Western Area Power Administration, DOE.
Notice of Proposed Network Integration Transmission and Ancillary Services Rates.
The Western Area Power Administration (Western) is proposing revised rate methodologies for network integration transmission service (network service) for the Parker-Davis Project (PDP), and the Pacific Northwest-Pacific Southwest Intertie Project (Intertie) and for ancillary services from the PDP, Boulder Canyon Project (BCP), and part of the Colorado River Storage Project (CRSP) located in the Desert Southwest Customer Service Region's (DSWR) Balancing Authority and Transmission Operations Area (BATO). Current rates, under Rate Schedules DSW-SD1, DSW-RS1, DSW-FR1, DSW-EI1, DSW-SPR1, DSW-SUR1, PD-NTS1, and INT-NTS1, extend through March 31, 2006. The proposed rates will provide sufficient revenue to pay all annual costs, including interest expense and repayment of required investment within the allowable period. Western will prepare a brochure that provides detailed information on the rates. The proposed rates, under Rate Schedules DSW-SD2, DSW-RS2, DSW-FR2, DSW-EI2, DSW-SPR2, DSW-SUR2, PD-NTS2, INT-NTS2, WS-NTS1, are scheduled to go into effect on April 1, 2006, and will remain in effect through March 31, 2011. Publication of this Federal Register notice begins the formal process for the proposed rates.
The consultation and comment period begins today and will end January 10, 2006. Western will present a detailed explanation of the proposed rates at a public information forum to be held on November 2, 2005, 1 p.m. MST, Phoenix, AZ. Western will accept oral and written comments at the public comment forum. The public comment forum will be held on November 29, 2005, 1 p.m. MST, Phoenix, AZ. Western will accept written comments any time during the consultation and comment period.
Send written comments to Mr. J. Tyler Carlson, Regional Manager, Desert Southwest Customer Service Region, Western Area Power Administration, P.O. Box 6457, Phoenix, AZ 85005-6457, e-mail email@example.com. Western will post information about the rate process on its external Web site at http://www.wapa.gov/dsw/dsw.htm. Western will post official comments received via letter and e-mail to its Web site after the close of the comment period. Western must receive written comments by the end of the consultation and comment period to ensure they are considered in Western's decision process. The location for the Public Information and Public Comment Forums is Desert Southwest Regional Office, 615 South 43rd Avenue, Phoenix, AZ.Start Further Info
FOR FURTHER INFORMATION CONTACT:
Mr. Jack Murray, Rates Team Lead, Desert Southwest Customer Service Region, Western Area Power Administration, P.O. Box 6457, Phoenix, AZ 85005-6457; telephone (602) 605-2442, e-mail firstname.lastname@example.org.End Further Info End Preamble Start Supplemental Information
The proposed rates for DSWR network service for the PDP and the Intertie and ancillary services for the Western Area Lower Colorado (WALC) BATO are designed to recover an annual revenue requirement that includes investment repayment, interest, operation and maintenance expense, and other expenses. The ancillary services apply to specified transmission service in the WALC BATO including firm point-to-point, non-firm and network services on the PDP, the Intertie, the Central Arizona Project (CAP), and the portions of the CRSP in WALC. All firm point-to-point and non-firm transmission service and network service on the CAP and CRSP are defined under existing Rate Orders and are not a part of the proposed rates.
The Deputy Secretary of Energy approved Rate Schedules DSW-SD1, DSW-RS1, DSW-FR1, DSW-EI1, DSW-SPR1, DSW-SUR1, PD-NTS1, and INT-NTS1 for the DSWR network service for PDP and Intertie and ancillary services for the WALC BATO on May 3, 1999 (Rate Order No. WAPA-84, 64 FR 25323, May 11, 1999), and the Federal Energy Regulatory Commission (Commission) confirmed and approved the rate schedules on January 20, 2000, under FERC Docket No EF99-5041-000, (90 FERC 62,032). Approval for Rate Schedules DSW-SD1, DSW-RS1, DSW-FR1, DSW-EI1, DSW-SPR1, DSW-SUR1, PD-NTS1, and INT-NTS1 covered 5 years beginning on April 1, 1999, and ending on March 31, 2004. These rate schedules were extended by a series of Rate Orders through March 31, 2006, with the most recent Rate Order being Rate Order No. WAPA-121 (70 FR 15622, March 28, 2005). The rate schedules were extended to accommodate the DSWR Multi-System Transmission Rate (MSTR) process. An MSTR has not been approved. However, Rate Schedule WS-NTS1 is structured to allow multi-system network service on the DSWR System if and when an MSTR is approved.
Under Rate Schedules PD-NTS2, INT-NTS2, and WS-NTS1, the methodology for calculating the customer's monthly charge is the product of the transmission customer's load-ratio share times one-twelfth of the Start Printed Page 59336annual transmission revenue requirement. The customer's load-ratio share is equal to the network transmission customer's coincidental peak (CP), which is the load coincident with the appropriate Project's monthly transmission system peak averaged with the previous 11 months (12 CP) divided by the resultant value of the appropriate Project's average monthly transmission system load at the hour of the system peak in each month.
The monthly hour of the system peak is determined as the hour that the sum of the network customers' metered loads is the greatest. The system load at the peak hour is determined by adding the point-to-point firm transmission reservations to the sum of the network customer's metered loads. The point-to-point firm transmission reservations can include the Open Access Transmission Tariff (OATT) firm point-to-point reservations, the PDP Firm Electric Service (FES) contract rates of delivery (CROD), the pre-OATT Firm Transmission Service (FTS) and the Salt Lake City Area Integrated Project FES with delivery points on the PDP.
The methodology to determine the network service charges is the same for the single system (PDP-NTS2 and INT-NTS2) and the whole system (WS-NTS1) services. One complication is that under WS-NTS1, the determinants (system load, peak hour, and revenue requirement) apply to the combined PDP, Intertie and CAP system (CRSP is excluded from this calculation).
Under Rate Schedule DSW-SD2, Scheduling, Dispatch, and System Control Ancillary Service, the rate is calculated as an annual cost of all personnel, capital costs (such as the dispatch center building), and other expenses incurred in providing the service for DSWR customers. These costs are recovered through a rate applied on a per tag basis. That rate is determined in two major steps: First, the yearly costs associated with capital improvements are determined and divided by the number of tags issued during the year; second, the average labor cost per tag is determined and added to the capital cost per tag. This rate design differs from the previous methodology in two ways: (1) The proposed rates are based on tags rather than schedules, and (2) the proposed methodology does not differentiate as to new vs. existing tags or as to whether or not a tag involves an intra-bus transfer.
Under Schedule DSW-RS2, Reactive Supply and Voltage Control Service (Var Support) from generation sources, the rate is determined by dividing the revenue requirement for the service by the reservations requiring the service. The revenue requirement for the service is one minus the power factor (1-PF) times the combined generation revenue requirement of the PDP, BCP and CRSP. The previous methodology used the factor (1-PF2) to determine the Var Support revenue requirement for BCP and PDP, and used an amount for the CRSP Var Support revenue requirement supplied by the CRSP Management Center.
Under Schedule DSW-FR2, Regulation and Frequency Response Service (Regulation), the rate is determined using the revenue requirement for the service divided by the load in the WALC requiring the service. The revenue requirement for the service is the product of the generation capacity that is used for regulation and the capacity rate of the Project, plus any regulation purchases the transmission provider must make. This total is multiplied by a use factor, which takes into consideration the customer load in the WALC BATO. The denominator in the equation and the load in the BATO requiring the service includes a portion of the CRSP load and the DSWR load.
Regulation is not available from DSWR resources on a long-term basis. However, if necessary, DSWR will purchase regulation on the open market for a charge that covers the cost of procuring and supplying the service. Regulation will be supplied from DSWR resources only on a short-term basis, if such resources are available. Under Rate Schedule DSW-FR1, Western also indicated that this service would only be supplied under short-term sales, but set the charge equal to the capacity rate of the Project supplying the service rather than basing the charge on a formula as with the proposed rate methodology.
Non-standard load refers to large, volatile loads (such as those associated with certain smelters and arc furnaces), which can require a BATO to acquire significant amounts of generation capacity for regulation. Such non-standard loads require separate metering of their moment-to-moment load values to accurately calculate their effects on the system, and will not be covered under the proposed regulation rate.
For this rate order, DSWR is defining a non-standard load as either a single plant or site: (1) With a regulation capacity requirement of 5 megawatts (MW) or greater on a recurring basis, and (2) whose capacity requirement is equal to 10 percent or greater of their average load. Regulation for non-standard loads, as determined by Western, must be delineated in a service agreement, which recognizes the additional burden required to supply this service.
Rate Schedule DSW-EI2, Energy Imbalance Service, proposes a different bandwidth for on-peak and for off-peak, because Western's ability to supply this service is different for these two scenarios, especially during periods of low water. The bandwidth for on-peak is proposed to be plus or minus 1.5 percent of the customer's load with a minimum of 5 MW of either over- or under-delivery. The off-peak bandwidth is 1.5 percent to a negative 3 percent of a customer's load with a minimum of 2 MW of over-delivery and 5 MW of under-delivery.
The settlement with the customer will be different for excursions within the bandwidth than for excursions outside the bandwidth. However, in all cases it is at Western's discretion whether to require a scheduled return of energy or a financial settlement. If the customer's Imbalance Energy is within the bandwidth for either on-peak or off-peak, the customer will be either charged or credited 100 percent of a weighted index price chosen by Western or a scheduled return of an equal amount of energy.
For energy outside the bandwidth during the on-peak hours, the methodology proposes 110 percent of a weighted index price for under-deliveries and 90 percent of the weighted index price for over-deliveries. For energy outside the bandwidth during the off-peak hours, the methodology proposes 110 percent of a weighted index price for under-deliveries. However, for over-deliveries in the off-peak hours, the methodology proposes the lesser of 60-percent of a weighted index price, or a WALC weighted sales price. In lieu of a financial settlement for energy outside the bandwidth, an amount of energy equivalent to the financial settlement will be scheduled.
The proposed rate methodology differs from the previous methodology in that previously DSWR used the FERC pro-forma methodology to define the service. Better metering and data sorting capabilities and the drought, which persists in the southwest, have shown that Western is disadvantaged when using the FERC pro-forma methodology. Under the previous methodology, a 3-percent bandwidth with a 2 MW deviation was used, and under-deliveries were assessed 100 mills per kilowatthour penalty and over-deliveries were credited at 50 percent of market value.
Under Schedule DSW-SPR2, Operating Reserves-Spinning Reserve Service is not available from DSWR Start Printed Page 59337resources on a long-term firm basis. If a customer cannot self-supply or purchase this service from another provider, Western may obtain the reserves on the open market for a charge that covers the cost of procuring the service. The transmission customer will be responsible for the transmission service to get these reserves to their destination.
Under Schedule DSW-SUR2, Operating Reserves-Supplemental Reserve Service is not available from DSWR resources on a long-term firm basis. If a customer cannot self-supply or purchase this service from another provider, at the customer's request, Western may obtain the reserves on the open market for a charge that covers the cost of procuring the service. The transmission customer will be responsible for the transmission service to get these reserves to their destination. Spinning and Supplemental Reserve Services were handled in the same way in the previous rate methodology as in this proposal.
Since the proposed rates constitute a major rate adjustment as defined by 10 CFR part 903, Western will hold both a public information forum and a public comment forum. After review of public comments, and possible amendments or adjustments, Western will recommend the Deputy Secretary of Energy approve the proposed rates on an interim basis.
Western is establishing network service for the PDP and the Intertie and ancillary services for the PDP, Intertie, CAP, and the part of the CRSP located in the WALC BATO under the Department of Energy Organization Act (42 U.S.C. 7152); 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)); and other acts that specifically apply to the projects involved.
By Delegation Order No. 00-037.00, effective December 6, 2001, the Secretary of Energy delegated: (1) The authority to develop power and transmission rates to 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 Department of Energy (DOE) procedures for public participation in power rate adjustments (10 CFR part 903) were published on September 18, 1985.
Availability of Information
All brochures, studies, comments, letters, memorandums, or other documents that Western initiates or uses to develop the proposed rates are available for inspection and copying at the Desert Southwest Regional Office, 615 South 43rd Avenue, Phoenix, Arizona. Many of these documents and supporting information are also available on DSWR's external Web site http://www.wapa.gov/dsw/dsw.htm.
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. 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.
In compliance with the National Environmental Policy Act of 1969 (NEPA) (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 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.Start Signature
Dated: September 30, 2005.
Michael S. Hacskaylo,
[FR Doc. 05-20433 Filed 10-11-05; 8:45 am]
BILLING CODE 6450-01-P