[Federal Register Volume 60, Number 136 (Monday, July 17, 1995)]
[Notices]
[Pages 36464-36522]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 95-17374]




[[Page 36463]]

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Part II





Department of Energy





_______________________________________________________________________



Bonneville Power Administration



_______________________________________________________________________



1996 Proposed Wholesale Power Rate and Transmission Rate Adjustment, 
Public Hearing, and Opportunities for Public Review and Comment; Notice

  Federal Register / Vol. 60, No. 136 / Monday, July 17, 1995 / Notices 
  

[[Page 36464]]


DEPARTMENT OF ENERGY

Bonneville Power Administration


1996 Proposed Wholesale Power Rate and Transmission Rate 
Adjustment, Public Hearing, and Opportunities for Public Review and 
Comment

AGENCY: Bonneville Power Administration (BPA), DOE.

ACTION: Notice of proposed wholesale power rates and transmission 
rates.

-----------------------------------------------------------------------

SUMMARY: BPA File No: WP-96 and TR-96. BPA requests that all comments 
and documents intended to become part of the Official Record in this 
process contain the file number designation WP-96/TR-96.
    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.
    By this notice, BPA announces its proposed 1996 wholesale power 
rates and transmission rates to be effective on October 1, 1996, 
including new 2- and 5-year rates. BPA also will publish a separate 
notice in the Federal Register of its new transmission services terms 
and conditions.

DATES: Written comments by participants relating to WP-96/TR-96 must be 
received by October 2, 1995, to be considered in the Draft Record of 
Decision (ROD).

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

FOR FURTHER INFORMATION CONTACT: Mr. Michael Hansen, Public Involvement 
and Information Specialist, at the address listed 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, S-
700; P.O. 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 
Broadway; Vancouver, WA 98660 (360-418-8600).
Ms. Marg Nelson; Manager, NW Sales and Customer Service District; 1601 
5th Avenue, Suite 1000; Seattle, WA 98101-1670 (206-216-4272).

    Responsible Official: Mr. Geoff Moorman, Manager for Pricing, 
Marginal Cost and Ratemaking, is the official responsible for the 
development of BPA's rates.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Introduction and Procedural Background
II. Purpose and Scope of Hearing
III. Public Participation
IV. Major Studies
V. Wholesale Power Rate Schedules and Transmission Rate Schedules
    A. Introduction
    B. Summary of Rate Schedules
    C. Wholesale Power Rate Schedules
    D. Transmission Rate Schedules
    E. General Rate Schedule Provisions (GRSPs)
I. Introduction and Procedural Background

    Section 7(i) of the Northwest Power Act, 16 U.S.C. 839e(i), 
requires that BPA's wholesale power and transmission rates be 
established according to certain procedures. These procedures include, 
among other things, issuance of a Federal Register notice announcing 
the proposed rates; one or more hearings; the opportunity to submit 
written views, supporting information, questions, and arguments; and a 
decision by the Administrator based on the record. As noted above, this 
rate proceeding to adjust wholesale power rates has been combined with 
the proceeding for BPA's proposal to adjust transmission rates. This 
proceeding is governed by BPA's rule for general rate proceedings, 
Sec. 1010.9 of BPA's Procedures Governing Bonneville Power 
Administration Rate Hearings, 51 FR 7611 (1986) (hereinafter 
Procedures). These Procedures implement the statutory section 7(i) 
requirements. Section 1010.7 of the Procedures prohibits ex parte 
communications.
    On December 28, 1994, 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).
    BPA's rate proceedings for 1995 and 1996, and the terms and 
conditions proceeding, began with a Prehearing Conference on February 
13, 1995. The proceedings, originally in two dockets, WP-95/TR-95 
(wholesale power and transmission rates) and TC-95 (transmission 
services terms and conditions), subsequently were separated into three 
different dockets as described below.
    At the direction of the Hearing Officers at the February 13, 1995, 
prehearing conference, an additional prehearing conference was 
scheduled for March 15, 1995, and additional time was allowed for 
petitions to intervene. A Federal Register Notice for Additional 
Prehearing/Settlement Conference for March 15, 1995, 60 FR 11962 
(1995), was published on March 3, 1995.
    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 
1995.
    At the March 15, 1995, prehearing conference, the parties notified 
the hearing officers that they had been involved in negotiations for a 
settlement of issues that might affect the hearing schedule and 
requested additional time to complete the negotiations. The Hearing 
Officers acted on petitions to intervene received to that date and set 
a scheduling conference for March 22, 1995.
    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 conduct a separate subsequent process to 
establish a 2-year and a 5-year rate proposal, and a proposal for 
transmission services terms and conditions. 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. 

[[Page 36465]]

    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 
Proceeding; and (2) ruled on other procedural matters concerning 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., P.O. Box 
12999, Portland, Oregon 97212, (503) 230-4201.
    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 
below.
    As a result of 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:
    A. The 1995 Wholesale Power and Transmission Rate Proceeding is 
designated WP-95/TR-95, and is a 90-day expedited rate proceeding 
conducted pursuant to Section 1010.10 of the Procedures. The proceeding 
began on May 1, 1995, when BPA issued its initial rate proposal and 
published it in the Federal Register, 60 FR 21132 (1995), and is 
scheduled to conclude on July 31, 1995, when BPA releases its Record of 
Decision (ROD). The proceeding proposes to extend current rates, 
including an extended VI rate, with a 4 percent surcharge, and 
establish the Southern Intertie Annual Cost rate and the Pacific 
Northwest Coordination Agreement (PNCA) rate.
    B. The 1996 Wholesale Power Proceeding is designated WP-96 and the 
Transmission Rate Proceeding is designated TR-96, and both will be 
general rate proceedings conducted pursuant to Section 1010.9 of the 
Procedures. The March 22 Order established a hearing 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 schedules adopted by the Hearing Officers for WP/
TR-96 and TC-96 afford the parties a hearing process that encompasses a 
period of 8 months for establishment of BPA's new rate designs 
including new 2- and 5-year rates, and for establishment of 
transmission services terms and conditions.
    C. 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. The terms and 
conditions proceeding will be on the same schedule as the 1996 
Wholesale Power and Transmission Rates proceedings.
    BPA will file its 1996 initial rate proposal on July 10, 1995, and 
will publish its final ROD on April 30, 1996. The schedule established 
for WP/TR-96 provides an opportunity for interested persons to review 
BPA's proposed rates, to participate in the rate hearing, and to submit 
oral and written comments. Consideration of comments may result in a 
final rate proposal differing from the rates proposed in this notice.

II. Purpose and Scope of Hearing

    BPA is planning significant changes in the design of its power 
rates. BPA is proposing to offer a 2-year and a 5-year power rate for 
requirements service. To address the increasingly competitive market 
for power and energy services, BPA is proposing to offer a menu of 
unbundled (or separately priced) products in the 1996 rate case. BPA 
expects that most of the products offered will be available both under 
current power sales contracts and under new power sales contracts. BPA 
expects to offer additional unbundled products in future rate cases and 
to price these products to meet market conditions and BPA's cost 
recovery obligations. In some cases, BPA expects the market will 
require flexible pricing. BPA is planning to ``unbundle'' what it 
offers so customers can choose among products and services based on 
what they need to meet their loads and support their own resources, if 
any. The services and products that customers may select to complement 
either firm requirements service provided by BPA, or power acquired 
from other sources, will be priced separately.
    BPA has assessed the potential environmental effects of its rate 
proposal, as required by the National Environmental Policy Act (NEPA), 
as part of the Business Plan Environmental Impact Statement (EIS). The 
Draft Business Plan EIS was circulated for review and comment in July 
1994. As a result of comments received, BPA prepared a Supplemental 
Draft Business Plan EIS, which was circulated for review and comment in 
February 1995. The Supplemental Draft Business Plan EIS evaluates 
several business structure alternatives. The analysis includes an 
evaluation of the environmental impacts of a range of rate design 
alternatives for BPA's power and transmission services, and an analysis 
of the environmental impacts of the rate levels resulting from the 
rates for such services under the business structure alternatives. 
BPA's initial rate proposal falls within the range of alternatives 
evaluated in the Final Business Plan EIS. Comments on the Business Plan 
EIS were received outside the formal rate hearing process, but will be 
included in the rate case record and considered by the Administrator in 
making a final decision establishing BPA's 1996 rates. The Business 
Plan EIS was completed in June 1995, and the Business Plan elaborating 
BPA's strategic action plans, will be released in the summer of 1995.
    BPA's spending levels are developed as a part of its Business Plan, 
which includes a public comment process. They also are determined as a 
part of the Federal budget process. Consistent with the Draft Business 
Plan, the Administrator formally announced spending levels for Fiscal 
Years (FYs) 1996-2001 to the public on January 12, 1995. Since that 
time, BPA made the decision to reduce those spending levels by an 
average of $250 million per year for FYs 1996-2000. BPA currently is 
engaged in a budget process which will culminate in decisions on where 
these reductions will occur. BPA will continue to refine its strategic 
business objectives, goals, and spending levels, and inform the public 
accordingly, as part of its Business Plan development process. 
Therefore, except for the limited exceptions hereafter noted, spending 
level decisions will not be addressed in this rate case.
    Pursuant to Section 1010.3(f) of the Procedures, the Administrator 
directs the Hearing Officer to exclude from the record any material 
attempted to be submitted or arguments attempted to be made in the 
hearing which in any way seek to visit the appropriateness or 
reasonableness of BPA's decisions on spending levels, as included in 
BPA's cost evaluation period of FY 1996 through FY 2001 and its test 
period revenue requirement for FYs 1997 through 2001. If, and to the 
extent, any re-examination of spending levels is necessary, that re-
examination will occur outside of the rate case.
    BPA's Revenue Requirement Study will incorporate spending levels 
and reflect BPA's risk mitigation, capital funding, and other financial 
goals in the rates. Excepted from this direction on account of their 
variable nature, dependency on BPA's rate case models, or timing, are: 
(1) Forecasts of residential exchange benefits; (2) forecasts of short-
term purchase power 

[[Page 36466]]
costs; (3) provision in BPA's revenue requirement for cash working 
capital or cash lag needs; (4) repayment matters such as interest rate 
forecasts, scheduled amortization, depreciation, replacements, and 
interest expense; and (5) updates to forecasts by BPA for which no 
other review forum has been provided.

Comparable Transmission Access

    In the Energy Policy Act of 1992, Congress approved amendments to 
the Federal Power Act that allow FERC to order access to transmitting 
utilities', including BPA's, systems. As a result, FERC has proposed 
standards for providing comparable transmission access, including 
developing guidelines for pricing such access. ``Comparable'' refers to 
FERC's undue discrimination analysis which is now focused on a 
determination of whether the transmitting utility is offering third 
parties access on the same or comparable terms and conditions, and at 
the same or comparable rates that the utility uses for itself. On March 
29, 1995, FERC issued a Notice of Proposed Rulemaking, ``Promoting 
Wholesale Competition Through Open Access Non-discrimination 
Transmission Services by Public Utilities,'' and Supplemental Notice of 
Proposed Rulemaking, ``Recovery of Stranded Costs by Public Utilities 
and Transmitting Utilities,'' (NOPR). 70 FERC 61,351 (1995). In that 
NOPR, FERC proposed to require all public utilities subject to FERC 
jurisdiction to file generic open access tariffs and to take 
transmission service, including ancillary services, for their own new 
wholesale electric sales and purchases under the open access tariffs. 
The NOPR also includes a supplemental proposed rule to permit the 
recovery of stranded costs associated with requiring open access 
tariffs.
    In a process concurrent with the 1996 rate case, BPA is proposing 
terms and conditions of general applicability for Network Integration 
and Point-to-Point transmission service that are modeled on the tariffs 
included in the NOPR. (For further information about the terms and 
conditions process, please contact Mr. Dennis Metcalf, Transmission 
Rates Manager, (503) 230-3410 or Mr. Michael Hansen, Public Involvement 
and Information Specialist, (503) 230-4328.) In conjunction with the 
proposed transmission services, this transmission rate proposal 
includes two new rate schedules (the Network Integration Transmission 
and Point-to-Point Transmission rates) that correspond to the new 
tariffs. In addition to being available to wheeling customers, BPA is 
proposing that its full and partial requirements customers will use 
these new comparable transmission services and associated rates for the 
transmission portion of their wholesale power purchases from BPA. BPA's 
proposed Energy Transmission rate schedule also will be used to price 
short-term firm and nonfirm service under the Point-to-Point 
Transmission Service Tariff. To the extent practicable, BPA is 
proposing a transmission construct under which the transmission cost 
associated with purchasing power from BPA is the same as that 
associated with purchasing non-Federal power. To this end, the 
segmentation of BPA's transmission system has been revised as described 
in Section IV.C, below. In response to the NOPR, BPA also will offer 
the Ancillary Products and Services and associated rates necessary for 
the transmission of power from resources to load on the FCRTS.

Stranded Investment, Cost Recovery Options, and Process for Regional 
Discussion

    If BPA is to succeed in its power marketing objectives, its power 
must be marketable in both the short- and the long-run. While many 
factors influence the marketability of power, the single most important 
factor is price: BPA's power will not be marketable if it is priced 
above market. BPA has succeeded in marketing its power over the past 50 
years because, while priced at cost, its power was priced at or below 
market. In fact, the impetus for the Northwest Power Act was the threat 
of an impending regional ``civil war'' of litigation among contenders 
for access to BPA's low-cost Federal hydropower. However, while BPA 
enjoyed a 400 percent price advantage in the early 1980's when the 
Northwest Power Act was passed, that price advantage now has largely 
disappeared.
    As a consequence of these market considerations, BPA has cut its 
costs dramatically and is proposing rates in its 1996 rate case that 
are calculated to meet market demand, while comporting with statutory 
ratemaking requirements. At their most rudimentary level, rates are a 
function of costs divided by sales. Hence, assuming costs do not 
change, greater sales result in lower rates, and less sales mean higher 
rates. However, significantly higher rates also result in less sales. 
The sales that BPA has forecasted for purposes of setting its proposed 
1996 rates is based on the assumption that BPA's power rates are 
competitive and will thus achieve BPA's marketing objective to retain 
sales and thereby stabilize rates and cost recovery.
    The power rates that BPA is proposing in its 1996 rate case may be 
as high as they can be before BPA suffers significant sales loss. A 
critical issue in the 1996 rate case will be whether BPA's power rates 
for each customer class are at, above, or below that sustainable 
revenue point. Misjudgment on that issue could result in significant 
sales loss by BPA. BPA currently believes its proposed rates are set at 
a level that will indeed meet market demand.
    If, however, customers reduce the amount of purchases they make 
from BPA significantly below the sales that BPA projected it would make 
when it set its rates, BPA runs a serious risk of revenue 
underrecovery. In previous proceedings establishing rates, BPA has 
factored risk of sales loss into its establishment of rates. 
Consequently, for the last 6 years BPA's power rates have included an 
Interim Rate Adjustment Clause or Cost Recovery Adjustment Clause (IRA) 
that would come into play and increase BPA's rates if they were not 
recovering BPA's costs. There were two primary reasons BPA's rates 
included these clauses. First, BPA's rate directives require that the 
Administrator establish rates based on BPA's total system costs and to 
assure repayment of the U.S. Treasury over a reasonable number of 
years. Second, market conditions enabled BPA to include these clauses 
in its power rates, i.e., BPA's power rates were still viable after 
consideration of the clauses.
    In its 1996 rate proposal, BPA has set its net revenues for risk to 
factor in the possibility of load loss, and it has not included an IRA 
or similar clause in its power rates. The reason is that the wholesale 
power market currently demands certainty and stability in price. Power 
prices without those features, i.e., prices that are subject to change, 
will not be viable in the current power market.
    If BPA experiences, or is faced with the possibility of sales loss, 
but cannot increase its rates directly or conditionally (such as 
through an IRA) to recover its costs, the issue arises of what actions 
BPA should take to prudently address the cost recovery problem. From a 
rates perspective, BPA has an obligation to establish its rates--power 
and transmission rates combined--to assure cost recovery, among other 
objectives. As discussed below, that would suggest the alternative of 
looking to transmission rates to assure cost recovery. From a broader 
perspective, the Northwest Power Act charges the Administrator with the 
responsibility of implementing the Act in a sound and business-like 

[[Page 36467]]
manner. That would suggest consideration of not just rate alternatives, 
but other alternatives as well, such as alternatives that might 
moderate sales loss in an amount that would not be significant to the 
degree of resulting in a BPA cost underrecovery.
    BPA does not have a specific proposal concerning this issue to make 
at this time for purposes of the 1996 wholesale power and transmission 
rates proceedings. This issue is of such critical importance to BPA's 
cost recovery, its various statutory missions, its business 
relationship with its customers, and its relationship with non-
customers such as fish and wildlife interests, that BPA believes it 
would be intolerable if, without the benefit of advance regional 
discussion, it were to make a formal rate case proposal and then limit 
dialogue on the issue by taking comment only through the formal process 
of the rate case. If the appropriate solution to the problem turns out 
to be a rates solution, prudent business judgment dictates that BPA 
first should have engaged its customers and interested third parties in 
a consensus-seeking dialogue on the issue. The dialogue should be 
sufficiently long to consider and evaluate parties' opinions with a 
view to forging consensus, and short enough to integrate the results of 
the discussions in the Administrator's final establishment of rates at 
the conclusion of this rate case, if that is necessary.
    Consequently, BPA hereby advises interested parties that it is 
discussing this cost recovery issue with its customers and interested 
third parties throughout the region. Initial discussions already have 
occurred in the context of negotiations over new power sales contracts. 
Parties wishing to be advised of future public discussions should 
contact BPA Corporate Communications at the address listed in Section I 
of this notice. BPA anticipates that discussions on rate options will 
conclude by the end of July or early August 1995. In the event the 
discussions result in a rate proposal by BPA, concluding discussions by 
the beginning of August should enable BPA to prepare and publish its 
rate proposal by October of 1995. The ensuing section 7(i) process 
would be timed to conclude so that the outcome could be integrated into 
the rates finally established at the conclusion of BPA's 1996 wholesale 
power and transmission rate proceedings. Consequently, pending 
resolution of this cost recovery issue, all transmission and wholesale 
power rates proposed at this time should be considered subject to a 
possible cost recovery adjustment.
    Apart from the possibility of some sort of a negotiated phased load 
loss or other contractual solution that avoids the cost recovery 
problem, BPA currently is considering two rate options to deal with the 
cost recovery issue. Each option is described below. The descriptions 
are provided not as a BPA proposal, but rather to enhance understanding 
of the issues and the expected discussion of them.
    In the first rate option, BPA would designate a portion of its 
proposed power rates as a charge to mitigate the revenue exposure BPA 
faces from potential loss of sales to alternative suppliers. All 
customers would pay that amount whether they continued to purchase 
power from BPA or not. The charge would be collected from utility 
customers that leave BPA in whole or in part, by terminating or by 
reducing their load on BPA through Section 12 of the utility power 
sales contract, and from Direct Service Industry (DSI) customers that 
reduce or eliminate load on BPA for any reason under the DSI contracts. 
For example, the amount could be 2 mills of a proposed 24 mill power 
rate--the assumption being that, if the customer purchasing at 24 mills 
departs, BPA may only recover 22 mills, leaving 2 mills ``stranded.'' 
This stranded cost component would be applied to the rates of all power 
customers, similar to a customer charge. If the customer decides to 
depart, then the customer may avoid the 22 mill power rate but would 
continue to pay the 2 mill customer charge on the transmission 
component of the departing customer's power rates (if the customer 
continues to purchase some part of its requirements from BPA) and 
wheeling rates. BPA' DSI customers may be anticipated to argue that 
this option runs counter to their contractual rights to take load off 
BPA on 1 year's notice if they pay BPA ``unrecoverable costs'' as 
defined through their contractual relationship with BPA.
    The second rate option (the cost recovery surcharge option) takes a 
different approach. This option does not target recovery only from 
customers that terminate their contracts or reduce their load, but 
rather would directly or conditionally impose a ``cost recovery'' 
surcharge on the transmission or wheeling rates of all existing and 
former power customers regardless of their then-current purchasing 
status. This approach is premised on the fact that BPA is obligated to 
recover all costs, not just those that are ``stranded'' by departing 
customers. The basis for the transmission surcharge in this option is 
that it is designed to recover costs that otherwise cannot be recovered 
through power rates, from all customers that have benefited from the 
power system, consistent with BPA's statutory obligation.
    The cost recovery surcharge would recover the amount of costs that, 
while otherwise properly allocable to power rates, cannot be recovered 
in a timely fashion through power rates. The surcharge would be 
developed in a manner that is equitable in relation to past power usage 
by BPA's requirements power customers in the Pacific Northwest, 
including residential exchange power customers. Such equitability could 
be, but would not necessarily be, achieved as follows: A first step 
would be to determine the average annual amount of Federal power 
purchased by each requirements power customer of BPA during the period 
1980 to 1994 or some other relevant period. All customers' annual 
average purchases then would be summed, and each customer's percentage 
share of the total would be determined. Each individual customer's 
percentage then would be multiplied by the total amount of the cost 
recovery surcharge amount (an amount that would vary with BPA load 
loss) to determine the customer's surcharge recovery responsibility. 
The adder to transmission rates could be designed to assure that each 
customer directly or indirectly pays the amount of its surcharge 
responsibility.
    Under both options, the payment could be indirect where the 
customer is served only by another power supplier that uses the FCRTS 
for any purpose. In that case, the power supplier would be assessed the 
surcharge or customer charge by BPA, with the expectation that the 
power supplier would recover the cost from the former BPA power 
customer. Power suppliers falling into that category are hereby put on 
notice of the possibility that BPA may levy such a charge. This notice 
is provided in the event they wish to structure pricing arrangement 
with the customer that fully recovers, or pass through, BPA's 
transmission charge.
III. Public Participation

    The procedural history of this rate proceeding is described in 
Section I, above. Petitions to intervene as parties have been received 
and acted upon by the Hearing Officers.
    BPA continues to conduct workshops on subjects relevant to its 
ratemaking. The purpose of the workshops is to identify, simplify, and 
reduce the number of issues that might become part of the 1996 rate 
case, and to reduce the amount of discovery normally required during 
the formal rate proceedings. 

[[Page 36468]]
Opportunity is provided for workshop participants to address the 
impacts of BPA's proposed 5-year rate, transmission issues, risk 
mitigation, and rate design issues. The workshops provide opportunity 
for informal public comment on issues prior to the formal hearing 
process.
    BPA's procedures allow submission of comments, views, opinions, and 
information from ``participants,'' who are defined in the Procedures as 
any person who may express views, but who does not petition 
successfully to intervene as a party. Participants' written comments 
will be made part of the official record of the case and considered by 
the Administrator. The participant category gives the public the 
opportunity to participate and have its views considered without 
assuming the obligations incumbent upon ``parties.'' Participants are 
not entitled to participate in the prehearing conference, cross-examine 
parties' witnesses, seek discovery, or serve or be served with 
documents, and are not subject to the same procedural requirements as 
parties.
    Written comments by participants will be included in the Draft ROD 
if they are received by October 2, 1995. This date follows the 
anticipated submission of BPA's and all other parties' direct cases. 
Written views, supporting information, questions, and arguments should 
be submitted to BPA's Manager of Corporate Communications at the 
address listed in Addresses Section of this notice. In addition, BPA 
will hold several public field hearings in the Pacific Northwest 
Region.
    Public field hearings are an opportunity for participants to have 
their views included in the official record. Participants may appear at 
the field hearings and present oral testimony. Written transcripts will 
be made at all of the field hearings. The transcripts of these hearings 
will be part of the record upon which the Administrator makes final 
rate decisions. Following are the tentative dates and locations for the 
field hearings. All of the field hearings are scheduled to begin at 7 
p.m. Registration begins at 6:30 p.m. Confirmation of these hearing 
dates and times will be made through mailings and public advertising or 
by calling BPA Corporate Communications at the telephone number listed 
in Section I above.

September 19, 1995
    Best Western Burley Inn, 800 N. Overland Avenue, Burley, Idaho 
83318
September 20, 1995
    Cavanaugh's, Ballroom B, 200 North Main, Kalispell, Montana 59901
September 21, 1995
    Red Lion GateWay, 3280 Gateway Drive, Springfield, Oregon 97477
September 26, 1995
    Howard Johnson Plaza Hotel, Whidbey-Camano Room, 3105 Pine, 
Everett, Washington
September 27, 1995
    Cavanaugh's, East 110 Fourth Avenue, Spokane, Washington 99202
September 28, 1995
    Pasco Red Lion, Design Room, 2525 North 20th, Pasco, Washington 
99301

    The record will include, among other things, the transcripts of any 
hearings, any written material submitted by the parties and 
participants, documents developed by BPA staff, BPA's environmental 
analysis and comments accepted thereon, and other material accepted 
into the record by the Hearing Officer. The Hearing Officer then will 
review the record, will supplement it if necessary, and will certify 
the record to the Administrator for a decision.
    The Administrator will develop final rates based on the entire 
record, including the record certified by the Hearing Officer, comments 
received from participants, other material and information submitted to 
or developed by the Administrator, and any other comments received 
during the rate development process. The basis for the final rates 
first will be expressed in the Administrator's Draft ROD. Parties will 
have an opportunity to comment on the Draft ROD as provided in BPA's 
hearing procedures. The Administrator will serve copies of the Final 
ROD on all parties and will file the final wholesale power and 
transmission rates together with the record with the Federal Energy 
Regulatory Commission (FERC) for confirmation and approval. 
Consideration of comments and more current data may result in the final 
rates differing from the rates proposed in this Notice.
    Because of the complexity of the issues in this rate case, in part 
occasioned by continuing contract negotiations between BPA and its 
customers, as well as BPA's ``reinvention'' and Competitiveness 
Project, BPA anticipates that it will need to meet with customers and 
other interested third parties during the rate case on a very frequent, 
and possibly extended, basis. To comport with the rate case procedural 
rule prohibiting ex parte communications, BPA will provide necessary 
notice of meetings involving rate case issues for participation by all 
rate case parties. Parties should be aware, however, that such meetings 
may be held on very short notice, and they should be prepared to devote 
the necessary resources to participate fully in every aspect of the 
rate proceeding.

IV. Major Studies

    The studies that have been prepared to support the 1996 initial 
proposal will be served on all parties of record and will be available 
for examination on or about July 10, 1995, at BPA's Public Information 
Center, BPA Headquarters Building, 1st Floor, 905 NE. 11th, Portland, 
Oregon. The studies and documents are:

A. Loads and Resources Study and Documentation
B. Revenue Requirement Study and Documentation
C. Segmentation Study
D. Marginal Cost Analysis Study and Documentation
E. Wholesale Power Rate Development Study and Documentation
F. Section 7(b)(2) Rate Test Study and Documentation
G. Transmission Rate Design Study
H. Wholesale Power and Transmission Rate Schedules

    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 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 

[[Page 36469]]
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.
    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 ``flow augmentation'' for fish mitigation. For this proposal, a 50-
year hydro study was completed, which includes assumptions regarding 
the flow augmentation. The hydro study starts in August 1995. The 50-
year study determines expected nonfirm energy availability for the 
region based on 50 years of streamflow data.

B. Revenue Requirement Study

    The BPA 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. Separate generation and transmission 
revenue requirements are developed in the Revenue Requirement Study. In 
compliance with a FERC order dated January 27, 1984, 26 FERC para. 
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. 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 1996 Initial Rate Proposal is 
based on cost and revenue estimates for FYs 1997-2001. The cost 
estimates include an undistributed reduction averaging $250 million for 
each year. This reflects BPA's decision to reduce revenue requirements 
to enable it to set rates at a level which recovers its costs but also 
meets 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, as well as to 
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. The risk analysis 
measures the financial risks surrounding the revenue and expense 
forecasts used to set rates. It also is used to determine the amount of 
cash required for risk that is needed to meet the target Treasury 
payment probability, and is used to determine the Treasury payment 
probability resulting from inclusion of cash for risk in the revenue 
requirement.

C. Segmentation Study

    BPA operates and maintains the FCRTS to provide transmission 
services throughout the region. Because most services do not require 
the use of the entire system, BPA has historically segmented the FCRTS 
into nine segments, each providing a distinct type of service. The nine 
segments are: integrated network; Fringe; Pacific Northwest-Pacific 
Southwest (Southern) Intertie; Northern Intertie; Eastern Intertie; 
generation integration; and delivery segments for public agency, DSI, 
and IOU customers. Although BPA is proposing different segmentation in 
its initial rate proposal, the Segmentation Study for the initial rate 
proposal will maintain the historic segments. Re-segmentation of the 
revenue requirement for the initial proposal will be done as part of 
the Transmission Rate Design Study.
    The Segmentation Study categorizes the facilities of the FCRTS 
according to the types of services BPA provides on such facilities. 
This provides the basis for segmenting the projected transmission 
revenue requirements used in BPA's rate proposals. The results of the 
Study include the historical investment and the average of the last 3 
years' operations and maintenance expenses. In addition, the facilities 
of the integrated network are divided among distinct services for use 
in developing the Formula Power Transmission rate. This division of the 
FCRTS into segments provides the basis for the equitable allocation of 
transmission costs between Federal and non-Federal customers based on 
their usage of the segments.
    In this proceeding, BPA proposes to reclassify the BPA transmission 
facilities formerly classified as fringe to the network segment to 
reflect the realignment of the transmission business. In addition, the 
former IOU Delivery segment is now included in the network segment. The 
definition of Delivery facilities also has been revised. BPA plans to 
reflect these changes to segmentation in the Segmentation Study in the 
supplemental rate proposal.

D. Marginal Cost Analysis

    The Marginal Cost Analysis (MCA) estimates the marginal cost that 
BPA incurs to supply peak demand on heavy load hours, and energy on a 
seasonal, daily, and hourly basis to meet customers' loads. The 
conditions and terms under which BPA supplies energy necessitate that 
BPA take actions that impose a cost. The MCA measures the costs that 
BPA incurs in taking actions to provide energy under different terms. 

[[Page 36470]]
BPA proposes to measure the marginal costs of actions it takes to: (1) 
Guarantee availability of energy; (2) guarantee a maximum rate of 
delivery of energy (demand); (3) provide energy at guaranteed prices; 
and (4) actually deliver energy. The results of the MCA are used to 
develop wholesale power rates that promote efficient development and 
operation of generation and conservation resources.
    BPA proposes to measure marginal costs based on the conditions BPA 
faces in the interconnected West Coast wholesale power market. 
Estimated marginal costs are based on the results from a model that was 
developed to simulate future wholesale market transactions to aid in 
BPA's long-term power marketing and resource strategy decisions--the 
Power Marketing Decision Analysis Model (PMDAM). PMDAM projects the 
marginal costs that BPA will face when taking actions to serve its 
Pacific Northwest customers, at the least cost, under conditions of 
uncertainty. PMDAM uses information on the costs associated with 
acquiring and operating resources to meet load in conjunction with the 
costs associated with purchasing and/or selling power in the West Coast 
bulk power market.
    The MCA provides estimates of BPA's marginal costs of supplying 
peaking demand on heavy load hours, and energy at different times. 
These estimates provide the basis for determining the generation 
component of BPA's demand charge. The estimates also provide the basis 
for the seasonal and hourly time-differentiation of energy charges, 
including the identification of time-periods in which different rates 
may apply and appropriate levels for rates in each time period relative 
to the others. These time periods consist of hours of the week when the 
marginal cost of power is high and those when it is relatively low, as 
well as seasons of the year when different marginal costs prevail. The 
results of the analysis suggest that BPA's rates be different for six 
seasons. The results also suggest that BPA's energy rates be 
differentiated between heavy and light load hours, which was not a 
feature of previous rate designs. The analysis does not include any 
quantitative estimate of marginal costs incurred on the transmission 
system.

E. Wholesale Power Rate Development Study (WPRDS)

    BPA is proposing substantial changes in the method used to develop 
its wholesale power rates. BPA's wholesale power rate development is a 
two step process. First, BPA allocates the test period generation 
revenue requirements and then adjusts these results to reflect various 
rate design objectives and statutory requirements.
1. Allocation of BPA's Generation Revenue Requirements
    BPA allocates the test year generation revenue requirements to 
customer classes based on the use of specific services by each customer 
class and the rate directives of the Northwest Power Act.
    BPA is proposing to recognize three different categories of 
generation costs as part of its effort to unbundle generation services: 
peak demand, rights to energy, and delivered energy. Generation energy 
cost allocations reflect the relative use of services and resources 
needed to serve load. Costs recovered from the sales of peak demand and 
rights to energy products are treated as a credit against BPA's 
generation costs prior to allocating the generation revenue 
requirements.
2. Adjustments to Allocated Costs
    The remaining steps in the rate design process use the allocated 
costs developed in the Cost of Service Analysis (COSA) and modify them 
to: (1) reflect BPA's rate design objectives; (2) conform with 
contractual requirements; (3) reflect the results of other BPA studies 
and commitments made in other public involvement processes under 
Section 7(i) of the Northwest Power Act; and (4) conform with 
requirements of applicable legislation. BPA's rate design objectives 
include recovery of BPA's revenue requirement, rate and revenue 
stability, practicality, fairness, and efficiency.
    Major rate design adjustments to the allocated COSA costs include 
the following:
a. Excess Revenue Adjustment
    In the initial cost allocation, BPA allocates its entire test 
period revenue requirement to firm power loads on the basis of 
resources available under critical water conditions. However, rates are 
set assuming BPA recovers nonfirm sales revenues equal to the expected 
value of revenues under 50 years of streamflows in the historical 
record. Because no generation costs are allocated to nonfirm energy 
(NF) service, the generation portion of forecasted NF revenues are 
credited against costs allocated to firm loads.
b. Surplus Firm Power Excess Revenue Adjustment
    BPA has sold and expects to continue to sell surplus power under 
long-term contracts. Expected revenues from the sale of such power are 
compared to allocated costs. BPA expects revenues to exceed costs of 
this power, resulting in a credit to other customers.
c. 7(c)(2) Adjustment
    The rates applicable to the DSIs are set according to the rate 
directives contained in Section 7(c) of the Northwest Power Act. In 
1987, BPA adopted a methodology for setting the DSI rate known as the 
IP-PF (Industrial Firm Power-Priority Firm Power) rate link. The link 
is essentially a formula that quantifies the rate directives. The 
components of the formula are the typical margin, a character of 
service adjustment, a value of reserves credit, and an inflation 
adjustment. The link has been used to set rates since the 1987 rate 
case. However, it will expire with the expiration of the current VI 
rate contract on September 30, 1996, and cannot be used to set rates in 
this rate proceeding.
    Therefore, BPA is recalculating the factors of the link. The first 
factor is the typical margin that BPA's preference customers include in 
their retail industrial rates. The second factor is the character of 
service adjustment that accounts for the fact that a portion of the DSI 
load is not served as firm on a planning basis. The third factor is the 
credit that reflects the value of reserves provided to BPA by its 
restriction rights on the DSI load. In this proposal an inflation 
adjustment is not included because its purpose in the current link is 
to escalate the other factors to each rate case so they do not have to 
be recalculated. It is not necessary to include an inflation adjustment 
because new values are being determined in this rate proceeding.
    Using the factors described above, a DSI rate calculation is 
performed that links it to the preference customer rate. The revenues 
from this linked DSI rate are less than the costs initially allocated 
to the DSIs. The difference is called the ``7(c)(2) delta'' and is 
allocated to other power customers.
    The foregoing list of rate design adjustments identifies some of 
the major cost adjustments and is not intended to be all-inclusive. As 
a final step in rate design, BPA develops seasonal and diurnally 
differentiated energy charges based on allocated costs and scaled based 
on the results of the MCA. The final step in the WPRDS is to combine 
the revenues projected for energy, capacity, rights to energy, and 
transmission. These total revenues by customer class are divided by the 
relevant billing determinants to calculate average rates. 

[[Page 36471]]

3. Changes in Rate Design
    A major change that BPA is proposing is the introduction of 
separate 5-year duration rate schedules for PF, IP, and NR rates. Other 
rate design changes include the elimination of an Interim Rate 
Adjustment, changes to demand charges, development of a composite rate 
for some small customers, changes to the Low Density Discount, 
elimination of the Irrigation Discount, changes to the unauthorized 
increase charge, changes to the NF contract rate, and development of a 
rate phase-in adjustment for full or metered requirements customers.
a. 5-Year Rate
    BPA is proposing to introduce a 5-year rate, available by 
subscription for all purchasers under the PF, IP, and NR rate 
schedules. The 5-year duration is available for power purchases, as 
well as related unbundled products, to purchasers under both the 
current and new power sales contracts. The longer-term rate is intended 
to provide customers with price certainty for the products needed to 
supply their entire electricity portfolio. BPA will continue to offer a 
2-year rate for products and services. The 5-year rate will have the 
same seasonal and diurnal shape as the 2-year rate, and will be 
constant over the 5-year period. In most cases, customers will be able 
to choose to place a portion of their load on the 2-year rate and a 
portion on the 5-year rate. Utilities serving New Large Single Loads 
(NLSLs) must elect to have their NLSLs served at either the 2-year or 
the 5-year rate. The 5-year rate will not be available to utilities 
participating in the exchange under section 5(c) of the Northwest Power 
Act.
b. Power Demand Charges
    BPA is proposing a number of changes to the demand charge. 
Customers will be billed for transmission service for their Federal 
power deliveries, assessed under the appropriate transmission rate 
schedules. Further discussion of the proposed transmission rates is in 
Section E, below. There also will be a ``generation'' demand charge in 
the PF, IP, NR, and FPS rate schedules. This charge will be assessed to 
power purchases that occur during the same hour as the transmission 
system peak. BPA has proposed to eliminate the Demand Ratchet included 
in previous rate cases. It has not proved to be effective, and with the 
other demand rate design changes, is unnecessary.
c. The Composite Rate
    A composite rate is being proposed for utility purchasers who 
choose to purchase their entire power requirements from BPA at the 
composite rate under the PF-96.5 rate schedule. Only customers whose 
forecasted average annual energy loads during the 5-year purchase 
period are 25 average annual megawatts or less are eligible to purchase 
at this rate. The composite rate is a weighted average rate based on 
the relative cost of generation demand, energy, load shaping and load 
regulation. Customers will be billed for transmission service for their 
Federal power deliveries, assessed under the appropriate transmission 
rate schedules.
d. Low Density Discount
    BPA is proposing to change the eligibility criteria and calculation 
of the Low Density Discount. In determining eligibility, the total 
electric energy requirement now will include nonfirm sales to firm 
retail and nonfirm loads. The calculation proposes using a sliding 
scale of percentage discounts based on both (1) the utility's number of 
customers per pole-mile and (2) the utility's ratio of total electric 
energy requirements to investment. Separate discounts resulting from 
each of the two ratios will be added to result in the utility's total 
discount, which is capped at 7 percent. The proposed discount will 
apply to total power purchases under both current and new power sales 
contracts, and will not apply to transmission-related charges.
e. Unauthorized Increase for Power Sales
    BPA proposes to change the unauthorized increase charge to 
eliminate seasonal differentiation. This reflects treating the charge 
as a penalty rate, applicable to purchasers taking demand and energy in 
excess of their contractual entitlement, rather than a cost-based rate. 
This unauthorized increase charge will apply both to current and new 
power sales contracts. In addition, there is an unauthorized deviation 
charge for partial requirements purchases purchasing under the new 
power sales contract. This rate is the same as the unauthorized 
increase charge.
f. Nonfirm Rate Schedule Contract Rate
    BPA also is proposing to modify the contract rate in the NF rate 
schedule. The contract rate will be equal to the average cost of 
nonfirm energy.
g. Rate Phase-in Adjustment
    BPA is proposing a rate phase-in mitigation for full or metered 
requirements preference customers, who, as a result of all of BPA's 
rate design changes, will see a rate increase greater than 9 percent. 
This phase-in adjustment is available only to customers who choose to 
purchase all of their power from BPA at the 5-year rate, and meet other 
eligibility requirements.
4. Unbundled Products
    For service under both the 1981 and 1996 power sales contracts, BPA 
is proposing separate charges under the PF, IP, and NR rate schedules 
for firm energy demand, load shaping, partial load shaping, and load 
regulation. Load shaping allows BPA to meet customer load variations 
from forecasts. Load regulation follows variations in the customers' 
loads on an instantaneous basis. BPA is unbundling, i.e., separately 
pricing, many products, generally available under two new rate 
schedules.
5. Ancillary Services
    BPA is proposing the Ancillary Products and Services (APS) rate 
schedule for those services necessary to support the transmission of 
electric power from resources to load on the FCRTS. These services are: 
control area reserves for resources; control area reserves for 
interruptible purchases; scheduling and dispatch; load regulation, and 
transmission losses.
6. Firm Power Products and Services
    BPA also has developed the Firm Power Products and Services (FPS) 
rate schedule. The FPS rate schedule will allow BPA to sell firm 
energy, capacity, or power using a variety of sources of supply, and 
will specify charges or specifically authorize negotiated charges for 
various unbundled products. Firm power products and services to be 
marketed by BPA under the FPS rate schedule are intended to be flexible 
so that BPA can respond to market conditions.

F. 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 


[[Page 36472]]
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.
    The Section 7(b)(2) rate test triggers in this proposal, causing 
costs to be reallocated in the test period. The Priority Firm rate 
applied to the general requirements of the 7(b)(2) customers has been 
reduced by the 7(b)(2) amount while all other rates, including the PF 
rate applied to customers purchasing under the Residential and Small 
Farm Power Exchange program, have been increased by an allocation of 
the 7(b)(2) amount.

G. Transmission Rate Design Study (TRDS)

    For the first time, rates for Federal and non-Federal use of the 
transmission system are developed in the TRDS. BPA's construct in 
developing the proposed transmission rates is to make transmission 
services available to power customers, wheeling customers, and its own 
power business at the same terms, conditions, and rates.
    The transmission service required for BPA power sales is offered 
under the new Network Integration (NT) rate and Point-to-Point (PTP) 
rate. These rates also are available for transmission of non-Federal 
power. BPA's full requirements customers must take transmission service 
at the NT rate; other BPA power customers may choose the NT or PTP 
rate. Consistent with the power rates, 2-year and 5-year NT and PTP 
rates have been developed. The 2-year NT and PTP rate may be used by 
power customers only if they are not purchasing power under the 5-year 
power rates. The remaining transmission rates are developed for a 2-
year rate period only.
    As part of implementing the transmission rate construct, the 
segmentation of BPA's transmission system also is being revised: BPA 
transmission facilities formerly in the Fringe now are included in the 
Network segment. Facilities at 34.5 kV and below are classified now as 
Delivery; facilities that are above 34.5 kV are segmented to the 
Network. Charges for Utility Delivery and DSI Delivery are developed in 
the TRDS to apply to all power delivered over these facilities. This 
new segmentation is performed in the TRDS for the initial rate 
proposal; the Segmentation Study should reflect the new segmentation in 
the supplemental proposal.
    To calculate rates in the TRDS, the segmented transmission revenue 
requirements are allocated to Federal and non-Federal power forecasted 
to use the FCRTS. The factors for allocating Network cost to loads are 
the billing determinants for the Network transmission services. Prior 
to allocating Network cost, BPA identifies the cost associated with 
transmission load shaping, a feature of Network Integration service, 
and removes it from Network cost. After allocation, this transmission 
load shaping cost is added to the costs to be recovered from the NT 
rate. Southern Intertie and Northern Intertie costs are allocated based 
on forecast energy use.
    Rate charges based on the allocated costs are calculated, and 
individual rate schedules are designed. In addition to the NT and PTP 
rates, all of BPA's traditional rates are calculated. BPA also is 
proposing the Advance Funding rate to allow BPA to recover the cost of 
specified transmission facilities through advance payment. Finally, BPA 
is proposing a Reservation Fee for Transmission Capacity, and a 
Reactive Power Charge that takes the place of the current Power Factor 
Adjustment.

V. Wholesale Power Rate Schedules and Transmission Rate Schedules

A. Introduction

    The rate schedules are divided into three sections. The first 
section (Section C below) contains the wholesale power rate schedules. 
The second section (Section D below) contains the transmission rate 
schedules. The third section (Section E below) is the combined GRSPs 
for power and transmission rates.
    The proposed wholesale power and transmission rate schedules were 
prepared in accordance with BPA's statutory authority to develop rates, 
including the BPA Project Act of 1937, as amended, 16 U.S.C. 832 
(1982); the Flood Control Act of 1944, 16 U.S.C. 825s (1982); the 
Federal Columbia River Transmission System Act (Transmission System 
Act), 16 U.S.C. 838 (1982); and the Northwest Power Act, 16 U.S.C. 839 
(1982).
    The 1996 proposed wholesale power and transmission rate schedules 
and the GRSPs associated with those rate schedules will supersede BPA's 
1995 rate schedules (which BPA proposes to become effective October 1, 
1995) to the extent stated in the Availability section of each 1996 
rate schedule. BPA proposes that its wholesale power and transmission 
rate schedules, including the GRSPs associated with these rate 
schedules, become effective upon interim approval or upon final 
confirmation and approval by FERC. BPA currently anticipates that it 
will request FERC approval of its revised rates effective October 1, 
1996.

B. Summary of Wholesale Power Rate Schedules

                     Wholesale Power Rate Schedules                     
                                                                        
                                                                        
PF-96          Priority Firm Power Rate.                                
NR-96          New Resource Firm Power Rate.                            
IP-96          Industrial Firm Power Rate.                              
VI-96          Variable Industrial Power Rate.                          
NF-96          Nonfirm Energy Rate.                                     
RP-96          Reserve Power Rate.                                      
PS-96          Power Shortage Rate.                                     
FPS-96         Firm Power and Services Rate.                            
APS-96         Ancillary Products and Services Rate.                    

    A summary of the proposed 1996 Wholesale Power Rate Schedules is 
provided below. Each rate schedule includes sections specifying the 
customer class and the service available under the rate schedule, the 
rates for the products and services offered under the schedule, the 
applicable billing factors, applicable transmission rate schedules, and 
other special provisions for rate 

[[Page 36473]]
adjustments, such as any discounts or penalties that apply to that rate 
schedule.
1. Priority Firm Power Rate (PF-96.2 and PF-96.5)
    The proposed PF-96.2 rate schedule would be available for a 2-year 
period beginning October 1, 1996, and would replace the PF-95 rate 
schedule. The proposed PF-96.5 rate schedule would be available for a 
5-year period beginning October 1, 1996. Power is available under the 
proposed PF-96 rate schedule to public bodies, cooperatives, and 
Federal agencies. Utilities participating in the residential exchange 
under section 5(c) of the Northwest Power Act may purchase power only 
under PF-96.2. Priority Firm power must be used to meet firm loads 
within the Pacific Northwest. The proposed PF rate consists of 
seasonally and diurnally differentiated energy charges, and charges for 
demand, load shaping, load regulation, and transmission. Rate 
adjustments include a Conservation Surcharge, Low Density Discount, 
Energy Return Surcharge, Deviation Adjustment, Phase-In Mitigation, 
Preschedule Change Charge, Reactive Power Charge, Transitional Service, 
Unauthorized Increase, and Industrial Exemption and Curtailment.
2. New Resource Firm Power Rate (NR-96.2 and NR-96.5)
    The proposed NR-96.2 rate schedule would be available for a 2-year 
period beginning October 1, 1996, and would replace the NR-95 rate 
schedule. The proposed NR-96.5 rate schedule would be available for a 
5-year period beginning October 1, 1996. The proposed NR-96 rate 
schedules are available to investor-owned utilities under net 
requirements contracts for resale to consumers, and to publicly owned 
utilities for New Large Single Loads. The proposed NR rate consists of 
seasonally and diurnally differentiated energy charges, and charges for 
demand, load shaping, load regulation, and transmission. Rate 
adjustments include a Conservation Surcharge, Low Density Discount, 
Energy Return Surcharge, Deviation Adjustment, Phase-In Mitigation, 
Preschedule Change Charge, Reactive Power Charge, Transitional Service, 
and Unauthorized Increase.
3. Industrial Firm Power Rate (IP-96.2 and IP-96.5)
    The proposed IP-96.2 rate schedule would be available for a 2-year 
period beginning October 1, 1996, and would replace the IP-95 rate. The 
proposed IP-96.5 rate schedule would be available for a 5-year period 
beginning October 1, 1996. The proposed IP-96 rate schedules are 
available to BPA's DSI customers for firm power to be used in their 
industrial operations. The proposed IP rate consists of seasonally and 
diurnally differentiated energy charges, and charges for demand, load 
shaping, load regulation, and transmission. Rate adjustments include a 
Conservation Surcharge, Curtailment Charge, Deviation Adjustment, First 
Quartile Discount, Operating Reserves Credit, Preschedule Change 
Charge, Reactive Power Charge, and Unauthorized Increase.
4. Variable Industrial Power Rate (VI-96)
    The proposed Variable Industrial Power (VI-96) rate schedule would 
replace the VI-95 rate. The proposed VI-96 rate is available to BPA's 
DSI customers who enter into a separate variable rate contract with BPA 
for power to be used in their aluminum and nickel smelting operations. 
Purchasers under this rate schedule must first elect service under the 
proposed IP rate schedule for either the 2-year period or the 5-year 
period, both beginning October 1, 1996. The variable rate will be based 
on the IP rate under which the purchaser has elected service. The 
demand charge for the variable rate will be the same as in the 
applicable IP rate, but the monthly energy charge will vary with the 
price of the metal used in the purchaser's smelting operation. Because 
BPA plans to hedge the risk of aluminum or nickel price fluctuations, 
individualized variable rates will be designed at the time each 
purchaser enters into a variable rate contract. The contracts will be 
designed so that BPA will receive revenues, either from the DSI or the 
hedging financial institution, equal to those that would be received 
under the IP-96 rate schedule. The purchaser can choose to have an 
initial variable rate formula in effect for any period from 1 to 2 
years under the 2-year rate option or from 1 to 5 years under the 5-
year rate option. At the expiration of the rate formula, a new one can 
be established based on then-prevailing market conditions for aluminum 
or nickel, or the purchaser may purchase power under the applicable IP 
rate. Rate adjustments include a Preschedule Change Charge, Reactive 
Power Charge, and Unauthorized Increase.
5. Nonfirm Energy Rate (NF-96)
    The proposed Nonfirm Energy (NF-96) rate schedule replaces the NF-
95 rate. The proposed NF-96 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 proposed NF-96 rate schedule includes four rate 
components: a flexible Standard rate; a flexible Market Expansion rate; 
a flexible Incremental rate; and a fixed Contract rate. Adjustments 
include a Guaranteed Delivery, Preschedule Charge, and Reactive Power 
Charges. The NF Rate Cap continues to apply to all sales under the 
proposed NF-96 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.
6. Reserve Power Rate (RP-96)
    The proposed Reserve Power (RP-96) rate schedule replaces the RP-95 
rate schedule. The proposed 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-96 rate consists of 
a demand charge, transmission charges, and seasonally and diurnally 
differentiated energy charges. Adjustments include a Reactive Power 
Charge.
7. Power Shortage Rate (PS-96)
    The proposed Power Shortage (PS-96) 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 available or to broker power under the 
proposed PS-96 rate schedule unless specified by contract. The proposed 
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. Adjustments include the Energy Return Surcharge, Deviation 
Adjustment, and Reactive Power and Unauthorized Increase Charges.
8. Firm Power and Services Rate (FPS-96)
    The proposed Firm Power Products and Services (FPS-96) rate 
schedule will be available for the purchase of Firm Power and certain 
unbundled products including supplemental control area services, 
shaping and load factoring services, and resource support services. 
Firm power products and 

[[Page 36474]]
services that may be marketed by BPA under the proposed FPS-96 rate 
schedule are intended to be priced so that BPA has the flexibility to 
provide purchasers with customized products and services that are not 
available under other rate schedules. The proposed FPS-96 rate contains 
fixed and negotiable rates for Firm Power. The rates for products and 
services other than firm power may be negotiated between BPA and the 
purchaser. The proposed FPS-96 rate schedule supersedes the SP-93 and 
CE-95 rates.
9. Ancillary Products and Services Rate (APS-96)
    The proposed Ancillary Products and Services (APS-96) rate schedule 
will be available for the ancillary services that are necessary to 
support the firm or nonfirm delivery of power that uses FCRTS 
facilities. The following ancillary services may be purchased under the 
proposed APS-96 rate: control area reserves for resources; control area 
reserves for interruptible purchases; load regulation; transmission 
losses; and scheduling and dispatch. The proposed APS-96 rate also will 
be available for ancillary services of a similar nature that FERC may 
order BPA to provide pursuant to sections 211 and 212 of the Federal 
Power Act (16 U.S.C. 824j and 824k).

C. Wholesale Power Rate Schedules

    These schedules and GRSPs shall be applicable to BPA's power sales 
contracts, as appropriate, including contracts executed both prior to 
and subsequent to enactment of the Northwest Power Act. In addition, as 
stated in the availability section of each schedule, certain of the 
rates will be effective for extended periods of time. The GRSPs are an 
integral part of each rate schedule.

Schedule PF-96.2

Priority Firm Power

Section I. Availability

    This schedule is available for the contract purchase of firm power 
or capacity to be used within the Pacific Northwest for a 2-year 
period, October 1, 1996, through September 30, 1998. Priority Firm 
Power may be purchased by public bodies, cooperatives, and Federal 
agencies for resale to ultimate consumers for direct consumption. This 
schedule is available for all PF power purchases not subscribed at the 
PF-96.5 rate.
    Rates in this schedule are applicable to purchases under 
requirements sales contracts effective on or before September 30, 1996 
(hereinafter termed the ``1981'' contracts, although some are actually 
dated ``1984'' or later), and under contracts that may be effective on 
or after October 1, 1996 (``1996'' contracts). Customers that purchase 
under 1981 contracts may buy either firm power or capacity without 
energy under this rate schedule. Customers that purchase under 1996 
contracts may buy only firm power. These and other products available 
under this rate schedule are defined in BPA's General Rate Schedule 
Provisions (GRSPs). Rates under contracts that contain charges that 
escalate based on rates listed in this rate schedule shall include 
applicable transmission charges.
    This rate schedule is also available to utilities participating in 
the residential and small farm exchange under section 5(c) of the 
Northwest Power Act pursuant to their Residential Purchase and Sale 
Agreement. All Priority Firm Power made available to utilities 
participating in the section 5(c) exchange shall be purchased under 
Section E of this rate schedule.
    This rate schedule supersedes Schedule PF-95, which went into 
effect on October 1, 1995. Sales under the PF-96.2 rate schedule are 
subject to BPA's General Rate Schedule Provisions. For sales under this 
rate schedule, bills shall be rendered and payments due pursuant to 
BPA's Billing Procedures.
Section II. Rates, Billing Factors, and Adjustments for each PF product

    For each customer designation, the rate(s) for each product along 
with the associated billing factor(s) are identified in separate 
sections of the rate schedule. The rates for each customer designation 
are identical except for Section E; the billing factors, however, vary 
according to the customer designation. Applicable adjustments and 
special rate provisions are listed for each customer designation. 
Network Integration transmission service at the Network Integration 
(NT) rate or Point-to-Point transmission service at the Point-to-Point 
(PTP) rate is required for purchases under this rate schedule.
    This rate schedule contains five subsections, corresponding to the 
customer categories to which this rate schedule applies:
    Section II.A  Applies to Metered Requirements customers who 
purchase under a ``1981'' power sales contract.
    Section II.B  Applies to Full Requirements customers who purchase 
under a ``1996'' power sales contract.
    Section II.C  Applies to Computed Requirements customers who 
purchase under a ``1981'' power sales contract.
    Section II.D  Applies to Partial Requirements customers who 
purchase under a ``1996'' power sales contract.
    Section II.E  Applies to customers who purchase under a Residential 
Purchase and Sale Agreement (RPSA).

A. PF Rates for Metered Requirements Customers who Purchase Under a 
``1981'' Power Sales Contract

    Metered Requirements customers purchasing power under a ``1981'' 
power sales contract are required to buy Load Shaping, Load Regulation, 
and Network Integration Transmission service at the Network Integration 
(NT) rate.
1. Priority Firm Power
1.1. Rates
1.1.1 Demand Charge

------------------------------------------------------------------------
                  Applicable months                          Rate       
------------------------------------------------------------------------
All months of the year..............................  $0.56/kW-mo.      
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                                                          HLH      LLH  
                   Applicable months                      rate     rate 
------------------------------------------------------------------------
September-December....................................    22.20    19.64
January-March.........................................    23.02    20.28
April.................................................    20.65    19.46
May-June..............................................    13.61    10.78
July..................................................    15.90    12.79
August................................................    20.10    16.63
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
    For purchasers of 2-year power only.
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load.
    For purchasers of a combination of 2-year and 5-year power.
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load minus the Purchaser's 5-year Billing 
Demand.
1.2.2. HLH Billing Energy
    For purchasers of 2-year power only.
    Purchaser's HLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    Purchaser's HLH Measured Energy minus the Purchaser's 5-year HLH 
Billing Energy.
1.2.3. LLH Billing Energy
    For purchasers of 2-year power only.
    Purchaser's LLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power
    Purchaser's LLH Measured Energy minus the Purchaser's 5-year LLH 
Billing Energy.

[[Page 36475]]

2. Full Load Shaping
2.1. Rate
    0.30 mills/kWh multiplied by the Utility Factor.
2.2. Billing Factor
    For purchasers of 2-year power only.
    Purchaser's total HLH and LLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    There is no charge for load shaping under the PF-96.2 rate 
schedule.
3. Load Regulation
    3.1. Rate
    0.25 mills/kWh multiplied by the Utility Factor.
    3.2. Billing Factor
    For purchasers of 2-year power only.
    Purchaser's total HLH and LLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    There is no charge for load regulation under the PF-96.2 rate 
schedule.
4. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate.
5. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
5.1. Rate Adjustments

------------------------------------------------------------------------
                       Rate adjustment                          Section 
------------------------------------------------------------------------
Conservation Surcharge......................................  II.A.     
Low Density Discount........................................  II.I.     
Reactive Power Charge.......................................  II.N.     
Transitional Service........................................  II.P.     
------------------------------------------------------------------------

5.2. Special Rate Provisions

------------------------------------------------------------------------
                   Special rate provisions                      Section 
------------------------------------------------------------------------
Cost contributions..........................................  II.B.     
Utility factor..............................................  II.R.     
------------------------------------------------------------------------

B. PF Rates for Full Requirements Customers who Purchase Under a 
``1996'' Power Sales Contract

    Full Requirements Purchasers purchasing power under a ``1996'' 
power sales contract are required to buy Load Shaping, Load Regulation, 
and Network Integration Transmission service at the Network Integration 
(NT) rate.
1. Priority Firm Power
1.1. Rates
1.1.1. Demand Charge

------------------------------------------------------------------------
                  Applicable months                          Rate       
------------------------------------------------------------------------
All Months of the Year..............................  $0.56/kW-mo.      
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                                                          HLH      LLH  
                   Applicable months                      rate     rate 
------------------------------------------------------------------------
September-December....................................    22.20    19.64
January-March.........................................    23.02    20.28
April.................................................    20.65    19.46
May-June..............................................    13.61    10.78
July..................................................    15.90    12.79
August................................................    20.10    16.63
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
    For purchasers of 2-year power only.
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load.
    For purchasers of a combination of 2-year and 5-year power.
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load minus the Purchaser's 5-year Billing 
Demand.
1.2.2. HLH Billing Energy
    For purchasers of 2-year power only.
    Purchaser's HLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    Purchaser's HLH Measured Energy minus the Purchaser's 5-year HLH 
Billing Energy.
1.2.3. LLH Billing Energy
    For purchasers of 2-year power only.
    Purchaser's LLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    Purchaser's LLH Measured Energy minus the Purchaser's 5-year LLH 
Billing Energy.
2. Full Load Shaping
2.1 Rate
    0.30 mills/kWh.
2.2 Billing Factor
    For purchasers of 2-year power only.
    Purchaser's Retail Load minus the Purchaser's Industrial Exemption, 
if any.
    For purchasers of a combination of 2-year and 5-year power.
    There is no charge for load shaping under the PF-96.2 rate 
schedule.
3. Load Regulation
3.1. Rate and Billing Factor
    For purchasers of 2-year power only.
    0.25 mills/kWh multiplied by Purchaser's Retail Load.
    For purchasers of a combination of 2-year and 5-year power.
    There is no charge for load regulation under the PF-96.2 rate 
schedule.
4. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate.
5. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
5.1. Rate Adjustments

------------------------------------------------------------------------
                       Rate adjustment                          Section 
------------------------------------------------------------------------
Conservation surcharge......................................  II.A.     
Deviation adjustment........................................  II.D.     
Industrial exemption/curtailment............................  II.H.     
Low density discount........................................  II.I.     
Reactive power charge.......................................  II.N.     
------------------------------------------------------------------------

5.2. Special Rate Provisions

------------------------------------------------------------------------
                   Special rate provisions                      Section 
------------------------------------------------------------------------
Cost contributions..........................................  II.B.     
------------------------------------------------------------------------

C. PF Rates for Computed Requirements Customers who Purchase Under a 
``1981'' Power Sales Contract

    Actual Computed Requirements Purchasers purchasing power under a 
``1981'' power sales contract are required to buy Load Shaping and 
Network Integration Transmission service at the Network Integration 
(NT) rate. Planned and Contracted Computed Requirements Purchasers are 
not allowed to buy Load Shaping. Load Regulation is required if the 
customer is in BPA's load control area, regardless of whether the 
customer is purchasing on the basis of actual, planned, or contracted 
computed requirements. Planned and Contracted Computed Requirements 
customers must elect either Network Integration Transmission service at 
the Network Integration (NT) rate or Point-to-Point Transmission 
service at the Point-to-Point (PTP) rate.
1. Priority Firm Power
1.1. Rates
1.1.1. Demand Charge

------------------------------------------------------------------------
                  Applicable months                          Rate       
------------------------------------------------------------------------
All Months of the Year..............................  $0.56/kW-mo.      
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                                                          HLH      LLH  
                   Applicable months                      rate     rate 
------------------------------------------------------------------------
September-December....................................    22.20    19.64
January-March.........................................    23.02    20.28
April.................................................    20.65    19.46
May-June..............................................    13.61    10.78
July..................................................    15.90    12.79
August................................................    20.10    16.63
------------------------------------------------------------------------


[[Page 36476]]

1.2. Billing Factors
1.2.1. Billing Demand
1.2.1.1  With Load Shaping
    For purchasers of 2-year power only.
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load.
    For purchasers of a combination of 2-year and 5-year power
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load minus the Purchaser's 5-year Billing 
Demand.
1.2.1.2  Without Load Shaping
    For purchasers of 2-year power only.
    Purchaser's Computed Peak Requirement.
    For purchasers of a combination of 2-year and 5-year power.
    Purchaser's Computed Peak Requirement minus the Purchaser's 5-year 
Billing Demand.
1.2.2. Billing Energy
1.2.2.1  For Purchasers of 2-Year Power Only
For Energy Delivered September-March
    The HLH Billing Energy is the Purchaser's HLH Measured Energy.
    The LLH Billing Energy is:
    a. 76 percent of the Purchaser's Measured Energy, plus 24 percent 
of the Purchaser's Computed Energy Maximum, minus
    b. The Purchaser's HLH Measured Energy.
For Energy Delivered April-August
    The HLH Billing Energy is the Purchaser's HLH Measured Energy.
    The LLH Billing Energy is:
    a. 63 percent of the Purchaser's Measured Energy, plus 37 percent 
of the Purchaser's Computed Energy Maximum, minus
    b. The Purchaser's HLH Measured Energy.
1.2.2.2  For Purchasers of a Combination of 2-Year and 5-Year Power
    The HLH Billing Energy is the Purchaser's HLH Computed Energy 
Maximum minus the Purchaser's 5-year HLH Billing Energy.
    The LLH Billing Energy is the Purchaser's LLH Computed Energy 
Maximum minus the Purchaser's 5-year LLH Billing Energy.
2. Firm Capacity Without Energy
2.1. Rate

------------------------------------------------------------------------
                  Applicable months                          Rate       
------------------------------------------------------------------------
September-December..................................  $1.11/kW-mo.      
January-March.......................................  1.15/kW-mo.       
April...............................................  0.82/kW-mo.       
May-June............................................  1.17/kW-mo.       
July................................................  1.23/kW-mo.       
August..............................................  1.31/kW-mo.       
------------------------------------------------------------------------

2.2. Billing Factors
    Purchaser's Computed Peak Requirement associated with the purchase 
of Firm Capacity Without Energy.
3. Full Load Shaping
3.1. Rate
    0.30 mills/kwh multiplied by the Utility Factor.
3.2. Billing Factor
    For purchasers of 2-year power only.
    Purchaser's total HLH and LLH Billing Energy.
    For purchasers of a combination of 2-year and 5-year power.
    There is no charge for load shaping under the PF-96.2 rate 
schedule.
4. Load Regulation
4.1. Rate
    0.25 mills/kWh multiplied by the Utility Factor.
4.2. Billing Factor
    For purchasers of 2-year power only.
    Purchaser's total HLH and LLH Billing Energy.
    For purchasers of a combination of 2-year and 5-year power.
    There is no charge for load regulation under the PF-96.2 rate 
schedule.
5. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate or the charge for Point-to-Point service under the Point-to-
Point (PTP) rate.
6. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
6.1. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Conservation Surcharge....................................  II.A.       
Energy Return Surcharge...................................  II.F.       
Low Density Discount......................................  II.I.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
Unauthorized Increase Charge..............................  II.Q.       
------------------------------------------------------------------------

6.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
Utility Factor............................................  II.R.       
------------------------------------------------------------------------

D. PF Rates for Partial Requirements Customers Who Purchase Under A 
``1996'' Power Sales Contract

    Partial Requirements customers purchasing power under a 1996 power 
sales contract may purchase Load Shaping. All customers in BPA's load 
control area are required to buy Load Regulation, and customers outside 
of BPA's load control area may not buy Load Regulation. Partial 
Requirements customers must elect either Network Integration 
Transmission service at the Network Integration (NT) rate or Point-to-
Point Transmission service at the Point-to-Point (PTP) rate.
1. Priority Firm Power
1.1. Rates
1.1.1. Demand Charge

------------------------------------------------------------------------
                 Applicable months                          Rate        
------------------------------------------------------------------------
All Months of the Year............................  $0.56/kW-mo.        
------------------------------------------------------------------------

 1.1.2. Energy Charge

------------------------------------------------------------------------
                  Applicable months                   HLH rate  LLH Rate
------------------------------------------------------------------------
September-December..................................     22.20     19.64
January-March.......................................     23.02     20.28
April...............................................     20.65     19.46
May-June............................................     13.61     10.78
July................................................     15.90     12.79
August..............................................     20.10     16.63
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
1.2.1.1  With Load Shaping
    For purchasers of 2-year power only.
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load.
    For purchasers of a combination of 2-year and 5-year power.
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load minus the Purchaser's 5-year Billing 
Demand.
1.2.1.1  Without Load Shaping
    Purchaser's 2-year Demand Subscription.
1.2.2. HLH Billing Energy
1.2.2.1  With Load Shaping
    For purchasers of 2-year power only.
    Purchaser's HLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    Purchaser's HLH Measured Energy minus the Purchaser's 5-year HLH 
Billing Energy.
1.2.2.2 Without Load Shaping
    Purchaser's 2-year HLH Energy Subscription. 

[[Page 36477]]

1.2.3. LLH Billing Energy
1.2.3.1 WITH Load Shaping
    For purchasers of 2-year power only.
    Purchaser's LLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    Purchaser's LLH Measured Energy minus the Purchaser's 5-year LLH 
Billing Energy.
1.2.3.2 Without Load Shaping
    Purchaser's 2-year LLH Energy Subscription.
2. Full Load Shaping
2.1 Rate
    0.30 mills/kWh.
2.2 Billing Factor
    For purchasers of 2-year power only.
    Purchaser's Retail Load minus the Purchaser's Industrial Exemption, 
if any.
    For purchasers of a combination of 2-year and 5-year power.
    There is no charge for load shaping under the PF-96.2 rate 
schedule.
3. Load Regulation
3.1  Rate and Billing Factor
    For purchasers of 2-year power only.
    0.25 mills/kWh multiplied by Purchaser's Retail Load.
    For purchasers of a combination of 2-year and 5-year power.
    There is no charge for load regulation under the PF-96.2 rate 
schedule.
4. Partial Load Shaping
4.1  Rate
    $3.05/MWhr-hr.
4.2  Billing Factor
    For purchasers of 2-year power only.
    MWhr-hr amount of Partial Load Shaping Subscribed for the month.
    For purchasers of a combination of 2-year and 5-year power.
    There is no charge for partial load shaping under the PF-96.2 rate 
schedule.
5. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate or the charge for Point-to-Point service under the Point-to-
Point (PTP) rate.
6. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
6.1. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Conservation Surcharge....................................  II.A        
Deviation Adjustment......................................  II.D.       
Industrial Exemption/Curtailment..........................  II.H.       
Low Density Discount......................................  II.I.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
------------------------------------------------------------------------

6.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------

E. PF Rates for Customers Who Purchase Under a Residential Purchase and 
Sale Agreement (RPSA)

    The rate for RPSA customers includes Load Shaping and Load 
Regulation. RPSA customers are required to purchase transmission 
service under the Network Integration (NT) rate.
1. Rates
1.1. Demand Charge

------------------------------------------------------------------------
                     Applicable months                          Rate    
------------------------------------------------------------------------
All Months of the Year....................................  $0.56/kW-mo.
------------------------------------------------------------------------

1.2  Energy Charge

------------------------------------------------------------------------
                       Applicable months                          Rate  
------------------------------------------------------------------------
September-December............................................     31.95
January-March.................................................     33.14
April.........................................................     29.72
May-June......................................................     19.59
July..........................................................     22.88
August........................................................     28.93
------------------------------------------------------------------------

2. Billing Factors
2.1.  Billing Demand
    The Billing Demand shall be the demand calculated by applying the 
load factor, determined as specified in the RPSA, to the Billing Energy 
for each billing period.
2.2.  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 
RPSA.
3. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate.
4. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Conservation Surcharge....................................  II.A.       
Low Density Discount......................................  II.I.       
------------------------------------------------------------------------

Schedule PF-96.5

Priority Firm Power

Section I. Availability

    This schedule is available for the contract purchase of firm power 
or capacity to be used within the Pacific Northwest for a 5-year 
period, October 1, 1996, through September 30, 2001. Priority Firm 
Power may be purchased by public bodies, cooperatives, and Federal 
agencies for resale to ultimate consumers for direct consumption. At 
their election, public body, cooperative, and Federal agency customers 
may purchase all or any designated portion of their power under this 
rate schedule as an alternative to purchasing power under the PF-96.2 
rate schedule. Customers making such an election shall agree to 
purchase the designated amount of power exclusively from BPA for 5 
years. Such election shall be a one-time irrevocable election and, as 
to the amount of power so designated, shall constitute a waiver of all 
rights to purchase power under any other power rate schedule for the 5-
year period. The election process is described in section II.E. of the 
GRSPs.
    Rates in this schedule are available for purchases under 
requirements sales contracts effective on or before September 30, 1996 
(hereinafter termed the ``1981'' contracts, although some are actually 
dated ``1984'' or later), and under contracts that may be effective on 
or after October 1, 1996 (``1996'' contracts). Customers electing to 
purchase power under this rate schedule and continuing to receive 
service pursuant to their 1981 power sales contract further waive any 
rights under that contract to modify their Firm Resources Exhibit in 
such a manner that reduces or interferes with their ability to purchase 
power for loads dedicated for service under this rate schedule. Rates 
under contracts that contain charges that escalate based on rates 
listed in this rate schedule shall include applicable transmission 
charges.
    Sales under the PF-96.5 rate schedule are subject to BPA's General 
Rate Schedule Provisions (GRSPs). Products available under this rate 
schedule are defined in the GRSPs. For sales under 

[[Page 36478]]
this rate schedule, bills shall be rendered and payments due pursuant 
to BPA's Billing Procedures.
Section II. Rates, Billing Factors, and Adjustments for Each PF Product
    For each customer designation, the rate(s) for each product along 
with the associated billing factor(s) are identified below. The rates 
for each customer designation are identical; the billing factors, 
however, vary according to the customer designation. Applicable 
adjustments and special rate provisions are listed for each customer 
designation. Network Integration transmission service at the Network 
Integration (NT) rate or Point-to-Point transmission service at the 
Point-to-Point (PTP) rate is required for purchases under this rate 
schedule.
    This rate schedule contains five subsections, corresponding to the 
customer categories to which this rate schedule applies:
Section II.A  Applies to Metered Requirements customers who purchase 
under a ``1981'' power sales contract.
Section II.B  Applies to customers who elect to purchase on a composite 
rate basis.
Section II.C  Applies to Full Requirements customers who purchase under 
a ``1996'' power sales contract and not on a composite rate basis.
Section II.D  Applies to Computed Requirements customers who purchase 
under a ``1981'' power sales contracts.
Section II.E  Applies to Partial Requirements customers who purchase 
under a ``1996'' power sales contracts.
A. PF Rates for Metered Requirements Customers who Purchase Under a 
``1981'' Power Sales Contract
    Metered Requirements customers purchasing power under a ``1981'' 
power sales contract are required to buy Load Shaping, Load Regulation, 
and Network Integration Transmission service at the Network Integration 
(NT) rate.
1. Priority Firm Power
1.1. Rates
1.1.1  Demand Charge

------------------------------------------------------------------------
                 Applicable months                          Rate        
------------------------------------------------------------------------
All Months of the Year............................  $0.56/kW-mo.        
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                  Applicable months                   HLH rate  LLH rate
------------------------------------------------------------------------
September-December..................................     22.20     19.64
January-March.......................................     23.02     20.28
April...............................................     20.65     19.46
May-June............................................     13.61     10.78
July................................................     15.90     12.79
August..............................................     20.10     16.63
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
    For purchasers of 5-year power only.
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of: Purchaser's Measured Demand that occurs during the 
hour of the Monthly Transmission Peak Load or Purchaser's 5-year Demand 
Subscription.
1.2.2. HLH Billing Energy
    For purchasers of 5-year power only.
    Purchaser's HLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of: Purchaser's HLH Measured Energy or Purchaser's 5-year 
HLH Energy Subscription.
1.2.3. LLH Billing Energy
    For purchasers of 5-year power only.
    Purchaser's LLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of: Purchaser's LLH Measured Energy or Purchaser's 5-year 
LLH Energy Subscription.
2. Full Load Shaping
2.1. Rate
    0.30 mills/kWh multiplied by the Utility Factor.
2.2. Billing Factor
    Purchaser's total HLH and LLH Measured Energy.
3. Load Regulation
3.1. Rate
    0.25 mills/kWh multiplied by the Utility Factor.
3.2. Billing Factor
    Purchaser's total HLH and LLH Measured Energy.
4. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate.
5. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
5.1. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Conservation Surcharge....................................  II.A.       
Low Density Discount......................................  II.I.       
Phase-In Mitigation.......................................  II.L.       
Reactive Power Charge.....................................  II.N.       
Transitional Service......................................  II.P.       
------------------------------------------------------------------------

5.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
Utility Factor............................................  II.R.       
------------------------------------------------------------------------

B. PF Rates for Customers who Elect to Purchase Power on a Composite 
Rate Basis
    Only customers whose average annual retail loads during the 1996 
rate period, as forecasted by BPA, are 25 average annual MW or less are 
eligible to purchase at this rate. The composite rate charge includes 
the PF-96.5 charges for demand, energy, Load Shaping, and Load 
Regulation. Purchasers at the composite rate also must purchase Network 
Integration Transmission service at the Network Integration (NT) rate.
1. Rate

------------------------------------------------------------------------
                                                                  Rate  
                Applicable months                 Daily period   (mills/
                                                                  kWh)  
------------------------------------------------------------------------
All Months of the Year..........................  All hours...     23.54
------------------------------------------------------------------------

2. Billing Factor
    Purchaser's Measured Energy.
3. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate.
4. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
4.1. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Conservation Surcharge....................................  II.A.       
Low Density Discount......................................  II.I.       
Phase-In Mitigation.......................................  II.L.       
Reactive Power Charge.....................................  II.N.       
------------------------------------------------------------------------

4.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------


[[Page 36479]]


C. PF Rates for Full Requirements Customers who Purchase Under a 
``1996'' Power Sales Contract and not on a Composite Rate Basis

    This customer category includes all Full Requirements customers 
whose forecasted loads exceed 25 aMW and those Full Requirements 
customers with forecasted loads of 25 aMW or less who decide not to 
purchase on a composite rate basis. Full Requirements Purchasers 
purchasing power under a 1996 power sales contract are required to 
buy Load Shaping, Load Regulation, and Network Integration Transmission 
service at the Network Integration (NT) rate.
1. Priority Firm Power
1.1. Rates
1.1.1. Demand Charge

------------------------------------------------------------------------
                  Applicable months                          Rate       
------------------------------------------------------------------------
All Months of the Year..............................  $0.56/kW-mo.      
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                                                          HLH      LLH  
                   Applicable months                      rate     rate 
------------------------------------------------------------------------
September-December....................................    22.20    19.64
January-March.........................................    23.02    20.28
April.................................................    20.65    19.46
May-June..............................................    13.61    10.78
July..................................................    15.90    12.79
August................................................    20.10    16.63
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
    For purchasers of 5-year power only.
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of:
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load or Purchaser's 5-year Demand 
Subscription.
1.2.2. HLH Billing Energy
    For purchasers of 5-year power only.
    Purchaser's HLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of:
    Purchaser's HLH Measured Energy or Purchaser's 5-year HLH Energy 
Subscription.
1.2.3. LLH Billing Energy
    For purchasers of 5-year power only.
    Purchaser's LLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of:
    Purchaser's LLH Measured Energy or Purchaser's 5-year LLH Energy 
Subscription.
2. Full Load Shaping
2.1. Rate
    0.30 mills/kWh.
2.2  Billing Factor
    Purchaser's Retail Load minus the Purchaser's Industrial Exemption, 
if any.
3. Load Regulation
3.1. Rate and Billing Factor
    0.25 mills/kWh multiplied by Purchaser's Retail Load.
4. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate.
5. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
5.1. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Conservation Surcharge....................................  II.A.       
Deviation Adjustment......................................  II.D.       
Industrial................................................              
Exemption/Curtailment                                       II.H.       
    Low Density Discount..................................  II.I.       
    Phase-In Mitigation...................................  II.L.       
    Reactive Power Charge.................................  II.N.       
------------------------------------------------------------------------

5.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------

D. PF Rates for Computed Requirements Customers Who Purchase Under a 
``1981'' Power Sales Contract

    Actual Computed Requirements Purchasers purchasing power under a 
``1981'' power sales contract are required to buy Load Shaping and 
Network Integration Transmission service at the Network Integration 
(NT) rate. Planned and Contracted Computed Requirements Purchasers are 
not allowed to buy Load Shaping. Load Regulation is required if the 
customer is in BPA's load control area, regardless of whether the 
customer is purchasing on the basis of actual, planned, or contracted 
computed requirements. Planned and Contracted Computed Requirements 
purchasers must elect either Network Integration Transmission service 
at the Network Integration (NT) rate or Point-to-Point Transmission 
service at the Point-to-Point (PTP) rate.
1. Priority Firm Power
1.1. Rates
1.1.1. Demand Charge

------------------------------------------------------------------------
                  Applicable months                          Rate       
------------------------------------------------------------------------
All Months of the Year..............................  $0.56/kW-mo.      
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                                                          HLH      LLH  
                   Applicable months                      rate     rate 
------------------------------------------------------------------------
September-December....................................    22.20    19.64
January-March.........................................    23.02    20.28
April.................................................    20.65    19.46
May-June..............................................    13.61    10.78
July..................................................    15.90    12.79
August................................................    20.10    16.63
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
1.2.1.1   With Load Shaping
    For purchasers of 5-year power only.
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of:
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load or Purchaser's 5-year Demand 
Subscription.
1.2.1.2  Without Load Shaping
    For purchasers of 5-year power only.
    Purchaser's 5-year Computed Peak Requirement.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of:
    Purchaser's Computed Peak Requirement or Purchaser's 5-year Demand 
Subscription.
1.2.2. Billing Energy
1.2.2.1  For purchasers of 5-year power only
For Energy Delivered September-March
    The HLH Billing Energy is the Purchaser's HLH Measured Energy.
    The LLH Billing Energy is:
    a. 76 percent of the Purchaser's Measured Energy, plus 24 percent 
of the Purchaser's Computed Energy Maximum, minus
    b. The Purchaser's HLH Measured Energy
For Energy Delivered April-August
    The HLH Billing Energy is the Purchaser's HLH Measured Energy.
    The LLH Billing Energy is:
    a. 63 percent of the Purchaser's Measured Energy, plus 37 percent 
of the 

[[Page 36480]]
Purchaser's Computed Energy Maximum, minus
    b. The Purchaser's HLH Measured Energy
1.2.2.2  For purchasers of a combination of 2-year and 5-year power
    The HLH Billing Energy is the lower of:
    Purchaser's HLH Computed Energy Maximum or
    Purchaser's 5-year HLH Energy Subscription.
    The LLH Billing Energy is the lower of:
    Purchaser's LLH Computed Energy Maximum or Purchaser's 5-year LLH 
Energy Subscription.
2. Full Load Shaping
2.1. Rate
    0.30 mills/kWh multiplied by the Utility Factor.
2.2. Billing Factor
    Purchaser's total HLH and LLH Billing Energy.
3. Load Regulation
3.1. Rate
    0.25 mills/kWh multiplied by the Utility Factor.
3.2. Billing Factor
    Purchaser's total HLH and LLH Billing Energy.
4. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate or the charge for Point-to-Point service under the Point-to-
Point (PTP) rate.
5. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
5.1. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Conservation Surcharge....................................  II.A.       
Energy Return Surcharge...................................  II.F.       
Low Density Discount......................................  II.I.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
Unauthorized Increase Charge..............................  II.Q.       
------------------------------------------------------------------------

5.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
Utility Factor............................................  II.R.       
------------------------------------------------------------------------

E. PF Rates for Partial Requirements Customers who Purchase Under a 
``1996'' Power Sales Contract

    Partial Requirements customers purchasing power under a 1996 power 
sales contract may purchase Load Shaping. All customers in BPA's load 
control area are required to buy Load Regulation, and customers outside 
of BPA's load control area may not buy Load Regulation. Partial 
Requirements customers must elect either Network Integration 
Transmission service at the Network Integration (NT) rate or Point-to-
Point Transmission service at the Point-to-Point (PTP) rate.
1. Priority Firm Power
1.1. Rates
1.1.1. Demand Charge

------------------------------------------------------------------------
                     Applicable months                          Rate    
------------------------------------------------------------------------
All Months of the Year....................................  $0.56/kW-mo.
------------------------------------------------------------------------

 1.1.2. Energy Charge

------------------------------------------------------------------------
                  Applicable months                   HLH rate  LLH rate
------------------------------------------------------------------------
September-December..................................     22.20     19.64
January-March.......................................     23.02     20.28
April...............................................     20.65     19.46
May-June............................................     13.61     10.78
July................................................     15.90     12.79
August..............................................     20.10     16.63
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
1.2.1.1  With Load Shaping
    For purchasers of 5-year power only.
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load.
    For purchasers of a combination of 2-year and 5-year power
    The lower of: Purchaser's Measured Demand that occurs during the 
hour of the Monthly Transmission Peak Load or Purchaser's 5-year Demand 
Subscription.
1.2.1.1  Without Load Shaping
    Purchaser's 5-year Demand Subscription.
1.2.2. HLH Billing Energy
    1.2.2.1  With Load Shaping
    For purchasers of 5-year power only.
    Purchaser's HLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of: Purchaser's HLH Measured Energy or Purchaser's 5-year 
HLH Energy Subscription.
1.2.2.2  Without Load Shaping
    Purchaser's 5-year HLH Energy Subscription.
1.2.3. LLH Billing Energy
1.2.3.1  With Load Shaping
    For purchasers of 5-year power only.
    Purchaser's LLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of: Purchaser's LLH Measured Energy or Purchaser's 5-year 
LLH Energy Subscription.
1.2.3.2  Without Load Shaping
    Purchaser's 5-year LLH Energy Subscription.
2. Full Load Shaping
2.1  Rate
    0.30 mills/kWh.
2.2  Billing Factor
    Purchaser's Retail Load minus the Purchaser's Industrial Exemption, 
if any.
3. Load Regulation
3.1  Rate and Billing Factor
    0.25 mills/kWh multiplied by Purchaser's Retail Load.
4. Partial Load Shaping
4.1  Rate
    $3.05/MWhr-hr.
4.2  Billing Factor
    MWhr-hr amount of Partial Load Shaping Subscribed for the month.
5. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate or the charge for Point-to-Point service under the Point-to-
Point (PTP) rate.
6. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
6.1. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Conservation Surcharge....................................  II.A.       
Deviation Adjustment......................................  II.D.       
Industrial Exemption/Curtailment..........................  II.H.       
Low Density Discount......................................  II.I.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
------------------------------------------------------------------------

6.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special Rate Provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------

 
[[Page 36481]]


Schedule NR-96.2

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 for a 2-year 
period, October 1, 1996, through September 30, 1998. New Resource Firm 
Power is available to investor-owned utilities (IOUs) under net 
requirements contracts for resale to ultimate consumers. New Resource 
Firm Power also is available to any public body, cooperative, or 
Federal agency to the extent such power is needed to serve any New 
Large Single Load (NLSL), as defined by the Northwest Power Act. Any 
power purchased by a customer to serve its New Large Single Load(s) 
must be purchased under either this rate schedule or under the NR-96.5 
rate schedule.
    Rates in this schedule are applicable to purchases under 
requirements sales contracts effective on or before September 30, 1996 
(hereinafter termed the ``1981'' contracts, although some are actually 
dated ``1984'' or later), and under contracts that may be effective on 
or after October 1, 1996 (``1996'' contracts). Customers purchasing 
power under ``1981'' contracts may buy either firm power or capacity 
without energy under this rate schedule. Customers purchasing power 
under ``1996'' contracts may buy only firm power. Products available 
under this rate schedule are defined in BPA's General Rate Schedule 
Provisions (GRSPs). Rates under contracts that contain charges that 
escalate based on rates listed in this rate schedule shall include 
applicable transmission charges.
    This schedule supersedes Schedule NR-95, which went into effect on 
October 1, 1995. Sales under this schedule are subject to BPA's General 
Rate Schedule Provisions. For sales under this rate schedule, bills 
shall be rendered and payments due pursuant to BPA's Billing 
Procedures.

Section II. Rates, Billing Factors, and Adjustments for Each NR Product

    For each customer designation, the rate(s) for each product along 
with the associated billing factor(s) are identified below. The rates 
for each customer designation are identical; the billing factors, 
however, vary according to the customer designation. Applicable 
adjustments and special rate provisions are listed for each customer 
designation. Network Integration transmission service at the Network 
Integration (NT) rate or Point-to-Point transmission service at the 
Point-to-Point (PTP) rate is required for purchases under this rate 
schedule.
    This rate schedule contains four subsections, corresponding to the 
customer categories to which this rate schedule applies:

Section II.A Applies to public agency Metered Requirements customers 
who purchase under ``1981'' power sales contracts and serve new large 
single loads.
Section II.B Applies to Full Requirements customers who purchase under 
``1996'' power sales contracts.
Section II.C Applies to Computed Requirements customers who purchase 
under ``1981'' power sales contracts.
Section II.D Applies to Partial Requirements customers who purchase 
under ``1996'' power sales contracts.

A. NR Rates for Metered Requirements Customers Who Purchase Under 
``1981'' Power Sales Contracts and Serve New Large Single Loads

    Metered Requirements customers purchasing power under a ``1981'' 
power sales contract serving a New Large Single Load (NLSL) are 
required to buy New Resource Firm Power (as needed for that NLSL), Load 
Shaping, Load Regulation, and Network Integration Transmission service 
at the Network Integration (NT) rate.
1. New Resource Firm Power
1.1. Rates
1.1.1. Demand Charge

------------------------------------------------------------------------
                 Applicable months                          Rate        
------------------------------------------------------------------------
All Months of the Year............................  $0.56/kW-mo.        
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                  Applicable months                   HLH Rate  LLH Rate
------------------------------------------------------------------------
September-December..................................     36.61     32.39
January-March.......................................     37.97     33.45
April...............................................     34.05     32.09
May-June............................................     22.45     17.78
July................................................     26.22     21.09
August..............................................     33.15     27.42
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
    Purchaser's Measured Demand.
1.2.2. HLH Billing Energy
    Purchaser's HLH Measured Energy.
1.2.3. LLH Billing Energy
    Purchaser's LLH Measured Energy.
2. Full Load Shaping
    For Purchasers whose Requirements Service is Provided Exclusively 
under the NR Rate
Rate
    0.30 mills/kWh multiplied by the Utility Factor.
Billing Factor
    Purchaser's HLH and LLH Measured Energy.
    For Purchasers whose Requirements Service is Provided under Both 
the PF and NR Rates.
    There is no charge for Load Shaping under the NR rate schedule.
3. Load Regulation
    For Purchasers whose Requirements Service is Provided Exclusively 
under the NR Rate.
Rate
    0.25 mills/kWh multiplied by the Utility Factor.
Billing Factor
    Purchaser's HLH and LLH Measured Energy.
    For Purchasers whose Requirements Service is Provided under Both 
the PF and NR Rates.
    There is no charge for Load Regulation under the NR rate schedule.
4. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate.
5. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
5.1. Rate Adjustments

------------------------------------------------------------------------
                      Rate Adjustment                          Section  
------------------------------------------------------------------------
Conservation Surcharge....................................  II.A.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
Transitional Service......................................  II.P.       
------------------------------------------------------------------------

5.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
Utility Factor............................................  II.R.       
------------------------------------------------------------------------

B. NR Rates For Full Requirements Customers Who Purchase Under ``1996'' 
Power Sales Contracts

    Full Requirements Purchasers purchasing power under a ``1996'' 
power sales contract are required to buy 

[[Page 36482]]
Load Shaping, Load Regulation, and Network Integration Transmission 
service at the Network Integration (NT) rate.
1. New Resource Firm Power
1.1. Rates
1.1.1. Demand Charge

------------------------------------------------------------------------
                       Applicable months                          Rate  
------------------------------------------------------------------------
All Months of the Year........................................  $0.56/kW-
                                                                     mo.
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                  Applicable months                   HLH Rate  LLH rate
------------------------------------------------------------------------
September--December.................................     36.61     32.39
January--March......................................     37.97     33.45
April...............................................     34.05     32.09
May--June...........................................     22.45     17.78
July................................................     26.22     21.09
August..............................................     33.15     27.42
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
    Purchaser's Measured Demand.
1.2.2. HLH Billing Energy
    Purchaser's HLH Measured Energy.
1.2.3. LLH Billing Energy
    Purchaser's LLH Measured Energy.
2. Full Load Shaping
2.1. Rate and Billing Factor
    For Purchasers whose Requirements Service is Provided Exclusively 
under the NR Rate.
    0.30 mills/kWh multiplied by Retail Load minus Industrial 
Exemption, if any.
    For Purchasers whose Requirements Service is Provided under Both 
the PF and NR Rates.
    There is no charge for Load Shaping under the NR rate schedule.
3. Load Regulation
3.1. Rate and Billing Factor
    For Purchasers whose Requirements Service is Provided Exclusively 
under the NR Rate.
    0.25 mills/kWh multiplied by Retail Load.
    For Purchasers whose Requirements Service is Provided under Both 
the PF and NR Rates.
    There is no charge for Load Regulation under the NR rate schedule.
4. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate.
5. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
    5.1. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Conservation Surcharge....................................  II.A.       
Deviation Adjustment......................................  II.D.       
Industrial Exemption/Curtailment..........................  II.H.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
------------------------------------------------------------------------

5.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------

C. NR Rates for Computed Requirements Customers who Purchase Under 
``1981'' Power Sales Contracts

    Actual Computed Requirements Purchasers purchasing power under a 
``1981'' power sales contract are required to buy Load Shaping and 
Network Integration Transmission service at the Network Integration 
(NT) rate. Planned and Contracted Computed Requirements Purchasers are 
not allowed to buy Load Shaping, and must elect either Network 
Integration Transmission service at the Network Integration (NT) rate 
or Point-to-Point Transmission service at the Point-To-Point (PTP) 
rate. Load Regulation is required if the customer is in BPA's load 
control area.
1. New Resource Firm Power
1.1. Rates
1.1.1. Demand Charge

------------------------------------------------------------------------
                 Applicable months                          Rate        
------------------------------------------------------------------------
All Months of the Year............................  $0.56/kW-mo.        
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                  Applicable months                   HLH rate  LLH rate
------------------------------------------------------------------------
September-December..................................     36.61     32.39
January-March.......................................     37.97     33.45
April...............................................     34.05     32.09
May-June............................................     22.45     17.78
July................................................     26.22     21.09
August..............................................     33.15     27.42
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand With Load Shaping
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load.
Without Load Shaping
    Purchaser's Computed Peak Requirement.
1.2.2. Billing Energy
1.2.2.1  For Energy Delivered September-March
    The HLH Billing Energy is the Purchaser's HLH Measured Energy.
    The LLH Billing Energy is:
    a. 55 percent of the Purchaser's Measured Energy, plus 45 percent 
of the Purchaser's Computed Energy Maximum, minus
    b. The Purchaser's HLH Measured Energy
1.2.2.2   For Energy Delivered April-August
    The HLH Billing Energy is the Purchaser's Measured Energy.
    The LLH Billing Energy is:
    a. 43 percent of the Purchaser's Measured Energy, plus 57 percent 
of the Purchaser's Computed Energy Maximum, minus
    b. The Purchaser's HLH Measured Energy
2. Firm Capacity Without Energy
2.1. Rate

------------------------------------------------------------------------
                 Applicable months                          Rate        
------------------------------------------------------------------------
September-December................................  $1.47/kW-mo.        
January-March.....................................  $1.54/kW-mo.        
April.............................................  $0.98/kW-mo.        
May-June..........................................  $1.57/kW-mo.        
July..............................................  $1.67/kW-mo.        
August............................................  $1.80/kW-mo.        
------------------------------------------------------------------------

2.2. Billing Factor
    Purchaser's Computed Peak Requirement associated with the purchase 
of Firm Capacity Without Energy.
3. Full Load Shaping
    For Purchasers whose Requirements Service is Provided Exclusively 
under the NR Rate.
Rate
    0.30 mills/kWh multiplied by the Utility Factor.
Billing Factor
    Purchaser's HLH and LLH Measured Energy.
    For Purchasers whose Requirements Service is Provided under Both 
the PF and NR Rates.
    There is no charge for Load Shaping under the NR rate schedule.
4. Load Regulation
    For Purchasers whose Requirements Service is Provided Exclusively 
under the NR Rate. 

[[Page 36483]]

Rate
    0.25 mills/kWh multiplied by the Utility Factor.
Billing Factor
    Purchaser's HLH and LLH Measured Energy.
    For Purchasers whose Requirements Service is Provided under Both 
the PF and NR Rates.
    There is no charge for Load Regulation under the NR rate schedule.
5. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate or the charge for Point-to-Point service under the Point-to-
Point (PTP) rate.
6. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
6.1. Rate Adjustments

------------------------------------------------------------------------
                     Rate adjustments                          Section  
------------------------------------------------------------------------
Conservation Surcharge....................................  II.A.       
Energy Return Surcharge...................................  II.F.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
Transitional Service......................................  II.P.       
Unauthorized Increase Charge..............................  II.Q.       
------------------------------------------------------------------------

6.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
Utility Factor............................................  II.R.       
------------------------------------------------------------------------

D. NR Rates for Partial Requirements Customers who Purchase Under 
``1996'' Power Sales Contracts

    Partial Requirements customers purchasing power under a ``1996'' 
power sales contract may purchase Load Shaping and must elect either 
Network Integration Transmission service at the Network Integration 
(NT) rate or Point-to-Point Transmission service at the Point-to-Point 
(PTP) rate. All customers in BPA's load control area are required to 
buy Load Regulation, and customers outside of BPA's load control area 
may not buy Load Regulation.
1. New Resource Firm Power
1.1. Rates
1.1.1  Demand Charge

------------------------------------------------------------------------
                 Applicable months                          Rate        
------------------------------------------------------------------------
All Months of the Year............................  $0.56/kW-mo.        
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                  Applicable months                   HLH rate  LLH rate
------------------------------------------------------------------------
September-December..................................     36.61     32.39
January-March.......................................     37.97     33.45
April...............................................     34.05     32.09
May-June............................................     22.45     17.78
July................................................     26.22     21.09
August..............................................     33.15     27.42
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
    With Load Shaping: Purchaser's Measured Demand that occurs during 
the hour of the Monthly Transmission Peak Load.
    Without Load Shaping: Purchaser's Demand Subscription.
1.2.2. HLH Billing Energy
    With Load Shaping: Purchaser's HLH Measured Energy.
    Without Load Shaping:
    Purchaser's HLH Energy Subscription.
1.2.3. LLH Billing Energy
    With Load Shaping:
    Purchaser's LLH Measured Energy.
    Without Load Shaping:
    Purchaser's LLH Energy Subscription.
2. Full Load Shaping
2.1. Rate and Billing Factor
    For Purchasers whose Requirements Service is Provided Exclusively 
under the NR Rate.
    0.30 mills/kWh multiplied by Retail Load minus Industrial 
Exemption, if any.
    For Purchasers whose Requirements Service is Provided under Both 
the PF and NR Rates.
    There is no charge for Load Shaping under the NR rate schedule.
3. Load Regulation
3.1. Rate and Billing Factor
    For Purchasers whose Requirements Service is Provided Exclusively 
under the NR Rate.
    0.25 mills/kWh multiplied by Retail Load.
    For Purchasers whose Requirements Service is Provided under Both 
the PF and NR Rates .
    There is no charge for Load Regulation under the NR rate schedule.
4. Partial Load Shaping
4.1 Rate
    $3.05 per MWhr-hr.
4.2 Billing Factor
    MWhr-hr amount of Partial Load Shaping Subscribed for the month.
5. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate or the charge for Point-to-Point service under the Point-to-
Point (PTP) rate.
6.  Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
6.1.  Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Conservation Surcharge....................................  II.A.       
Deviation Adjustment......................................  II.D.       
Industrial Exemption/Curtailment..........................  II.H.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
------------------------------------------------------------------------

6.2.  Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provision                       Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------

Schedule NR-96.5--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 for a 5-year 
period, October 1, 1996, through September 30, 2001. New Resource Firm 
Power is available to investor-owned utilities (IOUs) under net 
requirements contracts for resale to ultimate consumers. At their 
election, IOUs may purchase all or any designated portion of their 
power under this rate schedule as an alternative to purchasing power 
under the NR-96.2 rate schedule. IOU customers making such an election 
shall agree to purchase the designated amount of power exclusively from 
BPA for 5 years. New Resource Firm Power also is available to any 
public body, cooperative, or Federal agency to the extent such power is 
needed to serve any New Large Single Load (NLSL), as defined by the 
Northwest Power Act. Any power purchased by a customer to serve its New 
Large Single Load(s) must be purchased under either this rate schedule 
or under the NR-96.2 rate schedule. Public body, cooperative, or 
Federal agency customers electing to be served under this rate schedule 
shall agree to purchase power for service to the designated consumer 
NLSL facilities exclusively from BPA for 5 years. Such election by IOUs 
or preference customers shall be a one-time irrevocable election and, 
as to the 

[[Page 36484]]
amount of power so designated, shall constitute a waiver of all rights 
to purchase power under any other power rate schedule for the 5-year 
period. The election process is described in section II.E. of the 
GRSPs.
    Rates in this schedule are available for purchases under 
requirements sales contracts effective on or before September 30, 1996 
(hereinafter termed the ``1981'' contracts, although some are actually 
dated ``1984'' or later), and under contracts that may be effective on 
or after October 1, 1996 (``1996'' contracts). Customers electing to 
purchase power under this rate schedule and continuing to receive 
service pursuant to their 1981 power sales contract further waive any 
rights under that contract to modify their Firm Resources Exhibit in 
such a manner that reduces or interferes with their ability to purchase 
the amount of power dedicated for service under this rate schedule. 
Rates under contracts that contain charges that escalate based on rates 
listed in this rate schedule shall include applicable transmission 
charges.
    Products available under this rate schedule are defined in BPA's 
General Rate Schedule Provisions (GRSPs).
    Sales under this schedule are subject to BPA's General Rate 
Schedule Provisions. For sales under this rate schedule, bills shall be 
rendered and payments due pursuant to BPA's Billing Procedures.

Section II. Rates, Billing Factors, and Adjustments for Each NR Product

    For each customer designation, the rate(s) for each product along 
with the associated billing factor(s) are identified below. The rates 
for each customer designation are identical; the billing factors, 
however, vary according to the customer designation. Applicable 
adjustments and special rate provisions are listed for each customer 
designation. Network Integration transmission service at the Network 
Integration (NT) rate or Point-to-Point transmission service at the 
Point-to-Point (PTP) rate is required for purchases under this rate 
schedule.
    This rate schedule contains five subsections, corresponding to the 
customer categories to which this rate schedule applies:
    Section II.A  Applies to public agency Metered Requirements 
customers who purchase under ``1981'' power sales contracts and serve 
new large single loads.
    Section II.B  Applies to Full Requirements customers who purchase 
under ``1996'' power sales contracts.
    Section II.C  Applies to Computed Requirements customers who 
purchase under ``1981'' power sales contracts.
    Section II.D  Applies to Partial Requirements customers who 
purchase under ``1996'' power sales contracts.

A. NR Rates for Metered Requirements Customers who Purchase Under 
``1981'' Power Sales Contracts and Serve New Large Single Loads

    Metered Requirements customers purchasing power under a ``1981'' 
power sales contract serving a New Large Single Load (NLSL) are 
required to buy New Resource Firm Power (as needed for that NLSL), Load 
Shaping, Load Regulation, and Network Integration Transmission service 
at the Network Integration (NT) rate.
1. New Resource Firm Power
1.1. Rates
1.1.1. Demand Charge

------------------------------------------------------------------------
                  Applicable months                          Rate       
------------------------------------------------------------------------
All Months of the Year..............................  $0.56/kW-mo.      
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                                                          HLH      LLH  
                   Applicable months                      rate     rate 
------------------------------------------------------------------------
September-December....................................    36.61    32.39
January-March.........................................    37.97    33.45
April.................................................    34.05    32.09
May-June..............................................    22.45    17.78
July..................................................    26.22    21.09
August................................................    33.15    27.42
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
    Purchaser's Measured Demand.
1.2.2. HLH Billing Energy
    Purchaser's HLH Measured Energy.
1.2.3. LLH Billing Energy
    Purchaser's LLH Measured Energy.
2. Full Load Shaping
    For Purchasers whose Requirements Service is Provided Exclusively 
under the NR Rate.
Rate
    0.30 mills/kWh multiplied by the Utility Factor.
Billing Factor
    Purchaser's HLH and LLH Measured Energy.
    For Purchasers whose Requirements Service is Provided under Both 
the PF and NR Rates.
    There is no charge for Load Shaping under the NR rate schedule.
3. Load Regulation
    For Purchasers whose Requirements Service is Provided Exclusively 
under the NR Rate.
Rate
    0.25 mills/kWh multiplied by the Utility Factor.
Billing Factor
    Purchaser's HLH and LLH Measured Energy.
    For Purchasers whose Requirements Service is Provided under Both 
the PF and NR Rates.
    There is no charge for Load Regulation under the NR rate schedule.
4. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate.
5. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
5.1. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Conservation Surcharge....................................  II.A.       
Phase-In Mitigation.......................................  II.L.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
Transitional Service......................................  II.P.       
------------------------------------------------------------------------

5.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
Utility Factor............................................  II.R.       
------------------------------------------------------------------------

B. NR Rates for Full Requirements Customers Who Purchase Under ``1196'' 
Power Sales Contracts

    Full Requirements Purchasers purchasing power under a ``1996'' 
power sales contract are required to buy Load Shaping, Load Regulation, 
and Network Integration Transmission service at the Network Integration 
(NT) rate.

1. New Resource Firm Power

1.1. Rates
1.1.1. Demand Charge

------------------------------------------------------------------------
                  Applicable months                          Rate       
------------------------------------------------------------------------
All Months of the Year..............................  $0.56/kW-mo.      
------------------------------------------------------------------------


[[Page 36485]]


1.1.2. Energy Charge

------------------------------------------------------------------------
                                                          HLH      LLH  
                   Applicable months                      rate     rate 
------------------------------------------------------------------------
September-December....................................    36.61    32.39
January-March.........................................    37.97    33.45
April.................................................    34.05    32.09
May-June..............................................    22.45    17.78
July..................................................    26.22    21.09
August................................................    33.15    27.42
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
    Purchaser's Measured Demand.
1.2.2. HLH Billing Energy
    Purchaser's HLH Measured Energy.
1.2.3. LLH Billing Energy
    Purchaser's LLH Measured Energy.
2. Full Load Shaping
2.1. Rate and Billing Factor
    For Purchasers whose Requirements Service is Provided Exclusively 
under the NR Rate.
    0.30 mills/kWh multiplied by Retail Load minus Industrial 
Exemption, if any.
    For Purchasers whose Requirements Service is Provided under Both 
the PF and NR Rates.
    There is no charge for Load Shaping under the NR rate schedule.
3. Load Regulation
3.1. Rate and Billing Factor
    For Purchasers whose Requirements Service is Provided Exclusively 
under the NR Rate.
    0.25 mills/kWh multiplied by Retail Load.
    For Purchasers whose Requirements Service is Provided under Both 
the PF and NR Rates.
    There is no charge for Load Regulation under the NR rate schedule.
4. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate.
5. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
5.1. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Conservation Surcharge....................................  II.A.       
Deviation Adjustment......................................  II.D.       
Industrial Exemption/Curtailment..........................  II.H.       
Phase-In Mitigation.......................................  II.L.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
------------------------------------------------------------------------

5.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------

C. NR Rates for Computed Requirements Customers Who Purchase Under 
``1981'' Power Sales Contracts

    Actual Computed Requirements Purchasers purchasing power under a 
``1981'' power sales contract are required to buy New Resource Firm 
Power (as needed), Load Shaping, and Network Integration Transmission 
service at the Network Integration (NT) rate. Planned and Contracted 
Computed Requirements Purchasers are not allowed to buy Load Shaping, 
and must elect either Network Integration Transmission service at the 
Network Integration (NT) rate or Point-to-Point Transmission service at 
the Point-to-Point (PTP) rate. Load Regulation is required if the 
customer is in BPA's load control area.
1. New Resource Firm Power
1.1. Rates
1.1.1. Demand Charge

------------------------------------------------------------------------
                  Applicable months                          Rate       
------------------------------------------------------------------------
All Months of the Year..............................  $0.56/kW-mo.      
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                                                          HLH      LLH  
                   Applicable months                      rate     rate 
------------------------------------------------------------------------
September-December....................................    36.61    32.39
January-March.........................................    37.97    33.45
April.................................................    34.05    32.09
May-June..............................................    22.45    17.78
July..................................................    26.22    21.09
August................................................    33.15    27.42
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
    With Load Shaping:
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load.
    Without Load Shaping:
    Purchaser's Computed Peak Requirement.
1.2.2. Billing Energy
1.2.2.1  For Energy Delivered September-March
    The HLH Billing Energy is the Purchaser's HLH Measured Energy.
    The LLH Billing Energy is:
    a. 55 percent of the Purchaser's Measured Energy, plus 45 percent 
of the Purchaser's Computed Energy Maximum, minus
    b. The Purchaser's HLH Measured Energy.
1.2.2.2  For Energy Delivered April-August
    The HLH Billing Energy is the Purchaser's Measured Energy.
    The LLH Billing Energy is:
    a. 43 percent of the Purchaser's Measured Energy, plus 57 percent 
of the Purchaser's Computed Energy Maximum, minus
    b. The Purchaser's HLH Measured Energy.
2. Full Load Shaping
    For Purchasers whose Requirements Service is Provided Exclusively 
under the NR Rate.
Rate
    0.30 mills/kWh multiplied by the Utility Factor.
Billing Factor
    Purchaser's HLH and LLH Measured Energy.
    For Purchasers whose Requirements Service is Provided under Both 
the PF and NR Rates.
    There is no charge for Load Shaping under the NR rate schedule.
3. Load Regulation
    For Purchasers whose Requirements Service is Provided Exclusively 
under the NR Rate.
Rate
    0.25 mills/kWh multiplied by the Utility Factor.
Billing Factor
    Purchaser's HLH and LLH Measured Energy.
    For Purchasers whose Requirements Service is Provided under Both 
the PF and NR Rates.
    There is no charge for Load Regulation under the NR rate schedule.
4. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate or the charge for Point-to-Point service under the Point-to-
Point (PTP) rate.
5. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
5.1. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Conservation Surcharge....................................  II.A.       
Energy Return Surcharge...................................  II.F.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       

[[Page 36486]]
                                                                        
Transitional Service......................................  II.P.       
Unauthorized Increase Charge..............................  II.Q.       
------------------------------------------------------------------------



5.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
Utility Factor............................................  II.R.       
------------------------------------------------------------------------

D. NR Rates for Partial Requirements Customers who Purchase Under 
``1996'' Power Sales Contracts

    Partial Requirements customers purchasing power under a ``1996'' 
power sales contract may purchase New Resource Firm Power (as needed) 
and Load Shaping, and must elect either Network Integration 
Transmission service at the Network Integration (NT) rate or Point-to-
Point Transmission service at the Point-to-Point (PTP) rate. All 
customers in BPA's load control area are required to buy Load 
Regulation, and customers outside of BPA's load control area may not 
buy Load Regulation.
1. New Resource Firm Power
1.1. Rates
1.1.1  Demand Charge

------------------------------------------------------------------------
                  Applicable months                          Rate       
------------------------------------------------------------------------
All Months of the Year..............................  $0.56/kW-mo.      
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                                                          HLH      LLH  
                   Applicable months                      rate     rate 
------------------------------------------------------------------------
September-December....................................    36.61    32.39
January-March.........................................    37.97    33.45
April.................................................    34.05    32.09
May-June..............................................    22.45    17.78
July..................................................    26.22    21.09
August................................................    33.15    27.42
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
    With Load Shaping:
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load.
    Without Load Shaping:
    Purchaser's Demand Subscription.
1.2.2. HLH Billing Energy
    With Load Shaping:
    Purchaser's HLH Measured Energy.
    Without Load Shaping:
    Purchaser's HLH Energy Subscription.
1.2.3. LLH Billing Energy
    With Load Shaping:
    Purchaser's LLH Measured Energy.
    Without Load Shaping:
    Purchaser's LLH Energy Subscription.
2. Full Load Shaping
2.1. Rate and Billing Factor
    For Purchasers whose Requirements Service is Provided Exclusively 
under the NR Rate.
    0.30 mills/kWh multiplied by Retail Load minus Industrial 
Exemption, if any.
    For Purchasers whose Requirements Service is Provided under Both 
the PF and NR Rates.
    There is no charge for Load Shaping under the NR rate schedule.
3. Load Regulation
3.1. Rate and Billing Factor
    For Purchasers whose Requirements Service is Provided Exclusively 
under the NR Rate.
    0.25 mills/kWh multiplied by Retail Load minus Industrial 
Exemption, if any.
    For Purchasers whose Requirements Service is Provided under Both 
the PF and NR Rates.
    There is no charge for Load Regulation under the NR rate schedule.
4. Partial Load Shaping
4.1 Rate
    $3.05/MWhr-hr.
4.2 Billing Factor
    MWhr-hr amount of Partial Load Shaping Subscribed for the month.
5. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate or the charge for Point-to-Point service under the Point-to-
Point (PTP) rate.
6. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
6.1. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Conservation Surcharge....................................  II.A.       
Deviation Adjustment......................................  II.D.       
Industrial Exemption/Curtailment..........................  II.H.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
------------------------------------------------------------------------

6.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------

Schedule IP-96.2--Industrial Firm Power Rate

Section I. Availability

    This schedule is available to BPA's direct-service industrial (DSI) 
customers for firm power to be used in their industrial operations for 
a 2-year period, October 1, 1996, through September 30, 1998. If a DSI 
requests that BPA serve a portion of its load under another rate 
schedule and if BPA agrees, the IP-96.2 rate shall apply to only that 
portion of its load that is not served under the other schedule.
    Both DSIs that purchase power under power sales contracts that were 
effective on or before September 30, 1996 (hereinafter termed the 
``1981'' contracts), and DSIs that purchase power under new contracts 
(hereinafter termed the ``1996'' contracts) are eligible to purchase 
under this rate schedule. Products available under this rate schedule 
are defined in BPA's General Rate Schedule Provisions (GRSPs). Rates 
under contracts that contain charges that escalate based on rates 
listed in this rate schedule shall include applicable transmission 
charges.
    This rate schedule supersedes Schedule IP-95, which went into 
effect on October 1, 1995. Sales under the IP-96.2 rate schedule are 
subject to BPA's General Rate Schedule Provisions. For sales under this 
rate schedule, bills shall be rendered and payments shall be due 
pursuant to BPA's Billing Procedures.

Section II. Rates, Billing Factors, and Adjustments for Each IP Product

    For each customer designation, the rate(s) for each product along 
with the associated billing factor(s) are identified in separate 
sections of the rate schedule. The rates for each customer designation 
are identical; the billing factors, however, vary according to the 
customer designation. Applicable adjustments and special rate 
provisions are listed for each customer designation. Under the power 
sales contracts, the DSIs provide operating reserves and stability 
reserves. The credit for these reserves is reflected in the level of 
the applicable energy charges specified in this rate schedule. Network 
Integration transmission service at the Network Integration (NT) rate 
or Point-to-Point transmission service at the Point-to-Point (PTP) rate 
is required for purchases under this rate schedule.
    This rate schedule contains three subsections, corresponding to the 
customer categories to which this rate schedule applies:
    Section II.A  Applies to DSI purchasers who purchase under ``1981'' 
power sales contracts. 

[[Page 36487]]

    Section II.B  Applies to Full Requirements DSI purchasers who 
purchase under ``1996'' contracts.
    Section II.C  Applies to Partial Requirements DSI purchasers who 
purchase under ``1996'' contracts.

A. IP Rates for DSI Purchasers who Purchase Under ``1981'' Power Sales 
Contracts

    DSI Purchasers purchasing power under a ``1981'' power sales 
contract are required to buy Load Regulation and either Network 
Integration Transmission service at the Network Integration (NT) rate 
or Point-to-Point Transmission service at the Point-to-Point (PTP) 
rate.
1. Industrial Firm Power
1.1. Rates
1.1.1. Demand Charge

------------------------------------------------------------------------
                     Applicable months                          Rate    
------------------------------------------------------------------------
All Months of the Year....................................  $0.56/kW-mo.
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                                                          HLH      LLH  
                   Applicable months                      rate     rate 
------------------------------------------------------------------------
September--December...................................    22.29    19.72
January--March........................................    23.11    20.36
April.................................................    20.73    19.54
May--June.............................................    13.67    10.82
July..................................................    15.96    12.84
August................................................    20.18    16.69
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
    For purchasers of 2-year power only.
    Purchaser's BPA Operating Level that occurs during the hour of the 
Monthly Transmission Peak Load.
    For purchasers of a combination of 2-year and 5-year power.
    Purchaser's BPA Operating Level that occurs during the hour of the 
Monthly Transmission Peak Load minus the Purchaser's 5-year Billing 
Demand.
1.2.2. HLH Billing Energy
    For purchasers of 2-year power only.
    Purchaser's HLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    Purchaser's HLH Measured Energy minus the Purchaser's 5-year HLH 
Billing Energy.
1.2.3. LLH Billing Energy
    For purchasers of 2-year power only.
    Purchaser's LLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    Purchaser's LLH Measured Energy minus the Purchaser's 5-year LLH 
Billing Energy.
2. Load Regulation
2.1. Rate and Billing Factor
    For purchasers of 2-year power only.
    0.25 mills/kWh multiplied by Purchaser's Retail Load.
    For purchasers of a combination of 2-year and 5-year power.
    There is no charge for Load Regulation under the IP-96.2 rate 
schedule.
3. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate or the charge for Point-to-Point service under the Point-to-
Point (PTP) rate.
4. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
4.1. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Curtailment Charge........................................  II.C.       
Operating Reserves Adjustment.............................  II.K.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
Transitional Service......................................  II.P.       
Unauthorized Increase Charge..............................  II.Q.       
------------------------------------------------------------------------

4.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------

B. IP Rates for Full Requirements DSI Purchasers who Purchase Under 
``1996'' Power Sales Contracts

    Full Requirements customers purchasing power under a ``1996'' power 
sales contract are required to buy Load Shaping, Load Regulation, and 
either Network Integration Transmission service at the Network 
Integration (NT) rate or Point-to-Point Transmission service at the 
Point-to-Point (PTP) rate.
1. Industrial Firm Power
1.1. Rates
1.1.1. Demand Charge

------------------------------------------------------------------------
                  Applicable months                          Rate       
------------------------------------------------------------------------
All Months of the Year..............................  $0.56/kW-mo.      
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                                                          HLH      LLH  
                   Applicable months                      rate     rate 
------------------------------------------------------------------------
September--December...................................    22.29    19.72
January--March........................................    23.11    20.36
April.................................................    20.73    19.54
May-June..............................................    13.67    10.82
July..................................................    15.96    12.84
August................................................    20.18    16.69
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
    For purchasers of 2-year power only.
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load.
    For purchasers of a combination of 2-year and 5-year power.
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load minus the Purchaser's 5-year Billing 
Demand.
1.2.2. HLH Billing Energy
    For purchasers of 2-year power only.
    Purchaser's HLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power
    Purchaser's HLH Measured Energy minus the Purchaser's 5-year HLH 
Billing Energy.
1.2.3. LLH Billing Energy
    For purchasers of 2-year power only.
    Purchaser's LLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    Purchaser's LLH Measured Energy minus the Purchaser's 5-year LLH 
Billing Energy.
2. DSI Load Shaping
2.1. Rate
    $187/aMW.
2.2 Billing Factor
    For purchasers of 2-year power only.
    Purchaser's Calculated Energy Capacity minus the Purchaser's 
Industrial Exemption, if any.
    For purchasers of a combination of 2-year and 5-year power.
    There is no charge for Load Shaping under the IP-96.2 rate 
schedule.
3. Load Regulation
3.1. Rate and Billing Factor
    For purchasers of 2-year power only.
    0.25 mills/kWh multiplied by Purchaser's Retail Load.
    For purchasers of a combination of 2-year and 5-year power.
    There is no charge for Load Regulation under the IP-96.2 rate 
schedule.
4. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the 

[[Page 36488]]
Network Integration (NT) rate or the charge for Point-to-Point service 
under the Point-to-Point (PTP) rate.
5. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
5.1. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Industrial Exemption/Curtailment..........................  II.H.       
Operating Reserves Adjustment.............................  II.K.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
Unauthorized Increase Charge..............................  II.Q.       
------------------------------------------------------------------------

5.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------

C. IP Rates for Partial Requirements DSI Purchasers who Purchase Under 
``1996'' Power Sales Contracts

    Partial Requirements customers purchasing power under a ``1996'' 
power sales contract may purchase Load Shaping. All customers in BPA's 
load control area are required to buy Load Regulation, and customers 
outside of BPA's load control area may not buy Load Regulation. Partial 
Requirements customers must elect either Network Integration 
Transmission service at the Network Integration (NT) rate or Point-to-
Point Transmission service at the Point-to-Point (PTP) rate.
1. Industrial Firm Power
1.1. Rates
1.1.1. Demand Charge

------------------------------------------------------------------------
                  Applicable months                          Rate       
------------------------------------------------------------------------
All Months of the Year..............................  $0.56/kW-mo.      
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                                                          HLH      LLH  
                   Applicable months                      rate     rate 
------------------------------------------------------------------------
September-December....................................    22.29    19.72
January-March.........................................    23.11    20.36
April.................................................    20.73    19.54
May-June..............................................    13.67    10.82
July..................................................    15.96    12.84
August................................................    20.18    16.69
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
1.2.1.1  With Load Shaping
    For purchasers of 2-year power only.
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load.
    For purchasers of a combination of 2-year and 5-year power.
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load minus the Purchaser's 5-year Billing 
Demand.
1.2.1.1  Without Load Shaping
    Purchaser's 2-year Demand Subscription.
1.2.2. HLH Billing Energy
1.2.2.1  With Load Shaping
    For purchasers of 2-year power only.
    Purchaser's HLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    Purchaser's HLH Measured Energy minus the Purchaser's 5-year HLH 
Billing Energy.
1.2.2.2  Without Load Shaping
    Purchaser's 2-year HLH Energy Subscription.
1.2.3. LLH Billing Energy
1.2.3.1  With Load Shaping
    For purchasers of 2-year power only.
    Purchaser's LLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    Purchaser's LLH Measured Energy minus the Purchaser's 5-year LLH 
Billing Energy.
1.2.3.2  Without Load Shaping
    Purchaser's 2-year LLH Energy Subscription.
2. DSI Load Shaping
2.1  Rate
    $187/aMW.
2.2  Billing Factor
    For purchasers of 2-year power only.
    Purchaser's Calculated Energy Capacity minus the Purchaser's 
Industrial Exemption, if any.
    For purchasers of a combination of 2-year and 5-year power.
    There is no charge for Load Shaping under the IP-96.2 rate 
schedule.
3. Load Regulation
3.1  Rate and Billing Factor
    For purchasers of 2-year power only.
    0.25 mills/kWh multiplied by Purchaser's Retail Load.
    For purchasers of a combination of 2-year and 5-year power.
    There is no charge for Load Regulation under the IP-96.2 rate 
schedule.
4. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate or the charge for Point-to-Point service under the Point-to-
Point (PTP) rate.
5. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
5.1.  Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Deviation Adjustment......................................  II.D.       
Industrial Exemption/Curtailment..........................  II.H.       
Operating Reserves Adjustment.............................  II.K.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
Unauthorized Increase Charge..............................  II.Q.       
------------------------------------------------------------------------

5.2.  Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------

Schedule IP-96.5--Industrial Firm Power Rate

Section I. Availability

    This schedule is available to BPA's direct-service industrial (DSI) 
customers for firm power to be used in their industrial operations for 
a 5-year period, October 1, 1996, through September 30, 2001. At their 
election, customers may purchase all or any designated portion of their 
power under this rate schedule as an alternative to purchasing power 
under the IP-96.2 rate schedule. Customers making such an election 
shall agree to purchase the designated amount of power exclusively from 
BPA for 5 years. Such election shall be a one-time irrevocable election 
and, as to the amount of power so designated, shall constitute a waiver 
of all rights to purchase power under any other power rate schedule for 
the 5-year period. The election process is described in section II.E. 
of the GRSPs.
    Both DSIs that purchase power under power sales contracts that were 
effective on or before September 30, 1996 (hereinafter termed the 
``1981'' contracts), and DSIs that purchase power under new contracts 
(hereinafter termed the ``1996'' contracts) are eligible to purchase 
under this rate schedule. Customers electing to purchase power under 
this rate schedule and continuing to receive service pursuant to their 
``1981'' power sales contract further waive any rights to terminate 
service under that contract upon 12 months' notice. This waiver does 
not, however, preclude customers from signing ``1996'' power sales 
contracts for an amount of power equal to or greater than the 

[[Page 36489]]
amount designated to be purchased under the 5-year rate. Products 
available under this rate schedule are defined in BPA's General Rate 
Schedule Provisions (GRSPs). Rates under contracts that contain charges 
that escalate based on rates listed in this rate schedule shall include 
applicable transmission charges.
    Sales under the IP-96.5 rate schedule are subject to BPA's GRSPs. 
For sales under this rate schedule, bills shall be rendered and 
payments shall be due pursuant to BPA's Billing Procedures.

Section II. Rates, Billing Factors, and Adjustments for Each IP Product

    For each customer designation, the rate(s) for each product along 
with the associated billing factor(s) are identified in separate 
sections of the rate schedule. The rates for each customer designation 
are identical; the billing factors, however, vary according to the 
customer designation. Applicable adjustments and special rate 
provisions are listed for each customer designation. Under the power 
sales contracts, the DSIs provide operating reserves and stability 
reserves. The credit for these reserves is reflected in the level of 
the applicable energy charges specified in this rate schedule. Network 
Integration transmission service at the Network Integration (NT) rate 
or Point-to-Point transmission service at the Point-to-Point (PTP) rate 
is required for purchases under this rate schedule.
    This rate schedule contains three subsections, corresponding to the 
customer categories to which this rate schedule applies:
    Section II.A  Applies to DSI purchasers who purchase under ``1981'' 
power sales contracts.
    Section II.B  Applies to Full Requirements DSI purchasers who 
purchase under ``1996'' contracts.
    Section II.C  Applies to Partial Requirements DSI purchasers who 
purchase under ``1996'' contracts.

A. IP Rates for DSI Purchasers who Purchase Under ``1981'' Power Sales 
Contracts

    DSI Purchasers purchasing power under a ``1981'' power sales 
contract are required to buy Load Regulation and either Network 
Integration Transmission service at the Network Integration (NT) rate 
or Point-to-Point Transmission service at the Point-to-Point (PTP) 
rate.
1. Industrial Firm Power
1.1.  Rates
1.1.1. Demand Charge

------------------------------------------------------------------------
                  Applicable months                          Rate       
------------------------------------------------------------------------
All Months of the Year..............................  $0.56/kW-mo.      
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                                                          HLH      LLH  
                   Applicable months                      rate     rate 
------------------------------------------------------------------------
September-December....................................    22.29    19.72
January-March.........................................    23.11    20.36
April.................................................    20.73    19.54
May-June..............................................    13.67    10.82
July..................................................    15.96    12.84
August................................................    20.18    16.69
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
    For purchasers of 5-year power only.
    Purchaser's BPA Operating Level that occurs during the hour of the 
Monthly Transmission Peak Load.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of:
    Purchaser's BPA Operating Level that occurs during the hour of the 
Monthly Transmission Peak Load or
    Purchaser's 5-year Demand Subscription.
1.2.2. HLH Billing Energy
    For purchasers of 5-year power only.
    Purchaser's HLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of:
    Purchaser's HLH Measured Energy or
    Purchaser's 5-year HLH Energy Subscription.
1.2.3. LLH Billing Energy
    For purchasers of 5-year power only.
    Purchaser's LLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of:
    Purchaser's LLH Measured Energy or
    Purchaser's 5-year LLH Energy Subscription.
2. Load Regulation
2.1. Rate and Billing Factor
    0.25 mills/kWh multiplied by Purchaser's Retail Load.
3. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate or the charge for Point-to-Point service under the Point-to-
Point (PTP) rate.
4. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
4.1. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Curtailment Charge........................................  II.C.       
Operating Reserves Adjustment.............................  II.K.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
Transitional Service......................................  II.P.       
Unauthorized Increase Charge..............................  II.Q.       
------------------------------------------------------------------------

4.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------

B. IP Rates for Full Requirements DSI Purchasers who Purchase Under 
``1996'' Power Sales Contracts

    Full Requirements customers purchasing power under a ``1996'' power 
sales contract are required to buy Load Shaping, Load Regulation, and 
either Network Integration Transmission service at the Network 
Integration (NT) rate or Point-to-Point Transmission service at the 
Point-to-Point (PTP) rate.
1. Industrial Firm Power
1.1. Rates
1.1.1. Demand Charge

------------------------------------------------------------------------
                  Applicable months                          Rate       
------------------------------------------------------------------------
All Months of the Year..............................  $0.56/kW-mo.      
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                                                          HLH      LLH  
                   Applicable months                      rate     rate 
------------------------------------------------------------------------
September-December....................................    22.29    19.72
January-March.........................................    23.11    20.36
April.................................................    20.73    19.54
May-June..............................................    13.67    10.82
July..................................................    15.96    12.84
August................................................    20.18    16.69
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
    For purchasers of 5-year power only.
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of:
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load or
    Purchaser's 5-year Demand Subscription. 

[[Page 36490]]

1.2.2. HLH Billing Energy
    For purchasers of 5-year power only.
    Purchaser's HLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of:
    Purchaser's HLH Measured Energy or
    Purchaser's 5-year HLH Energy Subscription.
1.2.3. LLH Billing Energy
    For purchasers of 5-year power only.
    Purchaser's LLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of:
    Purchaser's LLH Measured Energy or
    Purchaser's 5-year LLH Energy Subscription.
2. DSI Load Shaping
2.1. Rate
    $187/aMW.
2.2 Billing Factor
    Purchaser's Calculated Energy Capacity minus the Purchaser's 
Industrial Exemption, if any.
3. Load Regulation
3.1. Rate and Billing Factor
    0.25 mills/kWh multiplied by Purchaser's Retail Load.
4. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate or the charge for Point-to-Point service under the Point-to-
Point (PTP) rate.
5. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
5.1. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                           Page    
------------------------------------------------------------------------
Industrial Exemption/Curtailment..........................  II.H.       
Operating Reserves Adjustment.............................  II.K.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
Unauthorized Increase Charge..............................  II.Q.       
------------------------------------------------------------------------

5.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                       Page    
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------

C. IP Rates for Partial Requirements DSI Purchasers who Purchase Under 
``1996'' Power Sales Contracts

    Partial Requirements customers purchasing power under a ``1996'' 
power sales contract may purchase Load Shaping. All customers in BPA's 
load control area are required to buy Load Regulation, and customers 
outside of BPA's load control area may not buy Load Regulation. Partial 
Requirements customers must elect either Network Integration 
Transmission service at the Network Integration (NT) rate or Point-to-
Point Transmission service at the Point-to-Point (PTP) rate.
1. Industrial Firm Power
1.1. Rates
1.1.1. Demand Charge

------------------------------------------------------------------------
                  Applicable months                          Rate       
------------------------------------------------------------------------
All Months of the Year..............................  $0.56/kW-mo.      
------------------------------------------------------------------------

1.1.2. Energy Charge

------------------------------------------------------------------------
                                                          HLH      LLH  
                   Applicable months                      rate     rate 
------------------------------------------------------------------------
September-December....................................    22.29    19.72
January-March.........................................    23.11    20.36
April.................................................    20.73    19.54
May-June..............................................    13.67    10.82
July..................................................    15.96    12.84
August................................................    20.18    16.69
------------------------------------------------------------------------

1.2. Billing Factors
1.2.1. Billing Demand
1.2.1.1  With Load Shaping
    For purchasers of 5-year power only.
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of:
    Purchaser's Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load or Purchaser's 5-year Demand 
Subscription.
1.2.1.1  Without Load Shaping
    Purchaser's 5-year Demand Subscription.
1.2.2. HLH Billing Energy
1.2.2.1  With Load Shaping
    For purchasers of 5-year power only.
    Purchaser's HLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of:
    Purchaser's HLH Measured Energy or
    Purchaser's 5-year HLH Energy Subscription.
1.2.2.2  Without Load Shaping
    Purchaser's 5-year HLH Energy Subscription.
1.2.3. LLH Billing Energy
1.2.3.1  With Load Shaping
    For purchasers of 5-year power only.
    Purchaser's LLH Measured Energy.
    For purchasers of a combination of 2-year and 5-year power.
    The lower of:
    Purchaser's LLH Measured Energy or
    Purchaser's 5-year LLH Energy Subscription.
1.2.3.2  Without Load Shaping
    Purchaser's 5-year LLH Energy Subscription.
2. DSI Load Shaping
2.1  Rate
    $187/aMW.
2.2  Billing Factor
    Purchaser's Calculated Energy Capacity minus the Purchaser's 
Industrial Exemption, if any.
3. Load Regulation
3.1  Rate and Billing Factor
    0.25 mills/kWh multiplied by Purchaser's Retail Load.
4. Transmission
    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate or the charge for Point-to-Point service under the Point-to-
Point (PTP) rate.
5. Adjustments, Charges, and Special Rate Provisions
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
5.1.  Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Deviation adjustment......................................  II.D.       
Industrial exemption/curtailment..........................  II.H.       
Operating reserves adjustment.............................  II.K.       
Preschedule change charge.................................  II.M.       
Reactive power charge.....................................  II.N.       
Unauthorized increase charge..............................  II.Q.       
------------------------------------------------------------------------

5.2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost contributions........................................  II.B.       
------------------------------------------------------------------------

Schedule VI-96--Variable Industrial Power Rate

Section I. Availability

    This schedule is available to BPA's direct-service industrial (DSI) 
customers for firm power to be used in their aluminum and nickel 
smelting operations). Only DSIs that purchase power under the 1996 
Contract) and that have signed a new Variable Industrial Rate Contract 
are eligible to purchase under this rate schedule. BPA is not 

[[Page 36491]]
obligated to sell power under this rate schedule. Products available 
under this rate schedule are defined in BPA's General Rate Schedule 
Provisions (GRSPs).
    A customer electing to purchase power under this rate schedule must 
first elect service to its entire load under either the IP-96.2 rate 
schedule or the IP-96.5 rate schedule. The purchaser may not purchase 
power under both rate schedules pursuant to the election process 
described in section II.E. of the GRSPs. Any variable rate established 
pursuant to this rate schedule will apply to the purchaser's entire 
load.
    At the expiration of the variable rate formula, a new one can be 
established, or the customer may purchase power under the applicable IP 
rate. However, the total term of all variable rate formulas for any DSI 
customer shall not be longer than 2 years under the IP-96.2 rate 
schedule and five years under the IP-96.5 rate schedule.
    This rate schedule supersedes Schedule VI-95, which went into 
effect on October 1, 1995. Sales under the VI-96 rate schedule are 
subject to BPA's General Rate Schedule Provisions. For sales under this 
rate schedule, bills shall be rendered and payments shall be due 
pursuant to BPA's Billing Procedures.

Section II. Rates, Billing Factors, and Adjustments

A. Variable Industrial Firm Power

1. Rates
    The variable rate formula will be based on the IP rate under which 
the customer has elected service. The Demand Charge for the variable 
rate will be the same as the Demand Charge in the applicable IP rate. 
The Base Energy Charge will be the average annual charge that results 
from applying the Energy Charges and the Load Regulation charge from 
the applicable IP rate to the customer's forecasted load. For customers 
that have elected service under the IP-96.2 rate schedule, upon the 
expiration of such schedule the Base Energy Charge shall be such annual 
average charge from any subsequent Industrial Firm Power Rate Schedule 
under which such customer elects service.
    The monthly Energy Charge varies with the price of aluminum, in the 
case of customers engaged in primary aluminum reduction, and with the 
price of nickel, in the case of customers engaged in primary nickel 
reduction. Individual rate formulas will be established for each 
customer. Each rate formula shall be such that, at the time BPA enters 
into a Variable Industrial Rate Contract with the individual customer 
incorporating such formula, BPA has the ability to hedge the aluminum 
or nickel price risk inherent in such rate formula, at zero cost to 
BPA, by entering into transactions with one or more substantial 
financial institutions.
    (``Zero cost to BPA'' means that either a) BPA will incur no cost 
to hedge the price risk of the variable rate, or b) BPA will recover 
the sum it pays to hedge the price risk of the variable rate from the 
applicable customer, either as a lump sum paid at the time BPA and the 
customer enter into the Variable Rate Contract, or over a time period 
no longer than the term of the variable rate formula incorporated in 
such contract. In the event that such sum is recovered over time, it 
shall bear interest at the rate payable on the Bonneville Fund in the 
United States Treasury at the time BPA and the customer enter into the 
Variable Rate Contract.)
    Individual rate formulas may be established for any period from one 
to two years, in the case of customers purchasing power under the IP-
96.2 rate schedule, and for any period from one to five years, in the 
case of customers purchasing power under the IP-96.5 rate schedule. At 
the expiration of any rate formula, a new rate formula for that 
customer may be established pursuant to the guidelines stated in this 
section, or the customer may purchase power under the applicable 
Industrial Firm Power rate schedule. However, the total term of all 
variable rate formulas for any single DSI purchaser shall not be longer 
than two years in the case of customers that have elected service under 
the IP-96.2 rate schedule, and five years in the case of customers that 
have elected service under the IP-96.5 rate schedule.
    The monthly Energy Charge shall be based on the monthly billing 
aluminum or nickel price. The monthly billing aluminum or nickel price 
shall be the average price of aluminum or nickel, in dollars per metric 
ton, on the London Metal Exchange (LME) during the calendar month 
immediately preceding the billing month. The average price during the 
month shall equal the average of all official LME daily cash settlement 
prices during such month rounded to the nearest dollar. BPA and each 
customer may agree to base the monthly energy charge on the average 
price of aluminum or nickel during a month other than the immediately 
preceding month.
    In the case of variable industrial rate formulas that contain pivot 
prices, the monthly Energy Charge shall be the Base Energy Charge when 
the monthly billing aluminum or nickel price is between the Lower Pivot 
Aluminum or Nickel Price and the Upper Pivot Aluminum or Nickel Price 
inclusive. In the case of variable industrial rate formulas that do not 
contain pivot prices, the monthly Energy Charge shall be the Base 
Energy Charge when the monthly billing aluminum or nickel price equals 
the price established in the customer's Variable Industrial Rate 
Contract at which the Base Energy Charge applies.
    The Lower Pivot Aluminum or Nickel Price is the aluminum or nickel 
price established in an individual customer's Variable Industrial Rate 
Contract such that the monthly energy charge decreases when the monthly 
billing aluminum or nickel price is below such price.
    The Upper Pivot Aluminum or Nickel Price is the aluminum or nickel 
price established in an individual customer's Variable Industrial Rate 
Contract such that the monthly energy charge increases when the monthly 
billing aluminum or nickel price is above such price.
2. Billing Factors
2.1. Billing Demand
    Purchaser's Demand Subscription.
2.2. Billing Energy
    Purchaser's Energy Subscription.

B. Transmission

    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate or the charge for Point-to-Point service under the Point-to-
Point (PTP) rate.

C. Adjustments, Charges, and Special Rate Provisions

    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
1. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
Unauthorized Increase Charge..............................  II.Q.       
------------------------------------------------------------------------

2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------

Schedule NF-96--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 

[[Page 36492]]
States including sales under the Western Systems Power Pool (WSPP) 
agreements and sales to consumers. BPA is not obligated to offer 
nonfirm energy to any purchaser that results in displacement of firm 
power purchases under BPA's ``1981'' or ``1996'' Power Sales Contracts. 
The offer of nonfirm energy under this schedule shall be determined by 
BPA. For purchases under this rate schedule, transmission service over 
FCRTS facilities shall be available at the applicable transmission rate 
schedule.
    This rate schedule supersedes schedule NF-95, which went into 
effect on October 1, 1995. Sales under the NF-96 rate schedule are 
subject to BPA's General Rate Schedule Provisions. For sales under this 
rate schedule, bills shall be rendered and payments due pursuant to 
BPA's Billing Procedures.

Section II. Rates, Billing Factors, and Adjustments

    The average cost of nonfirm energy is 20.92 mills per kilowatt-
hour. The NF-96 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 calculated in accordance with the methodology 
specified in the Adjustments, Charges, and Special Rate Provisions 
section of this document.
A. Rates for Nonfirm Energy
1. Standard Rate
    The Standard rate is any offered rate not to exceed 25.12 mills per 
kilowatt-hour.
2. Market Expansion Rate
    The Market Expansion rate is any offered rate below the Standard 
rate in effect. BPA may have one or more Market Expansion rates in 
effect simultaneously.
3. Incremental Rate
    The Incremental Rate is the Incremental Cost of energy plus 2.00 
mills 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.
4. Contract Rate
    The Contract Rate is 20.92 mills per kilowatt-hour.
B. Billing Factor for Nonfirm Energy
    The billing factor for nonfirm energy purchased under this rate 
schedule shall be the Measured Energy unless otherwise specified by 
contract.
C. Adjustments for Nonfirm Energy
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
1. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Guaranteed Delivery Charge................................  II.G.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
------------------------------------------------------------------------

2. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provision                       Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
NF Rate Cap...............................................  II.J.       
------------------------------------------------------------------------

Section III. Determination of the Applicable NF Rate

    Any time that BPA has nonfirm energy for sale, the Standard rate, 
the Market Expansion rate, the Incremental rate, the Contract rate, or 
any combination of these rates may be in effect.
A. Standard Rate
    The Standard rate:
    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 ``1981'' utility 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 
satisfying the Market Expansion Rate Qualifying Criteria specified in 
section III.B.2, above, who purchased nonfirm energy directly from BPA 
are eligible to purchase power under the Market Expansion rate offered 
if the decremental cost of the qualifying resource, purchase, or 
qualifying alternative fuel source is lower than the Standard rate in 
effect plus 2.00 mills per kilowatt-hour.
    Purchasers qualifying under section III.B.2 who purchase nonfirm 
energy through a third party are eligible to purchase power under the 
Market Expansion rate offered if the cost of the qualifying alternative 
fuel source is lower than the Standard rate in effect plus 4.00 mills 
per kilowatt-hour.
    b. When more than one Market Expansion rate is offered: Purchasers 
qualifying under section III.B.2 who purchase nonfirm energy directly 
from BPA are eligible to purchase power under the Market Expansion rate 
if the decremental cost of the qualifying resource, purchase, or 
qualifying alternative fuel source is lower than the Standard rate in 
effect plus 2.00 mills 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 III.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 4.00 mills per kilowatt-hour.
C. Incremental Rate
    The Incremental rate applies to sales of energy: 

[[Page 36493]]

    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 IV. Delivery

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

Schedule RP-96--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-
95, which went into effect on October 1, 1995. Sales under this 
schedule are subject to BPA's General Rate Schedule Provisions. For 
sales under this rate schedule, bills shall be rendered and payments 
due pursuant to BPA's Billing Procedures.

Section II. Rate

A. Demand Charge

------------------------------------------------------------------------
                 Applicable months                          Rate        
------------------------------------------------------------------------
All Months of the Year............................  $0.56/kW-mo.        
------------------------------------------------------------------------

B. Energy Charge

----------------------------------------------------------------------------------------------------------------
                Applicable months                            HLH rate                        LLH rate           
----------------------------------------------------------------------------------------------------------------
September-December..............................  24.3 mills/kWh................  21.5 mills/kWh.               
January-March...................................  25.2 mills/kWh................  22.2 mills/kWh.               
April...........................................  22.6 mills/kWh................  21.3 mills/kWh.               
May-June........................................  14.9 mills/kWh................  11.8 mills/kWh.               
July............................................  17.4 mills/kWh................  14.0 mills/kWh.               
August..........................................  22.0 mills/k..................  18.2 mills/kWh.               
----------------------------------------------------------------------------------------------------------------

Section III. Billing Factors

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 that occurs during the hour of the Monthly 
Transmission Peak Load.
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 HLH and 
LLH Measured Energy.

Section IV. Adjustments, Charges, and Special Rate Provisions

    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
A. Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Reactive Power Charge.....................................  II.N.       
------------------------------------------------------------------------

B. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------

Schedule PS-96--Power Shortage Rate Schedule

Section I. Availability

    This schedule is available inside the Pacific Northwest for the 
purchase of Shortage Power by signatories to the Share-the-Shortage 
Agreement, or a similar substitute agreement. Any transactions entered 
into by BPA pursuant to a Share-the-Shortage Agreement shall be subject 
to the terms and conditions specified in that agreement. The PS-96 rate 
does not incorporate the Agreement, but the Agreement controls if there 
is any conflict between the PS-96 rate and the Agreement. The PS-96 
rate shall not be available for transactions with a party 

[[Page 36494]]
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.
    This rate schedule is also available inside the Pacific Northwest 
when BPA arranges for the purchase of energy at the request of, and for 
the account of, a customer pursuant to a Share-the-Shortage Agreement.
    BPA is not obligated either to make Shortage Power available or to 
broker power under this rate schedule unless specified by contract.
    This schedule supersedes schedule PS-95, which went into effect on 
October 1, 1995. Sales under the PS-96 rate schedule are subject to 
BPA's General Rate Schedule Provisions (GRSPs), and BPA's Billing 
Procedures.

Section II. Rates

A. Power Rate
    The power rate is any offered rate not to exceed the lesser of:
    1. 100.00 mills per kilowatt-hour; or
    2. the maximum rate specified in the Share-the Shortage Agreement. 
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

A. Power Purchases
    The billing factors shall be the Contract Demand and Contract 
Energy, unless otherwise specified in the agreement initiating the 
Share-the-Shortage sales transaction.
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 number of kilowatt-hours purchased.
    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.
Section IV. Transmission

    The transmission charge for deliveries under this rate shall be the 
charge for Network Integration service under the Network Integration 
(NT) rate or the charge for Point-to-Point service under the Point-to-
Point (PTP) rate.

Section V. Adjustments, Charges, and Special Rate Provisions

    All adjustments are described in the GRSPs. The applicable sections 
are identified in parentheses for each adjustment.
A. Rate adjustments

------------------------------------------------------------------------
                      Rate Adjustment                          Section  
------------------------------------------------------------------------
Deviation Adjustment......................................  II.D.       
Reactive Power Charge.....................................  II.N.       
------------------------------------------------------------------------

B. Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------

Schedule FPS-96--Firm Power Products and Services

Section I. Availability

    This rate schedule is available for the purchase of Firm Power, 
Control Area Services that are not defined as ancillary services, and 
Shaping Services for use inside and outside the Pacific Northwest 
during the period beginning October 1, 1996, and ending September 30, 
2005.
    Products and services available under this rate schedule are 
described in the ``Definitions'' section of BPA's General Rate Schedule 
Provisions (GRSPs). BPA is not obligated to enter into agreements to 
sell products and services under this rate schedule or make power or 
energy available under this rate schedule if such power or energy would 
displace sales under the PF-96.2, PF-96.5, NR-96.2, NR-96.5, IP-96.2, 
IP-96.5, or VI-96 rate schedules or their successors. Sales under the 
FPS-96 rate schedule are subject to BPA's GRSPs. For purchases under 
this rate schedule, transmission service over FCRTS facilities shall be 
available under the applicable transmission rate schedule, and 
ancillary services shall be available under the Ancillary Products and 
Services (APS) rate schedule.
    This rate schedule supersedes the Surplus Firm Power (SP-93) and 
Emergency Capacity (CE-95) rate schedules. Sales under this schedule 
are made subject to BPA's General Rate Schedule Provisions. For sales 
under this rate schedule, bills shall be rendered and payments due 
pursuant to BPA's Billing Procedures.

Section II. Rates, Billing Factors, and Adjustments

    This section of the rate schedule is organized as follows:
    Section II.A. Rates, billing factors, and adjustments for Firm 
Power.
    Section II.B. Rates, billing factors, and adjustments for 
Supplemental Control Area Services.
    Section II.C. Rates, billing factors, and adjustments for Shaping 
Services.
A. Firm Power
1. Rates
1.1  Contract Rate
1.1.1  Demand Charge

------------------------------------------------------------------------
                 Applicable months                          Rate        
------------------------------------------------------------------------
All Months of the Year............................  $0.56/kW-mo.        
------------------------------------------------------------------------

1.1.2  Energy Charge

------------------------------------------------------------------------
                                                            HLH     LLH 
                    Applicable months                      rate    rate 
------------------------------------------------------------------------
September-December......................................   36.61   32.39
January-March...........................................   37.97   33.45
April...................................................   34.05   32.09
May-June................................................   22.45   17.78
July....................................................   26.22   21.09
August..................................................   33.15   27.42
------------------------------------------------------------------------

1.2  Flexible Rate
    Demand and/or energy charges may be specified at a higher or lower 
average rate as mutually agreed by BPA and the Purchaser.
1.3  Reservation Charge
    The reservation charge for reserving the right to change future 
delivery of firm energy and/or capacity may be as established by BPA or 
as mutually agreed by BPA and the Purchaser.
2. Billing Factors
2.1  Billing Demand
    The Billing Demand for Firm Power shall be the Contract Demand 
unless otherwise agreed by BPA and the Purchaser.
2.2  Billing Energy
    The Billing Energy for Firm Power shall be the Contract Energy 
unless otherwise agreed by BPA and the Purchaser.
2.3  Billing Factor for Reserved Firm Power
    The billing factor for reserved Firm Power shall be as specified by 
BPA or as mutually agreed by BPA and the Purchaser. 

[[Page 36495]]

3. Adjustments
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
3.1  Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Energy Return Surcharge...................................  II.F.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
Unauthorized Increase Charge..............................  II.Q.       
------------------------------------------------------------------------

3.2  Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------

B. Control Area Services That Are Not Ancillary Services

1. Rates
    The rate(s) shall be as specified by BPA or as mutually agreed by 
BPA and the Purchaser.
2. Billing Factors
    The billing factor(s) for control area services shall be as 
specified by BPA or as mutually agreed by BPA and the Purchaser.
3. Adjustments
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
3.1  Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Energy Return Surcharge...................................  II.F.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
Unauthorized Increase Charge..............................  I.Q.        
------------------------------------------------------------------------

3.2  Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------

C. Shaping Services

1. Rate
1.1  Rate for Shaping and Load Factoring Service
    The rate shall be as specified by BPA or as mutually agreed by BPA 
and the Purchaser.
1.2  Reservation Charge
    The reservation charge for reserving the right to take future 
delivery of shaping services shall be as specified by BPA or as 
mutually agreed by BPA and the Purchaser.
2. Billing Factor
2.1  Billing Factor for Shaping Services
    The Billing Factor(s) shall be as specified by BPA or as mutually 
agreed by BPA and the Purchaser.
2.2  Billing Factors for Reservation of the Right to Purchase Shaping 
Services
    The Billing Factor(s) shall be as specified by BPA or as mutually 
agreed by BPA and the Purchaser.
3. Adjustments
    All adjustments are described in the GRSPs. The applicable sections 
are identified for each adjustment.
3.1  Rate Adjustments

------------------------------------------------------------------------
                      Rate adjustment                          Section  
------------------------------------------------------------------------
Energy Return Surcharge...................................  II.F.       
Preschedule Change Charge.................................  II.M.       
Reactive Power Charge.....................................  II.N.       
Unauthorized Increase Charge..............................  II.Q.       
------------------------------------------------------------------------

3.2  Special Rate Provisions

------------------------------------------------------------------------
                  Special rate provisions                      Section  
------------------------------------------------------------------------
Cost Contributions........................................  II.B.       
------------------------------------------------------------------------

APS-96--Ancillary Products and Services

Section I. Availability

    This rate schedule is available for ancillary services necessary to 
support the firm or non-firm delivery of power from resources to loads 
using the Federal Columbia River Transmission System (FCRTS) 
facilities. The ancillary products and services available under this 
rate schedule are: Scheduling and Dispatching; Control Area Reserves 
for Resources; Control Area Reserves for Interruptible Purchases; Load 
Regulation; and Transmission Losses. These services are defined in the 
``Definitions'' section of BPA's General Rate Schedule Provisions 
(GRSPs). This schedule is also available for ancillary services of a 
similar nature as BPA may be ordered by the Federal Energy Regulatory 
Commission (FERC) pursuant to sections 211 and 212 of the Federal Power 
Act (16 U.S.C. 824j and 824k).
    To the extent that FERC allows transmitting utilities subject to 
the Federal Power Act to sell ancillary services at rates other than 
stated rates, the provisions providing for a flexible rate for the 
ancillary products or services provided in this schedule may apply.
    Sales under this schedule are made subject to BPA's General Rate 
Schedule Provisions. For sales under this rate schedule, bills shall be 
rendered and payments due pursuant to BPA's Billing Procedures.

Section II. Rates and Billing Factors

    This section of the rate schedule is organized as follows:
    Section II.A  Identifies the rates and billing factors for 
Scheduling and Dispatching.
    Section II.B  Identifies the rates and billing factors for Control 
Area Reserves for Resources.
    Section II.C  Identifies the rates and billing factors for Control 
Area Reserves for Interruptible Purchases.
    Section II.D  Identifies the rates and billing factors for Load 
Regulation.
    Section II.E  Identifies the rates and billing factors for 
Transmission Losses.
A. Scheduling and Dispatching
1. Rates
1.1  Rate for Scheduling and Dispatching
    The rate for scheduling and dispatching service shall be $71 per 
Preschedule.
1.2  Rate for Preschedule Change
    The rate for Preschedule Changes shall be $33 per change.
2. Billing Factors
2.1  Billing Factor for Scheduling and Dispatch
    The billing factor shall be the sum of Preschedules made for each 
of the Purchaser's scheduling accounts per billing month.
2.2  Billing Factor for Preschedule Change
    The billing factor shall be the sum of Preschedule Changes made for 
each of the Purchaser's scheduling accounts per billing month.
B. Control Area Reserves for Resources
1. Rates
    The rates below for Control Area Reserves For Resources apply to 
all hydro-electric and non-hydroelectric generating resources located 
in BPAs control area. The rates below do not apply to such resources 
with generating capacity of less than one MW.
1.2  Rate for Control Area Reserves for Hydroelectric Resources
1.2.1  Stated Rate
    The rate shall be $0.35 per kilowatt-month of billing demand.
1.2.2  Flexible Rate
    The rate shall be specified by BPA for such service. 

[[Page 36496]]

1.3  Rate for Control Area Reserves for Non-Hydroelectric Resources
1.3.1  Stated Rate
    The rate shall be $0.50 per kilowatt-month of billing demand.
1.3.2  Flexible Rate
    The rate shall be specified by BPA for such service.
2. Billing Factors
2.1  Billing Demand
    If the Purchaser's resource(s), regardless of resource type, have 
appropriate metering equipment, the billing demand shall be determined 
as specified in section 2.1.1 below. Otherwise, for the purchaser's 
hydroelectric resource(s) the billing demand shall be determined in 
accordance with section 2.1.2, and for the purchaser(s) thermal and any 
other non-hydroelectric resource(s) the billing demand shall be 
determined in accordance with section 2.1.3.
2.1.1  Billing Demand for Metered Resources
    For service applicable to the Purchaser's resource(s) regardless of 
type, having appropriate metering equipment, the billing demand shall 
be the average metered energy for each resource for the billing month.
2.1.2  Billing Demand for Hydroelectric Resources
    For service applicable to the Purchaser's hydroelectric resource(s) 
the billing demand shall be the total Resource Capability, as specified 
in section B.2.1.4, for the Purchaser's hydroelectric resource(s), 
multiplied by a capacity factor of 0.60.
2.1.3  Billing Demand for Non-Hydroelectric Resources
    For service applicable to the Purchaser's thermal resource(s) and 
any other non-hydro-electric resource(s), the billing demand shall be 
the total Resource Capability for the Purchaser's thermal resource(s) 
and any other non-hydroelectric resource(s), multiplied by a capacity 
factor of 0.90.
2.1.4  Resource Capability
    For service under 1981 power sales contracts, the Resource 
Capability, expressed in kilowatts, shall be equal to the Assured 
Peaking Capability of the Purchaser's resource(s). For 1996 contracts 
and all other agreements, the Resource Capacity shall be the Monthly 
Resource Peaking Capability as specified in the Agreement.
C. Control Area Reserves for Interruptible Purchases
1. Rates
1.1  Rate for Control Area Reserves for Interruptible Purchases
1.1.1  Stated Rate
    The rate shall be 4.00 mills per kilowatt-hour.
1.1.2  Flexible Rate
    The rate shall be specified by BPA for such service.
2. Billing Factor
    The billing factor shall be the sum of scheduled amounts of 
Interruptible Energy per billing month.
D. Load Regulation
1. Rate
1.1 Stated Rate
    The rate shall be 0.25 mills per kilowatt-hour of billing energy.
1.2 Flexible Rate
    The rate shall be specified by BPA for such service.
2. Billing Factor
    The billing factor for load regulation shall be the measured 
monthly kilowatt-hours of the purchaser's Retail Load.
E. Transmission Losses
1. RATE
1.1  Stated Rate
    For agreements that provide the option of purchasing transmission 
losses, the rate shall be 29.34 mills per kilowatt-hour.
1.2  Flexible Rate
    The rate shall be specified by BPA for such service.
2. Billing Factor
    The Billing Factor shall be the amount of losses for the billing 
month calculated as specified in the applicable Agreement.

D. Summary of Transmission Rate Schedules

FPT-96--Formula Power Transmission Rate
FPT-96.3--Formula Power Transmission Rate
IR-96--Integration of Resources Rate
NT-96.2--Network Integration Transmission Rate
NT-96.5--Network Integration Transmission Rate
PTP-96.2--Point-to-Point Firm Transmission Rate
PTP-96.5--Point-to-Point Firm Transmission Rate
ET-96--Energy Transmission Rate
IS-96--Southern Intertie Transmission Rate
IN-96--Northern Intertie Transmission Rate
IE-96--Eastern Intertie Transmission Rate
MT-96--Market Transmission Rate
UFT-96--Use-of-Facilities Transmission Rate
AF-96--Advance Funding Rate
TGT-96--Townsend-Garrison Transmission Rate

    A summary of the proposed 1996 Transmission Rate Schedules is 
provided below. Each of the rate schedules includes sections specifying 
the service available under the rate schedule, the rates for the 
products and services offered under the schedule, the billing factors, 
and other special provisions for rate adjustments, such as the 
discounts or penalties that apply to that rate schedule.
    Three new transmission rates are proposed: the Network Integration 
Transmission rate; the Point-to-Point Transmission rate; and the 
Advance Funding rate. Nonfirm rates in the proposed Southern Intertie, 
Northern Intertie, Eastern Intertie, and Energy Transmission rate 
schedules are revised to allow for downward flexibility from the stated 
cost. A Reservation Fee for Transmission Capacity and a Reactive Power 
Charge are included in many of the transmission rate schedules. BPA 
also has provided for charging opportunity costs in the firm 
transmission rates for new requests for transmission capacity. The 
Ancillary Products and Services rate schedule which specifies the 
charges for ancillary services that may be required to use BPA's 
transmission system is included in BPA's wholesale power rate proposal.

1. Formula Power Transmission (FPT-96)

    The FPT-96 rate is available for the firm wheeling of power on the 
network segment of the FCRTS. This rate includes a distance or mileage 
component for transmission lines and various transformation and 
terminal charges. The FPT rate form is designed to reflect a wheeling 
formula that is prescribed by contract provisions. The rate schedule 
provides for annual and seasonal service. Two FPT rate schedules are 
developed--one for rates that cannot be changed more frequently than 
once a year, and one for rates that cannot be changed more frequently 
than once every 3 years. Revised rates are proposed for both rate 
schedules.

[[Page 36497]]


2. Integration of Resources (IR-96)

    The IR service is a flexible transmission service that may be used 
to integrate multiple resources and transmit non-Federal power to 
multiple points of delivery on the FCRTS Network facilities. The IR-96 
rate is structured as a postage-stamp (independent of distance) rate. 
The proposed IR-96 rate schedule continues to include the Short-
Distance Discount, an exception to the postage stamp rate design for 
contractually specified points of integration. The IR rate has 
traditionally included both demand and energy charges; BPA is proposing 
that the IR-96 rate be a demand-only rate.

3. Network Integration (NT-96)

    Network Integration transmission service allows customers to serve 
their load located in the PNW region. The proposed NT-96 rate is 
designed to conform generally with the pricing provisions of the FERC 
NOPR Network Integration tariff. The proposed NT-96 rate includes a 
Network demand charge that is applied to a customer's total retail load 
occurring at the hour of the monthly BPA transmission system peak, with 
a credit for the utility's transmission facilities. For customers with 
1981 contracts, the Network charge will be applied to power delivered 
under those contracts on the hour of the monthly BPA transmission peak 
and no credit is given for customer transmission facilities. The rate 
schedule also includes delivery charges for customers served over 
Utility or DSI Delivery facilities. The NT rate also provides for a 
charge or credit to compensate for redispatching of resources. The NT 
rate will apply to BPA full requirements customers; partial 
requirements customers may elect either Network Integration 
Transmission service using the NT rate or Point to Point Transmission 
service using the Point to Point rate (see below). Residential Purchase 
and Sale Agreement purchasers shall take service under the 2-year NT 
rate.

4. Point-to-Point (PTP-96)

    Point-to-Point transmission service allows customers to serve their 
retail load and/or transactions with third parties and off-system sales 
over the Network. BPA also will apply this rate for sale to, and 
purchases for, its own customers which are not native load customers. 
The proposed PTP-96 rate is designed to conform generally with the 
pricing provisions of the FERC NOPR Point-to-Point tariff. The proposed 
PTP-96 rate includes a Network demand charge that is applied to the 
greater of: (1) the sum of the monthly Point of Integration 
Transmission Demands; or (2) the sum of the monthly Point of Delivery 
Transmission Demands. The PTP rate may apply to firm transmission 
service of 1 month or longer. The rate schedule also includes delivery 
charges for customers served over Utility or DSI Delivery facilities.

5. Energy Transmission (ET-96)

    The ET rate applies to firm service of less than a month and to 
nonfirm service over FCRTS facilities excluding the Interties. The rate 
may be used for service taken under the Point-to-Point tariff. The firm 
rate is a take-or-pay energy charge. The nonfirm rate is specified as a 
cap with flexibility below that level.

6. Southern Intertie (IS-96), Northern Intertie (IN-96), and Eastern 
Intertie (IE-96)

    The IS rate and IN rate are available for service over those 
respective facilities. The rates are structured similarly: a nonfirm 
energy-only rate; and a firm rate with separate demand and energy 
components. The nonfirm rates are specified as a cap with flexibility 
below those levels. The IE rate is available for nonfirm transmission 
on the Eastern Intertie and is structured as an energy-only rate with 
downward flexibility.

7. Market Transmission (MT-96)

    BPA is continuing the MT rate unchanged, except for the addition of 
the Reactive Power Charge. This rate schedule was developed for use 
among Western Systems Power Pool (WSPP) participants and allows for 
flexible hourly, daily, weekly, and monthly charges.

8. Use of Facilities Transmission (UFT-96) and Townsend-Garrison 
Transmission (TGT-96)

    The UFT-96 and TGT-96 rate schedules are formula rates that are 
being proposed unchanged from the current 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.

9. Advance Funding (AF-96)

    The proposed AF rate allows BPA to collect the capital and related 
costs of specified BPA-owned transmission facilities through advance 
payment. Such facilities could include interconnection and resource 
integration facilities, and upgrades or reinforcements to the FCRTS. 
Following commercial operation of the specified facilities, a true-up 
of estimated costs with actual costs would occur.
10. Reservation Fee for Transmission Capacity and Reactive Power Charge

    The proposed Reservation Fee is included in the firm transmission 
rate schedules for application to customers who enter into a contract 
with BPA for new or increased firm transmission service on the FCRTS 
and want to postpone the commencement of such service while maintaining 
the availability of transmission capacity. Payment of the Reservation 
Fee for Transmission Capacity would allow a customer to postpone 
service for a year at a time for up to 5 years. This proposed 
Reservation Fee is modeled on the one in FERC's Point-to-Point tariff. 
The proposed Reactive Power Charge is included in BPA's transmission 
rate schedules as well as BPA's power rate schedules, and charges 
customers for their reactive power requirements by point of delivery 
and points of interconnection.

E. Transmission Rate Schedules

Schedule FPT-96.2--Formula Power Transmission Rate

Section I. Availability

    This schedule supersedes schedule FPT-95.1 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 non-Federal power 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 transmission service is required. Service under this 
schedule is subject to BPA's General Rate Schedule Provisions. Bills 
shall be rendered and payments due pursuant to BPA's Billing 
Procedures.

Section II. Rate

    The monthly charge shall be A or B.
A. Embedded Cost
1. 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.
    a. 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 36498]]

    (1) Main Grid Distance Factor: The amount computed by multiplying 
the Main Grid Distance by $0.0526 per mile.
    (2) Main Grid Interconnection Terminal Factor: $0.36.
    (3) Main Grid Terminal Factor: $0.59.
    (4) Main Grid Miscellaneous Facilities Factor: $2.79.
    b. 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:
    (1) Secondary System Distance Factor: The amount determined by 
multiplying the Secondary System Distance by $0.3769 per mile.
    (2) Secondary System Transformation Factor: $5.37.
    (3) Secondary System Intermediate Terminal Factor: $1.70.
    (4) Secondary System Interconnection Terminal Factor: $1.17.
2. Partial-Year Service
    The monthly charge per kilowatt of Billing Demand shall be as 
specified in section II.A.1 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:
    a. During months for which service is specified, the monthly charge 
defined in section II.A.1, and
    b. During other months, the monthly charge defined in section 
II.A.1 multiplied by 0.2.
B. Opportunity Cost
    For applications for new service or increases in current service, 
Opportunity Costs may be charged if those costs are higher than the 
rates in section II.A.

Section III. Billing Factors

A. Embedded Cost
    Unless otherwise stated in the agreement, the Billing Demand for 
the rates specified in section II.A. shall be the largest of:
    1. The Transmission Demand;
    2. The highest hourly Scheduled Demand for the month; or
    3. The Ratchet Demand.
B. Opportunity Cost
    Billing factors for the rate specified in section II.B. shall be 
specified in the agreement.

Section IV. Other Provisions

A. Ancillary Services
    Ancillary services that may be required to support FPT transmission 
service are available under the APS rate schedule.
B. Reactive Power Charge
    Customers taking service under this rate schedule are subject to 
the Reactive Power Charge specified in section II.N. of the General 
Rate Schedule Provisions.
C. Reservation Fee for Transmission Capacity
    Customers who request new or increased firm transmission service 
under this rate schedule and want to reserve transmission capacity to 
accommodate such service are subject to the Reservation Fee for 
Transmission Capacity specified in section II.O. of the General Rate 
Provisions.
D. Rates Applicable to FPT Service
    The rates specified in section II are applicable to service over 
available transmission capacity. Customers requesting new or increased 
firm service that would require BPA to construct new facilities or 
upgrades to alleviate a capacity constraint may be subject to 
incremental cost rates for such service if incremental cost is higher 
than embedded cost. Incremental cost rates would be developed pursuant 
to section 7(i) of the Northwest Power Act.

Schedule FPT-96.3--Formula Power Transmission Rate

Section I. Availability

    This schedule supersedes schedule FPT-95.3 for all firm 
transmission agreements which provide that rates may be adjusted not 
more frequently than once every three years. It is available for firm 
transmission of non-Federal power 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 transmission service is required. 
Service under this schedule is subject to BPA's General Rate Schedule 
Provisions. Bills shall be rendered and payments due pursuant to BPA's 
Billing Procedures.

Section II. Rate

    The monthly charge shall be A or B.
A. Embedded Cost
1. 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.
    a. 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:
    (1) Main Grid Distance Factor: The amount computed by multiplying 
the Main Grid Distance by $0.0526 per mile.
    (2) Main Grid Interconnection Terminal Factor: $0.36.
    (3) Main Grid Terminal Factor: $0.59.
    (4) Main Grid Miscellaneous Facilities Factor: $2.79.
    b. 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:
    (1) Secondary System Distance Factor: The amount determined by 
multiplying the Secondary System Distance by $0.3769 per mile.
    (2) Secondary System Transformation Factor: $5.37.
    (3) Secondary System Intermediate Terminal Factor: $1.70.
    (4) Secondary System Interconnection Terminal Factor: $1.17.
2. Partial-Year Service
    The monthly charge per kilowatt of Billing Demand shall be as 
specified in section II.A.1 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:
    a. During months for which service is specified, the monthly charge 
defined in section II.A.1, and
    b. During other months, the monthly charge defined in section 
II.A.1 multiplied by 0.2.
B. Opportunity Cost
For applications for new service or increases in current service, 
Opportunity Costs may be charged if those costs are higher than the 
rates in section II.A.

Section III. Billing Factors

A. Embedded Cost
    Unless otherwise stated in the agreement, the Billing Demand for 
the rates specified in section II.A. shall be the largest of:
    1. The Transmission Demand;
    2. The highest hourly Scheduled Demand for the month; or
    3. The Ratchet Demand.
B. Opportunity Cost
    Billing factors for the rate specified in section II.B. shall be 
specified in the agreement.

Section IV. Other Provisions

A. Ancillary Services
    Ancillary services that may be required to support FPT transmission 
service are available under the APS rate schedule.

[[Page 36499]]

B. Reactive Power Charge
    Customers taking service under this rate schedule are subject to 
the Reactive Power Charge specified in section II.N. of the General 
Rate Schedule Provisions.
C. Reservation Fee for Transmission Capacity
    Customers who request new or increased firm transmission service 
under this rate schedule and want to reserve transmission capacity to 
accommodate such service are subject to the Reservation Fee for 
Transmission Capacity specified in section II.O. of the General Rate 
Schedule Provisions.
D. Rates Applicable to FPT Service
    The rates specified in section II are applicable to service over 
available transmission capacity. Customers requesting new or increased 
firm service that would require BPA to construct new facilities or 
upgrades to alleviate a capacity constraint may be subject to 
incremental cost rates for such service if incremental cost is higher 
than embedded cost. Incremental cost rates would be developed pursuant 
to section 7(i) of the Northwest Power Act.

Schedule IR-96--Integration of Resources Rate

Section I. Availability

    This schedule supersedes IR-95 and is available for transmission of 
non-Federal power for full-year firm transmission service and nonfirm 
transmission service in amounts not to exceed the customer's total 
Transmission Demand using Federal Columbia River Transmission System 
Network facilities. Service under this schedule is subject to BPA's 
General Rate Schedule Provisions. Bills shall be rendered and payments 
due pursuant to BPA's Billing Procedures.

Section II. Rate

    The monthly charge shall be A or B.
A. Embedded Cost
    The monthly charge shall be:
    1. $1.188 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  x  transmission distance/75)] * 
$0.594 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. Opportunity Cost
    For applications for new service or increases in current service, 
Opportunity Costs may be charged if those costs are higher than the 
rates in section II.A.

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 Energy 
Transmission rate, 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. Embedded Cost
    The Billing Demand shall be the largest of:
    1. The Transmission Demand, or, if defined in the agreement, the 
Total Transmission Demand;
    2. The highest hourly Scheduled Demand for the month; or
    3. The Ratchet Demand.
B. Opportunity Cost
    Billing factors shall be specified in the agreement.

Section IV. Other Provisions

A. Ancillary Services
    Ancillary services that may be required to support IR transmission 
service are available under the APS rate schedule.
B. Reactive Power Charge
    Customers taking service under this rate schedule are subject to 
the Reactive Power Charge specified in section II.N. of the General 
Rate Schedule Provisions.
C. Reservation Fee for Transmission Capacity
    Customers who request new or increased firm transmission service 
under this rate schedule and want to reserve transmission capacity to 
accommodate such service are subject to the Reservation Fee for 
Transmission Capacity specified in section II.O. of the General Rate 
Schedule Provisions.
D. Rates Applicable to IR Service
    The rates specified in section II are applicable to service over 
available transmission capacity. Customers requesting new or increased 
firm service that would require BPA to construct new facilities or 
upgrades to alleviate a capacity constraint may be subject to 
incremental cost rates for such service if incremental cost is higher 
than embedded cost. Incremental cost rates would be developed pursuant 
to section 7(i) of the Northwest Power Act.

Schedule NT-96.2 Network Integration Transmission Rate

Section I. Availability

    This schedule is available to each customer that executes a Network 
Integration Service Agreement (Agreement) and does not elect the 5-year 
rate option. Such Agreement provides for delivery of Federal and non-
Federal power to the customer's Network Load over Federal Columbia 
River Transmission System Network and Utility/DSI Delivery facilities. 
Terms and conditions of service are specified in the Network 
Integration Service Tariff. This schedule is available also for 
transmission service of a similar nature ordered by the Federal Energy 
Regulatory Commission (FERC) pursuant to sections 211 and 212 of the 
Federal Power Act (16 U.S.C. 824j and 824k). This schedule is available 
to utilities participating in the residential exchange under section 
5(c) of the Northwest Power Act pursuant to their Residential Purchase 
and Sale Agreements (RPSA). Service under this schedule is not 
available for transmission of non-Federal power to customers taking 
service concurrently under the Integration of Resources rate or Formula 
Power Transmission rate. Service under this schedule is subject to 
BPA's General Rate Schedule Provisions. Bills shall be rendered and 
payments due pursuant to BPA's Billing Procedures.

Section II. Rate

    The monthly charge shall be the sum of A and B.
A. Network Charge
    $1.597 per kilowatt per month of Billing Demand.
B. Delivery Charges
1. Utility
    For service over Utility Delivery facilities, the charge is $1.143 
per kilowatt per month of Billing Demand. 

[[Page 36500]]

2. DSI
    For service over DSI Delivery facilities, the charge is $0.404 per 
kilowatt per month of Billing Demand.
C. Redispatch Credit/Cost
    When BPA implements redispatch procedures pursuant to the Network 
Integration Service Tariff, the total cost impact of such procedures 
shall be shared among Network Integration customers based on the ratio 
of each customer's NT Network Charge Billing Demand to the sum of all 
NT Network Charge Billing Demands. Such Billing Demands shall be for 
the month in which the redispatch cost is incurred. Redispatch cost 
shall be charged on NT customers' monthly bills in a lump sum amount.
    To the extent that the cost borne by the NT customer whose resource 
was redispatched is greater than such customer's cost share (as 
determined above), a credit shall be given on the affected NT 
customer's monthly bill. To the extent that the cost borne by the 
affected NT customer is less than such customer's cost responsibility, 
the difference shall be charged on the affected NT customer's monthly 
bill.

Section III. Billing Factors

A. Network Charge
1. Billing Demand
    The monthly Billing Demand for the charge specified in section 
II.A. shall be the Customer's Load.
    Where ``Customer's Load'' is the customer's Network Load measured 
during the hour of the Monthly Transmission Peak Load. For customers 
with 1981 Contracts, ``Customer's Load'' is the power taken under 1981 
Contracts during the hour of the Monthly Transmission Peak Load. 
``Monthly Transmission Peak Load'' is the monthly peak loading on the 
FCRTS for the billing month.
    ``Network Load'' is the designated load of a Transmission Customer 
including the entire load of all designated Member Systems. A 
Transmission Customer's Network Load shall not be reduced to reflect 
any portion of such load served by the output of any generating 
facilities owned, or generation purchased, by the Transmission 
Customer, its Member Systems, or other customers served by the 
Transmission Customer under the Network Integration Service Tariff.
    The Network Load is the Transmission Customer's actual total system 
load, including distribution losses. No distinction is made between 
load that is served with BPA power and load that is served with power 
from other sources. To the extent the Transmission Customer is served 
with resources remote from their system, Network Load shall be measured 
at specified Points of Delivery.
2. Residential Exchange
    For RPSA utilities, the Billing Demand shall be the demand 
calculated by applying the load factor, determined as specified in the 
RPSA, to the energy associated with the utility's residential load for 
each billing period. Residential load shall be determined in accordance 
with the provisions of the purchaser's RPSA.
3. Network Billing Demand Adjustment
    The Network Charge Billing Demand determined under section III.A.1. 
shall be decreased by the power delivered under any BPA power sales 
contract, not including 1981 Contracts and 1996 Contracts, during the 
hour of the Monthly Transmission Peak Load. Adjustments shall be made 
for power delivered under contracts executed prior to October 1, 1996, 
that bundle the price for transmission with the price for power, or 
specify a transmission rate different than this NT Network rate.
B. Delivery Charge
    The monthly billing demand for the charges specified in section 
II.B. shall be the Customer's Load that occurs during the hour of the 
Monthly Transmission Peak Load at the Points of Delivery specified in 
BPA's Segmentation Study as Utility Delivery or DSI Delivery 
facilities.
C. Adjustment for Metering
    At those Points of Delivery that do not have meters capable of 
determining the demand on the hour of the Monthly Transmission Peak 
Load, the Billing Demand shall equal the highest hourly peak demand 
during the billing month at the Point of Delivery multiplied by 0.76.

Section IV. Adjustments and Other Provisions

A. Customer Facilities Credit
    Monthly bills for the Network Charge specified in section II.A. 
shall be reduced by a Customer Facilities Credit, if contractually 
specified. The Customer Facilities Credit is based on the annual cost 
of customer-owned transmission facilities which would be included in 
BPA's revenue requirement for the Network segment if BPA owned such 
customer facilities. The specification of which customer-owned 
transmission facilities shall be included in the Customer Facilities 
Credit shall be based on a determination of whether BPA would be 
responsible for providing such facilities, in accordance with BPA's 
Customer Service Policy, if the requesting party were a BPA full 
requirements power customer. The annual cost of the identified 
customer-owned transmission facilities shall be based on the customer's 
costs. The Customer Facilities Credit will be specified as a monthly 
amount in an exhibit to the contract. The Customer Facilities Credit is 
not available to Metered and Computed Requirements Customers.
B. Credit to NT Network Charge Bill
    A credit shall be made to the monthly bill for Network Integration 
Transmission Service for Partial Requirements Customers who purchase 
transmission service under Integration of Resources (IR) or Formula 
Power Transmission (FPT) rate schedules. Such credit shall equal the 
portion of the monthly bill for IR or FPT service to the customer's 
Network Load.
C. Credit to Delivery Charges
    A credit shall be made to the monthly bill for Network Integration 
Transmission Service for customers who pay for Utility Delivery or DSI 
Delivery facilities under the Use-of-Facilities (UFT) rate schedule. 
The credit shall equal the monthly UFT charges for such Delivery 
facilities.
D. Ancillary Services
    Ancillary services that may be required to support NT transmission 
service are available under the APS rate schedule.
E. Reactive Power Charge
    Customers taking service under this rate schedule are subject to 
the Reactive Power Charge specified in section II.N. of the General 
Rate Schedule Provisions.
F. Direct Assignment Facilities
    BPA shall collect the capital and related costs of a Direct 
Assignment Facility under the Advance Funding (AF) rate or the Use-of-
Facilities (UFT) rate. Associated costs, including but not limited to 
operations, maintenance, and general plant costs, also shall be 
recovered from the Network Integration Transmission customer under an 
applicable rate schedule.
G. Rates Applicable to NT Service
    The rates specified in section II are applicable to service over 
available transmission capacity. NT customers that integrate new 
Network Resources, new Member Systems, or new native load customers 
that would require BPA to construct Network Upgrades shall be 

[[Page 36501]]
subject to the higher of the rates specified in section II or 
incremental cost rates for service over such facilities. Incremental 
cost rates would be developed pursuant to section 7(i) of the Northwest 
Power Act.
H. Rate Adjustment Due to FERC Order Under FPA Sec. 212
    If, after review by FERC, this rate schedule, as initially 
submitted to FERC, is modified to satisfy the standards of section 
212(i)(1)(B)(ii) of the Federal Power Act (16 U.S.C. 824k(i)(1)(B)(ii)) 
for FERC-ordered transmission service, then such modifications shall 
automatically apply to this rate schedule for non-section 
212(i)(1)(B)(ii) transmission service. The modifications for non-
section 212(i)(1)(B)(ii) transmission service, as described above, 
shall be effective, however, only prospectively from the date of the 
final FERC-order granting final approval of this rate schedule for FERC 
ordered transmission service pursuant to section 212(i)(1)(B)(ii). No 
refunds shall be made or additional costs charged as a consequence of 
this prospective modification for any non-section 212(i)(1)(B)(ii) 
transmission service that occurred under this rate schedule prior to 
the effective date of such prospective modification.

Schedule NT-96.5--Network Integration Transmission Rate

Section I. Availability

    This schedule is available to each customer that executes a Network 
Integration Service Agreement (Agreement) and elects the 5-year rate 
option. Such Agreement provides for delivery of Federal and non-Federal 
power to the customer's Network Load over Federal Columbia River 
Transmission System Network and Utility/DSI Delivery facilities. Terms 
and conditions of service are specified in the Network Integration 
Service Tariff. This schedule is available also for transmission 
service of a similar nature ordered by the Federal Energy Regulatory 
Commission (FERC) pursuant to sections 211 and 212 of the Federal Power 
Act (16 U.S.C. 824j and 824k). Service under this schedule is not 
available for transmission of non-Federal power to customers taking 
service concurrently under the Integration of Resources rate or Formula 
Power Transmission rate. Service under this schedule is subject to 
BPA's General Rate Schedule Provisions. Bills shall be rendered and 
payments due pursuant to BPA's Billing Procedures.

Section II. Rate

    The monthly charge shall be the sum of A and B.
A. Network Charge
    $1.656 per kilowatt per month of Billing Demand.
B. Delivery Charges
1. Utility
    For service over Utility Delivery facilities, the charge is $1.164 
per kilowatt per month of Billing Demand.
2. DSI
    For service over DSI Delivery facilities, the charge is $0.415 per 
kilowatt per month of Billing Demand.
C. Redispatch Credit/Cost
    When BPA implements redispatch procedures pursuant to the Network 
Integration Service Tariff, the total cost impact of such procedures 
shall be shared among Network Integration customers based on the ratio 
of each customer's NT Network Charge Billing Demand to the sum of all 
NT Network Charge Billing Demands. Such Billing Demands shall be for 
the month in which the redispatch cost is incurred. Redispatch cost 
shall be charged on NT customers' monthly bills in a lump sum amount.
    To the extent that the cost borne by the NT customer whose resource 
was redispatched is greater than such customer's cost share (as 
determined above), a credit shall be given on the affected NT 
customer's monthly bill. To the extent that the cost borne by the 
affected NT customer is less than such customer's cost responsibility, 
the difference shall be charged on the affected NT customer's monthly 
bill.
Section III. Billing Factors

A. Network Charge
1. Billing Demand
    The monthly billing demand for the charge specified in section 
II.A. shall be the Customer's Load.
    Where ``Customer's Load'' is the customer's Network Load measured 
during the hour of the Monthly Transmission Peak Load. For customers 
with 1981 Contracts, ``Customer's Load'' is the power taken under the 
1981 Contracts during the hour of the Monthly Transmission Peak Load. 
``Monthly Transmission Peak Load'' is the monthly peak loading on the 
FCRTS for the billing month.
    ``Network Load'' is the designated load of a Transmission Customer 
including the entire load of all designated Member Systems. A 
Transmission Customer's Network Load shall not be reduced to reflect 
any portion of such load served by the output of any generating 
facilities owned, or generation purchased, by the Transmission 
Customer, its Member Systems, or other customers served by the 
Transmission Customer under the Network Integration Service Tariff.
    The Network Load is the Transmission Customer's actual total system 
load, including distribution losses. No distinction is made between 
load that is served with BPA power and load that is served with power 
from other sources. To the extent the Transmission Customer is served 
with resources remote from their system, Network Load shall be measured 
at specified Points of Delivery.
2. Network Billing Demand Adjustment
    The Network Charge Billing Demand determined under section III.A.1. 
shall be decreased by the power delivered under any BPA power sales 
contract, not including 1981 Contracts and 1996 Contracts, during the 
hour of the Monthly Transmission Peak Load. Adjustments shall be made 
for power delivered under contracts executed prior to October 1, 1996, 
that bundle the price for transmission with the price for power, or 
specify a transmission rate different than this NT Network rate.
B. Delivery Charge
    The monthly Billing Demand for the charges specified in section 
II.B. shall be the Customer's Load that occurs during the hour of the 
Monthly Transmission Peak Load at the Points of Delivery specified in 
BPA's Segmentation Study as Utility Delivery or DSI Delivery 
facilities.
C. Adjustment for Metering
    At those Points of Delivery that do not have meters capable of 
determining the demand on the hour of the Monthly Transmission Peak 
Load, the Billing Demand shall equal the highest hourly peak demand 
during the billing month at the Point of Delivery multiplied by 0.76.

Section IV. Adjustments and Other Provisions

A. Customer Facilities Credit
    Monthly bills for the Network Charge specified in section II.A. 
shall be reduced by a Customer Facilities Credit, if contractually 
specified. The Customer Facilities Credit is based on the annual cost 
of customer-owned transmission facilities which would be included in 
BPA's revenue requirement for the Network segment if BPA owned such 
customer facilities. The specification of 

[[Page 36502]]
which customer-owned transmission facilities shall be included in the 
Customer Facilities Credit shall be based on a determination of whether 
BPA would be responsible for providing such facilities, in accordance 
with BPA's Customer Service Policy, if the requesting party were a BPA 
full requirements power customer. The annual cost of the identified 
customer-owned transmission facilities shall be based on the customer's 
costs. The Customer Facilities Credit will be specified as a monthly 
amount in an exhibit to the contract. The Customer Facilities Credit is 
not available to Metered and Computed Requirements Customers.
B. Credit to NT Network Charge Bill
    A credit shall be made to the monthly bill for Network Integration 
Transmission Service for Partial Requirements customers who purchase 
transmission service under Integration of Resources (IR) or Formula 
Power Transmission (FPT) rate schedules. Such credit shall equal the 
portion of the monthly bill for IR or FPT service to the customer's 
Network Load.
C. Credit to Delivery Charges
    A credit shall be made to the monthly bill for Network Integration 
Transmission Service for customers who pay for Utility Delivery or DSI 
Delivery facilities under the Use-of-Facilities (UFT) rate schedule. 
The credit shall equal the monthly UFT charges for such Delivery 
facilities.
D. Ancillary Services
    Ancillary services that may be required to support NT transmission 
service are available under the APS rate schedule.
E. Reactive Power Charge
    Customers taking service under this rate schedule are subject to 
the Reactive Power Charge specified in section N of the General Rate 
Schedule Provisions.
F. Direct Assignment Facilities
    BPA shall collect the capital and related costs of a Direct 
Assignment Facility under the Advance Funding (AF) rate or the Use-of-
Facilities (UFT) rate. Associated costs, including but not limited to 
operations, maintenance, and general plant costs, also shall be 
recovered from the Network Integration Transmission customer under an 
applicable rate schedule.
G. Rates Applicable to NT Service
    The rates specified in section II are applicable to service over 
available transmission capacity. NT customers that integrate new 
Network Resources, new Member Systems, or new Native Load Customers 
that would require BPA to construct Network Upgrades shall be subject 
to the higher of the rates specified in section II or incremental cost 
rates for service over such facilities. Incremental cost rates would be 
developed pursuant to section 7(i) of the Northwest Power Act.
H. Rate Adjustment Due to FERC Order Under FPA Sec. 212
    If, after review by FERC, this rate schedule, as initially 
submitted to FERC, is modified to satisfy the standards of section 
212(i)(1)(B)(ii) of the Federal Power Act (16 U.S.C. 824k(i)(1)(B)(ii)) 
for FERC-ordered transmission service, then such modifications shall 
automatically apply to this rate schedule for non-section 
212(i)(1)(B)(ii) transmission service. The modifications for non-
section 212(i)(1)(B)(ii) transmission service, as described above, 
shall be effective, however, only prospectively from the date of the 
final FERC order granting final approval of this rate schedule for 
FERC-ordered transmission service pursuant to section 212(i)(1)(B)(ii). 
No refunds shall be made or additional costs charged as a consequence 
of this prospective modification for any non-section 212(i)(1)(B)(ii) 
transmission service that occurred under this rate schedule prior to 
the effective date of such prospective modification.

Schedule PTP-96.2--Point-to-Point Transmission Rate

Section I. Availability

    This schedule is available to each Customer that executes a Point-
to-Point Transmission Service Agreement (Agreement) and does not elect 
the 5-year rate option. Such Agreement provides for firm transmission 
service for Federal and non-Federal power for one calendar month or 
longer and for nonfirm transmission service in amounts not to exceed 
the customer's total Transmission Demand over Federal Columbia River 
Transmission System (FCRTS) Network and Utility/DSI Delivery 
facilities. Terms and conditions of service are specified in the Point-
to-Point Transmission Service Tariff. This schedule is available also 
for transmission service of a similar nature ordered by the Federal 
Energy Regulatory Commission (FERC) pursuant to sections 211 and 212 of 
the Federal Power Act (16 U.S.C. 824j and 824k). Service under this 
schedule for the transmission of non-Federal power is not available to 
customers taking service concurrently under the Integration of 
Resources rate or Formula Power Transmission rate. Service under this 
schedule is subject to BPA's General Rate Schedule Provisions. Bills 
shall be rendered and payments due pursuant to BPA's Billing 
Procedures.

Section II. Rate

A. Network Charge
    The charge shall be 1 or 2.
1. Embedded Cost
    $1.315 per kilowatt per month of Billing Demand.
2. Opportunity Cost
    For applications for new service or increases in current service, 
Opportunity Costs may be charged if those costs are higher than the 
rates in section II.A.1.
B. Delivery Charge
1. Utility
    For service over Utility Delivery facilities, the charge is $1.143 
per kilowatt per month of Billing Demand.
2. DSI
    For service over DSI Delivery facilities, the charge is $0.404 per 
kilowatt per month of Billing demand.

Section III. Billing Factors

    The monthly Transmission Demands shall be contractually specified.
A. Network Charge
1. Embedded Cost
    The monthly Billing Demand for the rate specified in section 
II.A.1. shall be the greater of:
    a. the sum of the monthly Point of Integration Transmission Demands 
(including monthly peak subscriptions designated pursuant to 1996 
Contracts and computed peak requirements pursuant to 1981 Contracts) 
that correspond to the current billing month, or
    b. the sum of the monthly Point of Delivery Transmission Demands 
(including monthly peak subscriptions designated pursuant to 1996 
Contracts and computed peak requirements pursuant to 1981 Contracts) 
that correspond to the current billing month.
2. Opportunity Cost
    The billing factor for the rate in section II.A.2. shall be 
specified in the Agreement.
B. Delivery Charge
    The monthly Billing Demand for the charges specified in section 
II.B. shall be the Measured Demand that occurs during the hour of the 
Monthly 

[[Page 36503]]
Transmission Peak Load at the Points of Delivery specified in BPA's 
Segmentation Study as Utility Delivery or DSI Delivery facilities.
    At those points of delivery that do not have meters capable of 
determining the demand on the hour of the Monthly Transmission Peak 
Load, the Billing Demand shall equal the highest hourly peak demand 
during the billing month at the Point of Delivery multiplied by 0.76.

Section IV. Other Provisions

A. Reactive Power Charge
    Customers taking service under this rate schedule are subject to 
the Reactive Power Charge specified in section II.N. of the General 
Rate Schedule Provisions.
B. Ancillary Services
    Ancillary services that may be required to support PTP transmission 
service are available under the APS rate schedule.
C. PTP Unauthorized Transmission Increase Charge
    Customers who exceed their monthly Point of Integration (POI) or 
Point of Delivery (POD) Transmission Demand on any hour shall be 
subject to the PTP Unauthorized Transmission Increase Charge.
1. Rate
    $16.78 per kilowatt of Billing Demand.
2. Billing Factor
    The Billing Demand shall be the number of kilowatts that exceeds 
the monthly Transmission Demand at any POI or POD, or exceeds the sum 
of monthly POI or POD Transmission Demands, on any hour.
D. Reservation Fee for Transmission Capacity
    Customers who request new or increased firm transmission service 
under this rate schedule and want to reserve transmission capacity to 
accommodate such service are subject to the Reservation Fee for 
Transmission Capacity specified in section II.O. of the General Rate 
Schedule Provisions.
E. Direct Assignment Facilities
    BPA shall collect the capital and related costs of a Direct 
Assignment Facility under the Advance Funding (AF) rate or the Use-of-
Facilities (UFT) rate. Associated costs, including but not limited to 
operations, maintenance, and general plant costs, also shall be 
recovered from the Point-to-Point Transmission customer under an 
applicable rate schedule.
F. Redispatch
    When BPA determines that capacity constraints that may be relieved 
more economically through redispatching the system rather than by 
building new facilities or upgrading existing facilities to eliminate 
such constraints, the customer taking Point-to-Point Transmission 
Service shall be responsible for such costs to the extent consistent 
with FERC policy.
G. Rates Applicable to PTP Service
    The rates specified in section II are applicable to service over 
available transmission capacity. Customers requesting new or increased 
firm service that would require BPA to construct Network Upgrades to 
alleviate a capacity constraint may be subject to incremental cost 
rates for such service if incremental cost is higher than embedded 
cost. Incremental cost rates would be developed pursuant to section 
7(i) of the Northwest Power Act.
H. Rate Adjustment Due to FERC Order Under FPA Sec. 212
    If, after review by FERC, this rate schedule, as initially 
submitted to FERC, is modified to satisfy the standards of section 
212(i)(1)(B)(ii) of the Federal Power Act (16 U.S.C. 824k(i)(1)(B)(ii)) 
for FERC-ordered transmission service, then such modifications shall 
automatically apply to this rate schedule for non-section 
212(i)(1)(B)(ii) transmission service. The modifications for non-
section 212(i)(1)(B)(ii) transmission service, as described above, 
shall be effective, however, only prospectively from the date of the 
final FERC order granting final approval of this rate schedule for 
FERC-ordered transmission service pursuant to section 212(i)(1)(B)(ii). 
No refunds shall be made or additional costs charged as a consequence 
of this prospective modification for any non-section 212(i)(1)(B)(ii) 
transmission service that occurred under this rate schedule prior to 
the effective date of such prospective modification.

Schedule PTP-96.5--Point-to-Point Firm Transmission Rate

Section I. Availability

    This schedule is available to each Customer that executes a Point-
to-Point Transmission Service Agreement (Agreement) and elects the 5-
year rate option. Such Agreement provides for firm transmission service 
for Federal and non-Federal power for one calendar month or longer and 
for nonfirm transmission service in amounts not to exceed the 
customer's total Transmission Demand over Federal Columbia River 
Transmission System (FCRTS) Network and Utility/DSI Delivery 
facilities. Terms and conditions of service are specified in the Point-
to-Point Transmission Service Tariff. This schedule is available also 
for transmission service of a similar nature ordered by the Federal 
Energy Regulatory Commission (FERC) pursuant to sections 211 and 212 of 
the Federal Power Act (16 U.S.C. 824j and 824k). Service under this 
schedule for the transmission of non-Federal power is not available to 
customers taking service concurrently under the Integration of 
Resources rate or Formula Power Transmission rate. Service under this 
schedule is subject to BPA's General Rate Schedule Provisions. Bills 
shall be rendered and payments due pursuant to BPA's Billing 
Procedures.

Section II. Rate

A. Network Charge
    The charge shall be 1 or 2.
1. Embedded Cost
    $1.386 per kilowatt per month of Billing Demand.
2. Opportunity Cost
    For applications for new service or increases in current service, 
Opportunity Costs may be charged if those costs are higher than the 
rates in section II.A
B. Delivery Charge
1. Utility
    For service over Utility Delivery facilities, the charge is $1.164 
per kilowatt per month of Billing Demand.
2. DSI
    For service over DSI Delivery facilities, the charge is $0.415 per 
kilowatt per month of Billing Demand.

Section III. Billing Factors

    The monthly Transmission Demands shall be contractually specified.
A. Network Charge
1. Embedded Cost
    The monthly Billing Demand for the rate specified in section 
II.A.1. shall be the greater of:
    a. the sum of the monthly Point of Integration Transmission Demands 
(including monthly peak subscriptions designated pursuant to 1996 
Contracts and computed peak requirements pursuant to 1981 Contracts) 
that correspond to the current billing month, or
    b. the sum of the monthly Point of Delivery Transmission Demands 
(including monthly peak subscriptions 

[[Page 36504]]
designated pursuant to 1996 Contracts and computed peak requirements 
pursuant to 1981 Contracts) that correspond to the current billing 
month.
2. Opportunity Cost
    The billing factor(s) for the rate in section II.A.2. shall be 
specified in the Agreement.
B. Delivery Charge
    The monthly Billing Demand for the charges specified in section 
II.B. shall be the Measured Demand that occurs during the hour of the 
Monthly Transmission Peak Load at the Points of Delivery specified in 
BPA's Segmentation Study as Utility Delivery or DSI Delivery 
facilities.
    At those Points of Delivery that do not have meters capable of 
determining the demand on the hour of the Monthly Transmission Peak 
Load, the Billing Demand shall equal the highest hourly peak demand 
during the billing month at the Point of Delivery multiplied by 0.76.

Section IV. Other Provisions

A. Reactive Power Charge
    Customers taking service under this rate schedule are subject to 
the Reactive Power Charge specified in section II.N. of the General 
Rate Schedule Provisions.
B. Ancillary Services
    Ancillary services that may be required to support PTP transmission 
service are available under the APS rate schedule.
C. PTP Unauthorized Transmission Increase Charge
    Customers who exceed their monthly Point of Integration (POI) or 
Point of Delivery (POD) Transmission Demand on any hour shall be 
subject to the PTP Unauthorized Transmission Increase Charge.
1. Rate
    $15.63 per kilowatt of Billing Demand.
2. Billing Factor
    The Billing Demand shall be the number of kilowatts that exceeds 
the monthly Transmission Demand at any POI or POD, or exceeds the sum 
of monthly POI or POD Transmission Demands, on any hour.
D. Reservation Fee for Transmission Capacity
    Customers who request new or increased firm transmission service 
under this rate schedule and want to reserve transmission capacity to 
accommodate such service are subject to the Reservation Fee for 
Transmission Capacity specified in section II.O. of the General Rate 
Schedule Provisions.
E. Direct Assignment Facilities
    BPA shall collect the capital and related costs of a Direct 
Assignment Facility under the Advance Funding (AF) rate or the Use-of-
Facilities (UFT) rate. Associated costs, including but not limited to 
operations, maintenance, and general plant costs, also shall be 
recovered from the Point-to-Point Firm Transmission customer under an 
applicable rate schedule.
F. Redispatch
    When BPA determines that capacity constraints may be relieved more 
economically through redispatching the system rather than by building 
new facilities or upgrading existing facilities to eliminate such 
constraints, the customer taking Point-to-Point Transmission Service 
shall be responsible for such costs to the extent consistent with FERC 
policy.
G. Rates Applicable to PTP Service
    The rates specified in section II are applicable to service over 
available transmission capacity. Customers requesting new or increased 
firm service that would require BPA to construct Network Upgrades to 
alleviate a capacity constraint may be subject to incremental cost 
rates for such service if incremental cost is higher than embedded 
cost. Incremental cost rates would be developed pursuant to section 
7(i) of the Northwest Power Act.
H. Rate Adjustment Due to FERC Order Under FPA Sec. 212
    If, after review by FERC, this rate schedule, as initially 
submitted to FERC, is modified to satisfy the standards of section 
212(i)(1)(B)(ii) of the Federal Power Act (16 U.S.C. 824k(i)(1)(B)(ii)) 
for FERC-ordered transmission service, then such modifications shall 
automatically apply to this rate schedule for non-section 
212(i)(1)(B)(ii) transmission service. The modifications for non-
section 212(i)(1)(B)(ii) transmission service, as described above, 
shall be effective, however, only prospectively from the date of the 
final FERC order granting final approval of this rate schedule for 
FERC-ordered transmission service pursuant to section 212(i)(1)(B)(ii). 
No refunds shall be made or additional costs charged as a consequence 
of this prospective modification for any non-section 212(i)(1)(B)(ii) 
transmission service that occurred under this rate schedule prior to 
the effective date of such prospective modification.

Schedule ET-96--Energy Transmission Rate

Section I. Availability

    This schedule supersedes ET-95 and is available for transmission 
service between points within the Pacific Northwest using Federal 
Columbia River Transmission System (FCRTS) facilities excluding the 
Southern Intertie, Eastern Intertie, and Northern Intertie. This rate 
is available for transmission of Federal and non-Federal power for firm 
transmission service of less than one calendar month duration and for 
nonfirm transmission service. Terms and conditions of Energy 
Transmission service are specified in the Point-to-Point Service 
Tariff. This schedule is available for transmission service of a 
similar nature ordered by the Federal Energy Regulatory Commission 
(FERC) pursuant to sections 211 and 212 of the Federal Power Act (16 
U.S.C. 824j and 824k). Service under this schedule is subject to BPA's 
General Rate Schedule Provisions. Bills shall be rendered and payments 
due pursuant to BPA's Billing Procedures.

Section II. Rate

    The charge shall be A or B.
A. Firm
1. Embedded Cost
    2.44 mills per kilowatt-hour.
2. Opportunity Cost
    For applications for new firm service or increases in current firm 
service, Opportunity Costs may be charged if those costs are higher 
than the rates in section II.A.1.
B. Nonfirm
    The charge shall not exceed 2.44 mills per kilowatt-hour.

Section III. Billing Factors

    The Billing Energy for the charge specified in section II.A.1. 
shall be the Contract Energy.
    The Billing Energy for the rate in section II.A.2. shall be 
specified in the agreement.
    The Billing Energy for charges under section II.B. shall be the 
monthly sum of scheduled kilowatt-hours.
Section IV. Other Provisions

A. Ancillary Services
    Ancillary services that may be required to support ET transmission 
service are available under the APS rate schedule. 

[[Page 36505]]

B. ET Unauthorized Transmission Increase Charge
    Customers who exceed their Contract Energy at any Point of 
Integration (POI) or Point of Delivery (POD) shall be subject to the ET 
Unauthorized Transmission Increase Charge.
1. Rate
    29.28 mills per kilowatt-hour of Billing Energy.
2. Billing Factor
    The Billing Energy shall be the amount of energy that exceeds the 
monthly Contract Energy at specified POIs or PODs.
C. Reactive Power Charge
    Customers taking service under this rate schedule are subject to 
the Reactive Power Charge specified in section II.N. of the General 
Rate Schedule Provisions.
D. Rate Adjustment Due to FERC Order Under FPA Sec. 212
    If, after review by FERC, this rate schedule, as initially 
submitted to FERC, is modified to satisfy the standards of section 
212(i)(1)(B)(ii) of the Federal Power Act (16 U.S.C. 824k(i)(1)(B)(ii)) 
for FERC-ordered transmission service, then such modifications shall 
automatically apply to this rate schedule for non-section 
212(i)(1)(B)(ii) transmission service. The modifications for non-
section 212(i)(1)(B)(ii) transmission service, as described above, 
shall be effective, however, only prospectively from the date of the 
final FERC order granting final approval of this rate schedule for 
FERC-ordered transmission service pursuant to section 212(i)(1)(B)(ii). 
No refunds shall be made or additional costs charged as a consequence 
of this prospective modification for any non-section 212(i)(1)(B)(ii) 
transmission service that occurred under this rate schedule prior to 
the effective date of such prospective modification.

Schedule IS-96--Southern Intertie Transmission Rate

Section I. Availability

    This schedule supersedes IS-95 and is available for firm and 
nonfirm transmission service on the Southern Intertie. Service under 
this schedule is subject to BPA's General Rate Schedule Provisions. 
Bills shall be rendered and payments due pursuant to BPA's Billing 
Procedures.

Section II. Rate

    The rates below apply to both north-to-south and south-to-north 
transactions.
A. Nonfirm Transmission Rate
    The charge shall not exceed 3.53 mills per kilowatt-hour of Billing 
Energy.
B. Firm Transmission Rate
    The charge shall be 1 or 2.
1. Embedded Cost
    $0.740 per kilowatt per month of Billing Demand, and 1.77 mills per 
kilowatt-hour of Billing Energy.
2. Opportunity Cost
    For applications for new firm service or increases in current firm 
service, Opportunity Costs may be charged if those costs are higher 
than the rates in section II.B.1.

Section III. Billing Factors

A. Nonfirm Transmission
    For nonfirm service under section II.A., the Billing Energy shall 
be the monthly sum of the scheduled kilowatt-hours, plus the monthly 
sum of kilowatt-hours allocated but not scheduled. The amount of 
allocated but not scheduled kilowatt-hours that is subject to billing 
may be reduced pro rata by BPA due to forced Intertie outages and other 
uncontrollable forces that may reduce Southern Intertie capacity. The 
amount of allocated but not scheduled kilowatt-hours that is subject to 
billing also may be reduced upon mutual agreement between BPA and the 
customer.
B. Firm Transmission
    For firm transmission service under section II.B.1., the Billing 
Demand shall be the Transmission Demand as specified in the agreement. 
The Billing Energy for firm transmission service shall be the monthly 
sum of scheduled kilowatt-hours, unless otherwise specified in the 
agreement.
    For firm transmission service under section II.B.2., the billing 
factors shall be specified in the agreement.

Section IV. Other Provisions

A. Ancillary Services
    Ancillary services that may be required to support IS transmission 
service are available under the APS rate schedule.
B. Reactive Power Charge
    Customers taking service under this rate schedule are subject to 
the Reactive Power Charge specified in section II.N. of the General 
Rate Schedule Provisions.
C. Reservation Fee for Transmission Capacity
    Customers who request new or increased firm transmission service 
under this rate schedule and want to reserve transmission capacity to 
accommodate such service will be subject to the Reservation Fee for 
Transmission Capacity specified in section II.O. of the General Rate 
Schedule Provisions.
D. Rates Applicable to IS Service
    The rates specified in section II are applicable to service over 
available transmission capacity. Customers requesting new or increased 
firm service that would require BPA to construct new facilities or 
upgrades to alleviate a capacity constraint may be subject to 
incremental cost rates for such service if incremental cost is higher 
than embedded cost. Incremental cost rates would be developed pursuant 
to section 7(i) of the Northwest Power Act.

Schedule IN-96 Northern Intertie Transmission Rate

Section I. Availability

    This schedule supersedes IN-95 and is available for firm and 
nonfirm transmission service on the Northern Intertie. Service under 
this schedule is subject to BPA's General Rate Schedule Provisions. 
Bills shall be rendered and payments due pursuant to BPA's Billing 
Procedures.

Section II. Rate

    The rates below apply to both north-to-south and south-to-north 
transactions.
A. Nonfirm Transmission Rate
    The charge shall not exceed 0.63 mills per kilowatt-hour of Billing 
Energy.
B. Firm Transmission Rate
    The charge shall be 1 or 2.
1. Embedded Cost
    $0.115 per kilowatt per month of Billing Demand, and 0.31 mills per 
kilowatt-hour of Billing Energy.
2. Opportunity Cost
    For applications for new firm service or increases in current firm 
service, Opportunity Costs may be charged if those costs are higher 
than the rates in section II.B.1.

Section III. Billing Factors

A. Nonfirm Transmission
    For nonfirm service under section II.A., the Billing Energy shall 
be the monthly sum of the scheduled kilowatt-hours.
B. Firm Transmission
    For firm service under section II.B.1., the Billing Demand shall be 
the Transmission Demand specified in the 

[[Page 36506]]
agreement. The Billing Energy for firm service shall be the monthly sum 
of the scheduled kilowatt-hours, unless otherwise specified in the 
agreement.
    For firm transmission service under section II.B.2., the billing 
factors shall be specified in the agreement.

Section IV. Other Provisions

A. Ancillary Services
    Ancillary services that may be required to support IN transmission 
service are available under the APS rate schedule.
B. Reactive Power Charge
    Customers taking service under this rate schedule are subject to 
the Reactive Power Charge specified in section II.N. of the General 
Rate Schedule Provisions.
C. Reservation Fee for Transmission Capacity
    Customers who request new or increased firm transmission service 
under this rate and want to reserve transmission capacity to 
accommodate such service are subject to the Reservation Fee for 
Transmission Capacity specified in section II.O. of the General Rate 
Schedule Provisions.
D. Rates Applicable to IN Service
    The rates specified in section II are applicable to service over 
available transmission capacity. Customers requesting new or increased 
firm service that would require BPA to construct new facilities or 
upgrades to alleviate a capacity constraint may be subject to 
incremental cost rates for such service if incremental cost is higher 
than embedded cost. Incremental cost rates would be developed pursuant 
to section 7(i) of the Northwest Power Act.

Schedule IE-96--Eastern Intertie Transmission Rate

Section I. Availability

    This schedule supersedes IE-95 and is available for nonfirm 
transmission service on the Eastern Intertie. Service under this 
schedule is subject to BPA's General Rate Schedule Provisions. Bills 
shall be rendered and payments due pursuant to BPA's Billing 
Procedures.

Section II. Rate

    The charge shall not exceed 1.89 mills per kilowatt-hour of Billing 
Energy.

Section III. Billing Factors

    Billing Energy shall be the monthly sum of the scheduled kilowatt-
hours, unless otherwise specified in the Agreement.
Section IV. Other Provisions

A. Ancillary Services
    Ancillary services that may be required to support IE transmission 
service are available under the APS rate schedule.
B. Reactive Power Charge
    Customers taking service under this rate schedule are subject to 
the Reactive Power Charge specified in section II.N. of the General 
Rate Schedule Provisions.

Schedule MT-96--Market Transmission Rate

Section I. Availability

    This schedule supersedes MT-95 and is available for transmission 
service for transactions using Federal Columbia River Transmission 
System facilities pursuant to the Western Systems Power Pool (WSPP) 
Agreement. Service under this schedule is subject to BPA's General Rate 
Schedule Provisions. Bills shall be rendered and payments due pursuant 
to BPAs Billing Procedures.

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 kilowatt-hour 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.

Section IV. Other Provisions

A. Ancillary Services
    Ancillary services that may be required to support MT transmission 
service are available under the APS rate schedule.
B. Reactive Power Charge
    Customers taking service under this rate schedule are subject to 
the Reactive Power Charge specified in section II.N. of the General 
Rate Schedule Provisions.

Schedule UFT-96--Use-of-Facilities Transmission Rate

Section I. Availability

    This schedule supersedes UFT-95 unless otherwise provided in the 
agreement, and is available for firm transmission over specified 
Federal Columbia River Transmission System (FCRTS) facilities. Service 
under this schedule is subject to BPA's General Rate Schedule 
Provisions. Bills shall be rendered and payments due pursuant to BPAs 
Billing Procedures.

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 


[[Page 36507]]
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 AF-96 Advance Funding Rate

Section I. Availability

    This schedule is available to customers who execute an agreement 
that provides for BPA to collect capital and related costs through 
advance funding or other financial arrangement for specified BPA-owned 
Federal Columbia River Transmission System (FCRTS) facilities used for:
    A. Interconnection or integration of resources and loads to the 
FCRTS;
    B. Upgrades, replacements, or reinforcements of the FCRTS for 
transmission service; or
    C. Other transmission service arrangements, as determined by BPA. 
Service under this schedule is subject to BPA's General Rate Schedule. 
Bills shall be rendered and payments due pursuant to BPA's Billing 
Procedures.

Section II. Rate

    The charge is the sum of the actual capital and related costs for 
specified FCRTS facilities, as provided in the agreement. Such actual 
capital and related costs include, but are not limited to, costs of 
design, materials, construction, overhead, spare parts, and all 
incidental costs necessary to provide service as identified in the 
agreement.

Section III. Payment

A. Advance Payment
    Payment to BPA shall be specified in the agreement as either:
    1. A lump sum advance payment;
    2. Advance payments pursuant to a schedule of progress payments; or
    3. Other payment arrangement, as determined by BPA.
Such advance payment or payments shall be based on an estimate of the 
capital and related costs for the specified FCRTS facilities as 
provided in the agreement.
B. Adjustment to Advance Payment
    BPA shall determine the actual capital and related costs of the 
specified FCRTS facilities as soon as practicable after the date of 
commercial operation, as determined by BPA. The customer will either 
receive a refund from BPA or be billed for additional payment for the 
difference between the advance payment and the actual capital and 
related costs pursuant to BPA`s Billing Procedures.

Schedule TGT-96

Townsend-Garrison transmission rate

Section I. Availability

    This schedule supersedes TGT-95 and shall apply to all agreements 
which provide for the firm transmission of electric power and energy 
over transmission facilities of BPA's section of the Montana [Eastern] 
Intertie. Service under this schedule is subject to BPA's General Rate 
Schedule Provisions and Adjustments, Charges, and Special Rate 
Provisions. Bills shall be rendered and payments due pursuant to BPAs 
Billing Procedures. Service under this schedule is subject to BPA's 
General Rate Schedule Provisions. Bills shall be rendered and payments 
due pursuant to BPAs Billing Procedures.
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
    Intertie Charge = [((TAC/12-NFR)  x  (CR-EC) TCR ]

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 

[[Page 36508]]
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 Public Law 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.
    F. General Rate Schedule Provisions (GRSPs): This section contains 
the combined GRSPs for power and transmission rates. The GRSPs contain 
detailed descriptions of all adjustments, charges, and special rate 
provisions, and definitions of products and services and of rate 
schedule terms:

Section I  Adoption of Revised Rate Schedules and General Rate Schedule 
Provisions
Section II  Adjustments, Charges, and Special Rate Provisions
Section III  Definitions

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

A. Approval of Rates
    These 1996 wholesale power and transmission 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). Bonneville Power Administration 
(BPA) has requested that FERC make these rates and GRSPs effective on 
October 1, 1996, for customers who are billed by BPA on a calendar 
month basis and on the first day of the first billing month following 
that date for all other customers. All rate schedules shall remain in 
effect until they are replaced or expire on their own terms.
B. General Provisions
    These 1996 wholesale power and transmission rate schedules and the 
GRSPs associated with these schedules supersede BPA's 1995 rate 
schedules (which became effective October 1, 1995) 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 Pacific 
Northwest Electric Power Planning and Conservation Act (Northwest Power 
Act). All sales under these rate schedules are subject to the following 
acts as amended: the Bonneville Project Act, the Regional Preference 
Act (Pub. L. 88-552), the Federal Columbia River Transmission System 
Act (Pub. L. 93-454), the Northwest Power Act (Pub. L. 96-501), and the 
Energy Policy Act of 1992 (Pub. L. 102-486).
    These 1996 rate schedules do not supersede any previously 
established rate schedule which is required, by agreement, to remain in 
effect.
C. Notices
    For the purpose of determining elapsed time from ``receipt'' of a 
notice applicable to rate schedule and GRSP administration, a notice 
shall be deemed to have been received at 0000 hours on the first 
calendar day following actual receipt of the notice.
Section II. Adjustments, Charges, and Special Rate Provisions

A. Conservation Surcharge (PF/NR only)
    The Conservation Surcharge, where implemented, shall be applied in 
accordance with relevant provisions of the Northwest Power Act, BPA's 
current conservation surcharge policy, and the customer's Power Sales 
Contract with BPA. The PF and NR rate schedules are subject to the 
Conservation Surcharge. If 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 PF and NR power purchases 
multiplied by the ratio of: (a) the Purchaser's total retail load that 
is subject to the surcharge; and (b) the customer's total retail load.
    The Conservation Surcharge shall be applied monthly and shall equal 
10 percent of the customer's total monthly charge for any portion of 
power purchased under each rate schedule subject to the surcharge. The 
level of the residential surcharge will be determined by dividing the 
customer's residential load not covered by a BPA-approved Model 
Conservation Standards (MCS) residential plan by the customer's total 
retail load, rounding the result to the nearest one-tenth of a percent 
and multiplying the resulting percentage by 0.10. The level of the 
commercial surcharge will be determined by dividing the customer's 
commercial load not covered by a BPA-approved MCS commercial plan by 
the customer's total retail load, rounding the result to the nearest 
one-tenth of a percent and multiplying the resulting percentage by 
0.10. The residential or commercial surcharge (one or the other, but 
not both for any one customer) will be applied to all power purchases 
and/or exchanges made by the customer under the applicable rate 
schedules, using the Council's surcharge methodology, and will be 
applied subsequent to any other rate adjustment.
B. Cost Contributions
    BPA has made the following resource cost determinations:
    1. The forecasted average cost of resources available to BPA under 
average water conditions is 22.56 mills per kilowatt-hour.
    2. The approximate cost contribution of different resource 
categories to each rate schedule is as follows:

                                                                        

[[Page 36509]]
------------------------------------------------------------------------
                                                       Resource cost    
                                                       contribution     
                                                 -----------------------
                  Rate schedule                     Federal             
                                                     base         New   
                                                    system     resources
                                                   (percent)   (percent)
------------------------------------------------------------------------
PF-96.2.........................................         100           0
PF-96.5.........................................         100           0
IP-96.2.........................................       77.69       22.31
IP-96.5.........................................       77.69       22.31
NR-96.2.........................................       77.69       22.31
NR-96.5.........................................       77.69       22.31
FPS-96..........................................       77.69       22.31
------------------------------------------------------------------------


C. Curtailment Charge (IP Only)
    Curtailment charges are charges assessed pursuant to section 9 of a 
DSI's 1981 Contract for failure to purchase an amount of power equal to 
75 percent of the DSI's Operating Demand.
D. Deviation Adjustment
    The Deviation Adjustment, described below, applies to Partial 
Requirements Purchasers under the 1996 Contract. In addition, for Full 
Requirements customers who purchase under 1996 Contracts, the Deviation 
Adjustment applies to those customers who elect to have their billing 
factor for Load Shaping reduced by an Industrial Exemption. In 
addition, the Deviation Adjustment applies to purchasers under the 
Power Shortage rate.
1. Definition of ``Deviation''
    Deviation is the difference between the quantity of power that was 
actually taken from BPA (Actual) and the quantity the customer should 
have taken pursuant to its power sales contract (Obligation). If a 
customer's Actual exceeds its Obligation, the deviation is considered a 
``positive'' deviation; if its Actual is less than its Obligation, the 
deviation is termed ``negative.''
2. The Customer's Purchase Obligation
    The customer's purchase Obligation is a function of whether the 
customer is purchasing BPA's Load Shaping product. The actual 
description of the Purchaser's Obligation is provided in the 
Purchasers 1996 Contract.
3. Application of the Deviation Adjustment
    The Deviation Adjustment is applied differently to customers 
purchasing Load Shaping and those not purchasing Load Shaping. 
Authorized Deviations are determined and charged for first, followed by 
Unauthorized Deviations.
a. Authorized Deviations

1. Load Shaping Purchasers

    The Authorized Deviation for any purchaser who is buying BPA's Load 
Shaping product is included in the PF, NR, and IP billing factors; 
there is no separate adjustment for Authorized Deviations.

2. Other Purchasers

    All other Purchasers who are subject to the Deviation Adjustment 
are eligible for an Authorized Deviation Adjustment. (In addition, they 
may be subject to the Unauthorized Deviation Charge below.) The 
Purchaser shall pay the established PF, NR, or IP rate, as applicable, 
for the authorized deviation.
b. Unauthorized Deviations

1. Unauthorized Deviation Charge

    a. Demand Charge: Demand Charge from applicable power rate 
schedule.
    b. Energy Charge: 100 mills per kWh in all months of the year.

2. Application of the Unauthorized Deviation Charge

    Application of the Unauthorized Deviation Charge consists of three 
separate calculations, each of which is completed for each purchaser.

Positive Deviations

    BPA will charge for positive deviations on a monthly basis at the 
rate specified above. (There is no additional charge for negative 
deviations, but the customer is not relieved of its take-or-pay 
obligation for negative deviations.)

Rate Period Excessive Purchases

    If, in the last month of the purchase period, BPA determines that 
the Purchaser has taken more power than it is entitled to take to serve 
its actual Retail Load for the purchase period, then the Purchaser 
shall be subject to the Unauthorized Deviation Charge for all such 
excessive purchases.

Diverted Power Adjustment Deviations

    If, in the last month of the purchase period, the Purchaser has not 
taken return of all of its Diverted Power (as described in the Billing 
Procedures), then the Purchaser must pay BPA the Unauthorized Deviation 
charge for all Diverted Power that was not returned to the Purchaser's 
system during the rate period.
E. Election Process
5-Year Rate Election
    Any purchaser, except utilities participating in the residential 
exchange under section 5(c) of the Northwest Power Act, must elect an 
amount of power to be purchased under the applicable 5-year rates (PF-
96.5, IP-96.5 or NR-96.5). The 5-year rate shall apply to purchasers 
who purchase power from BPA under either the 1981 or 1996 Contract and 
who comply with the requirements below.
1. Subscription Options
    The amount of power that customers can purchase under the 5-year 
rate shall be based on one of the following methods.

a. Percentage of Load Option

    This option is available only to: (a) Metered Requirements 
Customers and Actual Computed Requirements Customers as designated in 
the 1981 Contracts; and (b) Full Requirements Customers and Partial 
Requirements Customers as designated in the 1996 Contracts who elect to 
purchase Load Shaping from BPA. This option is not available for 
service to New Large Single Loads (NLSL). Purchasers eligible to use 
this option may select a single percentage equal to or less than 100 
percent for the 5-year period. If a purchaser selects less than 100 
percent, the remaining power purchased from BPA shall be billed at the 
PF-96.2, IP-96.2, or NR-96.2 rate, as appropriate. For utility 
purchasers under 1981 Contracts using this option, the amount of 
subscribed load under the 5-year rate shall be a percentage of the 
purchaser's Measured Demand and Energy. For DSIs purchasing under a 
1981 Contract, the amount of subscribed load at the 5-year rate shall 
be a percentage of the purchaser's operating level and measured energy. 
For Full and Partial Requirements utility and DSI customers under 1996 
Contracts, the amount of subscribed load under the 5-year rate shall be 
a percentage of the purchaser's total actual Retail Load.

b. Block of Power Option

    This option is available to all purchasers except those serving New 
Large Single Loads. For purchasers using this option, the amount of 
subscribed load at the 5-year rate shall be the amount of demand and 
energy as specified by the purchaser. Purchasers using this option 
cannot specify an amount of power that exceeds their contract 
entitlements. Priority Firm Power, New Resource Firm Power, and 
Industrial Firm Power provided in excess of the amount subscribed will 
be billed at the appropriate 2-year rate. Purchasers under the 1996 
Contract using this option must also specify an amount of power under 
the appropriate 2-year rate, as described in the contract. 

[[Page 36510]]


c. Consumer Facility Option

    This option is available to purchasers serving one or more New 
Large Single Loads. Purchasers under this option must elect to purchase 
under either the NR-96.2 rate or the NR-96.5 rate to serve all of that 
purchaser's NLSL load(s). For purchasers using this option, the amount 
of subscribed load to be served shall be the sum of the measured 
amounts of power (demand and energy) at all designated consumer 
facilities.
2. Notification Requirements
    Purchaser must notify BPA, no later than August 1, 1996, of their 
election to purchase power under the applicable 5-year rate.

a. Purchasers Under 1981 Contracts

    For customers continuing to receive service under the 1981 
Contract, such notification shall be in writing and must specify the 
amount of power that a purchaser agrees to purchase exclusively from 
BPA (subscription amount) over the 5-year rate period, using either the 
percentage of load option, the block of power option, or the consumer 
facility option (Subscription Options) as described above.
    Purchasers selecting the percentage of load option must specify a 
single percentage that will apply in each month of the 5-year period.
    Purchasers selecting the block of power option must specify the 
amount of demand, and the amount of energy for HLH and LLH, for each 
month of the first 2 years in which the rate is effective, October 1, 
1996, through September 30, 1998. For the remaining 3 years of the 
rate, FYs 1999, 2000, and 2001, the purchasers selecting the block of 
power option must specify annual amounts of demand, HLH energy, and LLH 
energy. Annual subscription amounts for years 3-5 cannot exceed the 
annual amounts for years 1-2 unless the increase is due to load growth. 
Purchasers will specify the monthly amounts for FYs 1999-2001 in 
subsequent notices, based on the previously selected annual amounts. By 
February 1, 1998, these purchasers must submit to BPA their monthly 
amounts of demand and HLH and LLH energy for the period beginning 
October 1, 1999, through September 30, 2000. By February 1, 2000, these 
purchasers must submit to BPA their monthly amounts of demand and HLH 
and LLH energy for the period beginning October 1, 2000, through 
September 30, 2001. Purchasers who fail to submit subsequent monthly 
amounts shall be deemed to have elected the same monthly shape selected 
for the period October 1, 1996, through September 30, 1998.

b. Purchasers under 1996 Contracts

    Purchasers under 1996 Contracts must elect to purchase power under 
the 5-year rate through provisions provided in the contract. Such 
election will occur at the time a purchaser signs this contract, but in 
no event later than August 1, 1996.
2-Year Rate Election
    Priority Firm Power, Industrial Firm Power, and New Resource Firm 
Power purchasers under the 1996 Contract purchasing all or a portion of 
their power under a 2-year rate must specify the amount of demand, and 
the amount of energy for HLH and LLH, for each month of the period 
October 1, 1996, through September 30, 1998. Subscriptions for the 2-
year rate will be made through provisions provided in the contract. PF, 
NR, and IP purchasers under a 1981 Contract purchasing all of their 
power under a 2-year rate do not need to make a subscription.
Load Shaping Election
    Any purchaser of load shaping, except utilities participating in 
the Residential Exchange under section 5(c) of the Northwest Power Act 
and purchasers under the Composite Rate, must elect to purchase the 
product at either the 2-year rate or the 5-year rate. The purchaser 
must notify BPA no later than August 1, 1996, of its rate election for 
the load shaping product.
Load Regulation Election
    Same as for load shaping, above.
F. Energy Return Surcharge (PF/NR/FPS Only)
    Any purchaser:
    1. who preschedules in accordance with sections 2(a)(4) and 2(c)(2) 
of Exhibit E of the 1981 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, or
    2. who purchases capacity under the FPS rate schedule, returns more 
than 60 percent of its Contract Demand for the billing month during a 
single offpeak hour, and is subject to the Energy Return Surcharge 
shall be subject to the following charge for each additional kilowatt-
hour so returned:
     3.63 mills per kilowatt-hour for the months of September-
December;
     3.83 mills per kilowatt-hour for the months of January-
March;
     3.27 mills per kilowatt-hour for the month of April;
     5.07 mills per kilowatt-hour for the months of May-June;
     5.37 mills per kilowatt-hour for the month of July;
     5.77 mills per kilowatt-hour for the month of August.
FPS purchasers are subject to the Energy Return Surcharge stated above 
unless their agreement with BPA specifically provides otherwise.
G. Guaranteed Delivery Charge (NF Only)
    A surcharge of 2.00 mills per kilowatt-hour of Billing Energy is 
applied whenever BPA guarantees delivery of nonfirm energy to a 
Purchaser under the Standard rate or Market Expansion rate.
H. Industrial Exemption and Industrial Curtailment
    Both Industrial Exemption and Industrial Curtailment are available 
to purchasers under the 1996 Contract only.
    Industrial Exemption adjusts the billing factor for Load Shaping by 
subtracting exempt industrial loads specified by the Purchaser. Each 
exempted industrial load must be greater than 5 aMW and must be 
separately metered. The customer is responsible for ensuring that 
variations from forecast are provided for; deviations may be subject to 
the Deviation Adjustment.
    Industrial Curtailment allows the purchaser to decrease the 
forecast of its exempt industrial loads during any billing month. The 
charge is $0.35 per MWh applied to the megawatthours of industrial 
curtailment rights nominated for the month.
I. Low Density Discount (PF Only)
1. Basic LDD Principles
    A predetermined discount shall be applied each billing month to the 
charges for all power (excluding transmission services) purchased under 
the PF and NR rate schedules by eligible purchasers as defined in 
section 2, 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 based on 
information for the utility's entire system in the Pacific Northwest, 
regardless of whether the utility has service areas in more than one 
state or whether the utility is participating in the residential 
exchange program in more than one state jurisdiction: 

[[Page 36511]]


a. The kWh/Investment Ratio

    The kWh/Investment ratio is calculated by dividing the purchaser's 
total electric energy requirements during the previous calendar year 
(the purchaser's firm sales, nonfirm sales to firm and nonfirm retail 
loads, sales for resale, and associated losses) by the value of the 
purchaser's depreciated electric plant (excluding generation plant) at 
the end of such year, and

b. The Consumers/Mile of Line Ratio

    The Consumers/Mile of Line ratio is calculated by dividing the 
average number of consumers (annual and seasonal consumers with 
residential, industrial, commercial, and irrigation accounts, but 
excluding the average number of consumers associated with separately 
billed services for water heating, electric space heating, and security 
lights) during the previous calendar year by the average number of pole 
miles of distribution line for such year, calculated by halving the sum 
of the end-of-year pole mile figures for the previous year and the 
current 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 average annual data provided 
in the Purchaser's financial and operating reports which they submit 
periodically to BPA (usually monthly or quarterly). In calculating 
these ratios, BPA shall compile the data submitted by the Purchaser 
based on the Purchaser's entire electric utility system in the Pacific 
Northwest, regardless of whether the utility has service areas in more 
than one state or whether the utility is participating in the 
residential exchange program in more than one state jurisdiction. 
Results of the calculations shall not be rounded.
    Customers who have not provided BPA with all four requisite pieces 
of annual data (see 1.a. and 1.b, 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.
2. Eligibility Criteria
    To qualify for a discount, the purchaser must meet all six of the 
following eligibility criteria:
    a. the Purchaser must serve as an electric utility offering power 
for resale;
    b. the Purchaser must agree to pass the benefits of the discount 
through to the Purchaser's consumers within the region served by BPA;
    c. the Purchaser's average retail rate for the reporting year must 
exceed the average applicable Priority Firm Power rate for the 
qualifying period by at least 10 percent. For Calendar Year (CY) 1996, 
the average Priority Firm Power rate shall be the average of the PF-95 
Preference rate for 9 months and the PF-96 Preference rate for 3 
months. For CY 1997, the average Priority Firm Power rate shall be the 
PF-96 Preference rate. For Purchasers under the PF-96.2 rate or the PF-
96.5 rate, the applicable rate shall be used for the calculation. For 
customers purchasing a portion of their load under each of the PF-96 
rates, an average of the applicable rates shall be calculated, 
weighting the PF-96.2 rate by the Purchaser's subscription at that rate 
and the PF-96.5 rate by the Purchaser's subscription at that rate;
    d. the Purchaser's kilowatt-hour-to-investment ratio (Ratio 1.a) 
must be less than 100;
    e. the Purchaser's consumers-per-mile ratio (Ratio 1.b) must be 
less than 12; and
    f. the Purchaser must qualify for a discount based on the criteria 
in section 3, below.
3. Discounts
    The Purchaser shall be awarded the lesser of the following 
discounts, provided such discount does not differ from the Purchaser's 
current discount by more than one-half of 1 percent per year:
    a. 7 percent, or
    b. the sum, not to exceed 7 percent, of the two potential discounts 
for which the Purchaser qualifies based on the qualifying criteria 
specified in the following table:

----------------------------------------------------------------------------------------------------------------
                                                                      Applicable range for  Applicable range for
                         Percentage discount                          kWh/investment (K/I)  consumers/mile (C/M)
                                                                              ratio                 ratio       
----------------------------------------------------------------------------------------------------------------
0.0.................................................................       35.0__ x         12.0 x   
                                                                                                                
0.5.................................................................  31.5 x <3                      
                                                                                       5.0  10.8 x <1
                                                                                                             2.0
1.0.................................................................  28.0 x <3                      
                                                                                       1.5  9.6 x <10
                                                                                                              .8
1.5.................................................................  24.5 x <2                      
                                                                                       8.0     8.4  x
                                                                                                            <9.6
2.0.................................................................  21.0 x <2                      
                                                                                       4.5  7.2 x <8.
                                                                                                               4
2.5.................................................................  17.5 x <2                      
                                                                                       1.0  6.0 x <7.
                                                                                                               2
3.0.................................................................  14.0 x <1                      
                                                                                       7.5  4.8 x <6.
                                                                                                               0
3.5.................................................................  10.5 x <1                      
                                                                                       4.0  3.6 x <4.
                                                                                                               8
4.0.................................................................  7.0 x <10                      
                                                                                        .5  2.4 x <3.
                                                                                                               6
4.5.................................................................  3.5 x <7.                      
                                                                                         0  1.2 x <2.
                                                                                                               4
5.0.................................................................                x <3.5                x <1.2
----------------------------------------------------------------------------------------------------------------

    If the Purchaser satisfies eligibility criteria 2.a.-2.e, above, 
and the discount calculated above differs from the existing discount by 
more than one-half of 1 percent, the applicable discount will be:
    a. the previous year's discount plus one-half percent if the 
calculated discount exceeds the previous year's discount; or
    b. the previous year's discount minus one-half percent if the 
calculated discount is less than the previous year's discount.
    The foregoing formula will be applied each successive year until 
the then-current calculated discount is fully phased in. 

[[Page 36512]]

    If the Purchaser fails to satisfy eligibility criteria 2.a.-2.e. 
above, the applicable discount will be zero.
J. 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 BPA's nonfirm 
energy, including any applicable service charges or rate adjustments, 
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 Customer Notification of the Value of the NF Rate Cap
    Prior to the beginning of each calendar month, BPA shall determine 
the effective NF Rate Cap for that month. BPA is obligated to provide 
advance notification of the NF Rate Cap level to purchasers of nonfirm 
energy. This notification requirement does not apply if BPA does not 
intend to offer Nonfirm Energy at prices above BPA's Average System 
Cost (BASC) at any time during a month. BPA shall give the notification 
to the purchasers at least 10 calendar days prior to the first day of 
any calendar month in which the NF Rate Cap is expected to apply. BPA 
shall also maintain, on file for public review, a record of the NF Rate 
Cap by month throughout the 12-year period that 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
    b. BASC+[0.30 * (DEC--BASC)]

where:
BASC=BPA's Average System Cost
DEC=The Decremental Fuel Cost
4. Determination of BPA's Average System Cost (BASC)
    BPA's Average System Cost is calculated by dividing BPA's Total 
System Costs by BPA's Total Annual System Sales, where:
    a. BPA's Total System Costs are 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 are the sum of all BPA's system 
firm and nonfirm energy 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 the Decremental Fuel Cost (DEC)
    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. All quantities are to be rounded to the nearest 
tenth of a mill in making the calculation.
    The monthly decremental fuel cost shall be calculated using the 
following formula:

DEC = [ (MGP * WGU) + (MOP * WOU)] / (WGU + WOU)
where:
MGP = the monthly California gas price
WGU = historical gas use in California
MOP = the monthly California petroleum price
WOU = historical petroleum use in California

    a. Determination of MGP, the Monthly California Gas Price.

MGP = AGP * HGP / 10
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.
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:
    i. 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;
    ii. 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
    iii. dividing the average monthly California gas price in ``i'' 
above, by the average monthly California gas price in ``ii'' 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.

    b. Determination of WGU, Historical Gas Use in California.

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 consumption in the 
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:
    i. 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;
    ii. 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
    iii. dividing the average consumption of gas in California for the 
month t as determined in ``i'' above by the average consumption of gas 
for the month r as determined in ``ii'' above and rounding to the 
nearest one-tenth, or three significant places.
    c. Determination of MOP, the Monthly California Petroleum Price.

MOP = AOP * HOP / 10
where:
AOP = same as AGP except the input data is for the average petroleum 
price (as opposed to the gas price). 

[[Page 36513]]

HOP = same as HGP, except the data is for the petroleum price (as 
opposed to the gas price).
10 = the same conversion factor as used for converting the gas data.

    d. Determination of WOU, Historical Petroleum Use in California.

WOU = COU * HOU
where:
COU = the same as CGU except the data for monthly net petroleum-fired 
generation is used instead of the gas data.
HOU = the same as HGU, except the data for petroleum consumption is 
used instead of the gas data.
6. Changes in Data Sources
    In the event that the data used to compute the NF Rate Cap become 
unavailable, BPA may identify and substitute other data sources for the 
purpose of calculating the monthly NF Rate Cap. As a result of this 
data substitution, it may also be necessary to modify the NF Rate Cap 
methodology to achieve an NF Rate Cap that is substantially equivalent 
in rate level to that which would have resulted from continued use of 
the data described in section 5, above.
    BPA shall notify interested parties of its intent to substitute 
data sources or to substitute data sources and change the NF Rate Cap 
methodology at least 120 days prior to the billing month in which the 
change would become effective. In this notification, BPA shall explain 
the reason(s) for the proposed changes and describe its proposed 
alternative. 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 data sources and the final NF Rate Cap methodology to differ from 
BPA's initial proposal. BPA shall notify all affected parties, and 
those parties that submitted comments, of its final determination 90 
days prior to the billing month in which the new NF Rate Cap parameters 
(data sources/methodology) become effective.
K. Operating Reserves Adjustment (IP only)
    The energy charges stated in the IP-96 rate schedules reflect a 
3.05 mills per kilowatthour credit for the operating reserves a DSI 
provides to BPA pursuant to its power sales contract. If a DSI chooses 
not to provide operating reserves, a billing adjustment will be made to 
remove the credit.
L. Phase-In Mitigation
    The phase-in mitigation is available for Full or Metered 
Requirements Preference customers. Phase-in mitigation does not apply 
to PF purchased under a Residential Purchase and Sale Agreement or an 
Exchange Transmission Credit Agreement.
1. Eligibility Criteria
    To qualify for the phase-in mitigation a purchaser must:
    a. be a Full Requirements customer of BPA as designated in the 1996 
Contract, or a Metered Requirements customer of BPA as designated in 
the 1981 Contract;
    b. agree to purchase all power from BPA for 5 years under one or 
more of BPA's 5-year rate schedules; and
    c. have a rate increase greater than 9 percent for all BPA power 
purchases, rounded to the nearest one-tenth of a percent, based on the 
determination in section 2 below.
2. Determination of Rate Increase for Phase-In Mitigation
    The percentage rate increase faced by a Full or Metered 
Requirements purchaser will be calculated as follows:
    a. Apply all applicable 1993 rate schedule (PF, NR, etc.) charges 
to the individual customer's FY 1996 expected BPA purchases, as 
forecasted in the 1996 rate case by BPA.
    b. Apply all applicable 1996 rate schedule (PF, NR, transmission, 
etc.) charges to the individual customer's FY 1996 expected BPA 
purchases, as forecasted in the 1996 rate case by BPA.
    c. If the value of 2.b minus the value of 2.a, divided by 2.a, is 
greater than 9 percent, rounded to the nearest tenth of a percent, the 
customer may notify BPA by letter to their Account Executive to phase 
in the 1996 rate increase. Such notice must be received by BPA by 
September 1, 1996. Purchasers may not apply for mitigation after this 
time
3. Rate Adjustment
    If the purchaser meets the eligibility criteria and requests BPA to 
phase in its 1996 rate increase, beginning each October 1 of each year 
BPA will limit the monthly increase in the customer's bill to 9 percent 
in the first year, with additional 9-percent increments in each 
subsequent year over the effective period of the 1996 5-year rates.
    The adjustment will be based on the difference between: (1) the 
purchaser's total monthly payment assuming the 1993 rates for the 
billing month were applied to power purchases for that month; and (2) 
the purchaser's total monthly payment under the 1996 rates for that 
month. In the first year, if the difference between the two is equal to 
or less than 9 percent, no adjustment will be made to the purchaser's 
monthly bill. If the difference between the two is greater than 9 
percent, an adjustment will be made such that the monthly bill to that 
customer will reflect an increase equal to 9 percent. In subsequent 
years, no adjustment shall be made if the difference between (1) and 
(2) above is less than or equal to 18 percent in the second year, 27 
percent in the third year, 36 percent in the fourth year, and 45 
percent in the fifth year.
M. Preschedule Change Charge
    As specified in the APS-96 rate schedule, BPA shall apply the 
following charge to any customer who changes its preschedules after the 
close of the preschedule window: $33 per change.
N. Reactive Power Charge
1. Conditions for Application of the Reactive Power Charge
    A Purchaser that purchases power under BPA's wholesale power rate 
schedules or transmission service on the Federal Columbia River 
Transmission System (FCRTS) under BPA's transmission rate schedules 
shall be charged for its Reactive Power requirements for such service.
    The Reactive Power Charge will apply only to the Purchaser's 
Reactive Power requirements for which measured data exist. The 
Purchaser's Reactive Power requirements shall be measured at each point 
of delivery and at each point of interconnection between BPA and the 
Purchaser where real power (MW) flow is unidirectional and the 
Purchaser is taking delivery of real power (either Federal or non-
Federal). Points of delivery that are served by transfer over another 
utility's transmission system will not be subject to a Reactive Power 
Charge unless: (1) the transferor imposes a reactive power charge on 
BPA for serving such Purchaser's load; or (2) there are BPA Integrated 
Network facilities between the Purchaser's points of delivery and the 
transferor's system. For points of interconnection, the flow of real 
power must be unidirectional on all hours during the billing month when 
the FCRTS facilities are in service. The Reactive Power Charge shall 
also apply to the Purchaser's Reactive Power requirements measured at 
points of integration where a Purchaser's generating resource is 
directly connected to the FCRTS, unless the Purchaser's generating 
resource is either: (1) a synchronous generator equipped with a voltage 
regulator; or (2) is equipped with Reactive Power control devices that 
comply with BPA's interconnection standards. Such resource must 
actively support the voltage schedule at the point of integration at 
all times, as determined by BPA, for this exemption to apply. 

[[Page 36514]]
Generating resources that do not satisfy the above criteria shall not 
be exempt from the Reactive Power Charge. A Purchaser will pay for its 
Reactive Power requirements at each point only once.
    The Purchaser may submit requests to BPA for special consideration 
of unique circumstances. BPA will consider the request and may make 
arrangements with the Purchaser to address the special circumstances.
    This Reactive Power Charge replaces the Power Factor Adjustment 
provision included in BPA's 1993 wholesale power rate schedules. 
Purchasers previously granted Power Factor Adjustment waivers under 
BPA's prior wholesale power rate schedules shall be subject to the 
Reactive Power Charge. The charges for a Purchaser's Reactive Power 
requirements under this subsection shall be subject to the provisions 
of BPA's Billing Procedures.
2. Rate
    BPA will bill the Purchaser for its total Reactive Power 
requirements at each point each month according to the methodology 
below.
a. Reactive Demand
    $0.08 per kVAr of lagging Reactive Billing Demand during HLH in all 
months of the year.
    $0.06 per kVAr of leading Reactive Billing Demand during LLH in all 
months of the year.
b. Reactive Energy
    0.16 mills per kVAr for all lagging and leading Reactive Billing 
Energy during all hours of all months of the year.
3. Billing Factors
a. Reactive Demand
    The Purchaser's Reactive Billing Demand shall be calculated 
independently for lagging Reactive Power and leading Reactive Power at 
each point for which a Reactive Power Charge is assessed.
    All reactive demands shall be established in the particular Peak 
Period (HLH) or Offpeak Period (LLH) hour during which the maximum 
applicable reactive demand is placed on BPA, regardless of the time of 
the real power peak.
    All reactive demand shall be established on a non-coincidental 
basis, regardless of whether the Purchaser is billed for real power or 
transmission on a coincidental or non-coincidental basis, unless:
    i. otherwise specified in the agreement between BPA and the 
Purchaser, or
    ii. coincidental billing is, in BPA's sole determination, more 
practical for BPA.
    The Purchaser's Reactive Billing Demand for the billing month shall 
be the larger of:
    i. the measured reactive demand during the billing month, or
    ii. the Ratchet Demand for Reactive Power. The Ratchet Demand for 
Reactive Power is equal to 100 percent of the largest measured reactive 
demand during the preceding 6-year, 11 month period. The Ratchet Demand 
for Reactive Power for the 6-year, 11-month period preceding October 1, 
1996, will be set at zero.
b. Reactive Energy
    The Purchaser's Reactive Billing Energy shall be the measured 
reactive energy delivered at Purchaser's point during the billing 
month. (This quantity is the absolute value of all measured reactive 
energy, not the net value created by summing the positive/lagging 
reactive energy and the negative/leading reactive energy.)
4. Additional Adjustments
a. Resetting of the Ratchet Demand
    BPA shall reset the Ratchet Demand for the Purchaser's Reactive 
Power to zero for any point of delivery or point of interconnection if 
BPA determines that both of the following criteria are met:
    i. The Purchaser has reduced its Reactive Power demand at such 
point to 20 percent or less of its real power demand at such point on 
all hours in the month following implementation of the corrective 
action. Corrective action includes installing switchable capacitors or 
reactors; and
    ii. BPA has not incurred capital expenditures to correct the 
problem in the preceding 6-year, 11-month period.
b. Adjustment for Reactive Losses
    Measured data shall be adjusted for reactive losses, if applicable, 
before determination of the Reactive Billing Demand and Reactive 
Billing Energy.
O. Reservation Fee for Transmission Capacity
1. Conditions for Application of Reservation Fee
    Reservation Fee is available to customers who enter into an 
agreement for Firm Transmission Service and want to postpone taking 
such service until a later date. Reservation Fee is available for new 
service or replacement of existing service. When used to replace 
existing service, Reservation Fee is intended to reserve transmission 
capacity:
    a. for the integration of resource capacity or load not included in 
the current service; and/or
    b. for new service that uses either expanded or different 
transmission facilities or requires changes in FCRTS operations.
    Reservation Fee will reserve capacity for 1 year. A customer can 
request yearly extensions up to a total reservation period of 5 years. 
If during the reservation period, another customer requests service 
which can only be satisfied out of the reserved capacity, then the 
customer with the reservation must agree to pay the full monthly charge 
for the Firm Transmission Service. The charge becomes effective on the 
date when the competing request was to become effective. In the event 
the customer with the reservation elects to release the reserved 
capacity, the Reservation Fees paid for the current and past years will 
be forfeited.
2. Reservation Fee
    The Reservation Fee shall be a nonrefundable fee equal to one-
twelfth of the annual cost of Firm Transmission Service, as determined 
pursuant to the agreement, for each year or fraction of a year in which 
the Customer chooses to postpone service. The Reservation Fee shall be 
paid in a lump sum within 30 days of the date the agreement is 
executed, and, for yearly extensions, within 30 days of the beginning 
of the extension. The Reservation Fee shall be assessed annually until 
transmission service begins or the reservation period ends, whichever 
occurs first. The Reservation Fee shall be specified in the executed 
agreement for transmission service.
3. Billing Factors
    The billing factors shall be the same as the type of transmission 
service requested, as determined pursuant to the applicable 
transmission rate schedule.
P. Transitional Service--Application of Rates During Initial Operation 
Period
    Under the 1981 Contract, and as specified in BPA's Billing 
Procedures, BPA may agree to bill the purchaser for Transitional 
Service. Transitional Service shall apply to DSIs having new, 
additional or reactivated plant facilities, and utility purchasers 
serving industrial purchasers with power purchased from BPA. 
Transitional Service will not be available under the 1996 Contract.
    If the purchaser requests billing on a Daily Demand basis pursuant 
to its power sales contract and if BPA agrees to such billing, the 
kilowatt Billing Demand for the billing month shall be 

[[Page 36515]]
based on one of the following billing methods, as agreed to by BPA and 
the purchaser, based on load characteristics and consistent with the 
procedures outlined in BPA's Billing Procedures. If for any reason 
agreement is not reached on a billing method, paragraph 1 below shall 
serve as a default billing method. Reactive power will continue to be 
billed normally.
1. Weighted Monthly Average of Daily Billing Demand
    The Billing Demand for each day is the maximum metered amount for 
any hour of that day. For the negotiated transitional period, each 
day's Billing Demand is averaged with the Billing Demand of every other 
day in the transitional period to compute the transitional period 
average. For the remaining period of the billing month, if any, the 
Billing Demand is the highest of the daily maximum metered amounts. To 
compute the Billing Demand for the month, the average Billing Demand 
for the transitional period and the Billing Demand for the remaining 
period are averaged, weighting each average by the number of days in 
each period.
2. Weighted Monthly Average of Daily HLH Billing Demand
    The Billing Demand for each day is the maximum metered amount for 
any HLH hour of that day. For the negotiated transitional period, each 
day's Billing Demand is averaged with the Billing Demand of every other 
day in the transitional period to compute the transitional period 
average. For the remaining period of the billing month, if any, the 
Billing Demand is the highest of the daily maximum metered amounts. To 
compute the Billing Demand for the month, the average Billing Demand 
for the transitional period and the Billing Demand for the remaining 
period are averaged, weighting each average by the number of days in 
each period.
Q. Unauthorized Increase Charge
    If specified in the applicable rate schedule, BPA shall apply the 
charge for Unauthorized Increase to any purchaser taking demand and 
energy in excess of its contractual entitlement.
1. Rate for Unauthorized Increase
    a. Demand Charge: Demand Charge from applicable power rate 
schedule.
    b. Energy Charge: 100 mills per kWh in all months of the year.
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 hours that 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:

    1. In accordance with the provisions of the ``Relief from Overrun'' 
exhibit to the 1981 Contract; or
    2. At the rate for Unauthorized Increase if such exhibit does not 
apply or is not a part of the Purchaser's power sales contract.
    b. Unauthorized Increase in Energy
    The amount of Measured Energy during a billing month that exceeds 
the amount of energy the purchaser is contractually entitled to take 
during that month and which cannot be assigned:
    1. To a class of power BPA delivers during such month pursuant to 
contracts between BPA and the purchaser; or
    2. To a type of power the purchaser acquires from sources other 
than BPA and which BPA delivers during such month,
shall be billed:

    1. In accordance with the provisions of the ``Relief from Overrun'' 
exhibit to the 1981 Contract; or
    2. At the rate for Unauthorized Increase if such exhibit does not 
apply or is not a part of the purchaser's power sales contract.
R. Utility Factor
    For purchasers under the 1981 Contract, charges for Load Shaping 
and Load Regulation are multiplied by a utility-specific, monthly 
Utility Factor.
    The Utility Factors to be used for billing will be developed 
annually based on historical data provided by the customers to BPA. The 
annual Utility Factor will be based on the customer's historical annual 
system load and purchases from BPA. Previous calendar year historical 
data (January 1-December 31) will be used to develop an annual utility 
factor that will be in effect for the following fiscal year (October 1-
September 30). The customer shall submit its end of calendar year 
Financial and Operating Report and Generation Report (if applicable). 
BPA will develop the billing factors once they have received all 
necessary data from customers (usually in April). If a customer has not 
submitted the required data by June 1, BPA will prepare an estimate of 
the customer's historical annual system load for the previous calendar 
year, after consultation with the customer, and prepare the Utility 
Factor from that estimate. Completed Utility Factors will be provided 
to the customers. The first effective year for utility factors 
coincides with the first year of implementation of the new rate 
structure: October 1, 1996-September 30, 1997. Historical data from the 
previous calendar year (January 1, 1995-December 31, 1995) will be used 
to develop the utility factor for this first year. The customer's 
annual system load (in kWh) is defined as the total of:

(1) Retail load; plus
(2) Utility's own use; plus
(3) Distribution losses; minus
(4) Sales for resale.

    The Utility Factor for the applicable fiscal year = customer system 
load  energy purchases under the 1981 power sales contract for 
the previous calendar year.

Section III. Definitions

A. Products and Services Offered by BPA
1. Ancillary Services
    Ancillary Services are those services necessary to support the 
transmission of electric power from resources to load while maintaining 
reliable operation of the FCRTS. Ancillary services include:
    Scheduling and Dispatching, Transmission Losses, Control Area 
Reserves for Resources, Control Area Reserves for Interruptible 
Purchasers, and Load Regulation.
2. Construction, Test and Start-Up, and Station Service
    Power for the purpose of Construction, Test and Start-Up, and 
Station Service for a generating resource or transmission facility 
shall be made available to eligible purchasers under the contract rate 
under the Firm Power Products and Services (FPS) rate schedule.
    Construction, test and start-up, and station service power must be 
used in the manner specified below:
    a. Power sold for construction is to be used in the construction of 
the project.
    b. Power sold for test and start-up may be used prior to commercial 
operation--both to bring the project on 

[[Page 36516]]
line and to ensure that the project is working properly.
    c. Power sold for station service may be purchased at any time 
following commercial operation of the project. Once the project has 
been energized for commercial operation, the Purchaser may use station 
service power for start-up, shut-down, normal operations, and 
operations during a shut-down period.
3. Control Area Services
    Control Area Services are services that BPA provides to the 
Purchaser for real-time fluctuations in the Purchaser's power 
requirements during the delivery hour. With these services, BPA will 
deliver power to the Purchaser in amounts that change automatically in 
response to changes in the Purchaser's loads or resource output located 
in BPA's control area. These services meet the standards established by 
the North American Electric Reliability Council (NERC), Western Systems 
Coordinating Council (WSCC), and the Northwest Power Pool (NWPP) for 
regulating margin and spinning and non-spinning operating reserves. In 
addition, BPA may also provide similar services to loads and resources 
outside BPA's control area. The general category, Control Area 
Services, includes:

a. Control area reserves for resources;
b. Control area reserves for interruptible purchases;
c. Load regulation;
d. Eccentric load following;
e. Other control area services.
4. Control Area Reserves for Resources
    Control Area Reserves for Resources are the control area services 
necessary to back up generation located in BPA's control area. Control 
Area Reserves for Resources provides the generation following and 
operating reserves for the remainder of the delivery hour.
5. Control Area Reserves for Interruptible Purchases
    Control Area Reserves for Interruptible Purchases are the operating 
reserves provided by BPA for interruptible energy delivered to BPA's 
control area. Interruptible energy is defined as energy deliveries that 
can be interrupted by the delivering control area during the delivery 
hour.
6. Eccentric Load Following
    Eccentric Load Following provides instantaneous (second-to-second) 
regulation of firm power supply for a Purchaser's actual real-time 
eccentric load within the hour. An eccentric load is defined as any 
specific cyclic customer or consumer load with the ability to change 
more than 50 MW in level at a rate of greater than 50 MW per minute, 
regardless of the duration of this change.
7. Firm Capacity without Energy
    Firm Capacity without Energy is a product available under the PF-
96.2 and NR-96.2 rate schedules to computed requirements customers who 
hold 1981 Contracts. Customers who buy this product may take power from 
BPA during HLH and must return the associated energy within 24 hours. 
This product is also offered under the FPS rate schedule with delivery 
and return provisions that may differ from those available under the 
1981 Contract.
8. Firm Power
    Firm Power available at the FPS rate is defined as firm energy with 
capacity, firm energy without capacity, and/or firm capacity that BPA 
may make available to the purchaser at BPA's discretion. Energy 
associated with the delivery of firm capacity must be returned to BPA 
either before or after delivery of the capacity and in a manner 
consistent with the agreement between BPA and the Purchaser.
    Firm Power may be used either for resale or direct consumption by 
purchasers both inside and outside the United States. Firm Power is 
guaranteed to be continuously available to the purchaser during the 
period covered by the commitment, except for reasons of certain 
uncontrollable forces. Firm Power may be used to meet the standards 
established by the North American Electric Reliability Council (NERC), 
Western Systems Coordinating Council (WSCC), and the Northwest Power 
Pool (NWPP) for Operating Reserves. Firm Power is also available for 
various unbundled products, including:

a. Construction, test and start-up, and station service;
b. Power supplied for emergency use;
c. Replacement of lost generation during forced outages;
d. Replacement of lost generation during planned outages;
e. Displacement of higher-cost firm capacity resources which are 
otherwise available to meet the purchaser's load;
f. Supplemental non-spinning operating reserves; and
g. Other purposes.
9. Firm Transmission Service
    Firm Transmission Service is the transmission service that BPA 
provides except for transmission service scheduled as nonfirm. If the 
firm service is provided pursuant to an agreement, the terms of the 
agreement may further define the service.
10. Industrial Curtailment
    Industrial Curtailment allows the purchaser to decrease the 
forecast of its exempt industrial loads (see Industrial Exemption).
11. Industrial Exemption
    Industrial Exemption adjusts the billing factor for Full Load 
Shaping to allow a customer to exempt industrial loads from load 
shaping charges. With the exemption, the customer is responsible for 
covering variations in the industrial load, except for loads also 
covered by Industrial Curtailment. The exempted industrial load must be 
greater than 5 aMW and must be separately metered.
12. Industrial Firm Power
    Industrial Firm Power is electric power that BPA will make 
continuously available to a direct-service industrial (DSI) purchaser 
subject to the terms of the Purchaser's power sales contract with BPA. 
Deliveries may be reduced or interrupted as permitted by the terms of 
the Purchaser's power sales contract with BPA. No Outage Adjustment 
shall be made for power restricted to provide reserves.
13. Load Regulation
    Load Regulation is the instantaneous (second-by-second) regulation 
of the supply of firm power that BPA provides to follow variations in 
customer's loads within the hour. The amount of Load Regulation 
provided is related to the customer's retail load.
14. Load Shaping
    Full Load Shaping provides coverage for the monthly difference 
between a utility purchaser's actual and forecasted retail loads. (Any 
deviations due to changes in resource operations are subject to the 
Unauthorized Deviation Adjustment or Unauthorized Increase Charge.) 
With the purchase of this product, a Purchaser will pay for only the 
power demand, HLH energy, and LLH energy it takes. Similarly, DSI Load 
Shaping, available to DSIs under a 1996 Contract only, provides 
coverage for a variation of up to 15 percent in a DSI customer's actual 
and forecasted loads due to changes in plant operations. Economic 
displacement is not allowed under DSI Load Shaping.
    A separate product, Partial Load Shaping, is available to utilities 
under 1996 Contracts only. Partial Load Shaping allows the Purchaser to 
specify an amount of load shaping it will purchase. If the Purchaser's 
retail load 

[[Page 36517]]
exceeds its forecast, BPA will provide additional demand and energy, 
limited to the amount specified by the customer. If the Purchaser's 
retail load is lower than forecast, BPA will relieve the take-or-pay 
obligation up to the amount of load shaping specified.
15. New Resource Firm Power
    New Resource Firm Power is electric power (capacity, energy, or 
capacity and energy) that BPA will make continuously available:
    a. For any New Large Single Load, and
    b. For firm power purchased by investor-owned utilities (IOUs) 
pursuant to power sales contracts with BPA.
    New Resource Firm Power is to be used to meet the Purchaser's 
actual firm load within the Pacific Northwest. Deliveries of New 
Resource Firm Power may be reduced or interrupted as permitted by the 
terms of the Purchaser's power sales contract with BPA.
16. Nonfirm Energy
    Nonfirm Energy is energy that is supplied or made available by BPA 
to a Purchaser under an arrangement that does not have the guaranteed 
continuous availability feature of firm power. Nonfirm energy is sold 
primarily under the Nonfirm Energy rate schedule, NF-96. Nonfirm energy 
also may be supplied under the NF-96 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.
17. Nonfirm Transmission Service
    Nonfirm Transmission Service is interruptible transmission service.
    18. Power Supplied for Emergency Use
    Power Supplied for Emergency Use is electric energy and/or capacity 
that has been supplied by BPA under the FPS rate schedule:
    a. For use during an emergency on the Purchaser's system, or
    b. Following an emergency to replace energy secured from sources 
other than BPA during such emergency.
    Mutual emergency assistance may be provided under exchange 
agreements, and payment for that power made in accordance with the 
terms of those agreements.
19. 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 and for direct consumption by public 
bodies, cooperatives, and Federal agencies. Utilities participating in 
the residential exchange under section 5(c) of the Northwest Power Act 
may purchase Priority Firm Power pursuant to their Residential Purchase 
and Sale Agreements (RPSA). Priority Firm Power is not available to 
serve New Large Single Loads.
    Power purchased under the rate schedule is to be used to meet the 
purchaser's actual firm load within the Pacific Northwest. Deliveries 
of Priority Firm Power may be reduced or interrupted as permitted by 
the terms of the Purchaser's power sales contract with BPA.
20. Reserve Power
    Reserve Power is firm power sold to a Purchaser:
    a. In cases where the purchaser's power sales contract states that 
the rate for Reserve Power shall be applied;
    b. To provide service when no other type of power is deemed 
applicable; or
    c. To serve the Purchaser's firm power loads under circumstances in 
which BPA does not have a power sales contract in force with the 
purchaser.
    Deliveries of Reserve Power may be reduced or interrupted either as 
a result of an uncontrollable force or when necessitated by 
emergencies, system maintenance requirements or other factors related 
to continuity of service.
21. Residential Purchase and Sale Agreement (RPSA) Power
    RPSA Power is power BPA sells to a Purchaser pursuant to the 
Purchaser's Residential Purchase and Sale Agreement (RPSA) with BPA. 
Under section 5(c) of the Northwest Power Act, BPA ``purchases'' power 
from each RPSA customer at that utility's average system cost (ASC). 
BPA then offers, in exchange, to ``sell'' an equivalent amount of 
electric power to that customer at BPA's PF rate applicable to 
exchanging utilities. The amount of power purchased and sold is equal 
to the utility's eligible residential and small farm load. Benefits 
must be passed directly to the utility's residential and small farm 
customers.
22. Scheduling and Dispatching
    Scheduling and Dispatching consists of all scheduling and 
generation-related dispatch activities including: real-time operation 
and control of generation resources located within BPA's control area; 
prescheduling; associated scheduling and dispatch; confirmation and 
verification of individual schedules, including preschedules and real-
time or after-the-fact changes; associated losses; and net interchange 
between control areas.
    a. Scheduling or prescheduling is the procedure to establish 
schedules between control areas for a predetermined or before-the-fact 
use of the FCRTS.
    b. Generation-related dispatch is all the dispatch activity related 
to the operation of generation located within BPA's control area 
including, but not limited to, AGC and required current-hour schedule 
changes.
    c. Preschedule is the process of identifying and activating 
accounts for the hourly energy transactions that will be implemented on 
the following day or days.
    d. Preschedule Change is any change to a Preschedule transaction 
after the close of the Preschedule Window and prior to the hour of 
real-time implementation of the schedule.
    e. Preschedule Window is the period of time during the commonly 
recognized workday when hourly schedules for the next day or days are 
prepared and entered into the energy management system.
    f. Real-Time Change is any change to a Prescheduled transaction 
during the current day and any addition to a customers total daily 
schedules submitted during the Preschedule Window.
    g. After-the-Fact Change is any change to a scheduled transaction 
for a historical day or days, including changes required due to a 
customer's scheduling error.
23. Shaping Services
    Shaping Services are services provided by BPA to a Purchaser to 
shape the output of the Purchaser's resource (or purchase) to the 
Purchaser's load. Shaping services may be provided on an hourly, daily, 
weekly, monthly, seasonal, or other basis, and may include advance 
delivery of the resource (or purchase) to the load. Shaping services 
are available under the FPS rate schedule.
24. Shortage Power
    Shortage Power is energy or energy with capacity, provided by BPA 
to a 

[[Page 36518]]
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.
25. Transitional Service
    Transitional Service is service that BPA provides to a DSI or 
utility customer that has a large industrial load that is being brought 
on-line. The load may be a new industrial plant, a major addition to an 
existing industrial plant, or reactivation of an existing industrial 
plant or major portion thereof. Pursuant to its agreement with the 
customer, BPA will serve the load and calculate the customer's monthly 
Billing Demand to account for the daily variations in the industrial 
load. In order to receive this service, the BPA customer must meet the 
eligibility requirements set forth in BPA's Billing Procedures.
26. Transmission Losses
    Transmission losses are the power losses associated with the 
transmission of power over the FCRTS. The loss factor that represents 
the amount of losses for a specific transaction is included in the 
wheeling agreement or the rate schedule or tariff.
27. Transmission Service
    As used in the MT rate schedule, Transmission Service is as defined 
in the Western Systems Power Pool Agreement.
28. Variable Industrial Power
    Variable Industrial Power is Industrial Firm Power that is sold at 
the VI-96 rate, consistent with the terms and conditions of the 
Variable Rate Contract between BPA and the Purchaser.
B. Definition of Rate Schedule Terms
1. 1981 Contract
    The ``1981 Contract'' refers to the initial power sales contracts 
that BPA executed with its Pacific Northwest customers pursuant to the 
requirements of the Northwest Power Act. Most of these contracts were 
executed in 1981, but some are dated ``1984'' or later. For purposes of 
these rate schedules, any such contract effective prior to October 1, 
1996, is referred to for convenience as a ``1981 Contract.''
2. 1996 Contract
    Contracts for the sale of firm power to Pacific Northwest customers 
pursuant to the requirements of the Northwest Power Act are termed the 
``1996 Contracts'' if they are effective on or after October 1, 1996.
3. Auxiliary Demand (1981 DSI Contract)
    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. 
Auxiliary Power is power in excess of the DSI's Operating Demand. 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 1981 Contract.
    BPA shall make Auxiliary Power available to Industrial Firm Power 
purchasers under the Industrial Firm Power rate schedule.
4. Billing Demand (Energy)
    The Purchaser's Billing Demand (Energy) is the amount of capacity 
(energy) to which the demand (energy) charge specified in the rate 
schedule is applied. When the rate schedule includes charges for 
several products, there may be a Billing Demand (Energy) quantity for 
each product. BPA establishes Billing Demand and Billing Energy 
quantities for both active power (kilowatts/kilowatt-hours) and 
reactive power (kilovars and kilovarhours).
    Various adjustments may be made to billing demand. At any POD that 
has an unbalanced phase current problem, BPA shall calculate the 
Billing Demand by multiplying the largest of the adjusted Integrated 
Demands on any phase during the billing month by three. BPA may 
continue this billing procedure until the Purchaser has made the 
necessary system corrections. Billing Demand also may be adjusted for 
certain outages (providing the Purchaser an Outage Credit) as specified 
in the Purchaser's agreement with BPA and pursuant to BPA's Billing 
Procedures.
5. BPA Operating Level (1981 DSI Contract)
    The BPA Operating Level is, for the purpose of these rate schedules 
and GRSPs, an hourly amount of 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.
    Each DSI must request service from BPA for each billing month in 
accordance with the terms of its power sales contract. The requested 
level of service under the 1981 Contract 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 provide, a 
level of service for the Offpeak Periods that differs from 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 during any single hour exceeds the 
BPA Operating Level for that hour shall be subject to an Unauthorized 
Increase charge for each kilowatt and kilowatt-hour of Unauthorized 
Increase associated with each such 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 and the Variable Industrial Power 
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.
6. Calculated Energy Capacity
    Calculated Energy Capacity is BPA's estimate of the amount of 
energy load (aMW) that a DSI would consume if its plant(s) is operating 
at full capacity. It is the billing factor for DSI Load Shaping.
7. Composite Rate
    The Composite Rate applies to PF-96.5 Purchasers under 1981 and 
1996 Contracts. Only customers whose average annual energy loads during 
the 5-year purchase period, as forecasted by BPA, are 25 average annual 
MW or less are eligible to purchase at this rate. The composite rate is 
a weighted average rate that takes into account the relative cost of 
typical quantities of each product purchased, including generation 
demand and energy, load shaping, and load regulation. 

[[Page 36519]]

8. Computed Average Energy Requirement (1981 Utility Contract)
    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.
9. Computed Energy Maximum (1981 Utility Contract)
    The Computed Energy Maximum equals the Computed Average Energy 
Requirement (CAER) multiplied by the number of hours in the billing 
month. HLH Computed Energy Maximum equals the CAER multiplied by the 
number of HLH in the month; LLH Computed Energy Maximum equals the CAER 
multiplied by the number of LLH in the month.
10. Computed Maximum Requirement (1981 Utility Contract)
    The Purchaser's Computed Maximum Requirement is the maximum amount 
of power that BPA is obligated to deliver to the Purchaser during the 
HLH of a month. The Computed Maximum Requirement is defined in section 
17(g)(1) of the Purchaser's 1981 Contract as the greater of the 
Purchaser's Computed Peak Requirement and Computed Average Energy 
Requirement unless the terms of section 7 (``Allocation Provisions in 
the Event of Planning Insufficiency'') apply.
11. Computed Peak Requirement (1981 Utility Contract)
    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.
12. Computed Requirements Customer (1981 Utility Contract)
    A Computed Requirements Customer is a Purchaser of Priority Firm 
and/or New Resource Firm Power who is designated as a computed 
requirements customer by the terms of its 1981 contract.
13. 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 applicable 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.''
14. Contract Energy
    Contract Energy is the maximum number of kilowatt-hours that BPA 
agrees to make available subject to any limitations included in the 
contractual agreement between BPA and the Purchaser. Contract Energy 
may refer to an energy purchase from BPA or to an amount of energy that 
BPA agrees to transmit over the FCRTS.
15. Curtailed Demand (1981 DSI Contract)
    A Curtailed Demand is the number of kilowatts of Industrial Firm 
Power during the billing month which results from a DSI's request for 
such power in amounts less than the Operating Demand therefor. Each 
purchaser of Industrial Firm Power may curtail its demand according to 
the terms of its 1981 contract (which permits up to three levels of 
Curtailed Demand each month).
16. Customer's Load
    Customer's Load is the customer's Network Load measured during the 
hour of the Monthly Transmission Peak Load. For customers with 1981 
Contracts, Customer's Load is the power taken under 1981 Contracts 
during the hour of the Monthly Transmission Peak Load.
17. Decremental Cost
    Unless otherwise specified in a contractual arrangement, 
Decremental Cost as applied to Nonfirm Energy transactions shall be 
defined as:
    a. 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
    b. 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.
18. Direct Assignment Facilities
    Direct Assignment Facilities are transmission facilities which are 
constructed by BPA for the sole use/benefit of facilitating a specific 
request for transmission service, the costs of which are directly 
assigned to the transmission customer requesting service.
19. Direct Service Industry (DSI) Delivery
    The DSI Delivery segment is the portion of the FCRTS that provides 
service to DSI customers at voltages of 34.5 kV and below.
20. Eastern Intertie
    The Eastern Intertie is the segment of the Federal Columbia River 
Transmission System (FCRTS) for which the transmission facilities 
consist of the Townsend-Garrison double-circuit 500 kV transmission 
line segment, including related terminals at Garrison.
21. Electric Power
    Electric Power is electric peaking capacity (kilowatts) and/or 
electric energy (kilowatt-hours).
22. Federal Columbia River Transmission System
    The Federal Columbia River Transmission System (FCRTS) is comprised 
of the transmission facilities of the Federal Columbia River Power 
System, which includes all transmission facilities owned by the 
government and operated by BPA, and other facilities over which BPA has 
obtained transmission rights.
23. Full Requirements Customer (1996 Contract)
    As currently proposed by BPA, a Full Requirements Customer is a 
customer 

[[Page 36520]]
that has not been designated by BPA as a Partial Requirements Customer 
under the terms of its 1996 Contract. This term will be further defined 
as 1996 Contracts are developed. For purposes of these rate schedules, 
Full Requirements Customers are those purchasers under 1996 Contracts: 
(a) with no resource; or (b) that have contracted for services with BPA 
or another party for their resource(s) so that the purchaser retains 
Full Requirements status.
24. Heavy Load Hours (HLH)
    Heavy Load Hours (HLH) are all those hours in the Peak Period (6 
a.m. to 10 p.m., Monday through Saturday).
25. Integrated Demand
    Integrated Demand is the quantity derived by mathematically 
``integrating'' kilowatt-hour deliveries over a 60-minute period.
26. Light Load Hours (LLH)
    Light Load Hours (LLH) are all those hours in the Offpeak Period 
(10 p.m. to 6 a.m. Monday through Saturday and all hours Sunday).
27. Main Grid
    As used in the FPT rate schedule, the Main Grid is that portion of 
the Network facilities with an operating voltage of 230 kV or more.
28. Main Grid Distance
    As used in the FPT rate schedules, Main Grid Distance is the 
distance in airline miles on the Main Grid between the Point of 
Integration (POI) and the Point of Delivery (POD), multiplied by 1.15.
29. Main Grid Interconnection Terminal
    As used in the FPT rate schedules, Main Grid Interconnection 
Terminal refers to Main Grid terminal facilities that interconnect the 
FCRTS with non-BPA facilities.
30. Main Grid Miscellaneous Facilities
    As used in the FPT rate schedules, Main Grid Miscellaneous 
Facilities refers to switching, transformation, and other facilities of 
the Main Grid not included in other components.
31. Main Grid Terminal
    As used in the FPT rate schedules, Main Grid Terminal refers to the 
Main Grid terminal facilities located at the sending and/or receiving 
end of a line, exclusive of the Interconnection terminals.
32. Measured Demand
    The Purchaser's Measured Demand is that portion of its Metered or 
Scheduled Demand purchased from BPA under the applicable rate schedule. 
The Measured Demand is computed for the hour of the Monthly 
Transmission Peak Load. If more than one class of power is delivered to 
any point of delivery, the portion of the measured quantities assigned 
to any class of power shall be as agreed by the parties. The portion of 
the total Measured Demand so assigned shall constitute the Measured 
Demand for each such class of power. Any residual quantity, after 
determination of the Purchaser's contractual entitlement at a 
particular rate, is considered ``unauthorized.'' Unauthorized amounts 
(Unauthorized Increases under the 1981 Contract and Unauthorized 
Deviations under the 1996 Contract) are considered a separate class of 
power when determining Measured Demand and are billed in accordance 
with the provisions of these GRSPs.
    In determining Measured Demand for any Purchaser who experiences an 
outage as defined in the Purchaser's agreement with BPA and in BPA's 
Billing Procedures, BPA shall exclude any abnormal Integrated Demand 
due to, or resulting from:
    a. Emergencies or breakdowns on, or maintenance of, the Federal 
System Facilities; and
    b. Emergencies on the Purchaser's facilities to the extent 
Bonneville determines that such facilities have been adequately 
maintained and prudently operated.
    Partial interruptions shall be converted to an equivalent outage of 
total Measured Demand.
33. Measured Energy
    The Purchaser's Measured Energy is that portion of its Metered or 
Scheduled Energy that is purchased from BPA under the applicable rate 
schedule during a particular season or diurnal period (HLH or LLH). If 
more than one class of power is delivered to any point of delivery, the 
portion of the measured quantities assigned to any class of power shall 
be as agreed by the parties. The portion of the total Measured Energy 
so assigned shall constitute the Measured Energy for each such class of 
power. Measured Energy for Load Shaping and Load Regulation includes 
both PF and NLSL (NR) purchases. Any residual quantity, after 
determination of the Purchaser's contractual entitlement at a 
particular rate, is considered ``unauthorized.'' Unauthorized amounts 
(Unauthorized Increases under the 1981 Contract and Unauthorized 
Deviations under the 1996 Contract) are considered a separate class of 
power when determining Measured Energy and are billed in accordance 
with the provisions of these GRSPs.
34. Metered Demand
    The Metered Demand in kilowatts shall be the largest of the 60-
minute clock-hour Integrated Demands at which electric energy is 
delivered to a purchaser:
    a. At each point of delivery for which the Metered Demand is the 
basis for determination of the Measured Demand,
    b. During each time period specified in the applicable rate 
schedule, and
    c. During any billing period.
    Such largest Integrated Demand shall be determined from 
measurements made in accordance with the provisions of the applicable 
contract and these GRSPs. This amount shall be adjusted as provided 
herein and in the applicable agreement between BPA and the Purchaser.
35. 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 applicable agreement and delivered to a purchaser:
    a. At all points of delivery for which metered energy is the basis 
for determination of the Measured Energy, and
    b. During any billing period.
36. Metered Requirements Customer
    A Metered Requirements Customer is a customer that has been 
designated as such under the terms of its 1981 Contract.
37. Monthly Transmission Peak Load
    Monthly Transmission Peak Load is the monthly peak loading on the 
FCRTS for the billing month.
38. Network (or Integrated Network)
    The Network is the segment of the Federal Columbia River 
Transmission System (FCRTS) for which the transmission facilities 
provide the bulk of transmission of electric power within the Pacific 
Northwest, as defined in BPA's Segmentation Study.
39. Network Upgrades
    Network Upgrades are modifications and/or additions to 
transmission-related facilities that are integrated with and support 
BPA's Network Transmission System to satisfy, at least in part, an 
application for transmission service as well as provide for the general 
benefit of all users of such Network Transmission System. 

[[Page 36521]]

40. Northern Intertie
    The Northern Intertie is the segment of the Federal Columbia River 
Transmission System (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, two 230-kV lines from Boundary Substation to the United 
States-Canadian border, and the associated substation facilities.
41. Offpeak Period
    The Offpeak Period (or LLH) includes all hours which do not occur 
during the Peak Period. Thus, the Offpeak Period consists of the hours 
from 10 p.m. to 6 a.m., Monday through Saturday, and all hours Sunday.
42. Operating Demand (1981 DSI Contract)
    The Operating Demand is that demand which is established by each 
DSI in accordance with section 5(b) of the DSI's 1981 Contract. Unless 
the DSI has requested, and BPA has granted, an Auxiliary Demand, the 
Operating Demand establishes a limit with respect to:
    a. The hourly 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.
43. Opportunity Cost
    Opportunity Cost is the net loss of revenue or the net increase in 
generation cost caused by displacing one transaction with another when 
the transmission system is so constrained that both transactions cannot 
be handled at the same time. Loss of revenue resulting from competition 
shall not be included in the determination of the Opportunity Cost. 
Opportunity Cost shall be determined consistent with FERC policy.
44. Partial Requirements Customer (1996 Contract)
    As currently proposed by BPA, a Partial Requirements Customer is a 
Purchaser (utility, Federal Agency, or DSI) that is designated as a 
Partial Requirements Customer by the terms of its 1996 Contract. This 
term will be further defined as 1996 Contracts are developed. For 
purposes of these rate schedules, Partial Requirements Customers are 
those purchasers under 1996 Contracts that dedicate generation 
resources or purchases to serve their retail load in specific amounts.
45. Peak Period
    The Peak Period (or HLH) includes the hours from 6 a.m. to 10 p.m., 
Monday through Saturday.
46. Phase-In Mitigation
    Phase-In Mitigation is available to Full and Metered Requirements 
Preference Purchasers who are purchasing their firm requirements under 
one or more of BPA's 5-year rate schedules and whose 1996 rate increase 
for BPA purchases is at least 9 percent. If the purchaser meets the 
eligibility criteria and requests that BPA phase in its 1996 rate 
increase, BPA will limit the Purchaser's annual rate increase to 9 
percent each year for the 5-year period.
47. Point of Delivery (POD)
    A Point of Delivery is where BPA delivers power to a customer. The 
delivered power will be Federal power to the extent that the customer 
is purchasing power under BPA's wholesale power rate schedules, and it 
will be non-Federal power to the extent that the customer is purchasing 
transmission services from BPA.
48. Point of Integration (POI)
    A Point of Integration is a connection point between the FCRTS and 
non-BPA facilities where non-Federal power is made available to BPA for 
wheeling.
49. Point of Interconnection
    A Point of Interconnection is a connection point between the FCRTS 
and non-BPA facilities where there is a change in facility ownership.
50. Purchaser
    Pursuant to the terms of an agreement and applicable rate 
schedule(s), a Purchaser contracts to pay BPA for providing a product 
or service.
51. Ratchet Demand
    The Ratchet Demand in kilowatts is 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. When the 
Ratchet Demand is used as a billing factor, BPA shall have specified 
the following information in the appropriate rate 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 that will be used to 
calculate the Ratchet Demand.
    In the event that the Purchaser has decreased its demand under the 
terms of its agreement with Bonneville, Bonneville shall, as necessary, 
reduce the Ratchet Demand to ensure that it does not exceed the maximum 
demand permitted under the terms of the Agreement.
52. Reactive Power
    Reactive Power is the out-of-phase component of the total 
voltamperes in an electric circuit. Reactive Power has two components: 
reactive demand (expressed in kilovars or kVAr) and reactive energy 
(expressed in kilovarhours or kVArh).
53. Restricted Demand (1981 DSI Contract)
    Restricted Demand is the number of kilowatts of Industrial Firm 
Power that results when BPA has restricted delivery of such power for 
one clock-hour or more. BPA makes such restrictions pursuant to the 
terms of the DSI's power sales contract with BPA. In a given billing 
month, there are as many possible levels of Restricted Demand for a DSI 
as the number of restrictions.
54. Retail Load
    Retail Load for a utility or Federal agency is the purchaser's 
regional retail energy load during any given time period plus 
distribution losses and the purchaser's system power requirements. No 
distinction is made between load that is served with BPA power and load 
that the customer serves with power acquired from other sources. Retail 
Load for a DSI is the purchaser's total energy load at facilities 
eligible for BPA service during any given time period, irrespective of 
whether the customer has chosen to serve its load with BPA or non-
Federal power. Retail Load is the billing factor for Load Shaping and 
Load Regulation for certain purchasers.
55. Scheduled Demand
    The Scheduled Demand in kilowatts is the largest of the hourly 
demands at which electric energy is scheduled for transmission on the 
FCRTS or delivery to a purchaser:
    a. To each system for which Scheduled Demand is the basis for 
determination of the Measured Demand;
    b. During each time period specified in the applicable rate 
schedule; and
    c. During any billing period.
    Scheduled amounts are deemed delivered for the purpose of 
determining Billing Demand.
56. Scheduled Energy
    The Scheduled Energy in kilowatt-hours shall be the sum of the 
hourly 

[[Page 36522]]
demands at which electric energy is scheduled for delivery to a 
purchaser:
    a. For each system for which scheduled energy is the basis for 
determination of the Measured Energy, and
    b. During any billing period.
    Scheduled amounts are deemed delivered for the purpose of 
determining Billing Energy.
57. Secondary System
    As used in the FPT and IR rate schedules, Secondary System is that 
portion of the Integrated Network facilities with an operating voltage 
of less than 230 kV.
58. Secondary System Distance
    As used in the FPT rate schedules, Secondary System Distance is the 
number of circuit miles of Secondary System transmission lines between 
the secondary POI and either the Main Grid or the secondary POD, or 
between the Main Grid and the secondary POD.
59. Secondary System Interconnection Terminal
    As used in the FPT rate schedules, Secondary System Interconnection 
Terminal refers to the terminal facilities on the Secondary System that 
interconnect the FCRTS with non-BPA facilities.
60. Secondary System Intermediate Terminal
    As used in the FPT rate schedules, Secondary System Interconnection 
Terminal refers to the first and final terminal facilities in the 
Secondary System transmission path, exclusive of the Secondary System 
Interconnection terminals.
61. Secondary Transformation
    As used in the FPT rate schedules, Secondary Transformation refers 
to transformation from Main Grid to Secondary System facilities.
62. Southern Intertie
    The Southern Intertie is the segment of the FCRTS which includes, 
but is not limited to, the major transmission facilities consisting 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, and the 500 kV AC Intertie facilities which 
include Captain Jack Substation, the Alvey-Meridian AC line, one 1,000 
kV DC line between the Celilo Substation and the Oregon-Nevada border; 
and associated substation facilities.
63. Subscription
    A Purchaser's Subscription is the amount(s) of a particular 
product(s) a Purchaser is entitled to purchase from BPA during a 
billing month. When a Purchaser must provide BPA with its Subscription 
is specified in the Purchaser's 1996 Contract with BPA.
    5-Year Demand Subscription (Substitute ``HLH Energy'' or ``LLH 
Energy'' for ``Demand'' as appropriate).
    The Purchaser's 5-Year Demand Subscription is the maximum amount of 
capacity (demand), as designated by the purchaser, that the purchaser 
elects to purchase from BPA under the applicable 5-year rate schedule 
for each month. A purchaser's demand subscription forms the basis for 
the monthly billing demand for that purchaser. For purchasers 
designating a monthly megawatt amount, the 5-Year Demand Subscription 
for that purchaser's billing month shall be the amount so specified by 
the purchaser. For DSIs under a 1981 Contract, the amount of subscribed 
load at the 5-year rate shall be a percentage of the purchaser's 
operating level and measured energy. For purchasers continuing service 
under the 1981 Contract who designate a percentage, the 5-Year Demand 
Subscription shall be determined by taking the specified percentage 
times the purchaser's Measured Demand. For purchasers under the 1996 
Contract, the 5-Year Demand Subscription shall be determined by taking 
the specified percentage times the purchaser's actual Retail [demand] 
Load. For purchasers electing service to a New Large Single Load(s) 
under the NR-96.5 rate, the 5-Year Demand Subscription shall be the 
total Measured Demand for all designated consumer facilities.
    2-Year Demand Subscription (Substitute ``HLH Energy'' or ``LLH 
Energy'' for ``Demand'' as appropriate).
    The Purchaser's 2-Year Demand Subscription is the maximum amount of 
capacity (demand), as designated by the purchaser, that the purchaser 
elects to purchase from BPA under the applicable 2-year rate schedule 
for each month. A purchaser's demand subscription forms the basis for 
the monthly billing demand for that purchaser. Only purchasers 
receiving service under the 1996 Contracts are required to subscribe to 
an amount of demand at the 2-year rate schedule.
64. Total Transmission Demand
    Total Transmission Demand is the sum of all the transmission 
demands as defined in the applicable Agreement.
65. Transmission Demand
    Transmission Demand is the demand for transmission services as 
specified in the applicable Agreement.
66. Utility Delivery
    The Utility Delivery segment is the portion of the FCRTS that 
provides service to utility customers at voltages of 34.5 kV and below.
67. Utility Factor
    A Utility Factor is the factor BPA applies to the charges for Load 
Shaping and Load Regulation under the 1981 Contracts. The Utility 
Factor is developed annually based on historical data provided by the 
customers to the Account executive or District Sales Office. The annual 
factor will be based on the customer's historical annual average retail 
load and average purchases from BPA and applied on a fiscal year basis.

    Issued in Portland, Oregon, on June 30, 1995.
Stephen J. Wright,
Vice President for the Washington, D.C. Liaison Office, Bonneville 
Power Administration.
[FR Doc. 95-17374 Filed 7-11-95; 3:38 pm]
BILLING CODE 6450-01-P