[Federal Register Volume 68, Number 49 (Thursday, March 13, 2003)]
[Notices]
[Pages 12048-12055]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 03-6091]


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DEPARTMENT OF ENERGY

Bonneville Power Administration

[BPA File No: SN-03]


Bonneville Power Administration's Proposed Safety-Net Cost 
Recovery Adjustment Clause Adjustment to 2002 Wholesale Power Rates

AGENCY: Bonneville Power Administration, Department of Energy.

ACTION: Notice of proposed safety-net cost recovery adjustment clause: 
public hearing, and opportunity for public review and comment.

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SUMMARY: 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. [para] 
61,360 (2001).

[[Page 12049]]


DATES: Proposed hearing dates are supplied in SUPPLEMENTARY 
INFORMATION, Section I.A. below.
    The period for public comment period closes on May 1, 2003.

ADDRESSES: Written comments should be submitted to: Bonneville Power 
Administration, P.O. Box 12999, Portland, Oregon 97212. Comments can 
also be sent electronically to: [email protected]. 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.

FOR FURTHER INFORMATION CONTACT: Interested persons may call Cynthia 
Jones at (503) 230-5459 or Cain Bloomer at (503) 230-7443.

SUPPLEMENTARY INFORMATION:

Table of Contents

Part I: Introduction and Procedural Background
    A. Relevant Statutory Provisions Governing This Rate Proceeding
    B. Background
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
    A. Introduction
    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.

B. Background

    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

[[Page 12050]]

summer 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 [para] 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

[[Page 12051]]

costs 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 [para]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

[[Page 12052]]

and 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

[[Page 12053]]

will 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

A. Introduction

    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);

[[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.

                                 Table A
                          [Dollars in millions]
------------------------------------------------------------------------
                                                               Maximum
                                                               Planned
                                                  SN CRAC      Recovery
              End of fiscal year                 threshold      Amount
                                                   (ANR)      (Beginning
                                                               October)
------------------------------------------------------------------------
2003..........................................        $-400         $470
2004..........................................         -140          470
2005..........................................            5          470
------------------------------------------------------------------------

    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 =
Revenue Amount
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.

[[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:
    [sbull] BPA forecasts a 50 percent or greater probability that it 
will nonetheless miss a payment to the U.S. Treasury or other creditor, 
or
    [sbull] 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.

    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