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

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........................................... I

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