[Federal Register Volume 60, Number 83 (Monday, May 1, 1995)]
[Notices]
[Pages 21132-21169]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 95-10065]



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DEPARTMENT OF ENERGY


Bonneville Power Administration 1995 Wholesale Power and 
Transmission Rates, Variable Industrial Power Rate Extension (VI-95), 
and Pacific Northwest Coordination Agreement (PNCA) Rates

AGENCY: Bonneville Power Administration (BPA), DOE.

ACTION: Availability of proposed 1995 wholesale power and transmission 
rates, variable industrial rate extension (VI-95), Pacific Northwest 
Coordination Agreement (PNCA) Rates, and order establishing schedule.

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SUMMARY: BPA File No: WP-95/TR-95, WP-96, TR-96, TC-96. On December 28, 
1994, Bonneville Power Administration (BPA) published a Notice of 
Intent to Revise Transmission Rates, 59 FR 66946 (1994), and Notice of 
Intent to Revise Wholesale Power Rates, 59 FR 66947 (1994). 
Subsequently, BPA published Federal Register Notices of Proposed 
Wholesale Power Rate Adjustment, 60 FR 8496 (1995), Proposed 
Transmission Rate Adjustment, 60 FR 8505 (1995), and Hearing and 
Opportunity for Public Comment Regarding Proposed Comparable 
Transmission Terms and Conditions, 60 FR 8511 (1995). On March 3, 1995, 
BPA published a Notice of Additional Prehearing/Settlement Conference 
for March 15, 1995, 60 FR 11962 (1995). At that prehearing conference, 
the Hearing Officers were expected to act on several procedural matters 
and to establish a procedural schedule. The March 3, 1995, Notice also 
included schedules for a New Rates and Terms and Conditions Proceeding 
and for an Extension of Current Rates Proceeding. Notice also was given 
that some issues might be settled by the litigants, causing the 
proposed schedule to change.
    At the Prehearing/Settlement Conference on March 15, 1995, the 
litigants reported to Hearing Officers about settlement discussions 
that had been taking place between BPA and its customers. The parties 
requested, and the Hearing Officers allowed, additional time to 
complete the settlement process. The Hearing Officers set an additional 
Scheduling Conference for March 22, 1995, at which time parties to the 
rate case would be asked to report on the status of the settlement and 
the Hearing Officers would rule on procedural matters. On March 17, 
1995, most parties to the rate case signed a Settlement Agreement 
agreeing that BPA would propose to surcharge BPA's current rates for a 
1-year period, October 1, 1995, through September 30, 1996, and to 
extend the Variable Industrial Power (VI) rate which was scheduled to 
expire on June 30, 1996, through September 30, 1996. The parties also 
agreed to establish a separate subsequent process to establish a 2-year 
rate proposal, a 5-year rate proposal, and a proposal for transmission 
services terms and conditions.
    By this notice, BPA announces its proposed 1995 rates to be 
effective for 1 year beginning on October 1, 1995, and extending 
through September 1996, and its proposed rates for transactions under 
the Pacific Northwest Coordination Agreement (PNCA). BPA will publish a 
separate notice in the Federal Register to announce its proposed new 
power and transmission rates to be effective on October 1, 1996, 
including new 2- and 5-year rates, and its new transmission services 
terms and conditions on or around the July 10, 1995, Filing Date 
established for Docket Numbers WP-96, TR-96, and TC-96.
    In separate orders issued March 22, 1995, the Hearing Officers: (1) 
adopted a service list for BPA's 1995 Wholesale Power and Transmission 
Rate Adjustment Proceeding, 1996 Wholesale Power and Transmission Rate 
Adjustment Proceeding and 1996 Transmission Terms and Conditions 
Proceedings; and (2) adopted other procedural rules governing these 
proceedings. Copies of all orders, including the Order Establishing 
Schedules, may be obtained by contacting: Francis (Jamie) Troy, Hearing 
Clerk--LQ, Bonneville Power Administration, 905 NE. 11th Ave., PO Box 
12999, Portland, Oregon 97212.
    Schedule for WP-95/TR-95:

May 1, 1995--BPA Files Direct Case
May 30, 1995--Parties File Direct Case
June 9, 1995--Close of Participant Comments
June 19, 1995--Litigants File Rebuttal Testimony
June 30, 1995--Cross-Examination
July 10, 1995--Initial Briefs Filed
July 31, 1995--Final Record of Decision

    Schedule for WP-96/TR-96 and TC-96:

July 10, 1995--BPA Files Direct Case/Prehearing Conference
September 8, 1995--Parties File Direct Case
October 2, 1995--Close of Participant Comments
October 25, 1995--Litigants File Rebuttal Testimony/BPA Supplemental 
Testimony
December 4, 1995--Litigants File Rebuttal to Supplemental Testimony
January 3-February 3, 1996--Cross-Examination
February 21, 1996--Initial Briefs Filed
February 28, 1996--Oral Argument
March 25, 1996--BPA Draft Record of Decision/Hearing Officers 
Recommended Decision
April 15, 1996--Briefs on Exceptions
April 30, 1996--Final Record of Decision

    BPA also will be conducting public field hearings. A notice of the 
dates, times, and locations of the field hearings will be made later 
through mailings and public advertising.

ADDRESSES: Written comments by participants must be received by June 9, 
1995, for WP-95/TR-95 and by October 2, 1995, for WP-96/TR-96/TC-96 to 
be considered in the Record of Decision (ROD). Written comments should 
be submitted to the Manager, Corporate Communications--CK; Bonneville 
Power Administration; PO Box 12999; Portland, Oregon 97212.

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

Mr. Steve Hickok; Group Vice President, Sales and Customer Service; PO 
Box 3621; Portland, OR 97232 (503-230-5356)
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 
[[Page 21133]] 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. Mr. Dennis Metcalf, BPA Transmission Team 
Lead, is the official responsible for the development of BPA's 
transmission terms and conditions.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Introduction
II. Background
III. Major Studies
IV. Wholesale Power Rate Schedules and General Rate Schedule 
Provisions
    A. Introduction
    B. Summary of Rate Schedules
    C. Wholesale Power Rate Schedules
    D. General Rate Schedule Provisions (GRSPs)
V. Transmission Rate Schedules and General Transmission Rate 
Schedule Provisions (GTRSPs)
    A. Summary of Rate Schedules
    B. Transmission Rate Schedules
    C. General Transmission Rate Schedule Provisions (GTRSPs)
VI. Charges Under the Amended and Integrated Pacific Northwest 
Coordination Agreement

I. Introduction

    Prior to the March 15, 1995, prehearing conference, BPA determined 
that its initial proposal should include new 2-year and 5-year rates. 
On February 14, 1995, BPA published a preliminary rate proposal in the 
Federal Register, 60 FR 8496. In that proposal, BPA noted that 
competitive forces are causing a fundamental and significant change in 
the Pacific Northwest wholesale power market. In light of these 
competitive forces, BPA determined that its initial proposal should 
include a 5-year rate as well as a 2-year rate. BPA anticipated that 
the work necessary to develop such a proposal would take until July of 
1995. As part of the settlement discussions, the parties expressed a 
need for additional time to respond to BPA's new rate designs. BPA 
believes that without an adjustment to its wholesale and transmission 
rates for the period October 1, 1995, through September 30, 1996, BPA's 
ability to satisfy its statutory obligations could be impaired. The 
rate case schedule adopted by the Hearing Officers on March 22, 1995, 
meets both BPA's and the parties' needs. The schedule affords the 
parties a hearing process that encompasses a period of eight months for 
establishment of BPA new rate designs including new 2- and 5-year 
rates. The effective date for the establishment of new 2- and 5-year 
rates is October 1, 1996.
    In order to have sufficient time to conduct a full rate proceeding 
for new 2- and 5-year rate proposals, BPA and most parties to the 1995 
rate proceeding agreed that BPA would propose to extend BPA's current 
adjustable rates with a 4 percent surcharge for a 1-year period, 
October 1, 1995, through September 30, 1996. The extension of rates 
requires a separate expedited proceeding and procedural schedule.
    After the March 22, 1995, Scheduling Conference, the Hearing 
Officers issued an Order (the March 22 order) that divided the 
proceedings previously designated as WP-95, TR-95, and TC-95 into three 
separate dockets as follows:
    (1) The 1995 Wholesale Power and Transmission Rates Proceeding is 
designated WP-95/TR-95, and will be a 90-day expedited rate proceeding 
conducted pursuant to section 1010.10 of the Procedures Governing 
Bonneville Power Administration Rate Hearings, 51 FR 7611 (1986) 
(hereinafter Procedures). This proceeding will extend current rates 
with a surcharge and establish the 3rd AC, annual cost rate, and the 
Pacific Northwest Coordination Agreement (PNCA) rate.
    (2) The March 22 Order also established a subsequent 8 month 
procedural schedule beginning July 10, 1995, to establish BPA's power 
and transmission rates for the period beginning October 1, 1996, and 
new transmission services terms and conditions. The 1996 Wholesale 
Power Proceeding is designated WP-96, and Transmission Rates Proceeding 
is designated TR-96 and both will be conducted pursuant to section 
1010.9 of the Procedures.
    (3) The 1996 Transmission Services Terms and Conditions Proceeding 
is designated TC-96 and will be conducted pursuant to section 1010.9 of 
the Procedures concurrently with WP-96/TR-96.
    In the March 22 Order, the Hearing Officers ruled that after March 
22, 1995, separate official records will be maintained and separate 
decisions will be issued for each of the three proceedings designated 
above. In addition, the Hearing Officers ruled that intervenors who 
intervened in the dockets designated WP-95/TR-95 and TC-95 on or before 
March 15, 1995, were admitted as parties for all proceedings noted 
above.
    Finally, the Hearing Officers established the final rate case 
schedules for Docket Numbers WP-95/TR-95, WP-96/TR-96, and TC-96. The 
schedule established by the Hearing Officers for Docket Number WP-95/
TR-95 provides an opportunity for interested persons to review BPA 
proposed rates, to participate in the rate hearing, and to submit oral 
and written comments. All comments and documents intended to become 
part of the Official Record in this process should contain the file 
number designation WP-95/TR-95. Consideration of comments may result in 
a final rate proposal differing from the rates proposed in this Notice.

II. Background

    The Pacific Northwest Electric Power Planning and Conservation Act 
(Northwest Power Act) provides that BPA must establish and periodically 
review its rates so that they are adequate to recover, in accordance 
with sound business principles, the costs associated with the 
acquisition, conservation, and transmission of electric power, and to 
recover the Federal investment in the Federal Columbia River Power 
System (FCRPS) and other costs incurred by BPA.
    On March 9, 1995, BPA published in the Federal Register a notice of 
availability of BPA's preliminary proposed Wholesale Power and 
Transmission Rate schedules, 60 FR 12915. Since that time, BPA has 
continued to study the adequacy of its preliminary rate proposal, 
including its proposal to tier rates for requirements service. On March 
17, 1995, BPA and most parties to the 1995 rate proceedings agreed to a 
settlement whereby BPA would propose that current rates be extended for 
1 year and surcharged 4 percent to meet BPA revenue requirements. The 
Settlement Agreement was an attempt to balance a number of interests, 
including concerns expressed by customer representatives to BPA's Power 
Sale Contract renegotiations. These representatives suggested that 
BPA's new Power Sales Contracts and new rate structures should be 
coordinated to allow customers to carefully consider the new rates and 
contracts package in detail before making any long-term commitments.
    BPA's initial proposal for the 1995 rate case proposes to surcharge 
by 4 percent each component of its current adjustable rates, including 
a Variable Industrial Power (VI) rate extended through September 30, 
1996, for 1 year, from October 1, 1995, through September 30, 1996. 
[[Page 21134]] 

III. Major Studies

    The studies that have been prepared to support the 1995 initial 
proposal will be served on all parties of record and available for 
examination on May 1, 1995, at BPA's Public Information Center, BPA 
Headquarters Building, 1st Floor; 905 NE. 11th, Portland, OR. The 
studies and documents are:

A. Loads and Resources Study and Documentation
B. Revenue Requirement Study and Documentation
C. Revenue Forecast Study and Documentation
D. Section 7(b)(2) Rate Test Study and Documentation

    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 accompanying documentation (these can be quite 
lengthy); otherwise, the study alone will be provided. (For example, 
ask for the ``Revenue Requirement Study and Documentation.'')

A. 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 (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 
conservation programs and utility purchases from alternative (non-BPA) 
power suppliers 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 DSI 
purchases from alternative (non-BPA) power suppliers. Forecasted non-
aluminum DSI purchases from BPA are prepared by analyzing historical 
and technical plant information, forecasted market conditions, and 
potential purchases from alternative power suppliers.
    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 ratemaking load/resource balance represents BPA's projected 
service to firm loads during the test years under 1930 water 
conditions. The ratemaking load/resource balance is used in the 
calculation of the supply of surplus firm power in the region and on 
the Federal system during the test period. 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 and ``spill.'' For this 
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 expected 
nonfirm energy availability for the region.

B. 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 of 
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 a 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 at proposed rates to recover 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 initial rate proposal is 
based on cost and revenue estimates for FY 1996. The cost estimates 
include an undistributed reduction of $80 million. This reflects BPA's 
decision to reduce revenue requirements by this amount to enable it to 
set rates at a level which recover its costs but also meet current 
market conditions, although specific program and/or organizational 
spending cuts have not been finalized. This study also includes planned 
net revenues to mitigate financial risk, to ensure that cash flows are 
adequate to demonstrate timely repayment of the Federal investment 
including irrigation assistance, and finance a portion of BPA's capital 
investments. 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 program costs.
    Also part of the Revenue Requirement Study is a risk analysis that 
evaluates the impact that various economic and generation resource 
capability conditions could have on BPA's ability to make annual U.S. 
Treasury payments during the rate test period. It measures the 
financial risks surrounding the revenue and expense forecasts used to 
set rates. Results of the risk analysis are used to determine the 
amount of planned net revenue required for risk mitigation. 
[[Page 21135]] 

C. Revenue Forecast Study

    The revenue forecast determines BPA's expected level of sales and 
revenue for the rate period, fiscal year 1996. Revenues are forecasted 
primarily by applying rates to a load forecast. In addition, because 
the load forecast assumes critical water, and streamflows usually are 
greater-than-critical, the revenue forecast reflects the effect of 
greater-than-critical streamflows (the product of which is secondary 
energy) on BPA's revenues. Secondary energy affects the revenue 
forecast by increasing or decreasing estimated revenues from the 
generating public utilities, direct-service industries, open market 
sales, and incidental wheeling. The revenue forecast is based on the 
average of 50 historical water years.
    BPA prepares two types of revenue forecasts: (1) Revenues 
forecasted under current rates; and (2) revenues forecasted under 
proposed rates. The rates in effect since October 1993 are used in the 
calculation of forecasted revenues at current rates for the rate test 
period, fiscal year 1996. BPA also develops price forecasts for certain 
prices that are not set by the rate schedules to determine revenues 
under the Variable Industrial Power (VI) rate, for contractual sales of 
surplus firm power, for sales at the Nonfirm Energy rate, and for rates 
applicable to the WNP-1 and WNP-3 Exchange Agreements.
    Included in the Revenue Forecast Study are the proposed wholesale 
power and transmission rate schedules, which are summarized below.

D. 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 4 years, are no higher than the costs of power 
to those customers would be for the same time period if specified 
assumptions are made. The effect of the rate test is to protect the 
7(b)(2) customers' wholesale firm power rates from certain costs 
resulting from provisions of the Northwest Power Act. The rate test can 
result in a reallocation of costs from the 7(b)(2) customers to other 
rate classes. The section 7(b)(2) Rate Test Study describes the 
application and results of the section 7(b)(2) 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 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 4 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, if any, is used as an adjustment to the 
allocated costs in the rate case test period.

IV. Wholesale Power Rate Schedules and General Rate Schedule 
Provisions

Table of Contents

Introduction

Summary of Rate Schedules

Wholesale Power Rate Schedules

PF-95. Priority Firm Power Rate
IP-95. Industrial Firm Power Rate
VI-95. Variable Industrial Power Rate
SI-95. Special Industrial Power Rate
CE-95. Emergency Capacity Rate
NR-95. New Resource Firm Power Rate
NF-95. Nonfirm Energy Rate
SS-95. Share-the-Savings Energy Rate
PS-95. Power Shortage Rate
RP-95. Reserve Power Rate

General Rate Schedule Provisions (GRSPs)

Section I. Adoption of Revised Rate Schedules and General Rate 
Schedule Provisions
Section II. Types of BPA Service
Section III. Billing Factors and Billing Adjustments
Section IV. Other Definitions
Section V. Application of Rates Under Special Circumstances
Section VI. Billing Information
Section VII. Variable Industrial Rate Parameters and Adjustments

A. Introduction

    The proposed wholesale power rate schedules are published as part 
of the Revenue Forecast Study. BPA agreed in the Settlement Agreement 
that its 1995 initial rate proposal would propose to apply a 4 percent 
surcharge to each component of its current adjustable rates, including 
the Variable Industrial Power (VI) rate which BPA would propose to 
extend through September 30, 1995. The current VI-91 rate expires June 
30, 1996. BPA also agreed to propose that the surcharged rates would be 
effective for the period October 1, 1995, through September 30, 1996.
    Consistent with the Settlement Agreement, BPA proposes to retain 
its current rate design, including most of the rate adjustments 
contained in the 1993 Wholesale Power Rate Schedules. BPA proposes to 
adjust each rate component contained in the Priority Firm Power (PF) 
rate, Industrial Firm Power (IP) rate, Variable Industrial Power (VI) 
rate, and New Resources (NR) rate such that the overall effective rate 
increase for sales under these rate schedules is 4 percent. BPA 
proposes to increase the demand and energy charges in these rates by 4 
percent and also to increase by 4 percent the Irrigation Discount and 
First Quartile Discount. BPA proposes to increase the Energy Return 
Surcharge based on the changes in the PF demand charge.
    BPA is proposing to retain the current percentages for the Low 
Density Discount and Availability Charge without further adjustments. 
Any change to these rate adjustments could result in an overall rate 
increase to customers different from 4 percent. In addition, BPA is 
proposing to maintain the Unauthorized Increase Charge at its current 
level. The Unauthorized Increase Charge is designed to deter customers 
from taking more power than they are entitled to take. The level of 
current Unauthorized Increase Charge achieves that purpose and as such 
a further increase is unnecessary.
    BPA has some long-term contract rates that are tied to changes in 
BPA's PF rate. BPA is proposing to increase these rates by 4 percent. 
In addition, BPA has rates that depend on changes in BPA's Average 
System Cost (BASC). BPA also is proposing to increase BASC by 4 percent 
and consequently any rates that are based on changes in BASC also will 
be increased by 4 percent.
    BPA also proposes to adjust the rate components contained in its 
Emergency Capacity (CE) rate and Nonfirm Energy rate schedules. Since 
the price BPA can obtain from these rates is based on market 
conditions, these rate schedules do not contain fixed rates but rather 
contain caps or ceilings. BPA proposes to increase the CE rate cap and 
the Intertie Charge by 4 percent. In the NF rate, BPA is proposing to 
increase the [[Page 21136]] average cost of nonfirm energy, which 
triggers the Intertie adder charge, and retain the upper limit on its 
Standard nonfirm energy rate by 4 percent. Given current market 
conditions, increasing the cap on the NF Standard rate is not expected 
to result in increased revenues during the rate period. BPA also is 
proposing to increase the Intertie Charge and the NF Contract rate by 4 
percent.
    BPA is proposing to extend the Reserve Power (RP) rate, the Share-
the-Savings (SS) rate and the Power Shortage (PS) rate unchanged for 
the 1 year period. These rates normally are not adjusted to reflect 
changes in BPA's costs. The RP rate is based on BPA's estimate of its 
long-term marginal cost. This rate has not been adjusted since 1987. 
The SS rate is an experimental nonfirm energy rate that allows for a 
mutually agreed-to formula rate. The PS rate is a contractually agreed-
to rate and is available for sales under the Shortage Agreement. The 
parties to the Shortage Agreement recently agreed to extend that 
agreement for another year.
    Unlike its other rates, BPA's current Surplus Power (SP-93) rate 
does not expire on September 30, 1995. FERC has approved the SP-93 rate 
through September 30, 1998. 67 FERC  61351 (June 20, 1994). Therefore, 
since the SP rate continues to be in effect during the 1-year rate 
period, BPA proposes to retain its current SP-93 rate and not refile a 
new SP rate for the 1-year rate period agreed to in the Settlement 
Agreement. The current SP-93 rate contains a contract rate and a 
flexible rate. BPA does not expect to make any sales at the contract 
rate during the rate period. The flexible rate is capped at BPA's 
highest cost resource, which is significantly above the expected market 
price during the rate period. As such increasing the SP flexible rate 
by 4 percent would not advance the settlement's cost recovery 
objectives.

B. Summary of Rate Schedules

    A summary of the proposed 1995 Wholesale Power Rate Schedules is 
provided below. Each of the rate schedules includes sections specifying 
the customer class and the service available under the rate schedule, 
the rates for the sales offered under the schedule, the billing 
factors, other special provisions for rate adjustments, such discounts 
or penalties that apply to that rate schedule, and the cost basis of 
the rates in the schedule (resource contribution). Because the 1995 
rates will be effective for a 1-year period, BPA is not proposing an 
Interim Rate Adjustment for these rates.
    1. Priority Firm Power rate: The proposed Priority Firm Power (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 consists of diurnally differentiated demand charges and 
seasonally differentiated energy charges. Other rate adjustments 
include an Irrigation Discount, a Low Density Discount, an Energy 
Return Surcharge, Unauthorized Increase Charge, Conservation Surcharge, 
Outage Credit and Power Factor Adjustment.
    2. New Resource Firm Power rate: The proposed New Resource Firm 
Power (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. The NR rate consists of diurnally 
differentiated demand charges and seasonally differentiated energy 
charges. Other rate adjustments include an Irrigation Discount, a Low 
Density Discount, an Energy Return Surcharge, Unauthorized Increase 
Charge, Conservation Surcharge, Outage Credit and Power Factor 
Adjustment.
    3. Industrial Firm Power rate: The proposed Industrial Firm Power 
Rate (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. The IP rate consists 
of diurnally differentiated demand charges and seasonally 
differentiated energy charges. Other rate adjustments include a First 
Quartile Discount, Curtailment Charge, Unauthorized Increase Charge, 
Outage Credit and Power Factor Adjustment.
    4. Variable Industrial Power rate: The Variable Industrial Power 
(VI-95) rate schedule is available to DSIs purchasing from BPA under 
the 1986 Variable Rate Contract. The proposed VI-95 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 
and the 1995 rate case. The proposed base rate components of the VI-95 
rate include the 4 percent surcharge, as do the First Quartile Discount 
and the Lower and Upper Rate Limits. The Lower and Upper Pivot Aluminum 
Prices are those that were effective July 1, 1995, pursuant to the VI-
91 rate. They will be adjusted again on July 1, 1996. The VI rate is 
proposed to be extended three months past its expiration date, June 30, 
1996, so that its term will be consistent with the other rates proposed 
for fiscal year 1996. The term of the proposed VI-95 rate thus would be 
October 1, 1995, through September 30, 1996.
    5. Special Industrial Power rate: The proposed Special Industrial 
Power (SI-95) rate would replace the SI-93 rate. The SI rate is 
available to any DSI purchaser which uses a raw mineral indigenous to 
the region as its primary resource and which qualifies for the special 
rate under the procedures established in section 7(d)(2) of the 
Northwest Power Act. The SI rate consists of diurnally differentiated 
demand charges and seasonally differentiated energy charges. Other rate 
adjustments include a Curtailment Charge, Unauthorized Increase Charge, 
Outage Credit, and Power Factor Adjustment.
    6. Nonfirm Energy rate: The proposed Nonfirm Energy (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 NF-95 rate schedule includes 
four rate components: A flexible Standard rate, a flexible Market 
Expansion rate, a flexible Incremental rate, and a fixed Contract rate. 
Other adjustments include a Guaranteed Surcharge and an Intertie 
Charge. The NF Rate Cap continues to apply to all sales under the 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 Average System Cost and California fuel costs.
    7. The Reserve Power rate: The Reserve Power (RP-95) rate schedule 
replaces the RP-93 rate schedule. The RP rate is available in cases 
where a purchaser's 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 RP 
rate consists of diurnally differentiated demand charges and a flat 
energy charge. Other rate adjustments include a Power Factor 
Adjustment.
    8. The Power Shortage rate: The Power Shortage (PS-95) rate 
schedule is available for sales under the Share-the-Shortage agreement 
or when BPA arranges for purchased energy at the request of a Northwest 
customer. BPA is not obligated to make Shortage Power 
[[Page 21137]] available or to broker power under the PS-95 rate 
schedule unless specified by contract. The PS rate contains two rate 
components: a flexible Power Rate not to exceed 100 mills/kWh and a 
flexible Brokering Rate not to exceed 1 mill/kWh. Other rate 
adjustments include a Power Factor Adjustment.

C. Wholesale Power Rate Schedules

Schedule PF-95

Priority Firm Power Rate

Section I. Availability

    This schedule is available for the contract purchase of firm power 
or capacity to be used within the Pacific Northwest. Priority Firm 
Power may be purchased by public bodies, cooperatives, and Federal 
agencies for resale to ultimate consumers for direct consumption, 
construction, test and startup, and station service.
    Utilities participating in the exchange under section 5(c) of the 
Northwest Power Act may purchase Priority Firm Power pursuant to their 
Residential Purchase and Sale Agreements.
    In addition, BPA may make power available to those parties 
participating in exchange agreements which use this rate schedule as 
the basis for determining the amount or value of power to be exchanged.
    This schedule supersedes Schedule PF-93, which went into effect on 
October 1, 1993. Sales under this schedule are made subject to BPA's 
General Rate Schedule Provisions (GRSPs).

Section II. Rate

    This rate schedule includes the Preference rate and the Exchange 
rate. The Preference rate is available for the general requirements of 
public body, cooperative and Federal agency customers. The Exchange 
rate is available for all purchases of residential and small farm 
exchange power pursuant to the Residential Purchase and Sale 
Agreements.

A. Preference Rate

1. Demand Charge
    a. $4.307 per kilowatt of billing demand occurring during all Peak 
Period hours during a billing month.
    b. No demand charge during Offpeak Period hours during a billing 
month.
2. Energy Charge
    a. 23.06 mills per kilowatt-hour of billing energy for the billing 
months September through March.
    b. 16.94 mills per kilowatt-hour of billing energy for the billing 
months April through August.

B. Exchange Rate

1. Demand Charge
    a. $4.307 per kilowatt of billing demand occurring during all Peak 
Period hours during a billing month.
    b. No demand charge during Offpeak Period hours during a billing 
month.
2. Energy Charge
    a. 23.06 mills per kilowatt-hour of billing energy for the billing 
months September through March.
    b. 16.94 mills per kilowatt-hour of billing energy for the billing 
months April through August.

Section III. Billing Factors

    In this section, billing factors are listed for each of the 
following types of purchasers: computed requirements purchasers 
(section III.A), purchasers of residential exchange power pursuant to 
the Residential Purchase and Sale Agreements (section III.B), and 
metered requirements purchasers and those Priority Firm Power 
purchasers not covered by sections III.A and III.B (section III.C).

A. Computed Requirements Purchasers

    Purchasers designated by BPA as computed requirements purchasers 
pursuant to power sales contracts shall be billed in accordance with 
the provisions of this subsection.
1. Billing Demand
    The billing demand for actual, planned, and contracted computed 
requirements purchasers shall be the higher of the billing factors 
``a'' and ``b,'' below:
    a. The lower of:
    (1) The larger of the Computed Peak Requirement or the Computed 
Average Energy Requirement; or
    (2) The Measured Demand, before adjustment for power factor.
    b. The lower of:
    (1) The Computed Peak Requirement; or
    (2) 60 percent of the highest Computed Peak Requirement during the 
previous 11 billing months (Ratchet Demand).
2. Billing Energy
    The billing energy for actual, planned, and contracted computed 
requirements purchasers shall be:
    a. For the months September through March, the sum of:
    (1) 76 percent of the Measured Energy (excluding unauthorized 
increase); and
    (2) 24 percent of the Computed Energy Maximum.
    b. For the months April through August, the sum of:
    (1) 63 percent of the Measured Energy (excluding unauthorized 
increase); and
    (2) 37 percent of the Computed Energy Maximum.

B. Purchasers of Residential Exchange Power

    Purchasers buying Priority Firm Power under the terms of a 
Residential Purchase and Sale Agreement shall be billed as follows:
1. Billing Demand
    The billing demand shall be the demand calculated by applying the 
load factor, determined as specified in the Residential Purchase and 
Sale Agreement, to the billing energy for each billing period.
2. Billing Energy
    The billing energy shall be the energy associated with the 
utility's residential load for each billing period. Residential load 
shall be computed in accordance with the provisions of the purchaser's 
Residential Purchase and Sale Agreement.

C. Metered Requirements Purchasers, Other Purchasers Not Covered by 
Sections III.A and III.B, Above

    Purchasers designated as metered requirements customers and 
purchasers taking or exchanging power under this rate schedule who are 
not otherwise covered by sections III.A and III.B shall be billed as 
follows:
1. Billing Demand
    The billing demand shall be the Measured Demand as adjusted for 
power factor, unless otherwise specified in the power sales contract.
2. Billing Energy
    The billing energy shall be the Measured Energy, unless otherwise 
specified in the power sales contract.

Section IV. Adjustments And Special Provisions

A. Power Factor Adjustment

    The adjustment for power factor, when specified in this rate 
schedule or in the power sales contract, shall be made in accordance 
with the provisions of both this section and section III.C.1 of the 
GRSPs. The adjustment shall be made if the average leading power factor 
or average lagging power factor at which energy is supplied during the 
billing month is less than 95 percent.
    To make the power factor adjustment, BPA shall increase the billing 
demand by 1 percentage point for each percentage point or major 
fraction thereof (0.5 or greater) by which the average leading power 
factor or average [[Page 21138]] lagging power factor is below 95 
percent. BPA may elect to waive the adjustment for power factor in 
whole or in part.

B. Low Density Discount (LDD)

    BPA shall apply a discount to the charges for all Priority Firm 
Power sold to purchasers who are eligible for an LDD. Eligibility for 
the LDD and the amount of the discount (3, 5, or 7 percent) shall be 
determined pursuant to section III.C.3 of the GRSPs.

C. Irrigation Discount

    BPA shall apply an irrigation discount, equal to 4.90 mills per 
kilowatt-hour, to the charges for qualifying energy purchased under 
this rate schedule. The irrigation discount shall be applied after 
calculation of the LDD. The discount shall apply only to energy 
purchased during the billing months of April through October. 
Eligibility for the irrigation discount and reporting requirements 
shall be determined pursuant to section III.C.4 of the GRSPs.

D. Conservation Surcharge

    The Northwest Power Planning Council has recommended that a 
conservation surcharge be imposed on those customers subject to such 
surcharge as determined by the Administrator in accordance with BPA's 
Policy to Implement the Council-Recommended Conservation Surcharge. The 
Conservation Surcharge shall be applied pursuant to section III.C.6 of 
the GRSPs and subsequent to any other rate adjustments.

E. Outage Credit

    Pursuant to section 7 of the General Contract Provisions, BPA shall 
provide an outage credit to any purchaser for those hours for which BPA 
is unable to deliver the full billing demand during that billing month 
due to an outage on the facilities used by BPA to deliver Priority Firm 
Power. Such credit shall not be provided if BPA is able to serve the 
purchaser's load through the use of alternative facilities or if the 
outage is for less than 30 minutes. The amount of the credit shall be 
calculated according to the provisions of section III.C.2 of the GRSPs.

F. Unauthorized Increase

    BPA shall apply the charge for Unauthorized Increase to any 
purchaser of Priority Firm Power taking demand and energy in excess of 
its contractual entitlement.
1. Rate for Unauthorized Increase
    a. 100.00 mills per kilowatt-hour during the billing months August 
through March.
    b. 57.40 mills per kilowatt-hour during the billing months April 
through July.
2. Calculation of the Amount of Unauthorized Increase
    Each 60-minute clock-hour integrated or scheduled demand shall be 
considered separately in determining the amount that may be considered 
an unauthorized increase. BPA first shall determine the amount of 
unauthorized increase related to demand and shall treat any remaining 
unauthorized increase as energy-related.
a. Unauthorized Increase in Demand
    That portion of any Measured Demand during Peak Period hours, 
before adjustment for power factor, which exceeds the demand that the 
purchaser is contractually entitled to take during the billing month 
and which cannot be assigned:
    (1) To a class of power that BPA delivers on such hour pursuant to 
contracts between BPA and the purchaser; or
    (2) To a type of power that the purchaser acquires from sources 
other than BPA and that BPA delivers during such hour, shall be billed:
    (a) In accordance with the provisions of the ``Relief from 
Overrun'' exhibit to the power sales contract; or
    (b) If such exhibit does not apply or is not a part of the 
purchaser's power sales contract, at the rate for Unauthorized 
Increase, based on the amount of energy associated with the excess 
demand.
    b. Unauthorized Increase in Energy
    The amount of Measured Energy during a billing month which exceeds 
the amount of energy which the purchaser is contractually entitled to 
take during that month and which cannot be assigned:
    (1) To a class of power which BPA delivers during such month 
pursuant to contracts between BPA and the purchaser; or
    (2) To a type of power which the purchaser acquires from sources 
other than BPA and which BPA delivers during such month, shall be 
billed:
    (a) In accordance with the provisions of the ``Relief from 
Overrun'' exhibit to the power sales contract; or
    (b) As unauthorized increase if such exhibit does not apply or is 
not a part of the purchaser's power sales contract.

G. Coincidental Billing Adjustment

    Purchasers of Priority Firm Power who are billed on a coincidental 
basis and who have diversity charges or diversity factors specified in 
their power sales contracts shall have their charges for billing demand 
adjusted according to the provisions of section III.C.5 of the GRSPs. 
Computed requirements purchasers are not subject to the Coincidental 
Billing Adjustment for scheduled power.

H. Energy Return Surcharge

    Any purchaser who preschedules in accordance with sections 2(a)(4) 
and 2(c)(2) of Exhibit E of the power sales contract and who returns, 
during a single offpeak hour, more than 60 percent of the difference 
between that purchaser's billing demand and computed average energy 
requirement for the billing month shall be subject to the following 
surcharge for each additional kilowatt-hour so returned:
    1. 4.25 mills per kilowatt-hour for the months of April through 
October;
    2. 1.80 mills per kilowatt-hour for the months of November through 
March.

Section V. Resource Cost Contribution

    BPA has made the following determinations:
    A. The approximate cost contribution of different resource 
categories to the PF-95 rate is 72.2 percent FBS and 27.8 percent 
Exchange.
    B. The forecasted average cost of resources available to BPA under 
average water conditions is 19.80 mills per kilowatt-hour.
    C. The forecasted cost of resources to meet load growth is 60.64 
mills per kilowatt-hour.

Schedule IP-95

Industrial Firm Power Rate

Section I. Availability

    This schedule is available to direct service industrial (DSI) 
customers for both the contract purchase of Industrial Firm Power and 
the purchase of Auxiliary Power if requested by the DSI customer and 
made available by BPA. If a DSI customer purchasing power under this 
rate schedule requests and BPA makes available power under another 
applicable wholesale rate schedule, the IP-95 rate schedule is 
available for that portion of power purchased not covered under the 
alternative rate schedule. This rate schedule supersedes Schedule IP-
93, which went into effect on October 1, 1993. Sales under this 
schedule are made subject to BPA's General Rate Schedule Provisions 
(GRSPs). [[Page 21139]] 

Section II. Rate

    The following rates shall be applied when first quartile service is 
provided under this rate schedule in accordance with the terms of a 
purchaser's Power Sales Contract dated August 25, 1981. A separate 
billing adjustment for the reserves provided by the purchasers of 
Industrial Firm Power is not contained in this rate schedule; the value 
of reserves credit has been included in the determination of the demand 
and energy charges.
    Any contractual reference to the IP Premium rate shall be deemed to 
refer to the demand and energy charges set forth below. Any reference 
to the IP Standard rate shall be deemed to refer to the same demand and 
energy charges minus the Discount for Quality of First Quartile 
Service.

A. Demand Charge

    1. $5.316 per kilowatt of billing demand occurring during all Peak 
Period hours during a billing month.
    2. No demand charge during Offpeak Period hours.

B. Energy Charge

    1. 21.90 mills per kilowatt-hour of billing energy for the billing 
months September through March.
    2. 18.02 mills per kilowatt-hour of billing energy for the billing 
months April through August.

Section III. Billing Factors

A. Billing Demand

    The billing demand shall be the BPA Operating Level during the Peak 
Period as adjusted for power factor. If there is more than one BPA 
Operating Level during the Peak Period within a billing month, the 
billing demand shall be a weighted average of the BPA Operating Levels 
during the Peak Period for the billing month. The BPA Operating Level 
is defined in section III.A.10 of the GRSPs. If BPA has agreed to serve 
a portion of a DSI load under an alternative rate schedule, the billing 
demand under the IP-95 rate schedule shall be specified in the contract 
initiating such arrangement.
    However, if BPA has agreed, pursuant to section 4 of the DSI power 
sales contract, to sell Industrial Firm Power on a daily demand basis 
(transitional service), then BPA shall bill the purchaser in accordance 
with the provisions of section V.C.3 of the GRSPs.

B. Billing Energy

    The billing energy shall be the Measured Energy for the billing 
month, minus any kilowatt-hours on which BPA assesses the charge for 
unauthorized increase.
    However, if BPA has agreed to serve only a portion of the DSI's 
load under the IP rate schedule, the billing energy for the power 
purchased under the IP rate shall be specified in the contract 
initiating such arrangement.

Section IV. Adjustments and Special Provisions

A. Discount for Quality of First Quartile Service

1. Application and Amount of First Quartile Discount
    If a purchaser requests discounted rate service, a discount of 0.72 
mills per kilowatt-hour of billing energy shall be granted. This 
billing credit shall be applied to the monthly billing energy under 
section III.B for all power purchased under this rate schedule. No 
credit shall be applied to those purchases subject to unauthorized 
increase charges under section IV.D of this rate schedule.
2. Eligibility Requirements for First Quartile Discount
    To qualify for the First Quartile Discount the purchaser must 
request discounted rate service in writing by April 2 of each calendar 
year. By virtue of making such request, the Purchaser is agreeing to 
accept the level and quality of First Quartile service described in 
section 6 of the Variable Industrial rate contract. Such acceptance 
includes the waiver of contract rights provided in section 6.a(2)(a) of 
said contract.

B. Curtailments

    BPA shall charge the DSI for curtailments of the lower three 
quartiles in accordance with the provisions of section 9 of the power 
sales contract. BPA shall apply the demand charge in effect at the time 
of the curtailment in the computation of the amount of the curtailment 
charge. In the event that a purchaser is found to be eligible to have a 
portion of their load served under an alternative rate schedule, 
application of the curtailment charge shall be specified in the 
contract instituting such arrangement.

C. Unauthorized Increase

1. Rate for Unauthorized Increase
    a. 100.00 mills per kilowatt-hour during billing months August 
through March.
    b. 57.40 mills per kilowatt-hour during billing months April 
through July.
2. Application of the Charge
    During any billing month, BPA may assess the unauthorized increase 
charge on the number of kilowatt-hours associated with the DSI Measured 
Demand in any one 60-minute clock-hour, before adjustment for power 
factor, that exceed the BPA Operating Level for that clock-hour, 
regardless of whether such Measured Demand occurs during the Peak or 
Offpeak Period.

D. Power Factor Adjustment

    The adjustment for power factor, when specified in this rate 
schedule or in the power sales contract, shall be made in accordance 
with the provisions of both this section and section III.C.1 of the 
GRSPs. The adjustment shall be made if the average leading power factor 
or average lagging power factor at which energy is supplied during the 
billing month is less than 95 percent.
    To make the power factor adjustment, BPA shall increase the billing 
demand by 1 percentage point for each percentage point or major 
fraction thereof (0.5 or greater) by which the average leading power 
factor or average lagging power factor is below 95 percent. BPA may 
elect to waive the adjustment for power factor in whole or in part.

E. Outage Credit

    Pursuant to section 7 of the General Contract Provisions, BPA shall 
provide an outage credit to any DSI for those hours for which BPA is 
unable to deliver the full billing demand during that billing month due 
to an outage on the facilities used by BPA to deliver Industrial Firm 
Power. Such credit shall not be provided if BPA is able to serve the 
DSI's load through the use of alternative facilities or if the outage 
is for less than 30 minutes. The amount of the credit shall be 
calculated according to the provisions of section III.C.2 of the GRSPs.

Section V. Resource Cost Contribution

    BPA has made the following determinations:
    A. The approximate cost contribution of different resource 
categories to the IP-95 rate is 85.8 percent Exchange and 14.2 percent 
New Resources.
    B. The forecasted average cost of resources available to BPA under 
average water conditions is 19.80 mills per kilowatt-hour.
    C. The forecasted cost of resources to meet load growth is 60.64 
mills per kilowatt-hour. [[Page 21140]] 

Schedule VI-95

Variable Industrial Power Rate

Section I. Availability

    This schedule is available to DSI customers for purchases under the 
Power Sales Contract implementing the VI rate schedule (Variable Rate 
Contract) of: (1) Industrial Firm Power; and (2) Auxiliary Power if 
requested by the DSI customer and made available by BPA. This schedule 
is available only for that portion of a DSI's load used in primary 
aluminum reduction including associated administrative facilities, if 
any. By virtue of incorporation of this rate schedule and associated 
GRSPs in the Variable Rate Contract, DSIs electing to purchase power 
under this rate schedule contractually agree to the terms and 
conditions of this rate schedule. A DSI further agrees to waive, for 
that portion of their load designated to purchase power at the VI rate, 
all rights they might otherwise have to purchase power at the 
Industrial Firm Power Rate Schedule for the duration of the Variable 
Rate Contract. Sales under this schedule are made subject to BPA's 
GRSPs.

Section II. Term of the Rate

    This rate schedule shall take effect on October 1, 1995, and shall 
terminate at midnight September 30, 1996.

Section III. Rate

A. Base Rate

    The formula to be used in the calculation of the monthly power bill 
is contained in section IV. A separate billing adjustment for the value 
of the reserves provided by purchasers of Industrial Firm Power is not 
contained in this rate schedule; the value of reserves credit has been 
included in the determination of the Plateau Energy Charge.
1. Base Variable Industrial Rate
a. Demand Charge
    $6.233 per kilowatt of billing demand, as adjusted, occurring 
during the Peak Period during a billing month. No demand charge is 
applied during Offpeak Period hours.
b. Plateau Energy Charge
    18.83 mills per kilowatt-hour of billing energy, as adjusted.
2. First Quartile Service Discount
    0.59 mills per kilowatt-hour of billing energy.
3. Lower Rate Limit
    15.03 mills per kilowatt-hour of billing energy.
4. Upper Rate Limit
    24.63 mills per kilowatt-hour of billing energy.

B. Base Rate Parameters Subject to Annual Adjustments

    The following base rate parameters shall be used to determine power 
bills for DSI customers purchasing power under the Variable Rate 
Contract. These parameters will be adjusted July 1, 1996, in accordance 
with the procedures contained in section VII.B of the GRSPs.
1. Lower Pivot Aluminum Price
    75.4 cents per pound.
2. Upper Pivot Aluminum Price
    91.6 cents per pound.

Section IV. Formula

    The Variable Industrial Power rate is a formula rate tied to the 
U.S. market price of aluminum. Under this rate schedule, the monthly 
energy charge varies in response to changes in the average price of 
aluminum in U.S. markets.

A. Demand Charge

    1. The Demand Charge, as stated in section III.A.1.a of this rate 
schedule, remains constant over all aluminum prices. The demand charge 
is applied to billing demand occurring during all Peak Period hours for 
all billing months.
    2. No demand charge during Offpeak Period hours.

B. Energy Charge

1. Plateau Energy Charge
    When the monthly billing aluminum price (described in section VII.A 
of the GRSPs) is between the Lower Pivot Aluminum Price and the Upper 
Pivot Aluminum Price inclusive (as stated in sections III.B.1 and 
III.B.2 of this rate schedule), the monthly energy charge shall be the 
Plateau Energy Charge as stated in section III.A.1.b of this rate 
schedule.
2. Reductions to Plateau Energy Charge
    When the monthly billing aluminum price is less than the Lower 
Pivot Aluminum Price, the monthly energy charge shall be the greater 
of:
a. The Plateau Energy Charge - (LP-MAP) * (LS)
where:

LP=the Lower Pivot Aluminum Price as stated in section III.B.1 of this 
rate schedule.
MAP=the monthly billing aluminum price in cents per pound determined 
pursuant to section VII.A of the GRSPs
LS=lower slope=1 mill per kilowatt-hour
    ________________________
    1 cent per pound

or

    b. The Lower Rate Limit as stated in section III.A.3 of this rate 
schedule.
3. Increases to Plateau Energy Charge
    When the monthly billing aluminum price is greater than the Upper 
Pivot Aluminum Price, the monthly energy charge shall be the lesser of:
a. The Plateau Energy Charge+(MAP-UP) * (US)
where:

MAP=the monthly billing aluminum price in cents per pound, as 
determined according to section VII.A of the GRSPs.
UP=the Upper Pivot Aluminum Price as stated in section III.B.2 of this 
rate schedule.
US=upper slope=0.75 mills per kilowatt-hour
    ____________________________
    1 cent per pound
b. The Upper Rate Limit, as stated in section III.A.4 of this rate 
schedule.

Section V. Billing Factors

A. Billing Demand

1. Billing Demand for Customers Whose Entire BPA Load Is Served at the 
VI Rate
    The billing demand for power purchased shall be the BPA Operating 
Level during the Peak Period as adjusted for power factor. If there is 
more than one BPA Operating Level during the Peak Period within a 
billing month, the billing demand shall be a weighted average of the 
BPA Operating Levels during the Peak Period for the billing month. The 
BPA Operating Level is defined in section III.A.10 of the GRSPs.
2. Billing Demand or Customers When Only a Portion of Their Total BPA 
Load Is Served at the Variable Rate
    The Billing Demand shall be the portion of the BPA Operating Level 
attributable to the VI rate as determined by the method specified in 
the Variable Rate Contract.
3. Billing Demand During Periods of Transitional Service
    If BPA has agreed, pursuant to section 4 of the DSI power sales 
contract, to sell Industrial Firm Power on a daily demand basis 
(transitional service), sections V.A.1 and V.A.2 of the rate schedule 
shall not apply, and BPA shall bill the purchaser in accordance with 
the provisions of section V.C of the GRSPs. [[Page 21141]] 

B. Billing Energy

    The billing energy for power purchased shall be the Measured Energy 
for the billing month, minus any kilowatt-hours on which BPA assesses 
the charge for unauthorized increase.

Section VI. Other Adjustments and Special Provisions

A. Lower and Upper Pivot Aluminum Prices

    Effective July 1, 1991, and every July 1 thereafter, the Lower and 
Upper Pivot Aluminum Prices set forth in section III.B of the rate 
schedule shall be adjusted following the procedures set forth in 
section VII.B of the GRSPs. The adjusted Lower and Upper Pivot Aluminum 
Prices shall supersede the Lower and Upper Pivot Aluminum Prices 
contained in section III.B of the rate schedule.

B. Discount for Quality of First Quartile Service

    If a purchaser requests First Quartile service with other than 
Surplus Firm Energy Load Carrying Capability (FELCC), a discount 
contained in section III.A.2 of this rate schedule shall be granted. 
This billing credit shall be applied to the monthly billing energy 
under section V.B for all power purchased under this rate schedule. No 
credit shall be applied to those purchases subject to unauthorized 
increase charges under section VI.F of this rate schedule. To qualify 
for the First Quartile Discount, the purchaser must request discounted 
rate service in writing by April 2 of each calendar year. By virtue of 
making such request, the Purchaser is agreeing to accept the level and 
quality of First Quartile service described in section 6 of the 
Variable Rate Contract. Such acceptance includes the waiver of contract 
rights provided in section 6.a(2)(a) of said contract.

C. Unauthorized Increase

1. Rate for Unauthorized Increase
    a. 100.00 mills per kilowatt-hour during the billing months August 
through March.
    b. 57.40 mills per kilowatt-hour during the billing months April 
through July.
2. Application of the Charge
    During any billing month, BPA may assess the unauthorized increase 
charge on the number of kilowatt-hours associated with the DSI Measured 
Demand in any one 60-minute clock-hour, before adjustment for power 
factor, that exceed the BPA Operating Level for that clock-hour, 
regardless of whether such Measured Demand occurs during the Peak or 
Offpeak Period.

D. Power Factor Adjustment

    The adjustment for power factor, when specified in this rate 
schedule or in the power sales contract, shall be made in accordance 
with the provisions of both this section and section III.C.1 of the 
GRSPs. The adjustment shall be made if the average leading power factor 
or average lagging power factor at which energy is supplied during the 
billing month is less than 95 percent.
    To make the power factor adjustment, BPA shall increase the BPA 
Operating Level by 1 percentage point for each percentage point or 
major fraction thereof (0.5 or greater) by which the average leading 
power factor or average lagging power factor is below 95 percent. BPA 
may elect to waive the adjustment for power factor in whole or in part.

E. Outage Credit

    Pursuant to section 7 of the General Contract Provisions, BPA shall 
provide an outage credit to any DSI to whom BPA is unable to deliver 
the full billing demand during that billing month due to an outage on 
the facilities used by BPA to deliver Industrial Firm Power. Such 
credit shall not be provided if BPA is able to serve the DSI's load 
through the use of alternative facilities or if the outage is for less 
than 30 minutes. The amount of the credit shall be calculated according 
to the provisions of section III.C.2 of the GRSPs.

Section VII. Resource Cost Contribution

    BPA has made the following determinations:
    A. The approximate cost contribution of different resource 
categories to the VI-95 rate is 85.8 percent Exchange and 14.2 percent 
New Resources.
    B. The forecasted average cost of resources available to BPA under 
average water conditions is 19.80 mills per kilowatt-hour.
    C. The forecasted cost of resources to meet load growth is 60.64 
mills per kilowatt-hour.

Schedule SI-95

Special Industrial Power Rate

Section I. Availability

    This rate schedule is available to any DSI purchaser using raw 
minerals indigenous to the region as its primary resource and 
qualifying for this special power pursuant to the procedures 
established in section 7(d)(2) of the Northwest Power Act. This 
schedule is available for the contract purchase of this special class 
of industrial power and also for the purchase of Auxiliary Power if 
requested by the DSI and made available by BPA. Schedule SI-95 
supersedes schedule SI-93, which went into effect on October 1, 1993. 
Sales under this schedule are made subject to BPA's General Rate 
Schedule Provisions (GRSPs).

Section II. Rate

    A separate billing adjustment for the value of the reserves 
provided by purchasers of this special class of Industrial Power is not 
contained in the rate schedule; the adjustment is reflected in the 
Special Industrial Power Rate charges.

A. Demand Charge

    1. $3.827 per kilowatt of billing demand occurring during all Peak 
Period hours during a billing month.
    2. No demand charge during Offpeak Period hours.

B. Energy Charge

    1. 21.20 mills per kilowatt-hour of billing energy for the billing 
months September through March;
    2. 15.08 mills per kilowatt-hour of billing energy for the billing 
months April through August.

Section III. Billing Factors

A. Billing Demand

    The billing demand for power purchased under the Standard Special 
Industrial Power rate shall be the BPA Operating Level during the Peak 
Period as adjusted for power factor. If there is more than one BPA 
Operating Level during the Peak Period within a billing month, the 
billing demand shall be a weighted average of the Peak Period BPA 
Operating Levels for the billing month. The BPA Operating Level is 
defined in section III.A.10 of the GRSPs.
    However, if BPA has agreed, pursuant to section 4 of the direct 
service industrial power sales contract, to sell Special Industrial 
Power on a daily demand basis (transitional service), BPA shall instead 
bill the purchaser in accordance with the provisions of section V.C of 
the GRSPs.

B. Billing Energy

    The billing energy under the Special Industrial rate shall be the 
Measured Energy for the billing month, minus any kilowatt-hours on 
which BPA assesses the charge for unauthorized increase.

Section IV. Adjustments and Special Provisions

A. Curtailments

    BPA shall charge the DSI for curtailments in accordance with the 
[[Page 21142]] provisions of the DSI's power sales contract. Any 
curtailment charge levied shall be computed using the Special 
Industrial Power rate.

B. Unauthorized Increase Charge

1. Rate for Unauthorized Increase
    a. 100.00 mills per kilowatt-hour during billing months August 
through March.
    b. 57.40 mills per kilowatt-hour during billing months April 
through July.
2. Application of the Charge
    During any billing month, BPA may assess the unauthorized increase 
charge on the number of kilowatt-hours associated with the DSI Measured 
Demand in any one 60-minute clock-hour, before adjustment for power 
factor, that exceed the BPA Operating Level for that clock-hour, 
regardless of whether such Measured Demand occurs during the Peak or 
Offpeak Period.

C. Power Factor Adjustment

    The adjustment for power factor, when specified in this rate 
schedule or in the power sales contract, shall be made in accordance 
with the provisions of both this section and section III.C.1 of the 
GRSPs. The adjustment shall be made if the average leading power factor 
or average lagging power factor at which energy is supplied during the 
billing month is less than 95 percent.
    To make the power factor adjustment for service under the Special 
Industrial Power rate, BPA shall increase the billing demand by 1 
percentage point for each percentage point or major fraction thereof 
(0.5 or greater) by which the average leading power factor or average 
lagging power factor is below 95 percent. BPA may elect to waive the 
adjustment for power factor in whole or in part.

D. Outage Credit

    Pursuant to section 7 of the General Contract Provisions, BPA shall 
provide an outage credit to any purchaser for those hours for which BPA 
is unable to deliver the full billing demand during that billing month 
due to an outage on the facilities used by BPA to deliver Special 
Industrial Power. Such credit shall not be provided if BPA is able to 
serve the purchaser's load through the use of alternative facilities or 
if the outage is for less than 30 minutes. The amount of the credit 
shall be calculated according to the provisions of section III.C.2 of 
the GRSPs.

Section V. Resource Cost Contribution

    BPA has made the following determinations:
    A. The SI-95 rate is not based on the cost of resources.
    B. The forecasted average cost of resources available to BPA under 
average water conditions is 19.80 mills per kilowatt-hour.
    C. The forecasted cost of resources to meet load growth is 60.64 
mills per kilowatt-hour.

Schedule CE-95

Emergency Capacity Rate

Section I. Availability

    This schedule is available for the purchase of capacity provided 
the purchaser requests such capacity and BPA has determined that 
capacity is available for such purpose. This schedule is available 
when:
    A. An emergency exists on the purchaser's system, or
    B. The purchaser wishes to displace higher-cost firm capacity 
resources which are otherwise available to meet the purchaser's load.
    This schedule supersedes Schedule CE-93 which went into effect on 
October 1, 1993. Sales under this schedule are made subject to BPA's 
General Rate Schedule Provisions.

Section II. Rate

A. Demand Charge

    As mutually agreed by BPA and the purchaser, up to $0.321 per 
kilowatt of demand per calendar day or portion thereof.

B. Intertie Charge

    The demand charge specified above shall be increased by $0.044 per 
kilowatt per day for capacity made available at the Oregon-California 
or Oregon-Nevada border for delivery over the Pacific Northwest-Pacific 
Southwest (Southern) Intertie.

Section III. Billing Factors

    The billing demand shall be the maximum amount requested by the 
purchaser and made available by BPA during a calendar day. If BPA is 
unable to meet subsequent requests by a purchaser for delivery at the 
demand previously established during such day, the billing demand for 
that day shall be the lower demand which BPA is able to supply.

Section IV. Billing Period

    Bills shall be rendered monthly.

Section V. Special Provision

    Energy delivered with such capacity shall be returned to BPA within 
7 days of the date of delivery and shall be returned at times and rates 
of delivery agreed to by both the purchaser and BPA prior to delivery. 
BPA may agree to accept the return energy after the normal 7 day return 
period provided that such delay has been mutually agreed upon prior to 
delivery.

Section VI. Resource Cost Contribution

    BPA has made the following determinations:
    A. The approximate cost contribution of different resource 
categories to the CE-95 rate is 85.8 percent Exchange and 14.2 percent 
New Resources.
    B. The forecasted average cost of resources available to BPA under 
average water conditions is 19.6 mills per kilowatt-hour.
    C. The forecasted cost of resources to meet load growth is 55.7 
mills per kilowatt-hour.

Schedule NR-95

New Resource Firm Power Rate

Section I. Availability

    This schedule is available for the contract purchase of firm power 
or capacity to be used within the Pacific Northwest. New Resource Firm 
Power is available to investor-owned utilities (IOUs) under net 
requirements contracts for resale to ultimate consumers, direct 
consumption, or use in construction, test and start up, and station 
service. New Resource Firm Power also is available to any public body, 
cooperative, or Federal agency to the extent such power is needed to 
serve any New Large Single Load. In addition, BPA may make this rate 
available to those parties participating in exchange agreements that 
use this rate schedule as the basis for determining the amount or value 
of power to be exchanged. This schedule supersedes Schedule NR-93, 
which went into effect on October 1, 1993. Sales under this schedule 
are made subject to BPA's General Rate Schedule Provisions (GRSPs).

Section II. Rate

A. Demand Charge

    1. $5.357 per kilowatt of billing demand occurring during all Peak 
Period hours during a billing month.
    2. No demand charge during Offpeak Period hours.

B. Energy Charge

    1. 28.66 mills per kilowatt-hour of billing energy for the billing 
months September through March.
    2. 25.10 mills per kilowatt-hour of billing energy for the billing 
months April through August.

Section III. Billing Factors

    In this section billing factors are listed for computed 
requirements purchasers [[Page 21143]] (section III.A), metered 
requirements purchasers, and those purchasers not covered by section 
III.A (section III.B).

A. Computed Requirements Purchasers

    Purchasers designated by BPA as computed requirements purchasers 
pursuant to power sales contracts shall be billed in accordance with 
the provisions of this section.
1. Billing Demand
    The billing demand for actual, planned, and contracted computed 
requirements purchasers shall be the higher of the billing factors 
``a'' and ``b,'' below:
    a. The lower of:
    (1) The larger of the Computed Peak Requirement or the Computed 
Average Energy Requirement; or
    (2) The Measured Demand, before adjustment for power factor.
    b. The lower of:
    (1) The Computed Peak Requirement; or
    (2) 60 percent of the highest Computed Peak Requirement during the 
previous 11 billing months (Ratchet Demand).
2. Billing Energy
    The billing energy for actual, planned, and contracted computed 
requirements purchasers shall be:
    a. For the months September through March, the sum of:
    (1) 55 percent of the Measured Energy; and
    (2) 45 percent of the Computed Energy Maximum.
    b. For the months April through August, the sum of:
    (1) 43 percent of the Measured Energy; and
    (2) 57 percent of the Computed Energy Maximum.

B. Metered Requirements Purchasers and Other Purchasers Not Covered by 
Section III.A, Above

    Purchasers designated as metered requirements customers and 
purchasers taking power under this rate schedule who are not otherwise 
covered by section III.A shall be billed as follows:
1. Billing Demand
    The billing demand shall be the Measured Demand as adjusted for 
power factor, unless otherwise specified in the power sales contract. 
However, purchasers who previously used the Firm Energy rate schedule, 
FE-2, either in the computation of their power bills or in the 
determination of the value of an exchange account, shall not be charged 
for demand under this rate schedule.
2. Billing Energy
    The billing energy shall be the Measured Energy, unless otherwise 
specified in the power sales contract.

Section IV. Adjustments and Special Provisions

A. Power Factor Adjustment

    The adjustment for power factor, when specified in this rate 
schedule or in the power sales contract, shall be made in accordance 
with the provisions of both this section and section III.C.1 of the 
GRSPs. The adjustment shall be made if the average leading power factor 
or average lagging power factor at which energy is supplied during the 
billing month is less than 95 percent.
    To make the power factor adjustment, BPA shall increase the billing 
demand by 1 percentage point for each percentage point or major 
fraction thereof (0.5 or greater) by which the average leading power 
factor or average lagging power factor is below 95 percent. BPA may 
elect to waive the adjustment for power factor in whole or in part.

B. Irrigation Discount

    BPA shall apply an irrigation discount, equal to 4.90 mills per 
kilowatt-hour, to the charges for qualifying energy purchased under 
this rate schedule. The discount shall apply only to energy purchased 
during the billing months of April through October. Eligibility for the 
irrigation discount and reporting requirements shall be determined 
pursuant to section III.C.4 of the GRSPs.

C. Conservation Surcharge

    The Conservation Surcharge shall be applied in accordance with 
section III.C.6 of the GRSPs and subsequent to any other rate 
adjustments.

D. Unauthorized Increase

    BPA shall apply the charge for Unauthorized Increase to any 
purchaser of New Resource Firm Power taking demand and/or energy in 
excess of its contractual entitlement.
1. Rate for Unauthorized Increase
    a. 100.00 mills per kilowatt-hour during billing months August 
through March.
    b. 57.40 mills per kilowatt-hour during billing months April 
through July.
2. Calculation of the Unauthorized Increase
    Each 60-minute clock-hour integrated or scheduled demand shall be 
considered separately in determining the amount which may be considered 
an unauthorized increase. BPA shall first determine the amount of 
unauthorized increase related to demand and shall then treat any 
remaining unauthorized increase as energy-related.
a. Unauthorized Increase in Demand
    That portion of any Measured Demand during Peak Period hours, 
before adjustment for power factor, that exceeds the demand which the 
purchaser is contractually entitled to take during the billing month 
and that cannot be assigned:
    (1) To a class of power which BPA delivers on such hour pursuant to 
contracts between BPA and the purchaser; or
    (2) To a type of power which the purchaser acquires from sources 
other than BPA and which BPA delivers during such hour, shall be 
billed:
    (a) In accordance with the provisions of the ``Relief from 
Overrun'' exhibit to the power sales contract; or
    (b) If such exhibit does not apply or is not a part of the 
purchaser's power sales contract, at the rate for Unauthorized 
Increase, based on the amount of energy associated with the excess 
demand.
b. Unauthorized Increase in Energy
    The amount of Measured Energy during a billing month that exceeds 
the amount of energy which the purchaser is contractually entitled to 
take during that month and that cannot be assigned:
    (1) To a class of power that BPA delivers during such month 
pursuant to contracts between BPA and the purchaser; or
    (2) To a type of power that the purchaser acquires from sources 
other than BPA and that BPA delivers during such month, shall be 
billed:
    (a) In accordance with the provisions of the ``Relief from 
Overrun'' exhibit to the power sales contract, or
    (b) As unauthorized increase if such exhibit does not apply or is 
not a part of the purchaser's power sales contract.

E. Coincidental Billing Adjustment

    Purchasers of New Resource Firm Power who are billed on a 
coincidental basis and who have diversity charges or diversity factors 
specified in their power sales contracts shall have their charges for 
billing demand adjusted according to the provisions of section III.C.5 
of the GRSPs. Computed requirements purchasers are not subject to the 
Coincidental Billing Adjustment for scheduled power.

F. Outage Credit

    Pursuant to section 7 of the General Contract Provisions, BPA shall 
provide [[Page 21144]] an outage credit to any purchaser for those 
hours for which BPA is unable to deliver the full billing demand during 
the billing month due to an outage on the facilities used by BPA to 
deliver New Resource Firm Power. Such credit shall not be provided if 
BPA is able to serve the purchaser's load through the use of 
alternative facilities or if the outage is for less than 30 minutes. 
The amount of the credit shall be calculated according to the 
provisions of section III.C.2 of the GRSPs.

G. Energy Return Surcharge

    Any purchaser who preschedules in accordance with sections 2(a)(4) 
and 2(c)(2) of Exhibit E of the Power Sales contract and who returns, 
during a single offpeak hour, more than 60 percent of the difference 
between that purchaser's billing demand and estimated computed average 
energy requirement for the billing month shall be subject to the 
following surcharge for each additional kilowatt-hour so returned:
    1. 4.25 mills per kilowatt-hour for the months of April through 
October; and
    2. 1.80 mills per kilowatt-hour for the months of November through 
March.

Section V. Resource Cost Contribution

    BPA has made the following determinations:
    A. The approximate cost contribution of different resource 
categories to the NR-95 rate is 89.7 percent Exchange and 10.3 percent 
New Resources.
    B. The forecasted average cost of resources available to BPA under 
average water conditions is 19.80 mills per kilowatt-hour.
    C. The forecasted cost of resources to meet load growth is 60.64 
mills per kilowatt-hour.

Schedule NF-95

Nonfirm Energy Rate

Section I. Availability

    This schedule is available for the purchase of nonfirm energy to be 
used both inside and outside the United States including sales under 
the Western Systems Power Pool (WSPP) agreements and sales to 
consumers. This schedule also applies to energy delivered for emergency 
use under the conditions set forth in section V.A of the General Rate 
Schedule Provisions (GRSPs). BPA is not obligated to offer nonfirm 
energy to any purchaser that results in displacement of firm power 
purchases under BPA's Power Sales Contracts. The offer of nonfirm 
energy under this schedule shall be determined by BPA. Schedule NF-95 
supersedes Schedule NF-93, which went into effect on October 1, 1993. 
Sales under this schedule are made subject to BPA's GRSPs.

Section II. Rates

    The average cost of nonfirm energy is 23.31 mills per kilowatt-
hour. The NF-95 rate schedule provides for upward and downward pricing 
flexibility from this average nonfirm energy cost. All rates and any 
subsequent adjustments contained in this rate schedule shall not exceed 
in total the NF Rate Cap defined in section IV.C of the GRSPs.

A. Standard Rate

    The Standard rate is any offered rate not to exceed 27.97 mills per 
kilowatt-hour.

B. Market Expansion Rate

    The Market Expansion rate is any offered rate below the Standard 
rate in effect. BPA may have one or more Market Expansion rates in 
effect simultaneously.

C. Incremental Rate

    The Incremental rate is the Incremental Cost of energy plus 2.00 
mills per kilowatt-hour, where the Incremental Cost is defined as all 
identifiable costs (expressed in mills per kilowatt-hour) that BPA 
would have avoided had it not produced or purchased the energy being 
sold under this rate.

D. Contract Rate

    The Contract rate is 14.83 mills per kilowatt-hour of billing 
energy.

Section III. Adjustments to Rates

A. Guaranteed Delivery Surcharge

    A surcharge of 2.00 mills per kilowatt-hour of billing energy is 
applied to guaranteed delivery of nonfirm energy under the Standard 
rate and Market Expansion rate.

B. Intertie Charge

    The Intertie Charge, on rate offers under any of the rates 
specified above, for sales of nonfirm energy scheduled for delivery 
over the Pacific Northwest-Pacific Southwest Intertie shall be:
    1. Inapplicable for rate offers of less than 23.31 mills per 
kilowatt-hour;
    2. At the discretion of BPA, from zero through 3.23 mills per 
kilowatt-hour, for rate offers of 23.31 mills per kilowatt-hour; or
    3. 3.23 mills per kilowatt-hour, for rate offers greater than 23.31 
mills per kilowatt-hour.

Section IV. Billing Factors

    The billing energy for nonfirm energy purchased under this rate 
schedule shall be the Measured Energy unless otherwise specified by 
contract.

Section V. Application and Eligibility

    Any time that BPA has nonfirm energy for sale, the Standard rate, 
the Market Expansion rate, the Incremental rate, the Contract rate, or 
a combination of these rates may be in effect.

A. Standard Rate

    The Standard rate:
    1. Is available for all purchases of nonfirm energy; and
    2. Applies to nonfirm energy purchased pursuant to the Relief from 
Overrun Exhibit to the power sales contract.

B. Market Expansion Rate

    1. Application of the Market Expansion Rate
    The Market Expansion rate applies when BPA determines that all 
markets at the Standard rate have been satisfied and BPA offers 
additional nonfirm energy.
    2. Market Expansion Rate Qualification Criteria
    In order to purchase nonfirm energy at the Market Expansion rate, a 
purchaser must:
    a. Have a displaceable resource, displaceable purchase of 
electricity, or
    b. Be an end-user load with a displaceable alternative fuel source.
    In addition, a purchaser must demonstrate one of the following:
    a. Shutdown or reduction of the output of the displaceable resource 
in an amount equal to the amount of Market Expansion rate energy 
purchased; or
    b. Reduction of a displaceable purchase and the output of the 
resource associated with that purchase, in an amount equal to the 
amount of Market Expansion rate energy purchased; or
    c. Shutdown or reduction of the identified output of the 
resource(s) indirectly in an amount equal to the amount of Market 
Expansion rate energy purchased (for example, the purchase may be used 
to run a pumped storage unit); or
    d. Decrease of an end-user alternate fuel source in an amount 
equivalent to the amount of Market Expansion rate energy purchased.
    3. Eligibility Criteria for Market Expansion Rate
    a. When only one Market Expansion rate is offered:
    Purchasers qualifying under section V.B.2 who purchased nonfirm 
energy directly from BPA are eligible to purchase power under the 
Market Expansion rate offered if the decremental cost of the qualifying 
[[Page 21145]] resource, purchase, or qualifying alternative fuel 
source is lower than the Standard rate in effect plus 2.0 mills per 
kilowatt-hour.
    Purchasers qualifying under section V.B.2 who purchase nonfirm 
energy through a third party are eligible to purchase power under the 
Market Expansion rate offered if the cost of the qualifying alternative 
fuel source is lower than the Standard rate in effect plus 4.0 mills 
per kilowatt-hour.
    b. When more than one Market Expansion rate is offered:
    Purchasers qualifying under section V.B.2 who purchase nonfirm 
energy directly from BPA are eligible to purchase power under the 
Market Expansion rate if the decremental cost of the qualifying 
resource, purchase, or qualifying alternative fuel source is lower than 
the Standard rate in effect plus 2.00 mills per kilowatt-hour. The rate 
applicable to a purchaser shall be the highest Market Expansion rate 
offered that is below the purchaser's qualifying decremental cost minus 
2.00 mills per kilowatt-hour.
    Purchasers qualifying under section V.B.2 who purchase nonfirm 
energy through a third party are eligible to purchase power under the 
Market Expansion rate if the decremental cost of the qualifying 
alternative fuel source is lower than the Standard rate plus 4.00 mills 
per kilowatt-hour. The rate applicable to a purchaser shall be the 
highest Market Expansion rate offered that is below purchaser's 
qualifying decremental cost minus 4.0 mills per kilowatt-hour.

C. Incremental Rate

    The Incremental rate applies to sales of energy:
    1. That is produced or purchased by BPA concurrently with the 
nonfirm energy sale;
    2. That BPA may at its option not produce or purchase; and
    3. That has an Incremental Cost greater than the Standard rate 
(plus the Intertie Charge, if applicable) less 2.00 mills per kilowatt-
hour.

D. Contract Rate

    The Contract rate applies to contracts (except power sales 
contracts offered pursuant to sections 5(b), 5(c), and 5(g) of the 
Northwest Power Act) that refer to the Contract rate:
    1. For the sale of nonfirm energy; or
    2. For determining the value of energy.

E. Western Systems Power Pool Transactions (WSPP)

    BPA may make available nonfirm energy for transactions under the 
WSPP agreement. WSPP sales shall be subject to the terms and conditions 
specified in the WSPP agreement and shall be consistent with regional 
and public preference. The rate for transactions under the WSPP 
agreement is any rate within the limits specified by the Standard, 
Market Expansion, and Incremental rates but may not exceed the maximum 
rate specified in the WSPP Agreement. The rate for WSPP sales may 
differ from the actual rate offered for non-WSPP transactions in any 
hour. The rate for WSPP transactions is independent of any other rate 
offered concurrently under this rate schedule outside that agreement.

F. End-User Rate

    BPA may agree to a rate or rate formula for nonfirm energy 
purchases by end-users. Such rate or rate formula shall be within the 
limits specified for the Standard and Market Expansion rates but may 
differ from the actual rates offered during any hour.

Section VI. Delivery

A. Rate of Delivery

    BPA shall determine the amount of nonfirm energy to be made 
available for each hour. Such determination shall be made for each 
applicable nonfirm energy rate.

B. Guaranteed Delivery

1. Availability
    BPA will determine the amount and duration of nonfirm energy to be 
offered on a guaranteed basis. Such daily or hourly amounts may be as 
small as zero or as much as all the nonfirm energy that BPA plans to 
offer for sale on such days.
2. Conditions
    Scheduled amounts of guaranteed nonfirm energy may not be changed 
except:
    a. When BPA and the purchaser mutually agree to increase or 
decrease the scheduled amounts; or
    b. When BPA must reduce nonfirm energy deliveries in order to serve 
firm loads because of unexpected generation or transmission losses.

Section VII. Resource Cost Contribution

    BPA has made the following determinations:
    A. The approximate cost contribution of different resource 
categories to the average cost of nonfirm energy is 92.7 percent FBS 
and 7.3 percent New Resources.
    B. The forecasted average cost of resources available to BPA under 
average water conditions is 19.80 mills per kilowatt-hour.
    C. The forecasted cost of resources to meet load growth is 60.64 
mills per kilowatt-hour.

Schedule SS-95

Share-the-Savings Rate

Section I. Availability

    This rate schedule is available for the contract purchase of 
Nonfirm Energy under an experimental rate and is limited to the term of 
the rate experiment. Nonfirm Energy will be made available under this 
rate schedule for use both inside and outside the United States for the 
displacement of a qualifying resource, displaceable purchase of 
electricity, or end-user load that can be served with alternate fuel 
sources. This rate schedule is only available to purchasers who execute 
a contract with BPA specifying use of the Share-the-Savings Rate. BPA 
is not obligated to offer Nonfirm Energy to any purchaser that results 
in displacement of firm power purchases under BPA's Power Sales 
Contracts. Schedule SS-95 supersedes Schedule SS-93, which went into 
effect on October 1, 1993. Sales under this schedule are made subject 
to BPA's General Rate Schedule Provisions (GRSPs).

Section II. Rate

    The rate shall be a formula rate based solely or in part on 
decremental cost information submitted by the purchaser. The rate 
formula and decremental cost, for purposes of establishing charges 
under this rate schedule, shall be defined in the applicable contract. 
The rate formula agreed upon by BPA and the purchaser shall in no event 
result in a rate higher than the NF Rate Cap defined in section IV.C of 
the GRSPs or lower than 1.00 mill per kilowatt-hour.

Section III. Billing Factor

    The billing energy for Nonfirm Energy purchased under this rate 
schedule shall be the Measured Energy unless otherwise specified in the 
Share-the-Savings rate contract.

Section IV. Application and Eligibility

A. General Requirements

    In order to purchase Nonfirm Energy under the Share-the-Savings 
Rate, the purchaser must:
    1. Have executed a contract specifying application of the Share-
the-Savings Rate Schedule, and
    2. Have a displaceable resource, displaceable purchase of 
electricity, or be an end-user load with a displaceable alternate fuel 
source. End-user loads with alternate fuel sources may not use the 
Decremental Cost of a displaceable [[Page 21146]] purchase of 
electricity to qualify for this rate.

B. BPA Service Priority

    Offers of Nonfirm Energy under this rate schedule shall be made 
pursuant to the terms and conditions set forth in the Share-the-Savings 
rate contract. BPA will sell Nonfirm Energy under this rate schedule 
consistent with regional and public preference.

Section V. Resource Cost Contribution

    BPA has made the following determinations:
    A. The SS-95 rate is not based on the cost of BPA resources.
    B. The forecasted average cost of resources available to BPA under 
average water conditions is 19.80 mills per kilowatt-hour.
    C. The forecasted cost of resources to meet load growth is 60.64 
mills per kilowatt-hour.

Schedule PS-95

Power Shortage Rate

Section I. Availability

    This schedule is available inside the Pacific Northwest for the 
purchase of Shortage Power to a utility when a shortage exists on its 
system and the utility requests Shortage Power under this rate 
schedule, or when Shortage Power is being delivered to a utility as the 
result of statewide or regionwide curtailment. This schedule is also 
available for sales under the Share-the-Shortage agreement, or a 
similar substitute agreement.
    This rate schedule is also available inside the Pacific Northwest 
when BPA arranges for purchase energy at the request of a customer. BPA 
is not obligated to make Shortage Power available or broker power under 
this rate schedule unless specified by contract. Sales under this 
schedule are made subject to BPA's General Rate Schedule Provisions.

Section II. Rates

A. Power Rate

    The power rate is any offered rate not to exceed 100.00 mills per 
kilowatt-hour. The offered rate may be specified as an energy charge 
only or as demand and energy charges.

B. Brokering Rate

    The brokering rate may be up to 1.00 mill per kilowatt-hour for 
services provided when BPA arranges for energy purchases for a customer 
from a seller other than BPA.

Section III. Billing Factors

    The billing factors shall be:

A. Power Purchases

    The factors to be used in determining the billings for power 
purchases under this rate schedule are as follows:
1. Billing Demand
    The billing demand shall be the Contract Demand as specified in the 
contract initiating such arrangement or as mutually agreed to by the 
parties. Otherwise the billing demand shall be the Measured Demand as 
adjusted for power factor.
2. Billing Energy
    The billing energy shall be the Contract Energy as specified in the 
contract initiating such arrangement or as mutually agreed to by the 
parties. Otherwise the billing energy shall be the Measured Energy.

B. Brokering Services

    When BPA arranges for energy purchases at the request of a 
customer, the purchaser shall be billed for such services based on the 
total amount of kilowatt-hours purchased.

Section IV. Adjustments and Special Provisions

A. Power Factor Adjustment

    The adjustment for power factor for BPA customers that are billed 
for shortage power on metered amounts, when specified in this rate 
schedule or in the contracts, shall be made in accordance with the 
provisions of both this section and section III.C.1 of the GRSPs. The 
adjustment shall be made if the average leading power factor or average 
lagging power factor at which energy is supplied during the billing 
month is less than 95 percent.
    To make the power factor adjustment, BPA shall increase the billing 
energy by 1 percentage point for each percentage point or major 
fraction thereof (0.5 or greater) by which the average leading power 
factor or average lagging power factor is below 95 percent. BPA may 
elect to waive the adjustment for power factor in whole or in part.

B. Power Brokering

    The charge for power brokering only applies to the service provided 
by BPA of finding purchased power for a customer from a seller other 
than BPA. BPA may agree to provide other services in addition to 
finding purchased power, but these services shall be billed separately 
at charges specified in the appropriate rate schedule(s) or 
agreement(s). Such services may include, but are not limited to, 
wheeling and load shaping.

C. Share-the-Shortage Transactions

    In the event a Share-the-Shortage type agreement is executed, BPA 
may make shortage power available to participants under such agreement. 
Any transactions entered into by BPA pursuant to the Share-the-Shortage 
agreement shall be subject to the terms and conditions specified in 
that agreement. The PS-95 rate does not incorporate the agreement but 
the agreement controls if there is any conflict between the PS-95 rate 
and the agreement. The rate for transactions under the Share-the-
Shortage agreement is any rate within the limits specified by the power 
rate but may not exceed the maximum rate specified in the agreement. 
The rate for Share-the-Shortage transactions is independent of any rate 
offered under this rate schedule for sales that do not fall under the 
agreement. The PS-95 power rate shall not be available for transactions 
with a party who triggers the Share-the-Shortage agreement if BPA 
elects to meet its required service obligations under the agreement by 
entering into an alternative agreement.

Section V. Resource Cost Contribution

    BPA has made the following determinations:
    A. The approximate cost contribution of different resource 
categories to the PS-95 rate is based upon the BPA's highest cost 
resource which currently is an FBS resource.
    B. The forecasted average cost of resources available to BPA under 
average water conditions is 19.80 mills per kilowatt-hour.
    C. The forecasted cost of resources to meet load growth is 60.64 
mills per kilowatt-hour.

Schedule RP-95

Reserve Power Rate

Section I. Availability

    This schedule is available for the purchase of power:
    A. In cases where a purchaser's power sales contract states that 
the rate for Reserve Power shall be applied;
    B. For which BPA determines no other rate schedule is applicable; 
or
    C. To serve a purchaser's firm power load in circumstances where 
BPA does not have a power sales contract in force with such purchaser, 
and BPA determines that this rate should be applied.
    This rate schedule may be applied to power purchased by entities 
outside the United States. This rate schedule supersedes Schedule RP-
93, which went into effect on October 1, 1993. Sales under this 
schedule are made [[Page 21147]] subject to BPA's General Rate Schedule 
Provisions (GRSPs).

Section II. Rate

A. Demand Charge

    1. $3.640 per kilowatt of billing demand occurring during all Peak 
Period hours during a billing month.
    2. No demand charge during Offpeak Period hours.

B. Energy Charge

    25.30 mills per kilowatt-hour of billing energy.

Section III. Billing Factors

    The factors to be used in determining the billing for power 
purchased under this rate schedule are as follows:

A. Billing Demand

    If applicable, the billing demand shall be the Contract Demand as 
specified in the power sales contract. Otherwise the billing demand 
shall be the Measured Demand as adjusted for power factor.

B. Billing Energy

    The billing energy shall be the Contract Demand multiplied by the 
number of hours in the billing month, if use of the Contract Demand for 
determining billing energy is specified in the power sales contract. 
Otherwise the billing energy for such purchasers shall be the Measured 
Energy.

Section IV. Power Factor Adjustment

    The adjustment for power factor, when specified in this rate 
schedule or in the power sales contract, shall be made in accordance 
with the provisions of both this section and section III.C.1 of the 
GRSPs. The adjustment shall be made if the average leading power factor 
or average lagging power factor at which energy is supplied during the 
billing month is less than 95 percent.
    To make the power factor adjustment, BPA shall increase the billing 
demand by 1 percentage point for each percentage point or major 
fraction thereof (0.5 or greater) by which the average leading power 
factor or average lagging power factor is below 95 percent. BPA may 
elect to waive the adjustment for power factor in whole or in part.

Section V. Resource Cost Contribution

    BPA has made the following determinations:
    A. The RP-95 rate is not based on the cost of resources.
    B. The forecasted average cost of resources available to BPA under 
average water conditions is 19.80 mills per kilowatt-hour.
    C. The forecasted cost of resources to meet load growth is 60.64 
mills per kilowatt-hour.

D. General Rate Schedule Provisions (GRSPs)

Table of Contents

I. Adoption of Revised Rate Schedules and General Rate Schedule 
Provisions
    A. Approval of Rates
    B. General Provisions
II. Types of BPA Service
    A. Priority Firm Power
    B. New Resource Firm Power
    C. Industrial Firm Power
    D. Special Industrial Power
    E. Auxiliary Power
    F. Shortage Power
    G. Surplus Firm Power
    H. Nonfirm Energy
    I.  Reserve Power
III. Billing Factors and Billing Adjustments
    A. Billing Factors for Demand
    B. Billing Factors for Energy
    C. Billing Adjustments
    D. Billing-Related Definitions
IV. Other Definitions
    A. Computed Requirements Purchasers
    B. Definitions Relating to Nonfirm Energy
    C. NF Rate Cap
    D. Determination of BPA's Average System Cost
V. Application of Rates Under Special Circumstances
    A. Energy Supplied for Emergency Use
    B. Construction, Test and Start-up, and Station Service
    C. Application of Rates During Initial Operation Period-
Transitional Service
    D. Changes in a DSI's BPA Operating Level
    E. Restriction of Deliveries
VI. Billing Information
    A. Determination of Estimated Billing Data
    B. Load Shift and Outage Reports
    C. Billing for New Large Single Loads
    D. Determination of Measured Demand
    E. Determination of Measured Energy
    F. Billing Month
    G. Payment of Bills
VII. Variable Industrial Rate Parameters and Adjustments
    A. Monthly Average Aluminum Price Determination
    B. Annual Adjustments to the Lower and Upper Pivot Aluminum 
Prices

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

A. Approval of Rates

    These 1995 rate schedules and General Rate Schedule Provisions 
(GRSPs) shall become effective upon interim approval or upon final 
confirmation and approval by the Federal Energy Regulatory Commission 
(FERC). BPA will request FERC approval effective October 1, 1995. BPA 
proposes that the following schedules, and the GRSPs associated with 
these schedules, be effective for 1 year: PF-95, IP-95, VI-95, SI-95, 
CE-95, NR-95, SS-95, NF-95, PS-95, and RP-95.

B. General Provisions

    These 1995 rate schedules, and the GRSPs associated with these rate 
schedules, supersede BPA's 1993 rate schedules (which became effective 
October 1, 1993) to the extent stated in the Availability section of 
each rate schedule. These schedules and GRSPs shall be applicable to 
all BPA contracts, including contracts executed both prior to and 
subsequent to enactment of the Northwest Power Act. All sales of power 
made under these rate schedules are subject to the following acts as 
amended: the Bonneville Project Act, the Regional Preference Act (Pub. 
L. 88-552), the Federal Columbia River Transmission System Act, and the 
Northwest Power Act.

Section II. Types of BPA Service

A. Priority Firm Power

    Priority Firm Power is electric power (capacity, energy, or 
capacity and energy) that BPA will make continuously available for 
resale to ultimate consumers for direct consumption, construction, test 
and startup, and station service by public bodies, cooperatives, and 
Federal agencies. (Construction, test and start-up, and station service 
are defined in section V.B of these GRSPs.)
    Utilities participating in the exchange under section 5(c) of the 
Northwest Power Act may purchase Priority Firm Power pursuant to their 
Residential Purchase and Sale Agreements.
    In addition, BPA may make Priority Firm Power available to those 
parties participating in exchange agreements specifying use of the 
Priority Firm rate for determining the amount or value of power to be 
exchanged.
    Power purchased under the rate schedule is to be used to meet the 
purchaser's actual firm load within the Pacific Northwest. Such power 
may be restricted in accordance with the Restriction of Deliveries 
section of these GRSPs (section V.E). However, BPA shall not restrict 
Priority Firm Power until Industrial Firm Power has been restricted in 
accordance with the provisions of section II.C of these GRSPs.
    Priority Firm Power is not available to serve New Large Single 
Loads.

B. New Resource Firm Power

    New Resource Firm Power is electric power (capacity, energy, or 
capacity and energy) that BPA will make continuously available:
    1. For any New Large Single Load,
    2. For firm power purchased by investor-owned utilities (IOUs) 
pursuant to power sales contracts with BPA, and [[Page 21148]] 
    3. For construction, test and start-up, and station service for 
facilities owned or operated by IOUs.
    New Resource Firm Power is to be used to meet the purchaser's 
actual firm load within the Pacific Northwest. Such power may be 
restricted in accordance with the Restriction of Deliveries section of 
these GRSPs (section V.E). However, BPA shall not restrict New Resource 
Firm Power until Industrial Firm Power has been restricted in 
accordance with the provisions of section II.C of these GRSPs.

C. Industrial Firm Power

    Industrial Firm Power is electric power that BPA will make 
continuously available to a direct service industrial (DSI) purchaser 
pursuant to the DSI's power sales contract and subject to:
    1. The restriction applicable to deliveries of all firm power 
pursuant to the Uncontrollable Forces and Continuity of Service 
provisions of the General Contract Provisions of the power sales 
contract, and
    2. The restrictions given in the Restriction of Deliveries section 
of the power sales contract.

D. Special Industrial Power

    Special Industrial Power is electric power which BPA will make 
continuously available to any DSI that qualifies for the Special 
Industrial Power rate pursuant to section 7(d)(2) of the Northwest 
Power Act. This power is similar in nature to Industrial Firm Power, 
but is subject to greater restriction by BPA. Special Industrial Power 
is made available to the qualifying DSI upon adoption of, and subject 
to, an amendment modifying its power sales contract.

E. Auxiliary Power

    Auxiliary Power is that power which a DSI requests and which BPA 
agrees to make available to serve that portion of the DSI's load which 
is in excess of the DSI's Operating Demand for Industrial Firm Power or 
Special Industrial Power.

F. Shortage Power

    Shortage Power is energy or energy with capacity, provided by BPA 
to a purchaser to serve such purchaser's regional load under 
circumstances where the purchaser is in danger of curtailing firm load 
even though the purchaser is operating all available resources and 
exercising all contractual rights to firm power to the maximum level 
feasible. In the event of a state ordered or regionwide load 
curtailment, a power deficiency is deemed to exist for those purchasers 
whose power supply condition is in part causally related to the 
state(s) initiated load curtailment.

G. Surplus Firm Power

    Surplus Firm Power is firm energy, firm power (firm energy with 
capacity), and firm capacity (capacity with energy return requirements) 
in excess of the amount required to meet BPA's existing contractual 
obligations to provide firm service. Surplus Firm Power may be used 
either for resale or direct consumption by purchasers both inside and 
outside the United States. Such power, however, may be restricted 
pursuant to the Restriction of Deliveries section of these GRSPs 
(section V.E).

H. Nonfirm Energy

    Nonfirm Energy is supplied or made available by BPA to a purchaser 
under an arrangement that does not have the guaranteed continuous 
availability feature of firm power. Nonfirm energy is mostly sold under 
the Nonfirm Energy rate schedule, NF-95. Nonfirm energy also may be 
supplied under the Share-the-Savings rate schedule, SS-95, which is 
available as an experimental rate for contract purchase.
    In addition, BPA also can make nonfirm energy available under the 
Nonfirm Energy rate schedule to the Western Systems Power Pool (WSPP) 
subject to terms and conditions agreed upon by the members 
participating in the WSPP and in accordance with BPA policy for such 
arrangements.
    However, Nonfirm Energy that has been purchased under a guarantee 
provision in the Nonfirm Energy rate schedule shall be provided to the 
purchaser in accordance with the provisions of that schedule and the 
power sales contract if applicable. BPA may make Nonfirm Energy 
available to purchasers both inside and outside the United States.

I. Reserve Power

    Reserve Power is firm power sold to a purchaser:
    1. In cases where the purchaser's power sales contract states that 
the rate for Reserve Power shall be applied;
    2. To provide service when no other type of power is deemed 
applicable; or
    3. To serve the purchaser's firm power loads under circumstances 
where BPA does not have a power sales contract in force with the 
purchaser.
    Sales of Reserve Power are subject to the Restriction of Deliveries 
section of these GRSPs (section V.E).

Section III. Billing Factors and Billing Adjustments

A. Billing Factors for Demand

1. Measured Demand
    The purchaser's Measured Demand shall be determined in the manner 
described in this section. Measured Demand shall be that portion of the 
metered or scheduled demand that is purchased from BPA under the 
applicable rate schedule. For those contracts to which BPA is a party 
and that provide for delivery of more than one class of electric power 
to the purchaser at any point of delivery, the portion of each 60-
minute clock-hour integrated demand assigned to any class of power 
shall be determined pursuant to the power sales contract. The portion 
of the total Measured Demand so assigned shall constitute the Measured 
Demand for each such class of power.
    The Measured Demand shall be determined from the metered demand or 
the scheduled demand, as hereinafter defined. The Measured Demand shall 
be determined on either a coincidental or a noncoincidental basis, as 
provided in the purchaser's power sales contract.
a. Metered Demand
    The metered demand in kilowatts shall be the largest of the 60-
minute clock-hour integrated demands, adjusted as specified in the 
power sales contract, at which electric energy is delivered to a 
purchaser:
    (1) At each point of delivery for which the metered demand is the 
basis for determination of the Measured Demand,
    (2) During each time period specified in the applicable rate 
schedule, and
    (3) During any billing period.
    Such largest integrated demand shall be determined from 
measurements made either in the manner specified in the power sales 
contract or as provided in section VI.A herein. In determining the 
metered demand, BPA shall exclude any abnormal integrated demands due 
to or resulting from:
    (1) Emergencies or breakdowns on, or maintenance of, the Federal 
system facilities; and
    (2) Emergencies on the purchaser's facilities, provided that such 
facilities have been adequately maintained and prudently operated, as 
determined by BPA.
b. Scheduled Demand
    The scheduled demand in kilowatts shall be the largest of the 
hourly demands at which electric energy is scheduled for delivery to a 
purchaser:
    (1) To each system for which scheduled demand is the basis for 
determination of the Measured Demand; [[Page 21149]] 
    (2) During each time period specified in the applicable rate 
schedule; and
    (3) During any billing period. Scheduled amounts are deemed 
delivered for the purpose of determining billing demand.
2. Ratchet Demand
    The Ratchet Demand in kilowatts shall be the maximum demand 
established during a specified period of time either during or prior to 
the current billing period. The demand on which the ratchet is based is 
specified in the relevant rate schedule or in these GRSPs. For 
utilities purchasing under the PF or NR rate schedules, the Ratchet 
Demand is based on the highest demand during prior billing months. When 
the Ratchet Demand is used as a billing factor, BPA shall have 
specified in the appropriate schedules or GRSPs:
    a. The period of time over which the ratchet shall be calculated;
    b. The type of demand to be used in the calculation; and
    c. The percentage (if any) of that demand which will be used to 
calculate the Ratchet Demand.
3. Contract Demand
    The Contract Demand shall be the maximum number of kilowatts that 
the purchaser agrees to purchase and BPA agrees to make available, 
subject to any limitations included in the power sales contract. BPA 
may agree to make deliveries at a rate in excess of the Contract Demand 
at the request of the purchaser, but shall not be obligated to continue 
such excess deliveries. Any contractual or other reference to Contract 
Demand as expressed in kilowatt-hours shall be deemed, for the purpose 
of these GRSPs, to refer to the term ``Contract Energy.''
4. Computed Peak Requirement
    For purchasers designated to purchase on the basis of computed 
requirements, the Computed Peak Requirement shall be determined as 
specified in the purchaser's power sales contract. That specification 
is provided in:
    a. Sections 16, 17(c), and 17(f), as adjusted by other sections of 
the contract, for actual computed requirements purchasers;
    b. Sections 16, 17(a), and 17(f), as adjusted by other sections of 
the contract, for planned computed requirements purchasers; and
    c. Sections 16 and 17(b), as adjusted by other sections of the 
contract, for contracted computed requirements purchasers.
5. Computed Average Energy Requirement
    For computed requirements purchasers, the Computed Average Energy 
Requirement shall be determined as specified in the purchaser's power 
sales contract. That specification is provided in:
    a. Sections 16, 17(c), and 17(f), as adjusted by other sections of 
the contract, for actual computed requirements purchasers;
    b. Sections 16, 17(a), and 17(f), as adjusted by other sections of 
the contract, for planned computed requirements purchasers; and
    c. Sections 16 and 17(b), as adjusted by other sections of the 
contract, for contracted computed requirements purchasers.
6. Operating Demand
    The Operating Demand is that demand which is established by each 
DSI in accordance with section 5(b) of the DSI's power sales contract. 
Unless the DSI has requested, and BPA has granted, an Auxiliary Demand, 
the Operating Demand establishes a limit with respect to:
    a. The demand which the purchaser may impose on BPA; and
    b. The total amount of energy during a billing month which the DSI 
is entitled to purchase from BPA.
7. Curtailed Demand
    A Curtailed Demand is the number of kilowatts of industrial power 
(Industrial Firm Power or Special Industrial Power) during the billing 
month which results from the DSI's request for such power in amounts 
less than the Operating Demand therefor. Each purchaser of industrial 
power may curtail its demand according to the terms of its power sales 
contract (which permits up to three levels of Curtailed Demand each 
month).
8. Restricted Demand
    Restricted Demand is the number of kilowatts of industrial power 
(either Industrial Firm Power or Special Industrial Power) that results 
when BPA has restricted delivery of such power for one clock-hour or 
more. BPA shall make such restrictions according to the terms of the 
DSI's power sales contract. In a given billing month, there are as many 
possible levels of Restricted Demand for a DSI as there are number of 
restrictions.
9. Auxiliary Demand
    Auxiliary Demand is the number of kilowatts of Auxiliary Power that 
a DSI requests and that BPA agrees to make available to serve a portion 
of the DSI's load during the period specified in the DSI's request. The 
DSI may request up to three levels of Auxiliary Demand during a billing 
month.
    If BPA agrees to a request for Auxiliary Power but later becomes 
unable to supply such demand, the Restricted Demand for Auxiliary Power 
is deemed to be the Auxiliary Demand for such period of restriction. 
Auxiliary Power may be curtailed by the DSI according to the provisions 
of section 9(a) of the DSI's power sales contract.
    BPA shall make Auxiliary Power available to Industrial Firm Power 
purchasers under the Industrial Firm Power rate schedule at the 
Standard Industrial rate. Auxiliary Power sales to DSIs electing to 
purchase under the Variable Industrial Power rate schedule (VI-95) 
shall be made at the rate determined pursuant to section III of the VI-
95 rate schedule. Auxiliary Power sales to DSIs purchasing under the 
Special Industrial rate will be made only at the Standard Special 
Industrial Power rate.
10. BPA Operating Level
    The BPA Operating Level is, for the purpose of these rate schedules 
and GRSPs, an hourly amount of industrial power (Industrial Firm Power 
or Special Industrial Power) for a DSI that is equal to the lowest of 
the following demands during that hour:
    a. Operating Demand plus Auxiliary Demand, if any;
    b. Curtailed Demand; or
    c. Restricted Demand.
    The weighted average BPA Operating Level for each DSI can be 
determined by summing the hourly BPA Operating Levels and dividing by 
the number of hours in the billing month.
    Each DSI must request service from BPA for each billing month in 
accordance with the terms of the power sales contract. The requested 
level of service will be the BPA Operating Level, provided BPA does not 
need to restrict the DSI and provided BPA agrees to supply any 
requested Auxiliary Demand. Each requested level of service may include 
a designation for both the Peak Period and the Offpeak Period. A DSI 
may request and BPA may agree to a level of service for the Offpeak 
Periods other than that in the Peak Period. If a DSI does not 
separately designate a requested level of service for the Peak and 
Offpeak Periods, the BPA Operating Level is the basis for determining 
if a DSI has incurred an unauthorized increase.
    Any DSI whose Measured Demand, before adjustment for power factor, 
during any 1 hour exceeds the BPA Operating Level for that hour shall 
be subject to unauthorized increase charges [[Page 21150]] for each 
kilowatt-hour of unauthorized increase associated with each overrun.
    Only the BPA Operating Level applicable during the Peak Period will 
be used in determining the Billing Demand for power purchased under the 
Industrial Firm Power rate schedule, the Variable Industrial Power rate 
schedule, and the Standard rate under the Special Industrial rate 
schedule. During the Peak Period the BPA Operating Level may be no 
greater than the Operating Demand for the billing month unless the 
customer has requested, and BPA has agreed to supply, the Auxiliary 
Demand.

B. Billing Factors for Energy

1. Measured Energy
    Measured Energy shall be that portion of the metered or scheduled 
energy that is purchased from BPA under the applicable rate schedule. 
For those contracts to which BPA is a party and that provide for 
delivery of more than one class of electric power to the purchaser at 
any point of delivery, the portion of each 60-minute clock-hour 
integrated demand assigned to any class of power shall be determined 
pursuant to the power sales contract. The sum of the portions of the 
demands so assigned shall constitute the Measured Energy for each such 
class of power.
    The Measured Energy shall be determined from the metered energy or 
the scheduled energy, as hereinafter defined.
a. Metered Energy
    The metered energy for a purchaser shall be the number of kilowatt-
hours that are recorded on the appropriate metering equipment, adjusted 
as specified in the power sales contract, and delivered to a purchaser:
    (1) At all points of delivery for which metered energy is the basis 
for determination of the Measured Energy, and
    (2) During any billing period.
    The metered energy shall be determined from measurements made 
either in the manner specified in the power sales contract or as 
provided in section VI.A herein.
b. Scheduled Energy
    The scheduled energy in kilowatt-hours shall be the sum of the 
hourly demands at which electric energy is scheduled for delivery to a 
purchaser:
    (1) For each system for which scheduled energy is the basis for 
determination of the Measured Energy, and
    (2) During any billing period.
    Scheduled amounts are deemed delivered for the purpose of 
determining billing energy.
2. Computed Energy Maximum
    The Computed Energy Maximum equals the product of the number of 
hours in the billing month and the Computed Average Energy Requirement.
3. Contract Energy
    The Contract Energy shall be the maximum number of kilowatt-hours 
that the purchaser agrees to purchase and BPA agrees to make available, 
subject to any limitations included in the power sales contract.

C. Billing Adjustments

1. Power Factor Adjustment
    The formula for determining average power factor is as follows:

[GRAPHIC][TIFF OMITTED]TN01MY95.071



    The data used in the above formula shall be obtained from meters 
that are ratcheted to prevent reverse registration. These data then 
shall be adjusted for losses, if applicable, before determination of 
the average power factor.
    When deliveries to a purchaser at any point of delivery either:
    a. Include more than one class of power; or
    b. Are provided under more than one rate schedule and it is 
impracticable to meter the kilowatt-hours and reactive 
kilovoltamperehours for each class or rate schedule separately, the 
average power factor of the total deliveries for the month will be 
used, where applicable, as the power factor for all power delivered to 
such point of delivery.
    To maintain acceptable operating conditions on the Federal system, 
BPA may, unless specifically otherwise agreed, restrict deliveries of 
power to a purchaser with a low power factor. Such restriction may be 
made to a point of delivery or to a purchaser's system at any time that 
the average leading power factor or average lagging power factor for 
all classes of power delivered to such point or to such system is below 
75 percent.
2. Outage Credit
    To the extent that BPA is unable to provide full service to a 
purchaser during the billing month as a result of interruptions in 
service due to reasons cited in the General Contract Provisions, BPA 
shall adjust the charges for those hours for billing demand for such 
purchaser to reflect BPA's inability to provide full service, provided 
such adjustment is mandated by the purchaser's power sales contract. 
The adjustment is provided on a point of delivery basis. To compute the 
adjustment for noncoincidentally billed systems, BPA shall determine 
the monthly demand charge(s) for the point(s) of delivery where the 
outage(s) occurred, multiply by the number of hours of outage, and 
divide by the total number of hours in the billing month. For 
coincidentally billed points of delivery, the adjustment shall apply 
only to those points of delivery at which BPA was unable to provide 
full service. For partial outages (such as an outage on one feeder in a 
substation with several feeders), BPA shall determine an equivalent 
interruption in order to arrive at the number of hours to be used in 
the calculation of the credit.
3. Low Density Discount (LDD)
a. Basic LDD Principles
    A predetermined discount shall be applied each billing month to the 
charges for all power purchased under the Priority Firm Power rate 
schedule by eligible purchasers as defined in section b, below. The 
discount shall be calculated on an annual basis and shall become 
effective with the first billing period in the calendar year. 
Retroactive billing for the LDD may be required if the data are not 
available by the January billing date. The level of the discount shall 
be determined from the following ratios:
    (1) The purchaser's total electric energy requirements during the 
previous calendar year (the purchaser's firm sales, nonfirm sales to 
firm retail loads, sales for resale, and associated losses, but 
excluding nonfirm sales to nonfirm retail loads, such as boiler loads 
served under BPA's alternate fuel policy) divided by the value of the 
purchaser's depreciated electric plant (excluding generation plant) at 
the end of such year, and [[Page 21151]] 
    (2) The average number of consumers (annual and seasonal consumers 
with residential, industrial, commercial, and irrigation accounts, but 
excluding separately billed services for water heating, electric space 
heating, and security lights) during the previous calendar year divided 
by the number of pole miles of distribution line at the end of such 
year. Distribution lines are defined as those that deliver electric 
energy from a substation or metering point, at a voltage of 34.5 kV or 
less, to the point of attachment to the consumer's wiring and include 
primary, secondary, and service facilities.
    These calculations shall be based on data provided in the 
purchaser's annual financial and operating report. In calculating these 
ratios, BPA shall use data pertaining to the purchaser's entire 
electric utility system within the region. Results of the calculations 
shall not be rounded.
    Customers who have not provided BPA with all four requisite pieces 
of annual data (see a.(1) and a.(2) above) by June 30 of each year 
shall be declared ineligible for the LDD effective with the June 
billing period for that year. BPA shall extend a customer's eligibility 
from the previous year through the June billing period of the following 
year and shall make any necessary retroactive adjustments once the new 
data have been processed. If no data have been received by December 31 
for the previous calendar year, BPA shall assume that the utility did 
not qualify for an LDD for that year. LDDs issued from January 1 to 
June 30 shall be assumed to have been in error, and the utility shall 
be billed for any such discounts issued.
    Revisions to the data used to calculate the amount of the LDD may 
be made by the purchaser for a period of up to 2 years from the first 
day to which the data apply. However, such revisions shall not apply to 
periods when the customer was ineligible for a discount due to late 
data submission.
b. Eligibility Criteria
    To qualify for a discount, the purchaser must meet all six of the 
following eligibility criteria:
    (1) The purchaser must serve as an electric utility offering power 
for resale;
    (2) The purchaser must agree to pass the benefits of the discount 
through to the purchaser's consumers within the region served by BPA;
    (3) The purchaser's average retail rate for the reporting year must 
exceed the average Priority Firm Power rate in effect for the 
qualifying period by 10 percent. For Calendar Year (CY) 1995, the 
average Priority Firm Power rate shall be the average of the PF-93 
Preference rate for 9 months and the PF-95 Preference rate for 3 
months;
    (4) The purchaser's kilowatt-hour-to-investment ratio (Ratio 
3.a.(1)) must be less than 100;
    (5) The purchaser's consumers-per-mile ratio (Ratio 3.a.(2)) must 
be less than 12; and
    (6) The purchaser must qualify for a discount based on the criteria 
in section c, below.
c. Discounts
    The purchaser shall be awarded the greatest discount for which that 
purchaser qualifies. The discounts and the qualifying criteria for 
those discounts are listed below.
    (1) Three percent, for any purchaser for whom:
    (a) The kilowatt-hour-to-investment ratio is equal to or greater 
than 25 but less than 35; or
    (b) The consumers-per-mile ratio is equal to or greater than 5 but 
less than 7.
    (2) Five percent, for any purchaser for whom:
    (a) The kilowatt-hour-to-investment ratio is equal to or greater 
than 15 but less than 25; or
    (b) The consumers-per-mile ratio is equal to or greater than 3 but 
less than 5.
    (3) Seven percent, for any purchaser for whom:
    (a) The kilowatt-hour-to-investment ratio is less than 15; or
    (b) The consumers-per-mile ratio is less than 3.
4. Irrigation Discount
a. Basic Irrigation Discount Principles
    A discount of 4.90 mills per kilowatt-hour shall be applied to the 
charges for qualifying irrigation energy purchased under the Priority 
Firm Power and New Resource Firm Power rate schedules, during the 
billing months of April through October. This discount shall be applied 
subsequent to calculation of the LDD, if applicable. Any energy on 
which the irrigation discount is claimed shall be metered separately by 
the Purchaser, and used exclusively for agricultural irrigation or 
drainage pumping.
b. Qualifying Energy Purchases
    The qualifying irrigation energy shall be determined as follows:
    (1) All irrigation energy must be used exclusively for the purpose 
of irrigation and drainage pumping on agricultural land and be measured 
at the end-use irrigation customer's meter. The discount shall apply to 
the measured energy sales at the end-use.
    (2) Energy subject to the discount must be purchased during the 
billing months of April through October.
    (3) Purchasers of exchange energy under the Residential Purchase 
and Sale Agreement (RPSA) are eligible for the irrigation discount for 
the portion of their irrigation sales qualifying for the exchange under 
the RPSA contracts. However, if the purchaser also purchases energy 
from BPA for general requirements, and receives an irrigation discount 
on those purchases, a second irrigation discount will not be applied to 
that energy through the RPSA exchange. Therefore, the irrigation 
discount will not be applied to any portion of the purchaser's 
irrigation sales qualifying for the RPSA exchange that receives the 
discount as a general requirements purchase.
    (4) General requirements customers are eligible for an irrigation 
discount for a portion of their irrigation sales equal to the share of 
their total sales served by BPA firm purchases (i.e., total irrigation 
and drainage pumping sales multiplied by BPA billing energy for 
Priority Firm or New Resources firm purchases divided by the total firm 
utility system requirements for the billing month).
c. Initial Reporting Requirements
    Requests for the Irrigation Discount must include the following 
information:
    (1) To receive an irrigation discount, a purchaser must file a 
request for the discount with its local BPA regional office by April 1 
each year.
    (2) In the request, the purchaser must certify that the irrigation 
energy is sold exclusively for use in irrigation and drainage pumping 
on agricultural land and that the discount is passed, in its entirety, 
to the irrigation consumer, regardless of whether the utility has 
raised its rates. BPA retains the right to verify, in a manner 
satisfactory to the Administrator, that the discounted energy is used 
for the sole benefit of the purchaser's irrigation load.
d. Annual Reporting Requirements
    Purchasers shall submit an annual irrigation report to their local 
BPA regional office in order to receive the irrigation discount. 
Purchasers are required to report information related to monthly 
irrigation energy sales. If a utility does not read its irrigation 
meters monthly, the utility must estimate its monthly irrigation sales. 
These estimates shall be reviewed by BPA regional offices. Purchasers 
must read their meters within 3 working days of the beginning and 
ending of the irrigation discount period (April-October). In order to 
qualify for the discount, the purchaser must submit all 
[[Page 21152]] data to BPA by December 31 of the calendar year in which 
the sales occurred. Irrigation reports to BPA shall include the 
following monthly information for the reporting period:
    (1) Utility name and period for which the report is being made;
    (2) Total irrigation sales and total qualifying irrigation energy 
sales (in kilowatt-hours) by month;
    (3) Total qualifying irrigation sales (in kilowatt-hours) by month 
under 400 horsepower, for exchanging utilities;
    (4) Total utility firm system requirements for other than full 
requirement customers by month (in kilowatt-hours);
    (5) Total energy purchased from BPA under the Priority Firm or New 
Resource rate by month in kilowatt-hours; and
    (6) The Purchaser shall list each irrigation and drainage account 
number in its annual report and whether each irrigation consumer is 
billed monthly, bimonthly, or seasonally. If the Purchaser is an 
exchanging utility, the Purchaser shall also identify the size (in 
horsepower) of the connected load for each active account. A utility 
may submit monthly reports, if it chooses. In that case, the active 
list of accounts should be included in the last monthly report 
submitted.
5. Coincidental Billing
    Purchasers of Priority Firm Power and New Resource Firm Power shall 
be billed on a noncoincidental demand basis for power purchased at each 
point of delivery under the applicable rate schedule(s) unless the 
power sales contract specifically provides for coincidental demand 
billing among particular points of delivery. For the purpose of these 
rate schedules and GRSPs, the purchaser's noncoincidental demand is the 
sum of the highest hourly peak demands during the billing month for 
each of the purchaser's points of delivery. The purchaser's 
coincidental demand is the highest demand for the billing month 
calculated by summing, for each hour of every day, the purchaser's 
demands for power purchased under the applicable rate schedule at all 
coincidentally billed points of delivery. See Special Provisions 
Exhibits of the Power Sales Contract, GCP E 17.
6. Conservation Surcharge
    The Conservation Surcharge shall be applied monthly and shall equal 
10 percent of the customer's total monthly charge for all power 
purchased under each rate schedule subject to the surcharge. The PF and 
NR rate schedules are subject to the Conservation Surcharge. If only a 
portion of the customer's service area is subject to the surcharge, 
then the amount of the surcharge shall equal 10 percent of the total 
charge for all power purchases multiplied by: (a) The portion of the 
customer's total retail load that is subject to the surcharge, divided 
by (b) the customer's total retail load.

D. Billing-Related Definitions

1. Peak Period
    The Peak Period includes the hours from 7 a.m. through 10 p.m. on 
any day Monday through Saturday inclusive. There are no exceptions to 
this definition; that is, it does not matter whether the day is a 
normal working day or a holiday. Any charges based on Peak Period hours 
shall be computed starting with the 8 a.m. meter reading since this 
reading applies to the 7 o'clock hour (7 a.m. to 8 a.m.). The 10 p.m. 
meter reading (for the 9 p.m. to 10 p.m. period) is the last meter 
reading of the day applicable to the Peak Period.
2. Offpeak Period
    The Offpeak Period includes all hours which do not occur during the 
Peak Period. Thus, the Offpeak Period consists of the hours from 10 
p.m. to 7 a.m., Monday through Saturday and all hours on Sunday.

Section IV. Other Definitions

A. Computed Requirements Purchasers

1. Designation as a Computed Requirements Purchaser
    A purchaser shall be designated as a computed requirements 
purchaser if it is so designated pursuant to the provisions of its 
power sales contract.
    When a purchaser operates two or more separate systems, only those 
systems designated by BPA will be covered by this section.
2. Purpose of the Computed Requirements Designation
    Use of the computed requirements designation is intended to assure 
that each purchaser who purchases power from BPA to supplement its own 
firm resources will purchase amounts of firm capacity and firm energy 
substantially equal to that which the purchaser would otherwise have to 
provide on the basis of normal and prudent operations.
    The amount of capacity and energy required for normal and prudent 
operations shall be determined pursuant to the purchaser's power sales 
contract.

B. Definitions Relating to Nonfirm Energy Decremental Cost

    Unless otherwise specified in a contractual arrangement, 
decremental cost as applied to Nonfirm Energy transactions shall be 
defined as:
    1. All identifiable costs (expressed in mills per kilowatt-hour) 
associated with the use of a displaceable thermal resource or end-user 
load with alternate fuel source to serve a purchaser's load that the 
purchaser is able to avoid by purchasing power from BPA, rather than 
generating the power itself or using an alternate fuel source; or
    2. All identifiable costs (expressed in mills per kilowatt-hour) to 
serve the load of a displaceable purchase of energy that the purchaser 
is able to avoid by choosing not to make the alternate energy purchase.
    All identifiable costs as used in the above definition may be 
reduced to reflect costs of purchasing BPA energy such as transmission 
costs, losses, or loopflow constraints that are agreed to by BPA and 
the purchaser.

C. NF Rate Cap

1. Application of the NF Rate Cap
    The NF Rate Cap defines the maximum nonfirm energy price for 
general application. At no time shall the total price for nonfirm 
energy, including any applicable service charges or rate adjustment, 
sold under any applicable rate schedule exceed the NF Rate Cap. The 
level of the NF Rate Cap is based on a formula tied to BPA's system 
cost and California fuel costs. The NF Rate Cap applies to all sales of 
nonfirm energy under any applicable rate schedule for a 12-year period 
beginning October 1, 1987.
2. Monthly Notification of the NF Rate Cap
    Prior to the beginning of a calendar month BPA shall perform the 
calculations contained in section IV.C.3 of these GRSPs to determine 
the effective NF Rate Cap for that calendar month. BPA is obligated to 
provide advance notification of the NF Rate Cap level to purchasers of 
nonfirm energy. BPA may waive this requirement only if BPA does not 
intend to offer Nonfirm Energy at prices above BPA's Average System 
Cost (BASC) at any time during a month. The notification will be given 
at least 10 calendar days prior to the first day of any calendar month 
in which the NF Rate Cap applies. BPA shall also maintain, on file for 
public review, a record of the NF Rate Cap by month throughout the 
period the cap is in effect.
3. NF Rate Cap Formula
    The NF Rate Cap shall be equal to the greater of the following:

a. BASC; or [[Page 21153]] 
b. BASC + .30(DEC-BASC)

Where:

BASC=BPA's average system cost, determined by dividing BPA's total 
system costs by BPA's total system sales. For this rate period BASC has 
been determined to be 29.41 mills per kilowatt-hour.
DEC=The Decremental Fuel Cost as determined in accordance with section 
IV.C.5 of these GRSPs.
4. Determination of BASC
    For purposes of determining BASC, the following definition shall 
apply:
    a. BPA's total system costs shall be the sum of all BPA's costs 
forecasted in each general rate case for the applicable rate period, 
including total transmission costs, Federal base system costs, new 
resource costs, exchange resource costs, and other costs not 
specifically allocated to a rate pool, such as section 7(g) costs.
    b. BPA's total annual system sales shall be the sum of all BPA's 
system firm and nonfirm sales forecasted each general rate case for the 
applicable test period. BASC shall be redetermined in each subsequent 
general rate case according to the above formula and will be in effect 
for the entire rate period over which the rates are in effect.
5. Determination of Decremental Fuel Cost
    The Decremental Fuel Cost shall be determined monthly by BPA. For 
purposes of calculating the NF Rate Cap, a weighted average of gas and 
petroleum prices for California will be used for approximating 
decremental fuel costs. The monthly decremental fuel cost shall be:
    a. the sum of:
    (1) The average California price for gas determined by multiplying 
the monthly gas use (WGU) developed pursuant to section IV.C.8.a times 
the monthly California gas price (MGP) determined pursuant to section 
IV.C.6 rounded to the nearest tenth of a mill; and
    (2) The average California price for petroleum determined by 
multiplying the monthly petroleum use (WOU) developed pursuant to 
section IV.C.8.b times the monthly California petroleum price (MOP) 
determined pursuant to section IV.C.7 rounded to the nearest tenth of a 
mill.
    b. Divided by the sum of the WGU and WOU developed in sections 
IV.C.8.a and b, respectively, rounded to the nearest tenth of a mill.
6. California Gas Price
    The MGP for purposes of calculating the decremental cost component 
of the rate cap shall be based on the following formula:

[GRAPHIC][TIFF OMITTED]TN01MY95.077


Where:

AGP=the average gas price for California electric utility plants 
expressed in cents per million Btu as reported in the most recent 
monthly issue of Electric Power Monthly (EPM) published by the Energy 
Information Administration (EIA), U.S. Department of Energy. Prices 
shall be rounded to the nearest one-tenth of a cent.
HGP=the historical relationship between gas prices in the effective 
month of the NF Rate Cap (month t) and the month in which the gas 
prices are reported in EPM (month r) using the following procedures:

    a. Summing all California gas prices, expressed in the nearest one-
tenth of a cent per million Btu, reported in EPM for month t for the 
years beginning with calendar year 1982 up to and including the prior 
calendar year. The sum of the historical monthly California gas prices 
shall be divided by the number of years for which MGPs were reported 
and rounded to the nearest one-tenth of a cent;
    b. Summing all California gas prices, expressed in the nearest one-
tenth of a cent per million Btu, reported in EPM for month r for the 
years beginning with calendar year 1982 up to and including the prior 
calendar year. The sum of the historical monthly California gas prices 
shall be divided by the number of years for which MGPs were reported 
and rounded to the nearest one-tenth of a cent; and
    c. Dividing the average monthly California gas price in a. above, 
by the average monthly California gas price in b. above, and rounding 
to the nearest one-tenth, or three significant places.

10=the factor for converting gas prices stated in cents per million Btu 
to mills per kWh. The factor assumes a heat rate of 10,000 Btu per 
kilowatt-hour.
7. California Petroleum Price
    The MOP for purposes of calculating the decremental cost component 
of the rate cap shall based on the following formula:

[GRAPHIC][TIFF OMITTED]TN01MY95.078


Where:

AOP=the last available average oil price for California electric 
utility plants expressed in cents per million Btu reported in EPM 
published by the EIA, U.S. Department of Energy. Prices shall be 
rounded to the nearest one-tenth of a cent.
HOP=the historical relationship between petroleum prices in the 
effective month of the NF Rate Cap (month t) and the last month in 
which the petroleum prices are reported in EPM (month r) using the 
following procedures:

    a. Summing all California petroleum prices, expressed in the 
nearest one-tenth of a cent per million Btu, reported in EPM for month 
t for the years beginning with calendar year 1982 up to and including 
the prior calendar year. The sum of the historical monthly California 
petroleum prices shall be divided by the number of years for which 
monthly petroleum prices were reported and rounded to the nearest one-
tenth of a cent;
    b. Summing all California petroleum prices, expressed in the 
nearest one-tenth of a cent per million Btu, reported in EPM for month 
r for the years beginning with calendar year 1982 up to and including 
the prior calendar year. The sum of the historical monthly California 
petroleum prices shall be divided by the number of years for which 
monthly petroleum prices were reported and rounded to the nearest one-
tenth of a cent; and
    c. Dividing the average monthly California petroleum price in a. 
above, by the average monthly California petroleum price in b. above, 
and rounding to the nearest one-tenth of a percent, or three 
significant places.

10=the factor for converting petroleum prices stated in cents per 
million Btu to mills per kWh. The factor assumes a heat rate of 10,000 
Btu per kilowatt-hour.
8. Weighting Factors
    For purposes of determining California fuel prices for the month, 
gas and petroleum prices will be weighted based on California's 
historical use of these two alternative fuels.
    a. Historical Gas Use in California. The following formula shall be 
used to determine the weighting factor for gas prices (WGU):

WGU=CGU*HGU
Where:

CGU=the monthly net gas-fired generation, expressed in gigawatthours, 
for California in the most recent monthly issue of EPM published by the 
EIA, U.S. Department of Energy.
HGU=the historical relationship between gas consumptions in the 
[[Page 21154]] effective month of the NF Rate Cap (month t) and the 
month for which gas consumption is reported in EPM (month r) using the 
following procedures:

    (1) Summing the reported net-gas fired generation for California, 
expressed in gigawatthours, from EPM for month t for the years 
beginning with calendar year 1982 up to and including the prior 
calendar year. The sum of California's historical monthly consumption 
shall be divided by the number of years for which gas consumption was 
reported and rounded to the nearest gigawatthour;
    (2) Summing the reported net gas-fired generation for California, 
expressed in gigawatthours, from EPM for month r for the years 
beginning with calendar year 1982 up to and including the prior 
calendar year. The sum of California's historical monthly consumption 
shall be divided by the number of years for which gas consumption was 
reported and rounded to the nearest gigawatthour; and
    (3) Dividing the average consumption of gas in California for the 
month t as determined in (1) above by the average consumption of gas 
for the month r as determined in (2) above and rounding to the nearest 
one-tenth, or three significant places.
    b. Historical Petroleum Use in California. The following formula 
shall be used to determine the weighting factor for petroleum prices 
(WOU):

WOU=COU*HOU
Where:

COU=the monthly net petroleum-fired generation, expressed in 
gigawatthours, in California in the most recent monthly issue of EPM 
published by the EIA, U.S. Department of Energy.
HOU=the historical relationship between petroleum consumptions in the 
effective month of the NF Rate Cap (month t) and the month for which 
petroleum consumption is reported in EPM (month r) using the following 
procedures:

    (1) Summing the reported net-petroleum generation for California, 
expressed in gigawatthours, from EPM for month t for the years 
beginning with calendar year 1982 up to and including the prior 
calendar year. The sum of California's historical monthly consumption 
shall be divided by the number of years for which petroleum consumption 
was reported and rounded to the nearest gigawatthour;
    (2) Summing the reported net-petroleum generation for California, 
expressed in gigawatthours, from EPM for month r for the years 
beginning with calendar year 1982 up to and including the prior 
calendar year. The sum of California's historical monthly consumption 
shall be divided by the number of years for which petroleum consumption 
was reported and rounded to the nearest gigawatthour; and
    (3) Dividing the average consumption of petroleum in California for 
the month t as determined in (1) above by the average consumption of 
petroleum for the month r or as determined in (2) above and rounding to 
the nearest one-tenth, or three significant places.

D. Determination of BPA's Average System Cost

    For purposes of determining BASC, the following definitions shall 
apply:
    1. BPA's total system costs shall be the sum of all BPA's costs 
forecasted in each general rate case for the applicable rate period, 
including total transmission costs, Federal base system costs, new 
resource costs, exchange resource costs, and other costs not 
specifically allocated to a rate pool, such as section 7(g) costs.
    2. BPA's total annual system sales shall be the sum of all BPA's 
system firm and nonfirm sales forecasted in each general rate case for 
the applicable test period.
    BASC shall be redetermined in each subsequent general rate case 
according to the above formula and will be in effect for the entire 
rate period over which the rates are in effect.

Section V. Application of Rates Under Special Circumstances

A. Energy Supplied for Emergency Use

    A purchaser taking Priority Firm or New Resource Firm Power shall 
pay in accordance with the Nonfirm Energy rate schedule, NF-95, and 
Emergency Capacity rate schedule, CE-95, for any electric energy or 
capacity which has been supplied:
    1. For use during an emergency on the purchaser's system, or
    2. Following an emergency to replace energy secured from sources 
other than BPA during such emergency.
    Mutual emergency assistance may, however, be provided and payment 
therefore settled under exchange agreements.

B. Construction, Test and Start-Up, and Station Service

    Power for the purpose of construction, test and start-up, and 
station service shall be made available to eligible purchasers under 
the Priority Firm and New Resource Firm Power Rate Schedules. Such 
power must be used in the manner specified below:
    1. Power sold for construction is to be used in the construction of 
the project.
    2. Power sold for test and start-up may be used prior to commercial 
operation both to bring the project on line and to ensure that the 
project is working properly.
    3. Power sold for station service may be purchased at any time 
following commercial operation of the project. Station service power 
may be used for project start-up, project shut-down, normal plant 
operations, and operations during a plant shut-down period.

C. Application of Rates During Initial Operation Period--Transitional 
Service

1. Eligibility for Transitional Service
    For an initial operating period, as specified in the power sales 
contract, beginning with the commencement of operation of a new 
industrial plant, a major addition to an existing plant, or 
reactivation of an existing plant or important part thereof, BPA may 
agree to bill the purchaser in accordance with the provisions of this 
section. This section shall apply to both:
    a. DSIs having new, additional or reactivated plant facilities, and
    b. Utility purchasers serving industrial purchasers with power 
purchased from BPA. BPA will provide transitional service to utilities 
for only those industrial loads for which the demand can be separately 
metered by the utility and recorded on a daily basis.
2. Calculation of the Daily Demand
    If the purchaser requests billing on a Daily Demand basis pursuant 
to its power sales contract and if BPA agrees to such billing, the 
billing demand for the billing month shall be the average of the Daily 
Demands as adjusted for power factor.
    Demand for each day shall be defined as 100 percent of the Measured 
Demand for the day (regardless of whether such Measured Demand occurs 
during the Peak Period or the Offpeak Period).
3. Billing for Transitional Service
    Utilities receiving transitional service shall provide BPA with 
Daily Demand information for the industrial consumer for whom 
transitional service is provided. To compute the power bill for the 
point of delivery which includes the load being served with 
transitional service, BPA shall, at its discretion, either:
    a. Determine the demand for the pertinent point of delivery without 
the industrial load and then add the average daily demand for such 
industrial load; or
    b. Bill the entire point of delivery on a daily demand basis. 
[[Page 21155]] 
    Daily demand billing shall not affect the level of any curtailment 
charge or energy charge assessed by BPA.

D. Changes in a DSI's BPA Operating Level

    If a DSI requests a waiver regarding the notice requirements 
specified in the DSI's power sales contract for a voluntary change in 
its BPA Operating Level, and if BPA does not grant the waiver, or if 
the DSI fails to give notice of such a change and does not request a 
waiver, the DSI shall be billed as if no notice has been provided until 
such time as the number of days in the notice period have passed. If, 
however, BPA agrees to waive the notice requirement, the power bill 
shall reflect the requested changes as of the requested effective date 
specified in the notice or, at BPA's discretion, a date of BPA's 
choosing within the notice period.

E. Restriction of Deliveries

    Deliveries of capacity or energy to any purchaser may be restricted 
when operation of the facilities used by BPA to serve such purchaser 
is:
    1. Suspended,
    2. Interrupted,
    3. Interfered with,
    4. Curtailed, or
    5. Restricted by the occurrence of any condition described in the 
Uncontrollable Forces or Continuity of Service sections of the General 
Contract Provisions of the power sales contract.

Section VI. Billing Information

A. Determination of Estimated Billing Data

    If the amounts of capacity, energy, or the 60-minute integrated 
demands for energy purchased from BPA must be estimated from data other 
than metered or scheduled quantities, historical patterns, and 
pertinent weather data, BPA and the purchaser will agree on billing 
data to be used in preparing the bill. If the parties cannot agree on 
estimated billing quantities, derived by any method, a determination 
binding on both parties shall be made in accordance with the 
arbitration provisions of the power sales contract.

B. Load Shift and Outage Reports

    Load shift and outage reports must be submitted to BPA within 4 
days of the corresponding load shift or outage. Reports may be made by 
telephone, mail, or other electronic processes where available. If 
customer reports are not received in a timely manner, BPA has the 
option to withhold load shift or outage credit.

C. Billing for New Large Single Loads

    Any BPA customer whose actual firm load includes one or more New 
Large Single Loads (NLSL) shall be billed for the NLSL(s) at the New 
Resource Firm Power Rate. The power requirements associated with the 
NLSL shall be established in a manner consistent with the provisions of 
this section.
    The purchaser shall warrant to BPA that NLSLs are separately 
metered. The metering must include provisions for determining:
    1. The NLSL demand during BPA's diurnal capacity billing periods,
    2. The NLSL energy during BPA's energy billing periods, and
    3. The NLSL reactive energy for the billing month.
    The design for the metering equipment for the NLSL must be approved 
by BPA. Testing and inspections of such metering installations shall be 
as provided in the General Contract Provisions.
    On a monthly basis, each purchaser of New Resource Firm Power shall 
report to BPA the quantity of power used by the NLSL during the 
purchaser's billing period. Data provided to BPA by the purchaser must 
be submitted to BPA within 2 normal working days of the date the 
purchaser reads the meters. BPA may elect to adjust the NLSL data for 
losses from the point of metering to the closest BPA point of delivery 
for the purchaser.

D. Determination of Measured Demand

    1. For points of delivery with fully operational metering under the 
Revenue Metering System (RMS), demand shall be measured from 0000 hours 
on the first day of the billing period through 2400 hours on the last 
day of the billing period.
    2. For points of delivery that do not have RMS metering, demand 
shall be measured from 0000 hours on the first complete (24 hour) day 
of the available metering data through 2400 hours on the last complete 
day of the available metering data. Billing demand will be determined 
from the period of available metering data that most closely matches 
the official billing period of the customer.

E. Determination of Measured Energy

    1. For points of delivery with fully operational metering under 
RMS, energy shall be measured from 0000 hours on the first day of the 
billing period through 2400 hours on the last day of the billing 
period.
    2. For points of delivery that do not have RMS metering, measured 
energy shall be the quantity of usage recorded on the meter between 
meter readings.

F. Billing Month

    Meters normally will be read and bills computed at intervals of 1 
month. A month is defined as the interval between scheduled meter-
reading dates. The billing month will not exceed 31 days in any case. 
While it may be necessary to read meters on a day other than the 
scheduled meter-reading date, for determination of billing demand, the 
billing month will cease at 2400 hours on the last scheduled meter-
reading date. Schedules will be predetermined. The customer must give 
30 days notice to request a change to the schedule.

G. Payment of Bills

    Bills for power shall be rendered monthly by BPA. Failure to 
receive a bill shall not release the purchaser from liability for 
payment. Bills for amounts due BPA of $50,000 or more must be paid by 
direct wire transfer; customers who expect that their average monthly 
bill will not exceed $50,000 and who expect special difficulties in 
meeting this requirement may request, and BPA may approve, an exemption 
from this requirement. Bills for amounts due BPA under $50,000 may be 
paid by direct wire transfer or mailed to the Bonneville Power 
Administration, P.O. Box 6040, Portland, Oregon 97228-6040, or to 
another location as directed by BPA. The procedures to be followed in 
making direct wire transfers will be provided by Financial Services and 
updated as necessary.
1. Computation of Bills
    Demand and energy billings for power purchased under each rate 
schedule shall be rounded to whole dollar amounts, by eliminating any 
amount which is less than 50 cents and increasing any amount from 50 
cents through 99 cents to the next higher dollar.
2. Estimated Bills
    At its option, BPA may elect to render an estimated bill for that 
month to be followed at a subsequent billing date by a final bill. Such 
estimated bill shall have the validity of and be subject to the same 
payment provisions as a final bill.
3. Due Date
    Bills shall be due by close of business on the 20th day after the 
date of the bill (due date). This requirement holds also for revised 
bills (see section 6 below). Should the 20th day be a Saturday, Sunday, 
or holiday (as celebrated by the purchaser), the due date shall be the 
next following business day. [[Page 21156]] 
4. Late Payment
    Bills not paid in full on or before close of business on the due 
date shall be subject to a penalty charge of $25. In addition, an 
interest charge of one-twentieth percent (0.05 percent) shall be 
applied each day to the sum of the unpaid amount and the penalty 
charge. This interest charge shall be assessed on a daily basis until 
such time as the unpaid amount and penalty charge are paid in full.
    Remittances received by mail will be accepted without assessment of 
the charges referred to in the preceding paragraph provided the 
postmark indicates the payment was mailed on or before the due date. 
Whenever a power bill or a portion thereof remains unpaid subsequent to 
the due date and after giving 30 days' advance notice in writing, BPA 
may cancel the contract for service to the purchaser. However, such 
cancellation shall not affect the purchaser's liability for any charges 
accrued prior thereto under such contract.
5. Disputed Billings
    In the event of a disputed billing, full payment shall be rendered 
to BPA and the disputed amount noted. Disputed amounts are subject to 
the late payment provisions specified above. BPA shall separately 
account for the disputed amount. If it is determined that the purchaser 
is entitled to the disputed amount, BPA shall refund the disputed 
amount with interest, as determined by BPA's financial services group.
    BPA retains the right to verify, in a manner satisfactory to the 
Administrator, all data submitted to BPA for use in the calculation of 
BPA's rates and corresponding rate adjustments. BPA also retains the 
right to deny eligibility for any BPA rate or corresponding rate 
adjustment until all submitted data have been accepted by BPA as 
complete, accurate, and appropriate for the rate or adjustment under 
consideration.
6. Revised Bills
    As necessary, BPA may render a revised bill.
    a. If the amount of the revised bill is less than or equal to the 
amount of the original bill, the revised bill shall replace all 
previous bills issued by BPA that pertain to the specified customer for 
the specified billing period and the revised bill shall have the same 
date as the replaced bill.
    b. If a revision causes an additional amount to be due BPA or the 
specified customer beyond the amount of the original bill, a revised 
bill will be issued for the difference and the date of the revised bill 
shall be its date of issue.

Section VII. Variable Industrial Rate Parameters and Adjustments

A. Monthly Average Aluminum Price Determination

1. Calculation of the Monthly Billing Aluminum Price
    The monthly billing aluminum price shall be determined by BPA for 
each billing month. For purposes of this rate schedule, the monthly 
billing aluminum price shall be based on the average price of aluminum 
in U.S. markets during the third calendar month prior to the billing 
month. The average price of aluminum in U.S. markets shall be defined 
as the average U.S. Transaction Price reported for the month by 
``Metals Week,'' in cents per pound, rounded to the nearest tenth of a 
cent.
2. Notification of the Monthly Average Aluminum Price
    BPA shall provide, 45 days prior to the billing month, written 
notification to purchasers under this rate schedule of the monthly 
billing aluminum price to be used for billing purposes. Upon written 
request supporting documentation shall be provided.
3. Changes in Aluminum Price Indicators
    In the event that BPA determines that factors outside its control 
render the monthly average U.S. Transaction Price unusable as an 
approximation of U.S. market prices, BPA may develop and substitute 
another indicator for prices in U.S. markets. BPA shall notify 
interested parties of its intent to do so at least 120 days prior to 
the billing month in which the change would become effective. In this 
notification, BPA shall explain the reason for the substitution and 
specify the replacement indicator it intends to use. BPA also shall 
describe the methodology to determine the monthly billing aluminum 
price to be used for billing purposes under this rate schedule and 
shall provide the necessary data to be used in the calculation. 
Interested persons will have until close of business 3 weeks from the 
date of the notification to provide comments. Consideration of comments 
and more current information may cause the final methodology and the 
substitute aluminum price index to differ from those proposed. BPA 
shall notify all affected parties, and those parties that submitted 
comments, of its final determination 90 days prior to the billing month 
the new indicator shall be effective.

B. Annual Adjustments to the Lower and Upper Pivot Aluminum Prices

    On July 1, 1991, and every July 1, thereafter, the Lower and Upper 
Pivot Aluminum Prices, as stated in section III.B of the rate schedule, 
shall be subject to change for billing purposes as herein described. 
The term ``annual adjustment date'' shall refer to July 1 of each year.
1. Implementation Procedures
    Beginning in 1991 and every year thereafter, prior to April 1 of 
that year, BPA shall provide the purchasers under this rate schedule 
preliminary written estimates of proposed adjustments to the Lower and 
Upper Pivot Aluminum Prices. By the last working day of the month of 
April, BPA shall notify interested parties in writing of BPA's revised 
determinations concerning changes to the Lower and Upper Pivot Aluminum 
Prices. BPA shall describe how the adjustments were determined and 
provide the data used in the calculations. In addition to written 
notification, BPA may, but is not obligated to, hold a public comment 
forum to clarify its determination and solicit comments. Interested 
persons may submit comments on the determinations to BPA and other 
parties. Comments will be accepted until close of business on the last 
working Friday in May. Consideration of comments and more current 
information may result in the final adjustment differing from the 
proposed adjustment. By June 30 of each year, BPA shall notify all VI 
purchasers, those parties that submitted comments, and parties that 
requested notification, of the final determination.
2. Annual Adjustment Procedures
    a. Annual Adjustment of the Lower Pivot Aluminum Price
    Beginning with the July 1, 1991, annual adjustment date, for each 
year that the Variable Industrial rate is in effect, the Lower Pivot 
Aluminum Price as stated in section III.B.1 of the rate schedule shall 
be adjusted on the July 1 annual adjustment date. The Lower Pivot 
Aluminum Price shall be revised by multiplying 59 cents per pound by 
the Cost Escalation Index described in section VII.B.3.b of these GRSPs 
and rounded to the nearest tenth of a cent. The revised Lower Pivot 
Aluminum Price shall replace the Lower Pivot Aluminum Price as stated 
in section III.B.1 of the rate schedule and shall be used to determine 
the energy rate in the subsequent 12 billing months.
    b. Annual Adjustment of the Upper Pivot Aluminum Price 
[[Page 21157]] 
    For each year that the Variable Industrial rate is in effect, the 
Upper Pivot Aluminum Price as stated in section III.B.2 of the rate 
schedule shall be adjusted on the July 1 annual adjustment date. The 
Upper Pivot Aluminum Price will be adjusted such that the Average 
Historical Aluminum Price described in section VII.B.4 of these GRSPs 
is the midpoint between the adjusted Upper Pivot Aluminum Price and the 
Average Historical Lower Pivot Aluminum Price described in section 
VII.B.5 below, except as limited to the greater of 65 cents per pound 
or the adjusted Lower Pivot Point for the year.
    The Upper Pivot Aluminum Price shall equal the greater of:

(1) (2)*(AAP)-ALP:

where

AAP=the Average Historical Aluminum Price described in section VII.B.4 
of these GRSPs.
ALP=the Average Historical Lower Pivot Aluminum Price described in 
section VII.B.5 of these GRSPs.

    (2) 65.0 cents per pound escalated to current dollars using the 
Cost Escalator for the Upper Pivot Aluminum Price described in section 
VII.B.3.c of these GRSPs.

or

    (3) The adjusted Lower Pivot Aluminum Price for the year.
    The revised Upper Pivot Aluminum Price shall supersede the Upper 
Pivot Aluminum Price as stated in section III.B.2 of the rate schedule 
and shall be used to determine the energy rate in the subsequent 12 
months.
3. Cost Escalators
    a. The cost indices described below shall be used in calculating 
the appropriate cost escalators. Each index shall be rounded to the 
nearest one-tenth of a percent, or three significant places.
(1) Electricity Cost Index
    The average VI rate in mills per kilowatt-hour based on the Plateau 
Energy Charge and the Discount for Quality of First Quartile Service in 
effect on the April 1 preceding the annual adjustment date and a load 
factor of 98.5 percent; divided by 22.8 mills per kilowatt-hour (the 
average VI-86 rate assuming the plateau energy charge and the Discount 
for Quality of First Quartile Service in 1986).
(2) Labor Cost Index
    The annual average hourly earnings for the U.S. primary aluminum 
industry (SIC 3334) over the previous complete calendar year, from the 
Employment and Earnings, published by the U.S. Department of Labor, 
Bureau of Labor Statistics (BLS), divided by $14.20 per hour (the value 
of SIC 3334 earnings reported for 1985).
(3) Alumina Cost Index
    The annual average of the monthly billing aluminum prices described 
in section VII.A of the GRSPs for the previous 1-year period beginning 
July 1 through June 30 divided by 50.8 cents per pound (the average 
U.S. Transaction price over the period April 1985 through March 1986).
(4) Other Costs Index
    The annual average GNP Implicit Price Deflator for the previous 
complete calendar year, as published by the U.S. Department of 
Commerce, Bureau of Economic Analysis, divided by 0.944 (the value of 
the GNP Implicit Price Deflator for 1985 with 1987=1.000).
    In the event the indices delineated above are discontinued or 
revised in a manner that BPA determines renders them unusable for 
calculating a consistent cost index, BPA will adjust or substitute 
another similar price index, following advance notification and 
opportunity for public comment as described in section VII.B.1 of these 
GRSPs.
    b. The Cost Escalator for the Lower Pivot Aluminum Price shall be a 
weighted average of the four indices contained in section VII.B.3.a 
above. The following weights shall be assigned each index:

Electricity Cost Index  .30
Labor Cost Index  .20
Alumina Cost Index  .20
Other Costs Index  .30

    c. The Cost Escalator for the Upper Pivot Aluminum Price shall be a 
weighted average of the Electricity Cost and Other Cost Escalators as 
stated in sections VII.B.3.a.(1) and VII.B.3.a.(4) above. The following 
weights shall be assigned each index:

Electricity Cost Index  .25
Other Costs Index  .75
4. Average Historical Aluminum Price
    Prior to the July 1, 1991, annual adjustment date and every annual 
adjustment date thereafter, an average historical aluminum price shall 
be calculated for the period the VI rate has been in effect beginning 
August 1986. The average historical aluminum price shall be determined 
following the procedures set forth below:
    a. Each monthly billing aluminum price determined pursuant to 
section VII.A of these GRSPs for the period August 1, 1986, through 
June 30 immediately preceding the annual adjustment date, shall be 
escalated to the current year dollars using the Price Deflator 
procedures described in section VII.B.6 below.
    b. The sum of the escalated monthly billing aluminum prices shall 
be divided by the number of months in the period and rounded to the 
nearest tenth of a cent to obtain the Average Historical Aluminum 
Price.
5. Average Historical Lower Pivot Aluminum Price
    Prior to the July 1, 1991, annual adjustment date and every annual 
adjustment date thereafter, the average of the Lower Pivot Aluminum 
Prices for the period the VI rate has been in effect beginning August 
1986, shall be calculated following the procedures set forth below:
    a. The Lower Pivot Aluminum Price in each month for the period 
August 1, 1986, through June 30 of the calendar year preceding the 
annual adjustment date, shall be escalated to the current year's 
dollars using the Price Deflator procedures described in section 
VII.B.6 below.
    b. The sum of the escalated monthly Lower Pivot Aluminum Prices 
shall be divided by the number of months in the period, and rounded to 
the nearest tenth of a cent to obtain an Average Historical Lower Pivot 
Aluminum Price.
6. Price Deflator Procedures
    For purposes of converting nominal dollars to real dollars in the 
calculation of the Average Historical Aluminum Price and the Average 
Historical Lower Pivot Aluminum Price, the following Price Deflator 
procedures shall be used:
    a. Monthly billing aluminum prices and Lower Pivot Aluminum Prices 
for any calendar months July through December shall be inflated by 
multiplying the price by the ratio of the GNP Implicit Price Deflator 
for the calendar year prior to the annual adjustment date divided by 
the Implicit Price Deflator for the calendar year in which the price 
occurred.
    b. Monthly billing aluminum prices and Lower Pivot Aluminum Prices 
for any calendar months January through June shall be inflated by 
multiplying the price by the ratio of the Implicit Price Deflator for 
the calendar year prior to the annual adjustment date divided by the 
Implicit Price Deflator for the calendar year prior to the year in 
which the price occurred. Each price shall be rounded to the nearest 
tenth of a cent.
[[Page 21158]]

V. Transmission Rate Schedules And General Transmission Rate 
Schedule Provisions (GTRSPs)

Table Of Contents

Summary of Rate Schedules

Transmission Rate Schedules

FPT-95.1  Formula Power Transmission
FPT-95.3  Formula Power Transmission
IR-95  Integration of Resources
IS-95  Southern Intertie Transmission
IN-95  Northern Intertie Transmission
IE-95  Eastern Intertie Transmission
ET-95  Energy Transmission
MT-95  Market Transmission
UFT-95  Use-of-Facilities Transmission
TGT-95  Townsend-Garrison Transmission
AC-95  Southern Intertie Annual Costs Rate and Billing Provisions

General Transmission Rate Schedule Provisions

Section I  Adoption of Revised Transmission Rate Schedules and 
General Transmission Rate Schedule Provisions
Section II  Billing Factor Definitions and Billing Adjustments
Section III  Other Definitions
Section IV  Billing Information

A. Summary of Rate Schedules

    BPA is proposing to surcharge by 4 percent the following 
transmission rate schedules: Formula Power Transmission; Integration of 
Resources; Southern Intertie Transmission; Northern Intertie 
Transmission; Eastern Intertie Transmission; and Energy Transmission. 
Pursuant to the Settlement Agreement, BPA proposes to increase the 
components of the FPT 95.3 rate by 4 percent for the October 1, 1995-
September 30, 1996 period. The increase to this rate for the 1-year 
period, however, does not preclude BPA from increasing the 3-year FPT 
rate, as necessary, in its 1996 rate case. BPA also is proposing 
extension of the Market Transmission (MT) rate, Use of Facilities (UFT) 
rate, and Townsend-Garrison Transmission (TGT) rate with no changes. 
The MT rate was developed for use among Western Systems Power Pool 
(WSPP) participants to allow for flexible hourly, daily, weekly, and 
monthly charges. The UFT and TGT rate schedules are formula rates. The 
UFT rate recovers the annual cost of identified facilities over which 
specific wheeling transactions occur. The TGT rate is a contract rate 
that recovers the cost of the Montana (Eastern) Intertie.
    In addition, BPA is proposing the Southern Intertie Annual Costs 
(AC-95) rate to be applied to owners of Pacific Northwest (PNW) 
Alternating Current (AC) Intertie capacity. This rate recovers the 
capacity owner's pro-rata share of actual PNW AC Intertie costs: 
operations, maintenance, general plant, and other identified expenses, 
as well as capital costs of replacements and reinforcements. The 
proposed AC-95 rate takes the place of the AC-93 rate, which was a 
``bridge'' rate until Capacity Ownership contracts were complete. 
Copies of the Ownership Agreement are available for examination at 
BPA's Public Information Center at the address listed at the beginning 
of this notice.

B. Transmission Rate Schedules

Schedule FPT-95.1

Formula Power Transmission

Section I. Availability

    This schedule supersedes schedule FPT-93.1 for all firm 
transmission agreements which provide that rates may be adjusted not 
more frequently than once a year. It is available for firm transmission 
of electric power and energy using the Main Grid and/or Secondary 
System of the Federal Columbia River Transmission System (FCRTS). This 
schedule is for full-year and partial-year service and for either 
continuous or intermittent service when firm availability of service is 
required. For facilities at voltages lower than the Secondary System, a 
different rate schedule may be specified. Service under this schedule 
is subject to BPA's General Transmission Rate Schedule Provisions 
(GTRSPs).

Section II. Rate

A. Full-Year Service

    The monthly charge per kilowatt of billing demand shall be one-
twelfth of the sum of the Main Grid Charge and the Secondary System 
Charge, as applicable and as specified in the Agreement.
1. Main Grid Charge
    The Main Grid Charge per kilowatt of billing demand shall be the 
sum of one or more of the following component factors as specified in 
the Agreement:
    a. Main Grid Distance Factor: The amount computed by multiplying 
the Main Grid Distance by $0.0386 per mile
    b. Main Grid Interconnection Terminal Factor: $0.28
    c. Main Grid Terminal Factor: $0.46
    d. Main Grid Miscellaneous Facilities Factor: $1.96
2. Secondary System Charge
    The Secondary System Charge per kilowatt of billing demand shall be 
the sum of one or more of the following component factors as specified 
in the Agreement:
    a. Secondary System Distance Factor: The amount determined by 
multiplying the Secondary System Distance by $0.2895 per mile
    b. Secondary System Transformation Factor: $4.26
    c. Secondary System Intermediate Terminal Factor: $1.34
    d. Secondary System Interconnection Terminal Factor: $0.71

B. Partial-Year Service

    The monthly charge per kilowatt of billing demand shall be as 
specified in Section II.A. for all months of the year except for 
agreements with terms 5 years or less and which specify service for 
fewer than 12 months per year. The monthly charge shall be:
    1. During months for which service is specified, the monthly charge 
defined in Section II.A., and
    2. During other months, the monthly charge defined in Section II.A. 
multiplied by 0.2.

Section III. Billing Factors

    Unless otherwise stated in the Agreement, the billing demand shall 
be the largest of:

A. The Transmission Demand;
B. The highest hourly Scheduled Demand for the month; or
C. The Ratchet Demand.

Schedule FPT-95.3

Formula Power Transmission

Section I. Availability

    This schedule supersedes schedule FPT-91.3 for all firm 
transmission agreements which provide that rates may be adjusted not 
more frequently than once every 3 years. It is available for firm 
transmission of electric power and energy using the Main Grid and/or 
Secondary System of the Federal Columbia River Transmission System. 
This schedule is for full-year and partial-year service and for either 
continuous or intermittent service when firm availability of service is 
required. For facilities at voltages lower than the Secondary System, a 
different rate schedule may be specified. Service under this schedule 
is subject to BPA's General Transmission Rate Schedule Provisions.

Section II. Rate

A. Full-Year Service

    The monthly charge per kilowatt of billing demand shall be one-
twelfth of the sum of the Main Grid Charge and the Secondary System 
Charge, as applicable and as specified in the Agreement.
1. Main Grid Charge
    The Main Grid Charge per kilowatt of billing demand shall be the 
sum of one or more of the following component factors as specified in 
the Agreement: [[Page 21159]] 
    a. Main Grid Distance Factor: The amount computed by multiplying 
the Main Grid Distance by $0.0292 per mile
    b. Main Grid Interconnection Terminal Factor: $0.28
    c. Main Grid Terminal Factor: $0.31
    d. Main Grid Miscellaneous Facilities Factor: $1.36
2. Secondary System Charge
    The Secondary System Charge per kilowatt of billing demand shall be 
the sum of one or more of the following component factors as specified 
in the Agreement:
    a. Secondary System Distance Factor: The amount determined by 
multiplying the Secondary System Distance by $0.2039 per mile
    b. Secondary System Transformation Factor: $2.63
    c. Secondary System Intermediate Terminal Factor: $0.87
    d. Secondary System Interconnection Terminal Factor: $0.46

B. Partial-Year Service

    The monthly charge per kilowatt of billing demand shall be as 
specified in Section II.A. for all months of the year except for 
agreements with terms 5 years or less and which specify service for 
fewer than 12 months per year. The charge shall be:
    1. During months for which service is specified, the monthly charge 
defined in Section II.A., and
    2. During other months, the monthly charge defined in Section II.A. 
multiplied by 0.2.

Section III. Billing Factors

    Unless otherwise stated in the Agreement, the billing demand shall 
be the largest of:
    A. The Transmission Demand;
    B. The highest hourly Scheduled Demand for the month; or
    C. The Ratchet Demand.

Schedule IR-95

Integration of Resources

Section I. Availability

    This schedule supersedes IR-93 and is available for firm 
transmission service for electric power and energy using the Main Grid 
and/or Secondary System of the Federal Columbia River Transmission 
System. The definitions of Main Grid and Secondary Systems are the same 
as for the FPT-95.1 and FPT-95.3 rate schedules and are contained in 
the General Transmission Rate Schedule Provisions (GTRSPs). For 
facilities at voltages lower than the Secondary System, a different 
rate schedule may be specified. Service under this schedule is subject 
to BPA's GTRSPs.

Section II. Rate

    The monthly charge shall be the sum of A and B where:

A. Demand Charge

    1. $0.441 per kilowatt of billing demand; or
    2. For Points of Integration (POI) specified in the Agreement as 
being short distance POIs, for which Main Grid and Secondary System 
facilities are used for a distance of less than 75 circuit miles, the 
following formula applies: [0.2 + (0.8 * transmission distance/75)] * 
($0.441 per kilowatt of billing demand)

Where:

    the billing demand for a short distance POI is the demand level 
specified in the Agreement for such POI, and the transmission distance 
is the circuit miles between the POI for a generating resource of the 
customer and a designated Point of Delivery serving load of the 
customer. Short distance POIs are determined by BPA after considering 
factors in addition to transmission distance.

B. Energy Charge

    1.10 mills per kilowatthour of billing energy.

Section III. Billing Factors

    To the extent that the Agreement provides for the customer to be 
billed for transmission in excess of the Transmission Demand or Total 
Transmission Demand, as defined in the Agreement, at the nonfirm 
transmission rate (currently ET-95), such transmission service shall 
not contribute to either the Billing Demand or the Billing Energy for 
the IR rate provided that the customer requests such treatment and BPA 
approves in accordance with the prescribed provisions in the Agreement.

A. Billing Demand

    The billing demand shall be the largest of:
    1. The Transmission Demand, except under General Transmission 
Agreements where a Total Transmission Demand is defined;
    2. The highest hourly Scheduled Demand for the month; or
    3. The Ratchet Demand.

B. Billing Energy

    The billing energy shall be the monthly sum of scheduled 
kilowatthours.

Schedule IS-95

Southern Intertie Transmission

Section I. Availability

    This schedule supersedes IS-93 and is available for all 
transmission on the Southern Intertie. Service under this schedule is 
subject to BPA's General Transmission Rate Schedule Provisions.

Section II. Rate

A. Nonfirm Transmission Rate

    The charge for nonfirm transmission of non-BPA power shall be 3.23 
mills per kilowatthour of billing energy. This charge applies for both 
north-to-south and south-to-north transactions.

B. Firm Transmission Rate

    The charge for firm transmission service shall be $0.734 per 
kilowatt per month of billing demand and 1.76 mills per kilowatthour of 
billing energy. Firm transmission will only be made available to 
customers under this rate schedule who have executed a contract with 
BPA specifying use of the Firm Transmission rate for either north-to-
south or south-to-north transactions.

Section III. Billing Factors

    A. For services under Section II.A, the billing energy shall be the 
monthly sum of the scheduled kilowatthours, plus the monthly sum of 
kilowatthours allocated but not scheduled. The amount of allocated but 
not scheduled energy that is subject to billing may be reduced pro rata 
by BPA due to forced Intertie outages and other uncontrollable forces 
that may reduce Intertie capacity.
    The amount of allocated but not scheduled energy that is subject to 
billing also may be reduced upon mutual agreement between BPA and the 
customer.
    B. For services under Section II.B, the billing demand shall be the 
Transmission Demand as defined in the Agreement. The billing energy 
shall be the monthly sum of scheduled kilowatthours, unless otherwise 
specified in the Agreement.

Schedule IN-95

Northern Intertie Transmission

Section I. Availability

    This schedule supersedes IN-93 and is available for all 
transmission on the Northern Intertie pursuant to an Agreement. Service 
under this schedule is subject to BPA's General Transmission Rate 
Schedule Provisions.

Section II. Rate

    The charge for transmission of non-BPA power on the Northern 
Intertie shall be 0.89 mills per kilowatthour. [[Page 21160]] 

Section III. Billing Factors

Billing Energy

    The billing energy shall be the monthly sum of the scheduled 
kilowatthours.

Schedule IE-95

Eastern Intertie Transmission

Section I. Availability

    This schedule supersedes IE-93 and is available for all nonfirm 
transmission on the Eastern Intertie. Service under this schedule is 
subject to BPA's General Transmission Rate Schedule Provisions.

Section II. Rate

    The charge for nonfirm transmission on the Eastern Intertie shall 
be 2.12 mills per kilowatthour.

Section III. Billing Factors

Billing Energy

    The billing energy shall be the monthly sum of the scheduled 
kilowatthours.

Schedule ET-95

Energy Transmission

Section I. Availability

    This schedule supersedes ET-93, unless otherwise specified in the 
Agreement, with respect to delivery using Federal Columbia River 
Transmission System facilities other than the Southern Intertie, 
Eastern Intertie, or the Northern Intertie, and is available for firm 
(of not more than 1 year duration) or nonfirm transmission between 
points within the Pacific Northwest. BPA may interrupt nonfirm service 
which is provided under this rate schedule. Service under this schedule 
is subject to BPA's General Transmission Rate Schedule Provisions.

Section II. Rate

    The charge for transmission of non-BPA power shall be 2.10 mills 
per kilowatthour.

Section III. Billing Factors

Billing Energy

    The billing energy shall be the monthly sum of scheduled 
kilowatthours.

Schedule MT-95

Market Transmission

Section I. Availability

    This schedule supersedes MT-91 and is available for Transmission 
Service for transactions using Federal Columbia River Transmission 
System facilities pursuant to the Western Systems Power Pool (WSPP) 
Agreement. General Transmission Rate Schedule Provisions.

Section II. Rate

    The charge shall be determined in advance by BPA. The charge shall 
be based on the duration of the proposed transaction and shall not 
exceed the following rates.

A. Hourly Rate

    The maximum charge shall be 6.5 mills per kilowatthour where the 
total hourly revenues from a given transaction during a calendar day 
shall not exceed the product of the Daily rate and the maximum demand 
scheduled during such day.

B. Daily Rate

    The maximum charge shall be $.105 per kilowattday where the total 
demand charge revenues in any consecutive 7-day period shall not exceed 
the product of the Weekly rate and the highest demand experienced on 
any day in the 7-day period.

C. Weekly Rate

    The maximum charge shall be $.52 per kilowattweek.

D. Monthly Rate

    The maximum charge shall be $2.27 per kilowattmonth.

Section III. Billing Factors

    The billing factors shall be specified in advance by BPA, as to 
representing the Transmission Service use or reservation.

Schedule UFT-95

Use-of-Facilities Transmission

Section I. Availability

    This schedule supersedes UFT-83 unless otherwise provided in the 
Agreement, and is available for firm transmission over specified 
Federal Columbia River Transmission System facilities. Service under 
this schedule is subject to BPA's General Transmission Rate Schedule 
Provisions.

Section II. Rate

    The monthly charge per kilowatt of Transmission Demand specified in 
the Agreement shall be one-twelfth of the annual cost of capacity of 
the specified facilities divided by the sum of Transmission Demands (in 
kilowatts) using such facilities. Such annual cost shall be determined 
in accordance with Section III.

Section III. Determination of Transmission Rate

    A. From time to time, but not more often than once in each Contract 
Year, BPA shall determine the following data for the facilities which 
have been constructed or otherwise acquired by BPA and which are used 
to transmit electric power:
    1. The annual cost of the specified FCRTS facilities, as determined 
from the capital cost of such facilities and annual cost ratios 
developed from the Federal Columbia River Power System financial 
statement, including interest and amortization, operation and 
maintenance, administrative and general, and general plant costs.
    2. The yearly noncoincident peak demands of all users of such 
facilities or other reasonable measurement of the facilities' peak use.
    B. The monthly charge per kilowatt of billing demand shall be one-
twelfth of the sum of the annual cost of the FCRTS facilities used 
divided by the sum of Transmission Demands. The annual cost per 
kilowatt of Transmission Demand for a facility constructed or otherwise 
acquired by BPA shall be determined in accordance with the following 
formula:
A
D

Where:

A = The annual cost of such facility as determined in accordance with 
A.1. above.
D = The sum of the yearly noncoincident demands on the facility as 
determined in accordance with A.2. above.

    The annual cost per kilowatt of facilities listed in the Agreement 
which are owned by another entity, and used by BPA for making 
deliveries to the transferee, shall be determined from the costs 
specified in the Agreement between BPA and such other entity.

Section IV. Determination of Billing Demand

    Unless otherwise stated in the Agreement, the factor to be used in 
determining the kilowatts of billing demand shall be the largest of:
    A. The Transmission Demand in kilowatts specified in the Agreement;
    B. The highest hourly Measured or Scheduled Demand for the month, 
the Measured Demand being adjusted for power factor; or
    C. The Ratchet Demand.

Schedule TGT-95

Townsend-Garrison Transmission

Section I. Availability

    This schedule supersedes TGT-1 and shall apply to all agreements 
which provide for the firm transmission of electric power and energy 
over transmission facilities of BPA's section [[Page 21161]] of the 
Montana [Eastern] Intertie. Service under this schedule is subject to 
BPA's General Transmission Rate Schedule Provisions.

Section II. Rate

    The monthly charge shall be one-twelfth of the sum of the annual 
charges listed below, as applicable and as specified in the agreements 
for firm transmission. The Townsend-Garrison 500-kV lines and 
associated terminal, line compensation, and communication facilities 
are a separately identified portion of the Federal Transmission System. 
Annual revenues plus credits for government use should equal annual 
costs of the facilities, but in any given year there may be either a 
surplus or a deficit. Such surpluses or deficits for any year shall be 
accounted for in the computation of annual costs for succeeding years. 
Revenue requirements for firm transmission use will be decreased by any 
revenues received from nonfirm use and credits for all government use. 
The general methodology for determining the firm rate is to divide the 
revenue requirement by the total firm capacity requirements. Therefore, 
the higher the total capacity requirements, the lower will be the unit 
rate.
    If the government provides firm transmission service in its section 
of the Montana (Eastern) Intertie in exchange for firm transmission 
service in a customer's section of the Montana Intertie, the payment by 
the government for such transmission services provided by such customer 
will be made in the form of a credit in the calculation of the Intertie 
Charge for such customer. During an estimated 1- to 3-year period 
following the commercial operation of the third generating unit at the 
Colstrip Thermal Generating Plant at Colstrip, Montana, the capability 
of the Federal Transmission System west of Garrison Substation may be 
different from the long-term situation. It may not be possible to 
complete the extension of the 500-kV portion of the Federal 
Transmission System to Garrison by such commercial operation date. In 
such event, the 500/230 kV transformer will be an essential extension 
of the Townsend-Garrison Intertie facilities, and the annual costs of 
such transformer will be included in the calculation of the Intertie 
Charge.
    However, starting 1 month after extension to Garrison of the 500-kV 
portion of the Federal Transmission System, the annual costs of such 
transformer will no longer be included in the calculation of the 
Intertie Charge.
    A. Nonfirm Transmission Charge:
    This charge will be filed as a separate rate schedule and revenues 
received thereunder will reduce the amount of revenue to be collected 
under the Intertie Charge below.
    B. Intertie Charge for Firm Transmission Service:

[GRAPHIC][TIFF OMITTED]TN01MY95.073



Section III. Definitions

A. TAC = Total Annual Costs of facilities associated with the Townsend-
Garrison 500-kV

    Transmission line including terminals, and prior to extension of 
the 500-kV portion of the Federal Transmission System to Garrison, the 
500/230 kV transformer at Garrison. Such annual costs are the total of: 
(1) Interest and amortization of associated Federal investment and the 
appropriate allocation of general plant costs; (2) operation and 
maintenance costs; (3) allowance for BPA's general administrative costs 
which are appropriately allocable to such facilities, and (4) payments 
made pursuant to section 7(m) of Pub. L. 96-501 with respect to these 
facilities. Total Annual Costs shall be adjusted to reflect reductions 
to unpaid total costs as a result of any amounts received, under 
agreements for firm transmission service over the Montana Intertie, by 
the government on account of any reduction in Transmission Demand, 
termination or partial termination of any such agreement or otherwise 
to compensate BPA for the unamortized investment, annual cost, removal, 
salvage, or other cost related to such facilities.
    B. NFR = Nonfirm Revenues, which are equal to: (1) The product of 
the Nonfirm Transmission Charge described in II(A) above, and the total 
nonfirm energy transmitted over the Townsend-Garrison line segment 
under such charge for such month; plus (2) the product of the Nonfirm 
Transmission Charge and the total nonfirm energy transmitted in either 
direction by the Government over the Townsend-Garrison line segment for 
such month.
    C. CR = Capacity Requirement of a customer on the Townsend-Garrison 
500-kV transmission facilities as specified in its firm transmission 
agreement.
    D. TCR = Total Capacity Requirement on the Townsend-Garrison 500-kV 
transmission facilities as calculated by adding (1) the sum of all 
Capacity Requirements (CR) specified in transmission agreements 
described in section I; and (2) the Government's firm capacity 
requirement. The Government's firm capacity requirement shall be no 
less than the total of the amounts, if any, specified in firm 
transmission agreements for use of the Montana Intertie.
    E. EC = Exchange Credit for each customer which is the product of: 
(1) The ratio of investment in the Townsend-Broadview 500-kV 
transmission line to the investment in the Townsend-Garrison 500-kV 
transmission line; and (2) the capacity which the Government obtains in 
the Townsend-Broadview 500-kV transmission line through exchange with 
such customer. If no exchange is in effect with a customer, the value 
of EC for such customer shall be zero.

Schedule AC-95

Southern Intertie Annual Costs Rate and Billing Provisions

Section I. Availability

    This schedule is applicable to each party (Capacity Owner) that 
executes a PNW AC Intertie Capacity Ownership Agreement (Agreement). 
Billings pursuant to this schedule are subject to the Billing 
Provisions in Exhibit B of the Agreement. This rate schedule shall be 
effective on the first day of the fiscal year following the earlier of 
interim or final FERC approval of this rate schedule. Unless otherwise 
defined in this rate schedule, capitalized terms used in this rate 
schedule shall have the respective definitions set forth in section 1 
of this Agreement.

Section II. Rate

A. Operations

    The monthly charge equals:


[[Page 21162]]

[GRAPHIC][TIFF OMITTED]TN01MY95.074


Where

    ``Months'' is equal to 12, or, if the Operating Plan has, during 
the fiscal year to which such Operating Plan pertains, been amended 
with respect to Operations Cost, the number of full months remaining in 
the fiscal year after such amended Operating Plan becomes effective for 
which Capacity Owners have not been billed.
    ``Operations Cost'' means, upon and after the effective date of 
Exhibit B pursuant to this Agreement, for any fiscal year any Allocated 
Direct Costs for Bonneville's PNW AC Intertie, operations Indirect 
Costs for Bonneville's PNW AC Intertie, and operations Overhead Costs 
for Bonneville's PNW AC Intertie for such fiscal year, each being 
determined in accordance with section I of Exhibit I.
    ``Capacity Ownership Percentage'' is as defined in subsection 1(k) 
of each Capacity Owner's Agreement.
    The monthly charge for the Operations rate shall be calculated 
using the forecast Operations Cost in the Operating Plan in effect 
during the month for which the monthly charge is calculated; provided, 
however, if the Operating Plan is amended during the fiscal year to 
which such Operating Plan pertains, the monthly charge for Operations 
Cost shall be calculated using the forecast Operations Cost less the 
Operations Cost already billed for such fiscal year for the remaining 
months of the fiscal year following such amendment.

B. Maintenance

    The monthly charge equals:

[GRAPHIC][TIFF OMITTED]TN01MY95.075


Where

    ``Months'' is equal to 12, or, if the Operating Plan has, during 
the fiscal year to which such Operating Plan pertains, been amended 
with respect to Maintenance Cost, the number of full months remaining 
in the fiscal year after such amended Operating Plan becomes effective 
for which Capacity Owners have not been billed.
    ``Maintenance Cost'' means, upon and after the effective date of 
Exhibit B pursuant to this Agreement, for any fiscal year any 
maintenance Direct Costs for Bonneville's PNW AC Intertie, maintenance 
Indirect Costs for Bonneville's PNW AC Intertie, and maintenance 
Overhead Costs for Bonneville's PNW AC Intertie for such fiscal year, 
each being determined in accordance with section II of Exhibit I.
    ``Capacity Ownership Percentage'' is as defined in subsection 1(k) 
of each Capacity Owner's Agreement.
    The monthly charge for the Maintenance rate shall be calculated 
using the forecast Maintenance Cost in the Operating Plan in effect 
during the month for which the monthly charge is calculated; provided, 
however, if the Operating Plan is amended during the fiscal year to 
which such Operating Plan pertains, the monthly charge for Maintenance 
Cost shall be calculated using the forecast Maintenance Cost less the 
Maintenance Cost already billed for such fiscal year for the remaining 
months of the fiscal year following such amendment.

C. General Plant

    The monthly charge equals:

[GRAPHIC][TIFF OMITTED]TN01MY95.078


Where

    ``Months'' is equal to 12, or, if the Operating Plan has, during 
the fiscal year to which such Operating Plan pertains, been amended 
with respect to General Plant Cost, the number of full months remaining 
in the fiscal year after such amended Operating Plan becomes effective 
for which Capacity Owners have not been billed.
    ``General Plant Cost'' means, upon and after the effective date of 
Exhibit B pursuant to this Agreement, for any fiscal year any costs 
(including direct costs, indirect costs, overhead costs, and AFUDC) for 
Bonneville's general plant investment for such fiscal year. The method 
for determining General Plant Cost is set forth in section IV of 
Exhibit I.
    ``Capacity Ownership Percentage'' is as defined in subsection 1(k) 
of each Capacity Owner's Agreement.
    The monthly charge for the General Plant rate shall be calculated 
using the General Plant Cost in the Operating Plan in effect during the 
month for which the monthly charge is calculated; provided, however, if 
the Operating Plan is amended during the fiscal year to which such 
Operating Plan pertains, the monthly charge for General Plant Cost 
shall be calculated using the General Plant Cost less the General Plant 
Cost already billed for such fiscal year for the remaining months of 
the fiscal year following such amendment.

D. Other Costs

    The monthly charge equals:

[GRAPHIC][TIFF OMITTED]TN01MY95.079


Where

    ``Months'' is equal to 12, or, if the Operating Plan has, during 
the fiscal year to which such Operating Plan pertains, been amended 
with respect to Other Cost, the number of full months remaining in the 
fiscal year after such [[Page 21163]] amended Operating Plan becomes 
effective for which Capacity Owners have not been billed.
    ``Other Costs'' means, upon and after the effective date of Exhibit 
B pursuant to this Agreement, Bonneville's other costs for Bonneville's 
PNW AC Intertie described in and determined pursuant to section V of 
Exhibit I.
    ``Capacity Ownership Percentage'' is as defined in subsection 1(k) 
of each Capacity Owner's Agreement.
    The monthly charge for the Other Costs rate shall be calculated 
using the forecast Other Costs in the Operating Plan in effect during 
the month for which the monthly charge is calculated; provided, 
however, if the Operating Plan is amended during the fiscal year to 
which such Operating Plan pertains, the monthly charge for Other Costs 
shall be calculated using the forecast Other Costs less the Other Costs 
already billed for such fiscal year for the remaining months of the 
fiscal year following such amendment.

E. Contracts and Rates

    The monthly charge equals:

[GRAPHIC][TIFF OMITTED]TN01MY95.080


Where

    ``Months'' is equal to 12, or, if the Operating Plan has, during 
the fiscal year to which such Operating Plan pertains, been amended 
with respect to Contracts and Rates Cost, the number of full months 
remaining in the fiscal year after such amended Operating Plan becomes 
effective for which Capacity Owners have not been billed.
    ``Contracts and Rates Costs'' means, upon and after the effective 
date of Exhibit B pursuant to this Agreement, for any fiscal year 
Bonneville's total contracts and rates costs (as described in section 
VI of Exhibit I) for such fiscal year as functionalized and allocated 
in accordance with section VI of Exhibit I to determine Contracts and 
Rates Costs for Bonneville's PNW AC Intertie.
    ``Capacity Ownership Percentage'' is as defined in subsection 1(k) 
of each Capacity Owner's Agreement.
    Contracts and Rates Cost is determined in accordance with section 
VI of Exhibit I as of the Effective Date. If Exhibit I is amended 
pursuant to subsection 19(k) of the Agreement to provide that the 
Contracts and Rates Cost determined in accordance with section VI of 
Exhibit I (and reflected in the Operating Plan for the fiscal year to 
which such Operating Plan pertains) is directly assigned to the 
Capacity Owners pursuant to such amended Exhibit I (and reflected in 
the Operating Plan for the fiscal year to which such Operating Plan 
pertains), the Capacity Ownership Percentage in the monthly charge 
calculation for such fiscal year shall be replaced by the ratio of (a) 
each Capacity Ownership Share to (b) the sum of all Capacity Ownership 
Shares.
    The monthly charge for the Contracts and Rates rate shall be 
calculated using the forecast Contracts and Rates Costs in the 
Operating Plan in effect during the month for which the monthly charge 
is calculated; provided, however, if the Operating Plan is amended 
during the fiscal year to which such Operating Plan pertains, the 
monthly charge for Contracts and Rates Cost shall be calculated using 
the forecast Contracts and Rates Cost less the Contracts and Rates Cost 
already billed for such fiscal year for the remaining months of the 
fiscal year following such amendment.

F. Power Scheduling

    The monthly charge equals:

[GRAPHIC][TIFF OMITTED]TN01MY95.081


    Where

    ``Months'' is equal to 12, or, if the Operating Plan has, during 
the fiscal year to which such Operating Plan pertains, been amended 
with respect to Power Scheduling Cost, the number of full months 
remaining in the fiscal year after such amended Operating Plan becomes 
effective for which Capacity Owners have not been billed.
    ``Power Scheduling Costs'' means, upon and after the effective date 
of Exhibit B pursuant to this Agreement, Bonneville's total power 
scheduling costs (as described in section VII of Exhibit I) as 
functionalized and allocated in accordance with section VII of Exhibit 
I to determine Power Scheduling Costs for Bonneville's PNW AC Intertie.
    ``Capacity Ownership Percentage'' is as defined in subsection 1(k) 
of each Capacity Owner's Agreement.
    Power Scheduling Cost is determined in accordance with section VII 
of Exhibit I as of the Effective Date. If Exhibit I is amended pursuant 
to subsection 19(k) of the Agreement to provide that the Power 
Scheduling Cost determined in accordance with section VII of Exhibit I 
(and reflected in the Operating Plan for the fiscal year to which such 
Operating Plan pertains) is directly assigned to the Capacity Owners 
pursuant to such amended Exhibit I (and reflected in the Operating Plan 
for the fiscal year to which such Operating Plan pertains), the 
Capacity Ownership Percentage in the monthly charge calculation for 
such fiscal year shall be replaced by the ratio of (a) each Capacity 
Ownership Share to (b) the sum of all Capacity Ownership Shares.
    The monthly charge for the Power Scheduling rate shall be 
calculated using the forecast Power Scheduling Costs in the Operating 
Plan in effect during the month for which the monthly charge is 
calculated; provided, however, if the Operating Plan is amended during 
the fiscal year to which such Operating Plan pertains, the monthly 
charge for Power Scheduling Cost shall be calculated using the forecast 
Power Scheduling Cost less the Power Scheduling Cost already billed for 
such fiscal year for the remaining months of the fiscal year following 
such amendment.

G. End of Term

    The monthly charge equals:


[[Page 21164]]

[GRAPHIC][TIFF OMITTED]TN01MY95.082


Where

    ``Months'' is equal to 12, or, if the Operating Plan has, during 
the fiscal year to which such Operating Plan pertains, been amended 
with respect to End of Term Costs, the number of full months remaining 
in the fiscal year after such amended Operating Plan becomes effective 
for which Capacity Owners have not been billed.
    ``End of Term Costs'' means, upon and after the effective date of 
Exhibit B pursuant to this Agreement, Bonneville's costs associated 
with decommissioning the PNW AC Intertie determined in accordance with 
section VIII of Exhibit I.
    ``Capacity Ownership Percentage'' is as defined in subsection 1(k) 
of each Capacity Owner's Agreement.
    The monthly charge for the End of Term rate shall be calculated 
using the forecast End of Term Costs in the Operating Plan in effect 
during the month for which the monthly charge is calculated; provided, 
however, if the Operating Plan is amended during the fiscal year to 
which such Operating Plan pertains, the monthly charge for End of Term 
Costs shall be calculated using the forecast End of Term Costs less the 
End of Term Cost already billed for such fiscal year for the remaining 
months of the fiscal year following such amendment.

H. Replacements and Reinforcements

    1. For each Replacement, the charge equals: Replacement Cost * 
Capacity Ownership Percentage.
    2. For each Reinforcement, the charge equals: Reinforcement Cost * 
Capacity Ownership Percentage.

Where

    ``Replacement Cost'' means, upon and after the effective date of 
Exhibit B pursuant to this Agreement, for any Replacement, the Direct 
Costs, Indirect Costs, Overhead Costs, and AFUDC for such Replacement, 
all capitalized to plant-in-service together with (1) simple interest 
on the foregoing costs accrued from the date on which Bonneville stops 
accruing AFUDC on the foregoing costs until the due date of the bill to 
Capacity Owner for the foregoing costs pursuant to subparagraph 
9(b)(2)(B) and (2) the costs of removal and any salvage credit 
associated with removal or replacement of existing facilities. 
Replacement Cost does not include capitalized general plant cost. The 
method for determining Replacement Costs for Bonneville's PNW AC 
Intertie is set forth in section III of Exhibit I.
    ``Reinforcement Cost'' means, upon and after the effective date of 
Exhibit B pursuant to this Agreement, for any Reinforcement, the Direct 
Costs, Indirect Costs, Overhead Costs, and AFUDC for such 
Reinforcement, all capitalized to plant-in-service together with (1) 
simple interest on the foregoing costs accrued from the date on which 
Bonneville stops accruing AFUDC on the foregoing costs until the due 
date of the bill to Capacity Owner for the foregoing costs pursuant to 
subparagraph 9(b)(2)(B) and (2) the costs of removal and any salvage 
credit associated with removal or replacement of existing facilities. 
Reinforcement Cost does not include capitalized general plant cost. The 
method for determining Reinforcement Costs for Bonneville's PNW AC 
Intertie is set forth in section III of Exhibit I.
    ``Capacity Ownership Percentage'' is as defined in subsection 1(k) 
of each Capacity Owner's Agreement.
    The charge for the Replacements and Reinforcements rate shall use 
the actual Replacement Cost and Reinforcement Cost in the Operating 
Plan.

Section III. Adjustments

    If an amendment to the Operating Plan results in a net amount that 
Bonneville owes the Capacity Owners pursuant to sections II.A-G or 
pursuant to section II.H, Bonneville shall refund such net amount 
pursuant to paragraph 9(f)(4) of the Agreement.
    The monthly charges assessed Capacity Owners under sections II.A-G 
shall be adjusted, and payment or refund made with interest, pursuant 
to paragraph 9(b)(2) or 9(f)(4) of the Agreement, to reflect amendments 
to the Operating Plan that occur after the year to which such Operating 
Plan pertains. A Capacity Owner's share of the adjustment shall be 
determined using the same Capacity Ownership Percentage used in the 
billings under sections II.A-G during the fiscal year that such 
Operating Plan is effective.

Annual Costs Rate

Billing Provisions

I. General Provisions

A. Approval of Rates

    The annual costs rate shall become effective upon interim approval 
or upon final confirmation and approval by FERC. Bonneville will 
request FERC approval of such rate schedule effective on the first day 
of a Bonneville fiscal year.

B. Application of Billing Provisions

    These Billing Provisions shall apply to bills rendered by 
Bonneville pursuant to the annual costs rate.

C. Definition of Terms

    The meaning of terms used in the annual costs rate shall be as 
defined in the Agreement or, if no definition is provided by the 
Agreement, such terms shall be defined according to applicable Federal 
law.

II. Billing Information

Payment of Bills

    Charges pursuant to the annual costs rate shall be included in 
Bonneville's monthly power bill to Capacity Owner. Failure to receive a 
power bill shall not release Capacity Owner from liability for payment. 
Power bills for amounts due of $50,000 or more must be paid by direct 
wire transfer. If Capacity Owner anticipates special difficulties in 
meeting this requirement, Capacity Owner may request and Bonneville may 
approve an exemption from this requirement. Power bills for amounts due 
Bonneville under $50,000 may be paid by direct wire transfer or mailed 
to the Bonneville Power Administration, P.O. Box 6040, Portland, Oregon 
97228-6040, or to another location as directed by Bonneville. The 
procedures to be followed in making direct wire transfers will be 
provided by Bonneville's Financial Services Group and updated as 
necessary.

A. Computation of Bills

    1. Bonneville shall bill Capacity Owner in accordance with the 
annual costs rate.
    2. Capacity Owner shall provide necessary information to Bonneville 
for any computation required to determine proper charges pursuant to 
the Agreement and shall cooperate with Bonneville in the exchange of 
additional information which may be reasonably useful for respective 
operations.
    3. Bills rendered pursuant to this Agreement shall be rounded to 
whole dollar amounts, by eliminating any amount which is less than 50 
cents and increasing any amounts from 50 cents to 99 cents to the next 
higher whole dollar.

B. Billing Month

    For charges pursuant to the annual costs rate the billing month 
shall be the [[Page 21165]] same as for the power bill rendered by 
Bonneville to Capacity Owner.

C. Due Date

    Charges pursuant to the annual costs rate shall be included in the 
power bill rendered by Bonneville to Capacity Owner and shall be due as 
part of the power bill when such power bill is due.

D. Late Payment

    The penalties for failure to pay a bill in full on or before close 
of business on the due date shall be the same as those contained in the 
late payment provisions in Bonneville's General Rate Schedule 
Provisions in effect on the date of the bill; provided, however, that 
no other provision of any such General Rate Schedule Provisions, 
including, but not limited to, provisions regarding cancellation, 
termination, or suspension of service, shall have application with 
respect to the payment of any rate or charge pursuant to the annual 
costs rate set forth in Exhibit B. Bonneville's right to suspend 
service for late payment under the Agreement shall be pursuant to 
paragraph 9(e)(1) of this Agreement, which right shall in no way be 
limited by this section.

E. Disputed Bills

    In the event of a disputed bill, full payment shall be rendered to 
Bonneville and the disputed amount noted. Disputed amounts are subject 
to the late payment provisions specified in section II(4) of the 
Billing Provisions of this Exhibit B. Bonneville shall separately 
account for the disputed amount. If it is determined that Capacity 
Owner is entitled to the disputed amount, Bonneville shall refund the 
disputed amount with interest, such interest to be determined by 
Bonneville's Financial Services Group. In the event that Bonneville and 
Capacity Owner do not resolve such dispute, Capacity Owner shall not be 
prevented by this section II(5) of the Billing Provisions of this 
Exhibit B from initiating arbitration pursuant to and to the extent 
allowed by section 15 of this Agreement.

F. Revised Bills

    If Bonneville determines that it has over- or under-charged 
Capacity Owner due to a computational error or because of an amendment 
to the Operating Plan in any given billing month, Bonneville may render 
to Capacity Owner a revised bill.
    1. If the amount of the revised bill is less than or equal to the 
amount of the original bill for such billing month, the revised bill 
shall replace the original bill issued by Bonneville. The revised bill 
shall have the same date as the original bill.
    2. If the amount of the revised bill is greater than the amount of 
the original bill for such billing month, a new bill will be issued for 
the difference between the revised bill and the original bill. The date 
of the new bill shall be its date of issuance, and Capacity Owner shall 
make payment to Bonneville as specified in the Billing Provisions of 
this Exhibit B.

C. General Transmission Rate Schedule Provisions (GTRSPs)

Table of Contents

I. Adoption of Revised Transmission Rate Schedules and General 
Transmission Rate Schedules Provision
    A. Approval of Rates
    B. General Provisions
    C. Interpretation
II. Billing Factor Definitions and Billing Adjustments
    A. Billing Factors
    B. Billing Adjustments
III. Other Definitions
    A. Agreement
    B. Eastern Intertie
    C. Electric Power
    D. Federal Columbia River Transmission System
    E. Firm Transmission Service
    F. Integrated Network
    G. Main Grid
    H. Main Grid Distance
    I. Main Grid Interconnection Terminal
    J. Main Grid Miscellaneous Facilities
    K. Main Grid Terminal
    L. Nonfirm Transmission Service
    M. Northern Intertie
    N. Point of Integration (POI)
    O. Point of Delivery (POD)
    P. Secondary System
    Q. Secondary System Distance
    R. Secondary System Interconnection Terminal
    S. Secondary System Intermediate Terminal
    T. Secondary Transformation
    U. Southern Intertie
    V. Transmission Service
IV. Billing Information
    A. Payment of Bills
V. Charges Under the Amended and Integrated Pacific Northwest 
Coordination Agreement
    A. Interchange Energy Imbalances
    B. Interchange Energy Service Charge
    C. Interchange Capacity Imbalances
    D. Transfers Due to Forced Outages
    E. Holding Interchange Energy Service Charge
    F. Stored Energy Service Charge
    G. Transfers to Avoid Spill
    H. Transmission Service Charges
    I. Special Storage Agreements

Section I. Adoption of Revised Transmission Rate Schedules and General 
Transmission Rate Schedule Provisions (GTRSPs)

A. Approval of Rates

    These rate schedules and GTRSPs shall become effective upon interim 
approval or upon final confirmation and approval by FERC. BPA will 
request FERC approval effective October 1, 1995.

B. General Provisions

    These 1995 Transmission Rate Schedules and associated GTRSPs 
supersede BPA's 1993 Transmission Rate Schedules and GTRSPs (which 
became effective October 1, 1993) but do not supersede prior rate 
schedules required by agreement to remain in force.
    Transmission service provided shall be subject to the following 
Acts, as amended: the Bonneville Project Act, the Regional Preference 
Act (Pub. L. 88-552), the Federal Columbia River Transmission System 
Act, and the Pacific Northwest Electric Power Planning and Conservation 
Act, and the Energy Policy Act of 1992, Pub. L. 102-486, 106 Stat. 2776 
(1992).
    The meaning of terms used in the transmission rate schedules shall 
be as defined in agreements or provisions which are attached to the 
Agreement or as in any of the above Acts.

C. Interpretation

    If a provision in the executed Agreement is in conflict with a 
provision contained herein, the former shall prevail.

Section II. Billing Factor Definitions and Billing Adjustments

A. Billing Factors

1. Scheduled Demand
    The largest of hourly amounts wheeled which are scheduled by the 
customer during the time period specified in the rate schedules.
2. Metered Demand
    The Metered Demand in kilowatts shall be the largest of the 60-
minute clock-hour integrated demands measured by meters installed at 
each POD during each time period specified in the applicable rate 
schedule. Such measurements shall be made as specified in the 
Agreement. BPA, in determining the Metered Demand, will exclude any 
abnormal readings due to or resulting from: (a) emergencies or 
breakdowns on, or maintenance of, the FCRTS; or (b) emergencies on the 
customer's facilities, provided that such [[Page 21166]] facilities 
have been adequately maintained and prudently operated as determined by 
BPA. If more than one class of power is delivered to any POD, the 
portion of the metered quantities assigned to any class of power shall 
be as agreed to by the parties. The amount so assigned shall constitute 
the Metered Demand for such class of power.
3. Transmission Demand
    The demand as defined in the Agreement.
4. Total Transmission Demand
    The sum of the transmission demands as defined in the Agreement.
5. Ratchet Demand
    The maximum demand established during the previous 11 billing 
months. Exception: If a Transmission Demand or Total Transmission 
Demand has been decreased pursuant to the terms of the Agreement during 
the previous 11 billing months, such decrease will be reflected in 
determining the Ratchet Demand.

B. Billing Adjustments

Average Power Factor
    The adjustment for average power factor, when specified in a 
transmission rate schedule or in the Agreement, shall be made in 
accordance with the average power factor section of the General 
Wheeling Provisions.
    To maintain acceptable operating conditions on the Federal system, 
BPA may restrict deliveries of power at any time that the average 
leading power factor or average lagging power factor for all classes of 
power delivered to such point or to such system is below 85 percent.

Section III. Other Definitions

    Definitions of the terms below shall be applied to these provisions 
and the Transmission Rate Schedules, unless otherwise defined in the 
Agreement.

A. Agreement

    An agreement between BPA and a customer to which these rate 
schedules and provisions may be applied.

B. Eastern Intertie

    The segment of the FCRTS for which the transmission facilities 
consist of the Townsend-Garrison double-circuit 500 kV transmission 
line segment including related terminals at Garrison.

C. Electric Power

    Electric peaking capacity (kW) and/or electric energy (kWh).

D. Federal Columbia River Transmission System

    The transmission facilities of the Federal Columbia River Power 
System, which include all transmission facilities owned by the 
government and operated by BPA, and other facilities over which BPA has 
obtained transmission rights.

E. Firm Transmission Service

    Transmission service which BPA provides for any non-BPA power 
except for transmission service which is scheduled as nonfirm. If the 
firm service is provided pursuant to the Agreement, the terms of the 
Agreement may further define the service.

F. Integrated Network

    The segment of the FCRTS for which the transmission facilities 
provide the bulk of transmission of electric power within the Pacific 
Northwest, excluding facilities not segmented to the network as shown 
in the Wholesale Power Rate Development Study used in BPA's rate 
development.

G. Main Grid

    As used in the FPT and IR rate schedules, that portion of the 
Integrated Network with facilities rated 230 kV and higher.

H. Main Grid Distance

    As used in the FPT rate schedules, the distance in airline miles on 
the Main Grid between the POI and the POD, multiplied by 1.15.

I. Main Grid Interconnection Terminal

    As used in the FPT rate schedules, Main Grid terminal facilities 
that interconnect the FCRTS with non-BPA facilities.

J. Main Grid Miscellaneous Facilities

    As used in the FPT rate schedules, switching, transformation, and 
other facilities of the Main Grid not included in other components.

K. Main Grid Terminal

    As used in the FPT rate schedules, the Main Grid terminal 
facilities located at the sending and/or receiving end of a line 
exclusive of the Interconnection terminals.

L. Nonfirm Transmission Service

    Interruptible transmission service which BPA may provide for non-
BPA power.

M. Northern Intertie

    The segment of the FCRTS for which the transmission facilities 
consist of two 500 kV lines between Custer Substation and the United 
States-Canadian border, one 500 kV line between Custer and Monroe 
Substations, and two 230 kV lines from Boundary Substation to the 
United States-Canadian border, and the associated substation 
facilities.

N. Point of Integration (POI)

    Connection points between the FCRTS and non-BPA facilities where 
non-Federal power is made available to BPA for wheeling.

O. Point of Delivery (POD)

    Connection points between the FCRTS and non-BPA facilities where 
non-Federal power is delivered to a customer by BPA.

P. Secondary System

    As used in the FPT and IR rate schedules, that portion of the 
Integrated Network facilities with operating voltage of 115 kV or 69 
kV.

Q. Secondary System Distance

    As used in the FPT rate schedules, the number of circuit miles of 
Secondary System transmission lines between the secondary POI and the 
Main Grid or the secondary POD, or the Main Grid and the secondary POD.

R. Secondary System Interconnection Terminal

    As used in the FPT rate schedules, the terminal facilities on the 
Secondary System that interconnect the FCRTS with non-BPA facilities.

S. Secondary System Intermediate Terminal

    As used in the FPT rate schedules, the first and final terminal 
facilities in the Secondary System transmission path exclusive of the 
Secondary System Interconnection terminals.

T. Secondary Transformation

    As used in the FPT rate schedules, transformation from Main Grid to 
Secondary System facilities.

U. Southern Intertie

    The segment of the FCRTS for which the major transmission 
facilities consist of two 500 kV AC lines from John Day Substation to 
the Oregon-California border; a portion of the 500 kV AC line from 
Buckley Substation to Summer Lake Substation; when completed, the Third 
AC facilities, which include Captain Jack Substation and the Alvey-
Meridian 500 kV AC line; one 1,000 kV DC line between the Celilo 
Substation and the Oregon-Nevada border; and associated substation 
facilities.

V. Transmission Service

    As used in the MT rate schedule, Transmission Service is as defined 
in [[Page 21167]] the Western Systems Power Pool Agreement.

Section IV. Billing Information

A. Payment of Bills

    Bills for transmission service shall be rendered monthly by BPA. 
Failure to receive a bill shall not release the customer from liability 
for payment. Bills for amounts due of $50,000 or more must be paid by 
direct wire transfer; customers who expect that their average monthly 
bill will not exceed $50,000 and who expect special difficulties in 
meeting this requirement may request, and BPA may approve, an exemption 
from this requirement. Bills for amounts due BPA under $50,000 may be 
paid by direct wire transfer or mailed to the Bonneville Power 
Administration, P.O. Box 6040, Portland, Oregon 97228-6040, or to 
another location as directed by BPA. The procedures to be followed in 
making direct wire transfers will be provided by the Office of 
Financial Management and updated as necessary.
1. Computation of Bills
    The transmission billing determinant is the electric power 
quantified by the method specified in the Agreement or Transmission 
Rate Schedule. Scheduled power or metered power will be used.
    The transmission customer shall provide necessary information to 
BPA for any computation required to determine the proper charges for 
use of the FCRTS, and shall cooperate with BPA in the exchange of 
additional information which may be reasonably useful for respective 
operations.
    Demand and energy billings for transmission service under each 
applicable rate schedule shall be rounded to whole dollar amounts, by 
eliminating any amount which is less than 50 cents and increasing any 
amounts from 50 cents through 99 cents to the next higher dollar.
2. Estimated Bills
    At its option, BPA may elect to render an estimated bill to be 
followed at a subsequent billing date by a final bill. The estimated 
bill shall have the validity of and be subject to the same payment 
provisions as a final bill.
3. Billing Month
    For charges based on scheduled quantities, the billing month is the 
calendar month. For charges based on metered quantities, the billing 
month is defined as the interval between scheduled meter-reading dates. 
The billing month will not exceed 31 days in any case. While it may be 
necessary to read meters on a day other than the scheduled meter-
reading date, for determination of billing demand, the billing month 
will cease at 2400 hours on the last scheduled meter-reading date. 
Schedules will be predetermined. The customer must give 30 days notice 
to request a change to the schedule.
4. Due Date
    Bills shall be due by close of business on the 20th day after the 
date of the bill (due date). Should the 20th day be a Saturday, Sunday, 
or holiday (as celebrated by the customer), the due date shall be the 
next following business day.
5. Late Payment
    Bills not paid in full on or before close of business on the due 
date shall be subject to a penalty charge of $25. In addition, an 
interest charge of one-twentieth percent (0.05 percent) shall be 
applied each day to the sum of the unpaid amount and the penalty 
charge. This interest charge shall be assessed on a daily basis until 
such time as the unpaid amount and penalty charge are paid in full.
    Remittances received by mail will be accepted without assessment of 
the charges referred to in the preceding paragraph provided the 
postmark indicates the payment was mailed on or before the due date. 
Whenever a power bill or a portion thereof remains unpaid subsequent to 
the due date and after giving 30 days' advance notice in writing, BPA 
may cancel the contract for service to the customer. However, such 
cancellation shall not affect the customer's liability for any charges 
accrued prior thereto under such agreement.
6. Disputed Billings
    In the event of a disputed billing, full payment shall be rendered 
to BPA and the disputed amount noted. Disputed amounts are subject to 
the late payment provisions specified above. BPA shall separately 
account for the disputed amount. If it is determined that the customer 
is entitled to the disputed amount, BPA shall refund the disputed 
amount with interest, as determined by BPA's Office of Financial 
Management.
    BPA retains the right to verify, in a manner satisfactory to the 
Administrator, all data submitted to BPA for use in the calculation of 
BPA's rates and corresponding rate adjustments. BPA also retains the 
right to deny eligibility for any BPA rate or corresponding rate 
adjustment until all submitted data have been accepted by BPA as 
complete, accurate, and appropriate for the rate or adjustment under 
consideration.
7. Revised Bills
    As necessary, BPA may render a revised bill.
    a. If the amount of the revised bill is less than or equal to the 
amount of the original bill, the revised bill shall replace all 
previous bills issued by BPA that pertain to the specified customer for 
the specified billing period and the revised bill shall have the same 
date as the replaced bill.
    b. If a revision causes an additional amount to be due BPA or the 
specified customer beyond the amount of the original bill, a revised 
bill will be issued for the difference and the date of the revised bill 
shall be its date of issue.

V. 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.
    All terms contained herein have the meaning accorded them in the 
Amended and Integrated Pacific Northwest Coordination Agreement. These 
rates are to be effective on the date on which rates are effective 
under the Amended and Integrated Pacific Northwest Coordination 
Agreement, as provided in such Agreement. They will remain in effect 
until revised rates are approved.

A. Interchange Energy Imbalances

                            1. Initial Deliveries of Interchange Energy
[[Page 21168]]

[GRAPHIC][TIFF OMITTED]TN01MY95.083


Heat rate = 10,000 BTU/kWh
Fuel price = Average mainline interruptible or spot market natural gas 
price at Sumas, Washington, in $/MMBTU (dollars per million BTUs), for 
the twelve months ending the immediately preceding June 30, as 
published in Inside FERC, or, in the event that Inside FERC is no 
longer published, a similar replacement publication.
Adder = 4.75 mills/kWh, adjusted each August 1 beginning August 1, 
1997, by the change in the Consumer Price Index (for all urban 
consumers as published by the Bureau of Labor Statistics) for Portland, 
Oregon, for the twelve-month period ending the immediately preceding 
June 30.
2. Return of Interchange Energy
    The Energy Charge for Return of Interchange Energy shall be the 
charge in effect for initial deliveries of Interchange Energy at the 
time the energy being delivered as Return of Interchange Energy was 
delivered as an initial delivery of Interchange Energy.

B. Interchange Energy Service Charge

    1. No charge for energy returned between 7:00 a.m. and 10:00 
p.m., Monday through Saturday.
    2. 2.50 mills per kilowatthour of energy returned at other 
hours, unless such energy was supplied during such other hours, or 
its return during such other hours was requested, in either of which 
events there shall be no charge.

C. Interchange Capacity Imbalances

    $2.00 per kilowatt week of demand.

D. Transfers Due to Forced Outage

1. Transfer Due to Loss of Thermal Capability
    $2.00 per kilowatt week of demand plus the greater of (a) the 
charge for Interchange Energy Imbalances and (b) the incremental costs 
of operating the resource used to supply the requested energy plus an 
adder of 4.00 mills per kilowatthour. The adder shall be adjusted each 
August 1 beginning August 1, 1997 by the change in the Consumer Price 
Index (for all urban consumers as published by the Bureau of Labor 
Statistics) for Portland, Oregon, for the twelve-month period ending 
the immediately preceding June 30.
2. Transfer of Emergency Capacity
    $2.00 per kilowatt week of demand plus the greater of (a) the 
charge for Interchange Energy Imbalances and (b) the incremental costs 
of operating the resource used to supply the requested energy. In the 
event that BPA requires the receiving party to return the energy 
associated with the transfer of emergency capacity, only the demand 
charge shall apply.

E. Holding Interchange Energy Service Charge

1. Basic Charge
    2.00 mills per kilowatthour of Holding Interchange Energy on 
delivery to BPA and 1.50 mills per kilowatthour of Holding Interchange 
Energy on return from BPA (3.50 mills per kilowatthour total). A loss 
of Holding Interchange Energy because of spill will result in a refund 
of 2.00 mills per kilowatthour of Holding Interchange Energy that is 
converted to Stored Energy and spilled.
2. Reshaping Charge
    2.50 mills per kilowatthour of energy. This charge shall apply, in 
each Light Load Hour during which the energy delivered or returned is 
greater than the average hourly amount of energy delivered or returned 
that day, to the amount of energy delivered or returned during such 
hour that exceeds the daily hourly average. This charge applies in 
addition to the basic charge.
F. Stored Energy Service Charge
    For the purposes of this rate, light load hours and heavy load 
hours shall not include any hours designated by the reservoir party as 
peak load hours.
1. Charges Paid on Delivery of Energy to a Reservoir Party
    a. 2.00 mills per kilowatthour of energy delivered to BPA on Light 
Load Hours.
    b. 1.00 mill per kilowatthour of energy delivered to BPA on Heavy 
Load Hours.
    c. No charge for energy delivered to BPA on Peak Load Hours.
2. Charges Paid on Return of Energy Stored Less Than Two Weeks
    a. 1.00 mill per kilowatthour of energy returned from BPA on Light 
Load Hours.
    b. 3.50 mills per kilowatthour for energy returned from BPA on 
Heavy Load Hours.
    c. 5.00 mills per kilowatthour for energy returned from BPA on Peak 
Load Hours.
3. Charges Paid on Return of Energy Stored for Two Weeks or More
    a. No charge for energy returned from BPA on Light Load Hours.
    b. 2.50 mills per kilowatthour for energy returned from BPA on 
Heavy Load Hours.
    c. 4.00 mills per kilowatthour for energy returned from BPA on Peak 
Load Hours.
4. Charges Paid on Return of Energy in Cases of Imminent Spill
    a. No charge for energy returned from BPA on Light Load Hours.
    b. 2.50 mills per kilowatthour for energy returned from BPA on 
Heavy Load Hours.
    c. 2.50 mills per kilowatthour for energy returned from BPA on Peak 
Load Hours.
5. Refund of Storage Charges in Cases of Spill
    In the event that stored energy is not returned to a party because 
of spill on BPA's system, or in the event that BPA transfers the stored 
energy to another Reservoir Party to avoid spill and the transferred 
energy is later spilled, BPA will refund the charges paid under section 
F.1. in an amount equal to the charges paid under such section, divided 
by the kilowatthours of energy delivered to BPA, multiplied by the 
kilowatthours of stored energy that is spilled.

G. Transfers To Avoid Spill

    1. No charge for stored energy transferred by a Reservoir Party to 
BPA in order to avoid spill.
    2. The applicable Stored Energy Service charge shall apply in the 
event that BPA accepts the transfer of stored energy to avoid spill and 
then returns the stored energy to the original delivering party.

H. Transmission Service Charges

    In any energy or capacity transaction that utilizes BPA 
transmission facilities where BPA acts solely as a transferor the 
following charges shall apply to both delivery and return of the 
energy, if applicable:
    1. 1.60 mills per kilowatthour of Interchange Energy or Generation 
Impact Replacement Energy paid by the receiving party.
    2. 1.75 mills per kilowatthour of Holding Interchange and Storage 
Energy paid by the party requesting the return.
    3. No charge for In Lieu Energy, except when the supplying or 
receiving [[Page 21169]] party requires BPA, under the terms of the 
PNCA, to provide transmission, in which case the charge shall be 2.00 
mills per kilowatthour of In Lieu Energy paid by the party requiring 
BPA to provide such transmission.
    4. 2.00 mills per kilowatthour of Provisional Energy paid by the 
Reservoir Party.
    5. 2.00 mills per kilowatthour of energy associated with Transfers 
Due to Cross-Border Flow Deviations paid by the party receiving the 
transfer.
    6. 2.00 mills per kilowatthour of energy associated with 
Interchange Capacity and FOR Capacity paid by the party requesting the 
delivery.

I. Special Storage Arrangements

1. Suggested Rate
    a. 1.00 mills per kilowatthour for energy returned during Light 
Load Hours.
    b. 3.00 mills per kilowatthour for energy returned during other 
hours.
2. Flexible Rate
    The charges for special storage arrangements may be specified at a 
higher rate as mutually agreed between the party requesting the special 
storage arrangement and BPA.

    Issued in Portland, Oregon, on April 17, 1995.
Randall W. Hardy,
Administrator and Chief Executive Officer.
[FR Doc. 95-10065 Filed 4-28-95; 8:45 am]
BILLING CODE 6450-01-P