Power rates: Pick-Sloan Missouri Basin Program,
[Federal Register: September 23, 2005 (Volume 70, Number 184)]
[Notices]
[Page 55821-55834]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr23se05-37]
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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and places the rate schedules in effect on a final basis through September 30, 2010, or until the rate schedules are superseded.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
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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
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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:
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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.
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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.
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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.
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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
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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,
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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:
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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
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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
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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
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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
