[Federal Register Volume 65, Number 232 (Friday, December 1, 2000)]
[Notices]
[Pages 75272-75284]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-30682]


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DEPARTMENT OF ENERGY

Bonneville Power Administration


Bonneville Power Administration's Proposed Amendments to 2002 
Wholesale Power Rate Adjustment Proposal

AGENCY: Bonneville Power Administration, DOE.

ACTION: Notice of proposed amendments to 2002 wholesale power rate 
adjustment proposal: public hearing, and opportunity for public review 
and comment proposal BPA File No: WP-02.

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SUMMARY: The Pacific Northwest Electric Power Planning and Conservation 
Act (Northwest Power Act) provides that Bonneville Power Administration 
(BPA) must establish and periodically review its rates so that they are 
adequate to recover, in accordance with sound business principles, the 
costs associated with the acquisition, conservation, and transmission 
of electric power, and to recover the Federal investment in the Federal 
Columbia River Power System (FCRPS) and other costs incurred by BPA. By 
this notice, BPA announces a proposed amendment to the 2002 rate 
proposal (BPA Docket WP-02), consideration of which has been stayed by 
Federal Energy Regulatory Commission (FERC) in Docket No. EF00-2012-
000. The 2002 rates replace the current 1996 rates, which expire on 
October 1, 2001, at the same time that most of BPA's current power 
supply contracts terminate.

DATES: Proposed hearing dates are supplied in the Supplementary 
Information Section I.C. below. Close of public comments is February 
14, 2001.

ADDRESSES: Written comments should be submitted to: Mr. Michael Hansen, 
Public Involvement and Information Specialist, Bonneville Power 
Administration, P.O. Box 12999, Portland, Oregon 97212. Documents will 
be available for public viewing after December 12, 2000, at 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 December 12, 2000, from 9 a.m. to 
12 p.m., Room 223, 911 NE.

[[Page 75273]]

11th, Portland, Oregon. The documents will also be available on BPA's 
web site at www.bpa.gov/power/ratecase. Mr. Barney Keep, Acting Power 
Manager, Power Products, Pricing and Rates, is the official responsible 
for the development of BPA's rates.

FOR FURTHER INFORMATION CONTACT: Interested persons may call (503) 230-
4328 or call toll-free 1-800-622-4519.

SUPPLEMENTARY INFORMATION:

Table of Contents

Part I: Introduction and Procedural Background
    A. Relevant Statutory Provisions Governing This Rate Proceeding
    B. Background
    C. Proposed Schedule Concerning This Rate Proceeding
Part II: Purpose and Scope of Hearing
    A. Procedural Background
    Scope of Proceeding
    Previous Limitations on Scope
Part III: BPA's Proposed Solution to Cost Recovery Problem
    A. The Subscription Strategy
    B. Status of Subscription Contracts
    C. Proposed Modifications to Cost Recovery Adjustment Clause 
(CRAC)
    D. CRAC Redesign
    1. Load-Based CRAC (LB CRAC)
    2. Financial-Based CRAC (FB CRAC)
    3. Safety-Net CRAC (SN CRAC)
    E. Other Issues
    1. Slice
    2. IOU Settlement
    3. Early Signers
    4. Changes to DDC Timing
    5. The National Environmental Policy Act
Part IV: Public Participation
    A. Distinguishing Between ``Participants'' and ``Parties''
    B. Developing the Record
Part V: The Amended 2002 GRSPs
    A. Introduction
    B. Summary of 2002 Wholesale Power Rate Schedules, 2002 GRSPs, 
and New 1996 GRSPs

Part I--Introduction and Procedural Background

A. Relevant Statutory Provisions Governing This Rate Proceeding

    Section 7 of the Northwest Power Act, 16 U.S.C. 839e, contains a 
number of general directives that the BPA Administrator must consider 
in establishing rates for the sale of electric energy and capacity. 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.

    Rates established by BPA are effective on an interim or final basis 
when approved by FERC. 16 U.S.C. 839e(a)(2). Similar rate directives 
may also be found in the Bonneville Project Act, 16 U.S.C. 832 et seq., 
the Federal Columbia River Transmission System Act, 16 U.S.C. 838 et 
seq., and the Flood Control Act of 1944, 16 U.S.C. 825 et seq.
    Section 7(i) of the Northwest Power Act, 16 U.S.C. 839e(i), 
requires that BPA's rates be set according to procedures which include:
     Issuance of a Federal Register notice announcing the 
proposed rates;
     One or more hearings;
     The opportunity to submit written views, supporting 
information, questions, or arguments; and
     A decision by the Administrator based on the record 
developed during the hearing process.
    This notice is intended to advise parties that BPA will be 
conducting additional hearings in WP-02 for the purpose of amending the 
proposal currently before FERC. This proceeding will be governed by 
BPA's ``Procedures Governing Bonneville Power Administration Rate 
Hearings,'' 51 FR 7611 (March 5, 1986). Special rules governing the 
proceeding may also be adopted at the prehearing conference.

B. Background

    On August 13, 1999, BPA filed a notice in the Federal Register, 64 
FR 44318 (1999), proposing new wholesale power rates to be effective on 
October 1, 2001. BPA's initial rate proposal, along with written 
testimony and studies, was filed on August 26, 1999. Parties to the 
proceeding filed their direct testimony on November 2, 1999. On 
December 17, 1999, litigants filed rebuttal to the Parties' direct 
cases. The Parties also filed prehearing briefs on December 17, 1999. 
Cross-examination began on January 24, 2000. Parties submitted initial 
briefs on February 28, 2000. Oral argument before the BPA Administrator 
was held on March 2, 2000.
    A Draft Record of Decision (ROD) was published on April 10, 2000. 
Parties filed briefs on exceptions on April 24, 2000. BPA published its 
Final ROD on May 15, 2000. BPA then filed its proposed rates with the 
FERC on July 6, 2000. BPA requested approval of the rates and General 
Rate Schedule Provisions (GRSPs) effective October 1, 2001, through 
September 30, 2006.\1\ BPA requested interim approval of its proposed 
rates by September 15, 2000, and final approval by January 19, 2001. On 
July 17, 2000, FERC issued notice of BPA's rate filings. See U.S. 
Department of Energy, Bonneville Power Admin., 65 FR 44041. In the 
notice FERC established Docket No. EF00-2012-000 to review BPA's 
proposed rates. On August 7, 2000, BPA requested a 30-day stay of 
proceedings at FERC. On September 4, 2000, BPA filed an additional 
motion with FERC requesting a stay of the proceedings through April 30, 
2001.
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    \1\ BPA also requested approval of the methodology used to 
calculate the rate for the Slice product sold under the Priority 
Firm (PF) rate schedule for a period from October 1, 2001, to 
September 30, 2011.
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C. Proposed Schedule Concerning This Rate Proceeding

    BPA will release its proposed 2002 amendments on December 12, 2000, 
and expects to publish a final Record of Decision by June 2001. The 
following proposed schedule is provided for informational purposes. A 
final schedule will be established by the Hearing Officer at the 
prehearing conference on December 12, 2000.

December 18: Clarification.
January 3: Motions to Strike.
January 5: Data Request Deadline.
January 10: Answers to Motions to Strike.
January 12: Data Response Deadline.
February 1: Parties File Direct Case.
February 8: Clarification.
February 16: Motions to Strike.
February 14: Close of Participant Comments.
February 20: Data Request Deadline.
February 23: Answers to Motions to Strike.
February 27: Data Response Deadline.
March 6: Litigants File Rebuttal.
March 14: Clarification.
March 19: Motions to Strike.
March 19: Data Request Deadline.
March 26: Answers to Strike.
March 26: Data Response Deadline.
April 4-6: Cross-Examination.
April 16: Initial Briefs Filed.
April 26: Oral Argument.
May 25: Draft ROD issued.
June 5: Briefs on Exception.
June 20: Final ROD--Final Studies.

Part II--Purpose and Scope of Hearing

    BPA's proposed amendments are necessary because market prices are 
expected to be much higher and more volatile than assumed in the 2002 
rate proposal. BPA's cost-based rates are now further below market 
price expectations for the FY 2002-2006 rate period. As a result of 
high market prices, BPA now expects much greater demand for service 
from customers, demand that BPA is required to serve and that exceeds 
the generating capability of the FCRPS. To meet this

[[Page 75274]]

increased load obligation, BPA will need to make substantially greater 
power purchases in the market at substantially higher and more 
uncertain prices than anticipated in revenue requirements for the 2002 
rate proposal. An adjustment to BPA's 2002 proposal is, therefore, 
necessary to ensure rates and revenue will be sufficient to recover the 
costs with a high degree of certainty.
    BPA's proposal deals with this cost recovery problem by amending 
certain risk mitigation tools contained in the 2002 General Rate 
Schedule Provisions (GRSPs), which apply to the base rates. BPA views 
this approach as a reliable and prudent means of assuring cost recovery 
while maintaining the basic underpinnings of BPA's Subscription 
Strategy for marketing power in the coming rate period. This hearing 
provides Parties and Participants an opportunity to respond to BPA's 
proposal.

A. Procedural Background

    On July 6, 2000, BPA submitted for filing to FERC the proposed rate 
adjustments for its wholesale power rates pursuant to section 7(a)(2) 
of the Northwest Power Act. 16 U.S.C. 839e(a)(2). On August 4, 2000, 
BPA filed a motion with FERC requesting that FERC stay for 30 days any 
determination regarding the adequacy of the rate filing. The motion was 
granted. Thereafter, BPA reviewed events during the summer months which 
indicated that power markets on the West Coast had become more volatile 
than previously anticipated.
    BPA concluded that, in light of the unprecedented price spikes 
during the summer months, BPA's cost-based rates for 2002-2006 would be 
far more attractive to prospective customers than market alternatives. 
As a result, preference customers could be expected to purchase 
significantly more power than originally anticipated. Due to higher 
market prices, there was both an increase in demand and higher 
augmentation purchases than previously expected. During the initial 
phase of the rate case, BPA's load forecast exceeded BPA's forecast of 
generation resources by 1,732 average megawatts (aMW). BPA now expects 
loads will exceed the original rate case forecast by an additional 
1,522 aMW. Moreover, the difficulty of forecasting the expense of 
serving the increased load obligations is magnified by the fact that 
prices are escalating in an extraordinarily volatile market.
    The combination of an unanticipated increase in loads with higher 
and more uncertain market prices greatly diminishes the probability 
that the rates proposed in the initial phase will fully recover 
generation function costs. Absent a change to proposed rates, Treasury 
Payment Probability (TPP) is significantly reduced. By law, BPA's 
payments to Treasury are the lowest priority of revenue application, 
meaning that such payments are the first to be missed if reserves are 
insufficient to pay all bills on time. For this reason, BPA expresses 
its cost recovery goal in terms of probability of being able to make 
Treasury payments on time. A TPP that is too low reflects an 
unacceptable degree of financial risk for BPA and the Treasury.
    The increased load obligations that BPA will be meeting through 
market purchases in a currently escalating and volatile market 
environment have decreased TPP to just such an unacceptable level. BPA 
is implementing the Fish and Wildlife Principles (Principles) in this 
rate proposal. Among other provisions, the Principles call for a TPP 
goal of 88 percent, and an acceptable range of 80 to 88 percent for the 
5-year, 2002-2006 rate period. The rates and risk mitigation tools were 
initially developed to achieve the TPP goal of 88 percent in full. 
After the rates were filed at FERC, increases and uncertainty 
surrounding augmentation purchase costs drove the TPP estimate to well 
below 70 percent.
    To remedy the cost recovery problems so that TPP fell within the 
acceptable range, BPA began in early August to explore its options. On 
August 1, 2000, BPA suspended the signing of any new power contracts 
with customers and initiated a separate public process to examine the 
problem and explore potential solutions. On August 3, 2000, BPA wrote a 
letter to rate case parties and other interested entities in the 
region, outlining two possible options for dealing with the problem. 
The first option entailed modifying a five-year rate lock provision in 
BPA's power contracts, to give BPA the ability to reset rates if 
necessary after September 30, 2003. The second option involved 
modifying the 2002 rate filing to address the problem. The letter 
requested written comment regarding the proposed options or any other 
ideas the parties had for addressing the problem.\2\ In addition, BPA 
set August 9, 2000, for a technical discussion of the issues facing BPA 
and August 21, 2000, for a public meeting to discuss the range of 
options.
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    \2\ BPA initially asked for all written comment by August 24, 
2000, but during the August 21, 2000, meeting, extended the time for 
customers to provide any comments while settlement discussions 
occurred. In her October 6, 2000, letter to customers, the 
Administrator requested all comments be sent to BPA by October 16, 
2000.
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    BPA received over 60 written comments in response to the August 3 
letter. On August 31, 2000, after the public meeting, BPA wrote a 
second letter to rate case and other interested parties. After 
consideration of all the comments and BPA's own internal analysis, a 
decision was made to explore some specific rate adjustments to deal 
with the cost recovery problem, rather than proposing modifications to 
the contract. BPA concluded that it could maintain an acceptable TPP 
level by revising the CRAC contained in the proposed 2002 GRSPs and by 
making some corresponding changes to the Slice methodology.
    BPA set aside the following weeks to engage the rate case parties 
in settlement discussions aimed at resolving the cost recovery problem 
in a mutually agreeable way. These discussions centered on four major 
issues presented by the option proposed by BPA:
    1. How should the CRAC be redesigned to provide BPA with the 
necessary financial protection?
    2. How should the Slice product be modified to insure that Slice 
customers pay an equitable share of BPA's augmentation costs?
    3. What changes, if any, are necessary to the proposed settlement 
of the IOUs Residential Exchange benefits, as a consequence of the 
revision to the CRAC?
    4. How would the proposed changes to the CRAC impact customers who 
had already signed contracts?
    BPA notified FERC on September 4, 2000, of its decision to pursue 
modifications to the CRAC and requested that the stay be extended 
through April 30, 2001, so that settlement discussions could be 
continued and a limited 7(i) proceeding could be conducted. During the 
month of September, BPA and rate case parties engaged in a series of 
meetings to discuss ways of resolving the four major issues described 
above. Despite this effort, the parties were unable to reach a 
consensus.
    On October 6, 2000, BPA notified rate case parties that it intended 
to initiate a limited 7(i) proceeding to revise the CRAC; make 
adjustments to the Slice methodology; adjust the Residential Exchange 
Settlement; and address the Subscription contracts signed earlier this 
summer in order to deal with the issues facing BPA. The Administrator

[[Page 75275]]

set the close of business on October 16, 2000, as the start of ex 
parte.\3\
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    \3\ On the effective date, ex parte communications regarding the 
merits of this proposal with any BPA or DOE employee are prohibited.
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B. Scope of Proceeding

    This additional hearing will address the problems created by 
increased purchase power costs created due to increased loads resulting 
from higher prices in a volatile market environment. In this second 
phase of the 2002 rate case, the Administrator will not open issues 
previously determined to be outside the scope of the first phase of the 
rate case, as described in the original 1999 Federal Register notice 
\4\ and in the phase one WP-02 ROD. BPA's proposal to amend the risk 
mitigation tools, rather than revise the base rates, does not require 
that BPA reexamine in this proceeding every issue that was debated and 
decided in the earlier phase of this proceeding. Many of those issues 
are not germane to the cost recovery problem that this amended 
proceeding has been initiated to address.
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    \4\ The details of the elements that were excluded from the 
earlier proceeding are described in detail at 64 FR 44318-44323 
(Aug. 13, 1999).
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    Therefore, the scope of this second phase of the proceeding is 
limited only by those guidelines the Administrator established during 
the first phase of this proceeding, a summary which is described below, 
and the parameters of the specific problem that is being addressed in 
this phase of the proceeding.

C. Previous Limitations on Scope

    On August 13, 1999, pursuant to Rule 1010.3(f) of BPA's Procedures, 
the Hearings Officer was directed to exclude from the record any 
evidence or arguments related to five specific areas.
    The first area of exclusion concerns the Cost Review 
recommendations and BPA's planned implementation of those 
recommendations which received extensive public review. This rate 
proceeding will not revisit the methodology used to develop the Cost 
Review recommendations, the policy merits or wisdom of the specific 
recommendations, or BPA's implementation plans.
    The second area of exclusion concerns decisions made in the 
Subscription Strategy. The Administrator directs the Hearing Officer to 
exclude from the record any material attempted to be submitted or 
arguments attempted to be made in the hearing which seek to in any way 
revisit decisions that were made in BPA's Subscription Strategy, 
including both the ROD and Supplemental ROD for the Strategy.
    The third area of exclusion concerns decisions made in the context 
of the Fish and Wildlife Funding Principles. The Administrator directs 
the Hearing Officer to exclude from the record any material attempted 
to be submitted or arguments attempted to be made in the hearing which 
seek to in any way revisit the policy merits or wisdom of the strategy 
to ``keep the options open'' or of the Fish and Wildlife Funding 
Principles.
    The fourth area of exclusion concerns transmission issues not part 
of the rate case or included in the settlement agreement reached in 
BPA's transmission rate case.
    The fifth area of exclusion concerns adjustments to the PF-96 
Rate.\5\

    \5\ FERC granted final approval of TACUL on October 26, 2000, in 
docket EF00-2013-000. 93 FERC para. 62,062 (2000).

    For this second phase of the proceeding, the Administrator again 
directs the Hearings 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 address the five areas noted above. 
Also, the Targeted Adjustment Charge, for Uncommitted Loads has been 
approved on a final basis by FERC in Docket No. EF00-2013-000. 
Therefore, the Administrator directs the Hearing Officer to exclude 
from the record any material attempted to be submitted or arguments 
attempted to make which seek to change the outcome of that 
proceeding or which would have such an effect.

Part III--BPA's Proposed Solution to Cost Recovery Problem

    To address cost recovery issues caused by the additional load and 
escalating market, BPA is proposing changes to the CRAC and some 
corresponding modifications to the Slice methodology. This solution 
provides sufficient assurance of cost recovery while achieving other 
goals, as outlined below.

A. The Subscription Strategy

    The WP-02 rate proposal was designed to implement the decisions 
made in BPA's Subscription Strategy. The Subscription Strategy was the 
result of a lengthy public process that began with the Comprehensive 
Regional Review. The Subscription Strategy was fundamentally a 
blueprint for how BPA should go about filling the void that would be 
left after the vast majority of its contracts expire in 2001. The 
Strategy provided a structure around which BPA could offer new 
contracts and meet its statutory obligations while responding to the 
myriad of changes that had occurred since enactment of the Northwest 
Power Act.
    Some of these changes were due to deregulation of the wholesale 
power market that began in the 1990s. These changes forced BPA to 
become more competitive and to unbundle its power products consistent 
with the open access to transmission and the more competitive climate 
in the wholesale power markets. The Subscription Strategy also mapped 
out a general plan for how the benefits of the FCRPS would be 
distributed in this new climate, consistent with the requirements and 
obligations created by the Northwest Power Act. In part, this meant 
attempting to strike a delicate balance between a wide range of 
competing interests, including customer groups, governmental entities, 
tribal representatives, and public interest groups.
    In sum, the Subscription Strategy reflected the varied and complex 
interests in the Pacific Northwest and laid the groundwork for an 
equitable distribution of the benefits of the FCRPS consistent with 
legal requirements. The four principal goals of the Subscription 
Strategy are:
     Promote the spread of the benefits of the FCRPS as broadly 
as possible, with special attention given to the residential and rural 
customers of the region.
     Avoid rate increases through a creative and businesslike 
response to markets and additional aggressive cost reductions.
     Fulfill BPA's fish and wildlife obligations while assuring 
a high level of Treasury payment.
     Provide market incentives for the valuation of 
conservation and renewable resources.
    Of course, the primary purpose of this proceeding is to determine 
how to deal effectively with the cost recovery risk associated with 
higher and more uncertain purchase power costs. This increased 
uncertainty is being caused by expected increases in rising prices in a 
volatile market and resultant increases in load obligations. However, 
this phase of the proceeding begins, as did the initial phase, with the 
basic assumption that a solution to the problem should, as much as 
possible, be designed to preserve the basic principles underlying the 
Subscription Strategy. That basic framework has been developed over a 
period of several years, reflects a wide range of public processes, and 
is predicated on the input of all regional interests and stakeholders. 
It continues to provide reasonable direction and structure for the 
rights and corresponding obligations that have

[[Page 75276]]

been embodied in contracts for service beginning October 1, 2001.

B. Status of Subscription Contracts

    All of BPA's regional customers have signed either a Subscription 
contract or a settlement agreement prior to the October 31, 2000, 
contract-signing deadline.\6\ The Subscription contracts translated the 
Subscription Strategy into product offerings and formalized the 
proposed distribution of power and benefits developed through the 
Subscription Strategy. The proposed WP-02 rates establish the price for 
those contracts. The contracts were offered to customers and all of 
BPA's regional customers have already signed, indicating their 
commitment to subscribing for power during the next rate period. BPA's 
proposal to amend the WP-02 rate filing through adjustments to the CRAC 
will preserve the proposed WP-02 rates, except for the few specific 
changes noted below.
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    \6\ BPA offered its IOU customers a Settlement Agreement as an 
alternative to the benefits under the standard Residential Power 
Sales Agreement (RPSA). Customers who did sign contracts prior to 
the close of the signing window may still do so but they will be 
subject to the Targeted Adjustment Clause (TAC).
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C. Proposed Modifications to Cost Recovery Adjustment Clause (CRAC)

    The proposed three-stage CRAC, described in detail below, addresses 
the cost recovery uncertainty caused by the unanticipated developments 
in the market. In the Subscription Strategy, BPA stated that a CRAC was 
an integral part of BPA's risk mitigation package in the development of 
its power rates. Subscription Strategy, at 14. The CRAC proposed, and 
eventually adopted in the ROD, was an adjustment to posted rates for 
all net firm power load requirements customers. Id. BPA's final 
proposal contained a CRAC that, when combined with Planned Net Revenues 
for Risk (PNRR) and other risk mitigation tools, produced a TPP that 
met BPA's stated objectives.
    The CRAC was designed to trigger when BPA's accumulated net 
revenues were reduced to below certain threshold levels. If the 
accumulated net revenues fell below these established thresholds, a 
financial adjustment would be made to the base rates. The amount of the 
annual adjustment was capped at preestablished levels. The values used 
for the initial proposal had the accumulated net revenue equivalents of 
reserve thresholds of $300 million in FY 2001-2002 and $500 million in 
FY 2003-2005. The proposal also provided that if BPA's accumulated net 
revenues are reduced to below the threshold levels, the annual cap for 
the rate adjustment for FY 2001 was $125 million, FY 2002 was $135 
million, FY 2003-2004 was $150 million, and FY 2005 was $87.5 million.
    In the first phase of the proceeding, BPA forecasted a need to 
augment its system with market purchases to meet its obligations. 
However, the existing rate proposal contemplated a lesser amount of 
augmentation purchases in a far less volatile market. Because the 
difference between BPA's rates and the market prices has increased 
dramatically, BPA's customers are not diversifying their sources of 
power as anticipated. Therefore customers have placed a greater portion 
of their load on BPA and BPA expects that the price BPA will pay for 
the power needed to serve that additional load will be higher than 
originally forecast.
    To be specific, in the rates now before FERC BPA assumed it would 
need to augment the system by 1,732 aMW at a price of $28.10/
megawatthour (MWh) for the power, while current estimates have BPA 
augmenting the system by 3254 aMW (an additional 1,522 aMW) at a market 
price in excess of $40.00/MW. As a consequence of these interrelated 
factors, the assumptions used in the original rate filing no longer 
adequately account for the anticipated expenses and financial risks in 
the next rate period. The risks, however, are fundamentally associated 
with three assumptions: market price, market volatility, and resultant 
increase in the load forecast. These three factors can be managed 
effectively and accurately by adjusting the CRAC to achieve a 
sufficient assurance of cost recovery.

D. CRAC Redesign

    In its earlier ROD, BPA proposed a single CRAC that triggered upon 
accumulated net revenues (ANR) dropping to pre-identified levels. The 
amendment now being proposed envisions a three-stage CRAC, with each 
stage designed to deal with a different aspect of the problem. The 
three stages are referred to as the Load-Based CRAC (LB CRAC), 
Financial-Based CRAC (FB CRAC), and Safety-Net CRAC (SN CRAC).
    The LB CRAC is primarily designed to address the problem of loads 
exceeding the forecast from the WP-02 Final Studies. The LB CRAC will 
be based on MW amounts in contracts already signed by customers. As a 
consequence, the load projection used for the LB CRAC will provide a 
very accurate indication of how much load BPA will actually be required 
to serve in the upcoming rate period. Therefore, BPA's risk of 
unforeseen exposure to the market, in terms of the amount of 
augmentation purchases required to serve load, is effectively mitigated 
by the LB CRAC.
    Potential exposure to higher market prices and increased volatility 
as well as other risks, are addressed by the FB CRAC. The uncertainties 
surrounding the current market make it difficult to project, with a 
high degree of certainty, the prices that BPA may be required to pay 
for the power needed to augment the system. The result is that BPA will 
be purchasing in a volatile market to a much greater extent, increasing 
the risk of exposure to higher than projected market prices. The 
proposed FB CRAC makes it possible for BPA to mitigate the risk of 
forecasting error related to market prices. This is accomplished by 
allowing BPA to maintain a stable and sufficient level of financial 
reserves that will enable it to fulfill its load obligations in the 
face of variability and unpredictability in market prices.
    The level of uncertainty presented by the current market volatility 
may under some circumstances cause BPA to forecast a deferral of its 
Treasury payment. The SN CRAC provides BPA with a tool to temporarily 
adjust posted power rates for Subscription sales upward in the event 
that a Treasury deferral will occur despite implementation of the LB 
CRAC and the FB CRAC. The SN CRAC would likely not trigger soon enough 
to avoid an initial deferral, but would help to avoid a second 
deferral.
1. Load-Based CRAC (LB CRAC)
    The LB CRAC is designed to address the problem of recovering the 
costs associated with additional augmentation caused by unanticipated 
load placed on BPA, in large part by high market prices. The LB CRAC 
will be implemented if the actual augmentation for the five-year rate 
period exceeds the amount of augmentation forecasted in the WP-02 Final 
Studies (1,732 aMW). Based upon the signed Subscription contracts, BPA 
will exceed the forecast augmentation amounts contained in the WP-02 
Final Studies by 1,522 aMW. BPA is proposing to impose the LB CRAC 
based on the additional (1,522 aMW) amount of augmentation along with 
that portion of the augmentation forecasted in the May 2000 WP-02 Final 
Studies but not purchased as of August 1, 2000.
    The total amount collected under the LB CRAC will be calculated in 
three different ways depending upon whether the MWs of augmentation 
were forecast in the May 2000 WP-02 Final studies. For the 1,522 aMW of 
augmentation not forecast in the WP-02 the amount of revenue to be 
collected is determined by

[[Page 75277]]

multiplying this additional amount of augmentation by the difference 
between the assumed flat purchase price of $34/megawatthour (MWh) and 
the flat PF rate of $19.26/MWh. For the MWs of augmentation forecasted 
but not purchased by August 1, 2000, the amount of revenue to be 
collected is determined by multiplying those MWs by the difference 
between $34/aMW and $28.1/aMW. There are, however, 46 aMW in the WP-02 
Final Studies that had a forecasted augmentation cost of $23/MWh. These 
MWs will be assessed the difference between $34 and $23. The sum of 
these revenue amounts will then be multiplied by the percentage of Non-
Slice Load to Total Requirements Load, to arrive at the total revenue 
amount to be collected from those customers subject to the LB CRAC. The 
total revenue amount under the LB CRAC will be converted into a 
percentage increase to the base rate for the entire rate period and 
would apply to the total charge for energy, demand, and load variance.
    The LB CRAC applies to power customers under the following firm 
power rate schedules:

    1. PF Preference [(PF excluding Slice), Exchange Program, and 
Exchange Subscription];
    2. Industrial Firm Power (IP-02), including power sold under the 
Industrial Firm Power Targeted Adjustment Charge (IPTAC) and Cost-
Based Index Rate;
    3. Residential Load (RL-02);
    4. New Resource Firm Power (NR-02); and
    5. Subscription purchases under Firm Power Products and Services 
(FPS).
    The LB CRAC does not apply to:
    1. PreSubscription rates;
    2. the financial portion of the Residential Exchange settlement; 
or
    3. Slice purchases.
2. Financial-Based CRAC (FB CRAC)
    The FB CRAC is designed to address the problem presented by market 
prices for augmentation being forecasted to be significantly higher and 
more volatile than what was originally expected. It would also trigger 
in the event that other events, such as low water conditions or WNP 
outages, sufficiently deplete financial reserves. The FB CRAC has a 
similar design to the CRAC in the May 2000 WP-02 Final Studies. It 
entails a temporary, upward adjustment to posted power rates for 
Subscription sales if ANR in the generation function are forecasted to 
fall below preestablished threshold levels. If the ANR at the end of 
any FY 2002-2006 is forecast to fall below the FB CRAC threshold 
applicable to that FY, the FB CRAC triggers, and a cost recovery 
adjustment rate increase will go into effect.
    The FB CRAC applies to power customers under these firm power rate 
schedules:

    1. PF Preference [(PF excluding Slice), Exchange Program, and 
Exchange Subscription];
    2. Industrial Firm Power (IP-02), including under the Industrial 
Firm Power Targeted Adjustment Charge (IPTAC) and Cost-Based Index 
Rate;
    3. Residential Load (RL-02);
    4. New Resource Firm Power (NR-02); and
    5. Subscription purchase under Firm Power Products and Services 
(FPS).
    The FB CRAC does not apply to:
    1. PreSubscription contracts;
    2. the Slice purchases; or
    3. the financial portion of the Residential Exchange Settlement.

    The FB CRAC would be based on a forecast of end-of-year ANR and 
would result in a percentage increase in rates to restore ANR to the 
lower of the threshold level or the maximum amount of the annual cap. 
Unlike the LB CRAC, the FB CRAC would trigger only in those years when 
ANR is forecasted to fall below the threshold and any collection under 
the FB CRAC would occur only in those years when it is triggered. The 
threshold levels and the annual caps for the CRAC in this proposal 
would also differ from those proposed in the WP-02 ROD. The ANR 
threshold levels for the five years of the rate period in 2002 are 
$98M; in 2003 are $41M; and in 2004, 2005 and 2006 are $7M. The annual 
cap is $330M.
    Under BPA's earlier CRAC proposal, BPA's determination of whether 
the threshold level was reached was based upon audited actual financial 
data. This approach was an after-the-fact determination of whether 
BPA's ANR dropped below the threshold levels. Under the FB CRAC, rather 
than basing the determination on audited actual financial data, the 
trigger will be based upon a forecast of ANR. One of the originally 
stated objectives for the CRAC was to achieve cap and threshold levels 
that did not make implementation impractical. Basing the determination 
on a forecast helps to achieve this objective by allowing BPA to 
collect any money due under the FB CRAC sooner. Relying on audited 
actual financial data, as envisioned earlier, would require BPA to have 
a CRAC with a higher threshold and cap levels to maintain the same TPP 
level. Therefore in order to keep the CRAC threshold and cap levels 
lower and more manageable, BPA is proposing to base the FB CRAC on a 
winter forecast of end-of-year ANR.
    A potential problem with basing the FB CRAC trigger of ANR on a 
forecast, rather than audited actual financial data, is the possibility 
of forecasting error. To remedy this possibility, BPA is proposing that 
the forecast be trued-up to actual financial data once it is available. 
Therefore, if BPA over or under collects, an adjustment would be made 
to correct the problem.
    A second difference between the CRAC in the WP-02 ROD and the FB 
CRAC is the manner in which the CRAC amount is collected. The original 
CRAC was designed to be assessed and collected monthly over 12 months, 
based upon the percent of the adjustment. Under this proposal the FB 
CRAC would be assessed and collected in 4 monthly payments rather than 
12. The payments would be assessed beginning in March, and all funds 
would be collected by June 30 of the year. As mentioned above, the 
intent in collecting the funds in a short period of time before June 30 
is to make the FB CRAC thresholds and cap lower and therefore the total 
revenues collected under the FB CRAC lower. Payments to BPA after June 
30 by many public customers become ``net billing'' assets and must be 
made to Energy Northwest under the terms of the bond agreements. BPA 
can achieve lower thresholds and caps and maintain the same TPP level, 
if the amounts due under the FB CRAC are collected before the end of 
June.
3. Safety-Net CRAC (SN CRAC)
    The third stage, or SN CRAC, is designed to trigger when BPA is 
forecasting a 50 percent probability of a missed Treasury payment, or 
there is an actual miss. If, after triggering the LB and FB CRACs, BPA 
is still projecting a Treasury miss, or has actually missed a Treasury 
payment, the SN CRAC would allow BPA to propose an upward adjustment to 
posted power rates for Subscription sales through modification of the 
same parameters used in the FB CRAC. A public process will be conducted 
to determine the extent to which the SN CRAC changes could have an 
amount to be collected, the duration and the timing different from the 
FB CRAC. At the end of the public process the Administrator will make a 
final decision on the SN CRAC. The SN CRAC gives BPA a flexible 
mechanism to deal with a wide scope of potential financial problems, 
even those unrelated to market effects.

E. Other Issues

1. Slice
    The Slice of the System product (Slice) offered as part of BPA's 
Subscription Strategy is exempt from the application of CRAC. Slice is 
exempt from the CRAC because Slice purchasers assume a proportionate

[[Page 75278]]

share of BPA's financial risks and receive a proportionate share of the 
benefits of the Federal system. Slice customers bear financial risk 
through the product design. Under BPA's rate design, certain types of 
risks are mitigated by tools such as PNRR and CRAC. However, Slice 
customers assume the risks PNRR and CRAC are designed to remedy, 
directly through the type of product they purchase. Because Slice 
customers assume the risks directly, neither the original CRAC nor the 
proposed modifications in this proposal apply to the Slice product.
    Slice purchasers pay a percentage of BPA's actual costs in return 
for a percentage of system generation. One of the costs Slice 
purchasers were obligated to assume was a percentage of BPA's 
augmentation expenses. These costs are referred to as the Inventory 
Solution in the Slice contract. To determine the Inventory Solution 
under the Slice contract, BPA calculated the annual average number of 
MWs necessary to augment the system to meet the total Subscription 
load. Under their contract, Slice purchasers were expected to bear 
responsibility for the net cost of the augmentation purchases. The net 
cost of the Inventory Solution was calculated by multiplying the annual 
average amount of augmentation by the difference between the market 
forecast of $28.10/MW for augmentation purchases and the revenue from 
sale of the augmentation power. This Net Inventory Cost solution also 
includes the cost of Conservation Augmentation as well as transmission 
loss underrecovery associated with 1732aMW of augmentation. This net 
amount was added to the Slice purchasers base rate under the WP-02 ROD 
for all five years of the rate period. The Net Cost of the Inventory 
Solution contained in WP-02 is one part of the Net Cost of the 
Inventory Solution contained in this proposal. A second piece of the 
Net Cost of the Inventory Solution is the Net Cost of additional 
augmentation for which the Slice contract provides for a one time MW 
true up to loads. This increment to the Net Cost identified in WP-02 is 
determined in exactly the same manner as was used to determine the Net 
Cost of the Inventory Solution contained in WP-02. When these two Net 
Costs are added, they then form the baseline from which to determine 
how much the Net Cost of the Inventory Solution will change, positive 
or negative, once the assumption of a fixed cost for augmentation of 
$28.10 is removed. However, because the market forecast of $28.10 is 
well below current estimates for the market price for power, relying 
entirely on this mechanism to insure Slice purchasers to pay their pro 
rata share of the augmentation cost will result in a cost shift to non-
slice customers if an adjustment is not made.
    The financial impacts of purchasing the unanticipated augmentation 
in a market where prices are significantly higher and more volatile 
are; not accounted for in the WP-02 ROD. In this rate proceeding, BPA 
is proposing changes to the manner in which the augmentation costs are 
calculated to insure purchasers proportionately share the additional 
financial risk associated with the increased augmentation requirements, 
market prices, and market volatility.
    Under the revised proposal, BPA would calculate its augmentation 
costs based upon a combination of actual purchases and an index of 
market prices. The actual costs of purchases will be calculated after 
the fact on a monthly basis and will be denoted in dollars per percent 
of Slice and then be applied to the Slice purchaser's bill in the next 
month. To calculate the dollar amount, BPA will use the flat annual 
average augmentation of 2,460aMW as the foundation for this 
calculation. The 2,460aMW equals the 3,254aMW flat annual augmentation 
minus augmentation purchases made by August 1, 2000, which are deemed 
to have been purchased at $28.10, and which amount to 794aMW. To 
calculate the Slice purchaser's share of the cost, BPA would use the 
advanced market purchases made by BPA to meet this augmentation 
requirement. To the extent that BPA also relies upon its own generation 
or short-term market purchases to meet the augmentation, those costs or 
avoided costs will also be factored into the charge to Slice 
purchasers. These costs will be priced at the weighted average of the 
50 percent of the firm Dow Jones COB flat price and 50 percent of the 
firm Mid-Columbia flat price for heavy and light load hours. BPA is 
proposing to define the baseline Net Inventory Costs as the sum of the 
Net Inventory Costs included in WP-02 plus the additional Net Inventory 
Costs associated with the increment in augmentation attributable to the 
one time MW true up to loads contain in the Slice contract. Slice 
customers will pay the sum of these Net Inventory Costs in the base 
Slice rate. The second step in the process will be an after the fact 
adjustment to the base Slice rate to reflect the actual costs of the 
augmentation. When the adjustment is greater or less than the Net 
Inventory Costs in the base Slice rate, there will be a debit or credit 
on Slice customer monthly bills.
2. IOU Settlement
    The Residential Exchange Settlements with regional IOUs provide 
benefits in the form of both power and cash. The monetary portion of 
the benefits is calculated based on the difference between the RL or 
PF-Exchange Subscription rate and BPA's rate case market price 
forecast. Originally, BPA adopted $28.10/MW as the rate case market 
forecast for calculation of the monetary benefits. After reconsidering 
the appropriateness of that number, given the escalating and volatile 
market now being experienced, BPA is proposing to calculate the 
financial aspect of the settlements using BPA's $34/MW rate case market 
forecast for the monetary benefits component of the IOU Settlement. In 
addition, the financial aspect of the settlement benefits will be 
exempt from the FB CRAC and LB CRAC.
3. Early Signers
    On August 1, 2000, BPA temporarily suspended the signing of any new 
power contracts, because of the uncertainty created by the projections 
of increased loads and greater market volatility. Prior to that date, 
BPA and a number of its customers had already signed new Subscription 
power contracts for the upcoming rate period that would price power at 
the PF-02 rate. The timing of the contract signing does not, under 
BPA's proposal, provide a sufficient basis to exempt these contracts 
from the application of the three-stage CRAC in this proposal.
4. Change to the DDC Timing
    BPA is proposing two changes to the Dividend Distribution Clause 
(DDC) as it was described in the May 2000 WP-02 Final Proposal. The 
first change is that the DDC would not be available in the first year 
(2002) of the rate period. The second change is that BPA intends to 
conduct the public process by April 1, 2002, rather than by October 
2001, to determine how any distribution will be allocated among 
stakeholders during the rate period. The first $15 million will 
continue to be allocated to qualifying Conservation and Renewable 
purposes.
5. The National Environmental Policy Act
    BPA has assessed the potential environmental effects of this rate 
adjustment, as required by the National Environmental Policy Act 
(NEPA), as part of BPA's Business Plan Environmental Impact Statement 
(EIS). The analysis includes an evaluation of

[[Page 75279]]

the environmental impacts of a range of rate design alternatives for 
BPA's power services and an analysis of the environmental impacts of 
the rate levels resulting from the rates for such services under the 
business structure alternatives. BPA's proposal to adjust the WP-02 
rate filing falls within the range of alternatives evaluated in the 
Final Business Plan EIS. Comments on the Business Plan EIS were 
received outside the formal rate hearing process. The comments have 
been included in the rate case record and will be considered by the 
Administrator in making a final decision amending BPA's revisions to 
the 2002 rate schedules. The Business Plan EIS was completed in June 
1995.

Part IV--Public Participation

A. Distinguishing Between ``Participants'' and ``Parties''

    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 submitted on or before February 14, 2001. Participants' 
written views, supporting information, questions, and arguments should 
be submitted to the address noted in the ADDRESSES section. The second 
category of interest is that of a ``party'' as defined in Rules 1010.2 
and 1010.4 of the BPA Procedures. 51 FR 7611 (1986). Parties who 
intervened in the original phase of this proceeding may participate in 
any aspect of the amended hearing process.
    All written submissions by parties should be directed to:

Anne C. Kunkel, Hearing Clerk--LP-7, Bonneville Power 
Administration, 905 NE. 11th Avenue, P.O. Box 12999, Portland, OR 
97212.

    The address for the Hearing Clerk is different from the BPA contact 
information listed in the ADDRESSES section of this notice given the 
Hearing Clerk is the contact for materials to be submitted to the 
Administrative Law Judge.

B. Developing the Record

    Cross-examination will be scheduled by the Hearing Officer as 
necessary following completion of the filing of all parties' and BPA's 
direct cases, rebuttal testimony, and discovery. Parties will have the 
opportunity to file initial briefs at the close of any cross-
examination. After the close of the hearings, and following submission 
of initial briefs, BPA will issue a Draft ROD that states the 
Administrator's tentative decision(s). Parties may file briefs on 
exceptions, or when all parties have previously agreed, oral argument 
may be substituted for briefs on exceptions. When oral argument has 
been scheduled in lieu of briefs on exceptions, the argument will be 
transcribed and made part of the record. The record will include, among 
other things, the transcripts of any hearings, written material 
submitted by the participants, and evidence accepted into the record by 
the Hearing Officer. The Hearing Officer then will review the record, 
supplement it if necessary, and certify the record to the Administrator 
for decision.
    The Administrator will develop the final adjustments to WP-02 based 
on the entire record, as amended in this proceeding. The basis for the 
final adjustments will be described in the Administrator's Final ROD. 
The Administrator will serve copies of the ROD on all parties and will 
file the final proposed rate correction, together with the record, with 
FERC for confirmation and approval. See generally, 18 CFR Pt. 300.

Part V--The Amended 2002 GRSPs

A. Introduction

    The following section (Part B below) contains BPA's proposed 
amendments to BPA's proposed 2002 GRSPs for power rates.
    The proposed GRSPs were prepared in accordance with BPA's statutory 
authority to develop rates, including the Bonneville Project Act of 
1937, as amended, 16 U.S.C. 832 (1982); the Flood Control Act of 1944, 
16 U.S.C. 825s (1982); the Federal Columbia River Transmission System 
Act (Transmission System Act), 16 U.S.C. 838 (1982); and the Northwest 
Power Act, 16 U.S.C. 839 (1982).
    BPA's 2002 proposed amendments to the GRSPs will supersede BPA's 
1996 rate schedules, except for the FPS-96 rate schedule. The FPS-96 
rate schedule continues in effect as modified in Docket No. FPS-96R. 
BPA proposes that its amended GRSPs become effective upon interim 
approval or upon final confirmation and approval by FERC. BPA currently 
anticipates that it will request FERC approval of its revised GRSPs 
effective October 1, 2001.

B. Summary of 2002 Wholesale Power Rate Schedules, 2002 GRSPs, and New 
1996 GRSPs

BPA'S Amended 2002 General Rate Schedule Provisions for Power Rates

Index of Amendments to the General Rate Schedule Provisions

Section II: Adjustments, Charges, and Special Rate Provisions

F. Cost Recovery Adjustment Clause (CRAC)
    1. Load-Based CRAC (LB CRAC)
    2. Financial-Based CRAC (FB CRAC)
    3. Safety-Net CRAC (SN CRAC)
H. Dividend Distribution Clause (DDC)
J. Five-Year Flat Block Price Forecast for Monetary Benefit Component 
of IOU Settlements
S. Slice True-Up Adjustment
X. Slice Augmentation Cost Adjustment (ACA)

F. Cost Recovery Adjustment Clause (CRAC)

    There are three sets of conditions under which rate increases under 
CRAC may trigger. The first is the Load-Based CRAC (LB CRAC), which 
triggers based on unanticipated augmentation load. The second is the 
Financial-Based CRAC (FB CRAC), which triggers based on the generation 
function's forecasted level of accumulated net revenues. The third is 
the Safety-Net CRAC (SN CRAC), to be implemented if the financial 
situation falls to a point where the first two components are not 
sufficient to avoid missing a Treasury payment.
1. Load-Based CRAC (LB CRAC)
    A LB CRAC is triggered if the final forecasted augmentation load 
for the five-year rate period, based on signed contracts, exceeds the 
amount forecast in the May 2000 WP-02 Final Studies. To the extent the 
five-year PF augmentation load exceeds that forecast, the CRAC amount 
will equal that excess load priced at the difference between an assumed 
flat purchase price of $34/megawatthour (MWh) and the flat PF rate. 
Forty-six (46) average megawatts (aMW) of additional Industrial Firm 
Power (IP) load, resulting from Alcoa's inclusion in the compromise 
approach, will be assessed the difference between $34/MWh and $23/MWh. 
If the LB CRAC triggers, the CRAC amount will also include the cost of 
that portion of augmentation originally forecasted in the May 2000 WP-
02 Final Studies (1732 aMW) which had not been purchased as of August 
1, 2000, priced

[[Page 75280]]

at the difference between $34/MWh and $28.1/MWh.
    The LB CRAC applies to power customers under these firm power rate 
schedules: Priority Firm Power (PF) Preference [(PF excluding Slice), 
Exchange Program, and Exchange Subscription], Industrial Firm Power 
(IP-02), including under the Industrial Firm Power Targeted Adjustment 
Charge (IPTAC) and Cost-Based Index Rate, Residential Load (RL-02), New 
Resource Firm Power (NR-02), and Subscription purchases under Firm 
Power Products and Services (FPS). The CRAC does not apply to Pre-
Subscription rates, the financial portion of the Residential Exchange 
settlement, or Slice purchases.
    a. Formula for Calculation of the LB CRAC. If actual augmentation 
load for which BPA has signed contracts, as determined in the Amended 
WP-02 Final Study, exceeds the amount forecast in the May 2000 WP-02 
Final Studies (five-year average of 1,732 aMW, or 75,861,600 MWh for 
the five-year rate period), the LB CRAC triggers, and a CRAC rate 
increase will go into effect beginning October 2001.
    The LB CRAC will be determined as follows:
    First, the revenue amount will be calculated in three steps, by the 
following formula:
    (1) The revenue amount reflecting the increase in augmentation 
required beyond the amount forecasted in the May 2000 Studies is 
calculated using the following formula:

[($34/MWh minus $19.26/MWh)
    times
(difference between PF augmentation load for the five-year rate 
period, as determined in the Amended WP-02 Final Study, and the 
augmentation load for the five-year rate period as forecasted in the 
May 2000 WP-02 Final Studies)]

    This equals

($14.74/MWh)
    times

(actual augmentation PF load for the five-year rate period, 
currently expected to be 142,525,200 MWhs, or 3,254 aMW per year,)
    minus
75,861,600 MWh).
equals $14.74 times 66,663,600 MWh
equals $982,621,464

    (2) The revenue amount reflecting the increased cost of 
augmentation on the amount forecast in the May 2000 Studies is 
calculated using the following formula:

[($34/MWh minus $28.1/MWh)

    times

(total augmentation load forecast for the five-year rate period in 
May 2000 WP-02 Final Studies minus total augmentation for the five-
year rate period purchased by August 1, 2000)]

    This equals

($5.9/MWh)

    times
(75,861,600 MWh

    minus
34,790,600 MWh)
=$5.9/MWh times 41,071,000 MWh
=$242,318,900

    (3) The revenue amount related to the additional 46 aMW of IP load 
is calculated using the following formula:

[($34/MWh minus $23/MWh)

    times
(46 aMW times 8,760 hours times 5 years)]

    This equals

($11/MWh)

    times 2,014,800 MWh
    equals $22,162,800

    The total Five-Year Revenue Amount is calculated by adding the 
results of calculations 1, 2, and 3.
    Where the Five-Year Revenue Amount is the amount of additional 
revenue that an increase in rates under LB CRAC is intended to generate 
in the rate period.
    Where the actual augmentation load is defined as the Amended WP-02 
Final Study amount of Subscription load for which BPA has signed 
contracts for service, which exceeds BPA's forecasted available firm 
resources.
    The Five-Year Revenue Amount is then multiplied by (Non-Slice Load 
divided by total load subject to LB CRAC plus Slice load) to determine 
the Pro-Rated Five-Year Revenue Amount. Once the Pro-Rated Five-Year 
Revenue Amount is determined, that amount will be converted to the LB 
CRAC Percentage.
    The LB CRAC Percentage will be determined by the following formula:

LB CRAC Percentage =
Pro-Rated Five-Year Revenue Amount
Divided by
LB CRAC Five-Year Revenue Basis

    Where LB CRAC Revenue Basis is the five-year total forecast of 
generation revenue from the loads subject to LB CRAC, for the rate 
period, based on the forecast in the WP-02 Amended Final Proposal.
    The LB CRAC Percentage is the percentage increase in each of the 
firm power rate schedules listed above. This percentage will be applied 
to energy, demand, and load variance charges subject to the LB CRAC to 
generate the additional LB CRAC revenue.
    b. Timing of LB CRAC. The LB CRAC will be assessed in monthly power 
bills beginning with the bill for delivery of power in October 2001, 
and continuing through the bill for delivery of power in September 
2006.
2. Financial-Based CRAC (FB CRAC)
    The FB CRAC is a temporary, upward adjustment to posted power rates 
for non-Slice Subscription sales if end-of-year Accumulated Net 
Revenues (ANR) in the generation function are forecasted to fall below 
a threshold level.
    The FB CRAC applies to power customers under these firm power rate 
schedules: PF Preference [(PF excluding Slice), Exchange Program, and 
Exchange Subscription], Industrial Firm Power (IP-02), including under 
the Industrial Firm Power Targeted Adjustment Charge (IPTAC) and Cost-
Based Index Rate, Residential Load (RL-02), New Resource Firm Power 
(NR-02), and Subscription purchases under Firm Power Products and 
Services (FPS). The CRAC does not apply to Pre-Subscription rates, 
Slice purchases, or the financial portion of any Residential Exchange 
Settlement.
    a. Formula for Calculation of the FB CRAC. By mid-February of each 
FY of the rate period, FY 2002-2006 a forecast of that end-of-year ANR 
will be completed. If the ANR at the end of any the forecast year falls 
below the FB CRAC Threshold applicable to that FY, the FB CRAC 
triggers, and a CRAC rate increase will go into effect beginning the 
following March.
    The Revenue Amount will be determined by the following formula:

Revenue Amount is the lower of:
FB CRAC Threshold minus forecasted ANR;

    or

The annual Maximum Planned Recovery Amount, shown in Table B below, 
multiplied by (loads subject to FB CRAC divided by [loads subject to FB 
CRAC plus Slice load]).
    Where Revenue Amount is the amount of additional revenue that an 
increase in rates under FB CRAC is intended to generate during the 
period that the rate increase is effective;
    Where FB CRAC Threshold is the ``trigger point'' for invoking a 
rate increase under the FB CRAC. The threshold is pre-specified for the 
end of FY 2002, 2003, 2004, 2005, and 2006 in Table B.
    Where ANR is generation function net revenues, as accumulated since 
1999, at the end of each of the FY 2002-2006. Audited Actual 
Accumulated Net Revenues (AANR), confirmed by BPA's independent 
auditing firm, will be used

[[Page 75281]]

for FY 1999, 2000, 2001, and any subsequent year for which they are 
available. Unaudited AANR will be used to the extent audited actuals 
are not available.
    The expected value of a probabilistic forecast of ANR through the 
end of each FY will be calculated and used to determine if the 
threshold has been reached, and what the Revenue Amount is. Net 
revenues for any given FY are accrued revenues less accrued expenses, 
in accordance with Generally Accepted Accounting Practices, with the 
following two exceptions. First, for purposes of determining if the FB 
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 CRAC threshold has been reached. Only generation 
function revenues and expenses, which is to say revenues and forecasted 
expenses that are associated with the production, acquisition, 
marketing, and conservation of electric power, will be included in 
determinations under the FB CRAC. Accrued revenues and expenses of the 
transmission function are excluded.
    Where Maximum Planned Recovery Amount is the maximum annual amount 
planned to be recovered through the FB CRAC. Rate increases under the 
FB CRAC will be due in four equal monthly payments from March through 
June. All revenues will be paid to BPA prior to June 30 preceding the 
end of a FY in which the ANR is forecasted to fall below the FB CRAC 
Threshold.

                                 Table B
------------------------------------------------------------------------
                                                               Maximum
                                                               planned
                                                  FB CRAC      recovery
                  Fiscal year                    threshold      amount
                                                  (ANR,  $    (Beginning
                                                 Millions)    following
                                                                March)
------------------------------------------------------------------------
2002..........................................           98       $330 M
2003..........................................           41        330 M
2004..........................................            7        330 M
2005..........................................            7        330 M
2006..........................................            7        330 M
------------------------------------------------------------------------

    Once the Revenue Amount is determined, that amount will be 
converted to the FB CRAC Percentage. The FB CRAC Percentage is the 
percentage increase in customers' rate (not including LB CRAC) in each 
of the firm power rate schedules listed above. This percentage will be 
applied to generate the additional FB CRAC revenue.
    The FB CRAC Percentage will be determined by the following formula:
    FB CRAC Percentage =

Revenue Amount
Divided by
FB CRAC Revenue Basis

    Where FB CRAC Revenue Basis is the total generation revenue (not 
including LB CRAC) for the loads subject to FB CRAC for the FY in which 
the FB CRAC implementation begins, based on the then most current 
revenue forecast.
    The FB CRAC Percentage is then applied to each customer's 
forecasted bill for that year (not including LB CRAC), to determine the 
customer-specific FB CRAC amount. Each customer's FB CRAC amount is 
then billed to that customer, in four equal amounts, in bills mailed in 
March through June (for February through May billing periods).
    b. FB CRAC Adjustment Timing. In February of each year of the rate 
period, the Administrator will determine whether the expected value of 
the ANR forecast at the end of that current FY is below the FB CRAC 
Threshold. If the ANR is forecasted to fall below the FB CRAC 
Threshold, the Administrator will propose, in February, to assess a 
cost recovery adjustment increase to applicable rates to be billed in 
March. The payment is due to BPA prior to June 30.
    Each customer will be notified, on or about March 1, of the revenue 
amount of FB CRAC they will be billed. Each customer will be sent a 
bill for \1/4\ of the customer's total FB CRAC obligation for that 
year, in each of months March, April, May, and June.
    c. FB CRAC Notification Process. BPA shall follow the following 
notification procedures:
(1) Financial Performance Status Reports
    Each quarter, BPA shall post on its electronic information access 
(World Wide Web) site preliminary, unaudited year-to-date aggregate 
financial results for generation, including ANR.
    By January of each year, BPA shall post on its web site the audited 
AANR attributable to the generation function for the FY ending 
September 30.
    By May, and August of each year, BPA shall post on its web site an 
end-of-year forecast of ANR attributable to the generation function.
(2) Notice of FB CRAC Trigger
    BPA shall complete and adopt a probabilistic forecast of end-of-
year ANR prior to mid-February. BPA shall notify all customers and rate 
case parties prior to mid-February, in each of the FY 2002-2006, if the 
expected value of ANR is forecasted to fall below the FB CRAC Threshold 
for that FY and the extent to which BPA intends to adjust rates under 
the FB CRAC. Notification will include the audited AANR for the prior 
FY, the forecast of end-of-year ANR, the calculation of the Revenue 
Amount, and the FB CRAC Percentage. The notice shall also describe the 
data and assumptions relied upon by BPA, as well as the cost management 
and other risk mitigation steps that BPA has considered and those it is 
taking. Such data, assumptions and documentation, if non-proprietary 
and/or non-privileged, shall be made available for review at BPA upon 
request. The notice shall also contain the tentative schedule for the 
remainder of the FB CRAC implementation process.
    Prior to mid-February of any of the FY 2002-2006 in which the ANR 
is forecasted to fall below the FB CRAC Threshold, BPA staff shall 
conduct a public forum to explain the ANR forecast, the calculation of 
the Revenue Amount and the FB CRAC Percentage, and demonstrate that the 
FB CRAC has been implemented in accordance with the General Rate 
Schedule Provisions (GRSPs). The forum will provide an opportunity for 
public comment.
    On or about March 1 of any of the FY 2002-2006 in which the ANR is 
forecasted to fall below the FB CRAC Threshold, the BPA Administrator 
shall notify all customers to whom the FB CRAC applies of the 
calculation of the adjustment and the resulting rate increase (as a 
percentage) applicable to each rate schedule.
d. True-up
    There will be two opportunities for truing-up the FB CRAC Revenue 
Amount and each customer's portion of it, based on updated data. When 
audited actuals are available, in January in the year subsequent to the 
FB CRAC being implemented, the AANR will be compared to the ANR 
forecast used to implement the FB CRAC. If the forecasted amount is 
within $20 million of the AANR (the tolerance), no true-up will be 
made. If AANR is higher than the forecasted ANR and the difference is 
greater than the tolerance, BPA will provide refunds of all revenues 
collected under the CRAC that are in excess of the amount that would be 
collected using the AANR. Refunds will be in the form of billing 
credits, shown as reductions on February through May bills. However, if 
FB CRAC has again triggered at the time of the true-up, no refund will 
be given. However, the

[[Page 75282]]

Revenue Amount for the new FB CRAC will be reduced by the amount over-
collected through the prior year FB CRAC.
    If AANR is lower than the forecasted ANR, and the difference is 
greater than the tolerance, BPA will collect from customers the 
difference in equal installments in the February through May billing 
period. The total amount collected, however, will not exceed the 
Maximum Planned Recovery Amount.
    BPA also has the option of following the same process to true-up to 
updated forecasts in June of any year the FB CRAC is implemented.
3. Safety-Net CRAC (SN CRAC)
    If the Administrator determines that the financial condition of 
BPA's generation function has deteriorated to such an extent that even 
with the implementation of the FB CRAC:
     BPA forecasts a 50 percent or greater probability that it 
will nonetheless miss its next Treasury payment, or
     BPA has missed a Treasury payment,

this component of the CRAC will be triggered. If the SN CRAC process is 
triggered, BPA will propose an SN CRAC that, to the extent market and 
other risk factors allow, achieves a high probability that the 
remainder of Treasury payments during the rate period will be made 
timely.
    The SN CRAC applies to power customers under these firm power rate 
schedules: PF Preference [(PF excluding Slice), Exchange Program, and 
Exchange Subscription], Industrial Firm Power (IP-02), including under 
the Industrial Firm Power Targeted Adjustment Charge (IPTAC) and Cost-
Based Index Rate, Residential Load (RL-02), New Resource Firm Power 
(NR-02), Subscription purchases under Firm Power Products and Services 
(FPS), and the financial portion of the Residential Exchange 
Settlement. The CRAC does not apply to Pre-Subscription rates or Slice 
purchases.
    The SN CRAC will be an upward adjustment to posted power rates for 
Subscription sales through modification of the same parameters used in 
the FB CRAC. A public process will be conducted to demonstrate the need 
for such an adjustment, and determine the extent to which the SN CRAC 
changes could have an amount to be collected, the duration and the 
timing different from the FB CRAC.
    Where Revenue Amount is the amount of additional revenue that an 
increase in rates under CRAC is intended to generate during the period 
that the rate increase is effective.
    BPA will propose how the Revenue Amount is to be applied to rate 
schedules to produce an increase in customers rates.

SN CRAC Notification Process

    At the time BPA determines that it will not have sufficient funds 
to make its next payment to Treasury on time and in full, even with 
full implementation of the FB CRAC, BPA will send notification of the 
determination to customers and interested parties. BPA will conduct a 
workshop at which it will identify the amount of shortfall, and present 
its proposal to achieve a high probability that the remainder of 
Treasury payments during the rate period will be made timely. The 
proposal will give priority to prudent cost management and other 
options that enhance Treasury Payment Probability (TPP) without raising 
CRAC.
    A public process will be conducted. Any interested person shall be 
provided an adequate opportunity to submit written views, data, 
questions, and arguments, which shall be made a part of the 
administrative record. After close of the public process, the 
Administrator shall make a final decision establishing a CRAC 
adjustment.

H. Dividend Distribution Clause (DDC)

    The DDC is a clause establishing criteria and public process 
requirements that the Administrator will use to decide whether 
dividends should be distributed and the dividend amount that should be 
distributed. The DDC enables BPA to distribute dividends to customers 
and other stakeholders. The DDC also establishes the mechanism to be 
used to make a distribution to certain firm power customers.
    The DDC applies to power customers under these firm power rate 
schedules: PF Preference [(PF excluding Slice), Exchange Program, and 
Exchange Subscription], Industrial Firm Power (IP-02), including under 
the Industrial Firm Power Targeted Adjustment Charge (IPTAC) and Cost-
Based Index Rate, Residential Load (RL-02), New Resource Firm Power 
(NR-02), and Subscription purchases under Firm Power Products and 
Services (FPS). The DDC does not apply to Pre-Subscription rates, Slice 
purchases, or the financial portion of any Residential Exchange 
Settlement under this rate schedule.
    The DDC does not apportion, or establish criteria for apportioning, 
dividends to customers under the above firm power rate schedules or to 
other customers and stakeholders, other than to qualifying power 
customers participating in the Conservation and Renewables Discount 
(C&R Discount).
    ``Stakeholders'' are groups or public purposes that have a 
fundamental policy or financial interest in BPA's generation function. 
These groups include, but are not limited to, customers subject to the 
posted firm power rate schedules cited above.
1. Formula for the Calculation of the Dividend Distribution Amount
    The DDC process will be implemented if audited actual accumulated 
net revenues for the end of any of the FY 2002-2005 are above the DDC 
Threshold value.
    Actual Accumulated Net Revenues (AANR) are generation function net 
revenues, as accumulated since 1999, at the end of each of the FY 2002-
2005. Net revenues are accrued revenues less accrued expenses, in 
accordance with Generally Accepted Accounting Practices, with the 
following two exceptions. For purposes of determining if the DDC 
threshold has been reached, actual and forecasted expenses will include 
BPA expenses associated with Energy Northwest debt service as 
forecasted in the May 2000 WP-02 Final Studies. The impact of adopting 
Financial Accounting Standard 133, Accounting for Derivative 
Instruments and Hedging Activities, will not be considered in 
determining if the CRAC threshold has been reached. Only generation 
function revenues and expenses, which is to say accrued revenues and 
accrued expenses that are associated with the production, acquisition, 
marketing, and conservation of electric power, are included in 
determinations under the DDC; accrued revenues and expenses of the 
transmission function are excluded. The determination of AANR will be 
confirmed by BPA's independent outside auditing firm.
    DDC Threshold is the minimum level of AANR that must be realized 
before a dividend distribution is considered. The DDC Threshold is $388 
million for the end of FY 2002, $331 million for the end of FY 2003, 
and $297 million for the end of FYs 2004, and 2005.
    DDC Amount is the aggregate amount that is available to be 
distributed to customers and stakeholders. The DDC Amount may be equal 
to zero and will be determined by the following formula:

DDC Amount is the lower of:
AANR-DDC Threshold; or
Cash in excess of that needed to meet the TPP Standard, based on the 
Five-Year Forecast.

    Where the TPP Standard is an 88 percent probability that all 
planned payments to the U.S. Treasury will be

[[Page 75283]]

paid on time and in full over the Five-Year Forecast period (or 
equivalent financial criterion in the event that BPA replaces its TPP 
Standard); and
    Where the Five-Year Forecast is the forecast of accrued revenues 
and expenses, and the risk analysis and assessment of TPP or any 
replacement financial criterion, for the current year and subsequent 
four years that the Administrator prepares and subjects to public 
review and comment if the DDC Threshold has been met.
    The portion of the DDC Amount allocated to power customers (the 
Power Customers' DDC Amount) will be determined according to a plan to 
be adopted in a public process BPA will conduct (see section 3 below). 
The Power Customer DDC Amount will be converted to a percentage (the 
Power Customer DDC Percentage), which will be applied to all power 
customer rates subject to the DDC to arrive at the amount to be rebated 
on power bills for each of the included power customers.
    The Power Customer DDC Percentage will be determined by the 
following formula:

Power Customer DDC Percentage equals:
Power Customer DDC Amount
Divided by the DDC Revenue Basis

    Where DDC Revenue Basis is the total generation revenue for the 
loads subject to the DDC for the FY in which the DDC implementation 
begins, based on the then most current revenue forecast.
    Each covered power customer will receive a rebate equal to the 
Power Customer DDC Percentage applied to their total charge for energy, 
demand and load variance. For any customer or stakeholder entitled to a 
dividend who is not a power customer, the Administrator will convert 
the DDC Percentage to a dollar figure.
2. Determination and Timing of a Dividend Distribution
    In January of each year of the rate period (FY 2003-2006), the 
Administrator will determine whether the AANR exceeds the DDC 
Threshold. If the AANR exceeds the DDC Threshold: (a) customers and 
rate case parties will be so notified; and (b) the Administrator will 
prepare a Five-Year Forecast. On or about March 1, the Administrator 
will propose to distribute or not distribute dividends. The 
Administrator will issue a final decision on the proposal on or about 
April 15.
    Dividends distributed to customers are included in energy 
deliveries beginning May 1, and, for any FY 2003-2005, remain in effect 
for 12 months i.e., through April 30 of the following year. In the last 
year of the rate period (FY 2006), the rebate would expire on September 
30, 2006.
3. Determining How the Distribution is Allocated
    The first $15 million of the DDC Amount, if the DDC Amount exceeds 
$15 million, or the entire DDC Amount if it equals $15 million or less, 
will be allocated to qualifying customers' participating in the C&R 
Discount. The C&R Discount is a rate mechanism designed to encourage 
incremental conservation and renewable resource development by BPA's 
power purchasers under PF, IP, RL, and NR rate schedules. See C&R 
Discount GRSPs, Section II.A.
    BPA intends to conduct a separate public consultation process by 
April 1, 2002, to develop the criteria for allocating any remaining DDC 
Amount (exceeding the $15 million for the C&R Discount) among customers 
and stakeholders.)
4. Dividend Distribution Notification Process
    BPA shall follow the following notification procedures:
    a. Financial Performance Status Reports. By no later than August 31 
of each year, BPA shall post on its electronic information access site 
(World Wide Web) a forecast of AANR attributable to the generation 
function for the FY ending September 30.
    b. Notice of DDC Trigger. On or about January 15 in each of the FY 
2003-2006, BPA will notify all power customers and rate case parties if 
the AANR exceeds the DDC Threshold. (If the December unaudited AANR 
report for the generation function indicated that the DDC Threshold 
might be exceeded, and the audited actuals show that it was not 
exceeded, customers will also be notified). Notification will include 
the AANR for the prior FY, the DDC Amount, the calculation of the DDC 
Amount, and the estimated resulting Power Customer DDC Percentage for 
each applicable rate schedule. The notice shall also describe the data 
and assumptions relied upon by BPA. Such data, assumptions, and 
documentation, if non-proprietary and/or non-privileged, shall be made 
available for review at BPA upon request. The notice shall also contain 
the tentative schedule for the remainder of the DDC implementation 
process.
    (1) On or about March 1 of any of the FY 2003-2006 in which the 
AANR exceeds the DDC Threshold, the Administrator will post the Five-
Year Forecast on BPA's website and will propose to distribute or not 
distribute dividends. During March, BPA will conduct a public review 
and comment process on the proposal.
    (2) On or about April 15 of any of the FY 2003-2006 in which the 
AANR exceeds the DDC Threshold, BPA shall notify customers to which the 
DDC applies of the decision on the proposal, the final calculation of 
the DDC Amount, the allocation of the DDC Amount, and, if applicable, 
the resulting level of the Power Customer DDC Percentage to be applied 
to each applicable firm power rate schedule.

J. Five-Year Flat Block Price Forecast for Monetary Benefit Component 
of IOU Settlements

    The risk-adjusted Five-Year Flat Block Price Forecast is BPA's 
price estimate of the market price for five-year block purchases for 
the 2002-2006 period. This forecast is used in calculating the cash 
component of the proposed settlement of the Residential Exchange 
Program with regional IOUs as described in BPA's Power Subscription 
Strategy. The risk-adjusted Five-Year Flat Block Price Forecast is $34 
per megawatthour (MWh).

S. Slice True-Up Adjustment

    Each year, when the audited actual Slice Revenue Requirement for 
the previous fiscal year is available, BPA will calculate the final 
true-up for the previous fiscal year. BPA will calculate the final 
true-up for the previous fiscal year based on the difference between 
the Slice Revenue Requirement's audited actual expenses (and credits) 
and those expenses (and credits) forecasted in the 2002 Power rate 
case. This true-up will be the True-Up Adjustment Charge and will be 
applied to the customer's bills. See the Slice Product Costing and 
True-Up Table (Table D). Adjustments to the MWs used in the Inventory 
Solution will be trued up using the formula in Table E. Section X 
contains the methodology BPA will rely on to adjust Inventory Solution 
costs to fluctuations in BPA's augmentation costs.

X. Slice Augmentation Cost Adjustment (ACA)

    a. Application of the ACA
    The ACA applies to the Slice Rate in the PF-02 rate schedule.
    (1) This adjustment will reconcile the difference between the Slice 
purchasers pro rata share of BPA's augmentation costs and the forecast 
of the augmentation costs that is a part of the Slice Revenue 
Requirement prior to this adjustment. The adjustment will result in a 
credit or charge to the Slice purchaser's bill as described in the 
methodology below.

[[Page 75284]]

    b. For purposes of calculating and applying the ACA, the following 
definitions will apply:
    (1) ``Adjusted Augmentation Costs'' (AAC) means the dollar cost of 
meeting AAMT separately for the HLH and LLH in the month.
    (2) ``Augmentation Amount'' (AAMT) means the total amount of 
augmentation in flat annual aMWs forecasted by BPA in its Amended ROD 
for the 2002 rate case to serve public, DSI, IOU, and Preexisting 
Contracts less augmentation purchases made by BPA prior to August 1, 
2000.
    (3) ``Augmentation Cost Adjustment'' (ACA) means the adjustment to 
the slice rate to recognize the difference between the cost of 
acquiring the AAMT at 28.1, and the adjusted cost basis of acquiring 
the AAMT that is described herein.
    (4) ``Augmentation Pre-Purchase'' (APP) means a contract or other 
binding obligation entered into by BPA for the delivery of energy and/
or capacity necessary to meet AAMT for that month with purchases prior 
to that month.
    (5) ``Baseline Net Augmentation Costs'' (BNAC) means the cost of 
augmentation for the month that slice customers already bear in the 
Slice rate to meet AAMT, and for purposes of calculating ACA, shall be 
determined as follows:
    BNAC=(AAMT * 28.1 * Hours in the month)
    (6) ``INDEX'' means the weighted average of 50 percent of Firm Dow 
Jones COB flat and 50 percent of Firm Mid-Columbia Flat for HLH, and 
separately, for LLH for the month. If one or more of these indexes are 
abolished or are determined to no longer provide a reasonable measure 
of market cost, BPA and Slice purchasers shall establish replacement 
index(s).
    (7) ``Net Adjusted Augmentation Cost Calculation'' (NAAC) means the 
TAAC for the month minus the BNAC for the month
    (8) ``Total Cost of Augmentation Pre-Purchases'' (TCAPP) means the 
cost in dollars for the APP made to meet AAMT for the month.
    (9) ``Total Adjusted Augmentation Cost'' (TAAC) means the gross 
adjusted cost of meeting AAMT for the month as determined below.
    c. Frequency of ACA Calculation
    The adjustment frequency is monthly during the rate period for each 
month in the rate period. The first month for which an ACA will be 
determined will be October 2001 and the last month for which an ACA 
will be determined is September 2006.
    d. Determining APP Quantity and Cost for the Month
    BPA will maintain records of APP made to meet AAMT identified in 
(d) noting the amounts (in MWh's and/or MW's and/or aMW's) for each 
month by Heavy Load Hour (HLH)) and Light Load Hour (LLH) and the cost. 
BPA will keep separate tallies of HLH and LLH, and will report these 
results in an aggregate form for HLH and LLH separately.
    e. Calculation of the Adjusted Augmentation Cost (AAC)
    These calculations will be separately performed for the HLH in the 
month and the LLH in the month.
    1. If APP for the month is greater than AAMT for the month,
AAC = [(AAMT/APP) * TCAPP]
    2. If APP for the month is equal to AAMT for the month,
AAC = TCAPP
    3. If APP for the month is less than AAMT for the month,
AAC = [TCAPP] + [(AAMT-APP) * INDEX * Hours]
    f. Calculation of Total Adjusted Augmentation Costs (TAAC)
    Once a separate AAC has been calculated for the HLH and LLH for the 
month, these will be summed to determine the TAAC for the month.
    g. Calculation of the Net Adjusted Augmentation Cost (NAAC)
    NAAC for the month shall be determined as follows:
NAAC = TAAC-BNAC
    h. Calculation of ACA
ACA for the month shall be determined as follows:
ACA = NAAC/100
    i. Adjusting Customer's Bill
    A credit to a customer's bill shall occur if ACA is negative. A 
debit shall occur if ACA is positive.
    The amount of credit or debit to appear on an individual customer's 
bill shall be determined using the ACA for that month and the 
customer's slice share.
    The resulting dollar adjustment shall appear on the bill as a 
separate line item on the first bill following the calculation of ACA.

    Issued in Portland, Oregon, on November 22, 2000.
Steven G. Hickok,
Acting Administrator and Chief Executive Officer, Bonneville Power 
Administration.
[FR Doc. 00-30682 Filed 11-30-00; 8:45 am]
BILLING CODE 6450-01-P