[Federal Register Volume 60, Number 30 (Tuesday, February 14, 1995)]
[Notices]
[Pages 8496-8505]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 95-3534]




[[Page 8495]]

_______________________________________________________________________

Part V





Department of Energy





_______________________________________________________________________



Bonneville Power Administration



_______________________________________________________________________



Pacific Northwest Electric Power Planning and Conservation Act; 
Proposed Transmission and Wholesale Power Rate Adjustment, Public 
Hearing, and Opportunities for Public Review and Comment; Notices

  Federal Register / Vol. 60, No. 30 / Tuesday, February 14, 1995 / 
Notices   
[[Page 8496]] 

DEPARTMENT OF ENERGY

Bonneville Power Administration


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

AGENCY: Bonneville Power Administration (BPA), DOE.

ACTION: Notice and Opportunities for 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 BPAs 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