Pick-Sloan Missouri Basin Program-Eastern Division Transmission and Ancillary Services-Rate Order No. WAPA-122, 55821-55834 [05-19039]

Download as PDF Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices DEPARTMENT OF ENERGY Western Area Power Administration Pick-Sloan Missouri Basin Program— Eastern Division Transmission and Ancillary Services-Rate Order No. WAPA–122 Western Area Power Administration, DOE. ACTION: Notice of Order Concerning Transmission and Ancillary Services Rates. AGENCY: SUMMARY: The Deputy Secretary of Energy confirmed and approved Rate Order No. WAPA–122 and Rate Schedules UGP–FPT1, UGP–NFPT1, UGP–NT1, UGP–AS1, UGP–AS2, UGP– AS3, UGP–AS4, UGP–AS5, and UGP– AS6 placing the Integrated System (IS) Transmission and Ancillary Services rate into effect on an interim basis. The provisional rates will be in effect until the Federal Energy Regulatory Commission (Commission) confirms, approves, and places them into effect on a final basis or until they are replaced by other rates. The provisional rates will provide sufficient revenue to pay all annual costs, including interest expense, and repayment of required investment, within the allowable periods. Rate Schedules UGP–FPT1, UGP–NFPT1, UGP–NT1, UGP–AS1, UGP–AS2, UGP–AS3, UGP–AS4, UGP– AS5, and UGP–AS6 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, 2005, and will be in effect until the Commission confirms, approves, and places the rate schedules in effect on a final basis through September 30, 2010, or until the rate schedules are superseded. These new rate schedules dated October 2005, supersede the similarly titled rate schedules dated 1998. DATES: FOR FURTHER INFORMATION CONTACT: Mr. Robert J. Harris, Upper Great Plains Regional Manager, Western Area Power Administration, 2900 4th Avenue North, Billings, MT 59101–1266, telephone (406) 247–7405, or Mr. Jon R. Horst, Rates Manager, Upper Great Plains Region, Western Area Power Administration, 2900 4th Avenue North, Billings, MT 59101–1266, telephone (406) 247–7444, e-mail horst@wapa.gov. SUPPLEMENTARY INFORMATION: The Deputy Secretary of Energy approved existing Rate Schedules UGP–FPT1, UGP–NFPT1, UGP–NT1, UGP–AS1, UGP–AS2, UGP–AS3, UGP–AS4, UGP– AS5, and UGP–AS6 for IS Transmission VerDate Aug<31>2005 15:21 Sep 22, 2005 Jkt 205001 and Ancillary Service rates on August 1, 1998, in Rate Order No. WAPA–79. The Commission confirmed and approved the rate schedules on November 25, 1998, in FERC Docket No. EF98–5031– 000. These rate schedules were then extended through September 30, 2005, by Rate Order No. WAPA–100, which was confirmed and approved by the Commission on December 16, 2003, under FERC Docket No. EF03–5032– 000. The rate schedules for Rate Order No. WAPA–79 and Rate Order No. WAPA–100 contained formulary rates that were recalculated yearly using the fixed charge rate methodology. The provisional formula rates will continue to use the fixed charge rate methodology and will continue to be recalculated yearly from updated financial and load data. However, the Generator Step Up Transformers are to be removed from the annual revenue requirement for IS. After the approval of the original Transmission and Ancillary Service rates for the IS, the Commission decided that Generator Step Up Transformers should not be included in transmission rates for jurisdictional utilities. Consistent with Western’s goal to observe Commission precedent to the extent consistent with its mission and permitted by law and regulation, the IS Transmission and Ancillary Service rates are being modified. The existing IS Long-Term Firm and Short-Term Firm Point-to-Point Transmission Service Rate Schedule is superseded by Rate Schedule UGP– FPT1, dated October 2005. The 2004– 2005 existing rate for IS Long-Term Firm and Short-Term Firm Point-toPoint Transmission Service is $2.72 per kilowattmonth (kWmonth). The provisional rate for IS Long-Term Firm and Short-Term Firm Point-to-Point Transmission Service is $2.69/ KWmonth. Under Rate Schedule UGP– NFPT1, the existing rate calculation for IS Non-Firm Point-to-Point Transmission Service is 3.73 mills per kilowatthour (mills/kWh). The provisional rate for IS Non-Firm Pointto Point Transmission Service is 3.68 mills/kWh. Under Rate Schedule UGP– NT1 the existing annual revenue requirement for IS Network Integration Transmission Service is $128,017,923. The provisional annual revenue requirement for IS Network Integration Transmission Service is $126,741,576. Under Rate Schedule UGP–AS1, the existing rate for Scheduling System Control and Dispatch (Scheduling and Dispatch) Service is $49.29/schedule/ day. The provisional rate for Scheduling and Dispatch is $49.77/schedule/day. Under Rate Schedule UGP–AS2, the existing rate for Reactive Supply and PO 00000 Frm 00007 Fmt 4703 Sfmt 4703 55821 Voltage Control from Generation Sources Service (Reactive Service) is $0.06/kWmonth. The provisional rate for Reactive Service is $0.07/kWmonth. Under Rate Schedule UGP–AS3, the provisional rate calculated for Regulation and Frequency Response Service is unchanged from the existing rate of $0.04/kWmonth. Under Rate Schedule UGP–AS4, there is no change in the rate for Energy Imbalance Service between the existing and the proposed rates. Under Rate Schedules UGP–AS5 and UGP–AS6, the rate for Spinning and Supplemental Reserves is $0.11/ kWmonth. The provisional rate calculated for Spinning and Supplemental Reserves is $0.12/ kWmonth. By Delegation Order No. 00–037.00, effective December 6, 2001, the Secretary of Energy delegated: (1) The authority to develop power and transmission rates to Western’s Administrator, (2) the authority to confirm, approve, and place such rates into effect on an interim basis to the Deputy Secretary of Energy, and (3) the authority to confirm, approve, and place into effect on a final basis, to remand or to disapprove such rates to the Commission. Existing DOE procedures for public participation in power rate adjustments (10 CFR part 903) were published on September 18, 1985. Under Delegation Order Nos. 00– 037.00 and 00–001.00A, 10 CFR part 903, and 18 CFR part 300, I hereby confirm, approve, and place Rate Order No. WAPA–122, the proposed IS Firm and Non-Firm Transmission and Ancillary Service rates into effect on an interim basis. The new Rate Schedules UGP–FPT1, UGP–NFPT1, UGP–NT1, UGP–AS1, UGP–AS2, UGP–AS3, UGP– AS4, UGP–AS5, and UGP–AS6 for IS Transmission and Ancillary Service rates will be promptly submitted to the Commission for confirmation and approval on a final basis. Dated: September 13, 2005. Clay Sell, Deputy Secretary. [Rate Order No. WAPA–122] In the matter of: Western Area Power Administration Rate Adjustment for the PickSloan Missouri Basin Program—Eastern Division Transmission and Ancillary Services; Order Confirming, Approving, and Placing the Pick-Sloan Missouri Basin Program—Eastern Division Transmission and Ancillary Services Formula Rates Into Effect on an Interim Basis This rate was established in accordance with section 302 of the Department of Energy (DOE) Organization Act (42 U.S.C. 7152). This Act transferred to and vested in the E:\FR\FM\23SEN1.SGM 23SEN1 55822 Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices Secretary of Energy the power marketing functions of the Secretary of the Department of the Interior and the Bureau of Reclamation under the Reclamation Act of 1902 (ch. 1093, 32 Stat. 388), as amended and supplemented by subsequent laws, particularly section 9(c) of the Reclamation Project Act of 1939 (43 U.S.C. 485h(c)), section 5 of the Flood Control Act of 1944 (16 U.S.C. 825s), and other Acts that specifically apply to the project involved. By Delegation Order No. 00–037.00, effective December 6, 2001, the Secretary of Energy delegated: (1) The authority to develop power and transmission rates to Western’s Administrator, (2) the authority to confirm, approve, and place such rates into effect on an interim basis to the Deputy Secretary of Energy, and (3) the authority to confirm, approve, and place into effect on a final basis, to remand or to disapprove such rates to the Commission. Existing DOE procedures for public participation in power rate adjustments (10 CFR part 903) were published on September 18, 1985. Acronyms and Definitions As used in this Rate Order, the following acronyms and definitions apply: $/kWmonth: Monthly charge for capacity (i.e., $ per kilowatt (kW) per month). 12-cp: 12-month coincident peak average. Administrator: The Administrator of the Western Area Power Administration. Ancillary Services: Those services necessary to support the transfer of electricity while maintaining reliable operation of the transmission system in accordance with standard utility practice. A&GE: Administrative and general expense. Balancing Authority: An electric system or systems, bounded by interconnection metering and telemetry, capable of controlling generation to maintain its interchange schedule with other Balancing Authorities and contributing to frequency regulation of the Interconnection. Formerly known as control area. Basin Electric: Basin Electric Power Cooperative. Capacity: The electric capability of a generator, transformer, transmission circuit, or other equipment. It is expressed in kilowatts. Capacity Rate: The rate which sets forth the charges for capacity. It is expressed in $/kWmonth. VerDate Aug<31>2005 15:21 Sep 22, 2005 Jkt 205001 Commission: Federal Energy Regulatory Commission. Corps of Engineers: U.S. Army Corps of Engineers. Customer: An entity with a contract that is receiving service from Western’s UGPR. DOE: United States Department of Energy. DOE Order RA 6120.2: An order outlining power marketing administration financial reporting and ratemaking procedures. Energy: Measured in terms of the work capacity over a period of time. It is expressed in kilowatthours. Emergency Energy: Electric energy purchased by an electric utility whenever an event on the system causes insufficient operating capability to cover its own demand requirement. Energy Imbalance Service: A service which provides energy correction for any hourly mismatch between a Transmission Customer’s energy supply and the demand served. Energy Rate: The rate which sets forth the charges for energy. It is expressed in mills per kilowatthour and applied to each kilowatthour delivered to each customer. FERC: The Commission (to be used when referencing Commission Orders). FERC Order No. 888: FERC Order Nos. 888, 888–A, 888–B and 888–C unless otherwise noted. Firm: A type of product and/or service available at the time requested by the customer. Firm Point-to-Point: Service that is reserved and/or scheduled between Points of Receipt and Delivery. FRN: Federal Register notice. FY: Fiscal year; October 1 to September 30. GSU: Generator Step Up Transformer. GWh: Gigawatthour—the electrical unit of energy that equals 1 billion watthours or 1 million kWh. Heartland: Heartland Consumers Power District. IS: Integrated System. ISO: Independent System Operator. JTS: Joint Transmission System. kW: Kilowatt—the electrical unit of capacity that equals 1,000 watts. kWh: Kilowatthour—the electrical unit of energy that equals 1,000 watts in 1 hour. kWmonth: Kilowattmonth—the electrical unit of the monthly amount of capacity. kWyear: Kilowattyear—the electrical unit of the yearly amount of capacity. Load: The amount of electric power or energy delivered or required at any specified point(s) on a system. Load-ratio share: Ratio of the Network Transmission Customer’s coincident PO 00000 Frm 00008 Fmt 4703 Sfmt 4703 hourly load (including its designated network load not physically interconnected with the Transmission Provider) to the Transmission Provider’s monthly Transmission System peak, calculated on a rolling 12-month basis. Long-Term Firm Point-to-Point: Firm Point-to-Point Transmission Service reservation with at least 12 consecutive equal monthly amounts. MAPP: Mid-Continent Area Power Pool. MBMPA: Missouri Basin Municipal Power Agency. Mill: A monetary denomination of the United States that equals one tenth of a cent or one thousandth of a dollar. Mills/kWh: Mills per kilowatthour— the unit of charge for energy. MVAR: Megavar, equal to 1,000,000 VARs. MW: Megawatt—the electrical unit of capacity that equals 1 million watts or 1,000 kilowatts. NERC: North American Electric Reliability Council. Net Revenue: Revenue remaining after paying all annual expenses. Network Customer: An entity receiving Transmission Service under the terms of the Transmission Provider’s Network Integration Transmission Service of the Tariff. Non-Firm Point-to-Point: Point-toPoint Transmission Service under the Tariff that is reserved and scheduled on an as-available basis and is subject to interruption for economic reasons. O&M: Operation and maintenance. OASIS: Open Access Same-Time Information System—provides access to information on transmission pricing and availability for potential transmission customers. OM&R: Operation, Maintenance & Replacement. P–SMBP: Pick-Sloan Missouri Basin Program. P–SMBP—ED: Pick-Sloan Missouri Basin Program—Eastern Division. Point-to-Point: The reservation and transmission of capacity and energy on either a firm or non-firm basis from designated Point(s) of Receipt to designated Point(s) of Delivery. Power: Capacity and energy. Provisional Rate: A rate which has been confirmed, approved, and placed into effect on an interim basis by the Deputy Secretary. Rate Brochure: An April 2005 document explaining the rationale and background for the rate proposal contained in this Rate Order. Reclamation: United States Department of the Interior, Bureau of Reclamation. Reclamation Law: A series of Federal laws. Viewed as a whole, these laws E:\FR\FM\23SEN1.SGM 23SEN1 Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices create the framework under which Western markets power. Reactive Supply and Voltage Control from Generating Sources Service: A service which provides reactive supply through changes to generator reactive output to maintain transmission line voltage and facilitate electricity transfers. Regulation and Frequency Response Service: A service which provides for following the moment-to-moment variations in the demand or supply in a Balancing Authority and maintaining scheduled interconnection frequency. Reserve Services: Spinning Reserve Service and Supplemental Reserve Service. Revenue Requirement: The revenue required to recover annual expenses (such as O&M, purchase power, transmission service expenses, interest, and deferred expenses) and repay Federal investments, and other assigned costs. SCADA: Supervisory Control and Data Acquisition. Schedule: An agreed-upon transaction size (megawatts), beginning and ending ramp times and rate, and type of service required for delivery and receipt of power between the contracting parties and the Balancing Authority(ies) involved in the transaction. Scheduling, System Control and Dispatch Service: A service which provides for (a) scheduling, (b) confirming and implementing an interchange schedule with other balancing authorities, including intermediary balancing authorities providing transmission service, and (c) ensuring operational security during the interchange transaction. Service Agreement: The initial agreement and any amendments or supplements entered into by the Transmission Customer and Western for service under the Tariff. Short-Term Firm Point-to-Point: Firm Point-to-Point Transmission Service with service duration of less than one year. 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. The Transmission Provider must offer this service when the transmission service is used to serve load within its Balancing Authority. The Transmission Customer must either purchase this service from the Transmission Provider or make alternative comparable arrangements to satisfy its Spinning Reserve Service obligation. VerDate Aug<31>2005 15:21 Sep 22, 2005 Jkt 205001 Supplemental Reserve Service: Generation capacity 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. Supplemental Reserve Service may be provided by generation units that are on-line but unloaded, by quick start generation or by interruptible load. The Transmission Provider must offer this service when the transmission service is used to serve load within its Balancing Authority. The Transmission Customer must either purchase this service from the Transmission Provider or make alternative comparable arrangements to satisfy its Supplemental Reserve Service obligation. Supporting Documentation: A compilation of data and documents that support the Rate Brochure and the rate proposal. System: An interconnected combination of generation, transmission and/or distribution components comprising an electric utility, independent power producer(s) (IPP), or group of utilities and IPP(s). Tariff: Western Area Power Administration Open Access Transmission Service Tariff, originally approved in Docket No. NJ98–1–000, 99 FERC ¶ 61,062 (2002) and amended in Docket No. NJ05–1–000, 112 FERC ¶ 61,044 (2005). Transmission Customer: Any eligible customer (or its designated agent) that receives transmission service under the Tariff. Transmission Provider: Any utility that owns, operates, or controls facilities used to transmit electric energy in interstate commerce. The UGPR, as operator of the IS, is the Transmission Provider for the purposes of this Federal Register notice. Transmission System: The facilities owned, controlled, or operated by the Transmission Provider that are used to provide transmission service. Transmission System Total Load: The 12-cp peak for Network Transmission Service plus reserved capacity for all Firm Point-to-Point Transmission Service. UGPR: The Upper Great Plains Customer Service Region of the Western Area Power Administration. In some places in this order, UGPR maybe referenced generically as Western. VAR: A unit of reactive power. WAUGP: The NERC acronym for the Western Area Upper Great Plains Balancing Authority. This balancing authority is also known as the Watertown Balancing Authority. Watertown Operation Office: Western Area Power Administration Upper Great PO 00000 Frm 00009 Fmt 4703 Sfmt 4703 55823 Plains Customer Service Region, Operations Office, 1330 41st Street SE., Watertown, South Dakota. Western: United States Department of Energy, Western Area Power Administration. Western Regions: Customer service regions of the Western Area Power Administration. Western’s Tariff: Western’s Open Access Transmission Service Tariff. Effective Date The new interim rates will take effect on the first day of the first full billing period beginning on or after October 1, 2005, and will remain in effect until September 30, 2010, pending approval by the Commission on a final basis. Public Notice and Comment Western followed the Procedures for Public Participation in Power and Transmission Rate Adjustments and Extensions, 10 CFR part 903, for a minor rate adjustment in developing these rates. The steps Western took to involve interested parties in the rate process were: 1. The proposed rate adjustment process began February 9, 2005, when Western mailed a notice announcing an informal customer meeting to all IS Transmission Customers and interested parties. The meeting was held on March 22, 2005, in Sioux Falls, South Dakota. At this informal meeting, Western explained the rationale for the rate adjustment, presented rate designs and methodologies, and answered questions. 2. A Federal Register notice published on April 18, 2005, (70 FR 20119), announced the proposed rates for P–SMBP—ED Transmission and Ancillary Service rates, and began a public consultation and comment period. 3. On April 28, 2005, Western mailed letters to all IS Transmission Customers and interested parties transmitting the Federal Register notice published on April 18, 2005, and directing them to the rate brochure on Western’s Web site. 4. Western received no comment letters during the consultation and comment period, which ended May 18, 2005. Project Description The initial stages of the Missouri River Basin Project were authorized by section 9 of the Flood Control Act of 1944 (58 Stat. 887, 890, Pub. L. 78–534). It was later renamed the P–SMBP. The P–SMBP is a comprehensive program, with the following authorized functions: flood control, navigation improvement, irrigation, municipal and industrial water development, and hydroelectric E:\FR\FM\23SEN1.SGM 23SEN1 55824 Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices production for the entire Missouri River Basin. Multipurpose projects have been developed on the Missouri River and its tributaries in Colorado, Montana, Nebraska, North Dakota, South Dakota, and Wyoming. The UGPR markets significant quantities of Federally-generated hydroelectric power from the P– SMBP—ED. Western owns and operates an extensive system of high-voltage transmission facilities which the UGPR uses to market approximately 2,400 MW of capacity from Federal projects within the Missouri River Basin. This capacity is generated by eight powerplants located in Montana, North Dakota, and South Dakota. The UGPR uses the transmission facilities of Western and others to market this power and energy to customers located within the P– SMBP—ED. This marketing area includes Montana, east of the Continental Divide, all of North and South Dakota, eastern Nebraska, western Iowa, and western Minnesota. Integrated System Description Using a single system, joint-planning concept, the UGPR, Basin Electric, and Heartland combined their transmission facilities to form the IS and developed Transmission and Ancillary Service rates for transmission over the IS. This action was necessary because the UGPR, Basin Electric, and Heartland, whose facilities are fully integrated, did not have rates suitable for long-term open access transmission service. The transmission facilities included in the IS are transmission lines, substations, communication equipment and facilities related to operation, maintenance, and support of the IS Transmission System. The UGPR is designated as the operator of the other participants’ transmission facilities and as such contracts for service, determines and posts the available transmission capacity on the OASIS, bills for service, collects payments, and distributes revenues to each IS participant. The IS consists of the transmission facilities owned by Basin Electric and Heartland east of the east-west electrical separation in the United States, the transmission facilities owned by Western in the P–SMBP—ED, and the Miles City DC Tie owned by Western and Basin Electric. These facilities interconnect with utilities in the states of Montana, North Dakota, South Dakota, Iowa, Minnesota, Missouri, and in addition include facilities which interconnect with Canada. The approach for formation of the IS was to include facilities which followed the spirit and intent of the FERC Order No. 888 and to make the system the most useful to all transmission requesters. The ‘‘seven-factor test’’ defined in FERC Order No. 888 was used to determine the distribution facilities that were excluded from the IS Transmission System. Several major facilities are included in the IS. The second 345-kV transmission line between the Antelope Valley and Leland Olds generation stations, which meets the standards for acceptable transmission facilities set in the Commission rulings on filings by other transmission entities, is included. The 230-kV transmission line between Tioga, North Dakota, and Boundary Dam, which provides access to generation and loads in Canada, is included in the IS. The IS also includes the Miles City DC tie, which opens the markets between the east-west electrical separation of the United States and increases access to other utilities. P–SMBP—ED Transmission and Ancillary Service Rates Study Western prepared a Transmission and Ancillary Service rates study to ensure that Transmission and Ancillary Service rates are based on the cost of service of the IS Transmission System. This study includes all IS Transmission and Ancillary Service expenses and associated offsetting revenues. Western charges IS Transmission Service rates separately to entities receiving transmission-only services over the IS Transmission System. The UGPR is proposing to continue using an annual fixed charge formula that will determine how much revenue must be recovered from the IS Transmission and Ancillary Service rates. The annual revenue requirements include O&M expenses, administrative and general expenses, interest expense, and depreciation expense. This methodology is applied annually using the most recent historical test year. These revenue requirements are offset by appropriate IS revenues. Integrated System Transmission Service Western will offer Network, Firm Point-to-Point, and Non-Firm Point-toPoint Transmission Service on the IS. The service offered is the transmission of energy and capacity from Points of Receipt to Points of Delivery on the IS. The IS Transmission Service Rates include the cost of Scheduling, System Control and Dispatch Service. Therefore, an additional charge for this ancillary service is not required for transmission users. Western, Basin Electric, and Heartland will take IS Transmission Service. Transmission Service to Western’s Customers continues to be bundled in the firm electric power service rate under existing contracts that expire in 2020. The UGPR prepared a transmission service study to ensure that the formula IS Transmission and Ancillary Service rates are based on the cost of service to the IS. The UGPR seeks approval of formula rates for calculating Point-toPoint IS Transmission Rates, the Network Annual Revenue Requirement for IS Transmission Service, and ancillary service rates. Western requests the Commission confirm that these rates are not arbitrary, capricious, or in violation of the law. The rates will be recalculated every year, effective May 1, based on the approved formula rates and updated financial and load data. The UGPR will provide customers notice of changes in the Transmission and Ancillary Service rates no later than April 1 of each year. IS Transmission System Total Load The IS Transmission System Total Load is the 12-cp system peak for IS Network Transmission Service plus the reserved capacity for all IS Long-Term Firm Point-to-Point Transmission Service. The IS Transmission System Total Load is calculated as follows based upon the most recent historical data available at the time of the initial rate proposal. This included both 2003 and 2004 data: IS Network Transmission Load ................................................................................................................................................. Long-Term Firm Point-to-Point Reserved Capacity .................................................................................................................. 3,185,000 kW 743,000 kW IS Transmission System Total Load .......................................................................................................................................... 3,928,000 kW Annual Costs Western calculated the annual costs of providing the various IS Transmission VerDate Aug<31>2005 15:21 Sep 22, 2005 Jkt 205001 and Ancillary Services using a Commission-recognized methodology for annual cost calculation with fixed PO 00000 Frm 00010 Fmt 4703 Sfmt 4703 charge rates for various cost components. The cost components applicable to Western include O&M, E:\FR\FM\23SEN1.SGM 23SEN1 Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices A&GE, depreciation, and the cost of capital. These components are displayed as fixed charge rates or percentages of net investment. These fixed charge rates are then summed to arrive at a total fixed charge rate associated with the particular service for which a rate is being calculated. The 55825 fixed charge rate calculation for the various IS Transmission and Ancillary Services can be summarized with the following formula: O&M ÷ Net investment + A&GE ÷ Net investment + Depreciation expense ÷ Net investment +Annual interest expense ÷ Unpaid investment balance Total fixed charge rate To arrive at the annual cost of providing the IS Transmission Service or one of the Ancillary Services, the total fixed charge rate is applied to the net investment allocated to the service: Total fixed charge rate × Net investment = Annual cost of providing service. The source for the UGPR’s annual O&M, A&GE, depreciation expense, interest expense, and investment is the Results of Operations for the Upper Great Plains Customer Service RegionPick Sloan Missouri Basin. The source for Heartland’s data is Heartland Consumers Power District Annual Report. The sources for Basin Electric’s data are Basin Electric’s Consolidated Financial Statement, Rural Utility Service Form 12, and other accounting records. Annual Revenue Requirement for IS Transmission Service The annual revenue requirement for IS Transmission Service is based upon the most recent historical data available at the time of the initial rate proposal. This data is used in a test year and uses an annual fixed charge methodology. The rates for IS Transmission Service (Network and Point-to-Point) are based on a revenue requirement that recovers the annual costs of Western, Basin Electric, and Heartland associated with providing the IS Transmission Service plus any facility credit paid to the IS Transmission Customers. The annual revenue requirement for IS Transmission Service includes the cost for Scheduling, System Control, and Dispatch Service needed to provide transmission service. Therefore, an additional charge for this ancillary service is not required for transmission users. The annual transmission costs are offset by appropriate Transmission Revenue Credits to avoid over-recovery of costs. The annual revenue requirement for IS Transmission Service can be summarized with the following formula: Annual IS Transmission Costs of UGPR + Annual IS Transmission Costs Basin Electric and Heartland + Transmission Customer Facility Credits ¥ Transmission Revenue Credits Annual Revenue Requirement for IS Transmission Service Transmission Customer Facility Credits are credits paid to IS Transmission Customers for facilities that are integrated with the IS and increase both the capability and the reliability of the IS. The credits are addressed in individual agreements and appropriate adjustments are made in subsequent rate calculations. The IS participants will evaluate requests for facility credits consistent with the Commission’s guidance in the FERC Order No. 888, other relevant Commission policy, and the terms of the Tariff. Transmission Revenue Credits include revenue from sales of Non-Firm, discounted IS Firm and Short-Term Firm Point-to-Point Transmission Service; revenue from existing transmission agreements; and revenue from Scheduling, System Control and Dispatch Services. IS Network Transmission Service The proposed rate for IS Network Transmission Service is a formula calculation based upon the annual revenue requirement for IS Transmission Service then in effect, as determined by the annual fixed charge methodology. The monthly charge for IS Network Transmission Service is as follows: Network Customer’s Load-ratio share × Annual Revenue Requirement for IS Transmission ÷ 12 months Monthly IS Network Transmission Service Charge The load ratio-share is the ratio of the Network Customer’s coincident hourly load to the monthly IS Transmission System peak minus the coincident peak for all IS Firm Point-to-Point Transmission Service plus the IS Firm Point-to-Point reservations, calculated VerDate Aug<31>2005 15:21 Sep 22, 2005 Jkt 205001 on a rolling 12-cp basis. The proposed rate formula would be effective October 1, 2005, through September 30, 2010. IS Firm Point-to-Point Transmission Service The rate for IS Firm Point-to-Point Transmission Service is the annual PO 00000 Frm 00011 Fmt 4703 Sfmt 4703 revenue requirement for IS Transmission Service divided by the IS Transmission System Total Load in kW, to derive a cost per kilowattyear (kWyear). The formula for the monthly rate is as follows: E:\FR\FM\23SEN1.SGM 23SEN1 55826 Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices Annual Revenue Requirement for IS Transmission ÷ IS Transmission System Total Load ÷ 12 months Monthly IS Firm Point-to-Point Transmission Rate The rate formula is applied annually by using the most current historical data available. The proposed rate formula would be effective October 1, 2005, through September 30, 2010. IS Non-Firm Point-to-Point Transmission Service The proposed rate for IS Non-Firm Point-to-Point Transmission Service is a mills/kWh rate, based upon the current firm point-to-point rate and may be discounted. The formula rate is as follows: Monthly IS Firm Point-to-Point Transmission Rate ÷ 730 hours/month × 1000 mills per dollar IS Non-Firm Point-to-Point Transmission Rate This rate will remain in effect for the same period as the IS Firm Point-toPoint Transmission Service rate and will also be reviewed annually. The IS Non-Firm Point-to-Point Transmission Service will be offered at hourly, daily, and monthly rates. The IS Transmission Service availability will be posted on the UGPR OASIS. Ancillary Services In accordance with the Tariff, Western will offer to all customers the six ancillary services defined by the Commission, two of which IS Transmission Customers are required to purchase: (1) Scheduling, System Control, and Dispatch Service, and (2) Reactive Supply and Voltage Control from Generation Sources Service. The remaining four ancillary services are: (3) Regulation and Frequency Response Service, (4) Energy Imbalance Service, (5) Spinning Reserve Service, and (6) Supplemental Reserve Service. The open access ancillary service formula rates are designed to recover only the costs incurred for providing the service(s). The charges for ancillary services are based on the cost of resources used to provide these services. Sales of Regulation and Frequency Response Service, Energy Imbalance Service, Spinning Reserve Service, and Supplemental Reserve Service may be limited since Western has allocated its power resources to preference entities under long-term commitments. In accordance with the Tariff, if Western is unable to provide these services from its own resources, an offer will be made to purchase the services and pass through these costs, including an administrative charge to the customer. Scheduling, System Control, and Dispatch Service Western’s annual revenue requirement for Scheduling, System Control, and Dispatch Service is determined by multiplying the portion of the Watertown Operations Office net plant and communications facilities net plant associated with Scheduling, System Control, and Dispatch Service by the transmission fixed charge rate. The formula rate for Scheduling, System Control, and Dispatch Service is: Annual Revenue Requirement for Scheduling, System Control and Dispatch Service ÷ Annual Number of Daily Schedules Scheduling, System Control and Dispatch Rate This rate and rate design only recovers Western’s revenue requirement for Scheduling, System Control, and Dispatch Service. Reactive Supply and Voltage Control from Generation Sources Service Western’s annual cost of providing Reactive Supply and Voltage Control from Generation Sources Service is determined by multiplying the total P– SMBP—ED generation net plant by the generation fixed charge rate. The annual cost is multiplied by the capability used for reactive support to determine Western’s reactive service revenue requirement. Basin Electric’s and Heartland’s annual revenue requirement is based on the annual cost of equipment installed on its generators to provide this service. Western’s, Basin Electric’s, and Heartland’s annual revenue requirements are summed for the total revenue requirement for this service. The Reactive Supply and Voltage Control Service from Generation Sources Service rate is then derived by dividing the total annual revenue requirement by the load requiring reactive service. The annual rate is then divided by 12 months to obtain a monthly rate. The Reactive Supply and Voltage Control rate calculation is summarized in the following formula: Annual Reactive Revenue Requirement + Load Requiring Reactive Service ÷ 12 months Monthly Reactive Rate VerDate Aug<31>2005 15:21 Sep 22, 2005 Jkt 205001 PO 00000 Frm 00012 Fmt 4703 Sfmt 4703 E:\FR\FM\23SEN1.SGM 23SEN1 Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices Peck powerplants’ installed capacity. This dollar per kilowatt amount is then applied to the capacity of Oahe generation and Fort Peck generation reserved for Regulation and Frequency Response Service in the balancing authority. The capacity reserved for Regulation and Frequency Response Service has been determined to be 2 percent of the annual peak load. The 2 percent value was derived by averaging yearly peak condensing as percentage of load for five years. Western’s annual revenue requirement for Regulation and Frequency Response Service is determined by applying the dollar per kilowatt amount to the capacity used for Regulation and Frequency Response Regulation and Frequency Response Service Regulation and Frequency Response Service in the east side of the balancing authority is provided primarily by Oahe generation and in the west side of the balancing authority by Fort Peck generation, both of which are Corps of Engineer facilities. To calculate the annual cost of providing Regulation and Frequency Response Service, the Corps of Engineers’ generation fixed charge rate is applied to Oahe generation and Fort Peck generation net plant investment. This cost is divided by the capacity at the plants to derive a dollar per kilowatt amount for Oahe and Fort 55827 Service. Basin Electric’s and Heartland’s annual revenue requirement is based on the annual cost of equipment installed on its generators to provide this service. Western’s, Basin Electric’s, and Heartland’s annual revenue requirements are summed for the total revenue requirement for this service. Annual rate for Regulation and Frequency Response Service is then determined by dividing the total revenue requirement by the total load in the Balancing Authority. The annual rate is then divided by 12 months to obtain a monthly rate. The Regulation and Frequency Response Service rate calculation is summarized in the following formula: Annual Revenue Requirement for Regulation + Load in the Balancing Authority Requiring Regulation ÷ 12 months Monthly Regulation and Frequency Response Rate Energy Imbalance Service Reserve Services This service is not intended to provide backup for generation supply. Energy shall be returned in like time frames (on-peak, off-peak, etc.) and accounts zeroed out monthly. Western reserves the right to apply a penalty to energy imbalances outside a 3-percent bandwidth (±1.5 percent deviation). The penalty for under deliveries outside the 3-percent bandwidth is 100 mills/kWh. Over deliveries outside the bandwidth will be forfeited to the balancing authority. Western’s annual cost of generation for Reserve Services is determined by multiplying the generation fixed charge rate by the P–SMBP—ED generation net plant investment. The cost/kW year is determined by dividing the annual cost of generation by the plant capacity. The capacity used for Reserve Services is determined by multiplying Western’s peak IS load by the MAPP operating reserve requirement of 5 percent. The cost/kW year is multiplied by the capacity used for Reserve Services to determine the annual revenue requirement for Reserve Services. The annual revenue requirement for Reserve Services is divided by Western’s peak transmission load to calculate the annual rate. The annual rate is then divided by 12 months to obtain a monthly rate. This rate and rate design recovers only Western’s revenue requirement associated with Reserve Services. If energy is taken under these services, the energy charge will be the MAPP or its successors rate for emergency energy. The Regulation and Frequency Response Service rate calculation is summarized in the following formula: Annual Revenue Requirement for Reserves ÷ Load Requiring Reserves ÷ 12 months Monthly Reserve Service Rate Existing and Provisional Rates values are outlined in the following table. These rates are calculated comparing the Existing Revenue Requirement to the Revenue The revenue requirements for the individual services and comparison Requirement based upon the most recent historical data available at the time of the initial rate proposal. TABLE 1 Existing revenue requirement Service Transmission ............................................................................................................................ Scheduling, System Control and Dispatch .............................................................................. Reactive Supply and Voltage Control from Generation Sources ............................................ Regulation and Frequency Control .......................................................................................... Reserves .................................................................................................................................. VerDate Aug<31>2005 15:21 Sep 22, 2005 Jkt 205001 PO 00000 Frm 00013 Fmt 4703 Sfmt 4703 $128,017,923 3,373,281 2,736,253 1,065,771 1,895,268 E:\FR\FM\23SEN1.SGM 23SEN1 Provisional revenue requirement $126,741,576 3,406,102 3,065,568 1,075,623 2,009,276 Percentage change ¥0.997 ¥0.973 12.035 0.924 6.015 55828 Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices Certification of Rates Western’s Administrator certifies that the IS Transmission and Ancillary Service rates placed into effect on an interim basis are the lowest possible rates consistent with sound business principles. The provisional formula rates were developed following administrative policies and applicable laws. IS Transmission Service Discussion Western proposes continuing the annual fixed charge formula to determine the Annual Revenue Requirement for IS Transmission Service. The annual revenue requirement for IS Transmission Service includes O&M expense, A&GE, interest expense, and depreciation expense from the most recent historical test year. This annual revenue requirement for IS Transmission Service is offset by appropriate revenue credits. The IS Transmission System includes the transmission facilities owned by Western, Basin Electric, Heartland and others in which the IS has contractual rights. The costs paid to others for contractual rights on their transmission lines are included in the costs recovered by the annual revenue requirement for IS Transmission Service. Western will continue to offer Network, Firm Point-to-Point, and NonFirm Point-to-Point Transmission Service on the IS Transmission System. The service offered is the transmission of energy and capacity from Points of Receipt to Points of Delivery on the IS. The IS Transmission Service rates include the cost of Scheduling, System Control, and Dispatch Service. Therefore an additional charge for this ancillary service is not required for transmission users. The provisional IS Transmission Service rates will be applied to customers who purchase transmission services. Western, Basin Electric, and Heartland will take IS Transmission Service. The IS Transmission Service to the UGPR’s Customers will continue to be bundled in the firm electric service rate under existing contracts that expire in 2020. IS Transmission System Total Load The IS Transmission System Total Load is the 12-cp system peak for Network IS Transmission Service plus the reserved capacity for all IS LongTerm Firm Point-to-Point Transmission Service. For the provisional rate, the IS Transmission System Total Load will be unchanged at 3,968,000 kW. Annual Costs Western will continue to use a Commission-recognized methodology for annual cost calculation with fixed charge rates for various cost components approved by the Commission in WAPA– 79 and WAPA–100. The change in the provisional rate is that the costs associated with the GSUs are no longer included in the net plant investment for transmission or the various expenses. The investment and costs for GSUs are now in the generation fixed charge calculation in support of ancillary services. The proposed methodology will continue to be an annual fixed charge formula that will determine the annual revenue requirement to be recovered from transmission services. Annual Revenue Requirement for IS Transmission A change in the costs that comprise the annual revenue requirement for IS Transmission is being proposed. The proposed transmission rate methodology is different from the current transmission rate methodology in one area. The GSU investments are removed from the transmission investments and placed in the generation investments. This also moves the corresponding costs of GSUs from transmission costs to generation costs. The existing annual revenue requirement for IS Transmission Service is $128,017,923. The provisional Annual Revenue Requirement for IS Transmission Service is $126,741,576. Network The current IS Network Transmission Service schedule expires on September 30, 2005. The provisional annual revenue requirement for IS Transmission Service will be used in the provisional rate formula for IS Network Transmission Service. The provisional charge for the monthly demand for IS Network Transmission Service will be the product of the network customer’s load ratio share times one-twelfth (1/12) of the annual revenue requirement for IS Transmission Service. The load ratio share will be based on the network customer’s hourly load (including its designated network load not physically interconnected with Western), coincident with the IS monthly transmission system peak, which will be calculated on a rolling 12-cp basis. Western’s transmission system peak includes the sum of capacity reserved for IS Point-to-Point Transmission Service, 12-cp monthly entitlements for firm power customers, and the average 12-cp monthly system peak for IS Network Transmission Service. The provisional rate formula is to be effective beginning October 1, 2005, through September 30, 2010. Firm Point-to-Point The current IS Firm Point-to-Point Transmission Service rate for 2004– 2005 is $2.72 and expires September 30, 2005. The provisional formula rate will continue to be the Annual Revenue Requirement for IS Transmission Service divided by the IS Transmission System Total Load. The provisional rate for IS Firm Point-to-Point Transmission Service is $2.69 per kWmonth for 2004– 2005. Non-Firm Point-to-Point The current IS Non-Firm Transmission Service rate expires September 30, 2005. The provisional rate for IS Non-Firm Transmission Service is expressed in mills/kWh and is based on the current IS Firm Pointto-Point Transmission Service rate and may be discounted. The provisional IS Non-Firm Point-to-Point Transmission Service rate will be the IS Firm Pointto-Point Transmission Service rate divided by 730 hours per month and multiplied by 1000 mills per dollar. The provisional IS Non-Firm Transmission Service rate for 2004–2005 is 3.68 mills/ kWh. The following table summarizes the difference in calculations between the current IS Transmission Service rates and the provisional IS Transmission Service rates. It compares the change in the average annual projections used in the 2004–2005 transmission and ancillary services study and the provisional IS Transmission Service rates for this rate adjustment based upon the most recent historical data available at the time of the initial rate proposal. COMPARISON OF ANNUAL REVENUES Item Existing rate Annual IS Costs ....................................................................................................................... Transmission Customer Facility Credits .................................................................................. VerDate Aug<31>2005 15:21 Sep 22, 2005 Jkt 205001 PO 00000 Frm 00014 Fmt 4703 Sfmt 4703 $137,088,496 2,482,447 E:\FR\FM\23SEN1.SGM 23SEN1 Provisional rate $136,289,145 2,482,647 Percent change ¥0.577 0.000 55829 Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices COMPARISON OF ANNUAL REVENUES—Continued Item Existing rate Transmission Revenue Credits ............................................................................................... Annual Revenue Requirement for IS Transmission Service ................................................... The change in annual revenue requirement for IS Transmission Service is primarily a result of a revision in the allocation of expenses and investments. The revenue change between the existing rate and the provisional rate is <1 percent and, therefore, this is a minor rate adjustment. Basis for Rate Development The existing rates for IS Network, Firm and Non-Firm Transmission Service in Rate Schedules UGP–NT1, UGP–FPT1, and UGP–NFPT1, expire September 30, 2005. This rate adjustment contains rates that replace existing rates. The adjusted rates reflect changes in costs. The provisional rates will provide sufficient revenue to pay all annual costs, including interest expense, and repay investment within the allowable period. The provisional IS Transmission Service rates, detailed in Rate Schedules UGP–NT1, UGP–FPT1, and UGP–NFPT1, will take effect on October 1, 2005 to correspond with the start of the Federal fiscal year and remain in effect through September 30, 2010, or until replaced. The proposed rates for IS Transmission Service include a provision to pass through electric industry restructuring costs associated with providing transmission service. These costs will be passed through to each appropriate IS Transmission Customer. Comments Western did not receive any comments or responses regarding the IS Transmission Service rate adjustment. Ancillary Services Discussion The IS will continue to offer six ancillary services. These are (1) Scheduling, system control, and dispatch service, (2) reactive supply and voltage control service, (3) regulation and frequency response service, (4) energy imbalance service, (5) spinning reserve service, and (6) supplemental reserve service. The first two are required services: (1) Scheduling, system control, and dispatch service 9,454,494 128,017,923 Percent change Provisional rate 9,454,494 126,741,576 0.000 ¥0.997 and (2) reactive supply and voltage control service. All these ancillary services are listed in Western’s Tariff. The provisional rates for ancillary services are designed to recover only the costs associated with providing the service(s). The formula for calculating the rates will remain the same but the GSUs will be included in the investment and costs for the generation fixed charge in support of ancillary services. The costs for providing Scheduling, System Control, and Dispatch Service are included in the provisional IS Transmission Service rates. The following table summarizes the difference in calculations between the current IS Ancillary Service rates and the provisional IS Ancillary Service rates. It compares the change in the average annual projections used in the 2004–2005 transmission and ancillary services study and the provisional IS Transmission and Ancillary Service rates for this rate adjustment based upon the most recent historical data available at the time of the initial rate proposal. COMPARISON OF ANCILLARY SERVICE RATES Item Unit Scheduling, System Control and Dispatch Service ................................. Reactive Supply and Voltage Control ...................................................... Regulation and Frequency Response ...................................................... Energy Imbalance .................................................................................... Reserves .................................................................................................. schedule/day ......... kWmonth ............... kWmonth ............... n/a ......................... kWmonth ............... Existing rate $49.29 0.06 0.04 n/a 0.11 Provisional rate Percent change $49.77 0.07 0.04 n/a 0.12 0.974 16.667 0.000 n/a 9.091 Basis for Rate Development Comments Regulatory Procedure Requirements The existing rates for IS Ancillary Services in Rate Schedules UGP–AS1, UGP–AS2, UGP–AS3, UGP–AS4, UGP– AS5, and UGP–AS6, expire September 30, 2005. The rate adjustment contains rates that replace existing rates. The adjusted rates reflect a revised methodology and changes in costs. The provisional rates will provide sufficient revenue to pay all annual costs, including interest expense, and repayment of required power investment within the allowable period. The provisional rates will take effect on October 1, 2005, to correspond with the start of the Federal fiscal year and remain in effect through September 30, 2010. Western did not receive any comments or responses regarding the IS Ancillary Services rate adjustment. Regulatory Flexibility Analysis VerDate Aug<31>2005 15:21 Sep 22, 2005 Jkt 205001 Availability of Information Information about this rate adjustment, including studies, brochures, comments, letters, memorandums, and other supporting material made or kept by Western, used to develop the provisional rates, is available for public review in the Upper Great Plains Regional Office, 2900 4th Avenue North, Billings, Montana. PO 00000 Frm 00015 Fmt 4703 Sfmt 4703 The Regulatory Flexibility Act of 1980 (5 U.S.C. 601, et seq.) requires Federal agencies to perform a regulatory flexibility analysis if a final rule is likely to have a significant economic impact on a substantial number of small entities and there is a legal requirement to issue a general notice of proposed rulemaking. Western has determined that this action does not require a regulatory flexibility analysis since it is a rulemaking of particular applicability involving rates or services applicable to public property. E:\FR\FM\23SEN1.SGM 23SEN1 55830 Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices 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. Small Business Regulatory Enforcement Fairness Act Western has determined that this rule is exempt from congressional notification requirements under 5 U.S.C. 801 because the action is a rulemaking of particular applicability relating to rates or services and involves matters of procedure. Submission to the Federal Energy Regulatory Commission The interim rates herein confirmed, approved, and placed into effect, together with supporting documents, will be submitted to the Commission 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 October 1, 2005, formula rates for the IS Transmission and Ancillary Services under Rate Schedules UGP–FPT1, UGP– NFPT1, UGP–NT1, UGP–AS1, UGP– AS2, UGP–AS3, UGP–AS4, UGP–AS5, and UGP–AS6. The rate schedules shall remain in effect on an interim basis, pending the Commission’s confirmation and approval of them or substitute rates on a final basis through September 30, 2010. Dated: September 13, 2005. Clay Sell, Deputy Secretary. Rate Schedule UGP–AS1; October 1, 2005; Supersedes 1998 Schedule Upper Great Plains Region Integrated System: Scheduling, System Control, and Dispatch Service Effective The first day of the first full billing period beginning on or after October 1, 2005, through September 30, 2010, or until superseded by another rate schedule. Applicable This service is required to schedule the movement of power through, out of, within, or into the Western Area Upper Great Plains Balancing Authority (WAUGP). The charges for Scheduling, System Control, and Dispatch Service are to be based on the rate outlined below. The formula rate used to calculate the charges for service under this schedule was developed and may be modified under applicable Federal laws, regulations, and policies. The rate will be applied to all schedules for WAUGP nonTransmission Customers. The WAUGP will accept any reasonable number of schedule changes over the course of the day without any additional charge. The charges for Scheduling, System Control, and Dispatch Service may be modified upon written notice to the customer. Any change to the charges for the Scheduling, System Control, and Dispatch Service shall be as set forth in a revision to this rate schedule developed under applicable Federal laws, regulations, and policies and made part of the applicable Transmission Customer’s Service Agreement. The Upper Great Plains Region (UGPR) shall charge the nonTransmission Customer under the rate then in effect. Formula Rate Annual Revenue Requirement for Scheduling, System Control, and Dispatch Service Rate per Schedule per Day = Number of Daily Schedules per Year A recalculated rate will go into effect every May 1 based on the above formula and data. The UGPR will notify the customer annually of the recalculated rate on or before April 1. Rate Schedule UGP–AS2; October 1, 2005; Supersedes 1998 Schedule Upper Great Plains Region Integrated System: Reactive Supply and Voltage Control From Generation Sources Service Effective The first day of the first full billing period beginning on or after October 1, 2005, through September 30, 2010, or until superseded by another rate schedule. VerDate Aug<31>2005 15:21 Sep 22, 2005 Jkt 205001 Applicable To maintain transmission voltages on all transmission facilities within acceptable limits, generation facilities under the control of the Western Area Upper Great Plains balancing authority (WAUGP) are operated to produce or absorb reactive power. Thus, Reactive Supply and Voltage Control from Generation Sources Service (Reactive Service) must be provided for each transaction on the transmission facilities. The amount of Reactive Service that must be supplied with respect to the Transmission Customer’s transaction will be determined based on the Reactive Service necessary to maintain transmission voltages within limits that are generally accepted in the region and consistently adhered to by WAUGP. The Transmission Customer must purchase this service from the PO 00000 Frm 00016 Fmt 4703 Sfmt 4703 Transmission Provider. The charges for such service will be based upon the rate outlined below. The formula rate used to calculate the charges for service under this schedule was developed and may be modified under applicable Federal laws, regulations, and policies. The charges for Reactive Service may be modified upon written notice to the Transmission Customer. Any change to the charges for Reactive Service shall be as set forth in a revision to this rate schedule developed under applicable Federal laws, regulations, and policies and made part of the applicable Transmission Customer’s Service Agreement. The Upper Great Plains Region (UGPR) shall charge the Transmission Customer under the rate then in effect. Those Transmission Customers with generators in the balancing authority providing WAUGP with adequate E:\FR\FM\23SEN1.SGM 23SEN1 EN23SE05.060</MATH> Rate Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices Reactive Service will not be charged for this service. Any waiver of this charge or any crediting arrangements for Reactive Service must be documented in the Transmission Customer’s Service Agreement. 55831 Formula Rate Formula Rate WAUGP Annual Revenue Requirement for Reactive Service Reactive Service = Load Requiring Reactive Service Rate Rate A recalculated rate will go into effect every May 1 based on the above formula and updated financial and load data. The UGPR will notify the Transmission Customer annually of the recalculated rate on or before April 1. Rate Schedule UGP–AS3; October 1, 2005; Supersedes 1998 Schedule Upper Great Plains Region Integrated System: Regulation and Frequency Response Service Effective The first day of the first full billing period beginning on or after October 1, 2005, through September 30, 2010, or until superseded by another rate schedule. Applicable Regulation and Frequency Response Service (Regulation) is necessary to provide for the continuous balancing of resources, generation, and interchange with load and for maintaining scheduled interconnection frequency at 60 cycles per second (60 Hz). Regulation is accomplished by committing on-line generation whose output is raised or lowered, predominantly through the use of automatic generating control equipment, as necessary to follow the moment-by-moment changes in load. The obligation to maintain this balance between resources and load lies with the Western Area Upper Great Plains balancing authority (WAUGP) operator. The Transmission Customer must either purchase this service from WAUGP or make alternative comparable arrangements to satisfy its Regulation obligation. The charges for Regulation are outlined below. The amount of Regulation will be set forth in the applicable Transmission Customer’s Service Agreement. The formula rate used to calculate the charges for service under this schedule was developed and may be modified under applicable Federal laws, regulations, and policies. Charges for Regulation may be modified upon written notice to the Transmission Customer. Any change to the Regulation charges shall be as set forth in a revision to this rate schedule developed under applicable Federal laws, regulations, and policies and made part of the applicable Transmission Customer’s Service Agreement. The Upper Great Plains Region (UGPR) shall charge the Transmission Customer under the rate then in effect. Transmission Customers will not be charged for this service if they receive Regulation from another source, or selfsupply it for their own load. Any waiver of this charge or any crediting arrangement for Regulation must be documented in the Transmission Customer’s Service Agreement. Formula Rate WAUGP Annual Revenue Requirement for Regulation Regulation = Load in the Balancing Authority Requiring Regulation Rate Upper Great Plains Region Integrated System: Energy Imbalance Service Effective The first day of the first full billing period beginning on or after October 1, 2005, through September 30, 2010, or until superseded by another rate schedule. VerDate Aug<31>2005 15:21 Sep 22, 2005 Jkt 205001 Energy Imbalance Service is provided when a difference occurs between scheduled and actual delivery of energy to a load located within the Western Area Upper Great Plains Balancing Authority (WAUGP) over a single hour. The Transmission Customer must either obtain this service from WAUGP or make alternative comparable arrangements to satisfy its Energy Imbalance Service obligation. The WAUGP shall establish a deviation band of +/¥1.5 percent (with a minimum of 2 MW) of the scheduled transaction to be applied hourly to any energy imbalance that occurs as a result of the Transmission Customer’s scheduled transaction(s). Deviation accounting will be completed monthly on an hour-to-hour basis. The formula rate used to calculate the charges for service under this schedule was developed and may be modified PO 00000 Frm 00017 Fmt 4703 Sfmt 4703 under applicable Federal laws, regulations, and policies. The Energy Imbalance Service compensation may be modified upon written notice to the Transmission Customer. Any change to the Transmission Customer compensation for Energy Imbalance Service shall be as set forth in a revision to this schedule developed under applicable Federal laws, regulations, and policies and made part of the applicable Transmission Customer’s Service Agreement. The Upper Great Plains Region (UGPR) shall charge the Transmission Customer under the rate then in effect. Formula Rate The UGPR reserves the right to implement the following upon providing notice to the Transmission Customer. E:\FR\FM\23SEN1.SGM 23SEN1 EN23SE05.062</MATH> Rate Schedule UGP–AS4; October 1, 2005; Supersedes 1998 Schedule Applicable EN23SE05.061</MATH> Rate A recalculated rate will go into effect every May 1 based on the above formula and updated financial and load data. The UGPR will notify the Transmission Customer annually of the recalculated rate on or before April 1. If resources are not available from a WAUGP resource, the UGPR will offer to purchase the Regulation and pass through the costs, plus an amount for administration, to the Transmission Customer. 55832 Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices For negative excursions (under deliveries) outside the bandwidth, the WAUGP will assess a penalty charge of 100 mills/kWh. For positive excursions (over deliveries) outside the bandwidth, over deliveries of energy will be forfeited to the balancing authority. Rate The bandwidth in effect October 1, 2005, through September 30, 2006, is 3 percent (+/¥1.5 percent hourly deviation). Rate Schedule UGP–AS5; October 1, 2005; Supersedes 1998 Schedule Upper Great Plains Region Integrated System: Operating Reserve—Spinning Reserve Service Effective The first day of the first full billing period beginning on or after October 1, 2005, through September 30, 2010, or until superseded by another rate schedule. 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 Transmission Customer must either purchase this service from the Western Area Upper Great Plains balancing authority (WAUGP) or make alternative comparable arrangements to satisfy its Reserves obligation. The charges for Reserves are outlined below. The amount of Reserves will be set forth in the applicable Transmission Customer’s Service Agreement. The formula rate used to calculate the charges for service under this schedule was promulgated and may be modified under applicable Federal laws, regulations, and policies. The charges for Reserves may be modified upon written notice to the Transmission Customer. Any change to the charges for Reserves shall be as set forth in a revision to this rate schedule developed pursuant to applicable Federal laws, regulations, and policies and made part of the applicable Transmission Customer’s Service Agreement. The Upper Great Plains Region (UGPR) shall charge the Transmission Customer under the rate then in effect. Formula Rate WAUGP Annual Revenue Requirement for Regulation Regulation = Load in the Balancing Authority Requiring Regulation Rate Rate Schedule UGP–AS6; October 1, 2005; Supersedes 1998 Schedule Rate A recalculated rate will go into effect every May 1 based on the above formula and updated financial and load data. The UGPR will notify the Transmission Customer annually of the recalculated rate on or before April 1. If resources are not available from a WAUGP resource, the UGPR will offer to purchase the Reserves and pass through the costs, plus an amount for administration, to the Transmission Customer. In the event that Reserves are called upon for emergency use, the UGPR will assess a charge for energy used at the Mid-Continent Area Power Pool Rate for emergency energy, presently the greater of 30 mills/kWh or the prevailing market energy rate in the region. The Transmission Customer would be responsible for providing transmission service to get the Reserves to its destination. Upper Great Plains Region Integrated System: Operating Reserve— Supplemental Reserve Service Effective The first day of the first full billing period beginning on or after October 1, 2005, through September 30, 2010, or until superseded by another rate schedule. 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 Transmission Customer must either purchase this service from the Western Area Upper Great Plains Balancing Authority (WAUGP) or make alternative comparable arrangements to satisfy its Reserves obligation. The charges for Reserves are outlined below. The amount of Reserves will be set forth in the applicable Transmission Customer’s Service Agreement. The formula rate used to calculate the charges for service under this schedule was developed and may be modified under applicable Federal laws, regulations, and policies. The charges for Reserves may be modified upon written notice to the Transmission Customer. Any change to the charges for Reserves shall be as set forth in a revision to this rate schedule developed under applicable Federal laws, regulations, and policies and made part of the applicable Service Agreement. The Upper Great Plains Region (UGPR) shall charge the Transmission Customer under the rate then in effect. Formula Rate A recalculated rate will go into effect every May 1 based on the above formula and updated financial and load data. The UGPR will notify the Transmission VerDate Aug<31>2005 15:21 Sep 22, 2005 Jkt 205001 Customer annually of the recalculated rate on or before April 1. If resources are not available from a WAUGP resource, the UGPR will offer to purchase the Reserves and pass PO 00000 Frm 00018 Fmt 4703 Sfmt 4703 through the costs, plus an amount for administration, to the Transmission Customer. In the event Reserves are called upon for Emergency Energy, the UGPR will E:\FR\FM\23SEN1.SGM 23SEN1 EN23SE05.063</MATH> Rate EN23SE05.064</MATH> WAUGP Annual Revenue Requirement for Reserves Reserves = Load Requiring Reserves Rate Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices 55833 Rate Schedule UGP–FPT1; October 1, 2005; Supersedes 1998 Schedule Upper Great Plains Region Integrated System: Long-Term Firm and ShortTerm Firm Point-to-Point Transmission Service Effective The first day of the first full billing period beginning on or after October 1, 2005, through September 30, 2010, or until superseded by another rate schedule. Applicable The Transmission Customer shall compensate the Upper Great Plains Region (UGPR) each month for Reserved Capacity under the applicable Firm Point-to-Point Transmission Service Agreement and rates outlined below. The formula rates used to calculate the charges for service under this schedule were developed and may be modified under applicable Federal laws, regulations, and policies. The UGPR may modify the rate for Firm Point-to-Point Transmission Service upon written notice to the Transmission Customer. Any change to the rate for Firm Point-to-Point Transmission Service shall be as set forth in a revision to this rate schedule developed under applicable Federal laws, regulations, and policies and made part of the applicable Transmission Customer’s Service Agreement. The UGPR shall charge the Transmission Customer under the rate then in effect. follows: (1) Any offer of a discount made by the UGPR must be announced to all eligible Transmission Customers solely by posting on the Open Access Same-Time Information System (OASIS), (2) any Transmission Customer-initiated requests for discounts, including requests for use by one’s wholesale merchant or an affiliate’s use, 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, the UGPR must offer the same discounted transmission service rate for the same time period to all eligible Transmission Customers on all unconstrained transmission paths that go to the same point(s) of delivery on the Transmission System. Discounts Three principal requirements apply to discounts for transmission service as assess a charge for energy used at the Mid-Continent Area Power Pool Rate for Emergency Energy, presently the greater of 30 mills/kWh or the prevailing market energy rate in the region. The Transmission Customer would be responsible for providing transmission service to get the Reserves to its destination. Formula Rate i Firm Point-to-Point = Annual IS Transmission Service Revenue Requirement Transmission Rate a IS Transmission System Total Load Discounts Three principal requirements apply to discounts for transmission service as Rate Schedule UGP–NFPT1; October 1, 2005; Supersedes 1998 Schedule Upper Great Plains Region Integrated System: Non-Firm Point-to-Point Transmission Service Effective The first day of the first full billing period beginning on or after October 1, 2005, through September 30, 2010, or until superseded by another rate schedule. Formula Rate Maximum Non-Firm 730 hours Point-to-Point = Firm Point-to-Point ÷ per month × 1000 mills Transmission Rate per dollar Transmission Rate VerDate Aug<31>2005 15:21 Sep 22, 2005 Jkt 205001 PO 00000 Frm 00019 Fmt 4703 Sfmt 4725 E:\FR\FM\23SEN1.SGM 23SEN1 EN23SE05.066</MATH> The Transmission Customer shall compensate the Upper Great Plains Region (UGPR) for Non-Firm Point-to- A recalculated rate will go into effect every May 1 based on the above formula and updated financial and load data. The UGPR will notify the Transmission Customer annually of the recalculated rate on or before April 1. follows: (1) Any offer of a discount made by the UGPR must be announced to all eligible Transmission Customers solely by posting on the Open Access Same-Time Information System (OASIS), (2) any Transmission Customer-initiated requests for discounts, including requests for use by one’s wholesale merchant or an affiliate’s use, 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, the UGPR must offer the same discounted transmission service rate for the same time period to all eligible Transmission Customers on all unconstrained transmission paths that go to the same point(s) of delivery on the Transmission System. EN23SE05.065</MATH> Applicable Point Transmission Service under the applicable Non-Firm Point-to-Point Transmission Service Agreement and rate outlined below. The formula rates used to calculate the charges for service under this schedule were developed and may be modified under applicable Federal laws, regulations, and policies. The UGPR may modify the rate for Non-Firm Point-to-Point Transmission Service upon written notice to the Transmission Customer. Any change to the rate for Non-Firm Point-to-Point Transmission Service shall be as set forth in a revision to this rate schedule developed under applicable Federal laws, regulations, and policies and made part of the applicable Transmission Customer’s Service Agreement. The UGPR shall charge the Transmission Customer under the rate then in effect. Rate 55834 Federal Register / Vol. 70, No. 184 / Friday, September 23, 2005 / Notices Rate A recalculated rate will go into effect every May 1 based on the above formula and updated financial and load data. The UGPR will notify the Transmission Customer annually of the recalculated rate on or before April 1. Rate Schedule UGP–NT1; October 1, 2005; Supersedes 1998 Schedule Upper Great Plains Region Integrated System: Annual Transmission Revenue Requirement for Network Integration Transmission Service Effective The first day of the first full billing period beginning on or after October 1, The Transmission Customer shall compensate the Upper Great Plains Region (UGPR) each month for Network Transmission Service under the applicable Network Integration Transmission Service Agreement and annual revenue requirement outlined below. The formula for the annual revenue requirement used to calculate the charges for this service under this schedule was developed and may be modified under applicable Federal laws, regulations, and policies. Formula Rate (Transmission Customer’s Load-Ratio Share × Annual Revenue Requirment for IS Transmission Service) 12 months Annual Revenue Requirement A recalculated annual revenue requirement will go into effect every May 1 based on updated financial data. The UGPR will notify the Transmission Customer annually of the recalculated annual revenue requirement on or before April 1. [FR Doc. 05–19039 Filed 9–22–05; 8:45 am] BILLING CODE 6450–01–P ENVIRONMENTAL PROTECTION AGENCY [ER–FRL–6667–7] Environmental Impact Statements and Regulations; Availability of EPA Comments Availability of EPA comments prepared pursuant to the Environmental Review Process (ERP), under section 309 of the Clean Air Act and Section 102(2)(c) of the National Environmental Policy Act as amended. Requests for copies of EPA comments can be directed to the Office of Federal Activities at 202–564–7167. An explanation of the ratings assigned to draft environmental impact statements (EISs) was published in the Federal Register dated April 1, 2005 (70 FR 16815). Draft EISs EIS No. 20050187, ERP No. D–SFW– F64005–00, Upper Mississippi National Wildlife and Fish Refuge Comprehensive Conservation Plan (CCP) Implementation, MN, WI, IL and IA. Summary: EPA has no objections to the Preferred Alternative, and recommends that the Final EIS address VerDate Aug<31>2005 Applicable The UGPR may modify the charges for Network Integration Transmission Service upon written notice to the Transmission Customer. Any change to the charges to the Transmission Customer for Network Integration Transmission Service shall be as set forth in a revision to this rate schedule promulgated developed under applicable Federal laws, regulations, and policies and made part of the applicable Transmission Customer’s Service Agreement. The UGPR shall charge the Transmission Customer under the revenue requirement then in effect. 15:21 Sep 22, 2005 Jkt 205001 how the plan will be integrated with the Upper Mississippi River Navigation Ecosystem Sustainability Program. Rating LO. EIS No. 20050209, ERP No. D–NPS– J65442–WY, Grand Teton National Park Transportation Plan, Implementation, Grand Teton National Park, Teton County, WY. Summart: EPA expressed concerns about wetland mitigation and storm water impacts. Rating EC2. EIS No. 20050259, ERP No. D–FHW– C40166–NY, Southtowns Connector/ Buffalo Outer Harbor Project, Improvements on the NYS Route 5 Corridor from Buffalo Skyway Bridge to NYS Route 179, in the City of Buffalo, City of Lackawanna and Town of Hamburg, Erie County, NY. Summary: EPA expressed concerns about assessment of cumulative impacts. Rating EC2. EIS No. 20050274, ERP No. D–AFS– J61107–ND, NE McKenzie Allotment Management Plan Revisions, Proposes to Continue Livestock Grazing on 28 Allotments, Dakota Prairie Grasslands Land and Resource Management Plan, Dakota Prairie Grasslands, McKenzie Ranger District, McKenzie County, ND. Summary: EPA expressed concerns about potential water quality impacts from sediment, fecal coliform and temperature modification in streams and other surface waters, and recommended reducing water quality impacts near aquatic/riparian resources by working with permittees and other stakeholders, and develop adaptive management monitoring. Rating EC2. EIS No. 20050281, ERP No. D–AFS– K65287–CA, North Fork Eel Grazing PO 00000 Frm 00020 Fmt 4703 Sfmt 4703 Allotment Management Project, Proposing to Authorize Cattle Grazing on Four Allotment, Six Rivers National Forest, Mad River Ranger District, North Fork Eel River and Upper Mad River, Trinity County, CA. Summary: EPA has no objection to the proposed action. Rating LO. EIS No. 20050306, ERP No. D–FHW– H40185–00, U.S. Highway 34, Plattsmouth Bridge Study, over the Missouri River between U.S. 75 and I– 29, Funding, Coast Guard Permit, U.S. Army COE 10 and 404 Permits, Cass County, NE and Mills County, IA. Summary: EPA expressed concerns about potential wetland, floodplain, stream, and cumulative impacts. Rating EC2. EIS No. 20050311, ERP No. D–NPS– H65025–NE, Niobrara National Scenic River General Management Plan, Implementation, Brown, Cherry, Keya Paha and Rock Counties, NE. Summary: EPA has no objection to the proposed action. Rating LO. EIS No. 20050294, ERP No. DR–COE– K11114–CA, Mare Island Reuse of Dredged Material Disposal Ponds as a Confirmed Updated Dredged Material Disposal Facility, Issuing Section 404 Permit Clean Water Act and Section 10 Permit Rivers and Harbor Act, San Francisco Bay Area, City of Vallejo, Solando County, CA. Summary: Many of EPA’s objections to the original Draft EIS were addressed in this revised document. However, EPA continues to have concerns about the delegation of responsibility for site operations and associated environmental safeguards, as well as implementation of wetlands restoration measures. Rating EC2.FINAL EISs. E:\FR\FM\23SEN1.SGM 23SEN1 EN23SE05.067</MATH> Monthly Charge = 2005, through September 30, 2010, or until superseded by another rate schedule.

Agencies

[Federal Register Volume 70, Number 184 (Friday, September 23, 2005)]
[Notices]
[Pages 55821-55834]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 05-19039]



[[Page 55821]]

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DEPARTMENT OF ENERGY

Western Area Power Administration


Pick-Sloan Missouri Basin Program--Eastern Division Transmission 
and Ancillary Services-Rate Order No. WAPA-122

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of Order Concerning Transmission and Ancillary Services 
Rates.

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

SUMMARY: The Deputy Secretary of Energy confirmed and approved Rate 
Order No. WAPA-122 and Rate Schedules UGP-FPT1, UGP-NFPT1, UGP-NT1, 
UGP-AS1, UGP-AS2, UGP-AS3, UGP-AS4, UGP-AS5, and UGP-AS6 placing the 
Integrated System (IS) Transmission and Ancillary Services rate into 
effect on an interim basis. The provisional rates will be in effect 
until the Federal Energy Regulatory Commission (Commission) confirms, 
approves, and places them into effect on a final basis or until they 
are replaced by other rates. The provisional rates will provide 
sufficient revenue to pay all annual costs, including interest expense, 
and repayment of required investment, within the allowable periods.

DATES: Rate Schedules UGP-FPT1, UGP-NFPT1, UGP-NT1, UGP-AS1, UGP-AS2, 
UGP-AS3, UGP-AS4, UGP-AS5, and UGP-AS6 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, 2005, and will be in effect until the 
Commission confirms, approves, and places the rate schedules in effect 
on a final basis through September 30, 2010, or until the rate 
schedules are superseded. These new rate schedules dated October 2005, 
supersede the similarly titled rate schedules dated 1998.

FOR FURTHER INFORMATION CONTACT: Mr. Robert J. Harris, Upper Great 
Plains Regional Manager, Western Area Power Administration, 2900 4th 
Avenue North, Billings, MT 59101-1266, telephone (406) 247-7405, or Mr. 
Jon R. Horst, Rates Manager, Upper Great Plains Region, Western Area 
Power Administration, 2900 4th Avenue North, Billings, MT 59101-1266, 
telephone (406) 247-7444, e-mail horst@wapa.gov.

SUPPLEMENTARY INFORMATION: The Deputy Secretary of Energy approved 
existing Rate Schedules UGP-FPT1, UGP-NFPT1, UGP-NT1, UGP-AS1, UGP-AS2, 
UGP-AS3, UGP-AS4, UGP-AS5, and UGP-AS6 for IS Transmission and 
Ancillary Service rates on August 1, 1998, in Rate Order No. WAPA-79. 
The Commission confirmed and approved the rate schedules on November 
25, 1998, in FERC Docket No. EF98-5031-000. These rate schedules were 
then extended through September 30, 2005, by Rate Order No. WAPA-100, 
which was confirmed and approved by the Commission on December 16, 
2003, under FERC Docket No. EF03-5032-000. The rate schedules for Rate 
Order No. WAPA-79 and Rate Order No. WAPA-100 contained formulary rates 
that were recalculated yearly using the fixed charge rate methodology. 
The provisional formula rates will continue to use the fixed charge 
rate methodology and will continue to be recalculated yearly from 
updated financial and load data. However, the Generator Step Up 
Transformers are to be removed from the annual revenue requirement for 
IS. After the approval of the original Transmission and Ancillary 
Service rates for the IS, the Commission decided that Generator Step Up 
Transformers should not be included in transmission rates for 
jurisdictional utilities. Consistent with Western's goal to observe 
Commission precedent to the extent consistent with its mission and 
permitted by law and regulation, the IS Transmission and Ancillary 
Service rates are being modified.
    The existing IS Long-Term Firm and Short-Term Firm Point-to-Point 
Transmission Service Rate Schedule is superseded by Rate Schedule UGP-
FPT1, dated October 2005. The 2004-2005 existing rate for IS Long-Term 
Firm and Short-Term Firm Point-to-Point Transmission Service is $2.72 
per kilowattmonth (kWmonth). The provisional rate for IS Long-Term Firm 
and Short-Term Firm Point-to-Point Transmission Service is $2.69/
KWmonth. Under Rate Schedule UGP-NFPT1, the existing rate calculation 
for IS Non-Firm Point-to-Point Transmission Service is 3.73 mills per 
kilowatthour (mills/kWh). The provisional rate for IS Non-Firm Point-to 
Point Transmission Service is 3.68 mills/kWh. Under Rate Schedule UGP-
NT1 the existing annual revenue requirement for IS Network Integration 
Transmission Service is $128,017,923. The provisional annual revenue 
requirement for IS Network Integration Transmission Service is 
$126,741,576.
    Under Rate Schedule UGP-AS1, the existing rate for Scheduling 
System Control and Dispatch (Scheduling and Dispatch) Service is 
$49.29/schedule/day. The provisional rate for Scheduling and Dispatch 
is $49.77/schedule/day. Under Rate Schedule UGP-AS2, the existing rate 
for Reactive Supply and Voltage Control from Generation Sources Service 
(Reactive Service) is $0.06/kWmonth. The provisional rate for Reactive 
Service is $0.07/kWmonth. Under Rate Schedule UGP-AS3, the provisional 
rate calculated for Regulation and Frequency Response Service is 
unchanged from the existing rate of $0.04/kWmonth. Under Rate Schedule 
UGP-AS4, there is no change in the rate for Energy Imbalance Service 
between the existing and the proposed rates. Under Rate Schedules UGP-
AS5 and UGP-AS6, the rate for Spinning and Supplemental Reserves is 
$0.11/kWmonth. The provisional rate calculated for Spinning and 
Supplemental Reserves is $0.12/kWmonth.
    By Delegation Order No. 00-037.00, effective December 6, 2001, the 
Secretary of Energy delegated: (1) The authority to develop power and 
transmission rates to Western's Administrator, (2) the authority to 
confirm, approve, and place such rates into effect on an interim basis 
to the Deputy Secretary of Energy, and (3) the authority to confirm, 
approve, and place into effect on a final basis, to remand or to 
disapprove such rates to the Commission. Existing DOE procedures for 
public participation in power rate adjustments (10 CFR part 903) were 
published on September 18, 1985.
    Under Delegation Order Nos. 00-037.00 and 00-001.00A, 10 CFR part 
903, and 18 CFR part 300, I hereby confirm, approve, and place Rate 
Order No. WAPA-122, the proposed IS Firm and Non-Firm Transmission and 
Ancillary Service rates into effect on an interim basis. The new Rate 
Schedules UGP-FPT1, UGP-NFPT1, UGP-NT1, UGP-AS1, UGP-AS2, UGP-AS3, UGP-
AS4, UGP-AS5, and UGP-AS6 for IS Transmission and Ancillary Service 
rates will be promptly submitted to the Commission for confirmation and 
approval on a final basis.

    Dated: September 13, 2005.
Clay Sell,
Deputy Secretary.

[Rate Order No. WAPA-122]

    In the matter of: Western Area Power Administration Rate 
Adjustment for the Pick-Sloan Missouri Basin Program--Eastern 
Division Transmission and Ancillary Services; Order Confirming, 
Approving, and Placing the Pick-Sloan Missouri Basin Program--
Eastern Division Transmission and Ancillary Services Formula Rates 
Into Effect on an Interim Basis

    This rate was established in accordance with section 302 of the 
Department of Energy (DOE) Organization Act (42 U.S.C. 7152). This Act 
transferred to and vested in the

[[Page 55822]]

Secretary of Energy the power marketing functions of the Secretary of 
the Department of the Interior and the Bureau of Reclamation under the 
Reclamation Act of 1902 (ch. 1093, 32 Stat. 388), as amended and 
supplemented by subsequent laws, particularly section 9(c) of the 
Reclamation Project Act of 1939 (43 U.S.C. 485h(c)), section 5 of the 
Flood Control Act of 1944 (16 U.S.C. 825s), and other Acts that 
specifically apply to the project involved.
    By Delegation Order No. 00-037.00, effective December 6, 2001, the 
Secretary of Energy delegated: (1) The authority to develop power and 
transmission rates to Western's Administrator, (2) the authority to 
confirm, approve, and place such rates into effect on an interim basis 
to the Deputy Secretary of Energy, and (3) the authority to confirm, 
approve, and place into effect on a final basis, to remand or to 
disapprove such rates to the Commission. Existing DOE procedures for 
public participation in power rate adjustments (10 CFR part 903) were 
published on September 18, 1985.

Acronyms and Definitions

    As used in this Rate Order, the following acronyms and definitions 
apply:
    $/kWmonth: Monthly charge for capacity (i.e., $ per kilowatt (kW) 
per month).
    12-cp: 12-month coincident peak average.
    Administrator: The Administrator of the Western Area Power 
Administration.
    Ancillary Services: Those services necessary to support the 
transfer of electricity while maintaining reliable operation of the 
transmission system in accordance with standard utility practice.
    A&GE: Administrative and general expense.
    Balancing Authority: An electric system or systems, bounded by 
interconnection metering and telemetry, capable of controlling 
generation to maintain its interchange schedule with other Balancing 
Authorities and contributing to frequency regulation of the 
Interconnection. Formerly known as control area.
    Basin Electric: Basin Electric Power Cooperative.
    Capacity: The electric capability of a generator, transformer, 
transmission circuit, or other equipment. It is expressed in kilowatts.
    Capacity Rate: The rate which sets forth the charges for capacity. 
It is expressed in $/kWmonth.
    Commission: Federal Energy Regulatory Commission.
    Corps of Engineers: U.S. Army Corps of Engineers.
    Customer: An entity with a contract that is receiving service from 
Western's UGPR.
    DOE: United States Department of Energy.
    DOE Order RA 6120.2: An order outlining power marketing 
administration financial reporting and ratemaking procedures.
    Energy: Measured in terms of the work capacity over a period of 
time. It is expressed in kilowatthours.
    Emergency Energy: Electric energy purchased by an electric utility 
whenever an event on the system causes insufficient operating 
capability to cover its own demand requirement.
    Energy Imbalance Service: A service which provides energy 
correction for any hourly mismatch between a Transmission Customer's 
energy supply and the demand served.
    Energy Rate: The rate which sets forth the charges for energy. It 
is expressed in mills per kilowatthour and applied to each kilowatthour 
delivered to each customer.
    FERC: The Commission (to be used when referencing Commission 
Orders).
    FERC Order No. 888: FERC Order Nos. 888, 888-A, 888-B and 888-C 
unless otherwise noted.
    Firm: A type of product and/or service available at the time 
requested by the customer.
    Firm Point-to-Point: Service that is reserved and/or scheduled 
between Points of Receipt and Delivery.
    FRN: Federal Register notice.
    FY: Fiscal year; October 1 to September 30.
    GSU: Generator Step Up Transformer.
    GWh: Gigawatthour--the electrical unit of energy that equals 1 
billion watthours or 1 million kWh.
    Heartland: Heartland Consumers Power District.
    IS: Integrated System.
    ISO: Independent System Operator.
    JTS: Joint Transmission System.
    kW: Kilowatt--the electrical unit of capacity that equals 1,000 
watts.
    kWh: Kilowatthour--the electrical unit of energy that equals 1,000 
watts in 1 hour.
    kWmonth: Kilowattmonth--the electrical unit of the monthly amount 
of capacity.
    kWyear: Kilowattyear--the electrical unit of the yearly amount of 
capacity.
    Load: The amount of electric power or energy delivered or required 
at any specified point(s) on a system.
    Load-ratio share: Ratio of the Network Transmission Customer's 
coincident hourly load (including its designated network load not 
physically interconnected with the Transmission Provider) to the 
Transmission Provider's monthly Transmission System peak, calculated on 
a rolling 12-month basis.
    Long-Term Firm Point-to-Point: Firm Point-to-Point Transmission 
Service reservation with at least 12 consecutive equal monthly amounts.
    MAPP: Mid-Continent Area Power Pool.
    MBMPA: Missouri Basin Municipal Power Agency.
    Mill: A monetary denomination of the United States that equals one 
tenth of a cent or one thousandth of a dollar.
    Mills/kWh: Mills per kilowatthour--the unit of charge for energy.
    MVAR: Megavar, equal to 1,000,000 VARs.
    MW: Megawatt--the electrical unit of capacity that equals 1 million 
watts or 1,000 kilowatts.
    NERC: North American Electric Reliability Council.
    Net Revenue: Revenue remaining after paying all annual expenses.
    Network Customer: An entity receiving Transmission Service under 
the terms of the Transmission Provider's Network Integration 
Transmission Service of the Tariff.
    Non-Firm Point-to-Point: Point-to-Point Transmission Service under 
the Tariff that is reserved and scheduled on an as-available basis and 
is subject to interruption for economic reasons.
    O&M: Operation and maintenance.
    OASIS: Open Access Same-Time Information System--provides access to 
information on transmission pricing and availability for potential 
transmission customers.
    OM&R: Operation, Maintenance & Replacement.
    P-SMBP: Pick-Sloan Missouri Basin Program.
    P-SMBP--ED: Pick-Sloan Missouri Basin Program--Eastern Division.
    Point-to-Point: The reservation and transmission of capacity and 
energy on either a firm or non-firm basis from designated Point(s) of 
Receipt to designated Point(s) of Delivery.
    Power: Capacity and energy.
    Provisional Rate: A rate which has been confirmed, approved, and 
placed into effect on an interim basis by the Deputy Secretary.
    Rate Brochure: An April 2005 document explaining the rationale and 
background for the rate proposal contained in this Rate Order.
    Reclamation: United States Department of the Interior, Bureau of 
Reclamation.
    Reclamation Law: A series of Federal laws. Viewed as a whole, these 
laws

[[Page 55823]]

create the framework under which Western markets power.
    Reactive Supply and Voltage Control from Generating Sources 
Service: A service which provides reactive supply through changes to 
generator reactive output to maintain transmission line voltage and 
facilitate electricity transfers.
    Regulation and Frequency Response Service: A service which provides 
for following the moment-to-moment variations in the demand or supply 
in a Balancing Authority and maintaining scheduled interconnection 
frequency.
    Reserve Services: Spinning Reserve Service and Supplemental Reserve 
Service.
    Revenue Requirement: The revenue required to recover annual 
expenses (such as O&M, purchase power, transmission service expenses, 
interest, and deferred expenses) and repay Federal investments, and 
other assigned costs.
    SCADA: Supervisory Control and Data Acquisition.
    Schedule: An agreed-upon transaction size (megawatts), beginning 
and ending ramp times and rate, and type of service required for 
delivery and receipt of power between the contracting parties and the 
Balancing Authority(ies) involved in the transaction.
    Scheduling, System Control and Dispatch Service: A service which 
provides for (a) scheduling, (b) confirming and implementing an 
interchange schedule with other balancing authorities, including 
intermediary balancing authorities providing transmission service, and 
(c) ensuring operational security during the interchange transaction.
    Service Agreement: The initial agreement and any amendments or 
supplements entered into by the Transmission Customer and Western for 
service under the Tariff.
    Short-Term Firm Point-to-Point: Firm Point-to-Point Transmission 
Service with service duration of less than one year.
    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. The Transmission Provider must offer this 
service when the transmission service is used to serve load within its 
Balancing Authority. The Transmission Customer must either purchase 
this service from the Transmission Provider or make alternative 
comparable arrangements to satisfy its Spinning Reserve Service 
obligation.
    Supplemental Reserve Service: Generation capacity 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. 
Supplemental Reserve Service may be provided by generation units that 
are on-line but unloaded, by quick start generation or by interruptible 
load. The Transmission Provider must offer this service when the 
transmission service is used to serve load within its Balancing 
Authority. The Transmission Customer must either purchase this service 
from the Transmission Provider or make alternative comparable 
arrangements to satisfy its Supplemental Reserve Service obligation.
    Supporting Documentation: A compilation of data and documents that 
support the Rate Brochure and the rate proposal.
    System: An interconnected combination of generation, transmission 
and/or distribution components comprising an electric utility, 
independent power producer(s) (IPP), or group of utilities and IPP(s).
    Tariff: Western Area Power Administration Open Access Transmission 
Service Tariff, originally approved in Docket No. NJ98-1-000, 99 FERC ] 
61,062 (2002) and amended in Docket No. NJ05-1-000, 112 FERC ] 61,044 
(2005).
    Transmission Customer: Any eligible customer (or its designated 
agent) that receives transmission service under the Tariff.
    Transmission Provider: Any utility that owns, operates, or controls 
facilities used to transmit electric energy in interstate commerce. The 
UGPR, as operator of the IS, is the Transmission Provider for the 
purposes of this Federal Register notice.
    Transmission System: The facilities owned, controlled, or operated 
by the Transmission Provider that are used to provide transmission 
service.
    Transmission System Total Load: The 12-cp peak for Network 
Transmission Service plus reserved capacity for all Firm Point-to-Point 
Transmission Service.
    UGPR: The Upper Great Plains Customer Service Region of the Western 
Area Power Administration. In some places in this order, UGPR maybe 
referenced generically as Western.
    VAR: A unit of reactive power.
    WAUGP: The NERC acronym for the Western Area Upper Great Plains 
Balancing Authority. This balancing authority is also known as the 
Watertown Balancing Authority.
    Watertown Operation Office: Western Area Power Administration Upper 
Great Plains Customer Service Region, Operations Office, 1330 41st 
Street SE., Watertown, South Dakota.
    Western: United States Department of Energy, Western Area Power 
Administration.
    Western Regions: Customer service regions of the Western Area Power 
Administration.
    Western's Tariff: Western's Open Access Transmission Service 
Tariff.

Effective Date

    The new interim rates will take effect on the first day of the 
first full billing period beginning on or after October 1, 2005, and 
will remain in effect until September 30, 2010, pending approval by the 
Commission on a final basis.

Public Notice and Comment

    Western followed the Procedures for Public Participation in Power 
and Transmission Rate Adjustments and Extensions, 10 CFR part 903, for 
a minor rate adjustment in developing these rates. The steps Western 
took to involve interested parties in the rate process were:
    1. The proposed rate adjustment process began February 9, 2005, 
when Western mailed a notice announcing an informal customer meeting to 
all IS Transmission Customers and interested parties. The meeting was 
held on March 22, 2005, in Sioux Falls, South Dakota. At this informal 
meeting, Western explained the rationale for the rate adjustment, 
presented rate designs and methodologies, and answered questions.
    2. A Federal Register notice published on April 18, 2005, (70 FR 
20119), announced the proposed rates for P-SMBP--ED Transmission and 
Ancillary Service rates, and began a public consultation and comment 
period.
    3. On April 28, 2005, Western mailed letters to all IS Transmission 
Customers and interested parties transmitting the Federal Register 
notice published on April 18, 2005, and directing them to the rate 
brochure on Western's Web site.
    4. Western received no comment letters during the consultation and 
comment period, which ended May 18, 2005.

Project Description

    The initial stages of the Missouri River Basin Project were 
authorized by section 9 of the Flood Control Act of 1944 (58 Stat. 887, 
890, Pub. L. 78-534). It was later renamed the P-SMBP. The P-SMBP is a 
comprehensive program, with the following authorized functions: flood 
control, navigation improvement, irrigation, municipal and industrial 
water development, and hydroelectric

[[Page 55824]]

production for the entire Missouri River Basin. Multipurpose projects 
have been developed on the Missouri River and its tributaries in 
Colorado, Montana, Nebraska, North Dakota, South Dakota, and Wyoming.
    The UGPR markets significant quantities of Federally-generated 
hydroelectric power from the P-SMBP--ED. Western owns and operates an 
extensive system of high-voltage transmission facilities which the UGPR 
uses to market approximately 2,400 MW of capacity from Federal projects 
within the Missouri River Basin. This capacity is generated by eight 
powerplants located in Montana, North Dakota, and South Dakota. The 
UGPR uses the transmission facilities of Western and others to market 
this power and energy to customers located within the P-SMBP--ED. This 
marketing area includes Montana, east of the Continental Divide, all of 
North and South Dakota, eastern Nebraska, western Iowa, and western 
Minnesota.

Integrated System Description

    Using a single system, joint-planning concept, the UGPR, Basin 
Electric, and Heartland combined their transmission facilities to form 
the IS and developed Transmission and Ancillary Service rates for 
transmission over the IS. This action was necessary because the UGPR, 
Basin Electric, and Heartland, whose facilities are fully integrated, 
did not have rates suitable for long-term open access transmission 
service. The transmission facilities included in the IS are 
transmission lines, substations, communication equipment and facilities 
related to operation, maintenance, and support of the IS Transmission 
System. The UGPR is designated as the operator of the other 
participants' transmission facilities and as such contracts for 
service, determines and posts the available transmission capacity on 
the OASIS, bills for service, collects payments, and distributes 
revenues to each IS participant. The IS consists of the transmission 
facilities owned by Basin Electric and Heartland east of the east-west 
electrical separation in the United States, the transmission facilities 
owned by Western in the P-SMBP--ED, and the Miles City DC Tie owned by 
Western and Basin Electric. These facilities interconnect with 
utilities in the states of Montana, North Dakota, South Dakota, Iowa, 
Minnesota, Missouri, and in addition include facilities which 
interconnect with Canada.
    The approach for formation of the IS was to include facilities 
which followed the spirit and intent of the FERC Order No. 888 and to 
make the system the most useful to all transmission requesters. The 
``seven-factor test'' defined in FERC Order No. 888 was used to 
determine the distribution facilities that were excluded from the IS 
Transmission System. Several major facilities are included in the IS. 
The second 345-kV transmission line between the Antelope Valley and 
Leland Olds generation stations, which meets the standards for 
acceptable transmission facilities set in the Commission rulings on 
filings by other transmission entities, is included. The 230-kV 
transmission line between Tioga, North Dakota, and Boundary Dam, which 
provides access to generation and loads in Canada, is included in the 
IS. The IS also includes the Miles City DC tie, which opens the markets 
between the east-west electrical separation of the United States and 
increases access to other utilities.

P-SMBP--ED Transmission and Ancillary Service Rates Study

    Western prepared a Transmission and Ancillary Service rates study 
to ensure that Transmission and Ancillary Service rates are based on 
the cost of service of the IS Transmission System. This study includes 
all IS Transmission and Ancillary Service expenses and associated 
offsetting revenues. Western charges IS Transmission Service rates 
separately to entities receiving transmission-only services over the IS 
Transmission System.
    The UGPR is proposing to continue using an annual fixed charge 
formula that will determine how much revenue must be recovered from the 
IS Transmission and Ancillary Service rates. The annual revenue 
requirements include O&M expenses, administrative and general expenses, 
interest expense, and depreciation expense. This methodology is applied 
annually using the most recent historical test year. These revenue 
requirements are offset by appropriate IS revenues.

Integrated System Transmission Service

    Western will offer Network, Firm Point-to-Point, and Non-Firm 
Point-to-Point Transmission Service on the IS. The service offered is 
the transmission of energy and capacity from Points of Receipt to 
Points of Delivery on the IS. The IS Transmission Service Rates include 
the cost of Scheduling, System Control and Dispatch Service. Therefore, 
an additional charge for this ancillary service is not required for 
transmission users.
    Western, Basin Electric, and Heartland will take IS Transmission 
Service. Transmission Service to Western's Customers continues to be 
bundled in the firm electric power service rate under existing 
contracts that expire in 2020.
    The UGPR prepared a transmission service study to ensure that the 
formula IS Transmission and Ancillary Service rates are based on the 
cost of service to the IS. The UGPR seeks approval of formula rates for 
calculating Point-to-Point IS Transmission Rates, the Network Annual 
Revenue Requirement for IS Transmission Service, and ancillary service 
rates. Western requests the Commission confirm that these rates are not 
arbitrary, capricious, or in violation of the law. The rates will be 
recalculated every year, effective May 1, based on the approved formula 
rates and updated financial and load data. The UGPR will provide 
customers notice of changes in the Transmission and Ancillary Service 
rates no later than April 1 of each year.

IS Transmission System Total Load

    The IS Transmission System Total Load is the 12-cp system peak for 
IS Network Transmission Service plus the reserved capacity for all IS 
Long-Term Firm Point-to-Point Transmission Service.
    The IS Transmission System Total Load is calculated as follows 
based upon the most recent historical data available at the time of the 
initial rate proposal. This included both 2003 and 2004 data:

IS Network Transmission Load........................        3,185,000 kW
Long-Term Firm Point-to-Point Reserved Capacity.....          743,000 kW
                                                     -------------------
IS Transmission System Total Load...................        3,928,000 kW
 

Annual Costs

    Western calculated the annual costs of providing the various IS 
Transmission and Ancillary Services using a Commission-recognized 
methodology for annual cost calculation with fixed charge rates for 
various cost components. The cost components applicable to Western 
include O&M,

[[Page 55825]]

A&GE, depreciation, and the cost of capital. These components are 
displayed as fixed charge rates or percentages of net investment. These 
fixed charge rates are then summed to arrive at a total fixed charge 
rate associated with the particular service for which a rate is being 
calculated. The fixed charge rate calculation for the various IS 
Transmission and Ancillary Services can be summarized with the 
following formula:

                                          O&M / Net investment
                                          + A&GE / Net investment
                                          + Depreciation expense / Net investment
                                          +Annual interest expense / Unpaid investment balance
                                         ------------------------------------------------------------------------------------
                                          Total fixed charge rate
 

To arrive at the annual cost of providing the IS Transmission Service 
or one of the Ancillary Services, the total fixed charge rate is 
applied to the net investment allocated to the service:
    Total fixed charge rate x Net investment = Annual cost of providing 
service.
    The source for the UGPR's annual O&M, A&GE, depreciation expense, 
interest expense, and investment is the Results of Operations for the 
Upper Great Plains Customer Service Region-Pick Sloan Missouri Basin. 
The source for Heartland's data is Heartland Consumers Power District 
Annual Report. The sources for Basin Electric's data are Basin 
Electric's Consolidated Financial Statement, Rural Utility Service Form 
12, and other accounting records.

Annual Revenue Requirement for IS Transmission Service

    The annual revenue requirement for IS Transmission Service is based 
upon the most recent historical data available at the time of the 
initial rate proposal. This data is used in a test year and uses an 
annual fixed charge methodology. The rates for IS Transmission Service 
(Network and Point-to-Point) are based on a revenue requirement that 
recovers the annual costs of Western, Basin Electric, and Heartland 
associated with providing the IS Transmission Service plus any facility 
credit paid to the IS Transmission Customers. The annual revenue 
requirement for IS Transmission Service includes the cost for 
Scheduling, System Control, and Dispatch Service needed to provide 
transmission service. Therefore, an additional charge for this 
ancillary service is not required for transmission users. The annual 
transmission costs are offset by appropriate Transmission Revenue 
Credits to avoid over-recovery of costs. The annual revenue requirement 
for IS Transmission Service can be summarized with the following 
formula:

                                        Annual IS Transmission Costs of UGPR
                                        + Annual IS Transmission Costs Basin Electric and Heartland
                                        + Transmission Customer Facility Credits
                                        - Transmission Revenue Credits
                                       ----------------------------------------------------------------------------------------
                                        Annual Revenue Requirement for IS Transmission Service
 

    Transmission Customer Facility Credits are credits paid to IS 
Transmission Customers for facilities that are integrated with the IS 
and increase both the capability and the reliability of the IS. The 
credits are addressed in individual agreements and appropriate 
adjustments are made in subsequent rate calculations. The IS 
participants will evaluate requests for facility credits consistent 
with the Commission's guidance in the FERC Order No. 888, other 
relevant Commission policy, and the terms of the Tariff.
    Transmission Revenue Credits include revenue from sales of Non-
Firm, discounted IS Firm and Short-Term Firm Point-to-Point 
Transmission Service; revenue from existing transmission agreements; 
and revenue from Scheduling, System Control and Dispatch Services.

IS Network Transmission Service

    The proposed rate for IS Network Transmission Service is a formula 
calculation based upon the annual revenue requirement for IS 
Transmission Service then in effect, as determined by the annual fixed 
charge methodology. The monthly charge for IS Network Transmission 
Service is as follows:

                                           Network Customer's Load-ratio share
                                           x Annual Revenue Requirement for IS Transmission
                                           / 12 months
                                          ----------------------------------------------------------------------------------
                                           Monthly IS Network Transmission Service Charge
 

    The load ratio-share is the ratio of the Network Customer's 
coincident hourly load to the monthly IS Transmission System peak minus 
the coincident peak for all IS Firm Point-to-Point Transmission Service 
plus the IS Firm Point-to-Point reservations, calculated on a rolling 
12-cp basis. The proposed rate formula would be effective October 1, 
2005, through September 30, 2010.

IS Firm Point-to-Point Transmission Service

    The rate for IS Firm Point-to-Point Transmission Service is the 
annual revenue requirement for IS Transmission Service divided by the 
IS Transmission System Total Load in kW, to derive a cost per 
kilowattyear (kWyear). The formula for the monthly rate is as follows:

[[Page 55826]]



                                          Annual Revenue Requirement for IS Transmission
                                          / IS Transmission System Total Load
                                          / 12 months
                                         ------------------------------------------------------------------------------------
                                          Monthly IS Firm Point-to-Point Transmission Rate
 

    The rate formula is applied annually by using the most current 
historical data available. The proposed rate formula would be effective 
October 1, 2005, through September 30, 2010.

IS Non-Firm Point-to-Point Transmission Service

    The proposed rate for IS Non-Firm Point-to-Point Transmission 
Service is a mills/kWh rate, based upon the current firm point-to-point 
rate and may be discounted. The formula rate is as follows:

                                          Monthly IS Firm Point-to-Point Transmission Rate
                                          / 730 hours/month
                                          x 1000 mills per dollar
                                         ------------------------------------------------------------------------------------
                                          IS Non-Firm Point-to-Point Transmission Rate
 

    This rate will remain in effect for the same period as the IS Firm 
Point-to-Point Transmission Service rate and will also be reviewed 
annually. The IS Non-Firm Point-to-Point Transmission Service will be 
offered at hourly, daily, and monthly rates. The IS Transmission 
Service availability will be posted on the UGPR OASIS.

Ancillary Services

    In accordance with the Tariff, Western will offer to all customers 
the six ancillary services defined by the Commission, two of which IS 
Transmission Customers are required to purchase: (1) Scheduling, System 
Control, and Dispatch Service, and (2) Reactive Supply and Voltage 
Control from Generation Sources Service. The remaining four ancillary 
services are: (3) Regulation and Frequency Response Service, (4) Energy 
Imbalance Service, (5) Spinning Reserve Service, and (6) Supplemental 
Reserve Service. The open access ancillary service formula rates are 
designed to recover only the costs incurred for providing the 
service(s). The charges for ancillary services are based on the cost of 
resources used to provide these services.
    Sales of Regulation and Frequency Response Service, Energy 
Imbalance Service, Spinning Reserve Service, and Supplemental Reserve 
Service may be limited since Western has allocated its power resources 
to preference entities under long-term commitments. In accordance with 
the Tariff, if Western is unable to provide these services from its own 
resources, an offer will be made to purchase the services and pass 
through these costs, including an administrative charge to the 
customer.

Scheduling, System Control, and Dispatch Service

    Western's annual revenue requirement for Scheduling, System 
Control, and Dispatch Service is determined by multiplying the portion 
of the Watertown Operations Office net plant and communications 
facilities net plant associated with Scheduling, System Control, and 
Dispatch Service by the transmission fixed charge rate. The formula 
rate for Scheduling, System Control, and Dispatch Service is:

                                          Annual Revenue Requirement for
                                          Scheduling, System Control and Dispatch Service
                                          / Annual Number of Daily Schedules
                                         ------------------------------------------------------------------------------------
                                          Scheduling, System Control and Dispatch Rate
 

This rate and rate design only recovers Western's revenue requirement 
for Scheduling, System Control, and Dispatch Service.

Reactive Supply and Voltage Control from Generation Sources Service

    Western's annual cost of providing Reactive Supply and Voltage 
Control from Generation Sources Service is determined by multiplying 
the total P-SMBP--ED generation net plant by the generation fixed 
charge rate. The annual cost is multiplied by the capability used for 
reactive support to determine Western's reactive service revenue 
requirement. Basin Electric's and Heartland's annual revenue 
requirement is based on the annual cost of equipment installed on its 
generators to provide this service. Western's, Basin Electric's, and 
Heartland's annual revenue requirements are summed for the total 
revenue requirement for this service. The Reactive Supply and Voltage 
Control Service from Generation Sources Service rate is then derived by 
dividing the total annual revenue requirement by the load requiring 
reactive service. The annual rate is then divided by 12 months to 
obtain a monthly rate. The Reactive Supply and Voltage Control rate 
calculation is summarized in the following formula:

                                 Annual Reactive Revenue Requirement
                                 + Load Requiring Reactive Service
                                 / 12 months
                                -------------------------------------------------------------
 


[[Page 55827]]

Regulation and Frequency Response Service

    Regulation and Frequency Response Service in the east side of the 
balancing authority is provided primarily by Oahe generation and in the 
west side of the balancing authority by Fort Peck generation, both of 
which are Corps of Engineer facilities. To calculate the annual cost of 
providing Regulation and Frequency Response Service, the Corps of 
Engineers' generation fixed charge rate is applied to Oahe generation 
and Fort Peck generation net plant investment. This cost is divided by 
the capacity at the plants to derive a dollar per kilowatt amount for 
Oahe and Fort Peck powerplants' installed capacity. This dollar per 
kilowatt amount is then applied to the capacity of Oahe generation and 
Fort Peck generation reserved for Regulation and Frequency Response 
Service in the balancing authority. The capacity reserved for 
Regulation and Frequency Response Service has been determined to be 2 
percent of the annual peak load. The 2 percent value was derived by 
averaging yearly peak condensing as percentage of load for five years. 
Western's annual revenue requirement for Regulation and Frequency 
Response Service is determined by applying the dollar per kilowatt 
amount to the capacity used for Regulation and Frequency Response 
Service. Basin Electric's and Heartland's annual revenue requirement is 
based on the annual cost of equipment installed on its generators to 
provide this service. Western's, Basin Electric's, and Heartland's 
annual revenue requirements are summed for the total revenue 
requirement for this service. Annual rate for Regulation and Frequency 
Response Service is then determined by dividing the total revenue 
requirement by the total load in the Balancing Authority. The annual 
rate is then divided by 12 months to obtain a monthly rate. The 
Regulation and Frequency Response Service rate calculation is 
summarized in the following formula:

                                         Annual Revenue Requirement for Regulation
                                         + Load in the Balancing Authority Requiring Regulation
                                         / 12 months
                                        -------------------------------------------------------------------------------------
                                         Monthly Regulation and Frequency Response Rate
 

Energy Imbalance Service

    This service is not intended to provide backup for generation 
supply. Energy shall be returned in like time frames (on-peak, off-
peak, etc.) and accounts zeroed out monthly. Western reserves the right 
to apply a penalty to energy imbalances outside a 3-percent bandwidth 
(1.5 percent deviation). The penalty for under deliveries 
outside the 3-percent bandwidth is 100 mills/kWh. Over deliveries 
outside the bandwidth will be forfeited to the balancing authority.

Reserve Services

    Western's annual cost of generation for Reserve Services is 
determined by multiplying the generation fixed charge rate by the P-
SMBP--ED generation net plant investment. The cost/kW year is 
determined by dividing the annual cost of generation by the plant 
capacity. The capacity used for Reserve Services is determined by 
multiplying Western's peak IS load by the MAPP operating reserve 
requirement of 5 percent. The cost/kW year is multiplied by the 
capacity used for Reserve Services to determine the annual revenue 
requirement for Reserve Services. The annual revenue requirement for 
Reserve Services is divided by Western's peak transmission load to 
calculate the annual rate. The annual rate is then divided by 12 months 
to obtain a monthly rate. This rate and rate design recovers only 
Western's revenue requirement associated with Reserve Services. If 
energy is taken under these services, the energy charge will be the 
MAPP or its successors rate for emergency energy. The Regulation and 
Frequency Response Service rate calculation is summarized in the 
following formula:

                                Annual Revenue Requirement for Reserves
                                / Load Requiring Reserves
                                / 12 months
                               ----------------------------------------------------------------
 

Existing and Provisional Rates

    The revenue requirements for the individual services and comparison 
values are outlined in the following table. These rates are calculated 
comparing the Existing Revenue Requirement to the Revenue Requirement 
based upon the most recent historical data available at the time of the 
initial rate proposal.

                                                     Table 1
----------------------------------------------------------------------------------------------------------------
                                                                                      Provisional
                            Service                              Existing revenue       revenue       Percentage
                                                                    requirement       requirement       change
----------------------------------------------------------------------------------------------------------------
Transmission...................................................      $128,017,923      $126,741,576       -0.997
Scheduling, System Control and Dispatch........................         3,373,281         3,406,102       -0.973
Reactive Supply and Voltage Control from Generation Sources....         2,736,253         3,065,568       12.035
Regulation and Frequency Control...............................         1,065,771         1,075,623        0.924
Reserves.......................................................         1,895,268         2,009,276        6.015
----------------------------------------------------------------------------------------------------------------


[[Page 55828]]

Certification of Rates

    Western's Administrator certifies that the IS Transmission and 
Ancillary Service rates placed into effect on an interim basis are the 
lowest possible rates consistent with sound business principles. The 
provisional formula rates were developed following administrative 
policies and applicable laws.

IS Transmission Service Discussion

    Western proposes continuing the annual fixed charge formula to 
determine the Annual Revenue Requirement for IS Transmission Service. 
The annual revenue requirement for IS Transmission Service includes O&M 
expense, A&GE, interest expense, and depreciation expense from the most 
recent historical test year. This annual revenue requirement for IS 
Transmission Service is offset by appropriate revenue credits.
    The IS Transmission System includes the transmission facilities 
owned by Western, Basin Electric, Heartland and others in which the IS 
has contractual rights. The costs paid to others for contractual rights 
on their transmission lines are included in the costs recovered by the 
annual revenue requirement for IS Transmission Service.
    Western will continue to offer Network, Firm Point-to-Point, and 
Non-Firm Point-to-Point Transmission Service on the IS Transmission 
System. The service offered is the transmission of energy and capacity 
from Points of Receipt to Points of Delivery on the IS. The IS 
Transmission Service rates include the cost of Scheduling, System 
Control, and Dispatch Service. Therefore an additional charge for this 
ancillary service is not required for transmission users.
    The provisional IS Transmission Service rates will be applied to 
customers who purchase transmission services. Western, Basin Electric, 
and Heartland will take IS Transmission Service. The IS Transmission 
Service to the UGPR's Customers will continue to be bundled in the firm 
electric service rate under existing contracts that expire in 2020.

IS Transmission System Total Load

    The IS Transmission System Total Load is the 12-cp system peak for 
Network IS Transmission Service plus the reserved capacity for all IS 
Long-Term Firm Point-to-Point Transmission Service. For the provisional 
rate, the IS Transmission System Total Load will be unchanged at 
3,968,000 kW.

Annual Costs

    Western will continue to use a Commission-recognized methodology 
for annual cost calculation with fixed charge rates for various cost 
components approved by the Commission in WAPA-79 and WAPA-100. The 
change in the provisional rate is that the costs associated with the 
GSUs are no longer included in the net plant investment for 
transmission or the various expenses. The investment and costs for GSUs 
are now in the generation fixed charge calculation in support of 
ancillary services. The proposed methodology will continue to be an 
annual fixed charge formula that will determine the annual revenue 
requirement to be recovered from transmission services.

Annual Revenue Requirement for IS Transmission

    A change in the costs that comprise the annual revenue requirement 
for IS Transmission is being proposed. The proposed transmission rate 
methodology is different from the current transmission rate methodology 
in one area. The GSU investments are removed from the transmission 
investments and placed in the generation investments. This also moves 
the corresponding costs of GSUs from transmission costs to generation 
costs. The existing annual revenue requirement for IS Transmission 
Service is $128,017,923. The provisional Annual Revenue Requirement for 
IS Transmission Service is $126,741,576.

Network

    The current IS Network Transmission Service schedule expires on 
September 30, 2005. The provisional annual revenue requirement for IS 
Transmission Service will be used in the provisional rate formula for 
IS Network Transmission Service. The provisional charge for the monthly 
demand for IS Network Transmission Service will be the product of the 
network customer's load ratio share times one-twelfth (1/12) of the 
annual revenue requirement for IS Transmission Service. The load ratio 
share will be based on the network customer's hourly load (including 
its designated network load not physically interconnected with 
Western), coincident with the IS monthly transmission system peak, 
which will be calculated on a rolling 12-cp basis. Western's 
transmission system peak includes the sum of capacity reserved for IS 
Point-to-Point Transmission Service, 12-cp monthly entitlements for 
firm power customers, and the average 12-cp monthly system peak for IS 
Network Transmission Service. The provisional rate formula is to be 
effective beginning October 1, 2005, through September 30, 2010.

Firm Point-to-Point

    The current IS Firm Point-to-Point Transmission Service rate for 
2004-2005 is $2.72 and expires September 30, 2005. The provisional 
formula rate will continue to be the Annual Revenue Requirement for IS 
Transmission Service divided by the IS Transmission System Total Load. 
The provisional rate for IS Firm Point-to-Point Transmission Service is 
$2.69 per kWmonth for 2004-2005.

Non-Firm Point-to-Point

    The current IS Non-Firm Transmission Service rate expires September 
30, 2005. The provisional rate for IS Non-Firm Transmission Service is 
expressed in mills/kWh and is based on the current IS Firm Point-to-
Point Transmission Service rate and may be discounted. The provisional 
IS Non-Firm Point-to-Point Transmission Service rate will be the IS 
Firm Point-to-Point Transmission Service rate divided by 730 hours per 
month and multiplied by 1000 mills per dollar. The provisional IS Non-
Firm Transmission Service rate for 2004-2005 is 3.68 mills/kWh.
    The following table summarizes the difference in calculations 
between the current IS Transmission Service rates and the provisional 
IS Transmission Service rates. It compares the change in the average 
annual projections used in the 2004-2005 transmission and ancillary 
services study and the provisional IS Transmission Service rates for 
this rate adjustment based upon the most recent historical data 
available at the time of the initial rate proposal.

                                          Comparison of Annual Revenues
----------------------------------------------------------------------------------------------------------------
                                                                                                       Percent
                              Item                                 Existing rate   Provisional rate     change
----------------------------------------------------------------------------------------------------------------
Annual IS Costs................................................      $137,088,496      $136,289,145       -0.577
Transmission Customer Facility Credits.........................         2,482,447         2,482,647        0.000

[[Page 55829]]

 
Transmission Revenue Credits...................................         9,454,494         9,454,494        0.000
Annual Revenue Requirement for IS Transmission Service.........       128,017,923       126,741,576       -0.997
----------------------------------------------------------------------------------------------------------------

    The change in annual revenue requirement for IS Transmission 
Service is primarily a result of a revision in the allocation of 
expenses and investments. The revenue change between the existing rate 
and the provisional rate is <1 percent and, therefore, this is a minor 
rate adjustment.

Basis for Rate Development

    The existing rates for IS Network, Firm and Non-Firm Transmission 
Service in Rate Schedules UGP-NT1, UGP-FPT1, and UGP-NFPT1, expire 
September 30, 2005. This rate adjustment contains rates that replace 
existing rates. The adjusted rates reflect changes in costs. The 
provisional rates will provide sufficient revenue to pay all annual 
costs, including interest expense, and repay investment within the 
allowable period. The provisional IS Transmission Service rates, 
detailed in Rate Schedules UGP-NT1, UGP-FPT1, and UGP-NFPT1, will take 
effect on October 1, 2005 to correspond with the start of the Federal 
fiscal year and remain in effect through September 30, 2010, or until 
replaced.
    The proposed rates for IS Transmission Service include a provision 
to pass through electric industry restructuring costs associated with 
providing transmission service. These costs will be passed through to 
each appropriate IS Transmission Customer.

Comments

    Western did not receive any comments or responses regarding the IS 
Transmission Service rate adjustment.

Ancillary Services Discussion

    The IS will continue to offer six ancillary services. These are (1) 
Scheduling, system control, and dispatch service, (2) reactive supply 
and voltage control service, (3) regulation and frequency response 
service, (4) energy imbalance service, (5) spinning reserve service, 
and (6) supplemental reserve service. The first two are required 
services: (1) Scheduling, system control, and dispatch service and (2) 
reactive supply and voltage control service. All these ancillary 
services are listed in Western's Tariff.
    The provisional rates for ancillary services are designed to 
recover only the costs associated with providing the service(s). The 
formula for calculating the rates will remain the same but the GSUs 
will be included in the investment and costs for the generation fixed 
charge in support of ancillary services. The costs for providing 
Scheduling, System Control, and Dispatch Service are included in the 
provisional IS Transmission Service rates.
    The following table summarizes the difference in calculations 
between the current IS Ancillary Service rates and the provisional IS 
Ancillary Service rates. It compares the change in the average annual 
projections used in the 2004-2005 transmission and ancillary services 
study and the provisional IS Transmission and Ancillary Service rates 
for this rate adjustment based upon the most recent historical data 
available at the time of the initial rate proposal.

                                      Comparison of Ancillary Service Rates
----------------------------------------------------------------------------------------------------------------
                                                                                    Provisional
               Item                             Unit               Existing rate       rate       Percent change
----------------------------------------------------------------------------------------------------------------
Scheduling, System Control and      schedule/day................          $49.29          $49.77           0.974
 Dispatch Service.
Reactive Supply and Voltage         kWmonth.....................            0.06            0.07          16.667
 Control.
Regulation and Frequency Response.  kWmonth.....................            0.04            0.04           0.000
Energy Imbalance..................  n/a.........................             n/a             n/a             n/a
Reserves..........................  kWmonth.....................            0.11            0.12           9.091
----------------------------------------------------------------------------------------------------------------

Basis for Rate Development

    The existing rates for IS Ancillary Services in Rate Schedules UGP-
AS1, UGP-AS2, UGP-AS3, UGP-AS4, UGP-AS5, and UGP-AS6, expire September 
30, 2005. The rate adjustment contains rates that replace existing 
rates. The adjusted rates reflect a revised methodology and changes in 
costs. The provisional rates will provide sufficient revenue to pay all 
annual costs, including interest expense, and repayment of required 
power investment within the allowable period. The provisional rates 
will take effect on October 1, 2005, to correspond with the start of 
the Federal fiscal year and remain in effect through September 30, 
2010.

Comments

    Western did not receive any comments or responses regarding the IS 
Ancillary Services rate adjustment.

Availability of Information

    Information about this rate adjustment, including studies, 
brochures, comments, letters, memorandums, and other supporting 
material made or kept by Western, used to develop the provisional 
rates, is available for public review in the Upper Great Plains 
Regional Office, 2900 4th Avenue North, Billings, Montana.

Regulatory Procedure Requirements

Regulatory Flexibility Analysis

    The Regulatory Flexibility Act of 1980 (5 U.S.C. 601, et seq.) 
requires Federal agencies to perform a regulatory flexibility analysis 
if a final rule is likely to have a significant economic impact on a 
substantial number of small entities and there is a legal requirement 
to issue a general notice of proposed rulemaking. Western has 
determined that this action does not require a regulatory flexibility 
analysis since it is a rulemaking of particular applicability involving 
rates or services applicable to public property.

[[Page 55830]]

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.

Small Business Regulatory Enforcement Fairness Act

    Western has determined that this rule is exempt from congressional 
notification requirements under 5 U.S.C. 801 because the action is a 
rulemaking of particular applicability relating to rates or services 
and involves matters of procedure.

Submission to the Federal Energy Regulatory Commission

    The interim rates herein confirmed, approved, and placed into 
effect, together with supporting documents, will be submitted to the 
Commission 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 October 1, 2005, 
formula rates for the IS Transmission and Ancillary Services under Rate 
Schedules UGP-FPT1, UGP-NFPT1, UGP-NT1, UGP-AS1, UGP-AS2, UGP-AS3, UGP-
AS4, UGP-AS5, and UGP-AS6. The rate schedules shall remain in effect on 
an interim basis, pending the Commission's confirmation and approval of 
them or substitute rates on a final basis through September 30, 2010.

    Dated: September 13, 2005.
Clay Sell,
Deputy Secretary.

    Rate Schedule UGP-AS1; October 1, 2005; Supersedes 1998 Schedule

Upper Great Plains Region Integrated System: Scheduling, System 
Control, and Dispatch Service

Effective

    The first day of the first full billing period beginning on or 
after October 1, 2005, through September 30, 2010, or until superseded 
by another rate schedule.

Applicable

    This service is required to schedule the movement of power through, 
out of, within, or into the Western Area Upper Great Plains Balancing 
Authority (WAUGP). The charges for Scheduling, System Control, and 
Dispatch Service are to be based on the rate outlined below. The 
formula rate used to calculate the charges for service under this 
schedule was developed and may be modified under applicable Federal 
laws, regulations, and policies.
    The rate will be applied to all schedules for WAUGP non-
Transmission Customers. The WAUGP will accept any reasonable number of 
schedule changes over the course of the day without any additional 
charge.
    The charges for Scheduling, System Control, and Dispatch Service 
may be modified upon written notice to the customer. Any change to the 
charges for the Scheduling, System Control, and Dispatch Service shall 
be as set forth in a revision to this rate schedule developed under 
applicable Federal laws, regulations, and policies and made part of the 
applicable Transmission Customer's Service Agreement.
    The Upper Great Plains Region (UGPR) shall charge the non-
Transmission Customer under the rate then in effect.

Formula Rate
[GRAPHIC] [TIFF OMITTED] TN23SE05.060

Rate

    A recalculated rate will go into effect every May 1 based on the 
above formula and data. The UGPR will notify the customer annually of 
the recalculated rate on or before April 1.

    Rate Schedule UGP-AS2; October 1, 2005; Supersedes 1998 Schedule

Upper Great Plains Region Integrated System: Reactive Supply and 
Voltage Control From Generation Sources Service

Effective

    The first day of the first full billing period beginning on or 
after October 1, 2005, through September 30, 2010, or until superseded 
by another rate schedule.

Applicable

    To maintain transmission voltages on all transmission facilities 
within acceptable limits, generation facilities under the control of 
the Western Area Upper Great Plains balancing authority (WAUGP) are 
operated to produce or absorb reactive power. Thus, Reactive Supply and 
Voltage Control from Generation Sources Service (Reactive Service) must 
be provided for each transaction on the transmission facilities. The 
amount of Reactive Service that must be supplied with respect to the 
Transmission Customer's transaction will be determined based on the 
Reactive Service necessary to maintain transmission voltages within 
limits that are generally accepted in the region and consistently 
adhered to by WAUGP.
    The Transmission Customer must purchase this service from the 
Transmission Provider. The charges for such service will be based upon 
the rate outlined below. The formula rate used to calculate the charges 
for service under this schedule was developed and may be modified under 
applicable Federal laws, regulations, and policies.
    The charges for Reactive Service may be modified upon written 
notice to the Transmission Customer. Any change to the charges for 
Reactive Service shall be as set forth in a revision to this rate 
schedule developed under applicable Federal laws, regulations, and 
policies and made part of the applicable Transmission Customer's 
Service Agreement. The Upper Great Plains Region (UGPR) shall charge 
the Transmission Customer under the rate then in effect.
    Those Transmission Customers with generators in the balancing 
authority providing WAUGP with adequate

[[Page 55831]]

Reactive Service will not be charged for this service. Any waiver of 
this charge or any crediting arrangements for Reactive Service must be 
documented in the Transmission Customer's Service Agreement.

Formula Rate
[GRAPHIC] [TIFF OMITTED] TN23SE05.061

Rate

    A recalculated rate will go into effect every May 1 based on the 
above formula and updated financial and load data. The UGPR will notify 
the Transmission Customer annually of the recalculated rate on or 
before April 1.

    Rate Schedule UGP-AS3; October 1, 2005; Supersedes 1998 Schedule

Upper Great Plains Region Integrated System: Regulation and Frequency 
Response Service

Effective

    The first day of the first full billing period beginning on or 
after October 1, 2005, through September 30, 2010, or until superseded 
by another rate schedule.

Applicable

    Regulation and Frequency Response Service (Regulation) is necessary 
to provide for the continuous balancing of resources, generation, and 
interchange with load and for maintaining scheduled interconnection 
frequency at 60 cycles per second (60 Hz). Regulation is accomplished 
by committing on-line generation whose output is raised or lowered, 
predominantly through the use of automatic generating control 
equipment, as necessary to follow the moment-by-moment changes in load. 
The obligation to maintain this balance between resources and load lies 
with the Western Area Upper Great Plains balancing authority (WAUGP) 
operator. The Transmission Customer must either purchase this service 
from WAUGP or make alternative comparable arrangements to satisfy its 
Regulation obligation.