OASIS. For any discount agreed upon for service on a path, from Point(s) of Receipt to Point(s) of Delivery, LAP must offer the same discounted transmission service rate for the same time period to all eligible customers on all unconstrained transmission paths that go to the same point(s) of delivery on the transmission system.
                        ( print page 61201) Effective The first day of the first full billing period beginning on or after October 1, 2011, through September 30, 2016. Formula Rate  Rate The rate to be in effect October 1, 2011, through September 30, 2012, is: Maximum ofYearly
$41.80/kW of reserved capacity per yearMonthly
$3.48/kW of reserved capacity per monthWeekly
$0.80/kW of reserved capacity per weekDaily
$0.11/kW of reserved capacity per day
 A revised rate will go into effect October 1 of each year of the effective rate period based on the formula above, updated financial and load projections, and the true-up of previous projections. Western will notify the Transmission Customer annually of the revised rate before October 1. Any change to the rate for Long-Term Firm and Short-Term Firm Transmission Service will be listed in a revision to this rate schedule issued under applicable Federal laws, regulations, and policies and made part of the applicable service agreement. Rate Schedule L-NFPT1 Schedule 8 to Tariff October 1, 2011 United States Department of Energy Western Area Power Administration Rocky Mountain Region Loveland Area Projects Non-Firm Point-To-Point Transmission Service Applicable The Transmission Customer will compensate Loveland Area Projects (LAP) for Non-Firm Point-to-Point Transmission Service under the applicable Non-Firm Point-to-Point Transmission Service Agreement and the rate outlined herein. Discounts Three principal requirements apply to discounts for transmission service as follows: (1) Any offer of a discount made by LAP must be announced to all eligible customers solely by posting on Rocky Mountain Region's Open Access Same-Time Information System web site (OASIS); (2) any customer-initiated requests for discounts, including requests for use by the LAP merchant, must occur solely by posting on the OASIS; and (3) once a discount is negotiated, details must be immediately posted on the OASIS. For any discount agreed upon for service on a path, from Point(s) of Receipt to Point(s) of Delivery, LAP must offer the same discounted transmission service rate for the same time period to all eligible customers on all unconstrained transmission paths that go to the same point(s) of delivery on the transmission system. Effective The first day of the first full billing period beginning on or after October 1, 2011, through September 30, 2016. Formula Rate  Rate The rate to be in effect October 1, 2011, through September 30, 2012, is: Maximum ofYearly
$41.80/kW of reserved capacity per yearMonthly
$3.48/kW of reserved capacity per monthWeekly
$0.80/kW of reserved capacity per weekDaily
$0.11/kW of reserved capacity per dayHourly
4.77 mills/kWh
 A revised rate will go into effect October 1 of each year of the effective rate period based on the formula above, updated financial and load projections, and the true-up of previous projections. Western will notify the Transmission Customer annually of the revised rate before October 1. Any change to the rate for Non-Firm Point-to-Point Transmission Service will be listed in a revision to this rate schedule issued under applicable Federal laws, regulations, and policies and made part of the applicable service agreement. Rate Schedule L-NT1 Schedule H to Tariff October 1, 2011 United States Department of Energy Western Area Power Administration Rocky Mountain Region Loveland Area Projects Annual Transmission Revenue Requirement for Network Integration Transmission Service Applicable Transmission Customers will compensate the Loveland Area Projects each month for Network Integration Transmission Service under the applicable Network Integration Transmission Service Agreement and the Annual Transmission Revenue Requirement described herein.
                        ( print page 61202) Effective The first day of the first full billing period beginning on or after October 1, 2011, through September 30, 2016. Formula Rate  Rate The Annual Transmission Revenue Requirement in effect October 1, 2011, through September 30, 2012, is $56,775,913. A revised Annual Transmission Revenue Requirement will go into effect October 1 of each year of the effective rate period based on updated financial projections and the true-up of previous projections. Western will notify the Transmission Customer annually of the revised Annual Transmission Revenue Requirement before October 1. Any change to the rate for Network Integration Transmission Service will be listed in a revision to this rate schedule issued under applicable Federal laws, regulations, and policies and made part of the applicable service agreement. Rate Schedule L-AS9 Schedule 9 to Tariff October 1, 2011 United States Department of Energy Western Area Power Administration Rocky Mountain Region Western Area Colorado Missouri Balancing Authority Generator Imbalance Service Applicable The Western Area Colorado Missouri (WACM) Balancing Authority provides Generator Imbalance Service when there is a difference between a Customer's (Federal Transmission Customers and customers on others' transmission systems inside WACM) resources and obligations. Generator Imbalance is calculated as actual generation minus scheduled generation for each hour. Customers inside WACM must either obtain this service from WACM or make alternative comparable arrangements to satisfy their Generator Imbalance Service obligation. This rate applies to all jointly-owned generators (unless arrangements are made to allocate actual generation to each individual owner), intermittent generators (unless arrangements are made to assess the intermittent generator under Rate Schedule L-AS4), and any non-intermittent generators serving load only outside WACM. Effective The first day of the first full billing period beginning on or after October 1, 2011, through September 30, 2016. Formula Rate Imbalances are calculated in three deviation bands as follows: 1. An imbalance of less than or equal to 1.5 percent of metered generation (or 4 MW, whichever is greater) for any hour is settled financially at 100 percent of the WACM weighted average hourly price. 2. An imbalance between 1.5 percent and 7.5 percent of metered generation (or 4 to 10 MW, whichever is greater) for any hour is settled financially at 90 percent of the WACM weighted average hourly price when actual generation exceeds scheduled generation or 110 percent of the WACM weighted average hourly price when actual generation is less than scheduled generation. 3. An imbalance greater than 7.5 percent of metered generation (or 10 MW, whichever is greater) for any hour is settled financially at 75 percent of the WACM weighted average hourly price when actual generation exceeds scheduled generation or 125 percent of the WACM weighted average hourly price when actual generation is less than scheduled generation. Intermittent generators are exempt from 25 percent penalties. All imbalances greater than 1.5 percent of metered generation are subject only to a 10 percent penalty. All Generator Imbalance Service provided by WACM is accounted for hourly and settled financially. The WACM aggregate imbalance determines the pricing used in all deviation bands. A surplus dictates the use of sale pricing; a deficit dictates the use of purchase pricing. When no hourly data is available, the pricing defaults for sales and purchase pricing are applied in the following order: 1. Weighted average sale or purchase pricing for the day (on- and off-peak). 2. Weighted average sale or purchase pricing for the current month (on- and off-peak). 3. Weighted average sale or purchase pricing for the prior month (on- and off-peak). 4. Weighted average sale or purchase pricing for the month prior to the prior month (and continuing until sale or purchase pricing is located) (on- and off-peak). Expansion of the bandwidth may be allowed during the following instances: Response to the loss of a physical resource.
                    During transition of large base-load thermal resources (capacity greater than 200 MW) between off-line and on-line following a reserve sharing group response, when the unit generates less than the predetermined minimum scheduling level. During periods of balancing authority operating constraints, Western reserves the right to eliminate credits for over-deliveries. The cost to Western of any penalty assessed by a regulatory authority due to a violation of operating standards resulting from under- or over-delivery of energy may be passed through to Generator Imbalance Service customers. Rate The bandwidths, penalties, and pricing described above are in effect October 1, 2011, through September 30, 2012. Any change to the rate for Generator Imbalance Service will be listed in a revision to this rate schedule issued under applicable Federal laws, regulations, and policies and made part of the applicable service agreement.
                        ( print page 61203) Rate Schedule L-UU1 Schedule 10 to Tariff October 1, 2011 United States Department of Energy Western Area Power Administration Rocky Mountain Region Loveland Area Projects Unreserved Use Penalties Applicable The Transmission Customer shall compensate the Loveland Area Projects (LAP) each month for any unreserved use of the transmission system (Unreserved Use) under the applicable transmission service rates as outlined herein. Unreserved Use occurs when an eligible customer uses transmission service that it has not reserved or a Transmission Customer uses transmission service in excess of its reserved capacity. Unreserved Use may also include a Customer's failure to curtail transmission when requested. Penalty Rate The penalty rate for a Transmission Customer that engages in Unreserved Use is 200 percent of LAP's approved rate for firm point-to-point transmission service assessed as follows: the Unreserved Use Penalty for a single hour of Unreserved Use is based upon the rate for daily firm point-to-point service. The Unreserved Use Penalty for more than one assessment for a given duration (e.g., daily) increases to the next longest duration (e.g., weekly). The Unreserved Use Penalty for multiple instances of Unreserved Use (e.g., more than one hour) within a day is based on the rate for daily firm point-to-point service. The Unreserved Use Penalty for multiple instances of Unreserved Use isolated to one calendar week is based on the rate for weekly firm point-to-point service. The Unreserved Use Penalty for multiple instances of Unreserved Use during more than one week in a calendar month is based on the rate 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, is required to pay for all ancillary services that were provided by the Western Area Colorado Missouri Balancing Authority and associated with the Unreserved Use. The Customer will pay for ancillary services based on the amount of transmission service it used and did not reserve. Effective The first day of the first full billing period beginning on or after October 1, 2011, through September 30, 2016. Rate The rate for Unreserved Use Penalties is 200 percent of LAP's approved rate for firm point-to-point transmission service assessed as described above. Any change to the rate for Unreserved Use Penalties will be listed in a revision to this rate schedule issued under applicable Federal laws, regulations, and policies and made part of the applicable service agreement. [FR Doc. 2011-23391 Filed 9-12-11; 8:45 am] Editorial Note: FR Doc. 2011-23391 which was originally published on pages 56433-56452 in the issue of Tuesday, September 13, 2011 is being republished in its entirety in the issue of Monday, October 3, 2011 because of editing errors.


# Footnotes

1.
    
                             WAPA-106 was approved by FERC on a final basis on January 31, 2005, in Docket No. EF2-04-5182-000 (110 FERC ¶ 62,084). Back to Citation
 2.
    
                             WAPA-141, Extension of Rate Order No. WAPA-106 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
 4.
    
                             WAPA-154, Extension of Rate Order Nos. WAPA-106 and WAPA-118 through February 28, 2013. 76 FR 1429, January 10, 2011. Back to Citation


[FR Doc. R1-2011-23391 Filed 9-30-11; 8:45 am] BILLING CODE 6450-01-P