Bonneville Power Administration, Department of Energy.
Notice of proposed safety-net cost recovery adjustment clause: public hearing, and opportunity for public review and comment.
The Pacific Northwest Electric Power Planning and Conservation Act (Northwest Power Act), 16 U.S.C. 839, provides that the Bonneville Power Administration (BPA) must establish and periodically review and revise its rates 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.
On February 7, 2003, the BPA Administrator determined that the Safety-Net Cost Recovery Adjustment Clause (SN CRAC) triggered based upon a forecast of a 50 percent or greater chance of missing a payment to the U.S. Treasury or another creditor during this fiscal year. The triggering of the SN CRAC initiates an expedited hearing under section 7(i) of the Northwest Power Act, 16 U.S.C. 839e(a)(1). By this notice, BPA announces a proposed SN CRAC adjustment to BPA's Wholesale Power Rates for FY 2002-2006, which the Federal Energy Regulatory Commission (FERC) approved on an interim basis on September 28, 2001. U. S. Department of Energy—Bonneville Power Admin., 96 F.E.R.C. ¶ 61,360 (2001).Start Printed Page 12049
Proposed hearing dates are supplied in SUPPLEMENTARY INFORMATION, Section I.A. below.
The period for public comment period closes on May 1, 2003.
Written comments should be submitted to: Bonneville Power Administration, P.O. Box 12999, Portland, Oregon 97212. Comments can also be sent electronically to: firstname.lastname@example.org. The documents will be available for public viewing after March 31, 2003. The documents are available at: http://www.bpa.gov/power/psp/rates/RateCases/sn03/, or in BPA's Public Information Center, BPA Headquarters Building, 1st Floor; 905 NE. 11th, Portland, Oregon, and will be provided to parties at the prehearing conference to be held on March 31, 2003, from 9 a.m. to 12 p.m., Room 223, 911 NE. 11th, Portland, Oregon. Mr. Byron G. Keep, Power Products, Pricing and Rates Manager, is the official responsible for the development of BPA's power rates.Start Further Info
FOR FURTHER INFORMATION CONTACT:
Interested persons may call Cynthia Jones at (503) 230-5459 or Cain Bloomer at (503) 230-7443.End Further Info End Preamble Start Supplemental Information
Table of Contents
Part I: Introduction and Procedural Background
A. Relevant Statutory Provisions Governing This Rate Proceeding
Part II: Purpose and Scope of Proceeding
A. Purpose of Proceeding
B. Scope of Proceeding
1. Other Proceedings
a. Power Business Line WP-02 Rate Case
b. Transmission Business Line TR-04 Rate Proceeding
2. Financial Choices and Spending Levels
3. Fish and Wildlife Costs and Hydro Operations
C. National Environmental Policy Act
Part III: Public Participation
A. Distinguishing Between “Participants” and “Parties”
B. Developing the Record
Part IV: BPA's Proposed Solution to the Cost Recovery Problem
B. Safety-Net Cost Recovery Adjustment Clause Design
C. BPA's Proposal
D. Summary of Supporting Study
Part V: The Amended 2002 GRSPs
Part I—Introduction and Procedural Background
A. Relevant Statutory Provisions Governing This Rate Proceeding
Guidance regarding BPA ratemaking is provided by 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.
BPA's rates must be established to recover BPA's costs. In particular, section 7(a)(1), 16 U.S.C. 839e(a)(1), provides in part that:
[s]uch rates shall be established and, as appropriate, revised to recover, in accordance with sound business principles, the costs associated with the acquisition, conservation, and transmission of electric power, including the amortization of the Federal investment in the Federal Columbia River Power System (including irrigation costs required to be repaid out of power revenues) over a reasonable period of years and the other costs and expenses incurred by the Administrator pursuant to this Act and other provisions of law.
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 notice of the proposed rates in the Federal Register; one or more hearings conducted as expeditiously as practicable by a Hearing Officer; public opportunity for both oral presentation and written submission of views, data, questions, and argument related to the proposed rates; cross-examination; and a decision by the Administrator based on the record. This proceeding is governed by section 1010.9 of BPA's Procedures Governing Bonneville Power Administration Rate Hearings, 51 FR 7611 (1986) (Procedures). The Procedures implement the statutory section 7(i) requirements. Section 1010.7 of the Procedures prohibits ex parte communications. Special rules governing the rate proceeding may also be adopted at the prehearing conference. Documents will be filed and served electronically under procedures to be established by the Hearing Officer at the prehearing conference.
BPA's proposed SN CRAC adjustment is published in Part V. below. The study addressing the factors used to develop the SN CRAC adjustment is summarized in Part IV.
BPA will release its 2003 initial SN CRAC rate proposal on March 31, 2003, and expects to publish a final Record of Decision (ROD) on June 30, 2003. BPA will conduct a formal evidentiary rate hearing for parties. Entities interested in becoming parties to this proceeding must file petitions to intervene in order to participate in the formal hearing. (See Part III. for further details on becoming a party.) A proposed schedule for the formal hearing is set forth below. A final schedule will be established by the Hearing Officer at the prehearing conference.
Prehearing/BPA Direct Case: March 31.
Clarification: April 2.
Motions to Strike: April 4.
Data Request Deadline: April 4.
Answers to Motions to Strike: April 10.
Data Response Deadline: April 10.
Field Hearing: April 16.
Parties file Direct Cases: April 17.
Clarification: April 21.
Motions to Strike: April 22.
Data Request Deadline: April 22.
Answers to Motions to Strike: April 28.
Data Response Deadline: April 28.
Close of Participant Comments: May 1.
Litigants file Rebuttal: May 2.
Clarification: May 5.
Motions to Strike: May 7.
Data Request Deadline: May 7.
Answers to Motions to Strike: May 13.
Data Response Deadline: May 13.
Cross-Examination: May 15-16.
Initial Briefs Filed: May 20.
Oral Argument: May 23.
Draft ROD issued: June 12.
Briefs on Exceptions: June 17.
Final ROD—Final Studies: June 30.
BPA will conduct a public field hearing on April 16, 2003, in Portland, Oregon. The public field hearing will provide 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 of the field hearing. The field hearing is scheduled to begin at 6 p.m. Confirmation of this hearing date and the specific location will be announced on BPA's Web site at: http://www.bpa.gov/power/psp/rates/RateCases/sn03/index.shtml and through public advertising, or interested persons may call the telephone numbers listed in above the FOR FURTHER INFORMATION CONTACT section of this Notice.
In May 2000, BPA completed its analysis and final proposal for FY 2002-2006 rates. On July 6, 2000, pursuant to section 7(a)(2) of the Northwest Power Act, 16 U.S.C. section 839e(a)(2), BPA's Power Business Line (PBL) filed its proposed wholesale power rates with the Federal Energy Regulatory Commission (FERC). On August 4, 2000, BPA filed a motion with FERC requesting that FERC stay the proceeding for 30 days. After requesting the stay, BPA reviewed the impact of the unexpected price increases in the wholesale power markets on the West Coast and their effect on PBL's power rate proposal.
BPA concluded that, in light of the unprecedented price spikes during the Start Printed Page 12050summer of 2000, PBL's proposed cost-based rates for FY 2002-2006 would be far more attractive to customers than market alternatives, and, in fact, public utility customers requested purchase contracts for significantly more power than forecasted in the BPA's May 2000 final rate proposal. This resulted in total load obligations of about 3,200 aMW more than the existing system could supply.
After a public comment period, BPA notified rate case parties on October 6, 2000, that it intended to initiate a limited 7(i) proceeding to address increased load obligations and high market prices. On December 1, 2000, BPA announced its proposed amendments to the 2002 wholesale power rate adjustment proposal. Proposed Amendments to 2002 Wholesale Power Rate Adjustment Proposal, 65 FR 75272 (2000) (Amended Proposal). BPA filed an Amended Proposal rather than formally modifying the original rate proposal for two main reasons. First, rates needed to be in place by October 2001 and there was no assurance a full rate proceeding could have been conducted within the time remaining. Second, the Treasury payment analysis showed that secondary revenues, even with very conservative assumptions relative to the actual forward market, would very likely cover any cost overruns.
After BPA released its Amended Proposal, the forecast for starting rate period reserves dropped substantially. In addition, market prices rose significantly from BPA's December 2000 forecast. These rapid developments necessitated significant changes to the Amended Proposal. BPA began settlement discussions with rate case parties to attempt to forge a resolution to the matter. When BPA and many of the rate case parties reached a Partial Settlement Agreement, BPA filed a Supplemental Proposal reflecting the terms of the Partial Settlement Agreement. The Partial Settlement Agreement included three separate Cost Recovery Adjustment Clauses, allowing the adoption of a general approach to keep base rates low and deal with financial shortfalls though the CRACs rather than raise base rates. These tools gave BPA the risk mitigation necessary to have a sufficiently high Treasury Payment Probability (TPP). The three CRACs are the Load-Based (LB) CRAC which is designed to cover augmentation costs, the Financial-Based (FB) CRAC which is designed to cover net revenue, and the Safety-Net (SN) CRAC which is available if the likelihood of missing a Treasury payment or payment to any other creditor is 50 percent or greater despite the implementation of the LB and FB CRACs. On September 28, 2001, FERC granted interim approval of BPA's rate filing, U.S. Department of Energy—Bonneville Power Admin., 96 FERC ¶ 61,360 (2001).
The forecasts included in the Supplemental Rate Proposal, and reflected in the TPP forecast, included two sources of revenue that would cover expense increases. The first revenue source was secondary sales from high market prices. Market prices were forecast to stay high through 2003 because the development of electrical infrastructure was expected to take up to two years of development to catch up with the high demand that BPA and the west coast was experiencing. Therefore, the initial two years of the rate period were expected to be supply-limited. The second revenue source was also tied to these high market prices. Credits toward BPA's Treasury payments based on fish-related costs (fish credits) and impacts on operations were expected to contribute significantly to total revenues through high market prices. These fish credits contribute to BPA's overall revenues through a credit against BPA's payment to the U.S. Treasury. When market prices are higher, the size of the credit available to BPA may increase. BPA's June 2001 forecasts for secondary energy prices and available credits during the rate period proved to be inaccurate when market prices dropped faster and to lower levels than forecasted. This resulted in lower-than-forecasted revenues for BPA in fiscal year 2002. Hydro production during FY 2002-2003 also has been well below forecasts. The lingering effects of the 2001 drought on FY 2002 and the poor hydro conditions in 2003 have contributed to the significant decline in BPA's revenues. Although the hydro conditions appeared to be about normal over the January-July 2002 period, BPA stored a significant amount of water to replenish the low reservoirs resulting from the 2001 drought. This need for storage resulted in less 2002 hydro production than was forecast.
In addition, both operating and non-operating cost increases, relative to the levels assumed in the rates that BPA filed with FERC, have contributed to BPA's eroding financial condition. These increases include: BPA internal operating costs; hydro system costs; Federal debt service, net interest expense and depreciation; Columbia Generating Station costs; Direct Service Industries, California Independent System Operator and California Power Exchange bad debt expenses; conservation costs; and an increase in benefits to residential and small farm customers of investor-owned utilities.
Faced with a deterioration of its overall financial condition, BPA sent a letter to rate case parties and other interested entities in the region on July 2, 2002, announcing the beginning of the Financial Choices public comment process. The Financial Choices process examined a variety of financial and program options for addressing PBL's FY 2003-2006 financial challenges. In this process, BPA described those financial challenges, the actions BPA already had taken to address the problem, and the financial outlook for the remainder of the rate period. Additionally, BPA identified a variety of potential financial alternatives that, separately or in combination, could form the basis of a solution to PBL's financial situation.
During the course of the process, BPA held ten public meetings and workshops with customers, public interest groups, tribes, and other interested persons to explain the nature of the problem, and to show program level costs and the potential effects of cost reductions. BPA also solicited suggestions to address its growing financial problem. The public comment period closed on September 30, 2002. As a result of the Financial Choices process, BPA made decisions to cut, eliminate, or defer certain costs and expenses. BPA issued a Financial Choices close-out letter to the region on November 22, 2002, outlining BPA's plan, in part, for meeting the PBL's financial challenges. The plan takes into consideration extensive public input BPA received during the Financial Choices public process. The actions BPA has taken, and will take, as described in the Financial Choices close-out letter, include the identification of $350 million in expense savings, expense deferrals, and other actions for the FY 2003-2006 period. These will be reflected in the program levels in BPA's Initial Proposal. An additional $500 million of other potential savings and deferrals are being pursued, but are uncertain since they largely involve actions by other parties in the region.
While BPA did not trigger the SN CRAC in November, by January 2003, worsening water conditions and a refined secondary revenue forecast increased the net revenue gap for the 2002-2006 rate period to $950 million. In February 2003, the Administrator determined that BPA had lower than a 50 percent probability of making its Treasury payment in September 2003. An SN CRAC adjustment became necessary to ensure that rates and revenues will be sufficient to recover Start Printed Page 12051costs with a high degree of certainty over the remainder of the rate period.
Part II—Purpose and Scope of Proceeding
A. Purpose of Proceeding
Triggering SN CRAC starts an expedited section 7(i) hearing to establish changes in the amount, duration, and timing parameters of the FB CRAC, taking into account prevailing conditions. On February 7, 2003, the BPA Administrator determined that the SN CRAC triggered based upon a forecast of a 50 percent or greater chance of missing a payment to the U.S. Treasury or another creditor during this fiscal year.
B. Scope of Proceeding
1. Other Proceedings
a. Power Business Line WP-02 Rate Case. On July 6, 2000, BPA filed proposed wholesale power rate adjustments with FERC as noticed in the Federal Register. 16 U.S.C. 839e(a)(2). Proposed Amendments to 2002 Wholesale Power Rate Adjustment Proposal, 65 FR 75272 (2000). BPA supplemented its rate filing with FERC on June 29, 2001. The supplementation of the rate filing included three CRAC risk mitigation tools. On September 28, 2001, FERC granted interim approval to BPA's rates filing. U.S. Department of Energy—Bonneville Power Admin., 96 FERC ¶61,360 (2001).
Pursuant to section 1010.3(f) of BPA's 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 visit the appropriateness or reasonableness of BPA's decisions in the WP-02 rate hearing. These decisions include but are not limited to issues related to the Slice methodology and contract issues including the Slice audit.
b. Transmission Business Line TR-04 Rate Proceeding. On December 20, 2002, BPA's Transmission Business Line (TBL) published a Federal Register Notice announcing the initiation of a rate-setting process for the FY 2004-2005 period. TBL's Initial Proposal reflected a settlement reached between BPA and its transmission customers. The Initial Proposal contains certain assumptions regarding TBL's revenues and expenses over the rate period. Some of these assumptions have been used in developing aspects of the SN-03 proposal and are identified in the supporting documentation. BPA does not intend to revisit the underlying basis for TBL's assumptions. Pursuant to section 1010.3(f) of BPA's 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 visit the appropriateness or reasonableness of BPA's decisions in the TR-04 rate hearing.
2. Financial Choices and Spending Levels
The Financial Choices process allowed extensive review and comment on PBL's costs.
In addition, the decisions made in the Financial Choices process implemented prudent cost management to enhance TPP while minimizing rate impacts. These decisions are reflected in assumptions regarding program spending levels in the SN-03 Initial Proposal. BPA does not intend to revisit in this proceeding the decisions made during the Financial Choices process, including decisions on program spending levels.
Pursuant to section 1010.3(f) of BPA's 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 visit the appropriateness or reasonableness of BPA's decisions and other decisions made in Financial Choices on spending levels, as included in PBL's test period revenue requirement for FY 2003-2006. If, and to the extent, any re-examination of spending levels is necessary, that re-examination will occur outside of the rate case. Excepted from this direction on account of their variable nature, dependency on PBL's rate case models, 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) inter-business line expenses.
3. Fish and Wildlife Costs and Hydro Operations
In BPA's WP-02 Wholesale Power Rate Case, potential fish and wildlife costs were reflected probabilistically, based on 13 system configuration alternatives arrived at during the development of the Fish and Wildlife Funding Principles (Revenue Requirement Study Documentation, Volume 1, WP-02-FS-BPA-02A, Chapter 13). These alternatives were developed specifically to inform and guide PBL's Subscription Process and power rate-setting, keeping options open because those processes would be concluded prior to decisions being made on system reconfiguration to aid threatened and endangered salmon.
In December 2000, the National Marine Fisheries Service (NOAA Fisheries) issued a Biological Opinion on the operation and configuration of the FCRPS addressing threatened and endangered salmon. Also in December 2000, the U.S. Fish and Wildlife Service (FWS) issued a Biological Opinion on the operation and configuration of the FCRPS addressing Endangered Species Act listed sturgeon and bull trout. Implementation of the NOAA Fisheries Biological Opinion requires the Action Agencies (Corps of Engineers, Bureau of Reclamation, and BPA) to issue annual implementation plans and five-year prospective implementation plans as well as regular annual progress reporting on the success of the Action Agencies' implementation actions. On November 6, 2002, BPA, the Corps of Engineers, and the Bureau of Reclamation released the Final FY 2003-2007 Implementation Plan for the FCRPS. The Implementation Plan identifies and describes the specific measures that the three agencies plan to implement in FY 2003-FY2007 and addresses the actions called for in the NOAA Fisheries and FWS 2000 Biological Opinions for the FCRPS. The Implementation Plan forms the basis for fish-related hydro-operations assumptions and spending level assumptions in the Initial Proposal.
BPA is currently engaged in regional discussions regarding fish-related changes to hydro operations, which are being evaluated in a regional forum. The Northwest Power Planning and Conservation Council (Council) is evaluating these proposed changes in its mainstem rulemaking proceedings. Upon receipt of the Council's final recommendations, the Action Agencies, in coordination with NOAA Fisheries and FWS, may decide to implement changes to measures as outlined in the Action Agencies Implementation Plan. The proposed changes are included in the analysis used to prepare BPA's Initial Proposal. To the extent other decisions are made in these proceedings by the time BPA's Final ROD is prepared, those decisions will be included in the Final ROD.
BPA's fish and wildlife program spending levels are developed to implement not only the Action Agencies' Implementation Plan, but also a set of operational, habitat, harvest, and hatchery measures to protect, mitigate, and enhance non-ESA listed species affected by the FCRPS. When BPA initiated Financial Choices, fish and wildlife spending levels were presented Start Printed Page 12052and comments were taken. Those spending levels, including expenses and capital, are reflected in the SN-03 Initial Proposal, but are currently under review by the Council. If BPA changes those levels based on recommendations by the Council prior to writing the Final Record of Decision (ROD), those changes will be reflected in the Final ROD.
Pursuant to section 1010.3(f) of BPA's 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 in any way to revisit the policy merits or wisdom of implementation of the Biological Opinion, or the related operations, assumptions, and program spending level forecasts included in BPA's rate proposal, as discussed above. The Implementation Plan and any subsequent modifications were and are developed through extensive public involvement and comment processes, and have been and will be adopted as policy pursuant to those separate processes.
C. National Environmental Policy Act
BPA is in the process of assessing the potential environmental effects of this proposed rate adjustment, consistent with the requirements of the National Environmental Policy Act (NEPA) and its implementing regulations. In its Business Plan Final Environmental Impact Statement, DOE/EIS-0183, June 1995 (Business Plan EIS), BPA evaluated the environmental impacts of a range of business structure alternatives that included, among other things, various combinations of power pricing and rate designs for BPA's power rates. In addition, the Business Plan EIS identifies various response strategies, such as raising firm power rates, that could be implemented to address revenue shortfalls. 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 is the alternative that best allows BPA to: (1) Recover costs through rates; (2) achieve strategic business objectives; (3) competitively market BPA's products and services; and (4) continue to meet BPA's legal mandates.
An initial review of this proposed rate adjustment indicates that it is consistent with these aspects of the Market-Driven Alternative. This rate proposal would result in rate levels similar to those resulting from the rate designs evaluated in the Business Plan EIS, and thus would not be expected to result in significantly different environmental impacts from those examined for the Market-Driven Alternative in the Business Plan EIS. Furthermore, implementation of this rate proposal would be consistent with the response strategy of raising firm power rates to generate necessary revenues that was identified for all alternatives in the Business Plan EIS and Business Plan ROD. Therefore, BPA expects that this rate proposal will fall within the scope of the Market-Driven Alternative that was evaluated in the Final Business Plan EIS and adopted in the Business Plan ROD, and that BPA thus may tier its decision under NEPA for the proposed rate adjustment to the Business Plan ROD.
Part III—Public Participation
A. Distinguishing Between “Participants” and “Parties”
BPA distinguishes between “participants in” and “parties to” the hearings. Apart from the formal hearing process, BPA will receive comments, views, opinions, and information from “participants,” who are defined in the BPA 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 part of the official record and considered by the Administrator. 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.
Written comments by participants will be included in the record if they are received by May 1, 2003. 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 the address listed in Section I. of this Notice. In addition, BPA will hold a field hearing in Portland, Oregon on April 16, 2003. Participants may appear at the field hearing and present oral testimony. The transcripts of these hearings will be a 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. 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 Officer by 9 a.m. on March 26, 2003. The petitions should be directed to: Maya R. Ferry, Hearing Clerk—LP, Bonneville Power Administration, 905 N.E. 11th Ave., P.O. Box 12999, Portland, Oregon 97212.
Petitioners must explain their interests in sufficient detail to permit the Hearing Officer to determine whether they have a relevant interest in the hearing. Pursuant to Rule 1010.1(d) of BPA's Procedures, BPA waives the requirement in Rule 1010.4(d) that an opposition to an intervention petition be filed and served 4 days before the prehearing conference. Any opposition to an intervention petition instead may 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. Opposition to an untimely petition to intervene shall be filed and received by BPA within two days after service of the petition.
B. Developing the Record
The record will include, among other things, 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. The Hearing Officer then will review the record, will supplement it if necessary, and will certify the record to the Administrator for decision. Given the need for the SN CRAC adjustment to be in place by October 1, 2003, the Administrator directs the Hearing Officer to conclude the hearing process no later than July 10, 2003 so as to allow BPA sufficient time to comply with 18 CFR part 300.
The Administrator will develop final proposed rates based on the entire record, including the record certified by the Hearing Officer, comments received from participants, other material and information submitted to or developed by the Administrator, and any other comments received during the rate development process. 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's Procedures. The Administrator Start Printed Page 12053will serve copies of the Final ROD on all parties. At the conclusion of the rate proceeding, BPA will file the SN-03 rate proposal with FERC for confirmation and approval.
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 notice of meetings involving rate case issues for participation by all rate case parties. Parties should be aware, however, that such meetings may be held on very short notice and they should be prepared to devote the necessary resources to participate fully in every aspect of the rate proceeding. Consequently, parties should be prepared to attend meetings every day during the course of the rate case.
Part IV—BPA's Proposed Solution to the Cost Recovery Problem
As noted earlier, the Administrator determined that in spite of the significant cost cutting identified in the Financial Choices process, BPA has less than a 50 percent probability of meeting its Treasury payment obligations. On February 7, 2003, the Administrator sent a letter to rate case parties and other interested individuals explaining the continued deterioration of BPA's financial situation and announcing the triggering of the SN CRAC process.
BPA is proposing a three-year variable SN CRAC adjustment to power rates, which has a cap limiting the amount of revenues that can be collected each year. Under BPA's proposal, in August of each year, the level of SN CRAC for the next fiscal year will be determined, based on the then-current forecast of PBL's accumulated net revenues (ANR) for the end of the then-current fiscal year. The annual average expected value for the SN CRAC is about 30 percent above May 2000 base rates. The adjustment in a particular year could be as high as 41 percent or as low as zero, depending on PBL's financial condition as reflected in BPA's forecasted ANR.
These percentages do not reflect the overall rate increase customers can expect after the implementation of PBL's proposed SN CRAC because of the interaction among the three CRACs. The total power rate customers will pay will reflect changes to the LB and FB CRACs and the proposed SN CRAC. While it will vary, the resulting total rate is expected to be about 16 percent, on average, above FY2003 rates (which include LB and FB CRACs) for the remainder of the rate period.
B. Safety-Net Cost Recovery Adjustment Clause Design
BPA's SN CRAC proposal uses a Treasury payment probability measure different from that used in prior rate cases. BPA is concerned that a rate increase of the magnitude necessary to achieve the 80-88 percent five-year TPP standard used to establish the WP-02 rates is not sustainable in the current economy. Therefore, BPA is proposing to relax the standard, but at the same time provide sufficient assurance that by the end of the rate period BPA will have a high probability of making its payment to the U.S. Treasury. This assurance will be met in part by an additional criterion that the PBL expected net revenues for the entire rate period (FY 2002-2006) will be zero or greater. For the next general rate proceeding, BPA intends to return to its long-term goal of 88 percent TPP.
In January 1993, BPA adopted a 10-Year Financial Plan that included a TPP standard for use in setting BPA's rates. At that time, BPA typically had two-year rate periods and the TPP standard called for achieving a 95 percent probability that BPA would make all of its Treasury payments in that rate period on time and in full. BPA's 1996 rates were set to cover a five-year period, and in that process, the 95 percent probability was translated into an 88 percent five-year TPP that provided comparable assurance of timely repayment. The Fish and Wildlife Funding Principles guided the development of power rates for the FY 2002-2006 rate period. In the Fish and Wildlife Funding Principles, the standard for that five-year TPP was allowed to be in the range of 80 to 88 percent in light of the economic burden that achieving the full 88 percent TPP would impose on the Pacific Northwest region.
Specifically for the SN CRAC proceeding, BPA is proposing to use three payment probability criteria in lieu of the long-term goal, mentioned above, including the net revenue criterion. BPA does not intend to replace the 88 percent standard, but is proposing these three alternative standards in this SN-03 process in order to meet the twin goals of moving toward a financially healthier BPA while limiting the effect on a fragile economy. The first criterion is a 50 percent probability that BPA can make all of its Treasury payments in the FY 2004-2006 three year period. This is relaxed from 87.5 percent, which is the three-year probability that corresponds to 80 percent for a five-year period. The second standard, a Treasury Recovery Probability (TRP), requires that the calculated probability that BPA will be able to make all of its FY 2006 payments to the U.S. Treasury, including repayment of any amounts missed in years FY 2003-2005, is at least 80 percent. The third standard requires that net revenues over the FY 2002-2006 period are zero or greater. These criteria provide a high level of assurance that BPA's obligations to the U.S. Treasury will be satisfied by the end of FY 2006.
C. BPA's Proposal
The proposed SN CRAC design is similar to the existing FB CRAC as described in the 2002 GRSPs. The proposed SN CRAC is a temporary, upward adjustment to posted power rates based on the level of end-of-year ANR in the generation function, as defined in the section on the FB CRAC in the 2002 GRSPs. The August forecast of ANR or each fiscal year from 2003-2005 is compared to the SN CRAC threshold applicable to that fiscal year. If the forecasted ANR is below the threshold, an SN CRAC rate adjustment will be implemented to collect either the amount of the difference between the forecasted ANR and the threshold, or an annual cap, whichever is smaller. The proposed SN CRAC rate adjustment will be determined annually, go into effect on October 1 of each year, and be in effect for the remainder of that fiscal year. The adjustment will be applied to the appropriate rates for the 12-month fiscal year.
The ANR threshold levels for the remaining three years of the rate period are: $-400 million for FY 2004, $−140 million for FY 2005, and $5 million for 2006. The annual cap is $470 million.
Consistent with the 2002 GRSPs, the SN CRAC applies to power customers under the following firm power rate schedules:
1. PF Preference (PF excluding Slice), PF Exchange Program, and PF Exchange Subscription;
2. Industrial Firm Power (IP-02), including purchases under the Industrial Firm Power Targeted Adjustment Charge (IPTAC) and Cost-Based Index Rate;
3. Residential Load (RL-02), including both actual power deliveries and the monetary benefits of any Residential Exchange Program (REP) Settlement;
4. New Resource Firm Power (NR-02); and
5. Subscription purchases under Firm Power Products and Services (FPS).
The SN CRAC does not apply to:
1. Pre-Subscription Contracts (to the extent prohibited by contract); Start Printed Page 12054
2. Seasonal and Irrigation Mitigation Contracts; or
3. Slice Purchases.
D. Summary of Supporting Study
There will be one study with seven chapters supporting BPA's SN CRAC proposal. Chapter 1 describes PBL's financial conditions and an overview of BPA's SN CRAC proposal. Chapter 2 describes the methodology for PBL's loads and sales forecasts. It also includes the assumptions used in the development of the hydro regulation study and other resources. Chapter 3 contains BPA's generation revenue requirement including a forecast of generation expenses. Chapter 4 describes the analysis that quantifies PBL's net revenue risk. Chapter 5 describes the methodology and resulting forecast of PBL's secondary revenues. Chapter 6 contains PBL's revenue forecast at current and proposed rates, and chapter 7 describes the Tool Kit model, the SN CRAC proposed design and the associated GRSPs.
Part V—The Amended 2002 GRSPs
Safety-Net Cost Recovery Adjustment Clause (SN CRAC)
The SN CRAC applies to power purchases under the following firm power rate schedules: PF [Preference (excluding Slice), Exchange Program and Exchange Subscription]; Industrial Firm Power (IP-02), including purchases under the Industrial Firm Power Targeted Adjustment Charge (IPTAC) and Cost-Based Index Rate; Residential Load (RL-02) (including both actual power deliveries and the 900 aMW of monetary benefits under the financial portion of any REP Settlement, buy-downs and load reduction agreements); New Resource Firm Power (NR-02); and subscription purchases under Firm Power Products and Services (FPS). The SN CRAC does not apply to power purchases under Pre-Subscription contracts to the extent prohibited by such contracts, to BPA's current contractual obligations for Seasonal and Irrigation Mitigation sales including for any eligible customer that converts from Slice to another BPA product, or to purchases under the PF Slice Rate.
A. Formula for Calculation of the Safety-Net Cost Recovery Adjustment Clause
By August of each fiscal year (FY 2003-2005) immediately prior to each fiscal year of the remainder of the rate period (i.e., FY 2004-2006), a forecast of that end-of-year Accumulated Net Revenue (ANR) will be completed. BPA will compare the forecasted ANR to the SN CRAC Threshold applicable to that year to determine the SN CRAC to be implemented. If the ANR at the end of the forecast year falls below the SN CRAC Threshold applicable to that fiscal year, an SN CRAC rate adjustment will be implemented. That SN CRAC rate adjustment will go into effect beginning in October of the upcoming fiscal year (FY 2004-2006).
The Revenue Amount will be determined by the following formula:
Revenue Amount is the lower of:
SN CRAC Threshold minus forecasted ANR; or
The annual Maximum Planned Recovery Amount, shown in Table A below.
Where Revenue Amount is the amount of additional revenue that an adjustment in rates under SN CRAC is intended to generate during the one year period that the rate adjustment is effective.
Where SN CRAC Threshold is the ANR level below which a rate adjustment is determined. The thresholds specified for the end of FY 2003, 2004, and 2005 are shown in Table A.
Where ANR is generation function net revenues, as accumulated since 1999, at the end of each of the fiscal years 2003-2005. The forecast of ANR through the end of each fiscal year will be calculated and used to determine if the threshold has been reached and the Revenue Amount needed. Net revenues for any given fiscal year are accrued revenues less accrued expenses, in accordance with Generally Accepted Accounting Principles, with the following two exceptions. First, for purposes of determining if the SN CRAC threshold has been reached, actual and forecasted expenses will include BPA expenses associated with Energy Northwest debt service as forecasted in the WP-02 Final Studies. Second, the impact of adopting Financial Accounting Standard 133, Accounting for Derivative Instruments and Hedging Activities, will not be considered in determining if the SN CRAC threshold has been reached. Only generation function actual and forecasted revenues and expenses that are associated with the production, acquisition, marketing, and conservation of electric power, will be included in determinations under the SN CRAC. Accrued revenues and expenses of the transmission function are excluded. Impacts of forecasted revenues, positive or negative, from contractual true-up pursuant to the Slice Agreement shall be included in the revenue forecast when determining the SN CRAC.
Where Maximum Planned Recovery Amount is the maximum annual amount planned to be recovered through the SN CRAC.
|End of fiscal year||SN CRAC threshold (ANR)||Maximum Planned Recovery Amount (Beginning October)|
Once the Revenue Amount is determined, that amount will be converted to the SN CRAC Percentage. The SN CRAC Percentage is the percentage adjustment in customers' rates (not including LB CRAC or FB CRAC) in each of the firm power rate schedules listed above. This percentage will be applied to generate the additional SN CRAC revenue.
The SN CRAC Percentage will be determined by the following formula:
SN CRAC Percentage =
Divided by SN CRAC Revenue Basis
SN CRAC Revenue Basis is the total generation revenue (not including LB CRAC or FB CRAC) for the loads subject to SN CRAC for the fiscal year in which the SN CRAC implementation begins, based on the then most current revenue forecast. Each non-Slice product's total charge for energy, demand, and load variance will be adjusted by this CRAC percentage amount.
Payment under the SN CRAC rate adjustment will be due monthly from November (for the October billing period) through October of the following year.
In August prior to the beginning of each fiscal year of the rate period (FY 2004-2006), the Administrator will compare the ANR forecast at the end of that current fiscal year to that year SN CRAC Threshold. The customers will be billed in accordance with the SN CRAC adjustment.
Each customer will be notified, on or about September 1st, of the percentage adjustment in rates due to the SN CRAC. The rates used to calculate the customers' bills for the following October through September for FY 2004-2006, will reflect the SN CRAC adjustment. Start Printed Page 12055
B. Retriggering of the SN CRAC
The SN CRAC will be retriggered if the Administrator determines that, after implementation of the FB CRAC, the currently active SN CRAC, and any forecast of Augmentation True-Ups, either of the following conditions exists:
- BPA forecasts a 50 percent or greater probability that it will nonetheless miss a payment to the U.S. Treasury or other creditor, or
- BPA has missed a payment to the U.S. Treasury or has satisfied its obligation to the U.S. Treasury but has missed a payment to any other creditor.
A retriggering of the SN CRAC will result in an upward adjustment to posted power rates listed above by modifying the SN CRAC parameters that are currently in use. BPA will propose changes to the SN CRAC parameters that will, to the extent market and other risk factors allow, achieve a high probability that the remainder of Treasury payments during the FY 2002-2006 rate period will be made in full. BPA's proposal could include changes to the Revenue Amount, the Cap, the Threshold, the duration (the length of time the SN CRAC would be in place, which could be more than one year), and the timing of collection. The additional revenue to be generated by the SN CRAC will be collected through a percentage adjustment in applicable rates and a commensurate decrease in the financial portion of the Residential Exchange Settlement. In addition to the revenue generated by the SN CRAC, BPA's payments for IOU load reductions will be reduced in accordance with contractual provisions.
a. SN CRAC Notification Process. At the time the Administrator determines that the SN CRAC has retriggered, BPA will send written notification of the determination to customers that purchase power under rates subject to the SN CRAC and to interested parties. Such notification shall include the documentation used by BPA to determine that the SN CRAC has retriggered, the amount of any forecast shortfall, and the time and location of a workshop on the SN CRAC.
The purpose of the SN CRAC workshop will be to discuss with customers and interested parties the cause of the shortfall, and any proposed changes to the SN CRAC that will achieve a high probability that the remainder of Treasury payments during the FY 2002-2006 rate period will be made on time. In determining which proposal to include in its initial proposal in the SN CRAC Section 7(i) proceeding, BPA will give priority to prudent cost management and other options that enhance Treasury Payment Probability while minimizing changes to the SN CRAC.
b. SN CRAC Hearing Process. As soon as practicable after a determination that the SN CRAC has retriggered, BPA will publish a Federal Register Notice initiating an expedited hearing process to be conducted in accordance with Section 7(i) of the Northwest Power Act. The hearing shall be completed within 40 days, unless a different duration is agreed to by BPA and the parties. Upon completion of such hearing, BPA will submit the following documentation to FERC in support of a request for review and confirmation: Statements A through F from the 2002-2006 BPA Wholesale Power Rate Adjustment Proceedings, Separate Accounting Analyses, current and revised revenue tests, the proposed revisions to the SN CRAC parameters and the administrative record compiled by BPA in the SN CRAC proceeding.
The changes to the SN CRAC parameters shall take effect 60 days from filing with FERC unless FERC orders otherwise prior to that time.Start Signature
Issued in Portland, Oregon, on March 6, 2003.
Stephen J. Wright,
Administrator and Chief Executive Officer, Bonneville Power Administration.
[FR Doc. 03-6091 Filed 3-12-03; 8:45 am]
BILLING CODE 6450-01-P