Bonneville Power Administration (BPA), Department of Energy (DOE).
Notice of proposed wholesale power rates.
The Pacific Northwest Electric Power Planning and Conservation Act (Northwest Power Act), 16 U.S.C. 839, provides that BPA must establish and periodically review and revise its rates so that they are adequate to recover, in accordance with sound business principles, the costs associated with the acquisition, conservation and transmission of electric power, and to recover the Federal investment in the Federal Columbia River Power System (FCRPS) and other costs incurred by BPA.
1. Persons wishing to become formal parties to the proceeding must file a petition to intervene notifying BPA in writing of their intention to do so in conformance with the requirements stated in this notice. Petitions to intervene should be directed to Jennifer Sanders, Hearing Clerk, LP-7, Bonneville Power Administration, 905 NE 11th Avenue, Portland, OR 97232 or may be e-mailed to the following e-mail address: firstname.lastname@example.org, and must be received no later than 5 p.m., Pacific Standard Time, on November 17, 2005. In addition, a copy of the petition must be served concurrently on BPA's General Counsel and directed to Peter J. Burger, LP-7, Office of General Counsel, Bonneville Power Administration, 905 NE 11th Avenue, Portland, OR 97232 or be e-mailed to the following e-mail address: http://email@example.com. (See Part III (A) for more information.)
2. Non-party participants may submit written comments between November 21, 2005, and February 13, 2006. Comments must be received no later than 5 p.m., Pacific Standard Time, on February 13, 2006, in order to be considered in the draft Record of Decision (ROD). Written comments may be made as follows: in person at the field hearings (see schedule and locations in Part I of this Notice), online at BPA's Web site: www.bpa.gov/comment, or by mail to: BPA Communications, DKP-7, P.O. Box 14428, Portland, OR 97293-4428. Please Start Printed Page 67686identify written or electronic comments as “FY 07-09 Power Rate Case.” BPA will consider and address the comments received in the draft ROD.
3. The rate adjustment proceeding will begin with a prehearing conference at 9 a.m., Pacific Standard Time on November 21, 2005, held in the BPA Rates Hearing Room, 2nd Floor, 911 NE 11th Avenue, Portland, OR. BPA will release its 2007 Wholesale Power Rate Case Initial Proposal (WP-07 Initial Proposal) and supporting documents at this prehearing conference. Compact discs (CDs) containing the WP-07 Initial Proposal documents, in PDF format, will be provided to the parties at the prehearing conference. The WP-07 Initial Proposal documents will also be available on BPA's Web site www.bpa.gov/power/rates. Due to increased security, attendees should allow additional time to enter the building and sign in at the security desk where photo identification will be required for entry.Start Further Info
FOR FURTHER INFORMATION CONTACT:
Ms. Jamae Hilliard Creecy, Public Affairs Specialist, Public Affairs Office, DKP-7, P.O. Box 14428, Portland, OR 97293-4428. Interested persons may also call (503) 230-4328 or 1-800-622-4519 (toll-free). Information also may be obtained from:
Ms. Kimberly Leathley, Manager, Financial Management, Rates, and Planning—PF-6, P.O. Box 3621, Portland, OR 97208.
Ms. Elizabeth Evans, Acting Rates Manager—PFR-6, P.O. Box 3621, Portland, OR 97208.
Mr. Garry Thompson, Hub Manager, Mr. Ken Hustad, Senior Customer Account Executive, or Ms. Carol Hustad, Customer Account Executive, Eastern Power Business Area-PSE, 707 W. Main, Suite 500, Spokane, WA 99201.
Mr. John Lebens, Hub Manager, Western Power Business Area—PSW-6, P.O. Box 3621, Portland, OR 97208.
Mr. Larry King, Customer Account Executive, 2700 Overland, Burley, ID 83318.
Mr. C. T. Beede, Customer Account Executive, P.O. Box 40, Big Arm, MT 59910.
Mr. Dan Bloyer, Customer Account Executive, 1011 SW Emkay Drive, Suite 211, Bend, OR 97702.
Mr. Edward Brost, Senior Customer Account Executive, Kootenai Building, Room 215, N. Power Plant Loop, Richland, WA 99352-0968.
Mr. Stuart Clarke, Senior Customer Account Executive, Mr. George Reich, Senior Customer Account Executive, or Ms. R. Kirsten Watts, Customer Account Executive, 909 First Avenue, Suite 380, Seattle, WA 98104-3636.
Responsible Official: Ms. Elizabeth Evans, Acting Rates Manager, is the official responsible for the development of BPA's wholesale power rates.End Further Info End Preamble Start Supplemental Information
Table of Contents
I. Introduction and Procedural Background
II. Purpose and Scope of Hearing
III. Public Participation
IV. Major Studies and Summary of Proposal
V. 2007 Wholesale Power Rate Case Schedules and General Rate Schedule Provisions
Part I—Introduction and Procedural Background
Section 7(i) of the Northwest Power Act, 16 U.S.C. 839e(i), requires that BPA's rates be established according to certain procedures. These procedures include, among other things, publication of this notice of the proposed rates in the Federal Register (Notice); one or more hearings conducted as expeditiously as practicable by a Hearing Officer; public opportunity to provide both oral and written views; data requests and responses and argument related to the proposed rates; and a decision by the Administrator based on the record. This proceeding is governed by § 1010, et seq., of BPA's Rules of Procedure Governing Rate Hearings, 51 FR 7611 (1986) (BPA Hearing Procedures). These procedures implement the statutory Section 7(i) requirements.
Section 1010.7 of the BPA Hearing Procedures prohibits ex parte communications. The ex parte rule applies to all BPA and all DOE employees. Except as provided below, any outside communications with BPA and/or DOE personnel regarding BPA's rate case by other Executive Branch agencies, Congress, existing or potential BPA customers (including tribes), and nonprofit or public interest groups are all considered outside communications and are subject to the ex parte rule. The general rule does not apply to communications relating to (1) Matters of procedure only (the status of the rate case, for example); (2) exchanges of data in the course of business or under the Freedom of Information Act; (3) requests for factual information; (4) matters for which BPA is responsible under statutes other than the ratemaking provisions; or (5) matters which all parties agree may be made on an ex parte basis. The ex parte rule remains in effect until the Administrator's final ROD is issued, which is scheduled to occur on July 7, 2006.
The Bonneville Project Act, 16 U.S.C. 832, the Flood Control Act of 1944, 16 U.S.C. 825s, the Federal Columbia River Transmission System Act, 16 U.S.C. 838, and the Northwest Power Act, 16 U.S.C. 839, provide guidance regarding BPA ratemaking. The Northwest Power Act requires BPA to set rates that are sufficient to recover, in accordance with sound business principles, the cost of acquiring, conserving and transmitting electric power, including amortization of the Federal investment in the FCRPS over a reasonable period of years, and certain other costs and expenses incurred by the Administrator.
BPA's initial proposed 2007 Wholesale Power Rate Schedules and General Rate Schedule Provisions (GRSPs) are available for viewing and downloading on PBL's Web site at http://www.bpa.gov/power/ratecase as discussed in Part V of this Notice. The studies addressing the factors used to develop these rates are listed in Part IV and will be available for examination on November 21, 2005, at BPA's Public Information Center, BPA Headquarters Building, 1st Floor, 905 NE 11th Avenue, Portland, Oregon, and will be provided to parties at the prehearing conference to be held on November 21, 2005, beginning at 9:00 am, Pacific Standard Time, Room 223, 911 NE 11th Avenue, Portland, Oregon.
You may download copies of the studies and documentation from BPA's Web site at http://www.bpa.gov/power/ratecase or request them (on a CD or hard copy) by calling BPA's document request line toll-free at: 1-800-622-4519.
BPA will release its WP-07 Initial Proposal and supporting documents on November 21, 2005, and expects to publish a final ROD on July 7, 2006. BPA will be conducting a formal evidentiary rate hearing attended by rate case parties. Interested parties must file petitions to intervene in order to take part in the formal hearing. A proposed schedule for the formal hearing is stated below. A final schedule will be established by the Hearing Officer at the prehearing conference.
November 21, 2005; BPA files Direct Case/Prehearing Conference
December 5-9, 2005; Clarification
December 9, 2005; Data Request Deadline
December 9, 2005; Motions to Strike
December 15, 2005; Data Response Deadline
December 15, 2005; Answers to Motions to Strike
January 6, 2006; Parties file Direct Cases
January 17-20, 2006; Clarification
January 24, 2006; Data Request Deadline
January 24, 2006; Motions to Strike
January 30, 2006; Data Response Deadline Start Printed Page 67687
January 30, 2006; Answers to Motions to Strike
February 13, 2006; Close of Participant Comments
February 13, 2006; Litigants File Rebuttal Testimony
February 16-17, 2006; Clarification
February 17, 2006; Data Request Deadline
February 17, 2006; Motions to Strike
February 23, 2006; Data Response Deadline
February 23, 2006; Answers to Motions to Strike
March 6-17, 2006; Cross-Examination
April 14, 2006; Initial Briefs Filed
April 26-27, 2006; Oral Argument before Administrator
May 26, 2006; Draft ROD issued
June 9, 2006; Briefs on Exceptions
July 7, 2006; Final ROD—Final Studies
BPA will also be conducting six public field hearings in cities throughout the Pacific Northwest. Public field hearings are an opportunity for persons who are not parties in the formal rate hearing to have their views included in the official record. Written transcripts will be made at all of the field hearings. The field hearings have been scheduled to take place at the locations, dates, and times specified below. The hearing dates also will be posted on the rate case Web site (www.bpa.gov/power/rates) and through announcements in local newspapers. Any changes to the scheduled public hearings will be available on the rate case Web site. The BPA Public Affairs Office also may be contacted for this information at the telephone number previously listed.
Public Field Hearings Schedule
November 29, 2005; Springfield, Oregon
November 30, 2005; Kalispell, Montana
December 1, 2005; Spokane, Washington
December 5, 2005; Idaho Falls, Idaho
December 6, 2005; Tacoma, Washington
December 7, 2005; Portland, Oregon
Part II—Purpose and Scope of Hearing
A. The Overview and Background to this Rate Filing
The WP-07 rate proceeding is designed to establish rates to replace existing rate schedules and GRSPs. One existing rate schedule, the Firm Power Products and Services rate schedule, was established for 10 years in the 1996 Wholesale Power Rate and Transmission Rate Adjustment Proceeding (WP-96/TR-96) and amended in the 1996 Firm Power Products and Services Rate Schedule Correction Proceeding (FPS-96R). The remaining power rate schedules and GRSPs were established in BPA's 2002 Wholesale Power Rate Adjustment Proceeding (WP-02). All of BPA's power rate schedules expire on September 30, 2006. Accordingly, BPA must conduct a rate case, pursuant to the 7(i) process, in order to comply with its statutory obligations to establish rates to market the power of the FCRPS.
The General Transfer Agreement (GTA) Delivery Charge, was established in the 2006 Transmission Rate Case (TR-06) for the period of October 1, 2005, through September 30, 2007. This power rate case will establish the General Transfer Agreement Delivery Charge for the period of October 1, 2007, through September 30, 2009.
On December 21, 1998, BPA issued the Power Subscription Strategy and Record of Decision (Subscription Strategy). The Subscription Strategy reflected BPA's position on the equitable distribution of Federal power for the Fiscal Year (FY) 2002-2011 period. The Subscription Strategy was the culmination of a multi-year public process that established BPA's plan for the availability of Federal power post-2001, the products from which customers could choose, along with an outline of the contracts and pricing framework for those products.
The Subscription Strategy provided a marketing framework for the WP-02 power rate case. The WP-02 power rate case developed the rates and rate schedules necessary for the products and contracts that were developed through Subscription. However, the rates established in the WP-02 power rate proceeding applied only to the first five years of the 10-year Subscription contracts. As noted above, the WP-02 power rates applicable to the Subscription contracts are set to expire on September 30, 2006, and must be replaced. The Subscription contracts continue to be the basis for the contractual relationship between BPA and nearly all of its firm power customers.
2. Firm Power Products and Services Rate Schedule
In addition to revising the rates for the Subscription contracts, BPA is proposing the successor to the Firm Power Products and Services (FPS) rate schedule. The FPS rate schedule is available for the purchase of surplus firm power and other products and services for use inside and outside the Pacific Northwest. The FPS rate schedule and associated GRSPs were established for a 10-year period running from October 1, 1996, to September 30, 2006. The rate schedule and GRSPs were slightly modified in 2000 through a 7(i) process (FPS-96R). The FPS rate schedule is used primarily for the sale at negotiated and/or posted rates of surplus firm power and related products. Unless replaced, BPA would lack a rate schedule to sell surplus power in the West Coast wholesale energy markets.
3. Regional Dialogue and the Policy for Power Supply Role for Fiscal Years 2007-2011 (Near-Term Policy)
The Regional Dialogue process began in April 2002 when a group of BPA's Pacific Northwest electric utility customers submitted a “joint customer proposal” to BPA that addressed both near-term and long-term contract and rate issues. Since then, BPA, the Northwest Power and Conservation Council (Council), customers, and other interested parties have worked on these near- and long-term issues. Considering the depth and complexity of many of these issues, BPA concluded it was not practical to resolve all issues before the start of the 2007 rate period. Therefore, BPA determined that it would address the issues in two phases. The first phase of the Regional Dialogue addresses issues that had to be resolved in order to replace power rates that will expire in September 2006. The second phase is expected to be implemented through new power sales contracts and in a future rate case before new power sales contracts go into effect.
BPA issued the Near-Term Policy and Record of Decision on February 4, 2005. The Near-Term Policy has resolved some outstanding issues prior to the start of the 2007 rate period. Those issues include, but are not limited to, the following:
a. FY 2007-2011 Rights to Lowest-Cost Priority Firm (PF) Rate
BPA will apply the lowest-cost PF rates to its public agency customers whose contracts contain the lowest-cost PF rate guarantee throughout the remaining term of the Subscription power sales contracts.
b. Term of the Next Rate Period
BPA will limit the duration of the next rate period to three years, from FY 2007 through FY 2009.
c. Five-Year Contract Holders
Public customers whose contracts do not contain a guarantee of the lowest cost-based PF rates for FY 2007-2011 will receive the same rate treatment in the FY 2007-2011 period as customers whose contracts contain this guarantee, so long as such customers signed a new Start Printed Page 67688contract or amendment by June 30, 2005, extending the term of the agreement through 2011.
d. Product Availability
Any new or existing public customer whose contract expires in 2006 may select from any of the standard products except Complex Partial (Factoring), Block with Factoring, or Slice. In addition, BPA resolved not to offer contract amendments that would allow changes in the power products and services purchased under a customer's 10-year Subscription contract.
e. Service to Residential and Small-Farm Consumers of Investor-Owned Utilities (IOUs)
BPA's Subscription contracts with the region's six IOUs require the agency to provide 2,200 aMW of power or financial benefits to the residential and small-farm consumers of these customers during FY 2007-2011. BPA signed agreements in late May 2004, with all six regional IOUs that provide certainty in the amount and manner that benefits will be provided to their residential and small-farm consumers under their Subscription contracts for 2007-2011. These agreements provide certainty by defining benefits based on a methodology that uses independent market-prices in calculating the financial benefits, and establishing a floor of $100 million and a cap of $300 million per year for the financial benefits.
f. Service to Direct Service Industries (DSIs)
BPA determined that it will provide eligible Pacific Northwest DSIs some level of Federal power service benefits, at a known quantity and capped cost, in the FY 2007-2011 period. In the Near-Term Policy, BPA decided that for the FY 2007-2011 period it would continue the ramp-down in DSI service by providing eligible DSI customers some level of service benefits, at a known quantity and capped cost, at rates no lower than rates paid by BPA's public customers, and under contractual terms no better than those offered to other customers. In order to provide an opportunity for additional dialogue with (and among) customers in the hope of achieving consensus for a balanced and durable solution for service to the DSIs, BPA noted in the Near-Term Policy that it reserved for later decision: (1) The actual level of service benefits it would provide; (2) the eligibility criteria it would apply in determining which DSIs would qualify for such service benefits; and (3) the mechanism or mechanisms it would use to deliver those service benefits. See Section 4, below, for a description of that later decision.
4. Service to DSIs
The Near-Term Policy established parameters for service to the DSIs which were addressed in Bonneville Power Administration's Service to DSI Customers for Fiscal Years 2007-2011 Administrator's Record of Decision (DSI ROD) (June 30, 2005).
In the DSI ROD, BPA determined to offer the aluminum company DSIs power sales contracts for an aggregate 560 aMW of benefits at a capped $59 million cost. In addition, BPA offered a 17 aMW surplus firm power sales contract for Port Townsend Paper Company through the local public utility under the FPS rate (or the IP rate if viable) at a price approximately equivalent to, but in no case less than, its lowest-cost PF rate.
BPA decided to allocate a share of the 560 aMW service benefits to each DSI aluminum company for purposes of making an initial offer of service, but the creditworthiness of each DSI, on a prospective basis, will determine whether BPA executes a contract with that company. In addition, each DSI aluminum company must demonstrate that it is operational. Because of the financial risks inherent in providing actual power and in order to meet the known and capped cost prerequisite, BPA determined that the default delivery mechanism would be to monetize the value of the below-market power sales to provide service benefits through cash payments. However, BPA retains an option to provide actual power in-lieu of monetizing the transaction.
5. Power Function Review
In January 2005, BPA initiated an extensive and in depth process to examine the PBL's program levels. This Power Function Review (PFR) provided customers and constituent's significant opportunity to provide input into the policy choices that drive program cost projections to be used in BPA's initial power rate proposal. The PFR focused on nine major cost areas:
a. Army Corps of Engineer and Bureau of Reclamation operation and maintenance costs and capital investments;
b. Columbia Generating Station operation and maintenance costs and capital investments;
c. Conservation program costs;
d. Fish and wildlife program expenses and capital investments;
e. Internal operations costs charged to power rates;
f. Renewable program costs;
g. Transmission acquisition costs;
h. Risk mitigation packages and tools; and
i. Federal and Non-Federal debt service and debt management.
Two main areas, (1) debt service and debt management and (2) risk mitigation, were discussed but not decided in the PFR. The PFR involved technical staff meetings, management level discussions, and regional public meetings. In total, BPA held seven technical meetings, five formal discussion sessions with utility managers and five regional public meetings that involved general managers representing public customers, and customer representatives representing customers and constituent groups. During this five-month review, interested persons submitted a total of 94 written comments to BPA about the issues under discussion. At the close of the comment period, BPA issued a draft close-out letter with proposed program cost levels, delineated the consequences and opportunities of further reductions, and sought comment on those proposed levels. BPA received a number of additional written comments on the draft close-out letter. A final close-out letter was issued June 24, 2005. The PFR resulted in $96 million in reductions per year in forecasted program level cost estimates.
In the close-out letter, BPA responded to the comments provided on the draft and laid out the program level cost estimates that would be used in BPA's WP-07 Initial Proposal. In addition, BPA committed to revisit many of the program areas when more information is known. BPA will hold discussions separately from the rate case proceedings to share the updated forecasts, define associated policy choices, and solicit feedback from customers and constituents before they are incorporated into the final rates.
6. Post-2006 Conservation Program Structure Proposal
In the fall of 2004, BPA established a post-2006 conservation workgroup. The conservation workgroup was composed of over 65 utility representatives and conservation stakeholders. The purpose of the workgroup was to discuss and develop BPA's conservation program for the post-2006 time frame. In January 2005, the workgroup provided BPA with recommendations and comments on how BPA should design its conservation program.
On March 28, 2005, BPA issued its Post-2006 Conservation Program Structure Proposal for review and a 30-day comment period. BPA received 56 comments on the proposal. On June 28, Start Printed Page 676892005, BPA issued its response to the comments along with its final decision on the design and scope of the Post-2006 proposal.
The proposal described the approach of the conservation programs that BPA will offer during the FY 2007 through 2009 timeframe. The decisions in the Post-2006 proposal have been used as inputs in the development of BPA's WP-07 Initial Proposal.
7. Transmission Rate Case
BPA is committed to marketing its power and transmission services separately in a manner that is modeled after the regulatory initiatives adopted in 1996 by FERC to promote competition in wholesale power markets. The Commission's initiatives in Orders 888  and 889  directed public utilities regulated under the Federal Power Act to separate their power merchant functions from their transmission reliability functions; unbundle transmission and ancillary services from wholesale power services; and set separate rates for wholesale generation, transmission, and ancillary services. Although BPA is not required by law to follow the Commission's regulatory directives that promote competition and open access transmission service, BPA elected to separate its power and transmission operations and unbundle its rates in a manner consistent with the directives concerning open access transmission service. BPA develops its transmission rates in separate proceedings from its power rates.
On February 2, 2005, BPA's Transmission Business Line (TBL) initiated a rate case to establish transmission rates for the FY 2006-2007 transmission rate period. Prior to the initiation of that rate case, TBL held several public meetings with customers over the period July through September 2004 to discuss transmission costs, revenues, and rate design issues for the FY 2006-2007 rate period. The customers expressed interest in meeting with TBL to develop a settlement for the FY 2006-2007 rate period. TBL continued meetings with customers between October and early December 2004, resulting in a Settlement Agreement. TBL's initial rate proposal reflected the terms of the Settlement Agreement.
On June 20, 2005, BPA issued the Final Transmission Proposal-Administrator's Record of Decision that adopted the transmission and ancillary services rates as reflected in the Settlement Agreement. Final approval of these TBL rates was issued by FERC on September 29, 2005. The TBL rate case settlement established formula rates for ancillary services and some transmission rates that incorporate ancillary services. For FY 2007, these formula rates will be affected by the pricing of generation inputs to ancillary services that will be determined in this PBL rate case. The pricing of generation inputs to ancillary services determined in this rate case also will be a factor in TBL's rates in FY 2008-2009.
B. Scope of the 2007 Rate Case
Many of the decisions that guide BPA's power marketing policies have been made or will be made in other public review processes. This section provides guidance to the Hearing Officer as to those matters that are within the scope of the rate case, and those that are outside the scope.
1. Program Level Expenses Decided in the PFR
As described above, the program level expense estimates, except those decided elsewhere, have already received extensive public review and comment in the PFR process. Pursuant to § 1010.3(f) of BPA Hearing Procedures, the Administrator hereby directs the Hearing Officer to exclude from the record any material attempted to be submitted or arguments attempted to be made in the hearing which seek to in any way revisit the appropriateness or reasonableness of BPA's decisions on spending levels, as included in BPA's revenue requirements for FYs 2007 through 2009. However, as noted above, BPA did commit to revisit many of the program areas where final results were not known at the time the final report was issued and will hold discussion separately from the rate case proceeding to share the updated forecasts, define associated policy choices, and solicit feedback from customers and constituents before they are incorporated into the final rates. Excepted from this direction due to their variable nature, dependency on BPA's rate case models, and/or timing, are: (1) Forecasts of short-term purchase power costs; (2) capital recovery matters such as interest rate forecasts, scheduled amortization, depreciation, replacements, and interest expense; and (3) risk mitigation packages and tools.
2. Near-Term Policy Decisions
As detailed above, BPA issued the Near-Term Policy on February 4, 2005. The Policy resolved a number of policy decisions that impact the design and features of BPA's WP-07 Initial Proposal. Those issues include but are not limited to, decisions on the availability of the lowest cost PF rate to public customers, term of the rate period, IOU and DSI service options, and the availability of products for new or existing customers. Pursuant to § 1010.3(f) of BPA Hearing Procedures, the Administrator hereby directs the Hearing Officer to exclude from the record any material attempted to be submitted or arguments attempted to be made in the hearing which seek to in any way revisit the appropriateness or reasonableness of BPA's decisions made in the Near-Term Policy ROD.
3. DSI Service
The DSI Service decisions finalized and established the manner and method by which BPA would provide service and benefits to its DSI customers. The decisions in that ROD resolved the method and level of service to be provided DSIs in the FY 2007-2011 period. Pursuant to § 1010.3(f) of BPA Hearing Procedures, the Administrator directs the Hearing Officer to exclude from the record any material attempted to be submitted or arguments attempted to be made in the hearing which seek to in any way revisit the appropriateness or reasonableness of BPA's decisions made in the DSI ROD.
4. Transmission Acquisition Expense
In addition to the program cost decisions, the PFR close-out letter also included transmission acquisition program cost level decisions. This program represents the cost associated with services necessary to deliver energy from generating resources to markets and loads. These costs include: transmission expenses; ancillary services; real power losses; generation integration costs associated with the U.S. Army Corps of Engineers and Bureau of Reclamation transmission facilities; and metering and communication requirements. In addition to these decisions, BPA determined the mechanism for modeling the variability in transmission expenses for the upcoming rate period.
Pursuant to § 1010.3(f) of BPA Hearing Procedures, the Administrator hereby directs the Hearing Officer to exclude from the record any material attempted to be submitted or arguments attempted to be made in the hearing which seek to in any way revisit the Start Printed Page 67690appropriateness or reasonableness of BPA's transmission acquisition program level estimates or the modeling used to calculate the variability of the transmission expense.
The only issue associated with the transmission acquisition program within the scope of this rate case is the risk analysis associated with modeling the transmission expense. In the PFR close-out letter, BPA agreed to model the transmission expense based on the full distribution of secondary sales rather than the average transmission expense. This issue will be addressed in the risk analysis portion of the rate case.
5. Other Transmission Issues
a. Generation Inputs
BPA's Power Business Line (PBL) provides a portion of the FCRPS's available generation to the TBL to enable TBL to meet its various transmission requirements. TBL uses the generation inputs to provide ancillary and control area services. To recover the costs associated with providing these generation inputs, PBL assigns a portion of the FCRPS costs to the transmission function. The cost allocations PBL is proposing to use to determine the generation input costs and associated unit costs to the TBL is a matter that is included within the scope of this rate proceeding.
Pursuant to § 1010.3(f) of BPA Hearing Procedures, the Administrator directs the Hearing Officer to exclude from the record any material attempted to be submitted or arguments attempted to be made in the hearing that seek in any way to revisit the appropriateness or reasonableness of any other issues related to the generation inputs. This includes, but is not limited to, issues regarding the level or quality of the generation inputs that TBL requests from PBL. These determinations are generally made by TBL in accordance with industry, reliability, and other compliance standards and criteria, and are not matters appropriate for the rate case.
b. Transmission Rate Case
On June 20, 2005, BPA issued the Final Transmission Proposal ROD in TBL's rate case, which received final approval on September 29, 2005. Pursuant to § 1010.3(f) of BPA Hearing Procedures, the Administrator hereby directs the Hearing Officer to exclude from the record any material attempted to be submitted or arguments attempted to be made in the hearing which seek in any way to revisit the appropriateness or reasonableness of issues determined in the TBL rate case. That proceeding addressed, among other things, transmission and ancillary service rate levels, the $1.5 million payment from TBL to PBL for Attachment K redispatch for FY 2006-2007, and the GTA Delivery Charge for FY 2007.
6. Post-2006 Conservation Program Structure Proposal
Through the post-2006 workgroup collaboration, customers and constituents provided input on the development of BPA's post-2006 conservation approach. Pursuant to § 1010.3(f) of BPA Hearing Procedures, the Administrator hereby directs the Hearing Officer to exclude from the record any material attempted to be submitted or arguments attempted to be made in the hearing that seek to in any way revisit the appropriateness or reasonableness of BPA's conservation programs and establishment of expense levels through the Post-2006 Conservation Program Structure Proposal dated June 28, 2005. The Hearing Officer is directed to exclude from the scope of this proceeding evidence regarding BPA's portfolio of conservation programs and the expenses BPA intends to pursue during the upcoming rate period.
7. Federal and Non-Federal Debt Service and Debt Management
During the PFR, and in other forums, BPA provided background information on its internal Federal and non-Federal debt management policies and practices. The discussions of these topics in the PFR and other forums were not intended to seek input from customers and constituents regarding BPA's debt management policies and practices. Rather, these discussions were intended to merely inform interested parties about these matters so that they would better understand BPA's debt structure. Although the PFR close-out letter did not make any decisions regarding BPA's debt management policies and practices, these remain outside the scope of the rate case. Therefore, pursuant to § 1010.3(f) of BPA Hearing Procedures, the Administrator hereby directs the Hearing Officer to exclude from the record any material attempted to be submitted or arguments attempted to be made in the hearing which seek to in any way visit the appropriateness or reasonableness of BPA's debt management policies and practices.
8. Potential Environmental Impacts
The Administrator directs the Hearing Officer to exclude from the record all evidence and argument that seek in any way to address the potential environmental impacts of the rates being developed in the 2007 Wholesale Power Rate Case. See Section C, below.
C. The National Environmental Policy Act
BPA is in the process of assessing the potential environmental effects of its WP-07 Initial Proposal, consistent with the National Environmental Policy Act (NEPA). BPA's Business Plan Environmental Impact Statement (Business Plan EIS), completed in June 1995, evaluated the environmental impacts of a range of business plan alternatives that could be varied by applying policy modules, including one for rates. Any combination of alternative policy modules should allow BPA to balance its costs and revenues. The Business Plan EIS also addressed response strategies, including adjusting rates that BPA could pursue if BPA's costs exceeded its revenues. In August 1995, the BPA Administrator issued a Record of Decision (Business Plan ROD) that adopted the Market-Driven Alternative from the Business Plan EIS. This alternative was selected because, among other reasons, it allows BPA to: (1) Recover costs through rates; (2) competitively market BPA's products and services; (3) develop rates that meet customer needs for clarity and simplicity; (4) continue to meet BPA's legal mandates; and (5) avoid adverse environmental impacts. BPA also committed to apply as many response strategies as necessary when BPA's costs and revenues do not balance. Because the WP-07 Initial Proposal likely would assist BPA in accomplishing these goals, the proposal appears consistent with these aspects of the Market-Driven Alternative. In addition, this rate proposal is similar to the type of rate designs evaluated in the Business Plan EIS; thus implementation of this rate proposal would not be expected to result in significantly different environmental impacts from those examined in the Business Plan EIS. Therefore, BPA expects that this WP-07 Initial Proposal will fall within the scope of the Market-Driven Alternative that was evaluated in the Business Plan EIS and adopted in the Business Plan ROD.
As part of the Administrator's ROD that will be prepared regarding this 2007 Wholesale Power Rate Case, BPA may tier its decision under NEPA to the Business Plan ROD. However, depending upon the ongoing environmental review, BPA may, instead, issue another appropriate NEPA document. Start Printed Page 67691
Part III—Public Participation
A. Distinguishing Between “Participants” and “Parties”
BPA distinguishes between “participants in” and “parties to” the 7(i) hearing process. Apart from the formal hearing process, BPA will accept comments, views, opinions, and information from “participants” who are defined in the BPA Hearing Procedures as persons who may submit comments without being subject to the duties of, or having the privileges of, parties. Participants' written and oral comments will be made a part of the official record and considered by the Administrator when making his decision. Participants are not entitled to participate in the prehearing conference; may not cross-examine parties' witnesses, seek discovery, or serve or be served with documents; and are not subject to the same procedural requirements as parties.
The views of the participants are important to BPA. Written comments by participants will be included in the record if they are received by 5 p.m. on February 13, 2006. This date follows the anticipated submission of BPA's and all other parties' direct cases. Written views, supporting information, questions, and arguments should be submitted to BPA Communications at the address listed in Section 2 of this Notice. In addition, BPA will hold six field hearings in the Pacific Northwest region. Participants may appear at the field hearings and present oral statements. The transcripts of these hearings will be part of the record upon which the Administrator makes his final rate decisions.
Persons wishing to become a party to BPA's rate proceeding must notify BPA in writing and file a Petition to Intervene with the Hearing Officer. Petitioners may designate no more than two representatives upon whom service of documents will be made. Petitions to Intervene shall state the name and address of the person requesting party status and the person's interest in the hearing.
Petitions to Intervene as parties in the rate proceeding are due to the Hearing Office by 5 p.m. on November 17, 2005. The petitions should be directed as stated below or may be e-mailed to the following e-mail address: firstname.lastname@example.org: Jennifer Sanders, Hearing Clerk—LP-7, Bonneville Power Administration, 905 NE 11th Avenue, P.O. Box 3621, Portland, OR 97208-3621.
Petitioners must explain their interests in sufficient detail to permit the Hearing Officer to determine whether they have a relevant interest in the proceeding. Pursuant to § 1010.1(d) of BPA Hearing Procedures, BPA waives the requirement in § 1010.4(d) that an opposition to an intervention petition must be filed and served 24 hours before the November 21, 2005, prehearing conference. Any opposition to an intervention petition may instead be made at the prehearing conference. Any party, including BPA, may oppose a petition for intervention. Persons who have been denied party status in any past BPA rate proceeding shall continue to be denied party status unless they establish a significant change of circumstances. All timely applications will be ruled on by the Hearing Officer. Late interventions are strongly disfavored.
B. Developing the Record
The record will comprise, among other things, verbal and written comments made by participants, including the transcripts of all hearings, any written material submitted by the parties, documents developed by BPA staff, BPA's environmental analysis and comments accepted on it, and other material accepted into the record by the Hearing Officer. Written comments by participants will be included in the record if they are received by 5 p.m., Pacific Standard Time, on February 13, 2006. The Hearing Officer will then review the record, supplement it if necessary, and will certify the record to the Administrator for decision.
The Administrator will develop final proposed rates based on the entire record, which includes the record certified by the Hearing Officer, as described above. The basis for the final proposed rates first will be expressed in the Administrator's draft ROD. Parties will have an opportunity to respond to the draft ROD as provided in BPA Hearing Procedures. The Administrator will serve copies of the final ROD on all parties. At the conclusion of the rate proceeding, BPA will file its rates with FERC for confirmation and approval at least 60 days prior to October 1, 2006.
BPA must continue to meet with customers in the ordinary course of business during the rate case. To comport with the rate case procedural rule prohibiting ex parte communications, BPA will provide the prescribed notice of meetings involving rate case issues in order to permit the opportunity for participation by all rate case parties. These meetings may be held on very short notice. Consequently, the parties should be prepared to devote the necessary resources to participate fully in every aspect of the rate proceeding and attend meetings any day during the course of the rate case.
Part IV—Major Studies and Summary of Proposal
A. Summary of Proposed 2007 Wholesale Power Rate Structure
1. List of Proposed 2007 Wholesale Power Rates
BPA is proposing five different rate schedules for its 2007 Wholesale Power Rates. The actual rate schedules and the GRSPs are available for viewing and downloading on PBL's Web site at www.bpa.gov/power/ratecase as discussed in Part V of this Notice.
a. PF-07 Priority Firm Power Rate
The PF rate schedule is comprised of two rates: the PF Preference rate and the PF Exchange rate.
The PF Preference rate applies to BPA's firm power sales to be used within the Pacific Northwest by public bodies, cooperatives, and Federal agencies. This power is guaranteed to be continuously available. The rate applies to the following products:
Full Service Product
Actual Partial Service Product—Simple
Actual Partial Service Product—Complex
Block Product with Factoring
Block Product with Shaping Capacity
The PF Exchange rate applies to sales of power to regional utilities that participate in the Residential Exchange Program established under Section 5(c) of the Northwest Power Act, 16 U.S.C. 839c(c).
b. NR-07 New Resource Firm Power Rate
The New Resource Firm Power (NR) rate applies to net requirements power sales to IOUs for resale to ultimate consumers for direct consumption, construction, test, and start-up, and for station service. NR-07 firm power is also available to public utility customers for serving New Large Single Loads. This rate applies to the following products:
New Large Single Loads
Full Service Product
Actual Partial Service Product—Simple
Actual Partial Service Product—Complex
Block Product with Factoring
Block Product with Shaping Capacity
c. IP-07 Industrial Firm Power Rate
The IP rate is available for discretionary firm power sales to DSI Start Printed Page 67692customers authorized by Section (5)(d)(1)(A) of the Northwest Power Act, 16 U.S.C. 839c(d)(1)(A).
d. FPS-07 Firm Power Products and Services Rate Schedule FPS
The FPS rate schedule is available for the purchase of Firm Power, Capacity Without Energy, Supplemental Control Area Services, Shaping Services, and Reservation and Rights to Change Services for use inside and outside the Pacific Northwest. The rates for these products are posted and/or negotiated. BPA is not obligated to enter into agreements to sell products and services under this rate schedule.
e. GTA-07 General Transfer Agreement Delivery Charge
The GTA Delivery Charge applies to customers who purchase Federal power that is delivered over non-Federal low voltage transmission facilities. The rate was set in the 2006 TBL Rate Case Settlement and approved by FERC on September 29, 2005, to mirror the Utility Delivery rate from October 1, 2005, through September 30, 2007. The 2006 TBL Rate Case Settlement set the GTA Delivery Charge at $1.119 per kilowatt-month through September 30, 2007. For the period of October 1, 2007 through September 30, 2009, PBL is proposing to continue to set the GTA Delivery Charge to the same rate as TBL's posted Utility Delivery rate. As adjustments are made to the Utility Delivery rate in future TBL rate cases, PBL proposes to reflect these changes in the GTA Delivery Charge.
2. Significant Rate Development Issues
a. Risk Mitigation
Several factors present new challenges for BPA to keep its power rates low while fulfilling its mission and meeting its obligations to the U.S. Treasury consistent with sound business principles. Increased market price volatility and six consecutive years of below-average runoff have significantly changed the landscape of risk and uncertainty facing BPA and its stakeholders.
The uncertainty and volatility of market prices are greater today than they have been in the past. As a consequence, the cost of covering the risk BPA faces in crediting a large portion of secondary revenues to power rates before receiving those uncertain funds is now greater. BPA also faces uncertainty around the operational costs for fish programs in FY 2006 and in the FY 2007-2009 rate period. A new Biological Opinion or possible court-ordered change to river operations would directly affect BPA's net revenues. In addition, enhanced risk management practices resulted in analysis that accounts for operational risks not previously modeled as well as a more comprehensive analysis of non-operating risks. Finally, the $325 million Fish Cost Contingency Fund (FCCF) was fully depleted in FY 2003 resulting in the loss of a risk tool that was available to mitigate dry year impacts on fish operations.
These changes create greater risk for BPA, reduce BPA's ability to absorb those risks, increase the costs of managing risks, and/or more fully reflect the costs of managing them. If rates were designed using a traditional approach of adding Planned Net Revenues for Risk (PNRR), these changes would require that power rates be set to recover a much larger “risk premium” than ever before in order to meet the Treasury Payment Probability (TPP) standard which, if this was the sole approach to managing risk, would result in a relatively high rate. Additional cash reserves and/or a more comprehensive risk mitigation package, such as the cost recovery adjustment clauses implemented in the FY 2002-2006 rates, are necessary to address these risks and ensure that BPA can maintain its minimum TPP standard of 92.6%  for the rate period.
As noted above, BPA faces a level of uncertainty regarding its assumption concerning river operations as well as direct program costs for fish and wildlife due to the ongoing issues surrounding BPA fish and wildlife obligations. To mitigate against this risk, BPA has proposed a specific rate adjustment (NFB adjustment). In order to balance the need to cover risk with overall rate levels, BPA is proposing to meet its TPP standard through a combination of PNRR, cost recovery adjustment charges, the NFB adjustment and a dividend distribution clause. See Sections 3 and 4, below.
BPA has been meeting with customers and the parties over the last year to explore alternative means of managing risk that would allow the TPP standard to be met with lower rates. BPA has committed to continue these discussions over the next several months in properly noticed meetings to continue to pursue the viability of these options in order to include them in the final studies.
b. Residential Exchange Program Settlement Benefits
Under Residential Exchange Program (REP) settlement agreements executed by BPA and the IOUs in 2000, BPA originally provided the IOUs 1,000 aMW of power benefits and 900 aMW of monetary benefits for the FY 2002-2006 period. Power sales were originally made at the Residential Load (RL) Firm Power Rate and the PF Exchange Subscription rate. Monetary benefits were originally calculated based on the difference between BPA's RL rate and BPA's then-current rate case 5-year flat block price forecast. The benefits increase to 2,200 aMW for the FY 2007-2011 period either in the form of power or monetary benefits, at BPA's discretion. Based on amendments of the REP settlement agreements in 2004, and the Near-Term Policy, however, BPA will not sell power to the IOUs during FY 2007-2011. BPA therefore is not proposing to establish an RL rate or a PF Exchange Subscription rate for IOU power sales in the WP-07 rate case. Instead, all IOU Settlement benefits for the FY 2007-2011 period are monetary benefits calculated based on the difference between an independent determination of a forecast of a forward flat block market price and BPA's flat PF rate, consistent with the IOU contracts.
c. Inter-Business Line Calculations
BPA is addressing certain inter-business line issues in this 2007 Power Rate Case. These include the generation inputs for: generation supplied reactive and voltage support; operating reserves; regulating reserves; generation and energy imbalance; generation dropping for remedial action schemes; and station service. Segmentation of the Corps of Engineers (COE) and the Bureau of Reclamation (Reclamation) facilities will also be addressed. BPA is proposing methodologies to calculate the costs of these services, and forecast revenues, in order to determine BPA's power revenue requirement to be recovered through power rates. These generation costs, or associated unit costs, will be allocated to TBL to support TBL's ancillary services and other operations. Relevant transmission and ancillary service rates for FY 2006-2007 include formulas that allow for the costs and charges developed in this power rate case to be factored into the transmission and ancillary service rates. BPA is also proposing to set a GTA Delivery Charge as determined by the 2006 Transmission rate settlement. This power rate proceeding will establish the GTA Delivery Charge for FY 2008 and 2009. Start Printed Page 67693
d. DSI Service 2007-2011
Consistent with the DSI ROD, BPA is not forecasting direct service under the IP rate to the DSI customers. Instead, BPA plans to offer the DSI aluminum smelters 560 aMW of surplus firm power service benefits for the FY 2007-2011 period at a capped cost of $59 million per year. BPA will offer Port Townsend Paper Company 17 aMW of surplus firm power service benefits, whereupon its local utility will provide power at a utility rate expected to be approximately equivalent to, but in no case lower than, BPA's PF rate. With the DSI aluminum companies, creditworthiness standards must be met or acceptable credit assurances must be provided by those companies qualifying for benefits. In addition, benefits can be monetized under the proposed contracts with these companies, but BPA will retain the right to provide physically delivered surplus power, subject to long-term interruption rights, in lieu of a financial transaction.
3. Changes in Rate Design
BPA is continuing, in general, its existing rate design for its FY 2007-2009 rates, with some changes and modifications as described below. Complete details on these changes are available for viewing and downloading on PBL's Web site at www.bpa.gov/power/ratecase as discussed in Part V of this Notice.
a. Conservation Rate Credit (CRC)
BPA is proposing to replace the Conservation and Renewables (C&R) Discount with a Conservation Rate Credit (CRC) program. The CRC will retain many of the features of the C&R Discount including: (1) The credit will remain at 0.5 mills per kWh; (2) monthly bill credits; (3) no decrement to customers' net requirements for CRC participation (including Slice customers); (4) customer flexibility in choosing between several eligible conservation and renewable energy measures; and (5) funding under the CRC for customer renewable resource activities is limited to $6 million annually.
b. Dividend Distribution Clause (DDC)
BPA is proposing to continue the DDC with a modification to the Threshold. BPA proposes that there will be a DDC if Accumulated Modified Net Revenues (AMNR) reach the equivalent of $800 million in reserves attributable to PBL.
c. Excess Factoring Charge
This is a charge that applies to purchasers of the Complex Actual Partial Service Product under the PF rate schedule. BPA is proposing minor changes to eliminate references to the California Power Exchange.
d. Green Energy Premium
BPA is proposing to continue the Green Energy Premium (GEP), available to customers purchasing firm power. The GEP is an adjustment to the PF rate when a customer chooses to designate any portion (up to 100 percent) of its Subscription purchase as Environmentally Preferred Power.
The GEP will range from zero to 40 mills per kWh depending on the specific products and associated costs selected by each customer. BPA forecasts an average of $1.4 million of annual revenue from the GEP over the rate period. Revenues from the GEP will support BPA renewable resource facilitation and research and development.
e. Load-Based Cost Recovery Adjustment Charge (LB CRAC) True-Up
BPA is not proposing to continue the existing LB CRAC in the FY 2007-2009 rate period. However, the LB CRAC contemplates an after-the-fact true-up as soon as the necessary actual data is available after each sixth-month LB CRAC period. The final LB CRAC True-Up is anticipated to occur in December 2006, after the expiration of BPA's current rates on September 30, 2006. Therefore, BPA is proposing to carry over the LB CRAC True-Up provisions in the GRSPs for the FY 2007-2009 rate period to allow for the final True-Up. Implementation will be limited to the true-up for the final 6 months (LBCRAC10 period) of the 2002-2006 rate period. True-Up billing adjustments will be made over twelve months starting in early 2007.
f. Load Variance Charge
BPA is proposing to continue the Load Variance Charge. This charge covers BPA's cost of meeting customers' load growth for reasons other than annexation or retail access load gain or loss. In addition, it provides Full and Partial Service purchasers the right to deviate from their monthly forecast BPA purchases due to weather, economic business cycles, plant energy consumptions and other reasons. The method for setting the Load Variance charge in this rate proposal differs from the WP-02 rate-setting process. It is no longer based on the cost of put or call options. Instead, load growth is forecast, and the cost is estimated based on a forecast of future market prices. The cost of forecast error is estimated based on an assumption of a two percent forecast error and a forecast of future market prices. The charge is set at 0.53 mills per kWh and is charged against the customer's Total Retail Load.
g. Low Density Discount (LDD)
BPA is proposing four changes to the LDD: (1) BPA proposes to change the eligibility criteria to account for BPA's separation of power and transmission rates which first occurred in 1996, and also to ensure that customers with very low retail rates will not qualify for the LDD; (2) one of the measures used in calculating the LDD is proposed to use “consumers per mile” instead of “meters per mile” to ensure consistency and equity; (3) the term “average retail rate” has been clarified for simplification of the LDD administration; and (4) BPA proposes to amend LDD to ensure it only applies to the qualifying Slice purchaser's net requirements.
h. Monthly Demand and Energy Charges
BPA is not proposing changes to the methodology for calculating energy charges. There will be two diurnal periods, Heavy Load Hour (HLH) and Light Load Hours (LLH), for each month. BPA is proposing slight changes to the definitions of HLH and LLH to be consistent with NERC definitions. BPA is proposing to revise the definition of HLH and LLH included in the 2006 Transmission General Rate Schedule Provisions for FY 2007 to be consistent with NERC and BPA's proposed definitions in the GRSPs for the power rates. The actual energy charges will be updated consistent with the method used in WP-2002.
BPA is proposing a minor modification to the methodology for calculating the demand charge. There will continue to be 12 monthly demand charges, but the average rate will decrease from $2.00 per kW-month to $1.05 per kW-month. This change is to better reflect the market price for demand with energy.
i. PF Targeted Adjustment Charge (PF TAC)
BPA is continuing the Targeted Adjustment Charge, with some proposed modifications. BPA proposes to exempt PF TAC loads from the PF TAC in any year of the three years of the rate period that the load subject to the TAC is less than 1 aMW. The TAC will apply to the entire load if it exceeds the minimum. Also, the calculation of the PF TAC rate will be based on monthly availability of the Federal Base System (FBS), rather than an annual calculation. Start Printed Page 67694
j. Unauthorized Increase Charges (UAI) for Power Sales
These are penalty charges for Unauthorized Increases in Energy and Unauthorized Increases in Demand for deliveries that exceed contractual entitlements for energy and demand, respectively. BPA is proposing minor changes to the UAI to eliminate references to the California Power Exchange.
4. New Adjustments in Rates
BPA is proposing a number of new adjustments and continuing some existing adjustments. Complete details of these adjustments are available for viewing and downloading on PBL's Web site at www.bpa.gov/power/ratecase as discussed in Part V of this Notice.
a. Operating Reserves
BPA is proposing changes in how it handles its forecasted revenues from providing operating reserves to the TBL. BPA's Open Access Transmission Tariff requires transmission customers serving load with generation located in the Transmission Provider's Control Area to acquire Operating Reserves from the Transmission Provider, from a third party, or by self-supply. The 2002 power rate case estimated total revenue recovered by PBL selling Operating Reserves generation inputs to TBL, assuming all customers purchased Operating Reserves from TBL. The expected revenue from the sale of Operating Reserves was deducted from the overall revenue requirement when determining the cost of the Federal system which is the basis for calculating power rates. During this current rate period, some customers began self-supplying Operating Reserves, and TBL has purchased less generation inputs from PBL. Therefore, PBL did not fully recover expected revenues. To avoid this under-recovery in the FY 2007-2009 rate period and to ensure that revenues are allocated equitably, PBL is proposing to estimate total revenues from the sale of generation inputs to TBL and give a 0.89 mills per kWh credit on the power bills of customers that elect to purchase Operating Reserves from TBL. This will prevent both under-recovery and over-recovery. While BPA proposes not to allocate these revenues or credits to those customers that self-supply Operating Reserves or acquire Operating Reserves from a third party, BPA will consider alternatives to this proposal that address BPA's concerns regarding the proper allocation of costs and revenues.
b. Cost Recovery Adjustment Clause (CRAC)
Prior to the beginning of each fiscal year of the rate period (i.e., FY 2007-2009), a forecast of the previous year's end-of-year AMNR will be completed. If the AMNR at the end of the forecast year falls below the defined CRAC Threshold for that fiscal year, the CRAC will trigger, and a rate increase will go into effect beginning in October of the upcoming fiscal year. Any such increase in a fiscal year's rates would remain in effect through September of the following year. This adjustment could occur as early as August 2006 for the rates in effect for FY 2007. The amount of the rate increase is limited to the lower of the annual Maximum Planned Recovery Amount of $300 million or the amount by which AMNRs under run the threshold.
|AMNR calculated at end of fiscal year||CRAC applied to fiscal year||CRAC threshold||Approx. threshold as measured in PBL reserves||Maximum CRAC recovery amount (cap)*|
c. The NFB Adjustment (National Marine Fisheries Service (NMFS) Federal Columbia River Power System (FCRPS) Biological Opinion (BiOp) Adjustment)
The NFB adjustment results in an upward adjustment to the CRAC Maximum Planned Recovery Amount (Cap) for any year in the rate period if unforeseen fish and wildlife costs arise from a predetermined set of circumstances. The NFB Adjustment calculation will result in an increase in the annual CRAC maximum recovery amount defined in Table A for the next fiscal year following the year the NFB Adjustment was triggered. The NFB Adjustment is applicable to FY 2007—2009. The NFB Adjustment will address increases in financial impacts to the anadromous fish portion of the Fish and Wildlife program only when those impacts result from changes in FCRPS Endangered Species Act (ESA) compliance as required by a court order (including court-approved agreements), an agreement related to litigation, a new NMFS FCRPS BiOp, or Recovery Plans under the ESA. Financial impacts include foregone revenue, power purchases, direct program expense, fish credits, COE and BOR O&M, and capital repayment. Financial impacts will be calculated net of forecast 4(h)(10)(C) credits. This adjustment would be calculated at the same time that the calculation of the CRAC would be made.
5. Rates With No Proposed Changes
The following is a list of rates or adjustments that BPA proposes to continue with no changes from current rates. Complete details on the rates or adjustments are available for viewing and downloading on PBL's Web site at www.bpa.gov/power/ratecase as discussed in Part V of this Notice.
a. Demand Adjuster
This is an adjustment that is made to the demand billing factor for certain requirements products.
b. Flexible PF and NR
These are rate options available, at BPA's discretion, to purchasers under the PF and NR rate schedules.
c. Slice True-Up Adjustment
BPA is not proposing any changes to the methodology used to conduct the Slice True-up. However, BPA does clarify in its proposal how certain costs are treated with the Slice Rate and True-up. These include debt optimization, bad debt expenses, augmentation expenses, Conservation Augmentation, IOU and DSI benefits, and Slice implementation expenses.
d. Value of Reserves
Section 7(c)(3) of the Northwest Power Act, 16 U.S.C. 839e(c)(3), Start Printed Page 67695provides that the Administrator shall adjust rates to the DSI customers “to take into account the value of power system reserves made available to the Administrator through his rights to interrupt or curtail service to such direct service industrial customers.” The DSIs may provide two types of reserves: Supplemental Contingency Reserves and Stability Reserves. The WP-07 Initial Proposal reflects Stability Reserves being purchased by the TBL and addressed in TBL's transmission rate case.
The PBL is proposing in this rate case to continue the approach to procure Supplemental Reserves developed in the WP-02 Rate Case. The PBL will purchase the most cost-effective Supplemental Reserves or provide those reserves itself. No Supplemental Reserves are explicitly forecast to be provided by the DSIs in this rate case. Any payment to the DSIs for Supplemental Contingency Reserves will be negotiated within a specified range on an individual customer basis rather than a credit applied to some or all of BPA's DSI load. The maximum amount PBL may pay is $6.96 per kW-month.
6. Rates and Adjustments Proposed To Be Discontinued
The following are rates and adjustments that BPA is proposing to discontinue.
a. Cost-Based-Indexed IP Rate
BPA does not forecast any sales under this product.
b. Cost-Based-Indexed PF Rate
BPA does not forecast any sales under this product.
c. Financial-Based Cost Recovery Adjustment Clause (FB CRAC)
BPA is not proposing a FB CRAC for this rate period. See Section 4.b., above, for BPA's risk mitigation.
d. Flexible IP
BPA is not proposing a flexible IP rate in the IP rate schedule as BPA does not forecast any sales under the IP rate schedule.
e. Industrial Power Targeted Adjustment Charge
BPA is not proposing to continue the industrial power targeted adjustment charge as BPA does not forecast any sales under the IP rate schedule.
f. Nonfirm Energy Rate Schedule
BPA is proposing to discontinue the NF rate in this rate proposal as it is no longer used.
g. Residential Load Firm Power Rate (RL)
BPA is proposing to discontinue the RL rate in this rate proposal as it is no longer necessary. See Section 2.b. above.
h. Safety Net Cost Recovery Adjustment Clause (SN CRAC)
BPA is not proposing a SN CRAC for this rate period. See Section 4.b., above, for BPA's risk mitigation.
i. Stepped Rates
BPA is not proposing stepped rates in this rate proposal because this is only a 3-year, not a 5-year, rate period.
j. Stepped Up Multi-Year (SUMY) Block Charge
BPA is not proposing a SUMY block charge in this rate proposal.
7. Development of IP Rate/7(c)(2) Adjustment
The IP-07 rate applies to discretionary firm power sales to BPA's DSI customers who purchase under Section 5(d) of the Northwest Power Act, 16 U.S.C. 839c(d). In this rate proposal, BPA is not forecasting any sales to DSIs under the IP rate but, for various reasons, the IP rate is nonetheless being set according to the rate directives contained in Section 7(c) of the Northwest Power Act, 16 U.S.C. 839e(c).
Section 7(c)(1)(B) provides that after July 1, 1985, DSI rates will be set “at a level which the Administrator determines to be equitable in relation to the retail rates charged by the pubic body and cooperative customers to their industrial consumers in the region.” 16 U.S.C. 839e(c)(1)(B). Pursuant to Section 7(c)(2), the IP rate is to be based on BPA's “applicable wholesale rates” to its preference customers and the “typical margins” included by those customers in their retail industrial rates. 16 U.S.C. 839e(c)(2). Section 7(c)(3) provides that the IP rate is also to be adjusted to account for the value of power system reserves provided through contractual rights that allow BPA to restrict portions of the DSI load. 16 U.S.C. 839e(c)(3). This adjustment is typically made through a value of reserves credit. Continuing past practice and given current circumstances, BPA will not propose a uniform value of reserves credit to be applied against the IP rate. Thus, the IP rate will be set equal to the applicable wholesale rate, plus a typical margin, subject to the floor rate test. As a final step in rate design, BPA develops monthly and diurnally differentiated energy charges and monthly differentiated demand charges based on allocated costs and scaled, based on the results of BPA's rate design.
The typical Industrial Margin is 0.573 mills per kWh. As stated above, a zero value of reserves credit is being forecast in this rate case. Thus, the net margin of 0.573 mills per kWh is added to the seasonal and diurnal PF energy charges to produce the initial IP rate charges.
BPA conducts a Section 7(b)(2) rate test as part of its ratemaking process and if the test “triggers,” the initial IP rate charges are increased. In the current rate case, the 7(b)(2) rate test does trigger and additional costs are allocated to the IP rate pool, substantially increasing the IP rate charges above their initial PF-plus margin level.
In addition, Section 7(c)(2) of the Northwest Power Act requires that IP rates in the post-1985 period “shall in no event be less than the rates in effect for the contract year ending on June 30, 1985.” 16 U.S.C. § 839e(c)(2). Accordingly, a floor rate test is performed to determine if the IP rate has been set at a level below the floor rate. If so, an adjustment is made that raises the IP rate to recover revenues that would be generated by application of the floor rate. Other customer classes are then credited with the increased revenue generated by application of the floor rate test and any resulting adjustment of the IP rate. If the IP rate has been set at a level above the floor rate, no floor rate adjustment is necessary.
The first step in calculating the floor rate is to apply the IP-83 Standard rate charges to test period (FY 2007-2009) DSI billing determinants. The resulting revenue figure is then divided by total IP test period loads to arrive at an average rate in mills per kWh. This rate is reduced by an Exchange Cost Adjustment and a deferral that were included in the IP-83 rate. Both adjustments are made on a mills per kWh basis.
BPA continues to conduct separate rate cases for power and transmission. Therefore, BPA has removed all transmission costs from the IP-83 rate to make a power-only floor rate comparison. These calculations result in a DSI floor rate of 20.97 mills per kWh. Because the proposed IP rate revenues are greater than the floor rate revenues, no adjustment was necessary.
8. Rate Design and Methodology
a. Risk Mitigation Package
PBL is proposing to rely on a number of elements for its risk mitigation package in its WP-07 Initial Proposal. These include a Cost Recovery Adjustment Clause (CRAC), with the Start Printed Page 67696NFB Adjustment and a DDC, as described above, as well as the following:
(1) Starting Reserves. The financial reserves attributable to PBL at the start of the rate period provide some financial protection against the financial uncertainties it faces. Starting financial reserves include the portions attributed to the generation function of cash in the BPA Fund and the deferred borrowing balance. The expected value for starting reserves is currently $381 million at the beginning of FY 2007.
(2) Other Agency Reserves Temporarily Available for Rate-Setting Purposes. BPA will assume that other agency reserves above the level required to meet the transmission function TPP for FY 2006-2007 can be considered for PBL rate-setting purposes to be temporarily available to PBL in FY 2007 only. BPA will ensure that this will not harm the interests of TBL or its customers.
(3) PNRR. The anticipated generation function reserves, with the tools noted above, are not sufficient for the agency to meet its financial objective of a 92.6 percent TPP. As a result, BPA's risk mitigation package includes some PNRR. PNRR is a dollar amount in the generation revenue requirement that generates additional revenue in order to increase the generation function reserves.
b. Rates Analysis Model (RAM)
The RAM2007 model is a large Excel spreadsheet model that is automated with Visual Basic macros. RAM2007 has three main steps: a Rate Design Step; a Subscription Step; and a Slice Separation Step. The RAM2007 Rate Design Step follows BPA's rate directives by determining the costs associated with the three resource pools (FBS resources, Residential Exchange resources, and new resources) used to serve sales load, and then allocates those costs to the rate pools (PF, IP, and NR). After the initial allocation of costs, the Northwest Power Act requires that some rate adjustments be made, such as those described in Section 7(b) and Section 7(c) of the Act. The RAM2007 performs these rate adjustments including the 7(b)(2) rate test in its Rate Design Step. The Rate Design Step of the RAM2007 concludes with the calculation of the “Rate Design Step” rates. At this point in the modeling, all posted rates are still preliminary except for the PF Exchange rate which is set and is then used to calculate the net cost of any public utility exchange. The Subscription Step calculates rates that will include the costs of the IOU Residential Exchange Program (REP) settlement. The Subscription Step section takes the rates resulting for the Rate Design Step and adjusts them by first subtracting any net cost of the traditional REP for the IOUs that have been included in the Rate Design Step rates, and then adding the costs of the IOU REP settlement. In the Rate Design and Subscription steps, costs were allocated to the various rate pools, including the PF Preference rate pool that contained all firm PF Preference loads. The Slice Separation Step separates out the PF Slice product revenues and firm loads from the overall PF Preference rate pool, leaving the costs that must be covered by the remaining non-Slice product PF Preference load.
B. Studies in Support of WP-07 Initial Proposal
The studies that have been prepared to support BPA's 2007 Initial Wholesale Power Rate proposal are described in detail in this section:
Load Resource Study and Documentation (Study about 35 pages, documentation about 120 pages);
Revenue Requirement Study and Documentation (Study about 200 pages, documentation about 450 pages);
Market Price Forecast Study and Documentation (Study about 25 pages, documentation about 400 pages);
Risk Analysis Study and Documentation (Study about 75 pages, documentation about 175 pages);
Wholesale Power Rate Development Study and Documentation (Study about 120 pages, documentation about 600 pages); and
Section 7(b)(2) Rate Test Study and Documentation (Study about 20 pages, documentation about 120 pages).
1. Load Resource Study
The Load Resource Study represents the compilation of the load and resource data necessary for developing BPA's wholesale rates. The Study has three major interrelated components: (a) BPA's Federal system load forecast; (b) BPA's Federal system resource forecast; and (c) the Federal system load and resource balances.
The Federal system forecast is composed of customer and group sales forecasts for public utilities and Federal agencies, IOUs, and other BPA contractual obligations.
The Federal system resource forecast includes power generated by both Federal and non-Federal hydro projects, return energy associated with BPA's existing capacity-for-energy exchanges, contracted resources, and other BPA hydro related contracts. The Federal system hydro resource estimates are derived from a hydro regulation study that estimates generation under 50 water years conditions using the operating provisions of the Pacific Northwest Coordination Agreement. The seasonal shape and magnitude of the Federal system hydro generation depends on availability of all regional resources and coordination of those resources to meet regional loads.
The projections of Federal system resources are compared with projected Federal system firm loads for each month of Fiscal Years 2007-2009 (October 2007-September 2009) under 1937 water conditions. The resulting load and resource balances yield the firm energy surplus or deficit of the Federal system resources. Similarly, firm capacity surpluses and deficits are determined for the same period.
2. Revenue Requirement Study
The purpose of the Revenue Requirement Study is to establish the level of revenues from wholesale power rates necessary to recover, in accordance with sound business principles, the FCRPS costs associated with the production, acquisition, marketing, and conservation of electric power. Generation revenue requirements include: Recovery of the Federal investments in hydrogeneration, fish and wildlife recovery, and energy conservation; Federal agencies' operations and maintenance expenses allocated to power; capitalized contract expenses associated with such non-Federal power suppliers as Energy Northwest; other purchase power expenses, such as short-term power purchases; power marketing expenses; cost of transmission services necessary for the sale and delivery of FCRPS power; and all other power-related costs incurred by the Administrator pursuant to law.
Cost estimates reflect the results of the Power Function Review and certain components of the Subscription Strategy. The repayment studies reflect updated actual and projected repayment obligations and accommodate the on-going implementation of BPA's Debt Optimization Program. All new capital investments are assumed to be financed from debt or appropriations. The adequacy of projected revenues to recover rate test period revenue requirements and to recover the Federal investment over the prescribed repayment period is tested and demonstrated for the generation function.
3. Market Price Forecast Study
The Market Price Forecast Study estimates the variable hourly cost of the Start Printed Page 67697marginal resource for transactions in the wholesale energy market. The specific market used in this analysis is the Mid-Columbia trading hub in the State of Washington.
The Market Price Forecast is used for two purposes in BPA's rate case. First, it is the basis for approximating the prices BPA may experience when selling to or buying from the wholesale power market. The Market Price Forecast estimates are therefore used to inform, but not directly set, the price used in BPA's surplus or net secondary revenue forecast. Second, the Market Price Forecast represents BPA's marginal cost in acquiring new energy, or the opportunity cost BPA may see in selling wholesale energy. The Market Price Forecast is therefore used in rate design and to send market-based price signals.
The Market Price Forecast uses a production cost model, AURORA, to estimate a market clearing price for wholesale energy. The fundamental assumption underlying AURORA modeling is the existence of a competitive wholesale energy pricing structure in the Western Electricity Coordinating Council Region. The model dispatches resources in a least cost order to meet a specified demand. Short-term prices are set at the variable cost of the marginal generator. Long-term capital investment decisions are based on economic profitability in an unregulated environment. The study will also forecast independent market-price forecasts used for IOU and DSI benefits.
4. Risk Analysis Study
The Risk Analysis Study focuses upon two types of risks and their impacts on BPA's revenues and expenses. The first class of risks is comprised of operating risks such as variations in economic conditions, load, and generation resource capability. These operating risks include the impacts of water supply conditions, alternative hydro operations, and market prices on net revenues. These operating risks are modeled in the Risk Analysis Model (RiskMod). The second class of risks comprises non-operating risks—all the risks included in the rate case risk modeling other than operating risks. This class of non-operating risks also includes uncertainty in achieving cost reductions identified in the Power Function Review. These risks are modeled in the Non-Operating Risk Model (NORM). The outputs from RiskMod and NORM are combined to develop the distribution of net revenues and cash flows that are required as input by the ToolKit Model.
BPA subsequently evaluates the impact that different risk mitigation measures have on reducing net revenue risk by calculating the TPP. The ToolKit Model assesses the impact that the net revenue deviations have on cash reserve levels, calculates the probability that BPA will make each Treasury payment on time and in full. If the TPP is below BPA's three-year 92.6 percent TPP standard, analysts change the combination of risk mitigation tools (e.g., Cost Recovery Adjustment Clauses, Planned Net Revenues for Risk, Dividend Distribution Clause, etc.) to meet the TPP standard. The amount of PNRR calculated in the ToolKit Model is included in revenue requirements and, thus, affects the level of the rates calculated in the rates analysis model below.
5. Wholesale Power Rate Development Study
The Wholesale Power Rate Development Study (WPRDS) is the primary source for details concerning BPA's power rates. It reflects the results of all of the other studies, documents the Rates Analysis Model, and documents the development of rates for BPA's wholesale power products and services. The WPRDS documents the allocation and recovery of Federal power costs, development of the Slice cost table; the development and forecast of inter-business line revenues and expenses (including Generation Input of Ancillary Services, segmentation of COE/Reclamation Transmission Facilities and GTA Delivery Charge), the development of charges for demand, load variance, unauthorized increase usage, excess load factoring, numerous rate provisions (e.g. the low-density discount, conservation and renewable discount, and rate mitigation), and the development of diurnal energy charges. Notably, one chapter of the WPRDS discusses BPA's risk mitigation package (i.e., the CRAC, NFB Adjustment, and DDC). The results of the WPRDS are the wholesale power rate schedules.
6. Section 7(b)(2) Rate Test Study
Section 7(b)(2) of the Northwest Power Act directs BPA to assure that the wholesale power rates effective after July 1, 1985, to be charged its public body, cooperative, and Federal agency customers (the 7(b)(2) Customers) for their general requirements for the rate period, plus the ensuing four years (in total, this is known as the test period), are no higher than the costs of power would be to those customers for the same time period if specified assumptions are made. The effect of the rate test is to protect the 7(b)(2) Customers' wholesale firm power rates from certain costs resulting from provisions of the Northwest Power Act. The rate test can result in a reallocation of costs from the 7(b)(2) Customers to other rate classes. The Section 7(b)(2) Rate Test Study describes the application and results of the Section 7(b)(2) Implementation Methodology.
The Section 7(b)(2) rate test triggers in this proposal, causing costs to be reallocated in the test period. The PF Preference rate applied to the general requirements of the 7(b)(2) Customers has been partially reduced by the 7(b)(2) amount. Other rates, including the PF Exchange Program rate applied to customers purchasing under the REP and the IP rate to be charged to any DSI taking direct service from BPA during the rate period, have been increased by an allocation of the 7(b)(2) amount. Because, after allocation of the 7(b)(2) amount, there are no REP loads, no power sales to IOUs, and no direct power sales to DSIs, remaining 7(b)(2) amount costs were allocated to the PF Preference rate. This is required by Section 7(a)(1) of the Northwest Power Act, which provides that BPA's power rates must recover BPA's power costs.
V. 2007 Wholesale Power Rate Schedules and General Rate Schedule Provisions (GRSPs)
BPA's proposed 2007 Wholesale Power Rate Schedules and GRSPs are available for viewing and downloading on PBL's Web site at www.bpa.gov/power/ratecase. A copy of the proposed rate schedules and GRSPs are also available for viewing in BPA's Public Reference Room at the BPA Headquarters, 1st Floor, 905 NE 11th Avenue, Portland, OR.Start Signature
Issued this 26th day of October, 2005.
Stephen J. Wright,
Administrator and Chief Executive Officer.
1. Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Pubic Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities Reg-Preamble, FERC Stats & Regs 1991-96, para. 31,036 (1996).Back to Citation
2. Open Access Same-Time Information System (formerly Real-Time Information Networks) and Standards of Conduct, Reg-Preamble, FERC Stats & Regs 1991-96, para. 31,035 (1996).Back to Citation
3. 92.6% TPP for a three-year rate period is equivalent to BPA's TPP standard of 95% applied to a two-year rate period. Two years were assumed to be the length of rate periods when the TPP standard was set.Back to Citation
[FR Doc. 05-22233 Filed 11-7-05; 8:45 am]
BILLING CODE 6450-01-P