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

SUMMARY: BPA File No: WP-95. BPA requests that all comments and

documents intended to become part of the Official Record in this

process contain the file number designation WP-95.

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. BPA is proposing

wholesale power rate schedules to be effective October 1, 1995, so that

the wholesale power rates in total produce revenues that best enable

BPA to meet its costs.

The proposal BPA is making at this time is preliminary. While BPA

was in the late stages of putting together its proposal, it determined

that the proposal as prepared could send an erroneous signal of BPA's

commitment to rate stability. Competitive forces are causing

fundamental and significant changes in the Pacific Northwest wholesale

electric power market on a weekly, and sometimes a daily, basis. The

competition is relentless, and BPA can not issue a final rate proposal

that does not allow it to meet and beat the competition. Nothing other

than that will allow BPA to sustain its statutory responsibilities. As

a consequence, BPA has determined that its initial proposal should

include a stable, 5-year rate for most, if not all, of its requirements

service. BPA anticipates that the work necessary to assemble such a

proposal will take until late March or early April of 1995. Since such

a rate would cover the bulk of BPA's firm sales, its impact on BPA's

overall proposal is fundamental. Thus, the information BPA is releasing

now should be considered preliminary. Information in BPA's preliminary

proposal concerning rate design, product definition and pricing,

revenue requirement, and other matters should provide parties valuable

information that will enable them to better assess BPA's initial

proposal when it is released in late March or early April. BPA will

propose a rate hearing schedule at the prehearing conference that will

take into account changes in the markets and allow review of BPA's

initial proposal that it intends to make in late March or early April

of 1995. The rate hearing schedule will be published in the Federal

Register immediately following the prehearing conference.

Opportunities will be available for interested persons to review

BPA's rate proposal, to participate in the rate hearing, and to submit

oral and written comments. During the development of the final rate

proposal, BPA will evaluate all written and oral comments received in

the rate proceeding. Consideration of comments and more current data

may result in the final rate proposal differing from the rates proposed

in this Notice.

DATES: Persons wishing to become a formal ``party'' to the proceedings

must notify BPA in writing of their intention to do so in accordance

with requirements stated in this Notice. Petitions to intervene must be

received by 9 a.m. February 13, 1995, and should be addressed as

follows: Hearing Officer, c/o Francis (Jamie) Troy, Hearing Clerk-LQ,

Bonneville Power Administration, 905 NE. 11th Ave., P.O. Box 12999,

Portland, Oregon 97212.

In addition, a copy of the petition must be served concurrently on

BPA's Office of Legal Services:, Janet L. Prewitt, Office of Legal

Services-LQ, 905 NE. 11th Ave., P.O. Box 3621, Portland, Oregon 97208.

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.

A prehearing conference will be held before the Hearing Officer at

9:00 a.m. on February 13, 1995, in the BPA Rates Hearing Room, 3rd

Level, 2032 Lloyd Center; Portland, Oregon. Registration for the

prehearing conference will begin at 8:30 a.m. BPA will prefile

preliminary proposal studies at the prehearing conference. The Hearing

Officer will act on all intervention petitions and oppositions to

intervention petitions, rule on any motions, establish additional

procedures, establish a service list, establish a procedural schedule,

and consolidate parties with similar interests for purposes of filing

jointly sponsored testimony and briefs, and for expediting any

necessary cross-examination. A notice of the dates and times of any

hearings will be mailed to all parties of record. Objections to orders

made by the Hearing Officer at the prehearing conference must be made

in person or through a representative at the prehearing conference.

The following schedule information is provided for informational

purposes. A final schedule will be established by the Hearing Officer

at the prehearing conference.

On or about February 9, 1995--Rate Schedules and General Rate Schedule

Provisions, mailed to customers and 1993 rate case parties and

available from BPA's Public Information Center; 905 NE. 11th, 1st

Floor, Portland, Oregon.

February 13, 1995--Deadline for interventions to be filed with Hearing

Clerk at above address.

On or about February 13, 1995--Preliminary proposal studies available

at BPA's Rates Hearing Room; 2032 Lloyd Center; Portland, Oregon and

BPA's Public Information Center; 905 NE. 11th, 1st Floor, Portland,

Oregon.

February 13, 1995--Prehearing conference to set schedule and act on

petitions to intervene.

On or about April 5, 1995--BPA Initial Proposal filed.

October 29, 1995--Final Record of Decision published.

BPA also will be conducting public field hearings. A field hearing

schedule will be announced at the prehearing conference. A notice of

the dates, times, and locations of the field hearings will be made

later through mailings and public advertising.

When BPA holds public field hearings, written transcripts are made

and included in the official record. A notice of the dates and times of

the field hearings also will be published in the Federal Register.

ADDRESSES: The date for written comments by participants must be

received by May 15, 1995, to be considered in the Draft Record of

Decision (ROD). 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, (503) 230-4328

or call toll-free 1-800-622-4519. Information may also be obtained

from:

Mr. Steve Hickok; Group Vice President, Sales and Customer Service;

P.O. Box 3621; Portland, OR 97232 (503-230-5356) [[Page 8497]]

Mr. George Eskridge; Manager, SE Sales and Customer Service District;

1101 W. River, Suite 250; Boise, ID 83702 (208-334-9137)

Mr. Ken Hustad; Manager, NE Sales and Customer Service District;

Crescent Court, Suite 500; 707 Main; Spokane, WA 99201 (509-353-2518)

Ms. Ruth Bennett; Manager, SW Sales and Customer Service District; 703

Broadway; Vancouver, WA 98660 (360-418-8600)

Ms. Marg Nelson; Manager, NW Sales and Customer Service District; 201

Queen Anne Ave. N., Suite 400; Seattle, WA 98109-1030 (206-216-4272).

Responsible Official: Mr. Geoff Moorman, Manager for Pricing,

Marginal Cost and Ratemaking, is the official responsible for the

development of BPA's rates.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Introduction

II. Purpose and Scope of Hearing

III. Procedures Governing Rate Adjustments and Public Participation

IV. Major Studies

V. Tiered Rates Methodology

VI. Wholesale Power Rate Schedules

VII. Charges Under the Amended and Integrated Pacific Northwest

Coordination Agreement

I. Introduction

After the 1993 rate case, BPA conducted a series of workshops on

subjects relevant to its ratemaking. The purpose of the workshops was

to identify, simplify, and reduce the number of issues that might

become part of the 1995 rate case, and to reduce the amount of

discovery normally required during the formal rate proceedings.

Opportunity was provided to address the impacts of BPA's

``reinvention,'' transmission issues, risk mitigation, forecasted

revenue requirements, and rate design issues. The workshops provided

opportunity for informal public comment on issues prior to the formal

hearing process.

On December 28, 1994, BPA published in the Federal Register a

Notice of ``Intent to Revise Wholesale Power Rates to Become Effective

October 1, 1995,'' 59 F.R. 66947, in order to satisfy contractual

provisions between BPA and its customers. Since then, BPA has continued

to study the adequacy of its current rates and has concluded that

current rates must be adjusted for the FY 1996 and FY 1997 rate period.

BPA also is considering setting some rates for periods longer than 2

years.

In order to assess its current rates, BPA first determined the

amount of revenues required to meet its financial obligations in FY

1996 and FY 1997. BPA has determined that the revenues it would expect

to collect from projected sales under its current rates will not

adequately recover these revenue requirements. Therefore, BPA proposes

to revise its wholesale power rates. At the conclusion of the rate

proceeding, BPA will file its rates with the Federal Energy Regulatory

Commission (FERC) for confirmation and approval.

Consistent with the risk mitigation policy adopted in BPA's last

rate case, BPA's preliminary proposal contains an Interim Rate

Adjustment (IRA) that allows, but does not require, BPA to increase its

rates for the second year of the rate period to reverse any serious,

unplanned decline in financial reserves that occurs in the first year

of the rate period. BPA also is including power rate schedules in this

preliminary proposal that are both new and significantly different from

BPA's 1993 power rate schedules, as well as including the negotiated

rates for the Pacific Northwest Coordination Agreement.

BPA is planning significant changes in the design of its power

rates. BPA is proposing to divide its priority firm (PF) and industrial

firm power (IP) rates into two tiers, (Tier 1 and Tier 2) and to

establish separate rates for each tier. The other services and products

that customers may select to complement either firm requirements

service provided by BPA, or power acquired from other sources, will be

priced separately.

The proposed wholesale power rates 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 Pacific Northwest Electric Power Planning and

Conservation Act, 16 U.S.C. 839 (1982). The proposed rate schedules

reflect many requirements contained principally in the Northwest Power

Act's rate directives (section 7) and the conditions related to classes

of customers and services contained in the Northwest Power Act's power

sales directives (section 5).

BPA proposes that its wholesale power rate schedules, including the

adjustments, charges, and special rate provisions, and the General Rate

Schedule Provisions associated with these rate schedules, become

effective upon interim approval or upon final confirmation and approval

by FERC. (BPA's proposal combines the General Rate Schedule Provisions

for Wholesale Power Rates and Transmission Rates into one document--the

GRSPs). BPA currently anticipates that it will request FERC approval of

its revised rates effective October 1, 1995.

The 1995 wholesale power rate schedules, and the GRSPs associated

with those rate schedules, supersede BPA's 1993 rate schedules (which

became effective October 1, 1993) to the extent stated in the

Availability section of each 1995 rate schedule. These schedules and

GRSPs shall be applicable to BPA power sales contracts, as appropriate,

including contracts executed both prior to and subsequent to enactment

of the Northwest Power Act. In addition, as stated in the availability

section of each schedule, certain of the rates and tiered rate

methodology will be effective for extended periods of time.

In developing the proposed wholesale power rates, BPA considered

many factors, including revenue requirements, ease of administration,

revenue stability, rate continuity, ease of comprehension, and BPA's

statutory obligations. The studies that have been prepared to support

the proposed preliminary rates will be mailed to all parties to BPA's

1993 rate case and will be available for examination on February 13,

1995, at BPA's public Information Center, BPA Headquarters Building,

1st Floor; 905 NE. 11th; Portland, and will be available at the

prehearing conference, to the extent they are available. The

preliminary studies and documents are:

1. Loads and Resources Study and Documentation

2. Revenue Requirement Study and Documentation

3. Segmentation Study

4. Marginal Cost Analysis Study and Documentation

5. Wholesale Power Rate Development Study and Documentation

6. Wholesale Power and Transmission Rate Schedules.

BPA's proposed Wholesale Power and Transmission Rate Schedules and

General Rate Schedule Provisions will be published in a separate

Federal Register Notice on or about February 13, 1995. In addition, the

documents described above will be mailed to BPA's customers, 1993 rate

case parties, and other interested persons, and will be available from

BPA's Public Information Center on or about February 9, 1995.

To request any of the above documents by telephone, call BPA's

document request line: (503) 230-3478 or call toll-free 1-800-622-4520.

Please request the document by its above-listed title. Also state

whether you require the [[Page 8498]] accompanying documentation (these

can be quite lengthy); otherwise, the study alone will be provided.

(For example, ask for the ``Revenue Requirement Study and

Documentation.'')

Because of the complexity of the issues in this rate case, in part

occasioned by continuing contract negotiations between BPA and its

customers, as well as BPA's ``reinvention'' and Competitiveness

Project, BPA anticipates that it will need to meet with customers and

other interested third parties during the rate case on a very frequent,

and possibly extended, basis. 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.

II. Purpose and Scope of Hearing

BPA's proposal to revise its wholesale power rates is needed in

order for BPA to continue to recover all costs and expenses allocated

to the Federal power system, including amortization of the Federal

investment in the FCRPS over a reasonable period of time, and to

recover the costs in a way that achieves the goals of BPA's

Competitiveness Project. BPA has found that substantial changes must be

made in the ways in which it sets its rates if it is to remain

competitive. If BPA is not competitive, it will not recover its costs,

and it then will be unable to satisfy its statutory responsibilities.

BPA began its Competitiveness Project in early 1993 in response to

market forces and deregulation of the electric utility industry. The

project, a re-invention of the agency to make it more competitive in

the new marketplace, included the development of a new business

concept, a marketing plan, a review of all of BPA's activities leading

to structural reorganization, strategic action plans for each of BPA's

major activities, an internal effort to promote leadership and employee

empowerment, and proposals to eliminate unnecessary administrative and

regulatory requirements.

BPA's Draft Strategic Business Plan and the Draft Business Plan EIS

were released to the public in June 1994. The Draft Strategic Business

Plan sets the overall strategic direction for both serving BPA's

customers and meeting BPA's legislated responsibilities, including new

statements of BPA's mission, values, and strategic business objectives

to guide its activities. The Draft Strategic Business Plan also

describes the conceptual framework for the products BPA is offering. As

stated in the Draft Strategic Business Plan, BPA's pricing policies are

designed to meet many objectives, including (1) providing maximum

customer choice and encouraging optimal use of the FCRPS; (2)

contributing to BPA's continued viability in an increasingly

competitive energy market environment; and (3) allowing BPA to take

full advantage of its responsibility and authority to manage the FCRPS,

consistent with all statutory requirements.

The Draft Strategic Business Plan envisions BPA as having three

separate and distinct business lines--power, transmission, and energy

services (conservation)--which will be self-supporting and serve

customers according to their unique needs. The Draft Strategic Business

Plan also outlines a number of initiatives to improve BPA's

competitiveness, including strategies to close the projected gap

between BPA's costs and revenues, a financial strategy, and proposals

to change BPA's power rate structures to give customers more choice, to

more accurately reflect BPA's costs associated with providing the

discrete components of electric service selected by customers, and

thereby to encourage investment in cost-effective conservation. BPA

proposes to close the revenue gap by exerting strict cost management

and becoming market-driven.

To provide customers with a price signal that encourages efficient

resource investment decisions, including conservation resources, and

appropriately shares the benefits of the relatively low-cost Federal

power and transmission systems, BPA is proposing to tier its power

rates for requirements service and for the residential exchange. The

rate for requirements service would be divided into two parts: a Tier 1

rate, and one or several alternative Tier 2 rates. BPA expects that the

Tier 1 rate will be available to serve most of the existing customers'

firm loads. The Tier 1 rate is expected to be a lower rate than Tier 2

because it will be based primarily on the costs associated with the

existing Federal system. The Tier 2 rates will be available to serve

regional firm requirements in excess of Tier 1, including future load

growth, and will be based on the costs associated with supplying power

to meet these loads.

To address the increasingly competitive market for power,

transmission, and energy services, BPA is proposing to offer a menu of

unbundled products in the 1995 rate case. BPA expects that the products

offered will be available both under the current power sales contracts

and under new power sales contracts. BPA expects to offer additional

unbundled products in future rate cases and to price these products to

meet market conditions and its cost recovery obligations. In some

cases, BPA expects the market will require flexible pricing. BPA is

planning to ``unbundle'' what it offers so customers can choose among

products and services based on what they need to meet their loads and

support their own resources, if any.

BPA is assessing the potential environmental effects of its rate

proposal, as required by the National Environmental Policy Act (NEPA),

as part of the Business Plan Environmental Impact Statement (EIS).

Beginning in June 1994, BPA solicited input to the Draft Strategic

Business Plan and the Business Plan EIS from customers throughout the

region. From August 3-August 9, BPA held numerous public comment

meetings throughout the region. Additionally BPA held a Draft Business

Plan EIS workshop where participants were invited to design their own

alternatives and consider the environmental and fiscal result. BPA

field staff also were available to brief groups on the Draft Business

Plan upon request. A supplemental Draft EIS, revised in response to

comments received, will be available for public comment in February.

The Draft EIS evaluates BPA's Business Plan proposal and a range of

alternatives, including the impacts of the range of potential rate

designs for BPA's power and transmission services. It also documents

the impact of the current rate proposal for purposes of the National

Environmental Policy Act. Comments on the Business Plan EIS will be

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 1995 rates. The Final Business Plan

and the Business Plan EIS that elaborates BPA's strategic action plans

will be released in late 1995.

BPA's spending levels are developed as a part of its Strategic

Business Plan, with the benefit of a public comment process. They also

are determined as a part of the Federal budget process. Consistent with

the Draft Strategic [[Page 8499]] Business Plan, the Administrator

formally announced spending levels for FYs 1996-2001 to the public on

January 12, 1995. BPA will continue to refine its strategic business

objectives, goals, and spending levels, and inform the public

accordingly, as part of its Strategic Business Plan development

process. That process is expected to culminate in a final Strategic

Business Plan published in June 1995. Therefore, except for the limited

exceptions hereafter noted, spending level decisions will not be

addressed in this rate case. Accordingly, pursuant to section 1010.3(f)

of the ``Procedures, Governing Bonneville Power Administration Rate

Hearings,'' 51 FR 7611 (March 5, 1986) (hereinafter 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 cost evaluation period of FY 1995 through FY 2000 and its test

period revenue requirement for FYs 1996 through 2000. If, and to the

extent, any re-examination of spending levels is necessary, that re-

examination will occur outside of the rate case. BPA's Revenue

Requirement Study will incorporate spending levels and reflect BPA's

risk mitigation, capital funding, and other financial goals in the

rates. 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) provision in BPA's revenue requirement for

cash working capital or cash lag needs; (4) repayment matters such as

interest rate forecasts, scheduled amortization, depreciation,

replacements, and interest expense; and (5) updates to forecasts by BPA

which may occur in the spring of 1995 and for which no other review

forum has been provided.

III. Procedures Governing Rate Adjustments and Public Participation

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, issuance of a

Federal Register Notice announcing the proposed rates; one or more

hearings; the opportunity to submit written views, supporting

information, questions, and arguments; and a decision by the

Administrator based on the record. The proceedings for BPA's proposal

to adjust wholesale power rates will be combined with the proceedings

for BPA's proposal to adjust transmission rates. This proceeding will

be governed by BPA's rules for general rate proceedings, Sec. 1010.9 of

BPA's Procedures, due to the importance and complexity of the issues

involved. These Procedures implement the statutory section 7(i)

requirements. Section 1010.7 of the Procedures prohibits ex parte

communications.

BPA's Procedures distinguish 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 Procedures as any person who

may express views, but who does not petition successfully to intervene

as a party. Participants' written comments will be made part of the

official record of the case and considered by the Administrator. The

participant category gives the public the opportunity to participate

and have its views considered without assuming the obligations

incumbent upon ``parties.'' Participants are not entitled to

participate in the prehearing conference, cross-examine parties'

witnesses, seek discovery, or serve or be served with documents, and

are not subject to the same procedural requirements as parties.

Written comments by participants will be included in the record if

they are received by May 15, 1995. This date is anticipated to follow

the 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 Summary section of this Notice, above. 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 the rate decision.

The second category of interest is that of a ``party'' as defined

in Secs. 1010.2 and 1010.4 of BPA's Procedures. Parties may participate

in any aspect of the hearing process.

Persons wishing to become a formal ``party'' to BPA's rate

proceeding must notify the Hearing Officer and BPA in writing of their

request. Petitions to intervene shall state the name and address of the

person and the person's interests in the outcome of the hearing.

Petitioners may designate no more than two representatives upon whom

service of documents will be made. BPA customers and customer groups

whose rates are subject to revision in the hearing will be granted

intervention based on a petition filed in conformance with this

section. Other petitioners must explain their interests in sufficient

detail to permit the Hearing Officer to determine whether they have a

relevant interest in the hearing. Intervention petitions will be

available for inspection in BPA's Public Information Center; 1st Floor;

905 NE. 11th; Portland, Oregon. Any opposition to a petition to

intervene must be raised at the February 13, 1995, prehearing

conference. All timely applications will be ruled on by the Hearing

Officer. Opposition to an untimely petition to intervene shall be filed

and served within 2 days after service of the petition. Interventions

are subject to Sec. 1010.4 of BPA's Procedures.

The record will include, among other things, the transcripts of any

hearings, any written material submitted by the parties and

participants, documents developed by BPA staff, BPA's environmental

impact statement and comments accepted on it, and other material

accepted into the record by the Hearing Officer. The Hearing Officer

then will review the record, supplement it if necessary, and certify

the record to the Administrator for decision.

The Administrator will develop the final 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 Record of Decision (ROD). Parties will have an

opportunity to comment on the Draft ROD as provided in BPA's hearing

procedures. The Administrator will serve copies of the Final ROD on all

parties and will file the final proposed rates together with the record

with FERC for confirmation and approval.

IV. Major Studies

1. Loads and Resources Study

BPA's forecasts of regional loads by customer group are the basis

from which public utility and direct service industry (DSI) customer

purchases from BPA (Federal system firm loads) are projected. BPA also

projects Federal transmission losses, obligations to regional investor-

owned utilities (IOUs) under their power sales contracts, and other

inter- and intraregional contractual obligations.

BPA develops forecasts of regional non- and small-generating public

utility (NSGPU) and generating public utility [[Page 8500]] (GPU) loads

using standard econometric techniques. Regional NSGPU and GPU loads are

forecasted as a function of average retail electricity prices, weather-

related variables, and nonagricultural employment. The regional load

forecasts then are adjusted to account for factors such as effects from

proposed wholesale tiered rate implementation and conservation programs

to derive a projection of NSGPU and GPU purchases from BPA. The IOU

load forecast was produced by updating the economic assumptions from

the 1991 joint BPA/Northwest Power Planning Council (NPPC) forecast.

Forecasts of aluminum DSI purchases from BPA are prepared by

analyzing smelter production costs relative to aluminum prices, and by

considering other factors affecting smelter loads, including BPA's

proposed tiered rate implementation. Forecasted non-aluminum DSI

purchases from BPA are prepared by analyzing historical and technical

plant information and forecasted market conditions. Adjustments also

are made to incorporate the effects of BPA's tiered rate

implementation.

BPA's resource acquisition plans are based on work by BPA and the

NPPC staff and reflect extensive input and review by the general public

and the region's utilities. The specific resource acquisitions and

associated costs included in this proposal are based on BPA's 1994

Draft Strategic Business Plan. Besides emphasizing a diverse resource

portfolio, including both conservation and generating resources, BPA is

committed to moving toward a blend of acquisition methods, including

BPA-designed, utility-designed, and developer-initiated programs. This

combination of resource diversity and acquisition approaches allows BPA

to better deal with varying circumstances and uncertainties.

The load/resource balance determines BPA's obligation to serve firm

loads during the test years under 1930 water conditions. It also

contributes to the determination of the supply of surplus firm power in

the region and on the Federal system. A related hydro regulation study

incorporates the operation of thermal plants, exports and imports of

power, projected resource acquisitions, and system constraints such as

the Columbia River flow augmentation project, ``spill,'' and the water

budget for fish migration. For this preliminary proposal, a 50-year

hydro study was completed, which includes assumptions regarding the

Columbia River flow augmentation. The hydro study starts in August

1995. The 50-year study determines nonfirm energy availability for the

region.

2. Revenue Requirement Study

The Bonneville Project Act, the Flood Control Act of 1944, the

Transmission System Act, and the Northwest Power Act require BPA to set

rates that are projected to collect revenues sufficient to recover the

cost of acquiring, conserving, and transmitting the electric power that

BPA markets, including amortization of the Federal investment in the

FCRPS over a reasonable period, and to recover BPA's other costs and

expenses. The Revenue Requirement Study includes a demonstration as to

whether current rates will produce enough revenues to recover all BPA

costs and expenses, including BPA's repayment requirements to the U.S.

Treasury. Revenue requirements are the major factor in determining the

overall level of BPA's proposed power and transmission rates.

The Transmission System Act and the Northwest Power Act require

that transmission rates be based on an equitable allocation of the

costs of the Federal transmission system between Federal and non-

Federal power using the system. In compliance with a FERC order dated

January 27, 1984, 26 FERC 61,096, the Revenue Requirement Study

incorporates the results of separate repayment studies for the

generation and transmission components of the FCRPS. The repayment

studies for generation and transmission demonstrate the adequacy of the

projected revenues to recover all of the Federal investment in the

FCRPS over the allowable repayment period. Separate generation and

transmission revenue requirements are developed in the Revenue

Requirement Study. The adequacy of projected revenues to recover test

period revenue requirements and to meet repayment period recovery of

the Federal investment is tested and demonstrated separately for the

generation and transmission functions.

The Revenue Requirement Study for the 1995 preliminary rate

proposal is based on cost and revenue estimates for FY 1996 and FY

1997. BPA's Revenue Requirement Study reflects actual amortization and

interest payments paid through September 30, 1994. In addition, it

reflects all FCRPS obligations incurred pursuant to the Northwest Power

Act, including residential exchange costs.

3. Segmentation Study

BPA operates and maintains the Federal Columbia River Transmission

System (FCRTS) to provide transmission services throughout the region.

Because most services do not require the use of the entire system, the

FCRTS is divided into nine segments, each providing a distinct type of

service. The nine segments are: integrated network; Pacific Northwest-

Pacific Southwest (Southern) Intertie; Northern Intertie; Eastern

Intertie; generation integration; fringe area; and delivery segments

for public agency, DSI, and IOU customers.

The Segmentation Study categorizes the facilities of the FCRTS

according to the types of services it provides. This provides the basis

for segmenting the projected transmission revenue requirements used in

BPA's rate proposals. The results of the Study include the historical

investment and the average of the last three years' operations and

maintenance expenses. In addition, the facilities of the integrated

network similarly are divided among distinct services. This division of

the FCRTS into segments provides the basis for the equitable allocation

of transmission costs between Federal and non-Federal customers based

on their usage of the segments.

4. Marginal Cost Analysis

The Marginal Cost Analysis (MCA) estimates the marginal cost that

BPA incurs to supply energy on a seasonal, daily, and hourly basis to

meet customers' loads.

The conditions and terms under which BPA supplies energy

necessitate that BPA take actions that impose a cost. The MCA measures

the costs that BPA incurs in taking actions to provide energy under

different terms. BPA proposes to measure the marginal costs of actions

it takes to (1) guarantee availability of energy, (2) provide energy at

guaranteed prices, and (3) actually deliver energy. The results of the

MCA are used to develop wholesale power rates that promote efficient

development and operation of generation and conservation resources.

BPA proposes to measure marginal costs based on the supply and

demand conditions BPA faces in the interconnected West Coast wholesale

power market. Estimated marginal costs are based on the results from a

model that was developed to simulate future wholesale market

transactions to aid in BPA's long-term power marketing and resource

strategy decisions--the Power Marketing Decision Analysis Model

(PMDAM). PMDAM projects the opportunity costs that BPA will face when

taking actions to serve its Pacific Northwest customers, at the least

cost, under conditions of uncertainty. PMDAM uses information on the

costs associated with acquiring and operating [[Page 8501]] resources

to meet load in conjunction with the costs associated with purchasing

and/or selling power in the West Coast bulk power market.

The MCA provides estimates of BPAs marginal costs of supplying

energy at different times. These estimates provide the basis for

classifying BPA's costs. All of BPA's generation costs were classified

to hourly energy; no generation costs were classified to demand. The

estimates also provide the basis for the seasonal and hourly time-

differentiation of rates, including the identification of time-periods

in which different rates may apply and appropriate levels for rates in

each time period relative to the others. These time periods consist of

hours of the week when the marginal cost of power is high and those

when it is relatively low, as well as seasons of the year when

different marginal costs prevail. The results of the analysis suggested

more seasonality in BPA rates, three annual periods instead of the two

previous seasons. The results also suggested that BPA energy rates be

diurnally differentiated, which was not a feature of previous rate

designs. This analysis does not include any quantitative estimate of

marginal costs incurred on the transmission system.

5. Wholesale Power Rate Development Study (WPRDS)

BPA is proposing substantial changes in the method used to develop

its wholesale power rates. BPA's wholesale power rate develop is a two

step process. First, BPA performs a Cost of Service Analysis (COSA) and

then adjusts these results to reflect various rate design objectives

and statutory requirements.

A. Cost of Service Analysis

The Cost of Service Analysis (COSA) apportions BPA's test year

revenue requirement to customer classes based on the use of specific

types of service by each customer class and in accord with the rate

directives of the Northwest Power Act. BPA's revenue requirement is

functionalized to transmission and generation in the Revenue

Requirement Study. Transmission costs are identified with segments of

the transmission system in BPA's Segmentation Study. The results of

these studies are used in the COSA to determine the costs of providing

generation and transmission services to BPA's customers.

The COSA further identifies costs of specific types of service by

performing the following steps:

1. Classification. BPA classified transmission costs entirely to

capacity, and the transmission costs allocated to the power uses of the

transmission system form the basis for the power rates demand charge.

As described above in the Section concerning the Marginal Cost

Analysis, in this rate proposal BPA proposes to classify generation

costs to two components of electric power, delivered energy and rights

to energy.

2. Allocation. The final major step in the COSA is to allocate the

functionalized, segmented, and classified costs to customer classes.

BPA's proposed tiered rate design necessitates a change in cost

allocation approach. BPA is proposing to allocate costs to reflect the

difference in costs associated with existing loads and future loads.

Costs are allocated to classes of service on the basis of the relative

use of services, and on the basis of priorities of service by resource

pools provided in the Northwest Power Act. The COSA also determines and

allocates the net costs incurred under the Residential Exchange Program

prescribed in Section 5(c) of the Northwest Power Act. Costs that

cannot be attributed to a particular resource pool or customer are

allocated on a uniform basis to all customers.

a. Resource pools: For cost allocation purposes, BPA is proposing

to separate resources into two categories: FBS resources and new

resources. FBS resources are defined as (1) the Federal Columbia River

Power System hydroelectric projects; (2) resources acquired by the

Administrator under long-term contracts in force on the effective date

of the Pacific Northwest Power Act; and (3) the resources acquired by

the Administrator in an amount necessary to replace reductions in

capabilities of resources in (1) and (2). Since enactment of the

Northwest power Act in 1980, a number of events have occurred that have

reduced FBS resources capability. BPA has initiated a consultation

process with its customers in which BPA is considering replacing a

portion of this lost capability with approximately 450 average

megawatts from ten generating resources that BPA has acquired or

contracted for since 1980. For the preliminary proposal, these FBS

replacement resources are included in the FBS resource pool. Remaining

resources are included in the new resource pool.

For the test period, BPA is proposing to allocate the payments BPA

makes under the residential exchange program. Under the residential

exchange program, BPA purchases power offered by an exchanging utility

at its ``average system cost.'' BPA then sells an equivalent amount of

power back to the exchanging utility at the applicable PF rate. The

residential exchange transaction, however, is only a ``paper

transaction'' and does not result in actual power deliveries. The

program provides for BPA to pay exchanging utilities the difference

between the cost of power ``purchased'' by BPA and the cost of power

``sold'' by BPA. These cash payments by BPA are referred to as the net

cost of the exchange. For the test period, BPA is proposing to allocate

the net cost of the exchange to all firm loads except preference

customer general requirement loads.

b. Tier 1 and Tier 2 Loads: Within each customer class, BPA is

proposing to allocate resource costs separately to Tier 1 and Tier 2

loads, instead of allocating costs to the total customer class load. To

accomplish this, the resources within the FBS resource pool are

separated further into Tier 1 resources and Tier 2 resources. BPA is

proposing to identify a set of FBS resources whose costs then will be

allocated to Tier 1 loads. All other resource costs, including future

FBS replacements or new resources, will be allocated to Tier 2 loads.

For the test period, BPA is proposing to include all FBS resources,

both existing and replacements, in the specified set of FBS resource

costs allocated to Tier 1 loads.

BPA is proposing to allocate the majority of its short-term

purchase power costs associated with meeting operational deficits to

Tier 2 loads. In the months in which short-term operational purchases

are required, these costs are allocated first to Tier 2 loads, new

resources loads, and long term surplus firm power contract loads. Any

remaining short-term purchase power costs then are allocated to Tier 1

loads.

B. Adjustments to Allocated Costs

The remaining steps in the rate design process use the allocated

costs developed in the COSA and modify them to: (1) reflect BPA's rate

design objectives; (2) conform with contractual requirements; (3)

reflect the results of other BPA studies and commitments made in other

public involvement processes under section 7(i) of the Northwest Power

Act; and (4) conform with requirements of applicable legislation. BPA's

rate design objectives include recovery of BPA's revenue requirement,

rate and revenue stability, practicality, fairness, and efficiency.

Major rate design adjustments to the allocated COSA costs include

the following:

1. Excess Revenue Adjustment. In the initial cost allocation, BPA

allocates its entire test period revenue requirement to firm power

loads on the basis of [[Page 8502]] resources available under critical

water conditions. However, rates are set assuming BPA recovers nonfirm

sales revenues equal to the expected value of revenues under 50 years

of streamflows in the historical record. Since no generation costs are

allocated to NF service, forecasted NF revenues are credited against

costs allocated to firm loads. Similarly, revenues from nonfirm

wheeling under the Energy Transmission (ET) rate schedule are credited

to firm transmission loads.

2. Nonfirm Energy Use Adjustment. The Nonfirm Energy Use adjustment

is a new adjustment that accounts for the costs and benefits derived

from the use of nonfirm power to displace planned power purchases. The

adjustment, in effect, results in loads served by balancing purchases

(i.e., purchases necessary to balance loads and resources) ``buying''

the nonfirm energy used to displace some of those purchases, and loads

served by the Federal Base System resources receiving a credit for this

use of the nonfirm energy produced by those resources. The cost of

purchase power is increased to reflect the average revenues received

from other sales of nonfirm energy in the same months when power

purchases are displaced. Loads served by Federal Base System resources

then are credited by the same amount for this use of nonfirm energy.

3. Surplus Firm Power Excess Revenue Adjustment. BPA has sold and

expects to continue to sell surplus power under long term contracts.

Expected revenues from the sale of such power are compared to allocated

costs. BPA expects revenues to exceed costs of this power, resulting in

a credit to other customers.

4. 7(c)(2) Adjustment. The rates applicable to the DSIs are set at

a level that is equitable in relation to BPA preference customers'

industrial rates. The costs allocated to the DSIs are higher than

revenues from the ``equitable'' rate. The difference is a revenue

deficiency called the ``7(c)(2) delta,'' which is allocated to other

customers.

The foregoing list of adjustments identifies some of the major cost

adjustments and is not intended to be all-inclusive. All of the above

adjustments are functionalized and segmented where appropriate. As a

final step in rate design, BPA will develop seasonal and diurnally

differentiated delivered energy charges based on the results of the

MCA. At this final stage in the rate development process, annual energy

costs have been allocated in COSA, and a series of rate design

adjustments have reallocated and adjusted the costs by class of

service. An average annual energy rate for each class of service then

is developed by dividing the adjusted allocated costs by the billing

determinants for the class of service. A set of seasonal and diurnally

differentiated energy rates which recover an equivalent amount of

adjusted costs then is developed.

5. Unbundled Products

For service under the 1981 and 1995 power sales contracts, BPA is

unbundling the PF, NR, IP, and VI rates into Tier 1, Tier 2, load

shaping and load regulation. Load shaping allows BPA to meet customer

load variations from forecast. Load regulation, sometimes called load

following, follows variations in the customers' loads on an

instantaneous basis. BPA also will be adding unbundled charges for

changes from preschedules and for reactive power deliveries. Outside of

the PF, NR, and IP rates, BPA has developed the Firm Power Products and

Services (FPS) rate schedule, which is the primary vehicle for BPA's

marketing of unbundled products described in the Draft Marketing Plan

and Draft Strategic Business Plan. The FPS rate schedule will allow BPA

to sell firm energy, capacity, or power using a variety of sources of

supply, and will specify charges or specifically authorize negotiated

charges for control area services and other resource support services.

The Control Area Services part of the FPS rate schedule also will

specify a charge for the generation control services provided pursuant

to section 13(d) of the 1981 utility power sales contracts. Firm power

products and services to be marketed by BPA under the FPS rate schedule

are intended to be flexible so that BPA can respond to market

conditions. Power products and services also are available for

ancillary services for transmission of non-Federal resources.

6. Other Rate Design Changes

BPA is proposing other rate design changes. These include, among

others, changes to demand charges, the development of a Long-Term Firm

Requirements Service option for some customers, elimination of the

Irrigation Discount, and development of a charge for reactive power.

BPA also is proposing to modify the contract rate in the NF rate

schedule.

a. Demand Charges. Only transmission costs are allocated to demand.

Demand charges are proposed to be billed based on each customer's

coincident peak, rather than on peaks at individual Points of Delivery.

Demand charges are seasonally differentiated into two seasons, with

charges higher in the months of December through February. The proposed

demand billing factors have been designed to be take-or-pay, relieved

to a certain extent by the purchase of the Load Shaping product. The

Demand Ratchet included in previous rates has been eliminated.

b. Long-Term Firm Requirements Service. Long-Term Firm Requirements

Service is a package of services available to purchasers who sign new

(``1995'') power sales contracts and make a 6-year commitment to

purchase from BPA. It includes an adjustment to the customer's power

bill to reflect the value to BPA of a long-term commitment and for

customers whose loads are 25 aMW or less, a composite rate.

c. Low Density Discount. The calculation of the proposed Low

Density Discount is revised from previous rate proposals. The

calculation uses a sliding scale of percentage discounts based on the

utility's number of customers per pole mile and the utility's ratio of

total electric energy requirements to investment. The two discounts

from the two ratios are added to result in the utility's total

discount, which is capped at 7 percent.

d. Irrigation Discount. The irrigation discount has been eliminated

in the 1995 rate proposal.

e. Reactive Power. Instead of charging a power factor penalty for

customers who take excessive quantities of reactive power, BPA proposes

to bill the customer directly for measured quantities of reactive

demand and reactive energy.

f. Unauthorized Increase. The proposed unauthorized increase charge

reflects a penalty rate without seasonal differentiation, and includes

a demand component to reflect transmission system usage. In addition,

there is an unauthorized deviation charge for partial requirements

purchases purchasing under the new (``1995'') power sales contract.

7. 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 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 [[Page 8503]] 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) rate test

implementation methodology.

The rate projections and the actual rate test itself are performed

using BPA's Supply Pricing Model (SPM). The SPM simulates BPA's rate

development process, using load, resource, and cost data consistent

with that used in this rate proposal. The assumptions and rate

development processes such as load/resource balancing, cost allocation,

and rate design also are consistent with this rate proposal. The SPM

calculates two sets of wholesale power rates for BPA's preference

customers: (1) a set of rates for the test period and the ensuing four

years, assuming that section 7(b)(2) is not in effect (program case

rates); and (2) a set for the same period considering the five

assumptions listed in section 7(b)(2) (7(b)(2) case rates). Certain

costs specified in section 7(g) of the Northwest Power Act (7(g) costs)

are subtracted from the program case rates.

The SPM then discounts each year's rates to the test year of the

relevant rate case, averages each set of discounted rates, and compares

the two resulting averages rounded to the nearest tenth of a mill. If

the average of the discounted program case rates, less the 7(g) costs,

is larger than the average discounted 7(b)(2) case rates, the rate test

triggers. If the rate test triggers, the amount of dollars to be

reallocated in the test period (7(b)(2) amount) is calculated by

multiplying the difference between the discounted program case and

7(b)(2) case rates by the general requirements loads of the preference

customers. The 7(b)(2) amount is used as an adjustment to the allocated

costs in the rate case test period. For the preliminary proposal, the

7(b)(2) rate test will not be performed.

V. Tiered Rates Methodology

In this rate period, BPA is proposing to tier its rates for sales

to public bodies, cooperatives, and Federal agencies under the Priority

Firm Power (PF-95) rate schedule and for sales to its Direct Service

Industrial (DSI) customers under the Industrial Firm Power (IP-95) rate

schedule. For utilities participating in the residential exchange, BPA

is also proposing to tier the PF rate applicable to such exchanges.

Under the proposed tiered rate design, firm power purchases will be

divided into two blocks of power. Separate rates will be developed for

each block of power for each customer class. The size of the first

block of power (Tier 1 power) is set so that most forecasted purchases

will be at the Tier 1 rate. BPA is proposing a somewhat higher rate

that would apply to Tier 2 power. The forecasted sales of Tier 2 power

will be based on the forecasted load above the Tier 1 amount. The

proposed Tier 1 and Tier 2 rates will be determined as part of BPA's

Wholesale Power Rates Development Study.

BPA is proposing to establish the amounts of Tier 1 power each

customer will be able to purchase, based in large part on information

submitted by the customers during the course of these rate proceedings.

BPA is proposing a nomination process where customers indicate the

amount of power they will purchase at the Tier 1 rate for each month

during the rate period within boundaries set in this rate proceeding.

Customer input will establish the billing factors for the Tier 1 rate,

by month, for that purchaser. The boundaries on the customers'

nominations also will be established based on information submitted by

the customers. The deadlines for customer submittals will be

established in BPA's initial proposal and after consultation with

parties and customers. BPA encourages all customers to devote the

necessary resources to provide the information needed to establish the

amounts of power they will be able to purchase at a Tier 1 rate. If a

customer is unable to provide the necessary information, BPA is

proposing to establish that customer's Tier 1 power amounts using the

same approach proposed in this preliminary proposal.

1. Utility Customers' Tier 1 Power: BPA proposes the following

process to determine each utility customers share of Tier 1 power. BPA

will establish an aggregate annual amount of Tier 1 power for all

preference customers based on a percentage share of the Pacific

Northwest Loads and Resources Study FY 1996-97 loads forecast. BPA will

base each preference customer's annual share of the total FY 1996-97

load forecast on historical sales during the period FY 1986 through FY

1993. Each customer may choose a 12-month historical period for

purposes of distributing the forecasted FY 1996-97 load between it and

the other customers. This chosen subperiod also will be used to shape

the given customer's annual load into monthly amounts. Since customers

will submit their choice of historical period during the course of this

proceeding, for the preliminary proposal, BPA has selected a historical

period for each customer for the historical 12-month period for which

BPA sales to that customer were the highest. BPA will shape the load

based on sales during the selected historical period. BPA proposes that

each utility's Tier 1 amount will be 90% of their shaped monthly Tier 1

energy amounts in August through March, and 100% of their shaped

monthly Tier 1 energy amounts in April through July.

Because BPA proposes to establish separate rates for Heavy Load

Hours (HLH) and Light Load Hours (LLH), BPA also will establish a

separate Tier 1 amount of power for HLH and LLH. Customers will be able

to choose how to shape their monthly Tier 1 amount of power into the

HLH and LLH. However, for the preliminary proposal, BPA split each

customer's monthly amount of Tier 1 power into HLH and LLH based on

relative percentage of HLH sales and LLH sales during the selected

historical period.

2. DSI's Tier 1 Power: BPA proposes to establish an amount of Tier

1 power for each individual DSI. For the DSI's, however, the aggregate

amount of Tier 1 power for the DSI class will be set at 2,450 aMW, in

each month. Like utilities, each DSI will select a contiguous 12-month

period of sales over the FY1986-93 historical period. An individual

DSI's monthly share of the 2,450 aMW will be based on its percentage of

historical load compared to the total DSI's historical load. For the

preliminary proposal, BPA selected a historical period for each DSI

based on the same criteria used to select each utility's historical

period. Similarly, BPA will split each DSI's monthly amount of Tier 1

power between HLH and LLH. Although BPA is proposing that a DSI may

elect to shape its monthly amounts of Tier 1 power so that its the same

in each hour of the month, for the preliminary proposal BPA calculated

the monthly amount of Tier 1 power in HLH and LLH based on relative

percentage of HLH sales and LLH sales during the selected historical

period.

3. Residential Exchange Customers' Tier 1 power: BPA is proposing

to establish an amount of Tier 1 power for residential exchange

utilities using an approach similar to the approach for establishing

utility customers' Tier 1 power. For exchanging utilities, however, BPA

will set an exchanging utility's amount of Tier 1 power proportional to

the amount of DSI and utility customers' Tier 1 power. The percentage

of DSI and preference customer Tier 1 load relative to their total load

will be applied to the forecasted exchange load for all utilities in

the residential exchange, both active and inactive, to determine the

exchange load amount of Tier 1 power. [[Page 8504]]

As part of this rate proceeding, BPA will propose a Long-term

Tiered Rate Methodology that will guide the implementation of a tiered

rate structure in subsequent rate cases. BPA expects that this

Methodology will resolve some of the basic questions associated with

developing a tiered rate. The Long-term Tiered Rate Methodology will be

published in a separate Federal Register Notice.

VI. Wholesale Power Rate Schedules

The wholesale power rates developed in the cost of service analysis

and rate design adjustment process are incorporated in the Wholesale

Power and Transmission Rate Schedules. The rate schedule document

includes three sections. The first section contains the wholesale power

and transmission rate schedules. Each schedule is comprised of sections

stating to whom the rate schedule is available, rates for the products

offered under the schedule, billing factors, and the cost basis of the

rates in the schedule (resource contribution). Each rate schedule also

lists the adjustments, charges, and special provisions that apply to

that rate schedule.

The second section contains detailed descriptions of the

adjustments, charges, and special provisions that apply to the various

rate schedules. The third section contains the General Rate Schedule

Provisions (GRSPs) for power and transmission rates. The GRSPs include

a lengthy list of definitions, both of products and services and of

rate schedule terms.

The Wholesale Power and Transmission Rate Schedules and the GRSPs

will be published in a separate Federal Register Notice as described in

Section I of this Notice. Following is a description of each wholesale

power rate schedule.

Priority Firm Power Rate, PF-95

The proposed PF-95 rate schedule would replace the PF-93 rate

schedule. Power is available under the PF-95 rate schedule to public

bodies, cooperatives, Federal agencies, and utilities participating in

the residential exchange under section 5(c) of the Northwest Power Act.

Priority Firm power must be used to meet firm loads within the Pacific

Northwest.

The PF rate schedule is available for power purchased both under

the 1981 power sales contracts and under the new contracts BPA expects

to offer in 1995 (1995 contracts). Rates have been developed for sales

under each contract and for the various products available: Tier 1

demand and energy; Standard Tier 2 demand and energy; Enhanced Tier 2

demand and energy; and Load Shaping and Load Regulation. The PF-95 rate

schedule also contains a ``composite'' rate, for these products for

small full requirement customers (25 aMW) purchasing power under the

1995 contracts. Also available is capacity without energy for computed

requirements purchasers under ``1981'' contracts. The PF-95 rate

schedule includes demand charges that are seasonally and diurnally

differentiated. There is no demand charge for Light Load Hours in any

month of the year. The energy charges also are seasonally and diurnally

differentiated.

The energy billing factors under the proposed PF-95 rate schedule

for Computed Requirements customers purchasing under existing

(``1981'') contracts have been changed from those in previous rate

proposals (the Availability Charge). The proposed billing factors are

now based entirely on contractual entitlements.

New Resource Firm Power Rate, NR-95

The proposed NR-95 rate schedule would replace the NR-93 rate

schedule. The NR-95 rate schedule is available to investor-owned

utilities under net requirements contracts for resale to consumers, and

to publicly owned utilities for New Large Single Loads. Products

available under the NR-95 rate schedule include New Resource Firm

Power, Load Shaping, and Load Regulation. Demand and energy charges are

seasonally and diurnally differentiated.

Industrial Firm Power Rate, IP-95

The proposed IP-95 rate would replace the IP-93 rate. The IP-95

rate schedule is available to BPA's direct-service industrial customers

for firm power to be used in their industrial operations. Products

available under the IP-95 rate include Tier 1 demand and energy,

Standard Tier 2 demand and energy, Enhanced Tier 2 demand and energy,

Load Shaping, and Load Regulation. The IP-95 rate schedule includes a

composite rate for DSI purchasers under 1995 or later power sales

contracts who are qualified and choose to purchase under the composite

rate. Demand and energy charges are seasonally and diurnally

differentiated.

Variable Industrial Power Rate

The VI-91 rate schedule is available to DSIs purchasing from BPA

under both the power sales contracts signed prior to 1995 and the 1986

Variable Rate Contract. The VI-91 rate schedule terminates on June 30,

1996, at the termination of the Variable Rate Contracts, at which time

sales to purchasers under the VI rate will be made at the IP-95 rate.

The VI-91 rate schedule is unchanged from prior years other than to

update the rates and rate parameters based on the rate adjustment

criteria established in 1991. Service under the VI rate is not tiered

(i.e., there is not Tier 1 and Tier 2 service under this rate). For the

preliminary rate proposal, BPA assumed no sales under the VI rate

schedule during the rate period.

Firm Power and Services Rate, FPS-95

The proposed FPS-95 rate schedule is available for purchase of firm

power products inside and outside the United States, and control area

services, until its termination date, September 30, 2000. The FPS-95

rate schedule would supersede both the SP-93 (Surplus Firm Power Rate)

and the CE-93 (Emergency Capacity) rate schedules, and also includes

products formerly available under other rate schedules, such as

construction, test and startup, and station service. Sales under FPS-95

may be made at fixed rates, as specified in the rate schedule, or at

flexible rates as established by BPA or mutually agreed to by BPA and

the purchaser. Fixed demand charges are diurnally but not seasonally

differentiated, and fixed energy charges do not change diurnally or

seasonally.

Nonfirm Energy Rate, NF-95

The proposed NF-95 rate schedule replaces the NF-93 rate. The NF-95

rate schedule is available for purchases of nonfirm energy inside and

outside the Pacific Northwest for resale to consumers, direct

consumption, and resale under Western Systems Power Pool agreements.

The form of the NF-95 rate has not changed from previous years, with

the schedule including a Standard rate, a Market Expansion rate, an

Incremental rate, a Western Systems Power Pool rate, an End-User rate,

and a Contract rate. However, the cost basis for the Contract rate has

changed to reflect the average cost of nonfirm energy.

The NF Rate Cap, described in the Adjustments, Charges, and Special

Rate Provisions section of the rate schedule document, continues to

apply to all sales under NF-95 rate schedule. The NF Rate Cap defines

the maximum nonfirm energy price for general application. The level of

the NF Rate Cap is based on a formula tied to BPA's system cost and

California fuel costs.

Reserve Power Rate, RP-95

The RP-95 rate schedule replaces the RP-93 rate schedule. The RP

rate is available in cases where a purchaser's [[Page 8505]] power

sales contract states that the rate for Reserve Power shall be applied;

when BPA determines no other rate schedule is applicable; or to serve a

purchaser's firm power load when BPA does not have a power sales

contract in force with such a purchaser, and BPA determines that this

rate should be applied. The demand and energy charges are seasonally

and diurnally differentiated, with no demand charge during light load

hours during any month of the year.

Power Shortage Rate, PS-95

The PS-95 rate schedule is available for sales under the Share-the-

Shortage agreement or a similar substitute agreement. BPA is not

obligated to make Shortage Power available or broker power under the

PF-95 rate schedule unless specified by contract.

VII. Charges Under the Amended and Integrated Pacific Northwest

Coordination Agreement

The Pacific Northwest Coordination Agreement (PNCA) is an agreement

for planned operations among the utilities and other entities that

operate the major electric generating facilities and systems in the

Pacific Northwest. The parties jointly and cooperatively plan and

coordinate their combined generation facilities so as to produce the

optimum firm load carrying capability (FLCC) of the coordinated system.

FLCC is the firm load that could be carried under coordinated operation

with critical streamflow conditions and with the use of all reservoir

storage.

In order to coordinate operations, and so that each party can meet

its individual FLCC, the PNCA provides for exchanges of energy and

capacity among the parties. The agreement sets up charges for each form

of exchange. The parties are negotiating a successor agreement to the

PNCA, and have agreed on charges to apply under the new agreement.

The PNCA Rate Schedules will be published in a separate Federal

Register Notice as described in Section I of this notice.

Issued in Portland, Oregon, on February 7, 1995.

J.H. Curtis,

Acting Administrator.

[FR Doc. 95-3534 Filed 2-13-95; 8:45 am]

BILLING CODE 6450-01-P