[Federal Register Volume 64, Number 156 (Friday, August 13, 1999)]
[Notices]
[Pages 44318-44361]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 99-20805]



[[Page 44317]]

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Part III





Department of Energy





_______________________________________________________________________



Bonneville Power Administraiton



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2002 Proposed Wholesale Power Rate Adjustment, Public Hearing, and 
Opportunities for Public Review and Comment and Proposed Correction of 
Errors in the Firm Power Products and Services Rate Schedule (FPS-96): 
Clarifying the Applicability of the FPS-96 Contract Rate to Certain 
Capacity With Energy Return Contracts, Public Hearing, and Opportunity 
for Public Review and Comment: Notices

  Federal Register / Vol. 64, No. 156 / Friday, August 13, 1999 / 
Notices  

[[Page 44318]]


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DEPARTMENT OF ENERGY

Bonneville Power Administration


2002 Proposed Wholesale Power Rate Adjustment, Public Hearing, 
and Opportunities for Public Review and Comment

AGENCY: Bonneville Power Administration (BPA), Department of Energy 
(DOE).

ACTION: Notice of Proposed Wholesale Power Rates and Proposed 
Resolution of Certain Transmission-Related Issues.

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SUMMARY: BPA requests that all comments and documents intended to 
become part of the Official Record in this process contain the file 
number designation WP-02. The Pacific Northwest Electric Power Planning 
and Conservation Act (Northwest Power Act), provides that BPA must 
establish and periodically review and revise its rates so that they are 
adequate to recover, in accordance with sound business principles, the 
costs associated with the acquisition, conservation, and transmission 
of electric power, and to recover the Federal investment in the Federal 
Columbia River Power System (FCRPS) and other costs incurred by BPA.
    By this notice, BPA announces its proposed 2002 wholesale power 
rates, a proposed methodology for treatment and allocation of inter-
business line costs, and a cost allocation proposal for non-Federal 
transmission for Federal and non-Federal power purchases for BPA's 
current General Transfer Customers, to be effective on October 1, 2001. 
The rate case proceedings also include BPA's proposal to revise the 
Priority Firm Power (PF-96) rate schedule by applying a Targeted 
Adjustment Charge for Uncommitted Loads, to be effective January 1, 
2001.

DATES: Written comments by participants must be received by November 5, 
1999, to be considered in the Record of Decision (ROD).

ADDRESSES: Written comments should be submitted to the Manager, 
Corporate Communications--CK; Bonneville Power Administration; P.O. Box 
12999; Portland, Oregon 97212.

FOR FURTHER INFORMATION CONTACT: Mr. Michael Hansen, Public Involvement 
and Information Specialist, at the address listed above. Interested 
persons may also call (503) 230-4328 or call toll-free 1-800-622-4519. 
Information also may be obtained from:

Mr. Allen L. Burns, Group Vice President, Power Business Line--PS-6, 
P.O. Box 3621, Portland, OR 97208
Mr. Stephen R. Oliver, Bulk Power Marketing--PSB-6, P.O. Box 3621, 
Portland, OR 97208
Mr. Richard J. Itami, Eastern Power Business Area--PSE, 707 W. Main, 
Suite 500, Spokane, WA 99201
Mr. John Elizalde, Western Power Business Area--PSW-6, P.O. Box 3621, 
Portland, OR 97208

    Responsible Official: Ms. Diane Cherry, Manager for Power Products, 
Pricing and Rates, is the official responsible for the development of 
BPA's wholesale power rates.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Introduction and Procedural Background
II. Purpose and Scope of Hearing
III. Public Participation
IV. Major Studies and Summary of Proposal
V. 2002 Wholesale Power Rate Schedules
    A. Introduction
    B. Summary of 2002 Wholesale Power Rate Schedules, 2002 GRSPs, 
and New 1996 GRSPs

Part I--Introduction and Procedural Background

    Section 7(i) of the Northwest Power Act, 16 U.S.C. 839e(i), 
requires that BPA's rates be established according to certain 
procedures. These procedures include, among other things, publication 
of 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; 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). These Procedures implement the statutory 
section 7(i) requirements. Section 1010.7 of the Procedures prohibits 
ex parte communications.
    The Bonneville Project Act, 16 U.S.C. 832, the Flood Control Act of 
1944, 16 U.S.C. 825s, the Federal Columbia River Transmission System 
Act, 16 U.S.C. 838, and the Northwest Power Act, 16 U.S.C. 839, provide 
guidance regarding BPA ratemaking. The Northwest Power Act requires BPA 
to set rates that are sufficient to recover, in accordance with sound 
business principles, the cost of acquiring, conserving, and 
transmitting electric power, including amortization of the Federal 
investment in the FCRPS over a reasonable period of years, and the 
other costs and expenses incurred by the Administrator. In addition, 
rates for the Federal Energy Regulatory Commission (FERC)-ordered 
transmission service, including ancillary services, must satisfy 
section 212(i) of the Federal Power Act, 16 U.S.C. 824k(i). Such rates 
must also satisfy the comparability standard for the open access tariff 
reciprocity compliance requirements of FERC Order 888.\1\ The inter-
business line and General Transfer Agreement (GTA) issues discussed 
below will be used to develop ancillary service and transmission rates 
in the subsequent transmission rate case.
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    \1\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery 
of Stranded Costs by Public Utilities and Transmitting Utilities, 
Order No. 888, FERC Stats. & Regs para. 31,036 (1996).
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    BPA's initial proposed 2002 Wholesale Power Rate Schedules and 
General Rate Schedule Provisions are published in Part V below. The 
studies addressing the factors used to develop these rates are listed 
in Part IV and will be available for examination on August 24, 1999, 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 August 24, 1999, from 9 a.m. to 12 
p.m., Room 223, 911 NE. 11th, Portland, Oregon.
    To request any of the studies by telephone, call BPA's document 
request line: (503) 230-4328 or call toll-free 1-800-622-4519. Please 
request the document by its listed title. Also state whether you 
require the accompanying documentation (these can be quite lengthy); 
otherwise the study alone will be provided. The studies and 
documentation will also be available on BPA's website at www.bpa.gov/
power/ratecase.
    BPA will release its 2002 initial wholesale power rate proposal on 
August 24, 1999, and expects to publish a final ROD on April 7, 2000. 
BPA will be conducting a formal evidentiary rate hearing attended by 
regional parties. Interested parties must file petitions to intervene 
in order to take part in the formal hearing. A proposed schedule for 
the formal hearing is stated below. A final schedule will be 
established by the Hearing Officer at the prehearing conference.

August 24, 1999: BPA files Direct Case/Prehearing Conference
October 14, 1999: Parties file Direct Cases
November 5, 1999: Close of Participant Comments
December 8, 1999: Litigants file Rebuttal Testimony
January 13, 2000: Cross-Examination
February 10, 2000: Initial Briefs Filed

[[Page 44319]]

February 17, 2000: Oral Argument before the Administrator
March 10, 2000: Draft ROD issued
March 24, 2000: Briefs on Exceptions
April 7, 2000: Final ROD--Final Studies

    BPA will also be conducting eight public field hearings in cities 
throughout the region. Public field hearings are an opportunity for 
persons who are not parties in the formal rate hearing to have their 
views included in the official record. Written transcripts will be made 
at all of the field hearings. The field hearings are scheduled to begin 
at 6 p.m. Following are the tentative dates and locations for the field 
hearings. Confirmation of these hearing dates will be made through 
mailings and public advertising or by calling BPA Corporate 
Communications at the telephone number listed above. Announcements will 
also be posted on BPA's wholesale power rate case website at 
www.bpa.gov/power/ratecase.

September 30, 1999: Idaho Falls, Idaho
October 4, 1999: Pasco, Washington
October 5, 1999: Missoula, Montana
October 6, 1999: Spokane, Washington
October 7, 1999: Everett, Washington
October 12, 1999: Olympia, Washington
October 13, 1999: Eugene, Oregon
October 14, 1999: Portland, Oregon

Part II--Purpose and Scope of Hearing

A. Overview of the Market

    The wholesale electricity market facing BPA today is different from 
1996, when BPA last set rates, although BPA anticipated that the market 
would become increasingly competitive. External influences such as the 
national and state-by-state deregulation of the power markets, changes 
in market price expectations, and continuing concerns about the 
environment are factors that BPA must take into account when 
establishing rates.
    In 1996, it appeared that BPA's rates could exceed market prices 
and BPA was not sure it could sell all its power at rates that would 
recover its costs. By 2002, however, BPA's rates are anticipated to be 
lower than market prices through cost cutting and careful management, 
as well as an expectation that market prices could increase. Thus, 
customers have now indicated an interest in purchasing more power than 
BPA can produce from the FCRPS.
    Despite customers' changed perceptions of the value of BPA power, 
BPA's business requirements are fairly constant and are dictated by 
legislation. BPA is required to sell power at a price that recovers all 
costs. These costs are determined by a number of factors, including, 
among other things, the cost of generating power; the costs of 
protecting, mitigating, and enhancing fish and wildlife; the costs of 
investing in public purposes; and the costs of repaying the Treasury 
for the capital investment in the hydro system. BPA has addressed these 
legislative requirements with policies that implement the statutory 
directives.
    The major goal for many of BPA's policies, as stated in BPA's 
Subscription Strategy, is to 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. Due to the changing 
market, BPA must balance the competing demands for its low cost power. 
Public agency customers, known as preference customers, continue to 
have first priority to this low cost power. For this group, BPA 
proposes to sell Subscription power below market, with no increase in 
the average Priority Firm Power (PF) rate from BPA's 1996 rates. BPA's 
initial rate proposal also implements the Subscription Strategy plan to 
offer a combination of power and financial benefits to regional 
investor-owned utilities (IOUs) for the benefit of their residential 
and small farm customers. BPA's rate proposal also responds to the 
viability concerns of BPA's direct service industrial customers (DSIs) 
by offering power below market prices.
    In addition to supplying low cost power to its customer groups, BPA 
policies also spread the benefits of the FCRPS to other stakeholders. 
BPA uses its funds to support its share of a wide range of activities 
designed to address fish and wildlife concerns by keeping open all the 
options for future fish alternatives. Finally, BPA protects the 
interests of the U.S. Treasury and Federal taxpayers by maintaining a 
high probability of making Treasury payments on time and in full.
    BPA's major Subscription goal is supported by the other three goals 
of the Subscription Strategy. The second Strategy goal is to avoid rate 
increases through a creative and businesslike response to markets and 
additional aggressive cost reductions. By avoiding rate increases, BPA 
believes that it contributes to a stable customer base comprised of all 
customer groups. A stable customer base leads in turn to a stable 
revenue stream which enables BPA to cover its share of fish and 
wildlife and conservation costs in this rate period and in future rate 
periods. BPA has committed to pursue a number of financial strategies 
through rates and contracts that will allow it to meet its goal of 
avoiding rate increases, such as following the recommendations of a 
regional public process known as the Cost Review (described below) to 
reduce costs.
    The third goal of BPA's Subscription Strategy was to allow BPA to 
fulfill its fish and wildlife obligations while assuring a high level 
of Treasury payment. There are a wide range of options currently under 
discussion for these fish and wildlife obligations. The options have 
different costs associated with them, so BPA's financial tools include 
methods to ensure that there will be sufficient money to meet the 
costs, such as risk mitigation measures in the event that future 
revenues are not as high as anticipated. BPA measures its ability to 
meet its obligations by setting an 88 percent probability goal of 
making its U.S. Treasury payment on time and in full. By setting a high 
Treasury Payment Probability (TPP), BPA assures that all other 
obligations are met before the Treasury payment is made.
    BPA's Subscription Strategy has a final goal of continuing to 
support its important role of being a leader in the regional effort to 
capture the value of conservation and renewable resources. BPA intends 
to provide market incentives for these and other emerging technologies.
    BPA's Subscription goal of spreading the benefits of the FCRPS 
through low cost power, as well as BPA's other goals, are reflected in 
all of BPA's actions. The rate case provides only one part of 
implementing BPA's goals--through rate levels and rate designs. Many 
actions, such as contract negotiations and setting spending levels, 
occur outside of the ratemaking process.
    BPA has conducted a number of public processes over the last five 
years to gain public input into how to balance these major goals. Now 
it is about to start another one, the ratemaking process. Following is 
a list of the other important public processes that BPA has used to 
involve its customers and stakeholders in the important decisions of 
how BPA will continue to provide service to the citizens of the Pacific 
Northwest.

B. An Overview of the Public Processes

    This section describes four major public review processes that BPA 
has undertaken in the last five years. Many important policy decisions 
were made in these processes. The ratemaking process is one vehicle to 
implement some of the decisions made in these other processes.
1. Business Plan Public Review Process
    In 1995, BPA prepared a draft and final Business Plan, including a 
draft and final Environmental Impact

[[Page 44320]]

Statement (EIS). In the Business Plan, BPA announced its response to a 
changing market. For the first time, BPA's costs appeared to exceed 
market prices, so BPA found itself in a more competitive environment. 
It responded in 1996 with products and services that were competitively 
priced and that included more flexible terms. BPA began to change how 
it sold power, establishing posted prices for core requirements 
products, while selling other unbundled products and energy services at 
negotiated prices reflecting the true costs of providing services. The 
goal of these early changes was to give customers lower prices, 
stability, and flexible new choices, while giving BPA greater certainty 
about its expected loads and revenues. Unbundling products allowed 
customers to pay for only those products and services that they needed. 
Decisions made during the 1995 Business Plan process will not be 
revisited in this rate case.
    The rate design in the current proposal continues the basic goals 
of the Business Plan, with some added features designed to allow BPA 
the flexibility of passing to customers the incremental cost of 
unanticipated expenses.
2. Cost Review Public Review Process
    In September 1997, BPA and the Northwest Power Planning Council 
initiated a process called the Cost Review of the Federal Columbia 
River Power System (Cost Review). The primary objective of the Cost 
Review was to ensure that BPA's long-term power and transmission costs 
would be as low as possible, consistent with sound business practices, 
so that BPA could maximize its ability to fully recover costs through 
power rates that are at or below market prices.
    The Cost Review process began with the establishment of a panel of 
five executives with considerable experience managing large 
organizations during periods of downsizing and competitive transition. 
The panel focused on costs to be recovered through power rates for the 
initial Subscription period, fiscal years (FY) 2002 through 2006. Costs 
associated with fish and wildlife recovery efforts were excluded from 
the scope of the Cost Review, while the following costs were recognized 
as subject to significant change in the rate development process:
     Short-term power purchases,
     Residential Exchange Program,
     General Transfer Agreements,
     Federal interest and depreciation, and
     Inter-business line expenses.
    A draft of the panel's recommendations was circulated throughout 
the region, and public comments were received during a month-long 
period that included public meetings and briefings with various 
interest groups. Based on comments received during this public 
consultation process, the draft recommendations were modified and 
presented to the Administrator, the region's Governors, the Northwest 
Congressional delegation, and the U.S. House and Senate Committees on 
Appropriations in March 1998.
    Additionally, both the recommendations and implementation plans 
were a subject of ``Issues '98,'' a public comment process conducted by 
BPA in summer 1998. A key purpose of Issues '98 was to decide how the 
Cost Review recommendations would be implemented.
    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. For 
informational purposes only, the history of the Cost Review and 
implementation of the final recommendations will be summarized in the 
Revenue Requirement Study, WP-02-E-BPA-02.
3. Subscription Strategy Public Review Process
    As noted previously, one of BPA's goals is to encourage the widest 
possible diversified use of electric energy while recovering costs. To 
define this broad concept in greater detail for the post-2001 period, 
BPA engaged in a multiyear process that culminated in BPA's 
Subscription Strategy.
    In 1996, a regional effort began with the Comprehensive Review of 
the Northwest Energy System. In December 1996, the Final Report of the 
Comprehensive Review recommended that BPA capture and deliver the low-
cost benefits of the Federal hydropower system to Northwest energy 
customers through a Subscription-based power sales approach.
    A public process to develop a Subscription Strategy began in 1997. 
This process brought together all the regional stakeholders in an 
ongoing series of workgroups and meetings. BPA issued a final 
Subscription Strategy and Record of Decision in December 1998.
    The Subscription Strategy provides a marketing policy framework for 
the power rate case. It reflects agency decisions on equitable 
distribution of the electric power generated by the FCRPS to BPA's 
customers within the framework of existing law. Although it did not 
establish any rates or rate designs, it suggested general rate design 
approaches to be considered in the formal ratemaking process.
    The Subscription Strategy also provided a framework for the 
bilateral negotiations with each customer that will reflect the 
specific business relationships between BPA and that customer. Those 
contracts will be negotiated outside this rate case.
    The Subscription Strategy recognized that the FCRPS is a regional 
resource, limited in size, and valued by the citizens of the Northwest. 
The Strategy seeks to balance potentially competing demands on the 
system, as described in the key marketing goals above. It guides the 
distribution of power among competing demands, while balancing the 
goals of avoiding PF rate increases, meeting fish and wildlife 
obligations, and funding public purposes.
    After going through an extensive public process, BPA stated in its 
Subscription Strategy that it planned to offer 1,800 average megawatts 
(aMW) worth of benefits for the residential and small farm consumers of 
IOUs while meeting all public agency net firm load requirements. The 
Strategy also stated that BPA expected to be able to meet all loads 
that DSI customers asked BPA to serve. This rate case consists of the 
rates to serve all BPA customers.
4. Fish and Wildlife Obligations Public Review Process
    Another important public review process has occurred since BPA's 
last ratemaking process in 1996. In late 1995, the Clinton 
Administration and the Northwest Congressional delegation agreed to 
stabilize BPA's fish and wildlife funding obligations over a six-year 
period, FY 1996 through FY 2001. In September 1996, the Secretaries of 
Energy, Commerce, Army and Interior signed a Memorandum of Agreement 
(MOA) on behalf of five Federal agencies--BPA, the National Marine 
Fisheries Service (NMFS), the U.S. Army Corps of Engineers, the U.S. 
Fish and Wildlife Service (USF&W), and the Bureau of Reclamation. The 
MOA represents a multiagency commitment to stable BPA funding for fish 
and wildlife through FY 2001.
    The MOA divides BPA's financial obligations for fish and wildlife 
into two major categories: (1) The financial impacts of the system 
operations called for in the 1995 Biological Opinions on the operation 
of the FCRPS issued by NMFS and the USF&W, as well as certain other 
operational measures specified in the MOA; and (2) a commitment of an 
average of $252 million per year for capital costs,

[[Page 44321]]

operation and maintenance of fish and wildlife facilities, and 
implementation of the Northwest Power Planning Council's Fish and 
Wildlife Program.
    In addition, the Administration committed to provide cost-sharing 
assistance pursuant to section 4(h)(10)(C) of the Northwest Power Act, 
16 U.S.C. Section 839b(4)(h)(10)(C), on a permanent basis for BPA's 
direct fish and wildlife expenses, and also to provide section 
4(h)(10)(C) credits for BPA's power purchase costs related to its fish 
and wildlife programs through FY 2001. The Administration also 
established a Fish Cost Contingency Fund (FCCF) consisting of U.S. 
Treasury payment credits associated with section 4(h)(10)(C) that BPA 
has not yet exercised. The FCCF balance of $325 million in U.S. 
Treasury payment credits will be available to BPA in the case of low 
water years and under certain other conditions to defray fish and other 
water-related costs. Further, the Administration acknowledged that, to 
the extent necessary, BPA would reduce its build-up of cash reserves in 
FY 1996-2001. This action could make it more likely that BPA would have 
to reschedule a portion of its annual U.S. Treasury payments in future 
years.
    In June 1997, all eight Senators representing the Northwest sent a 
letter to Vice President Gore requesting that the Administration work 
with the Northwest Congressional delegation and the four Northwest 
Governors through the Governors' Transition Review Board to develop a 
proposal for extending the MOA beyond FY 2001 to enable BPA to proceed 
with a Subscription process for post-FY 2001 power sales. As described 
above, the Subscription concept was created in 1996, during the year-
long Comprehensive Review of the Northwest Energy System. The 
Comprehensive Review was sponsored by the four Northwest Governors and 
studied how the region's electricity system should be structured in the 
deregulated wholesale electricity market.
    In the absence of a consensus on a post-FY 2001 fish and wildlife 
recovery strategy by mid-1998, concerned Federal agencies and regional 
stakeholders agreed that a strategy and mechanism were needed to 
establish post-FY 2001 fish and wildlife funding assumptions for 
Subscription and ratemaking purposes. This strategy is directed at 
``keeping the options open'' for future decisions on long-term 
configuration of the FCRPS, including the potential drawdown of 
reservoirs behind the four Lower Snake River projects and John Day Dam 
on the mainstem of the Columbia. Without such a strategy and mechanism, 
BPA could not proceed with its Subscription process for post-FY 2001 
power sales or its FY 2002-2006 power rates process because BPA could 
not provide the necessary cost certainty to its potential post-FY 2001 
power sales customers nor assure adequate funding for fish and wildlife 
recovery efforts.
    The Fish and Wildlife Funding Principles (Principles) were 
developed in consultation with constituents, customers, other Federal 
agencies, the Northwest Congressional delegation, and Columbia Basin 
Tribes in an extensive public involvement process. The parties focused 
on guidelines for structuring BPA's approach to Subscription and FY 
2002-2006 power rates to ensure that BPA could meet its financial 
obligations, including those for fish and wildlife, given 
hydroconditions, market prices, fish recovery costs, and other 
uncertainties. The Principles specify that BPA will take into account 
the full range of potential fish and wildlife costs, as reflected in 13 
long-term alternatives for configuration of the FCRPS, with each 
alternative assumed to be equally likely to occur.
    The Principles also state that BPA will set rates to achieve a high 
probability that U.S. Treasury payments will be made in full and on 
time over the five-year rate period, and that BPA will adopt rates and 
contract strategies that are easy to implement and administer and that 
will minimize rate impacts on Pacific Northwest power and transmission 
customers. The contract strategies may include sales of Subscription 
products on staggered contract terms, a Cost Recovery Adjustment Clause 
(CRAC) in power sales contracts, and cost-based indexed pricing for 
some Subscription products.
    The Principles also commit the Administration to extend the 
availability of section 4(h)(10)(C) U.S. Treasury payment credits and 
any remaining FCCF funds through FY 2006 under the same terms as those 
established for FY 1996 through FY 2001, and to support BPA's efforts 
to implement the Cost Review recommendations.
    The Principles have been reviewed by the Office of Management and 
Budget and are consistent with the Administration's principles and 
priorities. These Principles were published on September 16, 1998, in a 
document entitled ``Fish and Wildlife Funding Principles for Bonneville 
Power Administration Rates and Contracts.'' Vice President Gore 
announced the establishment of the Principles on September 21, 1998.
    These Principles differ significantly from the MOA. BPA and the 
other participants are not establishing a budget for the FY 2002 
through FY 2006 period. In fact, final decisions and approvals on a 
fish and wildlife recovery strategy and funding are not expected during 
this rate proceeding. Because rates are being set before decisions and 
approvals are made, the Principles take into account the broad range of 
potential costs associated with the hydrosystem configuration 
alternatives under consideration at the time the Principles were 
adopted. The Principles are intended to ensure that BPA's rates and 
power sales contracts yield a very high probability of meeting all 
post-FY 2001 financial obligations, including BPA funding obligations 
for the fish and wildlife recovery strategy that is eventually adopted.
    A number of fish and wildlife initiatives are currently being 
developed, analyzed, and reviewed in the region. These include: (1) the 
1999 decision on long-term configuration of the FCRPS called for in the 
1995 NMFS Biological Opinion and the NMFS recovery plan for listed 
salmon and steelhead; (2) the Columbia Basin Forum ``Four H'' process, 
which focuses on development of a regional fish and wildlife plan 
through a broad ecosystem approach that takes into consideration the 
hydrosystem, habitat, hatcheries, and harvest; (3) the Multi-Species 
Framework initiated by the Northwest Power Planning Council and NMFS, 
in consultation with the region's Indian Tribes, to establish a 
coherent array of scientifically based options for the Columbia Basin; 
and (4) proposed revisions to the Northwest Power Planning Council's 
Fish and Wildlife Program. BPA believes that the range of costs 
associated with the 13 alternatives is sufficiently broad to cover any 
eventual decision made on potential activities to be undertaken, or any 
outcome reached through these other processes.
    In December 1998, BPA published its implementation plan for the 
Principles. This document is entitled ``How BPA's Subscription Strategy 
Implements the Fish and Wildlife Funding Principles.'' See Revenue 
Requirement Study Documentation, WP-02-E-BPA-02A, Volume 1, Chapter 13.

C. Scope of the 2002 Rate Case

    Many of the decisions that guide BPA's marketing policies have been 
made or will be made in other public review processes. This section 
provides guidance to the Hearing Officer as to those matters that are 
within the scope

[[Page 44322]]

of the rate case, and those that are outside the scope.
1. Spending Levels
    As described above, the Cost Review recommendations and BPA's 
planned implementation of those recommendations have already received 
extensive public review. 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 on spending 
levels, as included in BPA's test period revenue requirement for FYs 
2002 through 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 BPA's rate case models, or timing, are: 
(1) forecasts of Residential Exchange benefits; (2) forecasts of short-
term purchase power costs; (3) capital recovery matters such as 
interest rate forecasts, scheduled amortization, depreciation, 
replacements, and interest expense; (4) inter-business line expenses; 
and (5) General Transfer Agreements.
2. Subscription Strategy
    As noted above, the Subscription Strategy has already received 
extensive public review and was accompanied by a Final ROD in December 
1998. BPA's Subscription Strategy states that BPA will negotiate new 
power sales contracts with the DSIs but make the actual level of 
service under such contracts contingent on the availability of power 
remaining after the close of the Subscription window. The Subscription 
Strategy also notes that BPA was not prepared at the time of issuing 
the Strategy to make any final decisions regarding augmentation in 
order to serve DSI load. Since then BPA has decided to propose serving 
approximately 1,440 aMW of DSI load. BPA does not intend to conduct a 
separate public process to take comments on this proposal. Therefore, 
parties to the rate case may raise and discuss any issues regarding 
BPA's proposal to serve the DSIs, including any issues regarding the 
potential effects of this proposal on BPA's rates.
    BPA's Subscription Strategy also provides that BPA will offer the 
equivalent of 1,800 aMW of Federal power to regional IOUs for the FY 
2002-2006 period as a proposed settlement of the Residential Exchange 
Program. BPA has recently received a suggestion to increase the amount 
of power provided to regional IOUs from 1,800 aMW to 1,900 aMW for the 
FY 2002-2006 period. While the Subscription Strategy accurately 
reflects BPA's settlement proposal, any decision by BPA to change the 
amount of power offered to the IOUs will be made outside of this rate 
case. Parties to the rate case, however, may raise and discuss any 
issues regarding the potential effects of such an increase on BPA's 
rates.
    BPA has developed the Conservation and Renewables (C&R) Discount 
over the past year based on public comment. The range of public opinion 
regarding the discount was discussed in the Subscription ROD. Working 
from the ROD, BPA has included the following proposal as part of the 
rate case. The C&R Discount will apply to all customers served under 
requirements rates including the Priority Firm Power rate (PF), the 
Industrial Firm Power rate (IP), the New Resource Firm Power rate (NR), 
the Residential Load Firm Power rate (RL), and Slice. The total 
eligibility for each customer will equal .5 mills per kilowatthour 
(kWh) based on Subscription loads. Customers will be accountable for 
demonstrating compliance with their expenditure target at the end of 
the contract term. The discount will be applied automatically on each 
customer's monthly bill. If a dividend is declared, based on better 
than expected revenues, the first $15 million will be disbursed to 
customers actively pursuing C&R Discount programs.
    Also based on the Subscription ROD, BPA is addressing the following 
issues outside the rate case. Recommendations for measures that will be 
eligible for the C&R Discount will be submitted to BPA by the Regional 
Technical Forum. BPA will go through a separate public process to 
review and adopt these recommendations before the new rates go into 
effect. BPA will conduct a separate process in the fall of 1999 to 
discuss simplified eligibility criteria for small utilities and other 
administrative details.
    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 the ROD for the 
Strategy.
3. 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 Principles were developed 
through extensive public involvement and comment processes, and have 
been adopted as policy at the highest levels of the Administration. The 
rate proceeding will, however, address implementation of the Principles 
in the Revenue Requirement Study (including repayment studies and risk 
mitigation), the Risk Analysis Study, the Loads and Resources Study, 
and the Wholesale Power Rate Development Study (including rate design, 
cost allocation, and revenue forecast).
    Fish and wildlife issues that will be addressed in this rate 
proceeding include: (1) how the terms of access to the FCCF are modeled 
in the rate proposal and their impact on TPP and rates; (2) how section 
4(h)(10)(C) credits are modeled in the rate proposal and their impact 
on TPP and rates; (3) the calculation and treatment of operations and 
maintenance and capital investment in repayment studies and the revenue 
requirement; (4) the selection, design, terms and conditions, 
assumptions, treatment, and impact of planned net revenues for risk, 
CRAC, indexed power sales contracts, stepped rates, and targeted 
adjustment charge; (5) the RiskMod, NORM, and Tool Kit model design, 
operation, inputs and outputs, and use of results; (6) the level of TPP 
that is targeted, from the range of potential TPP targets established 
in the Principles; and (7) the design, terms and conditions, 
assumptions, and treatment of the Dividend Distribution Clause (DDC), 
including the threshold for triggering a dividend distribution, the 
conditions under which a dividend is distributed, and the mechanism 
used to distribute dividends to certain power customers.
    Included among the policy decisions, commitments, and assumptions 
that are not at issue in this rate proceeding are: (1) The 
Administration's decision to extend the existing terms of access to the 
FCCF and to roll over the existing formula for calculating section 
4(h)(10)(C) credits from the current rate period to FY 2006; (2) the 
content, merits, or level of costs for the fish and wildlife recovery 
strategies reflected in each of the 13 alternatives; (3) the decision 
to include the full range of costs for all 13 alternatives for the 
purposes of BPA's repayment study, revenue requirement, revenue 
forecast, and risk management studies and strategies; (4) the TPP goal 
of 88 percent over the 5-year rate period with a ``floor'' of 80 
percent; (5) the policy

[[Page 44323]]

objective that rates and contracts be designed to position BPA to 
achieve similarly high TPP post-FY 2006; (6) the incorporation of the 
full range of costs using the same probabilistic method BPA uses for 
other cost and revenue uncertainties in its ratemaking; (7) the 
assumption that all 13 alternatives are equally likely to occur; (8) 
the assumption that BPA's annual fish and wildlife operations and 
maintenance costs have an equal probability of falling anywhere within 
the range of $100 million and $179 million; (9) the adoption of a 
flexible approach in order to respond to a variety of different fish 
and wildlife cost scenarios, and in particular, the 35 to 45 percent 
goal of total post-FY 2001 sales in contract-term lengths of three 
years or less, in short-term surplus sales, and/or in cost-based 
indexed sales; and (10) the goals of adopting rates and contract 
strategies that are easy to implement and administer.
4. Transmission Related Issues
    In setting rates for the period beginning October 1, 2001, BPA is 
bifurcating its general rate proceeding into separate power and 
transmission rate proceedings. BPA has voluntarily committed to 
marketing its power and transmission services in a manner modeled after 
the regulatory initiatives articulated by FERC in Order Nos. 888 and 
889.\2\ In Order No. 888, FERC directed public utilities regulated 
under the Federal Power Act to functionally unbundle transmission and 
ancillary services from their wholesale power services, and to 
establish separate rates for wholesale generation, transmission, and 
ancillary services. Establishing BPA's power and transmission and 
ancillary services rates in separate rate cases is consistent with 
FERC's unbundling paradigm because it will separately resolve power and 
transmission issues in the different rate cases.
---------------------------------------------------------------------------

    \2\ Open Access Same-Time Information System (Formerly Real-Time 
Information Networks) and Standards of Conduct (Order 889), FERC 
Stats, & Regs para. 31,035 (1996).
---------------------------------------------------------------------------

    The proposal for new and revised wholesale power rates, the 
methodology for the treatment and allocation of inter-business line 
costs, and the proposed cost allocation for non-Federal transmission 
costs for the Federal and non-Federal power purchases of GTA customers 
are discussed below. The Administrator will decide the inter-business 
line and GTA issues as part of the wholesale power rate case and will 
not revisit the decision on these issues in the subsequent transmission 
rate case. In addition, the scope of the wholesale power rate case does 
not include the merits of the business line separation or BPA's rates 
for transmission and ancillary services that will be marketed by the 
Transmission Business Line (TBL). All transmission and ancillary 
service rates and rate design issues will be addressed in the 
subsequent transmission rate case. A notice of BPA's transmission and 
ancillary services rate proposals will be announced and published in 
the Federal Register at a later date.
    In BPA's 2002 power rate case, BPA will decide the appropriate 
treatment of costs that mutually affect both of its power and 
transmission business lines, or that assess costs from one business 
line to the other. The treatment of these ``inter-business line'' 
issues will determine whether the costs are recovered through power, 
transmission, or ancillary services rates. BPA plans to address in this 
power rate case: functionalization of corporate overhead costs; 
treatment of generation-integration and generation step-up transformer 
costs; determination of the generation input costs or unit costs that 
will become the basis for certain ancillary services rates; and 
determination of the costs of generation services used by the TBL, 
including Remedial Action Schemes and station service.
    The other transmission-related issues to be proposed in the power 
rate case include all GTAs and GTA replacement costs for Federal power 
deliveries and for non-Federal power deliveries, and PBL 
responsibility, if any, for Delivery Segment costs. Resolution of the 
GTA issues for Federal and non-Federal power deliveries will allow GTA 
customers to make informed power purchase decisions and will affect the 
level of the power revenue requirement.
    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 address those 
transmission items which are not within the scope of this rate case as 
noted above.
5. Adjustment to PF-96 Rate: Targeted Adjustment Charge for Uncommitted 
Loads
    This rate case also includes a proposal to establish a charge in 
the PF-96 rate schedule for customer loads that were uncommitted during 
the 1996 rate case but return to BPA as firm requirements load prior to 
September 30, 2001. There are no other changes to the PF-96 rate 
schedule proposed in this rate case.
    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 on any issue regarding the proposed adjustment 
of the PF-96 rate schedule other than the Targeted Adjustment Charge 
for Uncommitted Loads.

D. The National Environmental Policy Act

    BPA's initial rate proposal falls within the scope of the Final 
Business Plan EIS, completed in June 1995. The analysis in the EIS 
includes an evaluation of the environmental impacts of rate design 
issues for BPA's power products and services. Comments on the Business 
Plan EIS were received outside the formal rate hearing process, but 
will be included in the rate case record and considered by the 
Administrator in making a final decision establishing BPA's 2002 rates.

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 November 5, 1999. This date follows the 
anticipated submission of BPA's and all other parties' direct cases. 
Written views, supporting information, questions, and arguments should 
be submitted to BPA's Manager of Corporate Communications at the 
address listed in the ADDRESSES Section of this Notice. In addition, 
BPA will hold several field hearings in the Pacific Northwest region. 
Participants may appear at the field hearings and present oral 
testimony. The transcripts of these hearings will be a part of the 
record upon which the Administrator makes her final rate decisions.
    Persons wishing to become a party to BPA's rate proceeding must 
notify BPA

[[Page 44324]]

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 August 24, 1999. The petitions should 
be directed to: Christopher Jones, Hearing Clerk--LP, Bonneville Power 
Administration, 905 NE. 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 24 hours 
before the prehearing conference. Any opposition to an intervention 
petition may instead be made at the prehearing conference. Any party, 
including BPA, may oppose a petition for intervention. Persons who have 
been denied party status in any past BPA rate proceeding shall continue 
to be denied party status unless they establish a significant change of 
circumstances. All timely applications will be ruled on by the Hearing 
Officer. Late interventions are strongly disfavored. 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.
    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 will serve copies of 
the Final ROD on all parties. At the conclusion of the rate proceeding, 
BPA will file its rates with FERC for confirmation and approval.
    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 necessary 
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--Major Studies and Summary of Proposal

A. Summary of Proposed 2002 Wholesale Power Rate Structure

1. List of Proposed 2002 Wholesale Power Rates
    BPA is proposing five different rate schedules for its 2002 
Wholesale Power Rates. All of these rate schedules are discussed in 
more detail in Part V of this Notice.
a. PF-02: Priority Firm Power Rate
    The PF rate schedule is comprised of three rates: the PF Preference 
rate, the PF Exchange Program rate, and the PF Exchange Subscription 
rate.
    The PF Preference rate applies to BPA's firm power sales to be used 
within the Pacific Northwest by public bodies, cooperatives, and 
Federal agencies. This power is guaranteed to be continuously 
available. The rate applies to the following products:

Full Service Product
Actual Partial Service Product--Simple
Actual Partial Service Product--Complex
Block Product
Block Product with Factoring
Block Product with Shaping Capacity
Slice Product

    The PF Exchange Program rate applies to sales of power to regional 
utilities that participate in the Residential Exchange Program 
established under section 5(c) of the Northwest Power Act, 16 U.S.C. 
Section 839c(c).
    The PF Exchange Subscription rate applies to sales of power to 
regional IOUs that participate in a settlement of the Residential 
Exchange Program. This proposed settlement was established in BPA's 
Subscription Strategy and includes a power sale component and a 
financial component. The Strategy noted that power sales under the 
settlement might be in the form of ``in lieu'' power sales under 
section 5(c) of the Northwest Power Act or requirements sales under 
section 5(b) of the Act. The PF Exchange Subscription rate applies to 
``in lieu'' sales under the settlement.
b. RL-02: Residential Load Firm Power Rate
    The RL rate applies to sales of power to regional investor-owned 
utilities that participate in a settlement of the Residential Exchange 
Program. As noted above, the Subscription Strategy indicated that power 
sales under the settlement might be in the form of ``in lieu'' power 
sales under section 5(c) of the Northwest Power Act or requirement 
sales under section 5(b) of the Act. The Residential Load rate applies 
to requirements sales under the settlement.
c. NR-02: New Resource Firm Power Rate
    The NR rate applies to net requirements power sales to IOUs for 
resale to ultimate consumers for direct consumption, for construction, 
test, and start-up, and for station service. NR-02 firm power is also 
available to public utility customers for serving New Large Single 
Loads. This rate covers seven products:

New Large Single Loads
Full Service Product
Actual Partial Service Product--Simple
Actual Partial Service Product--Complex
Block Product
Block Product with Factoring
Block Product with Shaping Capacity
d. IP-02: Industrial Firm Power Rate
    The IP rate applies to firm power sales to BPA's DSI customers. The 
IP rate applies to the firm take-or-pay Block Product for DSI customers 
that purchase under 2002 Industrial Firm Power Contracts. The IP-02 
rate includes Targeted Adjustment Charges.
e. NF-02: Nonfirm Energy Rate
    The NF rate applies to energy sold under an arrangement that does 
not have the guaranteed continuous availability of firm power. The rate 
provides for upward and downward pricing flexibility from an average 
cost. Any time that BPA has nonfirm energy for sale, any combination of 
the following rates may apply:

Standard Rate
Market Expansion Rate
Incremental Rate
Contract Rate
Western Systems Power Pool Transactions

[[Page 44325]]

End-user Rate
2. Rate Development Issues
a. Inter-Business Line Calculations
    BPA is addressing certain inter-business line issues that must be 
resolved in order to determine BPA's power revenue requirement and to 
forecast associated revenues. In its power rate case, BPA is proposing: 
a methodology for functionalizing corporate overhead costs; unit costs 
for generation inputs for operating reserves and regulation ancillary 
services; the generation input cost for the reactive ancillary service; 
and the costs of station service and remedial action schemes needed by 
the TBL. In addition, BPA is proposing an allocation of generation 
integration and generation step-up transformer costs to the business 
lines. BPA does not propose to recover any Delivery Segment costs 
through wholesale power rates. BPA's proposal for treatment of Delivery 
Segment costs will be resolved in the separate transmission rate case.
b. Rate Mitigation Costs
    The average proposed PF Preference rate is about the same as in 
1996. However, due to rate design changes, some utilities will 
experience a rate increase and some will experience a rate decrease 
based on their individual usage.
    BPA has proposed to mitigate rate impacts in a number of ways. 
These include modifying the monthly demand charge, capping the Load 
Variance Charge, and continuing the Low Density Discount. These items 
are described below. In addition, BPA proposes to have $4 million 
available each year to mitigate remaining impacts on certain customers.
c. System Augmentation Costs
    Under the Subscription Strategy, BPA expects to be obligated to 
serve more firm load than is forecasted to be produced by the Federal 
Base System (FBS) under critical water conditions. Additional firm 
power will be needed to augment the FBS. For ratemaking purposes, this 
firm power will be defined as FBS replacements. The costs associated 
with this FBS replacement power will be allocated to power rate pools 
as specified by the rate directives in the Northwest Power Act.
    Power purchases for system augmentation are distinguished from 
balancing power purchases by their longer duration. Balancing power 
purchases are shorter-term purchases needed to serve daily and monthly 
load obligations within the annual load/resource balance. System 
augmentation purchases are for a year or longer, and are needed on an 
annual basis to produce an annual load/resource balance.
    BPA's initial proposal contains a provision that requires 
purchasers of the Slice product to pay their share of the net costs of 
system augmentation purchases. The net costs are the actual costs of 
the system augmentation purchases minus the revenue BPA derives from 
selling the equivalent amount of power at posted rates. The initial 
proposal also frees Slice purchasers from paying for shorter-term 
balancing purchases. These elements of the Slice product were designed 
at a time when the amount of purchases necessary to augment the system 
was anticipated to be relatively small.
    The anticipated amount of power necessary to augment the system has 
increased significantly since Slice was initially proposed. Because of 
the increased augmentation purchases, the risks associated with having 
Slice purchasers only obligated to share the net costs of system 
augmentation may no longer be consistent with the underlying principle 
of the Slice product that there would be ``no cost shifts.'' BPA 
intends to examine this issue in the rate case to ensure that having 
Slice purchasers share only the net costs of system augmentation does 
not create a cost shift.
d. Exchange Settlement Methodology
    The Subscription Strategy proposes a settlement of the Residential 
Exchange Program with regional IOUs that includes both power and 
monetary benefits. The total package is valued at 1800 aMW at the RL-02 
or PF Exchange Subscription rate. BPA will supply at least 1000 aMW at 
the RL-02 or PF Subscription rate. In addition, the remaining 800 aMW 
will be provided either in the form of monetary benefits or as physical 
power at BPA's discretion. For purposes of the rate case this 800 aMW 
of benefits will be calculated as the difference between a market 
forecasted price for power and the RL-02 or PF Exchange Subscription 
rate.
    BPA does not know if the IOUs will accept the proposed settlement. 
(The IOUs have the choice of accepting this RL settlement or 
participating in the Residential Exchange Program.) Therefore, rates 
that will apply to the settlement, the RL-02 and PF Exchange 
Subscription rates, as well as a rate that will apply to the 
traditional Residential Exchange Program, the PF Exchange Program rate, 
must be established in the rate case.
3. Changes in Rate Design
    BPA redesigned its rates in BPA's 1996 rate case to send price 
signals that reflected the market estimated at that time. BPA is 
generally continuing the same rate design for its 2002 rates, with some 
changes described below to account for current market and hydro 
conditions.
    The major change that BPA has made in designing its rates is to add 
a ``Subscription Settlement'' step, which serves as the basis for 
calculating the RL and PF Exchange Subscription rates and for 
developing targeted adjustment charges for the IP and PF rates. More 
detail on this change is described later in this Notice under Rates 
Analysis Model.
a. Load Variance Charge
    In this rate case BPA is eliminating the Load Shaping Charge and 
replacing it with a Load Variance Charge. The Load Variance Charge 
covers BPA's cost of standing ready to meet customers' load growth for 
reasons other than annexation or retail access load gain or loss. In 
addition, it provides Full and Partial Service purchasers the right to 
deviate from their monthly forecasted BPA purchases due to weather, 
economic business cycles, or plant energy consumption. The charge is 
set at 0.80 mill per kWh and is charged against the customer's Total 
Retail Load. Further details on these charges are found in the General 
Rate Schedule Provisions (GRSPs) (Part V of this Notice).
b. Stepped Up Multi-Year (SUMY) Block Charge
    An additional adjustment is proposed by BPA to recover the added 
cost of serving a block purchase that increases over time. This is to 
compensate BPA for the incremental cost of serving an additional amount 
of load above first year loads.
c. Monthly Demand and Energy Charges
    BPA is proposing to set monthly energy and demand charges for the 
FY 2002-2006 rate period. BPA's Marginal Cost Analysis shows 
substantial monthly differentiation in predicted energy rates for this 
period. In setting monthly charges for energy and demand, BPA is moving 
away from the six seasonal period energy charges and the annual demand 
charge used in BPA's 1996 rate case.
d. Demand Adjuster
    In addition to the change in the development of the demand charge, 
BPA is making a change in the measurement of a customer's peak

[[Page 44326]]

demand. BPA will continue measuring Full Service customers' peak demand 
coincidental to BPA's generation peak. However, Partial Service 
customers' demand entitlement is measured on their system peak, and 
adjusted through a Demand Adjuster to compensate for the different 
demand billing basis compared to the demand billing basis of a Full 
Service customer.
e. Stepped Rates
    A major change in BPA's proposal is the posting of Stepped Rates. 
The Rates Analysis Model (RAM) calculates an average five-year rate, 
however, rates that customers pay will be differentiated between the 
first three years and the last two years of the rate period. The rates 
for the FY 2002 to 2004 period will be 0.6 mills per kWh below the 
average five-year rate. The rates for the FY 2005 to 2006 period will 
be 0.9 mills per kWh above the average five-year rate. The effective 
differential is 1.5 mills per kWh.
4. New Adjustments to Rates
    BPA is proposing a number of new adjustments and continuing some 
existing adjustments. These adjustments are listed alphabetically and 
are discussed in greater detail in Part V of this Notice.
a. Conservation and Renewables (C&R) Discount
    BPA has included a C&R Discount in this rate case. In setting power 
rates, BPA has included the cost of this discount by applying 0.5 mills 
per kWh to loads served by posted rates and the Slice product. Within 
the PBL billing process, customers will receive a C&R Discount to 
encourage investment in qualifying new conservation and renewables. BPA 
and its customers will reconcile the actual conservation and renewable 
investments and C&R Discount eligibility. BPA is assumed to remain 
revenue neutral in this program. While IP-02 rate customers are 
eligible for the C&R Discount, the discount cannot be used to lower the 
IP rate below the DSI Floor Rate.
b. Cost Recovery Adjustment Clause (CRAC)
    BPA is including a CRAC in its rate proposal as one of the risk 
mitigation tools intended to address the wide range of financial 
uncertainty BPA is facing in the FYs 2002-2006 rate period. The CRAC 
would cause posted power rates to be adjusted upward for one year if 
actual accumulated net revenues (AANR) fall below a threshold level: -
$350 million for FYs 2001 and 2002 and $200 million for FYs 2003, 2004, 
and 2005. These levels of AANR are equivalent to reserve levels of $300 
million for FYs 2001 and 2002, and $500 million for FYs 2003, 2004, and 
2005. In the event that AANR falls below the threshold level for any of 
the years from FYs 2001-2005, rates will be increased for a 12-month 
period beginning with power deliveries in the following April. (In FY 
2006, rates will only be increased for six months, through the end of 
FY 2006.) The CRAC is intended to generate additional revenue of up to 
$125 million, $135 million, $150 million, $150 million, and $87.5 
million if the threshold levels are crossed for FYs 2001, 2002, 2003, 
2004, or 2005, respectively. The CRAC is projected to have an average 
of about a 12 percent chance of triggering.
c. Cost-Based Indexed IP Rate
    BPA is proposing a variable rate for the direct service aluminum 
companies in this rate filing. It will be a rate that is adjusted 
higher or lower to reflect the aluminum price forecast. The rate is 
designed to go no lower than 19 mills per kWh, with an upper ceiling of 
28.5 mills per kWh. The variable rate will be designed to yield an 
average rate of 23.5 mills for those DSI customers that will be offered 
an Industrial Power Targeted Adjustment Charge (IP TAC) rate of 23.5 
mills, and 25 mills for those DSI customers that will be offered an IP 
TAC rate of 25 mills.
d. Cost-Based Indexed PF Rate
    This rate is designed to provide a market based alternative rate to 
all firm load requirements customers that wish to diversify their power 
portfolios. Customers can choose to convert their applicable PF rate to 
a market indexed or floating price adjusted for BPA's risk. The 
customer and BPA will choose a mutually agreeable reference point for 
the index, and the index price will be based on a current market 
forecast of the index selected.
e. Dividend Distribution Clause (DDC)
    Because of a wide range of financial uncertainties, there is the 
potential that net revenues will accumulate in excess of what will be 
needed to ensure recovery of costs over time. BPA is proposing to 
distribute ``dividends'' if an accumulated net revenue threshold is 
exceeded and if a five-year net revenue forecast and risk analysis show 
that an 88 percent Treasury Payment Probability would still be met.
    The DDC proposes criteria and process requirements that the 
Administrator will follow in determining the total amount of annual 
dividends. BPA intends to conduct a separate public consultation 
process before the beginning of the rate period to establish criteria 
for apportioning the amount of annual dividends among BPA stakeholders.
f. Excess Factoring Charges
    Part of the rate design in this rate case includes the 
establishment of a Factoring Product and an Excess Factoring Charge. 
Factoring for purposes of the Core Subscription Products is 
specifically defined as the BPA service of shaping a given quantity of 
megawatt-hours among hours during certain periods to follow load. 
Factoring charges will be applied to Excess Load Factoring that exceeds 
the benchmark limits. The Factoring Charge is limited to customers that 
have dispatchable resources and that have purchased the Actual Partial 
Product or the Block Product with the Factoring Product.
g. Green Energy Premium
    The Green Energy Premium (GEP) will be available to customers 
purchasing firm power. The GEP will be charged when a customer chooses 
to designate any portion (up to 100 percent) of its Subscription 
purchase as Environmentally Preferred Power.
    The GEP will range from zero to $40/megawatthour depending on the 
specific products and associated costs selected by each customer.
h. Industrial Power Targeted Adjustment Charge (IP TAC)
    BPA is proposing to apply a TAC to all IP sales to cover the 
incremental costs that it incurs from purchasing power to serve loads 
beyond the amount of firm inventory in the augmented FBS. It will apply 
to sales at both 23.5 mills and 25 mills. The IP TAC will prevent the 
transfer of these incremental costs to other customers. It is designed 
to recover costs to keep BPA whole, and is not designed to discourage 
purchases from BPA.
i. Low Density Discount (LDD)
    BPA is continuing to offer the LDD to utilities with low system 
densities, such as rural electric cooperatives with high distribution 
costs resulting from sparsely populated service areas. The LDD 
principles, eligibility criteria, and discount calculation table appear 
in the GRSPs.
j. PF Targeted Adjustment Charge (PF TAC)
    The purpose of the PF TAC is to allow BPA the flexibility of 
passing to customers the incremental cost of unanticipated or 
additional loads that are not embedded in the posted rates for

[[Page 44327]]

the FYs 2002-2006 rate period. The Subscription Strategy indicated that 
BPA would have inventory available during the Subscription window for 
customers. After the window closes, all ``late signers'' or public 
utilities with new or annexed load, including retail access load gain 
or returning load, will be subject to a PF TAC. The PF TAC also applies 
to requests for requirements service for customer loads previously 
served by a customer's own resources. If inventory is available to 
serve the request, the PF TAC is the PF rate. If BPA must buy power to 
serve the load, an adjustment charge reflecting the differences between 
PF-02 and BPA's cost to buy power is added to the PF rate.
    BPA will provide limited exemptions from the PF TAC for those 
customers requesting requirements load previously served by renewable 
resources. In developing the posted rates, BPA is not forecasting that 
it will receive revenues under the PF TAC.
k. Slice True-Up Adjustment
    Under the Subscription Strategy, BPA decided to offer a Slice 
product. Each year, BPA will calculate the difference between the Slice 
Revenue Requirement's audited actual expenses and credits and the 
expenses and credits that are forecast in this rate case. The true-up 
will be a charge to the Slice customer's bill.
l. Unauthorized Increase Charges for Power Sales
    This rate proposal includes separate penalty charges for 
Unauthorized Increases in Energy and Unauthorized Increases in Demand. 
These charges will be applied to deliveries that exceed contractual 
entitlements for energy and demand, respectively. Further details on 
these charges are found in the GRSPs (Part V of this Notice).
m. Value of Reserves
    Section 7(c)(3) of the Northwest Power Act, 16 U.S.C. 839e(c)(3), 
provides that the Administrator shall adjust rates to the direct 
service industrial customers ``to take into account the value of power 
system reserves made available to the Administrator through his rights 
to interrupt or curtail service to such direct service industrial 
customers.'' The DSIs may provide two types of reserves: Supplemental 
Contingency Reserves and Stability Reserves. The Initial Rate proposal 
assumes that Stability Reserves will be purchased by the TBL and 
addressed in TBL's transmission rate case.
    The PBL is proposing a new approach to procuring Supplemental 
Reserves in this rate case. The PBL will purchase the most cost-
effective Supplemental Reserves or provide those reserves itself. No 
Supplemental Reserves are explicitly forecasted to be provided by the 
DSIs in this rate case. Any payment to the DSIs for Supplemental 
Contingency Reserves will be negotiated within a specified range on an 
individual customer basis rather than a credit applied to some or all 
of BPA's DSI load. The range is stated in the IP rate schedule (see 
Part V of this Notice).
5. Development of IP Rate/7(c)(2) Adjustment
    The IP-02 rate applies to firm power sales to BPA's DSI customers, 
including the firm take-or-pay Block Product for DSIs that purchase 
power under 2002 Industrial Firm Power contracts. Rates for the DSIs 
are set according to the rate directives contained in section 7(c) of 
the Northwest Power Act, 16 U.S.C. 839e(c). Section 7(c)(1)(B) provides 
that after July 1, 1985, the DSI rates will be set ``at a level which 
the Administrator determines to be equitable in relation to the retail 
rates charged by the public body and cooperative customers to their 
industrial consumers in the region.'' 16 U.S.C. 839e(c)(1)(B). Pursuant 
to section 7(c)(2), the DSI rates are to be based on BPA's ``applicable 
wholesale rates'' to its preference customers and the ``typical 
margins'' included by those customers in their retail industrial rates. 
16 U.S.C. 839e(c)(2). Section 7(c)(3) provides that the DSI rates are 
also to be adjusted to account for the value of power system reserves 
provided through contractual rights that allow BPA to restrict portions 
of the DSI load. 16 U.S.C. 839e(c)(3). This adjustment is typically 
made through a value of reserves (VOR) credit. As described above, for 
this rate case BPA is not proposing a uniform VOR credit to be applied 
against DSI rates. Thus, the DSI rates shall be set equal to the 
applicable wholesale rate, plus a typical margin, subject to the floor 
rate test. As a final step in rate design, BPA develops monthly and 
diurnally differentiated energy charges and monthly differentiated 
demand charges based on allocated costs and scaled based on the results 
of BPA's Marginal Cost Analysis.
    The typical Industrial Margin is 0.46 mills per kWh. As stated 
above, a zero VOR credit is being forecast in this rate case. Thus, the 
net margin of 0.46 mills per kWh is added to the seasonal and diurnal 
PF energy charges.
    Section 7(c)(2) of the Northwest Power Act requires that the DSI 
rates in the post-1985 period ``shall in no event be less than the 
rates in effect for the contract year ending June 30, 1985.'' 16 U.S.C. 
839e(c)(2). Accordingly, a floor rate test is performed to determine if 
the IP rate has been set at a level below the floor rate. If so, an 
adjustment is made that raises the DSI rate to recover revenues at the 
floor rate and credits other customers with the increased revenue from 
the DSIs. If the DSI rate has been set at a level above the floor rate, 
no floor rate adjustment is necessary.
    The first step in calculating the floor rate is to apply the IP-83 
Standard rate charges to test period (FY 2002--2006) DSI billing 
determinants. The resulting revenue figure is then divided by total IP 
test period loads to arrive at an average rate in mills per kWh. This 
rate is reduced by an Exchange Cost Adjustment and a deferral that were 
included in the IP-83 rate. Both adjustments are made on a mills per 
kWh basis.
    BPA is conducting separate rate cases for power and transmission. 
Therefore, BPA has removed all transmission costs from the IP-83 rate 
to make a power-only floor rate comparison. These calculations result 
in a DSI floor rate of 20.98 mills per kWh. Because the proposed IP 
rate revenues are below the floor rate revenues, an adjustment was 
necessary. Therefore, the IP rate becomes the floor rate.
6. Changes in Methodology
a. AURORA Model
    AURORA is a model used to estimate the variable cost of the 
marginal resource in a competitively priced energy market. In 
competitive market pricing, the marginal cost of production is 
equivalent to the market clearing price, which is the basis for 
determining BPA's bulk power revenues in the rate case.
    AURORA models wholesale energy transactions within a competitive 
market pricing system. AURORA uses a demand forecast and supply cost 
information to estimate marginal cost. To determine the marginal cost 
in a given hour, AURORA models the dispatch of electric generating 
resources in least cost order to meet the load (demand) forecast. The 
price in the given hour is equal to the variable cost of the marginal 
resource. Over time, AURORA adds new resources and retires old 
resources based on the net present value of the resource.
b. Risk Mitigation
    This rate proposal implements the TPP standard that all payments to 
Treasury of the power function be

[[Page 44328]]

recovered through power rates on time and in full over the 5-year rate 
period with 88 percent probability. Payments to Treasury are the lowest 
priority in BPA's priority of payments. For this reason, TPP measures 
the ability to recover costs in a timely fashion.
    BPA has identified and analyzed its power risks and is proposing to 
implement several risk mitigation tools that, taken together, achieve 
an 88 percent TPP: access to the Fish Cost Contingency fund; starting 
FY 2002 financial reserves; a CRAC that adjusts posted rates upward as 
frequently as each year of the five-year rate period if actual 
accumulated net revenues attributable to the generation function fall 
below an accumulated net revenue threshold; and Planned Net Revenues 
for Risk, a component of the revenue requirement that is added to 
planned expenses.
c. Rates Analysis Model (RAM)
    The RAM has been modified to have two steps. The first is the Rate 
Design Step, which uses the Northwest Power Act's rate directives to 
calculate posted rates, including the NR-02 rate and the PF Exchange 
Program rate. In this first step, BPA calculates rates by: (1) 
allocating costs to rate pools as noted in the Cost of Service Analysis 
(COSA); (2) adjusting these results to reflect revenue credits and 
statutory rate directives; and (3) using the marginal cost of power 
values to shape the annual costs into energy rates across months and 
time-of-day. In the second step, the Subscription Step, BPA adjusts the 
rates calculated from the first step to reflect the Subscription 
Strategy and to produce Subscription power rates.
7. Adjustment to PF-96: Targeted Adjustment Charge for Uncommitted 
Loads
    The Targeted Adjustment Charge for Uncommitted Loads (TACUL) 
applies to purchases from BPA to serve customer loads that were 
uncommitted during the 1996 rate case due primarily to the 
diversification of customer loads. Uncommitted loads returning to BPA 
firm power requirements service from January 2001, through to the 
beginning of the 2002 rate period, will be subject to TACUL. The TACUL 
will prevent the erosion of reserves that could occur from additional 
costs of power purchases that may be required to meet customer returned 
load.
    BPA is currently facing an energy deficit during the time period 
January 2001 to September 2001, and could face even greater deficits 
should BPA receive additional requests by customers to serve returning 
uncommitted load. These incremental loads will be charged the PF 
Preference (PF-96) rate, plus the TACUL, which is an adjustment charge 
reflecting the difference between the PF-96 rate and BPA's cost to 
supply this power. BPA will calculate the cost for the TACUL at the 
time a customer requests power or requests BPA to price power already 
purchased under this schedule. The TACUL will be finalized prior to 
signing of the final contract or before initial delivery. The TACUL 
will expire with the PF-96 rate schedule.
8. Payment of Non-Federal Transmission Costs for GTA Customers' Federal 
and Non-Federal Power Purchases
    BPA's PBL and TBL are proposing to pay the non-Federal transmission 
cost for customers' Federal and non-Federal power purchases, 
respectively. PBL's and TBL's proposals are separate and distinct from 
one another.
    PBL proposes to continue existing GTA service to current loads for 
delivery of Federal power through the FY 2001-2006 rate period. 
Continuation of GTA service for Federal power deliveries is consistent 
with BPA's historical practice and helps promote the widespread use of 
Federal power. The GTA costs associated with delivery of Federal power 
will be borne by PBL and are estimated to be around $42 million per 
year through the rate period.
    TBL proposes to pay up to $6.5 million annually for non-Federal 
transmission to allow preference and DSI customers who have 
historically been served by GTAs to avoid ``pancaked'' transmission 
rates when serving their loads with non-Federal power. BPA proposes 
that the forecasted non-Federal transmission cost (up to the cap of 
$6.5 million) for GTA customers' non-Federal power purchases will be 
included in cost of the Network segment, or its successor, when it 
develops its transmission rate proposal. This rate treatment is 
included in the power rate case to resolve all issues that affect GTA 
customers and to enable GTA customers to make informed power purchase 
decisions.

B. Studies in Support of Initial Proposal

    The studies that have been prepared to support BPA's 2002 Initial 
Wholesale Power Rate proposal are described in detail in this section.

Loads and Resources Study and Documentation (Study about 100 pages, 
documentation about 500 pages)
Revenue Requirement Study and Documentation (Study about 250 pages, 
documentation about 700 pages)
Risk Analysis Study and Documentation (Study and documentation are 
combined, approximately 130 pages)
Marginal Cost Analysis Study and Documentation (Study about 50 pages, 
documentation about 400 pages)
Wholesale Power Rate Development Study and Documentation (Study about 
175 pages, documentation about 700 pages)
Section 7(b)(2) Rate Test Study and Documentation (Study about 50 
pages, documentation about 350 pages)
1. Loads and Resources Study
    The Loads and Resources Study represents the compilation of the 
load and resource data necessary for developing BPA's wholesale power 
rates. The Study has three major interrelated components: (a) BPA's 
Federal system load forecast; (b) BPA's Federal system resource 
forecast; and (c) the Federal system load and resource balances.
    The Federal system load forecast is composed of customer group 
sales forecasts for public utilities and Federal agencies, DSIs, IOUs, 
and other BPA contractual obligations.
    The Federal system resource forecast includes power generated by 
both Federal and non-Federal hydroprojects, return energy associated 
with BPA's existing capacity-for-energy exchanges, contracted 
resources, and other BPA hydrorelated contracts. The Federal system 
hydroresource estimates are derived from a hydroregulation study that 
estimates generation under 50 water conditions using the operating 
provisions of the Pacific Northwest Coordination Agreement. The 
seasonal shape and magnitude of the Federal system hydro generation 
depends on availability of all regional resources and coordination of 
those resources to meet regional loads.
    The projections of Federal system resources are compared with 
projected Federal system firm loads for each month of Operating Years 
2002-2007 (August 2001-July 2007) under 1937 water conditions. The 
resulting load and resource balances yield the firm energy surplus or 
deficit of the Federal system resources. Similarly, firm capacity 
surpluses and deficits are determined for the same period.
2. Revenue Requirement Study
    The purpose of the Revenue Requirement Study is to establish the 
level of revenues from wholesale power rates necessary to recover, in 
accordance with sound business principles, the FCRPS costs associated 
with the

[[Page 44329]]

production, acquisition, marketing, and conservation of electric power. 
Power revenue requirements include recovery of the Federal investment 
in hydrogeneration, fish and wildlife recovery, and conservation; 
Federal agencies' operations and maintenance expenses allocated to 
power; capitalized contract expenses associated with such non-Federal 
power suppliers as Energy Northwest (formerly known as the Supply 
System); other purchase power expenses, such as short-term power 
purchases; power marketing expenses; cost of transmission services 
necessary for the sale and delivery of FCRPS power; and all other 
power-related costs incurred by the Administrator pursuant to law.
    Cost estimates reflect implementation of Cost Review 
recommendations, the Principles, and certain components of the 
Subscription Strategy. No change in repayment policy or practice is 
proposed. The repayment study reflects actual implementation of the 
Appropriations Refinancing Act and a number of updates to actual and 
projected new repayment obligations. All new capital investments are 
assumed to be financed with debt or appropriations. The study includes 
a substantial level of planned net revenues to mitigate financial risk. 
This risk mitigation tool, in combination with other risk mitigation 
tools such as starting financial reserves, CRAC, and access to the 
FCCF, is designed to achieve the 88 percent TPP standard. The adequacy 
of projected revenues to recover test period revenue requirements and 
to meet repayment period recovery of the Federal investments is tested 
and demonstrated for the generation function.
3. Risk Analysis Study
    The Risk Analysis Study evaluates both operational and non-
operational risks. The portion addressing operational risks evaluates 
impacts of economic and generation resource capability variations on 
BPA's ability to meet its annual U.S. Treasury payment during the rate 
test period. The portion addressing non-operational risks evaluates the 
impacts of uncertainties in cost projections in the revenue 
requirement. The results are used to support the amount of planned net 
revenues for risk that are included in the revenue requirement. The 
risk variations are tested through the use of several risk simulation 
models including RiskMod, which quantifies net revenue risk; RevSim, a 
revenue and expense estimation model; RiskSim, a data management model; 
and the Non-Operating Risk Model (NORM), which quantifies the non-
operating risks. The Risk Analysis, through the use of these models, 
captures the range of ordinary risks that BPA could reasonably expect 
to face during the rate test period. The models do not attempt to 
capture and measure the effects of extraordinary and/or unquantifiable 
risks such as State or Federal electricity deregulation legislation.
    The Risk Analysis Study, with input from the Marginal Cost Analysis 
(MCA), is also used for estimating purchase power expense and secondary 
revenues.
4. Marginal Cost Analysis (MCA)
    The MCA estimates the hourly variable cost of the marginal resource 
for transactions in wholesale energy market. The specific market used 
in this analysis is at the Mid-Columbia trading hub in the State of 
Washington.
    The MCA is used for two purposes in the BPA rate case. First, the 
MCA is the basis for approximating the prices BPA may experience in the 
bulk power market. The MCA estimates are therefore used to inform, but 
not to directly set, the price used in BPA's bulk revenue forecast. 
Second, the MCA represents BPA's marginal cost in acquiring new energy, 
or the opportunity cost BPA may see in selling wholesale energy. The 
MCA is therefore used in rate design to send market based price 
signals.
    The MCA uses a production cost model, AURORA, to estimate a market 
clearing price for wholesale energy. The fundamental theory behind this 
model is based on a competitive wholesale energy pricing structure. The 
model dispatches resources in a least cost order to meet a specified 
demand. Short-term prices are set at the variable cost of the marginal 
generator. Long-term capital investment decisions are based on economic 
profitability in an unregulated environment.
5. Wholesale Power Rate Development Study
    The Wholesale Power Rate Development Study (WPRDS) is the primary 
source for details of the rates, reflecting the results of all the 
other studies. It documents the Rates Analysis Model and designs rates 
for BPA's wholesale power products and services. The WPRDS documents 
the development of Slice costs; the development and forecast of inter-
business line revenues and costs; the development of charges for 
demand, load variance, unauthorized increase charges, and excess 
factoring charges, and the development of the three and two year rates. 
The end results of the WPRDS are the wholesale power rate schedules.
6. Section 7(b)(2) Rate Test Study
    Section 7(b)(2) of the Northwest Power Act directs BPA to assure 
that the wholesale power rates effective after July 1, 1985, to be 
charged its public body, cooperative, and Federal agency customers (the 
7(b)(2) Customers) for their general requirements for the rate test 
period, plus the ensuing four years, are no higher than the costs of 
power to those customers would be for the same time period if specified 
assumptions are made. The effect of the rate test is to protect the 
7(b)(2) Customers' wholesale firm power rates from certain costs 
resulting from provisions of the Northwest Power Act. The rate test can 
result in a reallocation of costs from the 7(b)(2) Customers to other 
rate classes. The Section 7(b)(2) Rate Test Study describes the 
application and results of the Section 7(b)(2) Implementation 
Methodology.
    The Section 7(b)(2) rate test triggers in this proposal, causing 
costs to be reallocated in the test period. The PF Preference rate 
applied to the general requirements of the 7(b)(2) Customers has been 
reduced by the 7(b)(2) amount while other rates, including the PF 
Exchange Program rate applied to customers purchasing under the 
Residential Exchange Program, have been increased by an allocation of 
the 7(b)(2) amount.

Part V--2002 Wholesale Power Rate Schedules

A. Introduction

    BPA's 2002 Wholesale Power Rate Schedules cover five different 
rates:

PF-02: Priority Firm Power Rate
RL-02: Residential Load Firm Power Rate
NR-02: New Resource Firm Power Rate
IP-02: Industrial Firm Power Rate
NF-02: Nonfirm Energy Rate

    The following section (Part B below) contains BPA's proposed 2002 
wholesale power rate schedules, BPA's proposed 2002 GRSPs for power 
rates, and the new 1996 GRSP for the Targeted Adjustment Charge for 
uncommitted loads.
    The proposed wholesale power rate schedules 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).

[[Page 44330]]

    BPA's 2002 proposed wholesale power rate schedules and the GRSPs 
associated with those rate schedules 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 wholesale power rate schedules, including the GRSPs 
associated with these rate schedules, 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 rates 
effective October 1, 2001.

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

Schedule PF-02

Section I. Availability

    This schedule is available for the contract purchase of Firm Power 
or capacity to be used within the Pacific Northwest. Priority Firm 
Power may be purchased by public bodies, cooperatives, and Federal 
agencies for resale to ultimate consumers; for direct consumption; and 
for Construction, Test and Start-Up, and Station Service. Rates in this 
schedule are in effect beginning October 1, 2001, and are available for 
purchase under requirements Firm Power sales contracts for a three or 
five-year period. The Slice Product is only available for public bodies 
and cooperatives. Utilities participating in the Residential Exchange 
Program under section 5(c) of the Northwest Power Act may purchase 
Priority Firm Power pursuant to the Residential Exchange Program. 
Utilities participating in settlement of the Residential Exchange 
Program may purchase Priority Firm Power pursuant to their Subscription 
settlement agreement. Rates under contracts that contain charges that 
escalate based on BPA's Priority Firm Power rates shall be based on the 
five-year rates listed in this rate schedule in addition to applicable 
transmission charges.
    Sales under the PF Exchange Subscription rate will be delivered in 
equal hourly amounts over the rate period. The consumer bills of 
participating IOUs should designate ``Benefits of the Federal Columbia 
River Power System (FCRPS)'' to describe the amount of benefits each 
consumer receives. Only the block product is available under this rate 
schedule.
    This rate schedule supersedes the PF-96 rate schedule, which went 
into effect October 1, 1996. Sales under the PF-02 rate schedule are 
subject to BPA's 2002 General Rate Schedule Provisions (2002 GRSPs). 
Products available under this rate schedule are defined in the 2002 
GRSPs. For sales under this rate schedule, bills shall be rendered and 
payments due pursuant to BPA's 2002 GRSPs and billing process.

Section II. Rates Tables

    The rates in this section apply to PF products. The PF Exchange 
Program rates and the PF Exchange Subscription rates are shown in 
Section III.
A. Demand Rate
1. Monthly Demand Rate for FY 2002 Through FY 2006
1.1  Applicability
    These rates apply to customers purchasing Firm Power for three or 
five years. These rates are also used to implement the Pre-Subscription 
Contracts.
1.2  Rate Table

------------------------------------------------------------------------
                                                               Rate  (kW-
                      Applicable months                           mo)
------------------------------------------------------------------------
January......................................................      $2.14
February.....................................................       2.06
March........................................................       1.96
April........................................................       1.37
May..........................................................       1.32
June.........................................................       1.69
July.........................................................       2.12
August.......................................................       2.44
September....................................................       2.28
October......................................................       1.90
November.....................................................       2.31
December.....................................................       2.40
------------------------------------------------------------------

B. Energy Rate
1. Monthly Energy Rates for FY 2002 Through FY 2004
1.1  Applicability
    These rates apply to customers purchasing power in the first three 
years of the rate period.
1.2  Rate Table

------------------------------------------------------------------------
                                                     HLH rate   LLH Rate
                 Applicable months                   (mills/    (mills/
                                                       kWh)       kWh)
------------------------------------------------------------------------
January...........................................      19.06      13.45
February..........................................      17.95      12.84
March.............................................      17.18      12.09
April.............................................      11.64       8.55
May...............................................      11.21       7.02
June..............................................      14.51       8.61
July..............................................      18.85      15.60
August............................................      29.24      19.23
September.........................................      20.09      19.40
October...........................................      16.68      13.35
November..........................................      20.56      17.77
December..........................................      21.40      17.67
------------------------------------------------------------------------

2. Monthly Energy Rates for FY 2005 Through FY 2006
2.1  Applicability
    These rates apply to purchases during the last two years of the 
rate period for customers purchasing for all five years of the rate 
period.
2.2  Rate Table

------------------------------------------------------------------------
                                                     HLH rate   LLH Rate
                 Applicable months                   (mills/    (mills/
                                                       kWh)       kWh)
------------------------------------------------------------------------
January...........................................      20.56      14.95
February..........................................      19.45      14.34
March.............................................      18.68      13.59
April.............................................      13.14      10.05
May...............................................      12.71       8.52
June..............................................      16.01      10.11
July..............................................      20.35      17.10
August............................................      30.74      20.73
September.........................................      21.59      20.90
October...........................................      18.18      14.85
November..........................................      22.06      19.27
December..........................................      22.90      19.17
------------------------------------------------------------------------

3. Monthly Energy Rates for FY 2002 Through FY 2006
3.1  Applicability
    These rates are used to implement the Pre-Subscription Contracts. 
These rates are also available to customers purchasing for all five 
years of the rate period under this rate table.
3.2  Rate Table

------------------------------------------------------------------------
                                                     HLH rate   LLH Rate
                 Applicable months                   (mills/    (mills/
                                                       kWh)       kWh)
------------------------------------------------------------------------
January...........................................      19.66      14.05
February..........................................      18.55      13.44
March.............................................      17.78      12.69
April.............................................      12.24       9.15
May...............................................      11.81       7.62
June..............................................      15.11       9.21
July..............................................      19.45      16.20
August............................................      29.84      19.83
September.........................................      20.69      20.00
October...........................................      17.28      13.95
November..........................................      21.16      18.37
December..........................................      22.00      18.27
------------------------------------------------------------------------

C.  Load Variance Rate
    The Load Variance rate for FY 2002 through FY 2006 applies to all 
customers purchasing power under this rate schedule unless specifically 
excluded in Section IV below. The rate for Load Variance is 0.8 mills/
kWh.
D. Slice Rate
    The monthly rate for the Slice Product is $1,381,390 per 1 percent 
of the Slice System.

[[Page 44331]]

Section III. PF Exchange Rate Tables

    The rates in this section apply to sales under the Residential 
Exchange Program and the Subscription settlements of the Residential 
Exchange Program.
A. Demand Rate
1. Monthly Demand Rate for FY 2002 Through FY 2006
1.1  Applicability
    These rates apply to customers purchasing power for all five years 
of the rate period under the Residential Exchange Program and to 
customers purchasing power for all five years of the rate period under 
Subscription settlements of the Residential Exchange Program.
1.2  Rate Table

------------------------------------------------------------------------
                                                               Rate  kW-
                      Applicable months                            mo
------------------------------------------------------------------------
January......................................................      $2.14
February.....................................................       2.06
March........................................................       1.96
April........................................................       1.37
May..........................................................       1.32
June.........................................................       1.69
July.........................................................       2.12
August.......................................................       2.44
September....................................................       2.28
October......................................................       1.90
November.....................................................       2.31
December.....................................................       2.40
------------------------------------------------------------------------

B. Energy Rate
1. PF Exchange Program Energy Rates for FY 2002 Through FY 2006
1.1  Applicability
    These rates apply to customers purchasing power for all five years 
of the rate period under the Residential Exchange Program.
1.2  Rate Table

------------------------------------------------------------------------
                                                                 Energy
                      Applicable months                           rate
                                                               mills/kWh
------------------------------------------------------------------------
January......................................................      30.11
February.....................................................      28.67
March........................................................      27.52
April........................................................      19.68
May..........................................................      18.14
June.........................................................      22.80
July.........................................................      31.49
August.......................................................      45.01
September....................................................      35.08
October......................................................      27.78
November.....................................................      34.58
December.....................................................      35.43
------------------------------------------------------------------------

2. PF Exchange Subscription Energy Rates for FY 2002 Through FY 2006
2.1  Applicability
    These rates apply to eligible customers purchasing power under 
Subscription settlements of the Residential Exchange Program for all 
five years of the rate period.
2.2  Rate Table

------------------------------------------------------------------------
                                                     HLH Rate   LLH rate
                 Applicable months                  mills/kWh  mills/kWh
------------------------------------------------------------------------
January...........................................      19.66      14.05
February..........................................      18.55      13.44
March.............................................      17.78      12.69
April.............................................      12.24       9.15
May...............................................      11.81       7.62
June..............................................      15.11       9.21
July..............................................      19.45      16.20
August............................................      29.84      19.83
September.........................................      20.69      20.00
October...........................................      17.28      13.95
November..........................................      21.16      18.37
December..........................................      22.00      18.27
------------------------------------------------------------------------

C. Load Variance Rate
    The Load Variance rate for FY 2002 through FY 2006 applies to all 
customers purchasing power under this rate schedule unless specifically 
excluded in Section IV.H below. The rate for Load Variance is 0.8 
mills/kWh.

Section IV

    The rates described above apply to the following:

Section IV.A.  Full Service Product
Section IV.B.  Actual Partial Service Product--Simple
Section IV.C.  Actual Partial Service Product--Complex
Section IV.D.  Block Product
Section IV.E.  Block Product with Factoring
Section IV.F.  Block Product with Shaping Capacity
Section IV.G.  Slice Product
Section IV.H.  Customers who purchase under the Residential Exchange 
Program or Subscription settlements of the Residential Exchange Program
    1. Priority Firm Exchange Program Power
    2. Priority Firm Exchange Subscription Power
A. Full Service Product
    Purchases of the core Subscription Full Service Product are subject 
to the charges specified below.
1. Priority Firm Power
1.1  Demand Charge
    The charge for Demand will be:

The Purchaser's Measured Demand on the Generation System Peak as 
specified in the contract multiplied by the Demand Rate from Section 
II.A.
1.2  Energy Charge
    The total monthly charge for energy will be the sum of (1) and (2):

(1) The Purchaser's HLH Energy Entitlement as specified in the contract 
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract 
multiplied by the LLH Energy Rate from Section II.B.
1.3  Load Variance Charge
    The charge for Load Variance will be:

The Purchaser's Total Retail Load for the billing period multiplied by 
the Load Variance Rate from Section II.C.
2. Adjustments, Charges, and Special Rate Provisions
    Adjustments, Charges, and Special Rate Provisions are described in 
the 2002 GRSPs. Relevant sections are identified below.

------------------------------------------------------------------------
   Adjustments, charges, and special rate
                 provisions                       2002  GRSP  section
------------------------------------------------------------------------
Conservation and Renewables Discount........  II.A.
Conservation Surcharge......................  II.B.
Cost-Based Indexed PF Rate..................  II.D.
Cost Contributions..........................  II.E.
Cost Recovery Adjustment Clause.............  II.F.
Dividend Distribution Clause................  II.H.
Flexible PF Rate Option.....................  II.L.
Green Energy Premium........................  II.M.
Low Density Discount........................  II.P.
Rate Melding................................  II.Q.
Targeted Adjustment Charge..................  II.U.
Unauthorized Increase Charge................  II.V.
------------------------------------------------------------------------

B. Actual Partial Service Product--Simple
    Purchases of the core Subscription Actual Partial Service Product--
Simple are subject to the charges specified below.
1. Priority Firm Power
1.1  Demand Charge
    The charge for Demand will be:

(the Purchaser's Demand Entitlement multiplied by a Demand Adjuster) as 
specified in the contract multiplied by the Demand Rate from Section 
II.A.
1.2  Energy Charge
    The total monthly charge for energy will be the sum of (1) and (2):

(1) The Purchaser's HLH Energy Entitlement as specified in the contract 
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract 
multiplied by the LLH Energy Rate from Section II.B.
1.3  Load Variance Charge
    The charge for Load Variance will be:


[[Page 44332]]


The Purchaser's Total Retail Load for the billing period multiplied by 
the Load Variance Rate from Section II.C.
2. Adjustments, Charges, and Special Rate Provisions
    Adjustments, Charges, and Special Rate Provisions are described in 
the 2002 GRSPs. Relevant sections are identified below.

------------------------------------------------------------------------
   Adjustments, charges, and special rate
                 provisions                       2002  GRSP  section
------------------------------------------------------------------------
Conservation and Renewables Discount........  II.A.
Conservation Surcharge......................  II.B.
Cost-Based Indexed PF Rate..................  II.D.
Cost Contributions..........................  II.E.
Cost Recovery Adjustment Clause.............  II.F.
Dividend Distribution Clause................  II.H.
Flexible PF Rate Option.....................  II.L.
Green Energy Premium........................  II.M.
Low Density Discount........................  II.P.
Rate Melding................................  II.Q.
Targeted Adjustment Charge..................  II.U.
Unauthorized Increase Charge................  II.V.
------------------------------------------------------------------------

C. Actual Partial Service Product--Complex
    Purchases of the core Subscription Actual Partial Service Product--
Complex are subject to the charges specified below.
1. Priority Firm Power
1.1  Demand Charge
    The charge for Demand will be:

(The Purchaser's Demand Entitlement multiplied by a Demand Adjuster) as 
specified in the contract multiplied by the Demand Rate from Section 
II.A.
1.2  Energy Charge
    The total monthly charge for energy will be the sum of (1) and (2):

(1) The Purchaser's HLH Energy Entitlement as specified in the contract 
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract 
multiplied by the LLH Energy Rate from Section II.B.
1.3  Load Variance Charge
    The charge for Load Variance will be:

The Purchaser's Total Retail Load for the billing period multiplied by 
the Load Variance Rate from Section II.C.
2. Adjustments, Charges, and Special Rate Provisions
    Adjustments, Charges, and Special Rate Provisions are described in 
the 2002 GRSPs. Relevant sections are identified below.

------------------------------------------------------------------------
   Adjustments, charges, and special rate
                 provisions                       2002  GRSP  Section
------------------------------------------------------------------------
Conservation and Renewables Discount........  II.A.
Conservation Surcharge......................  II.B.
Cost-Based Indexed PF Rate..................  II.D.
Cost Contributions..........................  II.E.
Cost Recovery Adjustment Clause.............  II.F.
Dividend Distribution Clause................  II.H.
Excess Factoring Charge.....................  II.I.
Flexible PF Rate Option.....................  II.L.
Green Energy Premium........................  II.M.
Low Density Discount........................  II.P.
Rate Melding................................  II.Q.
Targeted Adjustment Charge..................  II.U.
Unauthorized Increase Charge................  II.V.
------------------------------------------------------------------------

D. Block Product
    Purchases of the core Subscription Block Product are subject to the 
charges specified below.
1. Priority Firm Power
1.1  Demand Charge
    The charge for Demand will be:

The Purchaser's Demand Entitlement as specified in the contract 
multiplied by the Demand Rate from Section II.A.
1.2  Energy Charge
    The total monthly charge for energy will be the sum of (1) and (2):

(1) The Purchaser's HLH Energy Entitlement as specified in the contract 
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract 
multiplied by the LLH Energy Rate from Section II.B.
1.3  Load Variance Charge
    Not applicable to Block purchases unless the customer is also 
purchasing another product to which Load Variance is applicable as 
specified by contract.
2. Adjustments, Charges, and Special Rate Provisions
    Adjustments, Charges, and Special Rate Provisions are described in 
the 2002 GRSPs. Relevant sections are identified below.

------------------------------------------------------------------------
   Adjustments, charges, and special rate
                 provisions                       2002  GRSP  section
------------------------------------------------------------------------
Conservation and Renewables Discount........  II.A.
Conservation Surcharge......................  II.B.
Cost-Based Indexed PF Rate..................  II.D.
Cost Contributions..........................  II.E.
Cost Recovery Adjustment Clause.............  II.F.
Dividend Distribution Clause................  II.H.
Flexible PF Rate Option.....................  II.L.
Green Energy Premium........................  II.M.
Low Density Discount........................  II.P.
Rate Melding................................  II.Q.
Stepped Up Multiyear Block (SUMY)...........  II.S.
Targeted Adjustment Charge..................  II.U.
Unauthorized Increase Charge................  II.V.
------------------------------------------------------------------------

E. Block Product With Factoring
    Purchases of the core Subscription Block Product with Factoring are 
subject to the charges specified below.
1. Priority Firm Power
1.1  Demand Charge
    The charge for Demand will be:

(The Purchaser's Demand Entitlement multiplied by a Demand Adjuster) as 
specified in the contract multiplied by the Demand Rate from Section 
II.A.
1.2  Energy Charge
    The total monthly charge for energy will be the sum of (1) and (2):

(1) The Purchaser's HLH Energy Entitlement as specified in the contract 
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract 
multiplied by the LLH Energy Rate from Section II.B.
1.3  Load Variance Charge
    Not applicable to Block purchases unless the customer is also 
purchasing another product to which Load Variance is applicable as 
specified by contract.
2. Adjustments, Charges, and Special Rate Provisions
    Adjustments, Charges, and Special Rate Provisions are described in 
the 2002 GRSPs. Relevant sections are identified below.

------------------------------------------------------------------------
   Adjustments, charges, and special rate
                 provisions                       2002  GRSP  section
------------------------------------------------------------------------
Conservation and Renewables Discount........  II.A.
Conservation Surcharge......................  II.B.
Cost-Based Indexed PF Rate..................  II.D.
Cost Contributions..........................  II.E.
Cost Recovery Adjustment Clause.............  II.F.
Dividend Distribution Clause................  II.H.
Excess Factoring Charge.....................  II.I.
Flexible PF Rate Option.....................  II.L.
Green Energy Premium........................  II.M.
Low Density Discount........................  II.P.
Rate Melding................................  II.Q.
Stepped Up Multiyear Block (SUMY)...........  II.S.
Targeted Adjustment Charge..................  II.U.
Unauthorized Increase Charge................  II.V.
------------------------------------------------------------------------

F. Block Product With Shaping Capacity
    Purchases of the core Subscription Block Product with Shaping 
Capacity

[[Page 44333]]

are subject to the charges specified below.
1. Priority Firm Power
1.1  Demand Charge
    The charge for Demand will be:

The Purchaser's Demand Entitlement as specified in the contract 
multiplied by the Demand Rate from Section II.A.
1.2  Energy Charge
    The total monthly charge for energy will be the sum of (1) and (2):

(1) The Purchaser's HLH Energy Entitlement as specified in the contract 
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract 
multiplied by the LLH Energy Rate from Section II.B.
1.3  Load Variance Charge
    Not applicable to Block purchases unless the customer is also 
purchasing another product to which Load Variance is applicable as 
specified by contract.
2. Adjustments, Charges, and Special Rate Provisions
    Adjustments, Charges, and Special Rate Provisions are described in 
the 2002 GRSPs. Relevant sections are identified below.

------------------------------------------------------------------------
   Adjustments, charges, and special rate
                 provisions                       2002 GRSP  section
------------------------------------------------------------------------
Conservation and Renewables Discount........  II.A.
Conservation Surcharge......................  II.B.
Cost-Based Indexed PF Rate..................  II.D.
Cost Contributions..........................  II.E.
Cost Recovery Adjustment Clause.............  II.F.
Dividend Distribution Clause................  II.H.
Flexible PF Rate Option.....................  II.L.
Green Energy Premium........................  II.M.
Low Density Discount........................  II.P.
Rate Melding................................  II.Q.
Stepped Up Multiyear Block (SUMY)...........  II.S.
Targeted Adjustment Charge..................  II.U.
Unauthorized Increase Charge................  II.V.
------------------------------------------------------------------------

G. Slice Product
    Purchases of the Subscription Slice Product are limited to Public 
Body Customers and are subject to the charges specified below.
1. Slice Product Charge
    The charge for the Slice Product will be:

The elected Slice Percentage expressed as a decimal (.01 = 1%) 
multiplied by 100 multiplied by the Slice Rate in Section II.D.
2. Adjustments, Charges, and Special Rate Provisions
    Adjustments, Charges, and Special Rate Provisions are described in 
the 2002 GRSPs. Relevant sections are identified below.

------------------------------------------------------------------------
   Adjustments, charges, and special rate
                 provisions                       2002  GRSP  section
------------------------------------------------------------------------
Conservation and Renewables Discount........  II.A.
Cost-Based Indexed PF Rate..................  II.D.
Cost Contributions..........................  II.E.
Low Density Discount........................  II.P.
Slice True-Up Adjustment....................  II.R.
Unauthorized Increase Charge................  II.V.
------------------------------------------------------------------------

H. Customers Who Purchase Under Residential Exchange Program or 
Subscription Settlements of the Residential Exchange Program
    The PF Exchange rates include: (1) the PF Exchange Program rate; 
and (2) the PF Exchange Subscription rate.
1. Priority Firm Exchange Program Power
    This PF Exchange Program rate applies to the traditional 
implementation of the Residential Exchange Program.
a. Priority Firm Exchange Program Power Charges
1.1  Demand Charge
    The charge for Demand will be:

(The Purchaser's Billing Demand, which is calculated by applying the 
load factor, determined as specified in the Residential Exchange 
Program agreement, to the Billing Energy for each billing period) 
multiplied by the Demand Rate from Section III.A.
1.2  Energy Charge
    The monthly charge for energy will be:

(The Purchaser's Billing Energy, which is the energy associated with 
the utility's residential load for each billing period computed in 
accordance with the provisions of the Purchaser's Residential Exchange 
Program agreement) multiplied by the Energy Rate from Section III.B.1.
1.3  Load Variance Charge
    The charge for Load Variance is embedded in the energy charge.
b. Transmission Charges
    Customers purchasing under this rate schedule are charged for 
transmission services under the NT rate schedule or its successor.
    Customers purchasing under this rate schedule are charged for Load 
Regulation under the applicable charge established by the TBL or its 
successor.
c. Adjustments, Charges, and Special Rate Provisions

------------------------------------------------------------------------
                                                                  2002
      Adjustments, charges, and special rate provisions           GRSP
                                                                section
------------------------------------------------------------------------
Conservation and Renewables Discount.........................      II.A.
Conservation Surcharge.......................................      II.B.
Cost Contributions...........................................      II.E.
Cost Recovery Adjustment Clause..............................      II.F.
Dividend Distribution Clause.................................      II.H.
Green Energy Premium.........................................      II.M.
Low Density Discount.........................................      II.P.
Unauthorized Increase Charge.................................      II.V.
------------------------------------------------------------------------

2. Priority Firm Exchange Subscription Power
    This PF Exchange Subscription rate applies to sales under section 
5(c) of the Northwest Power Act to investor-owned utilities (IOU) that 
participate in a settlement of the Residential Exchange Program as 
described in BPA's Subscription Strategy.
a. Priority Firm Exchange Subscription Power Charges
1.1  Demand Charge
    The charge for Demand will be:

The Purchaser's Contract Demand multiplied by the Demand Rate from 
Section III.A.
1.2  Energy Charge
    The total monthly charge for energy will be the sum of (1) and (2):

(1) The Purchaser's HLH Contract Energy multiplied by the HLH Energy 
Rate from Section III.B.2.
(2) The Purchaser's LLH Contract Energy multiplied by the LLH Energy 
Rate from Section III.B.2.
1.3  Load Variance Charge
    Not applicable.
b. Adjustments, Charges, and Special Rate Provisions

------------------------------------------------------------------------
                                                                  2002
      Adjustments, charges, and special rate provisions           GRSP
                                                                section
------------------------------------------------------------------------
Conservation and Renewables Discount.........................      II.A.
Conservation Surcharge.......................................      II.B.
Cost-Based Indexed PF Rate...................................      II.D.
Cost Contributions...........................................      II.E.
Cost Recovery Adjustment Clause..............................      II.F.
Dividend Distribution Clause.................................      II.H.
Green Energy Premium.........................................      II.M.
Low Density Discount.........................................      II.P.
Unauthorized Increase Charge.................................      II.V.
------------------------------------------------------------------------

Section IV. Transmission
    All customers will need to obtain transmission for delivery of 
products

[[Page 44334]]

listed under this rate schedule, except for the exchange product listed 
under Section IV.H.1.

Schedule RL-02

Residential Load Firm Power Rate

Section I. Availability

    This schedule is available for the contract purchase of Firm Power 
to be used within the Pacific Northwest. The Residential Load (RL) Firm 
Power Rate is available to investor-owned utilities (IOUs) under net 
requirement contracts for resale to ultimate residential consumers for 
direct consumption. Further, in order to purchase under this rate, the 
IOU must agree to waive its right to request benefits under section 
5(c) of the Northwest Power Act for the term of the contract. Each IOU 
will be able to purchase a specified amount of Firm Power at the RL-02 
rate. Additional sales of requirements power to IOUs will be made at 
the NR-02 rate.
    The product will be delivered in equal hourly amounts over the rate 
period. The consumer bills of participating IOUs should designate 
``Benefits of the Federal Columbia River Power System (FCRPS)'' to 
describe the amount of benefits each consumer receives.
    Rates in this schedule are available for purchases under 
requirements sales contracts for a five-year period. Only the block 
product is available under this rate schedule. Sales under this 
schedule are subject to BPA's 2002 General Rate Schedule Provisions 
(2002 GRSPs) and billing process.

Section II. Rates Tables

    The rates for the RL Firm Power product are identified below.
A. Demand Rate
1. Monthly Demand for FY 2002 through FY 2006
1.1  Applicability
    These rates apply to eligible customers purchasing power for five 
years.
1.2  Rate Table

------------------------------------------------------------------------
                                                               Rate (kW-
                      Applicable months                           mo)
------------------------------------------------------------------------
January......................................................      $2.14
February.....................................................       2.06
March........................................................       1.96
April........................................................       1.37
May..........................................................       1.32
June.........................................................       1.69
July.........................................................       2.12
August.......................................................       2.44
September....................................................       2.28
October......................................................       1.90
November.....................................................       2.31
December.....................................................       2.40
------------------------------------------------------------------------

B. Energy Rate
1. Monthly Energy Rates for FY 2002 Through FY 2006
1.1  Applicability
    These rates apply to eligible customers purchasing power for all 
five years of the rate period.
1.2  Rate Table

------------------------------------------------------------------------
                                                    HLH  rate  LLH  rate
                 Applicable months                    (mills/   (mills/
                                                       kWh)       kWh)
------------------------------------------------------------------------
January...........................................      19.66      14.05
February..........................................      18.55      13.44
March.............................................      17.78      12.69
April.............................................      12.24       9.15
May...............................................      11.81       7.62
June..............................................      15.11       9.21
July..............................................      19.45      16.20
August............................................      29.84      19.83
September.........................................      20.69      20.00
October...........................................      17.28      13.95
November..........................................      21.16      18.37
December..........................................      22.00      18.27
------------------------------------------------------------------------

C. Load Variance Rate
    Not applicable.

Section III. Billing Factors and Adjustments

    Eligible customers purchasing power under a contract implementing 
Subscription settlements of the Residential Exchange Program are 
subject to the charges specified below.
1. Residential Load Firm Power
1.1  Demand Charge
    The charge for Demand will be:

The Purchaser's Contract Demand multiplied by the Demand Rate from 
Section II.A.
1.2  Energy Charge
    The total monthly charge for energy will be the sum of (1) and (2):
(1) The Purchaser's HLH Contract Energy multiplied by the HLH Energy 
Rate from Section II.B; and
(2) The Purchaser's LLH Contract Energy multiplied by the LLH Energy 
Rate from Section II.B.
2. Adjustments, Charges, and Special Rate Provisions
    Adjustments, Charges, and Special Rate Provisions are described in 
the 2002 GRSPs. Relevant sections are identified below.

------------------------------------------------------------------------
                                                                  2002
      Adjustments, charges, and special rate provisions           GRSP
                                                                section
------------------------------------------------------------------------
Conservation and Renewables Discount.........................      II.A.
Conservation Surcharge.......................................      II.B.
Cost Contributions...........................................      II.E.
Cost Recovery Adjustment Clause..............................      II.F.
Dividend Distribution Clause.................................      II.H.
Green Energy Premium.........................................      II.M.
Low Density Discount.........................................      II.P.
Unauthorized Increase Charge.................................      II.V.
------------------------------------------------------------------------

Section IV. Transmission

    All customers will need to obtain transmission for delivery of 
products listed under this rate schedule unless BPA's Power Business 
Line (PBL) and the customer negotiate otherwise at time of sale.

Schedule NR-02

New Resource Firm Power Rate

Section I. Availability

    This schedule is available for the contract purchase of Firm Power 
or capacity to be used within the Pacific Northwest. New Resource Firm 
Power is available to investor-owned utilities (IOU) under net 
requirements contracts for resale to ultimate consumers; for direct 
consumption; and for Construction, Test and Start-Up, and Station 
Service. New Resource Firm Power also is available to any public body, 
cooperative, or Federal agency to the extent such power is needed to 
serve any New Large Single Load (NLSL), as defined by the Northwest 
Power Act. That portion of the utility's load placed on BPA that is 
attributable to the NLSL will be billed under this rate schedule.
    Rates in this schedule are available for purchases under contracts 
for which power deliveries begin on or after October 1, 2001 (2002 
Contract), for a three or five-year period. Products available under 
this rate schedule are defined in BPA's 2002 General Rate Schedule 
Provisions (2002 GRSPs).
    This rate schedule supersedes the NR-96 rate schedule, which went 
into effect October 1, 1996. Sales under the NR-02 rate schedule are 
subject to BPA's 2002 GRSPs and billing process.

Section II. Rates Tables

    The rates in this section apply to NR products.
A. Demand Rate
1. Monthly Demand Rate for FY 2002 Through FY 2006
1.1  Applicability
    These rates apply to eligible customers purchasing power for three 
or five years.

[[Page 44335]]

1.2  Rate Table

------------------------------------------------------------------------
                                                               Rate (kW-
                      Applicable months                           mo)
------------------------------------------------------------------------
January......................................................      $2.14
February.....................................................       2.06
March........................................................       1.96
April........................................................       1.37
May..........................................................       1.32
June.........................................................       1.69
July.........................................................       2.12
August.......................................................       2.44
September....................................................       2.28
October......................................................       1.90
November.....................................................       2.31
December.....................................................       2.40
------------------------------------------------------------------------

B. Energy Rate
1. Monthly Energy Rates for FY 2002 Through FY 2004
1.1  Applicability
    These rates apply to eligible customers purchasing power in the 
first three years of the rate period.
1.2  Rate Table

------------------------------------------------------------------------
                                                     HLH rate   LLH rate
                 Applicable months                   (mills/    (mills/
                                                       kWh)       kWh)
------------------------------------------------------------------------
January...........................................      40.75      29.41
February..........................................      38.50      28.19
March.............................................      36.96      26.68
April.............................................      25.76      19.52
May...............................................      24.88      16.41
June..............................................      31.56      19.64
July..............................................      40.34      33.76
August............................................      61.32      41.09
September.........................................      42.83      41.44
October...........................................      35.94      29.22
November..........................................      43.78      38.15
December..........................................      45.47      37.95
------------------------------------------------------------------------

2. Monthly Energy Rates for FY 2005 Through FY 2006
2.1  Applicability
    These rates apply to purchases during the last two years of the 
rate period for eligible customers purchasing for all five years of the 
rate period.
2.2  Rate Table

------------------------------------------------------------------------
                                                     HLH rate   LLH rate
                 Applicable months                   (mills/    (mills/
                                                       kWh)       kWh)
------------------------------------------------------------------------
January...........................................      42.25      30.91
February..........................................      40.00      29.69
March.............................................      38.46      28.18
April.............................................      27.26      21.02
May...............................................      26.38      17.91
June..............................................      33.06      21.14
July..............................................      41.84      35.26
August............................................      62.82      42.59
September.........................................      44.33      42.94
October...........................................      37.44      30.72
November..........................................      45.28      39.65
December..........................................      46.97      39.45
------------------------------------------------------------------------

3. Monthly Energy Rates for FY 2002 Through FY 2006
3.1  Applicability
    These rates apply to eligible customers purchasing for all five 
years of the rate period under this rate table.
3.2  Rate Table

------------------------------------------------------------------------
                                                     HLH rate   LLH rate
                 Applicable months                   (mills/    (mills/
                                                       kWh)       kWh)
------------------------------------------------------------------------
January...........................................      41.35      30.01
February..........................................      39.10      28.79
March.............................................      37.56      27.28
April.............................................      26.36      20.12
May...............................................      25.48      17.01
June..............................................      32.16      20.24
July..............................................      40.94      34.36
August............................................      61.92      41.69
September.........................................      43.43      42.04
October...........................................      36.54      29.82
November..........................................      44.38      38.75
December..........................................      46.07      38.55
------------------------------------------------------------------------

C. Load Variance Rate
    The Load Variance rate for FY 2002 through FY 2006 is applicable to 
all customers purchasing power under this rate schedule unless 
specifically excluded in Section III below. The rate for Load Variance 
is 0.8 mills/kWh.

Section III. Billing Factors, and Adjustments for Each NR Product

    This rate schedule contains seven subsections, corresponding to the 
products to which this rate schedule applies. The following seven 
products are available to serve NLSLs, or other loads served at the NR-
02 rate.

Section III.A.  New Large Single Load
Section III.B.  Full Service Product
Section III.C.  Actual Partial Service Product--Simple
Section III.D.  Actual Partial Service Product--Complex
Section III.E.  Block Product
Section III.F.  Block Product with Factoring
Section III.G.  Block Product with Shaping Capacity
A. New Large Single Load (NLSL) Service Product
    Purchases of New Resource Firm Power to serve a NLSL are subject to 
the charges specified below.
1. New Resource Firm Power
1.1  Demand Charge
    The charge for Demand will be:

The NLSLs Demand Entitlement as specified in the contract multiplied by 
the Demand Rate from Section II.A.
1.2  Energy Charge
    The total monthly charge for energy will be the sum of (1) and (2), 
unless BPA and the Purchaser agree to bill based on a contract amount 
of energy.

(1) The NLSLs HLH Energy Entitlement as specified in the contract 
multiplied by the HLH Energy Rate from Section II.B.
(2) The NLSLs LLH Energy Entitlement as specified in the contract 
multiplied by the LLH Energy Rate from Section II.B.
1.3  Load Variance Charge
    The charge for Load Variance will be:

The NLSLs Measured Energy for the billing period as specified in the 
contract multiplied by the Load Variance Rate from Section II.C.

    If the customer is already paying the Load Variance Charge on the 
NLSL load through this or another rate schedule, this charge does not 
apply.
2. Adjustments, Charges, and Special Rate Provisions
    Adjustments, Charges, and Special Rate Provisions are described in 
the 2002 GRSPs. Relevant sections are identified below.

------------------------------------------------------------------------
                                                                  2002
      Adjustments, charges, and special rate provisions           GRSP
                                                                section
------------------------------------------------------------------------
Conservation and Renewables Discount.........................      II.A.
Conservation Surcharge.......................................      II.B.
Cost Contributions...........................................      II.E.
Cost Recovery Adjustment Clause..............................      II.F.
Dividend Distribution Clause.................................      II.H.
Flexible NR Rate Option......................................      II.K.
Green Energy Premium.........................................      II.M.
Low Density Discount.........................................      II.P.
Rate Melding.................................................      II.Q.
Targeted Adjustment Charge...................................      II.U.
Unauthorized Increase Charge.................................      II.V.
------------------------------------------------------------------------

B. Full Service Product
    Purchases of the core Subscription Full Service Product are subject 
to the charges specified below.
1. New Resource Firm Power
1.1  Demand Charge
    The charge for Demand will be:

The Purchaser's Measured Demand on the Generation System Peak as 
specified in the contract multiplied by the Demand Rate from Section 
II.A.
1.2  Energy Charge
    The total monthly charge for energy will be the sum of (1) and (2):

(1) The Purchaser's HLH Energy Entitlement as specified in the contract 
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract 
multiplied by the LLH Energy Rate from Section II.B.

[[Page 44336]]

1.3  Load Variance Charge
    The charge for Load Variance will be:

The Purchaser's Total Retail Load for the billing period multiplied by 
the Load Variance Rate from Section II.C.
2. Adjustments, Charges, and Special Rate Provisions
    Adjustments, Charges, and Special Rate Provisions are described in 
the 2002 GRSPs. Relevant sections are identified below.

------------------------------------------------------------------------
                                                                  2002
      Adjustments, charges, and special rate provisions           GRSP
                                                                section
------------------------------------------------------------------------
Conservation and Renewables Discount.........................      II.A.
Conservation Surcharge.......................................      II.B.
Cost Contributions...........................................      II.E.
Cost Recovery Adjustment Clause..............................      II.F.
Dividend Distribution Clause.................................      II.H.
Flexible NR Rate Option......................................      II.K.
Green Energy Premium.........................................      II.M.
Low Density Discount.........................................      II.P.
Rate Melding.................................................      II.Q.
Targeted Adjustment Charge...................................      II.U.
Unauthorized Increase Charge.................................      II.V.
------------------------------------------------------------------------

C. Actual Partial Service Product--Simple
    Purchases of the core Subscription Actual Partial Service Product--
Simple are subject to the charges specified below.
1. New Resource Firm Power
1.1  Demand Charge
    The charge for Demand will be:

(The Purchaser's Demand Entitlement multiplied by a Demand Adjuster) as 
specified in the contract multiplied by the Demand Rate from Section 
II.A.
1.2  Energy Charge
    The total monthly charge for energy will be the sum of (1) and (2):

(1) The purchaser's HLH Energy Entitlement as specified in the contract 
multiplied by the HLH Energy Rate from Section II.B.
(2) The purchaser's LLH Energy Entitlement as specified in the contract 
multiplied by the LLH Energy Rate from Section II.B.
1.3  Load Variance Charge
    The charge for Load Variance will be:

The purchaser's Total Retail Load for the billing period multiplied by 
the Load Variance from Section II.C.
2. Adjustments, Charges, and Special Rate Provisions
    Adjustments, Charges, and Special Rate Provisions are described in 
the 2002 GRSPs. Relevant sections are identified below.

------------------------------------------------------------------------
                                                                  2002
      Adjustments, charges, and special rate provisions           GRSP
                                                                section
------------------------------------------------------------------------
Conservation and Renewables Discount.........................      II.A.
Conservation Surcharge.......................................      II.B.
Cost Contributions...........................................      II.E.
Cost Recovery Adjustment Clause..............................      II.F.
Dividend Distribution Clause.................................      II.H.
Flexible NR Rate Option......................................      II.K.
Green Energy Premium.........................................      II.M.
Low Density Discount.........................................      II.P.
Rate Melding.................................................      II.Q.
Targeted Adjustment Charge...................................      II.U.
Unauthorized Increase Charge.................................      II.V.
------------------------------------------------------------------------

D. Actual Partial Service Product--Complex
    Purchases of the core Subscription Actual Partial Service Product--
Complex are subject to the charges specified below.
1. New Resource Firm Power
1.1  Demand Charge
    The charge for Demand will be:

(The Purchaser's Demand Entitlement multiplied by a Demand Adjuster) as 
specified in the contract multiplied by the Demand Rate from Section 
II.A.
1.2  Energy Charge
    The total monthly charge for energy will be the sum of (1) and (2):

(1) The Purchaser's HLH Energy Entitlement as specified in the contract 
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract 
multiplied by the LLH Energy Rate from Section II.B.
1.3  Load Variance Charge
    The charge for Load Variance will be:

The Purchaser's Total Retail Load for the billing period multiplied by 
the Load Variance Rate from Section II.C.
2. Adjustments, Charges, and Special Rate Provisions
    Adjustments, Charges, and Special Rate Provisions are described in 
the 2002 GRSPs. Relevant sections are identified below.

------------------------------------------------------------------------
                                                                  2002
      Adjustments, charges, and special rate provisions           GRSP
                                                                section
------------------------------------------------------------------------
Conservation and Renewables Discount.........................      II.A.
Conservation Surcharge.......................................      II.B.
Cost Contributions...........................................      II.E.
Cost Recovery Adjustment Clause..............................      II.F.
Dividend Distribution Clause.................................      II.H.
Excess Factoring Charge......................................      II.I.
Flexible NR Rate Option......................................      II.K.
Green Energy Premium.........................................      II.M.
Low Density Discount.........................................      II.P.
Rate Melding.................................................      II.Q.
Targeted Adjustment Charge...................................      II.U.
Unauthorized Increase Charge.................................      II.V.
------------------------------------------------------------------------

E. Block Product
    Purchases of the core Subscription Block Product are subject to the 
charges specified below.
1. New Resource Firm Power
1.1.  Demand Charge
    The charge for Demand will be:

The Purchaser's Demand Entitlement as specified in the contract 
multiplied by the Demand Rate from Section II.A.
1.2.  Energy Charge
    The total monthly charge for energy shall be the sum of (1) and 
(2):

(1) The Purchaser's HLH Energy Entitlement as specified in the contract 
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract 
multiplied by the LLH Energy Rate from Section II.B.
1.3  Load Variance Charge
    Not applicable to Block purchases unless the customer is also 
purchasing another product to which Load Variance is applicable as 
specified by contract.
2. Adjustments, Charges, and Special Rate Provisions
    Adjustments, Charges, and Special Rate Provisions are described in 
the 2002 GRSPs. Relevant sections are identified below.

------------------------------------------------------------------------
                                                                  2002
      Adjustments, charges, and special rate provisions           GRSP
                                                                section
------------------------------------------------------------------------
Conservation and Renewables Discount.........................      II.A.
Conservation Surcharge.......................................      II.B.
Cost Contributions...........................................      II.E.
Cost Recovery Adjustment Clause..............................      II.F.
Dividend Distribution Clause.................................      II.H.
Flexible NR Rate Option......................................      II.K.
Green Energy Premium.........................................      II.M.
Low Density Discount.........................................      II.P.
Rate Melding.................................................      II.Q.
Stepped Up Multiyear Block (SUMY)............................      II.S.
Targeted Adjustment Charge...................................      II.U.
Unauthorized Increase Charge.................................      II.V.
------------------------------------------------------------------------

F. Block Product With Factoring
    Purchases of the core Subscription Block Product with Factoring are 
subject to the charges specified below.

[[Page 44337]]

1. New Resource Firm Power
1.1.  Demand Charge
    The charge for Demand will be:

(the Purchaser's Demand Entitlement multiplied by a Demand Adjuster) as 
specified in the contract multiplied by the Demand Rate from Section 
II.A.
1.2.  Energy Charge
    The total monthly charge for energy will be the sum of (1) and (2):

(1) The Purchaser's HLH Energy Entitlement as specified in the contract 
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract 
multiplied by the LLH Energy Rate from Section II.B.
1.3  Load Variance Charge
    Not applicable to Block purchases unless the customer is also 
purchasing another product to which Load Variance is applicable as 
specified by contract.
2. Adjustments, Charges, and Special Rate Provisions
    Adjustments, Charges, and Special Rate Provisions are described in 
the 2002 GRSPs. Relevant sections are identified below.

------------------------------------------------------------------------
                                                                  2002
      Adjustments, charges, and special rate provisions           GRSP
                                                                section
------------------------------------------------------------------------
Conservation and Renewables Discount.........................      II.A.
Conservation Surcharge.......................................      II.B.
Cost Contributions...........................................      II.E.
Cost Recovery Adjustment Clause..............................      II.F.
Dividend Distribution Clause.................................      II.H.
Excess Factoring Charge......................................      II.I.
Flexible NR Rate Option......................................      II.K.
Green Energy Premium.........................................      II.M.
Low Density Discount.........................................      II.P.
Rate Melding.................................................      II.Q.
Stepped Up Multiyear Block (SUMY)............................      II.S.
Targeted Adjustment Charge...................................      II.U.
Unauthorized Increase Charge.................................      II.V.
------------------------------------------------------------------------

G. Block Product With Shaping Capacity
    Purchases of the core Subscription Block Product with Shaping 
Capacity are subject to the charges specified below.
1. New Resource Firm Power
1.1.  Demand Charge
    The charge for Demand will be:

The Purchaser's Demand Entitlement as specified in the contract 
multiplied by the Demand Rate from Section II.A.
1.2.  Energy Charge
    The total monthly charge for energy shall be the sum of (1) and 
(2):

(1) The Purchaser's HLH Energy Entitlement as specified in the contract 
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract 
multiplied by the LLH Energy Rate from Section II.B.
1.3  Load Variance Charge
    Not applicable to Block purchases unless the customer is also 
purchasing another product to which Load Variance is applicable as 
specified by contract.
2. Adjustments, Charges, and Special Rate Provisions
    Adjustments, Charges, and Special Rate Provisions are described in 
the 2002 GRSPs. Relevant sections are identified below:

------------------------------------------------------------------------
                                                                  2002
      Adjustments, charges, and special rate provisions           GRSP
                                                                section
------------------------------------------------------------------------
Conservation and Renewables Discount.........................      II.A.
Conservation Surcharge.......................................      II.B.
Cost Contributions...........................................      II.E.
Cost Recovery Adjustment Clause..............................      II.F.
Dividend Distribution Clause.................................      II.H.
Flexible NR Rate Option......................................      II.K.
Green Energy Premium.........................................      II.M.
Low Density Discount.........................................      II.P.
Rate Melding.................................................      II.Q.
Stepped Up Multiyear Block (SUMY)............................      II.S.
Targeted Adjustment Charge...................................      II.U.
Unauthorized Increase Charge.................................      II.V.
------------------------------------------------------------------------

Section IV. Transmission

    All customers will need to obtain transmission for delivery of 
products listed under this rate schedule unless BPA's Power Business 
Line (PBL) and the customer negotiate otherwise at time of sale. 
Regulation and Frequency Response may have to be purchased for NLSLs.

IP-02

Industrial Firm Power Rate

Section I. Availability

    This schedule is available, in conjunction with the IPTAC, to BPA's 
direct service industrial (DSI) customers for Firm Power to be used in 
their industrial operations. DSIs that purchase power under contracts 
for which power deliveries begin on or after October 1, 2001 (2002 
Contracts), are eligible to purchase under this rate schedule for up to 
a five-year period.
    This rate schedule supersedes the IP-96 rate schedule, which went 
into effect October 1, 1996. Sales under the IP-02 rate schedule are 
subject to BPA's 2002 General Rate Schedule Provisions (2002 GRSPs) and 
billing process.

Section II. Rates Tables

    The rates for the IP Firm Power product are identified below.
A. Demand Rate for All IP/IPTAC Products
1. Flat Rate Demand for FY 2002 through 2006
1.1  Applicability
    These rates apply to eligible customers purchasing power for all 
five years of the rate period.
1.2  Rate Table

------------------------------------------------------------------------
                                                               Rate  (kW-
                      Applicable months                           mo)
------------------------------------------------------------------------
January......................................................      $2.14
February.....................................................       2.06
March........................................................       1.96
April........................................................       1.37
May..........................................................       1.32
June.........................................................       1.69
July.........................................................       2.12
August.......................................................       2.44
September....................................................       2.28
October......................................................       1.90
November.....................................................       2.31
December.....................................................       2.40
------------------------------------------------------------------------

B. Energy Rate
1. Monthly Energy Rates for FY 2002 Through FY 2006
1.1  Applicability
    These energy rates are to be combined with one of the two IP 
Targeted Adjustment Charges specified in Section 2.2 or 3.2 below.
1.2  Rate Table

------------------------------------------------------------------------
                                                    HLH  rate  LLH  rate
                 Applicable months                    (mills/    (mills/
                                                       kWh)       kWh)
------------------------------------------------------------------------
January...........................................      21.49      15.87
February..........................................      20.37      15.27
March.............................................      19.61      14.52
April.............................................      14.07      10.98
May...............................................      13.63       9.44
June..............................................      16.93      11.04
July..............................................      21.28      18.03
August............................................      31.66      21.65
September.........................................      22.51      21.83
October...........................................      19.10      15.78
November..........................................      22.99      20.20
December..........................................      23.82      20.10
------------------------------------------------------------------------

2. Monthly Energy Rates for FY 2002 Through FY 2006 for IPTAC (23.5 
mills)
    2.1  These rates apply to the eligible customers purchasing power 
under this rate schedule for all five years of the rate period.
    2.2  A charge of 2.02 mills shall be added to each IP energy rate 
in the Rate Table in 1.2 above.

[[Page 44338]]

3. Monthly Energy Rates for FY 2002 Through FY 2006 for IPTAC (25.0 
mills)
    3.1  These rates apply to the eligible customers purchasing power 
under this rate schedule for all five years of the rate period.
    3.2  A charge of 3.52 mills shall be added to each IP energy rate 
in the Rate Table in 1.2 above.

C. Load Variance Rate

    The Load Variance rate for FY 2002 through FY 2006 applies to all 
customers purchasing power under this rate schedule unless specifically 
excluded in Section III below. The rate for Load Variance is 0.8 mills/
kWh.

Section III. Billing Factors and Adjustments for Each IP Product

    This rate schedule contains two subsections, corresponding to the 
products to which this rate schedule applies. Only the firm take-or-pay 
Block Product is available under these rate schedules.

SECTION III.A.  DSI Customers Who Purchase Under 2002 Industrial Firm 
Power (IP) Contracts
SECTION III.B.  DSI Customers Who Purchase Under 2002 Industrial Firm 
Power Targeted Adjustment Charge (IPTAC) Contracts
A. DSI Customers Who Purchase Under 2002 Industrial Firm Power (IP) 
Contracts
    Purchases of power under a 2002 IP contract are subject to the 
charges specified below.
1. Industrial Firm Power
1.1  Demand Charge
    The charge for Demand will be:

The Purchaser's monthly Contract Demand multiplied by the Demand Rate 
from Section II.A.
1.2  Energy Charge
    The Total monthly charge for energy will be the sum of (1) and (2):

(1) The Purchaser's monthly HLH Contract Energy multiplied by the HLH 
Energy Rate from Section II.B; and
(2) The Purchaser's monthly LLH Contract Energy multiplied by the LLH 
Energy Rate from Section II.B.
1.3  Load Variance Charge
    Not applicable to Block purchases unless the customer is also 
purchasing another product to which Load Variance is applicable as 
specified by contract.
2. Adjustments, Charges, and Special Rate Provisions
    Adjustments, Charges, and Special Rate Provisions are described in 
the 2002 GRSPs. Relevant sections are identified below:

------------------------------------------------------------------------
                                                                  2002
      Adjustments, charges, and special rate provisions           GRSP
                                                                section
------------------------------------------------------------------------
Conservation and Renewable Discount..........................      II.A.
Conservation Surcharge.......................................      II.B.
Cost Contributions...........................................      II.E.
Cost Recovery Adjustment Clause..............................      II.F.
Dividend Distribution Clause.................................      II.H.
Green Energy Premium.........................................      II.M.
Rate Melding.................................................      II.Q.
Supplemental Contingency Reserves Adjustment.................      II.T.
Unauthorized Increase Charge.................................      II.V.
------------------------------------------------------------------------

B. DSI Customers Who Purchase Under 2002 Industrial Firm Power Targeted 
Adjustment Charge (IPTAC) Contracts
    Purchases of power under a 2002 IPTAC contract are subject to the 
charges specified below.
1. Industrial Firm Power
1.1  Demand Charge
    The charge for Demand will be:

The Purchaser's monthly Contract Demand multiplied by the Demand Rate 
from Section II.A.
1.2  Energy Charge
    Energy charges will be calculated pursuant to the GRSPs IPTAC at 
the time of contract negotiations.
1.3  Load Variance Charge
    Not applicable to Block purchases unless the customer is also 
purchasing another product to which Load Variance is applicable as 
specified by contract.
2. Adjustments, Charges, and Special Rate Provisions
    Adjustments, Charges, and Special Rate Provisions are described in 
the 2002 GRSPs. Relevant sections are identified below:

------------------------------------------------------------------------
                                                                  2002
      Adjustments, charges, and special rate provisions           GRSP
                                                                section
------------------------------------------------------------------------
Conservation and Renewable Discount..........................      II.A.
Conservation Surcharge.......................................      II.B.
Cost-Based Indexed IP Rate...................................      II.C.
Cost Contributions...........................................      II.E.
Cost Recovery Adjustment Clause..............................      II.F.
Dividend Distribution Clause.................................      II.H.
Flexible IP Rate Option......................................      II.J.
Green Energy Premium.........................................      II.M.
Industrial Firm Power Targeted Adjustment Charge.............      II.O.
Rate Melding.................................................      II.Q.
Supplemental Contingency Reserves Adjustment.................      II.T.
Unauthorized Increase Charge.................................      II.V.
------------------------------------------------------------------------

Section IV. Transmission

    All customers will need to obtain transmission for delivery of 
products listed under this rate schedule unless BPA's Power Business 
Line (PBL) and the customer negotiate otherwise at time of sale.

NF-02

Nonfirm Power Rate

Section I. Availability

    This schedule is available for the purchase of nonfirm energy to be 
used both inside and outside the United States including sales under 
the Western Systems Power Pool (WSPP) agreements and sales to 
consumers. The offer of nonfirm energy under this schedule shall be 
determined by BPA.
    This rate schedule supersedes the NF-96 schedule, which went into 
effect on October 1, 1996. Sales under the NF-02 rate schedule are 
subject to BPA's 2002 General Rate Schedule Provisions (2002 GRSPs). 
For sales under this rate schedule, bills shall be rendered and 
payments due pursuant to BPA's 2002 GRSPs and billing process.

Section II. Rates, Billing Factors, and Adjustments

    The average cost of nonfirm energy is 24.98 mills/kWh. The NF-02 
rate schedule provides for upward and downward pricing flexibility from 
this average nonfirm energy cost.
A. Rates for Nonfirm Energy
1. Standard Rate
    The Standard rate is any offered rate not to exceed 29.98 mills/
kWh.
2. Market Expansion Rate
    The Market Expansion rate is any offered rate below the Standard 
rate in effect. BPA may have one or more Market Expansion rates in 
effect simultaneously.
3. Incremental Rate
    The Incremental Rate is the Incremental Cost of energy plus 2.00 
mills/kWh, where the Incremental Cost is defined as all identifiable 
costs (expressed in mills/kWh) that BPA would have avoided had it not 
produced or purchased the energy being sold under this rate.
4. Contract Rate
    The Contract Rate is 24.98 mills/kWh.
B. Billing Factor for Nonfirm Energy
    The billing factor for nonfirm energy purchased under this rate 
schedule shall be the Measured Energy unless otherwise specified by 
contract.

[[Page 44339]]

C. Adjustments for Nonfirm Energy
    All adjustments are described in the 2002 GRSPs. The applicable 
sections are identified for each adjustment.

------------------------------------------------------------------------
                                                                  2002
      Adjustments, charges, and special rate provisions           GRSP
                                                                section
------------------------------------------------------------------------
Cost Contributions...........................................      II.E.
Unauthorized Increase Charge.................................      II.V.
------------------------------------------------------------------------

Section III. Determination of the Applicable NF Rate

    Any time that BPA has nonfirm energy for sale, the Standard rate, 
the Market Expansion rate, the Incremental rate, the Contract rate, or 
any combination of these rates may be in effect.
A. Standard Rate
    The Standard rate is available for all purchases of nonfirm energy.
B. Market Expansion Rate
1. Application of the Market Expansion Rate
    The Market Expansion rate applies when BPA determines that all 
markets at the Standard rate have been satisfied and BPA offers 
additional nonfirm energy.
2. Market Expansion Rate Qualification Criteria
    In order to purchase nonfirm energy at the Market Expansion rate, a 
purchaser must:
    a. Have a displaceable resource, displaceable purchase of 
electricity; or
    b. Be an end-user load with a displaceable alternative fuel source. 
In addition, a purchaser must demonstrate one of the following:
    a. Shutdown or reduction of the output of the displaceable resource 
associated with that purchase, in an amount equal to the amount of 
Market Expansion rate energy purchased; or
    b. Reduction of a displaceable purchase and the output of the 
resource associated with that purchase, in an amount equal to the 
amount of Market Expansion rate energy purchased; or
    c. Shutdown or reduction of the identified output of the 
resource(s) indirectly in an amount equal to the amount of Market 
Expansion rate energy purchased (for example, the purchase may be used 
to run a pumped storage unit); or
    d. Decrease of an end-user alternate fuel source in an amount 
equivalent to the amount of Market Expansion rate energy purchased.
3. Eligibility Criteria for Market Expansion Rate
    a. When only one Market Expansion rate is offered:
    Purchasers satisfying the Market Expansion Rate Qualifying Criteria 
specified in Section III.B.2 above, who purchased nonfirm energy 
directly from BPA, are eligible to purchase power under the Market 
Expansion rate offered if the decremental cost of the qualifying 
resource, purchase, or qualifying alternative fuel source is lower than 
the Standard rate in effect plus 2.00 mills/kWh.
    Purchasers qualifying under Section III.B.2 who purchase nonfirm 
energy through a third party are eligible to purchase power under the 
Market Expansion rate offered if the cost of the qualifying alternative 
fuel source is lower than the Standard rate in effect plus 4.00 mills/
kWh.
    b. When more than one Market Expansion rate is offered:
    Purchasers qualifying under Section III.B.2 who purchase nonfirm 
energy directly from BPA are eligible to purchase power under the 
Market Expansion rate if the decremental cost of the qualifying 
resource, purchase, or qualifying alternative fuel source is lower than 
the Standard rate in effect plus 2.00 mills/kWh. The rate applicable to 
a purchaser will be the highest Market Expansion rate offered that is 
below the purchaser's qualifying decremental cost minus 2.00 mills/kWh.
C. Incremental Rate
    The Incremental rate applies to sales of energy:
    1. That is produced or purchased by BPA concurrently with the 
nonfirm energy sale;
    2. That BPA may at its option not produce or purchase; and 3. that 
has an Incremental Cost greater than the Standard rate (plus the 
Intertie Charge, if applicable) minus 2 mills.
D. Contract Rate
    The Contract rate applies to contracts (except power sales 
contracts offered pursuant to Sections 5(b), 5(c), and 5(g) of the 
Northwest Power Act) that refer to the Contract rate:
    1. For sale of nonfirm energy; or
    2. For determining the value of energy.
E. Western Systems Power Pool Transactions (WSPP)
    BPA may make available nonfirm energy for transactions under the 
WSPP agreement. WSPP sales shall be subject to the terms and conditions 
specified in the WSPP agreement and will be consistent with regional 
and public preference. The rate for transactions under the WSPP 
agreement is any rate within the limits specified by the Standard, 
Market Expansion, and Incremental rates but may not exceed the maximum 
rate specified in the WSPP agreement. The rate for WSPP sales may 
differ from the actual rate offered for non-WSPP transactions in any 
hour. The rate for WSPP transactions is independent of any other rate 
offered concurrently under this rate schedule outside the agreement.
F. End-User Rate
    BPA may agree to a rate formula for nonfirm energy purchases by 
end-users. Such rate or rate formula will be within the limits 
specified for the Standard and Market Expansion rates but may differ 
from the actual rates offered during any hour.

Section IV. Delivery

A. Rate of Delivery
    BPA shall determine the amount of nonfirm energy to be made 
available for each hour. Such determination shall be made for each 
applicable nonfirm energy rate.
B. Guaranteed Delivery
1. Availability
    BPA will determine the amount and duration of nonfirm energy to be 
offered on a guaranteed basis. Such daily or hourly amounts may be as 
small as zero or as much as all the nonfirm energy that BPA plans to 
offer for sale on such days.
2. Conditions
    Scheduled amounts of guaranteed nonfirm energy may not be changed 
except:
    a. When BPA and the purchaser mutually agree to increase or 
decrease the scheduled amounts; or
    b. When BPA must reduce nonfirm energy deliveries in order to serve 
firm loads.

Section V. Transmission

    All customers will need to obtain transmission for delivery of 
products listed under this rate schedule unless BPA's Power Business 
Line (PBL) and the customer negotiate otherwise at time of sale.

BPA'S 2002 General Rate Schedule Provisions for Power Rates

Index General Rate Schedule Provisions

Section I: Adoption of Revised Rate Schedules and General Rate 
Schedule Provisions

A. Approval of Rates
B. General Provisions

[[Page 44340]]

C. Late Payment Provisions
D. Notices

Section II: Adjustments, Charges, and Special Rate Provisions

A. Conservation and Renewables Discount (C&R Discount)
B. Conservation Surcharge (PF/NR only)
C. Cost-Based Indexed IP Rate
D. Cost-Based Indexed PF Rate
E. Cost Contributions
F. Cost Recovery Adjustment Clause (CRAC)
G. Demand Adjuster
H. Dividend Distribution Clause (DDC)
I. Excess Factoring Charges
J. Flexible IP Rate Option
K. Flexible NR Rate Option
L. Flexible PF Rate Option
M. Green Energy Premium
N. Guaranteed Delivery Charge (NF Only)
O. Industrial Firm Power Targeted Adjustment Charge (IPTAC)
P. Low Density Discount
Q. Rate Melding
R. Slice True-Up Adjustment
S. Stepped Up Multiyear Block (SUMY)
T. Supplemental Contingency Reserves Adjustment (SCRA)
U. Targeted Adjustment Charge
V. Unauthorized Increase Charge

Section III: Definitions

A. Power Products and Services Offered By the Power Business Line of 
BPA
    1. Actual Partial Service Product--Simple/Complex
    2. Block Product
    3. Block Product with Factoring
    4. Block Product with Shaping Capacity
    5. Construction, Test and Start-Up, and Station Service
    6. Core Subscription Products
    7. Customer System Peak (CSP)
    8. Full Service Product
    9. Industrial Firm Power
    10. Load Variance
    11. New Resource Firm Power
    12. Nonfirm Energy
    13. Priority Firm Power
    14. Regulation and Frequency Response
    15. Residential Exchange Program Power
    16. Slice Product
B. Definition of Rate Schedule Terms
    1. 2002 Contract
    2. Annual Billing Cycle
    3. Billing Demand
    4. Billing Energy
    5. California Independent System Operator (California ISO)
    6. California ISO Spinning Reserve Capacity
    7. California ISO Supplemental Energy
    8. California Power Exchange (California PX)
    9. Contract Demand
    10. Contract Energy
    11. Control Area
    12. Decremental Cost
    13. Delivering Party
    14. Demand Entitlement
    15. Discount Period
    16. Dow Jones Mid-C Indexes (DJ Mid-C Indexes)
    17. Electric Power
    18. Energy Entitlement
    19. Federal System
    20. Firm Power (PF-02, IP-02, NR-02, RL-02)
    21. Full Service Customer
    22. Generation System Peak
    23. Heavy Load Hours (HLH)
    24. Inventory Solution Costs
    25. Light Load Hour (LLH)
    26. Measured Demand
    27. Measured Energy
    28. Metered Demand
    29. Metered Energy
    30. Mid-Columbia Bus (Mid-C Bus)
    31. Monthly Federal System Peak Load
    32. NP15
    33. NW1 (California-Oregon Border)
    34. NW3 (Nevada-Oregon Border)
    35. Partial Service Customer
    36. Point of Delivery (POD)
    37. Point of Integration (POI)
    38. Point of Interconnection (POI)
    39. Points of Metering (POM)
    40. Pre-Subscription Contract
    41. Purchaser
    42. Receiving Party
    43. Retail Access
    44. Scheduled Demand
    45. Scheduled Energy
    46. Slice Administrative Costs
    47. Slice Revenue Requirement
    48. Subscription
    49. Subscription Contract
    50. System Obligations
    51. Total Plant Load
    52. Total Retail Load (TRL)
    53. Utility Distribution Company

General Rate Schedule Provisions

Section I. Adoption of Revised Rate Schedules and General Rate Schedule 
Provisions

A. Approval of Rates
    These 2002 Wholesale Power Rate Schedules and General Rate Schedule 
Provisions (2002 GRSPs) shall become effective upon interim approval or 
upon final confirmation and approval by the Federal Energy Regulatory 
Commission (FERC). Bonneville Power Administration (BPA) has requested 
that FERC make these rates and 2002 GRSPs effective on October 1, 2001, 
for customers who are billed by BPA on a calendar month basis and on 
the first day of the first billing month following that date for all 
other customers. All rate schedules shall remain in effect until they 
are replaced or expire on their own terms.
B. General Provisions
    These 2002 Wholesale Power Rate Schedules and the 2002 GRSPs 
associated with these schedules supersede BPA's 1996 rate schedules 
(which became effective October 1, 1996) to the extent stated in the 
Availability section of each rate schedule. These schedules and 2002 
GRSPs shall be applicable to all BPA contracts, including contracts 
executed both prior to, and subsequent to, enactment of the Pacific 
Northwest Electric Power Planning and Conservation Act (Northwest Power 
Act). All sales under these rate schedules are subject to the following 
acts as amended: The Bonneville Project Act, the Regional Preference 
Act (P.L. 88-552), the Federal Columbia River Transmission System 
(FCRTS) Act (P.L. 93-454), the Northwest Power Act (P.L. 96-501), and 
the Energy Policy Act of 1992 (P.L. 102-486).
    These 2002 rate schedules do not supersede any previously 
established rate schedule which is required, by agreement, to remain in 
effect.
    If a provision in an executed agreement is in conflict with a 
provision contained herein, the former shall prevail.
C. Late Payment Provisions
    Bills not paid in full on or before close of business on the due 
date shall be subject to an interest charge of one-twentieth percent 
(0.05 percent) applied each day to the unpaid amount. This interest 
charge shall be assessed on a daily basis until such time as the unpaid 
amount is paid in full.
    Remittances will be accepted without assessment of the charges 
referred to in the preceding paragraph provided payment was received on 
or before the due date. The due date is the 20th day after the issue 
date of the bill unless the 20th day is a Saturday, Sunday, or Federal 
holiday, in which case the due date is the next business day. Whenever 
a power bill or a portion thereof remains unpaid subsequent to the due 
date, and after giving 30 days' advance notice in writing, BPA may 
cancel the contract for service to the Purchaser. However, such 
cancellation shall not affect the Purchaser's liability for any 
previously accrued charges under such contract.
D. Notices
    For the purpose of determining elapsed time from receipt of a 
notice applicable to rate schedule and GRSP administration, a notice 
shall be deemed to have been received at 0000 hours on the first 
calendar day following actual receipt of the notice.

Section II. Adjustments, Charges, and Special Rate Provisions

A. Conservation and Renewables Discount (C&R Discount)
1. Description of the Discount
    To encourage and support the development of conservation projects 
and renewable resources in the Pacific Northwest, BPA is offering a 
Conservation and Renewables Discount (C&R Discount) to customers 
purchasing

[[Page 44341]]

under the Priority Firm (PF-02), New Resources (NR-02), and Residential 
Load (RL-02) rate schedules. Customers purchasing under the Industrial 
Firm Power Rate (IP-02) will be eligible to the extent that the C&R 
Discount does not reduce their effective rate below the DSI floor rate. 
Regional public agency customers with Pre-Subscription contracts with 
collared pricing provisions may be eligible for the C&R Discount 
subject to contract provisions. The amount of the Discount will be a 
fixed monthly amount based on the customer's forecasted purchases from 
BPA under its Subscription contract. Following the end of the Discount 
Period (which is the end of the rate period or the customer's contract 
term, whichever comes first), BPA will evaluate the customer's 
investments in eligible conservation and renewable resource projects 
during the Discount Period. Any customer that has not spent at least as 
much money on eligible activities as the cumulative discount received 
from BPA must reimburse the difference to BPA.
2. Calculation and Application of the Discount
a. Overview of the Discount
    The C&R Discount will be included as a fixed dollar credit in the 
monthly power bill of each participating customer. The credit will 
equal the customer's forecasted average monthly Subscription contract 
(in megawatts) multiplied by the unit discount. (Because the average 
contract is used, the discount does not vary by month).
b. Determination of the ``Unit Discount''
    The unit discount will equal 0.5 mills per kilowatthour (kWh).
c. Determination of Individual Customer Discounts
    For a participating customer buying power from BPA under a 
Subscription contract for the entire five-year rate period, BPA will 
determine the monthly dollar discount by multiplying the customer's 
forecasted average monthly power consumption over the rate period by 
the unit discount.
d. Annual Review of Individual Customer Discounts
    At least 30 days prior to the start of each fiscal year, customers 
will submit adjustments to the section c monthly discounts based on 
changes to the customers load as specified in their BPA contract.
e. Application of the Discount
    The C&R Discount will be applied after BPA has determined all other 
charges and credits on the participating customer's power bill.
    BPA will provide the discount even in those months when the 
discount amount is larger than the customer's total power bill amount.
3. Qualifying Expenditures
    Participating customers shall record all qualifying expenditures to 
ensure full credit for their conservation and renewable resource 
activities. Qualifying expenditures are those that meet technical 
standards developed by the Regional Technical Forum as approved by BPA.
    Although BPA will provide the credit on a monthly basis, the 
customer has no obligation to adhere to any particular expenditure 
pattern. To retain the full discount provided by BPA, the participating 
customer must make qualifying expenditures during the Discount Period 
in an amount equal to, or exceeding, the cumulative C&R Discount 
received from BPA during the Discount Period.
4. Reporting
a. Interim Conservation and Renewable Reports
    Participating customers shall submit to BPA annual Interim 
Conservation and Renewable Reports at the end of each fiscal year of 
the rate period (i.e., 10/01/01 to 9/30/02; 10/01/02, to 9/30/03; 
etc.). The Interim Report shall show the customer's cumulative 
discounts received to date and their cumulative qualifying 
expenditures. If the report shows that the customer's qualifying 
expenditures are less than or equal to its discount receipts by 5 
percent or more, the customer must indicate in its report how it plans 
to adjust its expenditures to ensure that it will retain the full 
discount after the Discount Period.
b. Final Reconciliation Reports
    At the end of the Discount Period the participating customer shall 
prepare a Final Reconciliation Report. This report shall be submitted 
and received by BPA one month after the end of the Discount Period 
(November 1, 2006, for participating customers' purchasing power from 
BPA for the full five-year rate period).
    This report shall identify:
    i. The cumulative C&R Discount that the customer has received from 
BPA during the Discount Period, and
    ii. The total qualifying expenditures that the customer has made 
during the Discount Period segregated into the following four 
categories:
    I. Incremental Conservation
    II. Renewable Resources
    III. Low Income Weatherization
    IV. Support Activities (i.e., administrative, advertising, R&D, and 
evaluation
c. Certification of Incremental Spending
    Each Interim Report and the Final Reconciliation Report shall 
include language certifying the participating customer's actual 
incremental spending, such as:
    ``[Customer] certifies that the expenditures documented in this 
report are incremental increases in this organization's budget for the 
current operating year beyond what we planned to spend absent the 
discount.''
d. Exemption Language for State and Municipal Initiatives
    If States, municipalities, or other governmental bodies in the BPA 
service territory require, by law or regulation, that a utility, which 
is a participating customer in the C&R Discount, to acquire or invest 
in new conservation and/or a new renewable resource project, then such 
acquisitions and investments will be deemed as incremental budget 
increases for the purposes of section 4.c. above.
5. Reimbursement
a. Customers Whose Expenditures Exceed the Threshold
    No reimbursements are required of any participating customer whose 
total expenditures over the Discount Period equal or exceed the total 
cumulative C&R Discount received from BPA.
b. Customers Whose Expenditures Fall Below the Threshold
    If a participating customer's Final Reconciliation Report shows 
that the cumulative discount received from BPA exceeds the customer's 
total qualifying expenditures, the customer may take an additional 
month (for a total of two months after the end of the Discount Period) 
to make the necessary qualifying expenditures and prepare a Revised 
Final Reconciliation Report. The final report is due to BPA within two 
months of the end of the Discount Period (December 1, 2006, for the 
five-year customers). If the customer's qualifying expenditures still 
do not equal or exceed its cumulative discount, the customer must 
reimburse the difference to BPA. Such reimbursement shall be made 
within the same two-month grace period and shall be made using the same 
payment method as the customer uses for paying its wholesale bill.
    BPA will not assess interest on any reimbursement paid within the 
two-month window. However, any payment received after the due date 
(December 1, 2006, the five-year customers) shall be

[[Page 44342]]

subject to a late payment charge as described in their Subscription 
contract.
6. Revenue Dividends
a. Implementation
    If BPA declares that there is a dividend during this rate period, 
the first $15 million will be allocated to conservation and renewable 
resource development. BPA will distribute the C&R portion of any 
declared dividend in the same manner outlined in this section with the 
following modifications:
    1. In order to receive their portion of the C&R dividend, customers 
must be actively participating in the basic C&R Discount effort; and
    2. Participating customers must spend two dollars on eligible 
activities to receive one dollar of their dividend share (i.e., any C&R 
dividend will be leveraged on a 2 for 1 basis).
    3. The unit discount for participating customers receiving the 
dividend will set at $0.75 per MWh during the months the dividend is in 
effect.
B. Conservation Surcharge (PF/NR Only)
    The Conservation Surcharge, where implemented shall be applied in 
accordance with relevant provisions of the Northwest Power Act, BPA's 
current conservation surcharge policy, and the customer's power sales 
contract with BPA. The PF and NR rate schedules are subject to the 
Conservation Surcharge.
C. Cost-Based Indexed IP Rate
    The Cost-Based Indexed IP Rate option shall be offered at BPA's 
discretion to a DSI Purchaser who makes a contractual commitment to 
purchase power for all five years of the rate period from BPA that is 
subject to the IP Targeted Adjustment Charge (IPTAC). The charges and 
billing factors under this option shall be specified by BPA at the time 
the Administrator offers to make power available to a Purchaser under 
this option. The actual charges and billing factors will be mutually 
agreed to by BPA and the Purchaser. The following criteria will be used 
in establishing any flexible rate:
    1. Equivalent Net Present Value Revenues: Forecasted revenues from 
a Purchaser under this rate option must be equivalent to or greater 
than, on a net present value basis, the revenues BPA would have 
received had the IPTAC specified in the IP-02 rate schedule been 
applied to the same sales.
    2. Risk Adjustments: Risk, both credit risk associated with 
individual customers and price risk associated with power and commodity 
prices, will be factors in establishing any flexible rate option. 
Creditworthiness will be determined by BPA consistent with prevailing 
business standards, and applied consistently to each customer. Such 
credit risks will be dealt with through a ``margin deposit'' expense 
charge built into the rates, or other methods acceptable to BPA.
    3. Industry Index: The Cost-Based Indexed IP Rate will be adjusted 
on a regular basis consistent with a negotiated cash or financial 
index. Adjusting the price of the Cost-Based Indexed IP Rate with the 
fluctuations in a world aluminum price index would be one use of an 
industry index.
    4. Lower Rate Limit and Upper Rate Limit: A lower and upper rate 
limit will bound the Cost-Based Index and establish the minimum and 
maximum prices to be charged during the contract period.
D. Cost-Based Indexed PF Rate
    The Cost-Based Indexed PF Rate will be offered to all firm load 
requirements customers who wish to convert their applicable PF rate 
under their contracts to a market-indexed or floating price adjusted 
for BPA's risk. The following are features of this rate:
    1. BPA and the customer will choose during contract negotiations a 
mutually agreed reference point and sponsor for the index used. For 
example, the California-Oregon border (location) and the Dow Jones cash 
or the New York Mercantile Exchange futures (sponsor), or some other 
combination to arrive at an agreed upon index.
    2. BPA will base the index pricing on a current market forecast of 
the market index referenced. The expected Net Present Value (NPV) 
revenue of the forecast index prices will be adjusted by a HLH and a 
LLH Market Index Monthly Adjustment (MIMA) to equal the expected NPV of 
the applicable PF rates. The MIMA reflects BPA's PF equivalent expected 
revenues at the time the contract is signed, including an insurance 
premium to ensure revenue sufficiency.
    3. Customers must select this rate for the term of their 
Subscription contract that the 2002-2006 rate period covers. Customers 
who choose a contract length of less than five years and wish to renew 
will be subject to rates established under a new rate case.
    4. Billing will be based on the index's average of the last 15 days 
of closing or posted daily prices at the reference point. The MIMA will 
be calculated as follows:

Index = average of last 15 days of closing or posted daily prices at 
the reference point.
PF = monthly PF HLH or LLH energy rate
Cost of Insurance = The premium on a physical and financial 
instrument used to mitigate the risk.
MIMA = Index-PF+Cost of Insurance
E. Cost Contributions
    BPA has made the following resource cost determinations:
    1. The forecasted average cost of resources available to BPA under 
average water conditions is 19.12 mills/kWh.
    2. The approximate cost contribution of different resource 
categories to each rate schedule is as shown in Table A:

                                                     Table A
----------------------------------------------------------------------------------------------------------------
                                                                            Resource cost contribution
                                                                 -----------------------------------------------
                          Rate schedule                            Federal base
                                                                      system*        Exchange*    New resources*
----------------------------------------------------------------------------------------------------------------
PF..............................................................          100               0               0
IP..............................................................           52.86           43.66            3.48
NR..............................................................           52.86           43.66            3.48 
----------------------------------------------------------------------------------------------------------------
* In percent.

F. Cost Recovery Adjustment Clause (CRAC)
    The CRAC is an upward adjustment to posted power rates for 
Subscription sales on a temporary basis if Actual Accumulated Net 
Revenues (AANR) in the generation function fall below a threshold 
level.
    The CRAC applies to power customers under these firm power rate 
schedules: Priority Firm Power [Preference (PF excluding Slice), 
Exchange Program, and Exchange

[[Page 44343]]

Subscription], IP-02, including under the IPTAC and Cost-Based Index 
Rate, RL-02 including the financial portion of any Residential Exchange 
Settlement under this rate schedule, NR-02, and Subscription purchase 
under FPS. The CRAC does not apply to Pre-Subscription rates or Slice 
purchases.
1. Formula for the Calculation of the Revenue Amount and CRAC 
Percentage
    If the AANR in any fiscal year 2001 through 2004 falls below the 
CRAC Threshold for that same fiscal year, the CRAC triggers, and rates 
will be increased for a 12-month period beginning the following April. 
The Revenue Amount will be determined by the following formula:

Revenue Amount is the lower of:
CRAC Threshold--AANR; or
The annual Maximum Planned Recovery Amount, shown in Table B below.

    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.
    Where CRAC Threshold is the ``trigger point'' for invoking a rate 
increase under the CRAC. The threshold is pre-specified for the end of 
fiscal years 2001, 2002, 2003, 2004, and 2005 in Table B.
    Where AANR is generation function net revenues, as accumulated 
since 1998, at the end of each of the fiscal years 2001 through 2005. 
Net revenues for any given fiscal year are accrued revenues less 
accrued expenses, in accordance with Generally Accepted Accounting 
Practices. 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, 
will be included in determinations under the CRAC. Accrued revenues and 
expenses of the transmission function are excluded. The determination 
of AANR will be confirmed by BPA's independent auditing firm.
    Where Maximum Planned Recovery Amount is the maximum amount planned 
to be recovered through the CRAC beginning in April following the end 
of a fiscal year in which the AANR falls below the CRAC Threshold.
    If the AANR in fiscal year 2005 falls below the CRAC Threshold, the 
CRAC triggers, and rates will be increased for a six-month period 
beginning the following April. The Revenue Amount will be determined by 
the following formula:

Revenue Amount is the lower of:
(CRAC Threshold-AANR) divided by 2; or $87.5 million ($175 million 
divided by 2)

                                 Table B
------------------------------------------------------------------------
                                                         Maximum planned
                                         CRAC threshold  recovery amount
              Fiscal year                   (AANR, $        (beginning
                                            millions)       following
                                                              April)
------------------------------------------------------------------------
2001...................................            -350            125
2002...................................            -350            135
2003...................................            -200            150
2004...................................            -200            150
2005...................................            -200             87.5
------------------------------------------------------------------------

    Once the Revenue Amount is determined, that amount will be 
converted to the CRAC Percentage. The CRAC Percentage is the percentage 
increase in each of the firm power rate schedules listed above. This 
percentage will be applied for a period of time to generate the 
additional (CRAC) revenue. The CRAC Percentage will be determined by 
the following formula:

CRAC Percentage =
Revenue Amount
Divided by
CRAC Revenue Basis,

    Where CRAC Revenue Basis is the total generation revenue for the 
loads subject to CRAC, plus any Slice loads, for the fiscal year in 
which the 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 increased by this CRAC Percentage amount.
2. CRAC Adjustment Timing
    In January of each year of the rate period, the Administrator will 
determine whether the AANR at the end of the preceding fiscal year fell 
below the CRAC Threshold. If the AANR is below the CRAC Threshold, the 
Administrator will propose, in January, to increase applicable rates 
effective in the following April. The adjustment is applied to power 
deliveries beginning April 1. Any such increase beginning in fiscal 
years 2002-2005 remains in effect through March of the following year. 
An increase beginning in the final fiscal year of the rate period 
(2006) will remain in effect through September 2006.
3. CRAC 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 fiscal year ending 
September 30. By no later than December 1 of each year, BPA shall also 
post on its World Wide Web site the unaudited AANR.
b. Notice of CRAC Trigger
    BPA shall notify all customers and rate case parties on or about 
January 15 in each of the fiscal years 2002-2006, if the AANR fell 
below the CRAC Threshold for that fiscal year and rates will be 
adjusted under the CRAC. (If the December unaudited AANR report for the 
generation function indicated that the CRAC Threshold might be reached, 
and the audited actuals show that it has not triggered, customers and 
rate case parties will be so notified.) Notification will include the 
audited AANR for the prior fiscal year, the calculation of the Revenue 
Amount, and the estimated CRAC Percentage. 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 CRAC implementation process.
    On or about February 1 of any of the fiscal years 2002-2006 in 
which the AANR falls below the CRAC Threshold,

[[Page 44344]]

BPA staff shall conduct a public forum to explain the AANR result, the 
calculation of the Revenue Amount and the CRAC Percentage, and 
demonstrate that the CRAC has been implemented in accordance with the 
GRSPs. The forum will provide an opportunity for public comment.
    On or about March 1 of any of the fiscal years 2002-2006 in which 
the AANR falls below the CRAC Threshold, the BPA Administrator shall 
notify all customers to whom the CRAC applies of the final calculation 
of the adjustment and the resulting rate increase (as a percentage) 
applicable to each rate schedule.
G. Demand Adjuster
    The Demand Adjuster is applied to a customer's demand billing 
factor. It is a number less than or equal to one calculated by dividing 
the customer's Total Retail Load on the Generation System Peak by the 
customer's Total Retail Load on their system peak. The minimum Demand 
Adjuster is 0.6 (six tenths). The Demand Adjuster is used with the 
demand billing factor for the Actual Partial Service Products, and with 
the demand billing factor for the Block with Factoring.
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 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: Priority Firm Power [Preference (PF excluding Slice), 
Exchange Program, and Exchange Subscription], IP-02 including under the 
IPTAC and Cost-Based Index Rate, RL-02 including the financial portion 
of any Residential Exchange Settlement under this rate schedule, NR-02, 
and Subscription purchases under FPS. The DDC does not apply to Pre-
Subscription rates or Slice purchases, unless those customers 
participate in the C&R Discount and a distribution is made to eligible 
participants of that program.
    The DDC does not apportion, or establish criteria for apportioning, 
dividends to customers under the above firm power rate schedules other 
than to qualifying power customers participating in the C&R Discount, 
or to other customers and stakeholders.
    ``Stakeholders'' are groups 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. A full identification of stakeholders will be 
provided for comment in the public consultation process.
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 fiscal years 2001-2005 are above 
the DDC Threshold value.
    Actual Accumulated Net Revenues (AANR) are generation function net 
revenues, as accumulated since 1998, at the end of each of the fiscal 
years 2001 through 2005. Net revenues are accrued revenues less accrued 
expenses, in accordance with Generally Accepted Accounting Practices. 
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 $500 
million for the end of fiscal years 2001, 2002, 2003, 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 Treasury Payment Probability
(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 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 fiscal year 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
    On or about January 15 of each year of the rate period (FY 2002-
2006), the Administrator will determine whether the AANR exceeds the 
DDC Threshold. If the AANR exceeds the DDC Threshold: (1) Customers and 
rate case parties will be so notified; and (2) 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 fiscal year 2002-2005, remain 
in affect 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 
Conservation and Renewables Discount Program (C&R

[[Page 44345]]

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 
Conservation and Renewables Discount GRSP, Section II.A.
    BPA intends to conduct a separate public consultation process by 
October 1, 2001, 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 fiscal year ending 
September 30. By December 1 of each year, BPA shall post on its World 
Wide Web site the unaudited AANR.
b. Notice of DDC Trigger
    On or about January 15 in each of the fiscal years 2002-2006, 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 fiscal year, 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 fiscal years 2002-2006 in 
which the AANR exceeds the DDC Threshold, the Administrator will post 
the Five-Year Forecast on BPA's World Wide Web site 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 fiscal years 2002-2006 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.
I. Excess Factoring Charges
1. Excess Within-Day Factoring Charge
    The within-day factoring test compares the hour-by-hour shape of 
the customer's load to the customer's hour-by-hour energy take from BPA 
within a day. This test identifies whether or not the hour-by-hour 
shape of the customer's take from BPA has used more within-day 
factoring service, measured in kilowatthours, than the underlying load 
would have used.
    Excess Within-Day Factoring Charge, for any hour(s) in the month, 
applies to that amount of hourly energy in excess of the authorized 
maximum energy amounts defined by the customer's within-day load shape.
    The total amount of Excess Within-Day Factoring Charge during the 
HLH's of the month shall be billed the greater of:
    a. Five (5) mills/kWh;
    b. Among all HLH periods of the billing month, the maximum within-
day difference between the highest hourly HLH California ISO 
Supplemental Energy price (NP15) and the lowest hourly HLH California 
ISO Supplemental Energy price (NP15).
    The total amount of Excess Within-Day Factoring Charge during the 
LLH's of the month shall be billed the greater of:
    a. Five (5) mills/kWh;
    b. Among all LLH periods of the billing month, the maximum within-
day difference between the highest hourly LLH California ISO 
Supplemental Energy price (NP15) and the lowest hourly LLH California 
ISO Supplemental Energy price (NP15).
    In the event that the index for ISO Supplemental Energy expires, 
that index will be replaced for the purpose of deriving Excess Within-
Day Factoring Charges by another hourly energy index, such as the 
California PX (NW1 or NW 3), at a hub at which Northwest parties can 
trade.
2. Excess Within-Month Factoring Charges
    The within-month factoring test compares the day-by-day shape of 
the customer's load to the customer's day-to-day energy take from BPA 
within a month. This test identifies whether the day-to-day shape of 
the customer's take from BPA used more within-month factoring service 
than the underlying load would have used. The within-day factoring test 
(see above) is not equipped to identify a factoring service issue if, 
for example, the customer resource deliveries were zero for a 
particular day. The within-month factoring test is equipped to address 
that type of instance. The within-month factoring test establishes an 
upper and lower boundary for each diurnal period of the day. Excess 
within-month factoring for each diurnal period is the greater of: (1) 
the sum of the amounts greater than the upper boundary; or (2) the sum 
of the amounts less than the lower boundary.
    Excess Within-Month Factoring Charge applies to that amount of 
energy take that either exceeds or falls short of a range defined by: 
(1) a flat load placement on BPA; and (2) a load placement that follows 
the customer's actual load shape.
    The Excess Within-Month Factoring quantities are reduced by any 
Unauthorized Increase Energy amounts in the like diurnal period, and 
only the residual is charged the Excess Within-Month Factoring Charge.
    The Excess Within-Month Factoring during the HLH's of the month 
shall be billed the greater of:
    a. Five (5) mills/kWh.
    b. The highest peak DJ Mid-C Index price for firm power during the 
month LESS the lowest peak DJ Mid-C Firm Index price for firm power 
during the month.
    c. The highest average HLH California ISO Supplemental Energy price 
(NP15) (average of hours 7 through 22, excluding Sundays) during the 
month LESS the lowest average HLH California ISO Supplemental Energy 
price (NP15) for the same period.
    The Excess Within-Month Factoring during the LLH's of the month 
shall be billed the greater of:
    a. Five (5) mills/kWh.
    b. The highest offpeak DJ Mid-C Index price for firm power during 
the month LESS the lowest offpeak DJ Mid-C Index price for firm power;
    c. The highest average LLH California ISO Supplemental Energy price 
(NP15) (average of hours 1 through 6, and 23, and 24 Monday through 
Saturday; average of hours 1 through 24 Sunday) during the month LESS 
the lowest average LLH California ISO Supplemental Energy price (NP15) 
for the same month in the same time period.
    In the event that the index for ISO Supplemental Energy or DJ Mid-C 
Index expires, that index will be replaced for the purpose of deriving 
Excess Within-

[[Page 44346]]

Month Factoring Charges by another hourly or diurnal energy index, such 
as the California PX (NW1 or NW3), at a hub at which Northwest parties 
can trade.
J. Flexible IP Rate Option
    The Flexible IP rate option will be offered at BPA's discretion to 
purchasers who make a contractual commitment to purchase under this 
option for all five years of the rate period. The charges and billing 
factors under this option will be specified by BPA at the time the 
Administrator offers to make power available to a Purchaser under this 
option. The actual charges and billing factors will be mutually agreed 
to by BPA and the Purchaser subject to satisfying the following 
condition:
    Equivalent Net Present Value Revenues: Forecasted revenues from a 
Purchaser under the Flexible IP rate option must be equivalent, on a 
net present value basis, to the revenues BPA would have received had 
the appropriate charges specified in the IP rate schedule Section II 
been applied to the same sales.
    The Flexible IP rate contract may establish a limit on the amount 
of power purchased at the Flexible IP rate. In this case, purchases 
beyond the contractual limit will be billed at the Demand and Energy 
charges specified in the IP rate schedule Section II unless such power 
would be charged as an Unauthorized Increase.
    Risk Adjustments: Credit risk associated with individual customers 
will be a factor in establishing any flexible rate option. 
Creditworthiness will be determined by BPA consistent with prevailing 
business standards, and applied consistently to each customer. Such 
credit risks will be dealt with through a ``margin deposit,'' expense 
charge, built into the rates, or other methods acceptable to BPA.
K. Flexible NR Rate Option
    The Flexible NR rate option will be offered at BPA's discretion to 
purchasers who make a contractual commitment to purchase under this 
option. The charges and billing factors under this option shall be 
specified by BPA at the time the Administrator offers to make power 
available to a Purchaser under this option. The customers purchasing 
under the Flexible NR rate option purchase the same set of power 
products and services that they would otherwise purchase under the rate 
schedule. The actual charges and billing factors will be mutually 
agreed to by BPA and the Purchaser subject to satisfying the following 
condition:
    Equivalent Net Present Value Revenues: Forecasted revenues from a 
Purchaser under the Flexible NR rate option must be equivalent, on a 
net present value basis, to the revenues BPA would have received had 
the appropriate charges specified in the NR rate schedule Section II 
been applied to the same sales.
    The Flexible NR rate contract may establish a limit on the amount 
of power purchased at the Flexible NR rate. In this case, purchases 
beyond the contractual limit will be billed at the Demand and Energy 
(and Load Variance and SUMY, if appropriate) charges specified in the 
PF rate schedule Section II, unless such power would be charged as an 
Unauthorized Increase.
    The Flexible NR rate option is only available for development of an 
energy rate that is stepped up in FY 2005 and 2006.
L. Flexible PF Rate Option
    The Flexible PF rate option will be offered at BPA's discretion to 
purchasers who make a contractual commitment to purchase under this 
option. The charges and billing factors under this option shall be 
specified by BPA at the time the Administrator offers to make power 
available to a Purchaser under this option. The customers purchasing 
under the Flexible PF rate option purchase the same set of power 
products and services that they would otherwise purchase under the rate 
schedule. The actual charges and billing factors will be mutually 
agreed to by BPA and the Purchaser subject to satisfying the following 
condition:
    Equivalent Net Present Value Revenues: Forecasted revenues from a 
Purchaser under the Flexible PF rate option must be equivalent, on a 
net present value basis, to the revenues BPA would have received had 
the appropriate charges specified in the PF rate schedule Section II 
been applied to the same sales.
    The Flexible PF rate contract may establish a limit on the amount 
of power purchased at the Flexible PF rate. In this case, purchases 
beyond the contractual limit will be billed at the Demand and Energy 
(and Load Variance, and SUMY if appropriate) charges specified in the 
PF rate schedule Section II, unless such power would be charged as an 
Unauthorized Increase.
    The Flexible PF rate option is only available for development of an 
energy rate that is stepped up in FY 2005 and 2006.
M. Green Energy Premium
1. Overview of the Premium
    The Green Energy Premium (GEP) is a premium ranging from zero to 
$40/megawatthour (MWh) that a customer elects to pay BPA to ensure that 
BPA is producing some system power from Environmentally Preferred Power 
(EPP) resources. The GEP is the difference between the customer's 
applicable average annual energy charge under the PF-02, RL-02, NR-02, 
and IP-02 rates and the total cost of the EPP resource selected by the 
customer. The GEP is applied to the number of EPP MWhs that the 
customer has elected to purchase. BPA guarantees the customer paying 
the premium that BPA will produce an amount of EPP equal to the amount 
of energy subject to this adjustment. The GEP will be charged in a line 
item on the monthly power bill of each participating.
    The costs to be considered in determining the applicable GEP 
include, but are not limited to:
     Costs of existing EPP resources, over and above the cost 
of BPA system resources.
     Costs of new EPP resources, over and above the cost of BPA 
system resources.
     Costs of BPA system resources.
     Endorsement fees for specific EPP resources.
     Market purchases of EPP resources.
     Transmission and other services required to integrate EPP 
resources into the BPA system.
2. Calculation and Application of the Premium
a. Determination of the Premium
    For a customer buying power from BPA under a requirements firm 
power sales contract, the amount of EPP and the premium will be 
determined as part of the product selection process and will be 
completed as part of the power sales contract negotiation during the 
Subscription window. The charge will not exceed $40 per MWh and may be 
as low as zero. The premium will be zero if the unit cost of the GEP 
resource(s) dedicated to the customer is equal to, or less than, the 
energy charge of the applicable rate. The premium will be equal to the 
average unit cost of the GEP resource(s) minus the applicable average 
PF-02, RL-02, NR-02, and IP-02 energy charge.
b. Determination of Individual Customer GEP
    (1) During the Subscription window, customers will be provided 
notice of the availability of specific GEP products and associated 
premiums. The total GEP

[[Page 44347]]

for the customer will be based on the customer's elections of product 
amounts and content.
    (2) The average annual energy charge will be calculated as the 
average per kilowatthour (kWh) charge for an annual flat undelivered 
product using the energy charges applicable to the customer. Where 
customers are purchasing under more than one rate schedule, the average 
energy charge will be calculated using expected loads and applicable 
rate schedules.
    (3) The individual customer GEP for billing will be the total cost 
of the product selected by the customer minus the average annual energy 
charge.
c. Application of the GEP
    The GEP will be applied after BPA has determined all other charges 
and credits except the Conservation and Renewables Discount line item, 
on the participating customer's power bill.
d. Billing for the Premium
    The customer's bill will include a line item showing the kWh amount 
of EPP purchased times the GEP for the products elected and the total 
cost. The calculation will appear as:

(EPP amount) kWh * GEP mills/kWh = $XXXXX
N. Guaranteed Delivery Charge (NF only)
    A surcharge of 2.00 mills/kWh of Billing Energy is applied whenever 
BPA guarantees delivery of nonfirm energy to a Purchaser under the NF 
Standard rate or Market Expansion rate.
O. Industrial Firm Power Targeted Adjustment Charge (IPTAC)
1. Availability
    The Industrial Firm Power Targeted Adjustment Charge (IPTAC) 
pertains to the IP rate schedule. The IPTAC will be applied to Firm 
Power requirements service of DSIs who take service from a combination 
of Federal inventory and power purchased from the market during the 
2002 rate period.
    The maximum total requirements service the IPTAC will be developed 
for, and applied to, is 1,440 aMW (flat, annual block). The total 
inventory used to provide this requirement service will be composed of 
990 aMW from Federal inventory and 450 aMW of market purchases.
    There will be two rates for the IPTAC product. 1210 aMW will be 
sold at $23.50 per MWh, and 230 aMW sold at $25 per MWh.
P. Low Density Discount
1. Application and Definitions
    For eligible Purchasers as defined in section 2 below, a discount 
shall be applied each billing month to BPA's charges for the following 
components of Priority Firm Power, New Resources Firm Power and 
Residential Load Firm Power service: (1) Demand; (2) HLH purchases; (3) 
LLH purchases; and (4) Load Variance. The Low Density Discount (LDD) 
shall not be applied to Unauthorized Increase Charges, Excess Factoring 
Charges, transmission charges or any other charges. The discount shall 
be revised annually based on data supplied by June 30 of each Calendar 
Year (CY) for the previous CY and shall become effective on the 
upcoming October 1.
a. The Kilowatthour/Investment Ratio
    The kWh/Investment (K/I) ratio is calculated annually based on the 
data supplied by June 30 for the previous CY. The K/I ratio is 
calculated by dividing the Purchaser's Total Retail Load during the CY 
by the value of the Purchaser's depreciated electric plant (excluding 
generation plant) at the end of the CY.
b. The Consumers/Mile of Line Ratio
    The Consumers/Mile of Line (C/M) ratio is determined annually using 
the data supplied by June 30 for the previous CY. The C/M ratio is 
calculated by dividing the maximum number of consumers on the 
distribution system, in any one month during the CY, by the end of CY 
number of pole miles of distribution.
    Consumer means every billed consumer regardless of usage. 
Separately billed services for water heating and security lights are 
not counted as an additional billed consumer.
    The number of pole miles of distribution line means the end of CY 
pole miles. Distribution lines are defined as lines that deliver 
electric energy from a substation or metering point, at a voltage of 
34.5 kilovolt or less, to the point of attachment to the consumer's 
wiring and include primary, secondary, and service facilities. (Service 
drops are considered service facilities.)
    These calculations shall be based on CY data provided from the 
Purchaser's annual financial and operating reports. The Purchaser shall 
certify that the data submitted is correct and that no loads gained as 
provided in section 6, Retail Access Exclusion, are receiving LDD 
benefits.
    In calculating these ratios, BPA shall compile the data submitted 
by the Purchaser based on the Purchaser's entire electric utility 
system in the Pacific Northwest (PNW). For Purchasers with service 
territories that include any areas outside the PNW, BPA shall compile 
data submitted by the Purchaser separately on the Purchaser's system in 
the PNW and on the Purchaser's entire electric utility inside and 
outside the PNW. BPA will apply the eligibility criteria and discount 
percentages to the Purchaser's system within the PNW and, where 
applicable, also to its entire system inside and outside the PNW. The 
Purchaser's eligibility for the LDD will be determined by the lesser 
amount of discount applicable to its PNW system or to its combined 
system inside and outside the PNW. BPA, in its sole discretion, may 
waive the requirement to submit separate data for the Purchaser with a 
small amount of its system outside the PNW. Results of the calculations 
shall not be rounded.
    A Purchaser who has not provided BPA with the requisite pieces of 
data needed to calculate the K/I and C/M ratios by June 30 of each 
year, for the prior CY, shall be declared ineligible for the LDD, 
effective the upcoming October 1.
    If a Purchaser's data was submitted on time and a revision is 
necessary to the data, the revised data must be resubmitted no later 
than 12 months after the original submission date to be considered for 
an adjustment.
2. Eligibility Criteria
    To qualify for a discount, the Purchaser must meet all five of the 
following eligibility criteria:
    a. The Purchaser must serve as an electric utility offering power 
for resale;
    b. The Purchaser must agree to pass the benefits of the discount 
through to the Purchaser's eligible consumers within the region served 
by BPA;
    c. The Purchaser's average retail rate for the reporting year must 
exceed the Purchaser's average cost of BPA power purchases under the 
applicable rate for the qualifying period by at least 10 percent. For 
CY 2001, the Purchaser's average cost of BPA power purchases under the 
applicable rate shall be under the applicable 1996 rate for the first 
nine months and under the applicable 2002 rate for the last three 
months. For CY 2002 and beyond, the Purchaser's average cost of BPA 
power purchases under the applicable rate shall be under the applicable 
rate for all 12 months;
    d. The Purchaser's K/I ratio must be less than 100; and
    e. The Purchaser's C/M ratio must be less than 12.

[[Page 44348]]

3. Discounts
    The Purchaser shall be awarded the following discount beginning 
October 1, 2001, in accordance with section 4 below. The discount will 
be the sum of the two potential discounts for which the Purchaser 
qualifies, based on the following Table C. The discount shall not 
exceed 7 percent.

                 Table C.--LDD Percentage Discount Table
------------------------------------------------------------------------
                                   Applicable range    Applicable range
       Percentage discount        for KWh/investment  for consumers/mile
                                      (K/I) ratio         (C/M) ratio
------------------------------------------------------------------------
0.0.............................  35.0  X  12.0  X
0.5.............................  31.5  X  10.8  X
                                     < 35.0              < 12.0
1.0.............................  28.0  X  9.6  X
                                     < 31.5             < 10.83
1.5.............................  24.5  X  8.4  X
                                     < 28.0               < 9.6
2.0.............................  21.0  X  7.2  X
                                     < 24.5               < 8.4
2.5.............................  17.5  X  6.0  X
                                     < 21.0               < 7.2
3.0.............................  14.0  X  4.8  X
                                     < 17.5               < 6.0
3.5.............................  10.5  X  3.6  X
                                     < 14.0               < 4.8
4.0.............................  7.0  X   2.4  X
                                     < 10.5               < 3.6
4.5.............................  3.5  X   1.2  X
                                      < 7.0               < 2.4
5.0.............................           X  3.5   X < 1.2
------------------------------------------------------------------------

4. LDD Phase-Out Adjustment
    If the Purchaser satisfies the eligibility criteria (2. a. through 
e.), and the calculated discount differs from the existing discount by 
more than one-half of 1 percent, the applicable discount will be:
    a. The existing discount plus \1/2\ percent if the calculated 
discount exceeds the existing discount; or
    b. The existing discount minus \1/2\ percent if the calculated 
discount is less than the existing discount.
    The foregoing formula will be applied each October 1 until the 
then-current calculated discount is fully phased out.
    The Purchaser is not eligible to receive any discount, effective 
each October, if the Purchaser fails to meet the eligibility criteria 
in section 2. a. through e.
5. Benefits Legislation Exclusion
    If the Federal government or a State, or local government adopt(s) 
a law, regulation or other provision that establishes benefits for low 
density and/or rural electric systems that are similar to benefits 
provided by BPA's LDD, then the Purchaser's service territory within 
that jurisdiction shall no longer be eligible to receive the LDD. The 
effective date for discontinuation of the LDD and the Phase-Out 
Adjustment shall be the implementation date of the jurisdiction's 
benefits provision legislation. BPA will evaluate new provisions and 
determine, in BPA's judgment, whether they provide benefits similar to 
the LDD. If BPA concludes that the benefits are similar, BPA will 
conduct a public comment process before issuing a final decision.
6. Retail Access Exclusion
    Load that is gained by a Purchaser as a direct result of retail 
access rights established by Federal, State, or local legislation, and 
that would not otherwise have been gained absent such legislation, is 
not eligible to receive the benefits provided by the LDD. The Purchaser 
shall not pass the benefits of the LDD to its gained load consumers.
Q. Rate Melding
    BPA's rate proposal allows the customers more than one rate choice. 
Separately tracking and administering the customer's rate choices and 
maintaining the distinction would increase BPA's overall cost of 
providing rate choices. For administrative simplicity upon mutual 
agreement between BPA and the customer, BPA may offer to meld the 
customer's rate choices into a single composite set of rates that 
reflects the specific choices made by the customer. BPA will ensure 
that this melded set of rates will result in a bill that is nearly 
mathematically equivalent to applying the customer's individual choices 
throughout the rate period. BPA will provide the affected customer the 
calculations it used to establish the melded rates and provide 30 days 
for the customer to review and accept the melding calculation before it 
implements the melded rates. Melded rates established by BPA will 
continue until one of the customer's rate choices expires, or a rate 
adjustment occurs that is provided for under the chosen rate schedules 
(e.g., Cost Recovery Adjustment Clause), or a significant change in the 
loads applicable to the rates occurs.
R. Slice True-Up Adjustment
    By March 31 of each 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 rate case (except for the 
Inventory Solution which is billed based on the estimate from the 2002 
rate case). This true-up will be the True-Up Adjustment Charge and will 
be applied to the customer's May bill. In addition, an interim true-up 
adjustment procedure to allow for an intermediate true-up prior to 
March 31, will be developed in the power sales contracts with the 
customers.
S. Stepped Up Multiyear Block (SUMY)
    The SUMY Block charge applies to Block purchases if the annual 
amounts increase (i.e., step up) over multiple years of a purchase 
commitment term due to increases in customer net requirement which are 
not subject to a Targeted Adjustment Charge (TAC).
    The cost for the SUMY Block service is the difference between PF-02 
rates and the AURORA On-and Off-Peak market price forecast in the final 
rate proposal.
    The starting basis for computing the SUMY Block quantities will be 
the purchaser's subscribed block amount for the period October 2001 
through September 2002. Costs will be computed for 24 monthly blocks 
(12 HLH and 12 LLH) for each year of the rate period. Each year's 
monthly amount above the base year's monthly amount is the stepped up 
quantity. Total cost is the sum of each month's HLH and LLH stepped up 
quantities times each month's HLH and LLH costs.
    The SUMY charge is the total cost of the SUMY Block service divided 
by the total Block energy purchase including stepped up amounts. The 
charge is in addition to the PF and NR energy and demand rates that the 
customer will pay for these power purchases.

BILLING CODE 6450-01-P

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BILLING CODE 6450-01-C

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Formula for Calculating a Charge for SUMY Block Service
Step 1: Determine HLH MWh of SUMY Block. October 2002 HLH Block minus 
October 2001 HLH Block = HLH MWh of SUMY Block for October 2002
Step 2: Determine LLH MWh of SUMY Block. October 2002 LLH Block minus 
October 2001 LLH Block = LLH MWh of SUMY Block for October 2002
Step 3: Determine Cost of HLH SUMY Block service. HLH MWh of SUMY Block 
* (Aurora October 2002 On-Peak Market Price minus October 2002 PF HLH 
energy and demand rate) = Total Cost of October 2002 HLH SUMY Block 
service.
Step 4: Determine Cost of LLH SUMY Block service. LLH MWh of SUMY Block 
* (Aurora October 2002 Off-Peak Market Price minus October 2002 PF LLH 
energy rate) = Total Cost of October 2002 LLH SUMY Block service.
Step 5: Determine Cost for all months of the rate period by repeating 
Steps 1-4 for each month of the remaining purchase period always 
calculating the MWh difference from the first year and corresponding 
month. Calculate the price difference using that year's and month's 
market price and PF rate.
Step 6: Custom Charge: Divide the Net Present Value (NPV) of the stream 
of costs derived from Steps 1-5 by the NPV of the total block purchase 
including SUMY Block in MWh for the five-year period. The NPV uses a 
6.8 percent discount rate and is present valued to October 2001.
Step 7: Billing Determinant: Custom charge is applied to each MWh of 
block purchase including the SUMY Block amounts.
T. Supplemental Contingency Reserves Adjustment (SCRA)
    The energy charges stated in the IP-02 rate schedule will be 
adjusted to reflect the negotiated SCRA adjustment. PBL will negotiate 
with any DSI interested in providing Supplemental Contingency Reserves 
(Supplemental Reserves). Supplemental Reserves refers to generating 
capacity, and associated energy, fully available within 10 minutes 
notice of a system disturbance. PBL has established a flexible rate 
with a cap that will permit BPA to negotiate a price according to the 
quality of reserves provided. The maximum amount PBL may pay for 
Supplemental Reserves from a DSI is capped at $5.92/kW-mo.
    The suitability and quality of the Supplemental Reserves will be 
measured by whether they have certain characteristics, some of which 
are required and others optional. Any Supplemental Reserves purchased 
by PBL must be consistent with NERC, WSCC, and NWPP criteria:
    1. The interruptible load must be offline within five minutes after 
a call by BPA;
    2. In the event of a system disturbance, the interruptible load 
must be accessible prior to a request for reserves from other NWPP 
parties;
    3. The interruptible load must be available to be offline for up to 
60 minutes.
    In addition to these required characteristics, the issues 
identified below will help define when PBL may pay the maximum value 
for Supplemental Reserves:
    1. The extent to which PBL has the discretion when and how to use 
all operating reserves and to determine what resources to call on in 
the event of a system disturbance;
    2. Whether there are limitations on the number of times or total 
minutes the reserves may be utilized.
U. Targeted Adjustment Charge
1. Availability
    The Targeted Adjustment Charge (TAC) pertains to the PF rate 
schedule, except for PF exchange program and PF exchange Subscription 
rates. The TAC applies to firm power requirements service to regional 
firm load that results in an unanticipated increase in BPA's projected 
loads within the rate period. The TAC will be applied to the applicable 
rate for requirements service requested after the Subscription window 
closes.
    TAC will also apply to subsequent requests made by a customer under 
a Subscription contract for requirements service for such customer's 
load(s) that had been previously served by that customer's 5(b)(1)(A) 
or 5(b)(1)(B) resources.
    If a public agency customer that requests requirements service from 
BPA is annexing or otherwise taking on the obligation of load from 
another public agency customer and the request to annex or take on load 
obligation and the reduction in obligation are equal amounts such that 
BPA's total load obligation does not increase, BPA may exempt the newly 
acquired load from the TAC and apply PF-02. The TAC will apply if the 
annexed requirements service has been previously served by that 
customer's 5(b)(1)(A) or 5(b)(1)(B) resources.
    Where a public agency customer annexes residential and small farm 
load previously served by an IOU and such load was receiving BPA power 
or financial benefits through Subscription, the public agency customer 
will receive through assignment the right to the IOUs power and/or 
financial benefits applicable to the annexed load. BPA will deliver the 
same amount of firm power that was assigned by the IOU to the annexing 
public agency customer at the PF-02 rate. Power provided by BPA to the 
public agency customer to meet the remaining annexed load not covered 
by the power assigned from the IOU will be subject to the TAC.
    The TAC will apply for the duration of the Customer's contract or 
until 2006, whichever occurs first. For five-year contracts that 
guarantee rates for a multitude of periods (for example, contracts that 
have both three-year and five-year components) the TAC applies until 
the end of the five-year rate period. If a new public requests service, 
the TAC, if any, must apply until 2006.
    If a PF Preference customer is serving a portion of its load with a 
certifiable renewable resource eligible for the C&R Discount, or 
contract purchases of certified renewable resource power eligible for 
the C&R Discount for a period less than the term of the customer's BPA 
requirements firm power contract, then the customer may request, during 
the 2002 to 2006 rate period, requirements firm power service for such 
load at the end of the specified contract period at PF Preference (PF-
02) without being subject to the TAC. This limited exception applies to 
the first 200 aMW in any contract year, or to amounts that BPA 
specifies in accordance with its Policy on the Determination of Net 
Requirements.
2. Energy Charge
    The TAC is a monthly mills/kWh adjustment to the HLH and LLH energy 
rates specified in the 2002 rate schedule, and is applied to that 
portion of the Purchaser's load that is subject to the TAC. The TAC 
rate adjustment will be established based on the following formula:

TAC = [(Incr $ * Incr Amt)--(Rate $ * Incr Amt)]/TAC Amt

Where:

TAC Amt = The amount of load subject to the TAC, determined monthly.
Rate $ = The monthly PF energy rate shown in the applicable rate 
schedule.
Inventory Amt=Amount of energy in inventory available to serve this 
load based on average annual Federal system firm resource capability,

[[Page 44354]]

estimated using critical water excluding balancing purchases and 
purchases for system augmentation, from the 2002 rate case with updates 
if BPA determines that is necessary.
Incr $=Monthly cost to BPA, including a handling fee, of incremental 
power purchases expressed in mills/kWh. These costs also may include, 
where applicable, wheeling, ancillary, and other charges BPA may incur 
in purchasing power from other entities such as, but not limited to, 
the California ISO or the California PX.
Incr Amt=Amount of incremental power required, determined monthly and 
defined as the TAC Amt minus the Inventory Amt. (If there is no 
available Inventory Amt, the Incr Amt will equal the TAC Amt).

Incr $ is greater than Rate $ (If Incr $ is less than Rate $, the TAC 
is 0 mills/kWh).

    TAC is the monthly rate adjustment in mills/kWh. BPA will calculate 
the cost (Incr $) per month in mills/kWh of the additional power per 
month (Incr Amt) for a specific customer request. BPA will establish 
the cost of the additional power by the following methods:
     BPA will establish the price based on BPA's monthly cost 
to purchase the incremental load by purchases of resources at market.
V. Unauthorized Increase Charge
1. Charge for Unauthorized Increase in Demand
    The amount of Measured Demand during a billing hour that exceeds 
the amount of demand the purchaser is contractually entitled to take 
during that hour shall be billed at the greater of:
    a. Three (3) times the applicable monthly demand charge;
    b. The sum of hourly California ISO Spinning Reserve Capacity 
prices for all HLHs in the month, at path NW1 (COB); or
    c. The sum of hourly California ISO Spinning Reserve Capacity 
prices for all HLHs in the month, at path NW3 (NOB).
    In the event that the hourly California ISO Spinning Reserve 
Capacity market expires, the Unauthorized Increase Charge for demand 
shall be the greater of:
    a. Three (3) times the applicable monthly demand charge;
    b. The sum of hourly or diurnal prices for all HLHs in the month, 
at a hub at which Northwest parties can trade, established between 
October 1, 2001, and September 30, 2006.
2. Charge for Unauthorized Increase in Energy
    The amount of Measured Energy during a diurnal period of a billing 
month, day, or hour that exceeds the amount of energy the purchaser is 
contractually entitled to take during that period shall be billed the 
greater of:
    a. One hundred (100) mills/kWh; or
    b. For the month in question, the greater of:
    (1) the highest diurnal DJ Mid-C Index price for firm power; or
    (2) the highest hourly ISO California Supplemental Energy price 
(NP15).
    In the event that either the ISO California Supplemental Energy 
price index or the DJ Mid-C Index expires, the index will be replaced 
for purposes of the Unauthorized Increase Charge for energy by:
    (1) The highest price experienced for the month at the California 
PX, NW1 (COB);
    (2) The highest price experienced for the month at the California 
PX, NW3 (NOB); or
    (3) The highest price experienced for the month from any applicable 
new hourly or diurnal energy index at a hub at which Northwest parties 
can trade, established between October 1, 2001, and September 30, 2006.

Section III. Definitions

A. Power Products and Services Offered By the Power Business Line of 
BPA
1. Actual Partial Service Product--Simple/Complex
    The Actual Partial Service Products are core Subscription products 
that are available to purchasers who have a right to purchase from BPA 
for their requirements. These products are intended for customers who 
have contractual or generating resources with firm capabilities and 
therefore require a product other than Full Service. The Simple and 
Complex versions of this product category differ in that the Complex 
version is subject to the Factoring Benchmark tests in the billing 
process and to potential Excess Factoring Charges. The Simple version 
encompasses several possible approaches to customer resource 
declaration, all of which obviate the need for the Factoring Benchmark 
tests.
2. Block Product
    The Block Product is a core Subscription product that is available 
to purchasers who have a right to purchase from BPA for their 
requirements. This product is available in HLH and LLH quantities per 
month, with the hourly amount flat for all hours in such periods.
3. Block Product with Factoring
    The Block Product with Factoring is a combination of the Block 
Product with the core Subscription staple-on product for Factoring 
Service. Factoring provides the service of distributing Block energy to 
follow Purchaser hourly load needs to the extent of such Block energy.
4. Block Product With Shaping Capacity
    The Block Product with Shaping Capacity is a combination of the 
Block HLH energy product and the core Subscription staple-on product 
for Shaping capacity. Shaping capacity allows the customer to 
preschedule Block energy with some limited shape among HLHs within a 
contractually specified bandwidth.
5. Construction, Test and Start-Up, and Station Service
    Power for the purpose of Construction, Test and Start-Up, and 
Station Service for a generating resource or transmission facility 
shall be made available to eligible purchasers under the Priority Firm 
Power (PF-02), New Resources Firm Power (NR-02), and Firm Power 
Products and Services (FPS-96), rate schedules. Such power is not 
available for the PF Exchange Program rate, the PF Exchange 
Subscription rate, and the Residential Load rate.
    Construction, Test and Start-Up, and Station Service power must be 
used in the manner specified below:
    a. Power sold for construction is to be used in the construction of 
the project.
    b. Power sold for test and start-up may be used prior to commercial 
operation, both to bring the project online and to ensure that the 
project is working properly.
    c. Power sold for station service may be purchased at any time 
following commercial operation of the project. Once the project has 
been energized for commercial operation, the Purchaser may use station 
service power for start-up, shutdown, normal operations, and operations 
during a shutdown period.
    d. Power sold for Construction, Test and Start-Up, and Station 
Service is not available for replacement of lost generation for forced 
or planned outages or resource underperformance.
6. Core Subscription Products
    BPA's Core Subscription Products are described in the BPA Product 
Catalog. Core Subscription Products are available at the posted rates 
for customers who have a right to purchase them.
    The core products are:
     Actual Partial Service Product--Simple/Complex
     Block Product
     Block Product with Factoring
     Block Product with Shaping Capacity

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     Full Service Product
7. Customer System Peak (CSP)
    Customer System Peak (CSP) is the largest measured HLH Total Retail 
Load (TRL) amount in kilowatts for the billing period.
8. Full Service Product
    Full Service is a core Subscription product that is available to 
purchasers who have a right to purchase from BPA for their 
requirements. This product is available to customers who either have no 
resources or whose resources meet the criteria for small, non-
dispatchable resources.
9. Industrial Firm Power
    Industrial Firm Power is electric power that BPA will make 
continuously available to a direct-service industrial (DSI) purchaser 
subject to the terms of the Purchaser's power sales contract with BPA. 
Deliveries may be reduced or interrupted as permitted by the terms of 
the Purchaser's power sales contract with BPA. Adjustments as provided 
in the Purchaser's power sales contract shall be made for power 
restricted to provide reserves.
10. Load Variance
    For core Subscription products, Load Variance is defined as the 
variability in monthly energy consumption within the BPA customer's 
system. Through the Load Variance charge under the Full and Actual 
Partial Service Products, the customer's billing factors will follow 
actual consumption. Load Variance is not applicable to Block Product 
purchases. For purposes of pricing and rate tests under Pre-
Subscription contracts, the Load Variance charge is deemed to 
correspond to the PF-96 Load Shaping charge.
11. New Resource Firm Power
    New Resource Firm Power is electric power (capacity, energy, or 
capacity and energy) that BPA will make continuously available:
    a. For any New Large Single Load (NLSL); and
    b. For Firm Power purchased by IOUs pursuant to power sales 
contracts with BPA.
    New Resource Firm Power is to be used to meet the Purchaser's firm 
power load within the PNW. Deliveries of New Resource Firm Power may be 
reduced or interrupted as permitted by the terms of the Purchaser's 
power sales contract with BPA.
    New Resource Firm Power is guaranteed to be continuously available 
to the Purchaser during the period covered by its contractual 
commitment, except for reasons of certain uncontrollable forces and 
force majeure events. New Resource Firm Power is power where BPA agrees 
to provide operating reserves in accordance with the standards 
established by the NERC, WSCC, and the NWPP.
12. Nonfirm Energy
    Nonfirm Energy is energy that is supplied or made available by BPA 
to a Purchaser under an arrangement that does not have the guaranteed 
continuous availability feature of Firm Power. Nonfirm energy is sold 
primarily under the Nonfirm Energy rate schedule, NF-02. Nonfirm energy 
also may be supplied under the NF-02 rate schedule to the Western 
Systems Power Pool (WSPP) subject to terms and conditions agreed upon 
by the members participating in the WSPP and in accordance with BPA 
policy for such arrangements. Nonfirm Energy that has been purchased 
under a guarantee provision in the Nonfirm Energy rate schedule shall 
be provided to the Purchaser in accordance with the provisions of that 
schedule and the power sales contract if applicable. BPA may make 
Nonfirm Energy available to purchasers both inside and outside the 
United States.
13. Priority Firm Power
    Priority Firm Power is electric power (capacity, energy, or 
capacity and energy) that BPA will make continuously available for 
direct consumption or resale by public bodies, cooperatives, and 
Federal agencies. Utilities participating in the Residential Exchange 
under section 5(c) of the Northwest Power Act may purchase Priority 
Firm Power pursuant to their Residential Exchange contracts with BPA. 
Priority Firm Power is not available to serve NLSLs. Deliveries of 
Priority Firm Power may be reduced or interrupted as permitted by the 
terms of the Purchaser's power sales contract with BPA.
    Priority Firm Power is guaranteed to be continuously available to 
the Purchaser during the period covered by its contractual commitment, 
except for reasons of certain uncontrollable forces and force majeure 
events. Priority Firm Power is power where BPA agrees to provide 
operating reserves in accordance with the standards established by the 
NERC, WSCC, and NWPP.
14. Regulation and Frequency Response
    Regulation and frequency response is the generating capacity of a 
power system that is immediately responsive to AGC control signals 
without human intervention. Regulation and frequency response is 
required to provide AGC response to load and generation fluctuations in 
an effective manner and to maintain desired compliance with NERC AGC 
Control Performance
15. Residential Exchange Program Power
    Residential Exchange Program Power is power BPA sells to a 
Purchaser pursuant to the Residential Exchange Program. Under section 
5(c) of the Northwest Power Act, BPA ``purchases'' power from PNW 
utilities at a utility's Average System Cost (ASC). BPA then offers, in 
exchange, to ``sell'' an equivalent amount of electric power to that 
customer at BPA's PF rate applicable to exchanging utilities. The 
amount of power purchased and sold is equal to the utility's eligible 
residential and small farm load. Benefits must be passed directly to 
the utility's residential and small farm customers.
16. Slice Product
    The Slice product is a power sale based upon an eligible customer's 
annual net firm requirements load and is shaped to BPA's generation 
from the Federal system resources over the year. Slice purchasers are 
entitled to a fixed percentage of the energy generated by the FCRPS. 
The Slice purchaser's percentage entitlements are set by contract. The 
Slice product includes both service to net requirements firm load as 
well as an advance sale of surplus power.
B. Definition of Rate Schedule Terms
1. 2002 Contract
    A 2002 contract is a contract for service in the FY 2002 through 
2006 rate period that is signed after January 1, 1999.
2. Annual Billing Cycle
    The Annual Billing Cycle is the 12 months beginning with the 
customer's first monthly power bill for deliveries in the first billing 
month starting on or after October 1.
3. Billing Demand
    The Purchaser's Billing Demand is the amount of capacity to which 
the demand charge specified in the rate schedule is applied. When the 
rate schedule includes charges for several products, there may be a 
Billing Demand quantity for each product. The calculation of Billing 
Demand is described in the customer's contract.
4. Billing Energy
    The Purchaser's Billing Energy is the amount of energy to which the 
energy

[[Page 44356]]

charge specified in the rate schedule is applied. When the rate 
schedule includes charges for several products, there may be a Billing 
Energy quantity for each product. Billing Energy is divided into HLH 
and LLH for this rate period.
5. California Independent System Operator (California ISO)
    The FERC regulated control area operator of the ISO transmission 
grid. Its responsibilities include providing non-discriminatory access 
to the transmission grid, managing congestion, maintaining the 
reliability and security of the grid, and providing billing and 
settlement services. The ISO has no affiliation with any market 
participant.
6. California ISO Spinning Reserve Capacity
    The portion of unloaded synchronized generating capacity, 
controlled by the California ISO, which is capable of being loaded in 
10 minutes, and which is capable of running for at least two hours.
7. California ISO Supplemental Energy
    Energy from generating units and other resources which have 
uncommitted capacity following finalization of the hour-ahead schedules 
and for which scheduling coordinators have submitted bids to the 
California ISO at least 30 minutes before the commencement of the 
settlement period.
8. California Power Exchange (California PX)
    An independent agency responsible for conducting an auction for the 
generators seeking to sell energy and for loads which are not otherwise 
being served by bilateral contracts. The California PX is responsible 
for scheduling generation in its scheduling (e.g., day-ahead) markets, 
for determining hourly market clearing prices for its market, and for 
settlement and billing for suppliers and Utility Distribution Company's 
(UDC) using its market.
9. Contract Demand
    The Contract Demand is the maximum number of kilowatts that the 
Purchaser agrees to purchase and BPA agrees to make available, subject 
to any limitations included in the applicable contract between BPA and 
the Purchaser.
10. Contract Energy
    Contract Energy is the maximum number of kilowatthours that the 
Purchaser agrees to purchase and BPA agrees to make available, subject 
to any limitations included in the applicable contract between BPA and 
the Purchaser.
11. Control Area
    A Control Area is the electrical (not necessarily geographical) 
area within which a controlling utility operating under all NERC 
standards has the responsibility to adjust its generation on an 
instantaneous basis to match internal load and power flow across 
interchange boundaries to other Control Areas.
12. Decremental Cost
    Unless otherwise specified in a contractual arrangement, 
Decremental Cost as applied to Nonfirm Energy transactions is defined 
as:
    a. All identifiable costs (expressed in mills/kWh) associated with 
the use of a displaceable thermal resource or end-use load with 
alternate fuel source to serve a purchaser's load that the purchaser is 
able to avoid by purchasing power from BPA, rather than generating the 
power itself or using an alternate fuel source; or
    b. All identifiable costs (expressed in mills/kWh) to serve the 
load of a displaceable purchase of energy that the purchaser is able to 
avoid by choosing not to make the alternate energy purchase.
    All identifiable costs as used in the above definition may be 
reduced to reflect costs of purchasing BPA energy such as transmission 
costs, losses, or loopflow constraints that are agreed to by BPA and 
the Purchaser.
13. Delivering Party
    The entity supplying the capacity and/or energy to be transmitted 
at Point(s) of Interconnection.
14. Demand Entitlement
    For purchases made under contracts for core Subscription products, 
Demand Entitlement is the largest HLH amount of power in kilowatts that 
the purchaser is entitled to receive from BPA during the billing period 
as specified in the contract.
15. Discount Period
    The end of the rate period or the customer's contract term, 
whichever comes first.
16. Dow Jones Mid-C Indexes (DJ Mid-C Indexes)
    Peak and offpeak price indexes for sale of firm and nonfirm power 
traded at the Mid-Columbia Bus.
17. Electric Power
    Electric Power is electric peaking capacity (kilowatts) and/or 
electric energy (kilowatthours).
18. Energy Entitlement
    For purchases made under contracts for core Subscription products, 
HLH and LLH Energy Entitlement is the sum in kilowatthours of amounts 
for HLH and LLH energy respectively, that the purchaser is entitled to 
receive from BPA as specified in the contract.
19. Federal System
    The Federal System is the generating facilities of the FCRPS, 
including the Federal generating facilities for which BPA is designated 
as marketing agent; the Federal facilities under the jurisdiction of 
BPA; and any other facilities:
    a. From which BPA receives all or a portion of the generating 
capability (other than station service) for use in meeting BPA's loads 
to the extent BPA has the right to receive such capability. ``BPA's 
loads'' do not include any of the loads of any BPA customer that are 
served by a non-Federal generating resource purchased or owned directly 
by such customer which may be scheduled by BPA;
    b. Which BPA may use under contract or license; or
    c. To the extent of the rights acquired by BPA pursuant to the 1961 
U.S.-Canada Treaty relating to the cooperative development of water 
resources of the Columbia River Basin.
20. Firm Power (PF-02, IP-02, NR-02, RL-02)
    Firm Power is electric power (capacity and energy) that BPA will 
make continuously available under contracts executed pursuant to 
Section 5 of the Northwest Power Act.
21. Full Service Customer
    A Full Service customer is one who is purchasing power from BPA 
through the Full Service Product.
22. Generation System Peak
    The Generation System Peak is the hour of the largest HLH output of 
the Federal System that occurs during the customer's billing period.
23. Heavy Load Hours (HLH)
    Heavy Load Hours (HLH) are all those hours in the peak period hour 
ending 7 a.m. to the hour ending 10 p.m., Monday through Saturday, 
Pacific Prevailing Time (Pacific Standard Time or Pacific Daylight 
Time, as applicable). There are no exceptions to this definition; that 
is, it does not matter

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whether the day is a normal working day or a holiday.
24. Inventory Solution Costs
    Costs associated with BPA's potential actions to supplement the 
capability of the Federal System Resources, as a result of BPA's 
Subscription process. It is currently not known whether an Inventory 
Solution will be necessary, or what form the Inventory Solution will 
take.
25. Light Load Hours (LLH)
    Light Load Hours (LLH) are all those hours in the offpeak period 
hour ending 11 p.m. to the hour ending 6 a.m., Monday through Saturday 
and all hours Sunday, Pacific Prevailing Time (Pacific Standard Time or 
Pacific Daylight Time, as applicable).
26. Measured Demand
    The Purchaser's Measured Demand is that portion of its Metered or 
Scheduled Demand provided by BPA to the Purchaser. If more than one 
class of power is delivered to any point of delivery, the portion of 
the measured quantities assigned to any class of power shall be as 
specified by contract. Any delivery of Federal power not assigned to 
classes of power delivered under other agreements shall be included in 
the Measured Demand for PF, NR, or IP power as applicable. The portion 
of the total Measured Demand so assigned shall constitute the Measured 
Demand for each such class of power. Any residual quantity, after 
determination of the Purchaser's contractual entitlement at a 
particular rate, is considered ``unauthorized.'' Unauthorized increases 
are billed in accordance with the provisions of these GRSPs.
    In determining Measured Demand for any Purchaser who experiences an 
outage as defined pursuant to the Purchaser's agreement with BPA, BPA 
shall adjust any abnormal Integrated Demand due to, or resulting from:
    a. Emergencies or breakdowns on, or maintenance of, the Federal 
System Facilities; and
    b. Emergencies on the Purchaser's facilities to the extent BPA 
determines that such facilities have been adequately maintained and 
prudently operated. BPA will follow its billing process in establishing 
the Billing Demand should an outage cause an unusual Billing Demand 
quantity. BPA will not give outage credits for demand.
27. Measured Energy
    The Purchaser's Measured Energy is that portion of its Metered or 
Scheduled Energy that is provided by BPA to the Purchaser during a 
particular diurnal period (HLH or LLH) in a billing period. If more 
than one class of power is delivered to any point of delivery, the 
portion of the measured quantities assigned to any class of power shall 
be as specified by contract. Any delivery of Federal power not assigned 
to classes of power delivered under other agreements shall be included 
in the Measured Energy for PF, NR, or IP power as applicable. The 
portion of the total Measured Energy so assigned shall constitute the 
Measured Energy for each such class of power. Any residual quantity, 
after determination of the Purchaser's contractual entitlement at a 
particular rate, is considered ``unauthorized.'' Unauthorized increases 
are billed in accordance with the provisions of these GRSPs.
28. Metered Demand
    The Metered Demand in kilowatts shall be the largest of the 60-
minute clock-hour Integrated Demands at which electric energy is 
delivered to a purchaser:
    a. At each point of delivery for which the Metered Demand is the 
basis for determination of the Measured Demand;
    b. During each time period specified in the applicable rate 
schedule; and
    c. During any billing period.
    Such largest Integrated Demand shall be determined from 
measurements made in accordance with the provisions of the applicable 
contract and these GRSPs. This amount shall be adjusted as provided 
herein and in the applicable agreement between BPA and the Purchaser.
29. Metered Energy
    The Metered Energy for a purchaser shall be the number of 
kilowatthours that are recorded on the appropriate metering equipment, 
adjusted as specified in the applicable agreement and delivered to a 
Purchaser:
    a. At all points of delivery for which metered energy is the basis 
for determination of the Measured Energy; and
    b. during any billing period.
30. Mid-Columbia Bus (Mid-C Bus)
    The switchyards associated with five non-Federal hydroelectric 
projects, including Rocky Reach, Priest Rapids, Wanapum, Douglas, and 
McKenzie. The following Federal switchyards which are operated by BPA 
and interconnected with the non-Federal switchyards are also included: 
Valhalla, Columbia, Midway, Sickler, and Vantage.
31. Monthly Federal System Peak Load
    Monthly Federal System Peak Load is the peak load on the Federal 
System during a customer's billing month, determined by the largest 
hourly integrated demand produced from system generating plants in 
BPA's control area and scheduled imports for BPA's account from other 
control areas.
32. NP15
    The portion of the California ISO's control area north of 
transmission path 15.
33. NW1 (California-Oregon Border)
    California PX and California ISO designation for delivery at COB 
(Captain Jack/Malin).
34. NW3 (Nevada-Oregon Border)
    California PX and California ISO designation for delivery at NOB.
35. Partial Service Customer
    A Partial Service customer is any customer that is not a Full 
Service customer.
36. Point of Delivery (POD)
    A Point of Delivery is the contractual interconnection point where 
power is delivered to the customer. Typically, a point of delivery is 
located at a substation site, but it could be located at the change of 
ownership point on a transmission line.
37. Point of Integration (POI)
    A Point of Integration is the contractual interconnection point 
where power is received from the customer. Typically a point of 
integration is located at a resource site, but it could be located at 
some other interconnection point to receive system power from the 
customer.
38. Point of Interconnection (POI)
    A Point of Interconnection is a point where the facilities of two 
entities are interconnected.
39. Points of Metering (POM)
    The Points of Metering (POM) shall be those points specified in the 
contract at which TRL and Metered Amounts are measured.
40. Pre-Subscription Contract
    A contract for service in the FY 2002 through 2006 rate period that 
was signed prior to January 1, 1999, is a Pre-Subscription Contract.
41. Purchaser
    Pursuant to the terms of an agreement and applicable rate 
schedule(s), a Purchaser contracts to pay BPA for providing a product 
or service.

[[Page 44358]]

42. Receiving Party
    The entity receiving the capacity and/or energy transmitted by BPA 
to a Point(s) of Delivery.
43. Retail Access
    Retail Access is nondiscriminatory retail distribution access 
mandated either by Federal or State law which grants retail electric 
power consumers the right to choose their electricity supplier.
44. Scheduled Demand
    For purposes of applying the rates herein to applicable purchases 
by the Purchaser, the Scheduled Demand in kilowatts is the largest of 
the hourly demands at which electric energy is scheduled by BPA for 
delivery to a purchaser:
    a. To each system for which Scheduled Demand is the basis for 
determination of the Measured Demand;
    b. During each time period specified in the applicable rate 
schedule; and
    c. During any billing period.
    Scheduled Demand is deemed delivered for the purpose of determining 
Billing Demand.
45. Scheduled Energy
    For purposes of applying the rates herein to applicable purchases 
by the Purchaser, Scheduled Energy in kilowatthours shall be the sum of 
the hourly demands at which electric energy is scheduled by BPA for 
delivery to a purchaser:
    a. For each system for which Scheduled Energy is the basis for 
determination of the Measured Energy; and
    b. During any billing period.
    Scheduled Energy is deemed delivered for the purpose of determining 
Billing Energy.
46. Slice Administrative Costs
    All overhead costs incurred by BPA that are attributable to the 
implementation of the Slice product.
47. Slice Revenue Requirement
    The Slice Revenue Requirement is comprised of all the line items in 
BPA's PBL revenue requirement as identified in all of the PBL's rate 
cases that are effective during the term of the Slice Purchaser's 
contract except for the following items: (1) transmission costs (other 
than those associated with the fulfillment of System Obligations); (2) 
power purchase costs (with the exception of those net costs incurred as 
part of the ``Inventory Solution''); and (3) planned net revenues for 
risk.
    See Table E for Slice Product Costing Table.
48. Subscription
    Subscription refers to the Power Subscription Strategy issued by 
BPA on December 21, 1998, which is BPA's policy power sales beginning 
FY 2002.
49. Subscription Contract
    See 2002 Contract.
50. System Obligations

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    System Obligations include, but are not limited to, the 
transmission costs associated with the return of the Canadian 
Entitlement, and transactions related to the Pacific Northwest 
Coordination Agreement, Mid-Columbia Hourly Coordination, and the 
Canadian Non-Treaty Storage Agreement.
51. Total Plant Load
    Total Plant Load means a DSI customer's total electrical energy 
load at facilities eligible for BPA service during any given time 
period whether the customer has chosen to serve its load with BPA power 
or non-Federal power.
52. Total Retail Load (TRL)
    Total Retail Load is all electric power consumption including 
distribution system losses, within a utility's distribution system as 
measured at metering points, adjusted for unmetered loads or 
generation. No distinction is made between load that is served with BPA 
power and load that is served with power from other sources. For DSIs, 
Total Retail Load is called Total Plant Load.
53. Utility Distribution Company
    A company that owns and maintains the distribution facilities used 
to serve end-use customers.

BPA's New 1996 General Rate Schedule Provisions for Power Rates

A. Targeted Adjustment Charge for Uncommitted Loads
1. Availability
    The Targeted Adjustment Charge for Uncommitted Loads (TACUL) 
pertains to the PF rate schedule. The TACUL applies after December 7, 
2000, to purchases to serve customer loads that were uncommitted during 
the 1996 rate case which are returned to BPA firm power requirements 
service during a period prior to FY 2002. Customers subject to the 
TACUL are those that reduced their purchases from BPA by adding firm 
resources to serve load under: (1) 1981 power sales contracts that 
expire on or before July 31, 2001, as may be amended; (2) Amendatory 
Agreement No. 7 (AA7) to the 1981 power sales contracts, or new 
``1996'' power sales contracts where the customer provides BPA notice 
after December 7, 1998, consistent with the terms of the customer's 
power sales contract, for requirements service for the period prior to 
FY 2002. This charge will be in effect through September 30, 2001.
    This rate schedule amends the PF-96 rate schedule, which went into 
effect October 1, 1996.
2. Energy Charge
    The TACUL is a monthly mills/kWh adjustment to the HLH and LLH 
energy rates specified in the 1996 rate schedule, and is applied to 
that portion of the customer's load that is subject to the TACUL. The 
TACUL rate adjustment will be established based on the following 
formula:

TACUL = [(Incr $ * Incr Amt)-(Rate $ * Incr Amt)]/TACUL Amt

Where:

TACUL Amt = The amount of load subject to the TACUL, determined 
monthly.
Rate $ = The monthly PF energy rate shown in the applicable rate 
schedule.
Inventory Amt = Amount of energy available to serve this load based on 
an annual energy Federal system firm resource capability as defined in 
the Loads and Resources Study, and updated if BPA determines that is 
necessary.
Incr $ = Monthly cost to BPA, plus a handling fee, of incremental power 
for HLH and LLH expressed in mills/kWh (see below). These costs also 
may include where applicable, wheeling, ancillary, and other charges 
BPA may incur in purchasing power from other entities such as, but not 
limited to, the California ISO or the California PX.
Incr Amt = Amount of incremental power required, determined monthly and 
defined as the TACUL Amt minus the Inventory Amt. (If there is no 
available Inventory Amt, the Incr Amt will equal the TACUL Amt).

    Incr $ is greater than Rate $ (If Incr $ is less than Rate $, the 
TACUL is 0 mills/kWh).
    TACUL is the monthly rate adjustment in mills/kWh. BPA will 
calculate the cost (Incr $) per month in mills/kWh of the additional 
power per month (Incr Amt) for a specific Customer request. BPA will 
establish the cost of the additional power by the following methods:
    a. BPA will establish the price based on BPA's monthly cost to 
purchase the incremental load by purchases of resources at market, or 
the monthly cost of BPA recallable power contracts, averaged, whichever 
is less.
    b. A price plus handling fee calculated based on the following 
index.
    BPA will calculate the price per month for HLH and LLH, based on an 
index calculated according to the following:

Price of HLH = \1/3\ HLH (DJ Mid C) + \1/3\ HLH (California PX) + \1/3\ 
(NYMEX Mid C)
Price of LLH = \1/2\ LLH (DJ Mid C) + \1/2\ LLH (PX)

Where the California PX basis is adjusted to DJ Mid C

Where:

DJ Mid C = Dow Jones Firm On-peak (HLH) and Firm Off-peak (LLH) Mid-
Columbia Electricity Price Index
California PX = California Power Exchange Day-Ahead Zonal Prices 
(Constrained)--the average of NW1 (Captain Jack/Malin--COB) and NW3 
(NOB) for HLH and LLH
NYMEX Mid C = the New York Mercantile Exchange Futures Electricity 
Closing Price at Mid-C for the applicable month

California PX prices will be adjusted for basis difference between COB/
NOB and the Mid-C using the IS/PTP Rates contained in BPA's 1996 
Transmission Rate Schedules.

    Issued in Portland, Oregon, on July 30, 1999.
Jack Robertson,
Deputy Administrator.
[FR Doc. 99-20805 Filed 8-12-99; 8:45 am]
BILLING CODE 6450-01-P