[Federal Register Volume 60, Number 83 (Monday, May 1, 1995)]
[Notices]
[Pages 21132-21169]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 95-10065]
=======================================================================
-----------------------------------------------------------------------
DEPARTMENT OF ENERGY
Bonneville Power Administration 1995 Wholesale Power and
Transmission Rates, Variable Industrial Power Rate Extension (VI-95),
and Pacific Northwest Coordination Agreement (PNCA) Rates
AGENCY: Bonneville Power Administration (BPA), DOE.
ACTION: Availability of proposed 1995 wholesale power and transmission
rates, variable industrial rate extension (VI-95), Pacific Northwest
Coordination Agreement (PNCA) Rates, and order establishing schedule.
-----------------------------------------------------------------------
SUMMARY: BPA File No: WP-95/TR-95, WP-96, TR-96, TC-96. On December 28,
1994, Bonneville Power Administration (BPA) published a Notice of
Intent to Revise Transmission Rates, 59 FR 66946 (1994), and Notice of
Intent to Revise Wholesale Power Rates, 59 FR 66947 (1994).
Subsequently, BPA published Federal Register Notices of Proposed
Wholesale Power Rate Adjustment, 60 FR 8496 (1995), Proposed
Transmission Rate Adjustment, 60 FR 8505 (1995), and Hearing and
Opportunity for Public Comment Regarding Proposed Comparable
Transmission Terms and Conditions, 60 FR 8511 (1995). On March 3, 1995,
BPA published a Notice of Additional Prehearing/Settlement Conference
for March 15, 1995, 60 FR 11962 (1995). At that prehearing conference,
the Hearing Officers were expected to act on several procedural matters
and to establish a procedural schedule. The March 3, 1995, Notice also
included schedules for a New Rates and Terms and Conditions Proceeding
and for an Extension of Current Rates Proceeding. Notice also was given
that some issues might be settled by the litigants, causing the
proposed schedule to change.
At the Prehearing/Settlement Conference on March 15, 1995, the
litigants reported to Hearing Officers about settlement discussions
that had been taking place between BPA and its customers. The parties
requested, and the Hearing Officers allowed, additional time to
complete the settlement process. The Hearing Officers set an additional
Scheduling Conference for March 22, 1995, at which time parties to the
rate case would be asked to report on the status of the settlement and
the Hearing Officers would rule on procedural matters. On March 17,
1995, most parties to the rate case signed a Settlement Agreement
agreeing that BPA would propose to surcharge BPA's current rates for a
1-year period, October 1, 1995, through September 30, 1996, and to
extend the Variable Industrial Power (VI) rate which was scheduled to
expire on June 30, 1996, through September 30, 1996. The parties also
agreed to establish a separate subsequent process to establish a 2-year
rate proposal, a 5-year rate proposal, and a proposal for transmission
services terms and conditions.
By this notice, BPA announces its proposed 1995 rates to be
effective for 1 year beginning on October 1, 1995, and extending
through September 1996, and its proposed rates for transactions under
the Pacific Northwest Coordination Agreement (PNCA). BPA will publish a
separate notice in the Federal Register to announce its proposed new
power and transmission rates to be effective on October 1, 1996,
including new 2- and 5-year rates, and its new transmission services
terms and conditions on or around the July 10, 1995, Filing Date
established for Docket Numbers WP-96, TR-96, and TC-96.
In separate orders issued March 22, 1995, the Hearing Officers: (1)
adopted a service list for BPA's 1995 Wholesale Power and Transmission
Rate Adjustment Proceeding, 1996 Wholesale Power and Transmission Rate
Adjustment Proceeding and 1996 Transmission Terms and Conditions
Proceedings; and (2) adopted other procedural rules governing these
proceedings. Copies of all orders, including the Order Establishing
Schedules, may be obtained by contacting: Francis (Jamie) Troy, Hearing
Clerk--LQ, Bonneville Power Administration, 905 NE. 11th Ave., PO Box
12999, Portland, Oregon 97212.
Schedule for WP-95/TR-95:
May 1, 1995--BPA Files Direct Case
May 30, 1995--Parties File Direct Case
June 9, 1995--Close of Participant Comments
June 19, 1995--Litigants File Rebuttal Testimony
June 30, 1995--Cross-Examination
July 10, 1995--Initial Briefs Filed
July 31, 1995--Final Record of Decision
Schedule for WP-96/TR-96 and TC-96:
July 10, 1995--BPA Files Direct Case/Prehearing Conference
September 8, 1995--Parties File Direct Case
October 2, 1995--Close of Participant Comments
October 25, 1995--Litigants File Rebuttal Testimony/BPA Supplemental
Testimony
December 4, 1995--Litigants File Rebuttal to Supplemental Testimony
January 3-February 3, 1996--Cross-Examination
February 21, 1996--Initial Briefs Filed
February 28, 1996--Oral Argument
March 25, 1996--BPA Draft Record of Decision/Hearing Officers
Recommended Decision
April 15, 1996--Briefs on Exceptions
April 30, 1996--Final Record of Decision
BPA also will be conducting public field hearings. A notice of the
dates, times, and locations of the field hearings will be made later
through mailings and public advertising.
ADDRESSES: Written comments by participants must be received by June 9,
1995, for WP-95/TR-95 and by October 2, 1995, for WP-96/TR-96/TC-96 to
be considered in the Record of Decision (ROD). Written comments should
be submitted to the Manager, Corporate Communications--CK; Bonneville
Power Administration; PO Box 12999; Portland, Oregon 97212.
FOR FURTHER INFORMATION CONTACT: Mr. Michael Hansen, Public Involvement
and Information Specialist, at the address listed immediately above,
(503) 230-4328 or call toll-free 1-800-622-4519. Information also may
be obtained from:
Mr. Steve Hickok; Group Vice President, Sales and Customer Service; PO
Box 3621; Portland, OR 97232 (503-230-5356)
Mr. George Eskridge; Manager, SE Sales and Customer Service District;
1101 W. River, Suite 250; Boise, ID 83702 (208-334-9137)
Mr. Ken Hustad; Manager, NE Sales and Customer Service District;
Crescent Court, Suite 500; 707 Main; Spokane, WA 99201 (509-353-2518)
Ms. Ruth Bennett; Manager, SW Sales and Customer Service District; 703
[[Page 21133]] Broadway; Vancouver, WA 98660 (360-418-8600)
Ms. Marg Nelson; Manager, NW Sales and Customer Service District; 201
Queen Anne Ave. N., Suite 400; Seattle, WA 98109-1030 (206-216-4272).
Responsible Official: Mr. Geoff Moorman, Manager for Pricing,
Marginal Cost and Ratemaking, is the official responsible for the
development of BPA's rates. Mr. Dennis Metcalf, BPA Transmission Team
Lead, is the official responsible for the development of BPA's
transmission terms and conditions.
SUPPLEMENTARY INFORMATION:
Table of Contents
I. Introduction
II. Background
III. Major Studies
IV. Wholesale Power Rate Schedules and General Rate Schedule
Provisions
A. Introduction
B. Summary of Rate Schedules
C. Wholesale Power Rate Schedules
D. General Rate Schedule Provisions (GRSPs)
V. Transmission Rate Schedules and General Transmission Rate
Schedule Provisions (GTRSPs)
A. Summary of Rate Schedules
B. Transmission Rate Schedules
C. General Transmission Rate Schedule Provisions (GTRSPs)
VI. Charges Under the Amended and Integrated Pacific Northwest
Coordination Agreement
I. Introduction
Prior to the March 15, 1995, prehearing conference, BPA determined
that its initial proposal should include new 2-year and 5-year rates.
On February 14, 1995, BPA published a preliminary rate proposal in the
Federal Register, 60 FR 8496. In that proposal, BPA noted that
competitive forces are causing a fundamental and significant change in
the Pacific Northwest wholesale power market. In light of these
competitive forces, BPA determined that its initial proposal should
include a 5-year rate as well as a 2-year rate. BPA anticipated that
the work necessary to develop such a proposal would take until July of
1995. As part of the settlement discussions, the parties expressed a
need for additional time to respond to BPA's new rate designs. BPA
believes that without an adjustment to its wholesale and transmission
rates for the period October 1, 1995, through September 30, 1996, BPA's
ability to satisfy its statutory obligations could be impaired. The
rate case schedule adopted by the Hearing Officers on March 22, 1995,
meets both BPA's and the parties' needs. The schedule affords the
parties a hearing process that encompasses a period of eight months for
establishment of BPA new rate designs including new 2- and 5-year
rates. The effective date for the establishment of new 2- and 5-year
rates is October 1, 1996.
In order to have sufficient time to conduct a full rate proceeding
for new 2- and 5-year rate proposals, BPA and most parties to the 1995
rate proceeding agreed that BPA would propose to extend BPA's current
adjustable rates with a 4 percent surcharge for a 1-year period,
October 1, 1995, through September 30, 1996. The extension of rates
requires a separate expedited proceeding and procedural schedule.
After the March 22, 1995, Scheduling Conference, the Hearing
Officers issued an Order (the March 22 order) that divided the
proceedings previously designated as WP-95, TR-95, and TC-95 into three
separate dockets as follows:
(1) The 1995 Wholesale Power and Transmission Rates Proceeding is
designated WP-95/TR-95, and will be a 90-day expedited rate proceeding
conducted pursuant to section 1010.10 of the Procedures Governing
Bonneville Power Administration Rate Hearings, 51 FR 7611 (1986)
(hereinafter Procedures). This proceeding will extend current rates
with a surcharge and establish the 3rd AC, annual cost rate, and the
Pacific Northwest Coordination Agreement (PNCA) rate.
(2) The March 22 Order also established a subsequent 8 month
procedural schedule beginning July 10, 1995, to establish BPA's power
and transmission rates for the period beginning October 1, 1996, and
new transmission services terms and conditions. The 1996 Wholesale
Power Proceeding is designated WP-96, and Transmission Rates Proceeding
is designated TR-96 and both will be conducted pursuant to section
1010.9 of the Procedures.
(3) The 1996 Transmission Services Terms and Conditions Proceeding
is designated TC-96 and will be conducted pursuant to section 1010.9 of
the Procedures concurrently with WP-96/TR-96.
In the March 22 Order, the Hearing Officers ruled that after March
22, 1995, separate official records will be maintained and separate
decisions will be issued for each of the three proceedings designated
above. In addition, the Hearing Officers ruled that intervenors who
intervened in the dockets designated WP-95/TR-95 and TC-95 on or before
March 15, 1995, were admitted as parties for all proceedings noted
above.
Finally, the Hearing Officers established the final rate case
schedules for Docket Numbers WP-95/TR-95, WP-96/TR-96, and TC-96. The
schedule established by the Hearing Officers for Docket Number WP-95/
TR-95 provides an opportunity for interested persons to review BPA
proposed rates, to participate in the rate hearing, and to submit oral
and written comments. All comments and documents intended to become
part of the Official Record in this process should contain the file
number designation WP-95/TR-95. Consideration of comments may result in
a final rate proposal differing from the rates proposed in this Notice.
II. Background
The Pacific Northwest Electric Power Planning and Conservation Act
(Northwest Power Act) provides that BPA must establish and periodically
review its rates so that they are adequate to recover, in accordance
with sound business principles, the costs associated with the
acquisition, conservation, and transmission of electric power, and to
recover the Federal investment in the Federal Columbia River Power
System (FCRPS) and other costs incurred by BPA.
On March 9, 1995, BPA published in the Federal Register a notice of
availability of BPA's preliminary proposed Wholesale Power and
Transmission Rate schedules, 60 FR 12915. Since that time, BPA has
continued to study the adequacy of its preliminary rate proposal,
including its proposal to tier rates for requirements service. On March
17, 1995, BPA and most parties to the 1995 rate proceedings agreed to a
settlement whereby BPA would propose that current rates be extended for
1 year and surcharged 4 percent to meet BPA revenue requirements. The
Settlement Agreement was an attempt to balance a number of interests,
including concerns expressed by customer representatives to BPA's Power
Sale Contract renegotiations. These representatives suggested that
BPA's new Power Sales Contracts and new rate structures should be
coordinated to allow customers to carefully consider the new rates and
contracts package in detail before making any long-term commitments.
BPA's initial proposal for the 1995 rate case proposes to surcharge
by 4 percent each component of its current adjustable rates, including
a Variable Industrial Power (VI) rate extended through September 30,
1996, for 1 year, from October 1, 1995, through September 30, 1996.
[[Page 21134]]
III. Major Studies
The studies that have been prepared to support the 1995 initial
proposal will be served on all parties of record and available for
examination on May 1, 1995, at BPA's Public Information Center, BPA
Headquarters Building, 1st Floor; 905 NE. 11th, Portland, OR. The
studies and documents are:
A. Loads and Resources Study and Documentation
B. Revenue Requirement Study and Documentation
C. Revenue Forecast Study and Documentation
D. Section 7(b)(2) Rate Test Study and Documentation
To request any of the above documents by telephone, call BPA's
document request line: (503) 230-3478 or call toll-free 1-800-622-4520.
Please request the document by its above-listed title. Also state
whether you require the accompanying documentation (these can be quite
lengthy); otherwise, the study alone will be provided. (For example,
ask for the ``Revenue Requirement Study and Documentation.'')
A. Loads and Resources Study
BPA's forecasts of regional loads by customer group are the basis
from which public utility and direct service industry (DSI) customer
purchases from BPA (Federal system firm loads) are projected. BPA also
projects Federal transmission losses, obligations to regional investor-
owned utilities (IOUs) under their power sales contracts, and other
inter- and intraregional contractual obligations.
BPA develops forecasts of regional non- and small generating public
utility (NSGPU) and generating public utility (GPU) loads using
standard econometric techniques. Regional NSGPU and GPU loads are
forecasted as a function of average retail electricity prices, weather-
related variables, and nonagricultural employment. The regional load
forecasts then are adjusted to account for factors such as effects from
conservation programs and utility purchases from alternative (non-BPA)
power suppliers to derive a projection of NSGPU and GPU purchases from
BPA. The IOU load forecast was produced by updating the economic
assumptions from the 1991 joint BPA/Northwest Power Planning Council
(NPPC) forecast.
Forecasts of aluminum DSI purchases from BPA are prepared by
analyzing smelter production costs relative to aluminum prices, and by
considering other factors affecting smelter loads, including DSI
purchases from alternative (non-BPA) power suppliers. Forecasted non-
aluminum DSI purchases from BPA are prepared by analyzing historical
and technical plant information, forecasted market conditions, and
potential purchases from alternative power suppliers.
BPA's resource acquisition plans are based on work by BPA and the
NPPC staff and reflect extensive input and review by the general public
and the region's utilities. The specific resource acquisitions and
associated costs included in this proposal are based on BPA's 1994
Draft Strategic Business Plan. Besides emphasizing a diverse resource
portfolio, including both conservation and generating resources, BPA is
committed to moving toward a blend of acquisition methods, including
BPA-designed, utility-designed, and developer-initiated programs. This
combination of resource diversity and acquisition approaches allows BPA
to better deal with varying circumstances and uncertainties.
The ratemaking load/resource balance represents BPA's projected
service to firm loads during the test years under 1930 water
conditions. The ratemaking load/resource balance is used in the
calculation of the supply of surplus firm power in the region and on
the Federal system during the test period. A related hydro regulation
study incorporates the operation of thermal plants, exports and imports
of power, projected resource acquisitions, and system constraints such
as the Columbia River flow augmentation project and ``spill.'' For this
proposal, a 50-year hydro study was completed, which includes
assumptions regarding the Columbia River flow augmentation. The hydro
study starts in August 1995. The 50-year study determines expected
nonfirm energy availability for the region.
B. Revenue Requirement Study
The Bonneville Project Act, the Flood Control Act of 1944, the
Transmission System Act, and the Northwest Power Act require BPA to set
rates that are projected to collect revenues sufficient to recover the
cost of acquiring, conserving, and transmitting the electric power that
BPA markets, including amortization of the Federal investment in the
FCRPS over a reasonable period, and to recover BPA's other costs and
expenses. The Revenue Requirement Study includes a demonstration of
whether current rates will produce enough revenues to recover all BPA
costs and expenses, including BPA's repayment requirements to the U.S.
Treasury. Revenue requirements are a major factor in determining the
overall level of BPA's proposed power and transmission rates.
The Transmission System Act and the Northwest Power Act require
that transmission rates be based on an equitable allocation of the
costs of the Federal transmission system between Federal and non-
Federal power using the system. In compliance with a FERC order dated
January 27, 1984, 26 FERC 61,096, the Revenue Requirement Study
incorporates the results of separate repayment studies for the
generation and transmission components of the FCRPS. The repayment
studies for generation and transmission demonstrate the adequacy of the
projected revenues at proposed rates to recover the Federal investment
in the FCRPS over the allowable repayment period. Separate generation
and transmission revenue requirements are developed in the Revenue
Requirement Study. The adequacy of projected revenues to recover test
period revenue requirements and to meet repayment period recovery of
the Federal investment is tested and demonstrated separately for the
generation and transmission functions.
The Revenue Requirement Study for the 1995 initial rate proposal is
based on cost and revenue estimates for FY 1996. The cost estimates
include an undistributed reduction of $80 million. This reflects BPA's
decision to reduce revenue requirements by this amount to enable it to
set rates at a level which recover its costs but also meet current
market conditions, although specific program and/or organizational
spending cuts have not been finalized. This study also includes planned
net revenues to mitigate financial risk, to ensure that cash flows are
adequate to demonstrate timely repayment of the Federal investment
including irrigation assistance, and finance a portion of BPA's capital
investments. BPA's Revenue Requirement Study reflects actual
amortization and interest payments paid through September 30, 1994. In
addition, it reflects all FCRPS obligations incurred pursuant to the
Northwest Power Act, including residential exchange program costs.
Also part of the Revenue Requirement Study is a risk analysis that
evaluates the impact that various economic and generation resource
capability conditions could have on BPA's ability to make annual U.S.
Treasury payments during the rate test period. It measures the
financial risks surrounding the revenue and expense forecasts used to
set rates. Results of the risk analysis are used to determine the
amount of planned net revenue required for risk mitigation.
[[Page 21135]]
C. Revenue Forecast Study
The revenue forecast determines BPA's expected level of sales and
revenue for the rate period, fiscal year 1996. Revenues are forecasted
primarily by applying rates to a load forecast. In addition, because
the load forecast assumes critical water, and streamflows usually are
greater-than-critical, the revenue forecast reflects the effect of
greater-than-critical streamflows (the product of which is secondary
energy) on BPA's revenues. Secondary energy affects the revenue
forecast by increasing or decreasing estimated revenues from the
generating public utilities, direct-service industries, open market
sales, and incidental wheeling. The revenue forecast is based on the
average of 50 historical water years.
BPA prepares two types of revenue forecasts: (1) Revenues
forecasted under current rates; and (2) revenues forecasted under
proposed rates. The rates in effect since October 1993 are used in the
calculation of forecasted revenues at current rates for the rate test
period, fiscal year 1996. BPA also develops price forecasts for certain
prices that are not set by the rate schedules to determine revenues
under the Variable Industrial Power (VI) rate, for contractual sales of
surplus firm power, for sales at the Nonfirm Energy rate, and for rates
applicable to the WNP-1 and WNP-3 Exchange Agreements.
Included in the Revenue Forecast Study are the proposed wholesale
power and transmission rate schedules, which are summarized below.
D. Section 7(b)(2) Rate Test Study
Section 7(b)(2) of the Northwest Power Act directs BPA to assure
that the wholesale power rates effective after July 1, 1985, to be
charged its public body, cooperative, and Federal agency customers (the
7(b)(2) customers) for their general requirements for the rate test
period, plus the ensuing 4 years, are no higher than the costs of power
to those customers would be for the same time period if specified
assumptions are made. The effect of the rate test is to protect the
7(b)(2) customers' wholesale firm power rates from certain costs
resulting from provisions of the Northwest Power Act. The rate test can
result in a reallocation of costs from the 7(b)(2) customers to other
rate classes. The section 7(b)(2) Rate Test Study describes the
application and results of the section 7(b)(2) rate test implementation
methodology.
The rate projections and the actual rate test itself are performed
using BPA's Supply Pricing Model (SPM). The SPM simulates BPA's rate
development process, using load, resource, and cost data consistent
with that used in this rate proposal. The SPM calculates two sets of
wholesale power rates for BPA's preference customers: (1) A set of
rates for the test period and the ensuing 4 years, assuming that
section 7(b)(2) is not in effect (program case rates); and (2) a set
for the same period considering the five assumptions listed in section
7(b)(2) (7(b)(2) case rates). Certain costs specified in section 7(g)
of the Northwest Power Act (7(g) costs) are subtracted from the program
case rates.
The SPM then discounts each year's rates to the test year of the
relevant rate case, averages each set of discounted rates, and compares
the two resulting averages rounded to the nearest tenth of a mill. If
the average of the discounted program case rates, less the 7(g) costs,
is larger than the average discounted 7(b)(2) case rates, the rate test
triggers. If the rate test triggers, the amount of dollars to be
reallocated in the test period (7(b)(2) amount) is calculated by
multiplying the difference between the discounted program case and
7(b)(2) case rates by the general requirements loads of the preference
customers. The 7(b)(2) amount, if any, is used as an adjustment to the
allocated costs in the rate case test period.
IV. Wholesale Power Rate Schedules and General Rate Schedule
Provisions
Table of Contents
Introduction
Summary of Rate Schedules
Wholesale Power Rate Schedules
PF-95. Priority Firm Power Rate
IP-95. Industrial Firm Power Rate
VI-95. Variable Industrial Power Rate
SI-95. Special Industrial Power Rate
CE-95. Emergency Capacity Rate
NR-95. New Resource Firm Power Rate
NF-95. Nonfirm Energy Rate
SS-95. Share-the-Savings Energy Rate
PS-95. Power Shortage Rate
RP-95. Reserve Power Rate
General Rate Schedule Provisions (GRSPs)
Section I. Adoption of Revised Rate Schedules and General Rate
Schedule Provisions
Section II. Types of BPA Service
Section III. Billing Factors and Billing Adjustments
Section IV. Other Definitions
Section V. Application of Rates Under Special Circumstances
Section VI. Billing Information
Section VII. Variable Industrial Rate Parameters and Adjustments
A. Introduction
The proposed wholesale power rate schedules are published as part
of the Revenue Forecast Study. BPA agreed in the Settlement Agreement
that its 1995 initial rate proposal would propose to apply a 4 percent
surcharge to each component of its current adjustable rates, including
the Variable Industrial Power (VI) rate which BPA would propose to
extend through September 30, 1995. The current VI-91 rate expires June
30, 1996. BPA also agreed to propose that the surcharged rates would be
effective for the period October 1, 1995, through September 30, 1996.
Consistent with the Settlement Agreement, BPA proposes to retain
its current rate design, including most of the rate adjustments
contained in the 1993 Wholesale Power Rate Schedules. BPA proposes to
adjust each rate component contained in the Priority Firm Power (PF)
rate, Industrial Firm Power (IP) rate, Variable Industrial Power (VI)
rate, and New Resources (NR) rate such that the overall effective rate
increase for sales under these rate schedules is 4 percent. BPA
proposes to increase the demand and energy charges in these rates by 4
percent and also to increase by 4 percent the Irrigation Discount and
First Quartile Discount. BPA proposes to increase the Energy Return
Surcharge based on the changes in the PF demand charge.
BPA is proposing to retain the current percentages for the Low
Density Discount and Availability Charge without further adjustments.
Any change to these rate adjustments could result in an overall rate
increase to customers different from 4 percent. In addition, BPA is
proposing to maintain the Unauthorized Increase Charge at its current
level. The Unauthorized Increase Charge is designed to deter customers
from taking more power than they are entitled to take. The level of
current Unauthorized Increase Charge achieves that purpose and as such
a further increase is unnecessary.
BPA has some long-term contract rates that are tied to changes in
BPA's PF rate. BPA is proposing to increase these rates by 4 percent.
In addition, BPA has rates that depend on changes in BPA's Average
System Cost (BASC). BPA also is proposing to increase BASC by 4 percent
and consequently any rates that are based on changes in BASC also will
be increased by 4 percent.
BPA also proposes to adjust the rate components contained in its
Emergency Capacity (CE) rate and Nonfirm Energy rate schedules. Since
the price BPA can obtain from these rates is based on market
conditions, these rate schedules do not contain fixed rates but rather
contain caps or ceilings. BPA proposes to increase the CE rate cap and
the Intertie Charge by 4 percent. In the NF rate, BPA is proposing to
increase the [[Page 21136]] average cost of nonfirm energy, which
triggers the Intertie adder charge, and retain the upper limit on its
Standard nonfirm energy rate by 4 percent. Given current market
conditions, increasing the cap on the NF Standard rate is not expected
to result in increased revenues during the rate period. BPA also is
proposing to increase the Intertie Charge and the NF Contract rate by 4
percent.
BPA is proposing to extend the Reserve Power (RP) rate, the Share-
the-Savings (SS) rate and the Power Shortage (PS) rate unchanged for
the 1 year period. These rates normally are not adjusted to reflect
changes in BPA's costs. The RP rate is based on BPA's estimate of its
long-term marginal cost. This rate has not been adjusted since 1987.
The SS rate is an experimental nonfirm energy rate that allows for a
mutually agreed-to formula rate. The PS rate is a contractually agreed-
to rate and is available for sales under the Shortage Agreement. The
parties to the Shortage Agreement recently agreed to extend that
agreement for another year.
Unlike its other rates, BPA's current Surplus Power (SP-93) rate
does not expire on September 30, 1995. FERC has approved the SP-93 rate
through September 30, 1998. 67 FERC 61351 (June 20, 1994). Therefore,
since the SP rate continues to be in effect during the 1-year rate
period, BPA proposes to retain its current SP-93 rate and not refile a
new SP rate for the 1-year rate period agreed to in the Settlement
Agreement. The current SP-93 rate contains a contract rate and a
flexible rate. BPA does not expect to make any sales at the contract
rate during the rate period. The flexible rate is capped at BPA's
highest cost resource, which is significantly above the expected market
price during the rate period. As such increasing the SP flexible rate
by 4 percent would not advance the settlement's cost recovery
objectives.
B. Summary of Rate Schedules
A summary of the proposed 1995 Wholesale Power Rate Schedules is
provided below. Each of the rate schedules includes sections specifying
the customer class and the service available under the rate schedule,
the rates for the sales offered under the schedule, the billing
factors, other special provisions for rate adjustments, such discounts
or penalties that apply to that rate schedule, and the cost basis of
the rates in the schedule (resource contribution). Because the 1995
rates will be effective for a 1-year period, BPA is not proposing an
Interim Rate Adjustment for these rates.
1. Priority Firm Power rate: The proposed Priority Firm Power (PF-
95) rate schedule would replace the PF-93 rate schedule. Power is
available under the PF-95 rate schedule to public bodies, cooperatives,
Federal agencies, and utilities participating in the residential
exchange under section 5(c) of the Northwest Power Act. Priority Firm
power must be used to meet firm loads within the Pacific Northwest. The
PF rate consists of diurnally differentiated demand charges and
seasonally differentiated energy charges. Other rate adjustments
include an Irrigation Discount, a Low Density Discount, an Energy
Return Surcharge, Unauthorized Increase Charge, Conservation Surcharge,
Outage Credit and Power Factor Adjustment.
2. New Resource Firm Power rate: The proposed New Resource Firm
Power (NR-95) rate schedule would replace the NR-93 rate schedule. The
NR-95 rate schedule is available to investor-owned utilities under net
requirements contracts for resale to consumers, and to publicly owned
utilities for New Large Single Loads. The NR rate consists of diurnally
differentiated demand charges and seasonally differentiated energy
charges. Other rate adjustments include an Irrigation Discount, a Low
Density Discount, an Energy Return Surcharge, Unauthorized Increase
Charge, Conservation Surcharge, Outage Credit and Power Factor
Adjustment.
3. Industrial Firm Power rate: The proposed Industrial Firm Power
Rate (IP-95) rate would replace the IP-93 rate. The IP-95 rate schedule
is available to BPA's direct-service industrial customers for firm
power to be used in their industrial operations. The IP rate consists
of diurnally differentiated demand charges and seasonally
differentiated energy charges. Other rate adjustments include a First
Quartile Discount, Curtailment Charge, Unauthorized Increase Charge,
Outage Credit and Power Factor Adjustment.
4. Variable Industrial Power rate: The Variable Industrial Power
(VI-95) rate schedule is available to DSIs purchasing from BPA under
the 1986 Variable Rate Contract. The proposed VI-95 rate schedule is
unchanged from prior years other than to update the rates and rate
parameters based on the rate adjustment criteria established in 1991
and the 1995 rate case. The proposed base rate components of the VI-95
rate include the 4 percent surcharge, as do the First Quartile Discount
and the Lower and Upper Rate Limits. The Lower and Upper Pivot Aluminum
Prices are those that were effective July 1, 1995, pursuant to the VI-
91 rate. They will be adjusted again on July 1, 1996. The VI rate is
proposed to be extended three months past its expiration date, June 30,
1996, so that its term will be consistent with the other rates proposed
for fiscal year 1996. The term of the proposed VI-95 rate thus would be
October 1, 1995, through September 30, 1996.
5. Special Industrial Power rate: The proposed Special Industrial
Power (SI-95) rate would replace the SI-93 rate. The SI rate is
available to any DSI purchaser which uses a raw mineral indigenous to
the region as its primary resource and which qualifies for the special
rate under the procedures established in section 7(d)(2) of the
Northwest Power Act. The SI rate consists of diurnally differentiated
demand charges and seasonally differentiated energy charges. Other rate
adjustments include a Curtailment Charge, Unauthorized Increase Charge,
Outage Credit, and Power Factor Adjustment.
6. Nonfirm Energy rate: The proposed Nonfirm Energy (NF-95) rate
schedule replaces the NF-93 rate. The NF-95 rate schedule is available
for purchases of nonfirm energy inside and outside the Pacific
Northwest for resale to consumers, direct consumption, and resale under
Western Systems Power Pool agreements. The NF-95 rate schedule includes
four rate components: A flexible Standard rate, a flexible Market
Expansion rate, a flexible Incremental rate, and a fixed Contract rate.
Other adjustments include a Guaranteed Surcharge and an Intertie
Charge. The NF Rate Cap continues to apply to all sales under the NF-95
rate schedule. The NF Rate Cap defines the maximum nonfirm energy price
for general application. The level of the NF Rate Cap is based on a
formula tied to BPA's Average System Cost and California fuel costs.
7. The Reserve Power rate: The Reserve Power (RP-95) rate schedule
replaces the RP-93 rate schedule. The RP rate is available in cases
where a purchaser's power sales contract states that the rate for
Reserve Power shall be applied; when BPA determines no other rate
schedule is applicable; or to serve a purchaser's firm power load when
BPA does not have a power sales contract in force with such a
purchaser, and BPA determines that this rate should be applied. The RP
rate consists of diurnally differentiated demand charges and a flat
energy charge. Other rate adjustments include a Power Factor
Adjustment.
8. The Power Shortage rate: The Power Shortage (PS-95) rate
schedule is available for sales under the Share-the-Shortage agreement
or when BPA arranges for purchased energy at the request of a Northwest
customer. BPA is not obligated to make Shortage Power
[[Page 21137]] available or to broker power under the PS-95 rate
schedule unless specified by contract. The PS rate contains two rate
components: a flexible Power Rate not to exceed 100 mills/kWh and a
flexible Brokering Rate not to exceed 1 mill/kWh. Other rate
adjustments include a Power Factor Adjustment.
C. Wholesale Power Rate Schedules
Schedule PF-95
Priority Firm Power Rate
Section I. Availability
This schedule is available for the contract purchase of firm power
or capacity to be used within the Pacific Northwest. Priority Firm
Power may be purchased by public bodies, cooperatives, and Federal
agencies for resale to ultimate consumers for direct consumption,
construction, test and startup, and station service.
Utilities participating in the exchange under section 5(c) of the
Northwest Power Act may purchase Priority Firm Power pursuant to their
Residential Purchase and Sale Agreements.
In addition, BPA may make power available to those parties
participating in exchange agreements which use this rate schedule as
the basis for determining the amount or value of power to be exchanged.
This schedule supersedes Schedule PF-93, which went into effect on
October 1, 1993. Sales under this schedule are made subject to BPA's
General Rate Schedule Provisions (GRSPs).
Section II. Rate
This rate schedule includes the Preference rate and the Exchange
rate. The Preference rate is available for the general requirements of
public body, cooperative and Federal agency customers. The Exchange
rate is available for all purchases of residential and small farm
exchange power pursuant to the Residential Purchase and Sale
Agreements.
A. Preference Rate
1. Demand Charge
a. $4.307 per kilowatt of billing demand occurring during all Peak
Period hours during a billing month.
b. No demand charge during Offpeak Period hours during a billing
month.
2. Energy Charge
a. 23.06 mills per kilowatt-hour of billing energy for the billing
months September through March.
b. 16.94 mills per kilowatt-hour of billing energy for the billing
months April through August.
B. Exchange Rate
1. Demand Charge
a. $4.307 per kilowatt of billing demand occurring during all Peak
Period hours during a billing month.
b. No demand charge during Offpeak Period hours during a billing
month.
2. Energy Charge
a. 23.06 mills per kilowatt-hour of billing energy for the billing
months September through March.
b. 16.94 mills per kilowatt-hour of billing energy for the billing
months April through August.
Section III. Billing Factors
In this section, billing factors are listed for each of the
following types of purchasers: computed requirements purchasers
(section III.A), purchasers of residential exchange power pursuant to
the Residential Purchase and Sale Agreements (section III.B), and
metered requirements purchasers and those Priority Firm Power
purchasers not covered by sections III.A and III.B (section III.C).
A. Computed Requirements Purchasers
Purchasers designated by BPA as computed requirements purchasers
pursuant to power sales contracts shall be billed in accordance with
the provisions of this subsection.
1. Billing Demand
The billing demand for actual, planned, and contracted computed
requirements purchasers shall be the higher of the billing factors
``a'' and ``b,'' below:
a. The lower of:
(1) The larger of the Computed Peak Requirement or the Computed
Average Energy Requirement; or
(2) The Measured Demand, before adjustment for power factor.
b. The lower of:
(1) The Computed Peak Requirement; or
(2) 60 percent of the highest Computed Peak Requirement during the
previous 11 billing months (Ratchet Demand).
2. Billing Energy
The billing energy for actual, planned, and contracted computed
requirements purchasers shall be:
a. For the months September through March, the sum of:
(1) 76 percent of the Measured Energy (excluding unauthorized
increase); and
(2) 24 percent of the Computed Energy Maximum.
b. For the months April through August, the sum of:
(1) 63 percent of the Measured Energy (excluding unauthorized
increase); and
(2) 37 percent of the Computed Energy Maximum.
B. Purchasers of Residential Exchange Power
Purchasers buying Priority Firm Power under the terms of a
Residential Purchase and Sale Agreement shall be billed as follows:
1. Billing Demand
The billing demand shall be the demand calculated by applying the
load factor, determined as specified in the Residential Purchase and
Sale Agreement, to the billing energy for each billing period.
2. Billing Energy
The billing energy shall be the energy associated with the
utility's residential load for each billing period. Residential load
shall be computed in accordance with the provisions of the purchaser's
Residential Purchase and Sale Agreement.
C. Metered Requirements Purchasers, Other Purchasers Not Covered by
Sections III.A and III.B, Above
Purchasers designated as metered requirements customers and
purchasers taking or exchanging power under this rate schedule who are
not otherwise covered by sections III.A and III.B shall be billed as
follows:
1. Billing Demand
The billing demand shall be the Measured Demand as adjusted for
power factor, unless otherwise specified in the power sales contract.
2. Billing Energy
The billing energy shall be the Measured Energy, unless otherwise
specified in the power sales contract.
Section IV. Adjustments And Special Provisions
A. Power Factor Adjustment
The adjustment for power factor, when specified in this rate
schedule or in the power sales contract, shall be made in accordance
with the provisions of both this section and section III.C.1 of the
GRSPs. The adjustment shall be made if the average leading power factor
or average lagging power factor at which energy is supplied during the
billing month is less than 95 percent.
To make the power factor adjustment, BPA shall increase the billing
demand by 1 percentage point for each percentage point or major
fraction thereof (0.5 or greater) by which the average leading power
factor or average [[Page 21138]] lagging power factor is below 95
percent. BPA may elect to waive the adjustment for power factor in
whole or in part.
B. Low Density Discount (LDD)
BPA shall apply a discount to the charges for all Priority Firm
Power sold to purchasers who are eligible for an LDD. Eligibility for
the LDD and the amount of the discount (3, 5, or 7 percent) shall be
determined pursuant to section III.C.3 of the GRSPs.
C. Irrigation Discount
BPA shall apply an irrigation discount, equal to 4.90 mills per
kilowatt-hour, to the charges for qualifying energy purchased under
this rate schedule. The irrigation discount shall be applied after
calculation of the LDD. The discount shall apply only to energy
purchased during the billing months of April through October.
Eligibility for the irrigation discount and reporting requirements
shall be determined pursuant to section III.C.4 of the GRSPs.
D. Conservation Surcharge
The Northwest Power Planning Council has recommended that a
conservation surcharge be imposed on those customers subject to such
surcharge as determined by the Administrator in accordance with BPA's
Policy to Implement the Council-Recommended Conservation Surcharge. The
Conservation Surcharge shall be applied pursuant to section III.C.6 of
the GRSPs and subsequent to any other rate adjustments.
E. Outage Credit
Pursuant to section 7 of the General Contract Provisions, BPA shall
provide an outage credit to any purchaser for those hours for which BPA
is unable to deliver the full billing demand during that billing month
due to an outage on the facilities used by BPA to deliver Priority Firm
Power. Such credit shall not be provided if BPA is able to serve the
purchaser's load through the use of alternative facilities or if the
outage is for less than 30 minutes. The amount of the credit shall be
calculated according to the provisions of section III.C.2 of the GRSPs.
F. Unauthorized Increase
BPA shall apply the charge for Unauthorized Increase to any
purchaser of Priority Firm Power taking demand and energy in excess of
its contractual entitlement.
1. Rate for Unauthorized Increase
a. 100.00 mills per kilowatt-hour during the billing months August
through March.
b. 57.40 mills per kilowatt-hour during the billing months April
through July.
2. Calculation of the Amount of Unauthorized Increase
Each 60-minute clock-hour integrated or scheduled demand shall be
considered separately in determining the amount that may be considered
an unauthorized increase. BPA first shall determine the amount of
unauthorized increase related to demand and shall treat any remaining
unauthorized increase as energy-related.
a. Unauthorized Increase in Demand
That portion of any Measured Demand during Peak Period hours,
before adjustment for power factor, which exceeds the demand that the
purchaser is contractually entitled to take during the billing month
and which cannot be assigned:
(1) To a class of power that BPA delivers on such hour pursuant to
contracts between BPA and the purchaser; or
(2) To a type of power that the purchaser acquires from sources
other than BPA and that BPA delivers during such hour, shall be billed:
(a) In accordance with the provisions of the ``Relief from
Overrun'' exhibit to the power sales contract; or
(b) If such exhibit does not apply or is not a part of the
purchaser's power sales contract, at the rate for Unauthorized
Increase, based on the amount of energy associated with the excess
demand.
b. Unauthorized Increase in Energy
The amount of Measured Energy during a billing month which exceeds
the amount of energy which the purchaser is contractually entitled to
take during that month and which cannot be assigned:
(1) To a class of power which BPA delivers during such month
pursuant to contracts between BPA and the purchaser; or
(2) To a type of power which the purchaser acquires from sources
other than BPA and which BPA delivers during such month, shall be
billed:
(a) In accordance with the provisions of the ``Relief from
Overrun'' exhibit to the power sales contract; or
(b) As unauthorized increase if such exhibit does not apply or is
not a part of the purchaser's power sales contract.
G. Coincidental Billing Adjustment
Purchasers of Priority Firm Power who are billed on a coincidental
basis and who have diversity charges or diversity factors specified in
their power sales contracts shall have their charges for billing demand
adjusted according to the provisions of section III.C.5 of the GRSPs.
Computed requirements purchasers are not subject to the Coincidental
Billing Adjustment for scheduled power.
H. Energy Return Surcharge
Any purchaser who preschedules in accordance with sections 2(a)(4)
and 2(c)(2) of Exhibit E of the power sales contract and who returns,
during a single offpeak hour, more than 60 percent of the difference
between that purchaser's billing demand and computed average energy
requirement for the billing month shall be subject to the following
surcharge for each additional kilowatt-hour so returned:
1. 4.25 mills per kilowatt-hour for the months of April through
October;
2. 1.80 mills per kilowatt-hour for the months of November through
March.
Section V. Resource Cost Contribution
BPA has made the following determinations:
A. The approximate cost contribution of different resource
categories to the PF-95 rate is 72.2 percent FBS and 27.8 percent
Exchange.
B. The forecasted average cost of resources available to BPA under
average water conditions is 19.80 mills per kilowatt-hour.
C. The forecasted cost of resources to meet load growth is 60.64
mills per kilowatt-hour.
Schedule IP-95
Industrial Firm Power Rate
Section I. Availability
This schedule is available to direct service industrial (DSI)
customers for both the contract purchase of Industrial Firm Power and
the purchase of Auxiliary Power if requested by the DSI customer and
made available by BPA. If a DSI customer purchasing power under this
rate schedule requests and BPA makes available power under another
applicable wholesale rate schedule, the IP-95 rate schedule is
available for that portion of power purchased not covered under the
alternative rate schedule. This rate schedule supersedes Schedule IP-
93, which went into effect on October 1, 1993. Sales under this
schedule are made subject to BPA's General Rate Schedule Provisions
(GRSPs). [[Page 21139]]
Section II. Rate
The following rates shall be applied when first quartile service is
provided under this rate schedule in accordance with the terms of a
purchaser's Power Sales Contract dated August 25, 1981. A separate
billing adjustment for the reserves provided by the purchasers of
Industrial Firm Power is not contained in this rate schedule; the value
of reserves credit has been included in the determination of the demand
and energy charges.
Any contractual reference to the IP Premium rate shall be deemed to
refer to the demand and energy charges set forth below. Any reference
to the IP Standard rate shall be deemed to refer to the same demand and
energy charges minus the Discount for Quality of First Quartile
Service.
A. Demand Charge
1. $5.316 per kilowatt of billing demand occurring during all Peak
Period hours during a billing month.
2. No demand charge during Offpeak Period hours.
B. Energy Charge
1. 21.90 mills per kilowatt-hour of billing energy for the billing
months September through March.
2. 18.02 mills per kilowatt-hour of billing energy for the billing
months April through August.
Section III. Billing Factors
A. Billing Demand
The billing demand shall be the BPA Operating Level during the Peak
Period as adjusted for power factor. If there is more than one BPA
Operating Level during the Peak Period within a billing month, the
billing demand shall be a weighted average of the BPA Operating Levels
during the Peak Period for the billing month. The BPA Operating Level
is defined in section III.A.10 of the GRSPs. If BPA has agreed to serve
a portion of a DSI load under an alternative rate schedule, the billing
demand under the IP-95 rate schedule shall be specified in the contract
initiating such arrangement.
However, if BPA has agreed, pursuant to section 4 of the DSI power
sales contract, to sell Industrial Firm Power on a daily demand basis
(transitional service), then BPA shall bill the purchaser in accordance
with the provisions of section V.C.3 of the GRSPs.
B. Billing Energy
The billing energy shall be the Measured Energy for the billing
month, minus any kilowatt-hours on which BPA assesses the charge for
unauthorized increase.
However, if BPA has agreed to serve only a portion of the DSI's
load under the IP rate schedule, the billing energy for the power
purchased under the IP rate shall be specified in the contract
initiating such arrangement.
Section IV. Adjustments and Special Provisions
A. Discount for Quality of First Quartile Service
1. Application and Amount of First Quartile Discount
If a purchaser requests discounted rate service, a discount of 0.72
mills per kilowatt-hour of billing energy shall be granted. This
billing credit shall be applied to the monthly billing energy under
section III.B for all power purchased under this rate schedule. No
credit shall be applied to those purchases subject to unauthorized
increase charges under section IV.D of this rate schedule.
2. Eligibility Requirements for First Quartile Discount
To qualify for the First Quartile Discount the purchaser must
request discounted rate service in writing by April 2 of each calendar
year. By virtue of making such request, the Purchaser is agreeing to
accept the level and quality of First Quartile service described in
section 6 of the Variable Industrial rate contract. Such acceptance
includes the waiver of contract rights provided in section 6.a(2)(a) of
said contract.
B. Curtailments
BPA shall charge the DSI for curtailments of the lower three
quartiles in accordance with the provisions of section 9 of the power
sales contract. BPA shall apply the demand charge in effect at the time
of the curtailment in the computation of the amount of the curtailment
charge. In the event that a purchaser is found to be eligible to have a
portion of their load served under an alternative rate schedule,
application of the curtailment charge shall be specified in the
contract instituting such arrangement.
C. Unauthorized Increase
1. Rate for Unauthorized Increase
a. 100.00 mills per kilowatt-hour during billing months August
through March.
b. 57.40 mills per kilowatt-hour during billing months April
through July.
2. Application of the Charge
During any billing month, BPA may assess the unauthorized increase
charge on the number of kilowatt-hours associated with the DSI Measured
Demand in any one 60-minute clock-hour, before adjustment for power
factor, that exceed the BPA Operating Level for that clock-hour,
regardless of whether such Measured Demand occurs during the Peak or
Offpeak Period.
D. Power Factor Adjustment
The adjustment for power factor, when specified in this rate
schedule or in the power sales contract, shall be made in accordance
with the provisions of both this section and section III.C.1 of the
GRSPs. The adjustment shall be made if the average leading power factor
or average lagging power factor at which energy is supplied during the
billing month is less than 95 percent.
To make the power factor adjustment, BPA shall increase the billing
demand by 1 percentage point for each percentage point or major
fraction thereof (0.5 or greater) by which the average leading power
factor or average lagging power factor is below 95 percent. BPA may
elect to waive the adjustment for power factor in whole or in part.
E. Outage Credit
Pursuant to section 7 of the General Contract Provisions, BPA shall
provide an outage credit to any DSI for those hours for which BPA is
unable to deliver the full billing demand during that billing month due
to an outage on the facilities used by BPA to deliver Industrial Firm
Power. Such credit shall not be provided if BPA is able to serve the
DSI's load through the use of alternative facilities or if the outage
is for less than 30 minutes. The amount of the credit shall be
calculated according to the provisions of section III.C.2 of the GRSPs.
Section V. Resource Cost Contribution
BPA has made the following determinations:
A. The approximate cost contribution of different resource
categories to the IP-95 rate is 85.8 percent Exchange and 14.2 percent
New Resources.
B. The forecasted average cost of resources available to BPA under
average water conditions is 19.80 mills per kilowatt-hour.
C. The forecasted cost of resources to meet load growth is 60.64
mills per kilowatt-hour. [[Page 21140]]
Schedule VI-95
Variable Industrial Power Rate
Section I. Availability
This schedule is available to DSI customers for purchases under the
Power Sales Contract implementing the VI rate schedule (Variable Rate
Contract) of: (1) Industrial Firm Power; and (2) Auxiliary Power if
requested by the DSI customer and made available by BPA. This schedule
is available only for that portion of a DSI's load used in primary
aluminum reduction including associated administrative facilities, if
any. By virtue of incorporation of this rate schedule and associated
GRSPs in the Variable Rate Contract, DSIs electing to purchase power
under this rate schedule contractually agree to the terms and
conditions of this rate schedule. A DSI further agrees to waive, for
that portion of their load designated to purchase power at the VI rate,
all rights they might otherwise have to purchase power at the
Industrial Firm Power Rate Schedule for the duration of the Variable
Rate Contract. Sales under this schedule are made subject to BPA's
GRSPs.
Section II. Term of the Rate
This rate schedule shall take effect on October 1, 1995, and shall
terminate at midnight September 30, 1996.
Section III. Rate
A. Base Rate
The formula to be used in the calculation of the monthly power bill
is contained in section IV. A separate billing adjustment for the value
of the reserves provided by purchasers of Industrial Firm Power is not
contained in this rate schedule; the value of reserves credit has been
included in the determination of the Plateau Energy Charge.
1. Base Variable Industrial Rate
a. Demand Charge
$6.233 per kilowatt of billing demand, as adjusted, occurring
during the Peak Period during a billing month. No demand charge is
applied during Offpeak Period hours.
b. Plateau Energy Charge
18.83 mills per kilowatt-hour of billing energy, as adjusted.
2. First Quartile Service Discount
0.59 mills per kilowatt-hour of billing energy.
3. Lower Rate Limit
15.03 mills per kilowatt-hour of billing energy.
4. Upper Rate Limit
24.63 mills per kilowatt-hour of billing energy.
B. Base Rate Parameters Subject to Annual Adjustments
The following base rate parameters shall be used to determine power
bills for DSI customers purchasing power under the Variable Rate
Contract. These parameters will be adjusted July 1, 1996, in accordance
with the procedures contained in section VII.B of the GRSPs.
1. Lower Pivot Aluminum Price
75.4 cents per pound.
2. Upper Pivot Aluminum Price
91.6 cents per pound.
Section IV. Formula
The Variable Industrial Power rate is a formula rate tied to the
U.S. market price of aluminum. Under this rate schedule, the monthly
energy charge varies in response to changes in the average price of
aluminum in U.S. markets.
A. Demand Charge
1. The Demand Charge, as stated in section III.A.1.a of this rate
schedule, remains constant over all aluminum prices. The demand charge
is applied to billing demand occurring during all Peak Period hours for
all billing months.
2. No demand charge during Offpeak Period hours.
B. Energy Charge
1. Plateau Energy Charge
When the monthly billing aluminum price (described in section VII.A
of the GRSPs) is between the Lower Pivot Aluminum Price and the Upper
Pivot Aluminum Price inclusive (as stated in sections III.B.1 and
III.B.2 of this rate schedule), the monthly energy charge shall be the
Plateau Energy Charge as stated in section III.A.1.b of this rate
schedule.
2. Reductions to Plateau Energy Charge
When the monthly billing aluminum price is less than the Lower
Pivot Aluminum Price, the monthly energy charge shall be the greater
of:
a. The Plateau Energy Charge - (LP-MAP) * (LS)
where:
LP=the Lower Pivot Aluminum Price as stated in section III.B.1 of this
rate schedule.
MAP=the monthly billing aluminum price in cents per pound determined
pursuant to section VII.A of the GRSPs
LS=lower slope=1 mill per kilowatt-hour
________________________
1 cent per pound
or
b. The Lower Rate Limit as stated in section III.A.3 of this rate
schedule.
3. Increases to Plateau Energy Charge
When the monthly billing aluminum price is greater than the Upper
Pivot Aluminum Price, the monthly energy charge shall be the lesser of:
a. The Plateau Energy Charge+(MAP-UP) * (US)
where:
MAP=the monthly billing aluminum price in cents per pound, as
determined according to section VII.A of the GRSPs.
UP=the Upper Pivot Aluminum Price as stated in section III.B.2 of this
rate schedule.
US=upper slope=0.75 mills per kilowatt-hour
____________________________
1 cent per pound
b. The Upper Rate Limit, as stated in section III.A.4 of this rate
schedule.
Section V. Billing Factors
A. Billing Demand
1. Billing Demand for Customers Whose Entire BPA Load Is Served at the
VI Rate
The billing demand for power purchased shall be the BPA Operating
Level during the Peak Period as adjusted for power factor. If there is
more than one BPA Operating Level during the Peak Period within a
billing month, the billing demand shall be a weighted average of the
BPA Operating Levels during the Peak Period for the billing month. The
BPA Operating Level is defined in section III.A.10 of the GRSPs.
2. Billing Demand or Customers When Only a Portion of Their Total BPA
Load Is Served at the Variable Rate
The Billing Demand shall be the portion of the BPA Operating Level
attributable to the VI rate as determined by the method specified in
the Variable Rate Contract.
3. Billing Demand During Periods of Transitional Service
If BPA has agreed, pursuant to section 4 of the DSI power sales
contract, to sell Industrial Firm Power on a daily demand basis
(transitional service), sections V.A.1 and V.A.2 of the rate schedule
shall not apply, and BPA shall bill the purchaser in accordance with
the provisions of section V.C of the GRSPs. [[Page 21141]]
B. Billing Energy
The billing energy for power purchased shall be the Measured Energy
for the billing month, minus any kilowatt-hours on which BPA assesses
the charge for unauthorized increase.
Section VI. Other Adjustments and Special Provisions
A. Lower and Upper Pivot Aluminum Prices
Effective July 1, 1991, and every July 1 thereafter, the Lower and
Upper Pivot Aluminum Prices set forth in section III.B of the rate
schedule shall be adjusted following the procedures set forth in
section VII.B of the GRSPs. The adjusted Lower and Upper Pivot Aluminum
Prices shall supersede the Lower and Upper Pivot Aluminum Prices
contained in section III.B of the rate schedule.
B. Discount for Quality of First Quartile Service
If a purchaser requests First Quartile service with other than
Surplus Firm Energy Load Carrying Capability (FELCC), a discount
contained in section III.A.2 of this rate schedule shall be granted.
This billing credit shall be applied to the monthly billing energy
under section V.B for all power purchased under this rate schedule. No
credit shall be applied to those purchases subject to unauthorized
increase charges under section VI.F of this rate schedule. To qualify
for the First Quartile Discount, the purchaser must request discounted
rate service in writing by April 2 of each calendar year. By virtue of
making such request, the Purchaser is agreeing to accept the level and
quality of First Quartile service described in section 6 of the
Variable Rate Contract. Such acceptance includes the waiver of contract
rights provided in section 6.a(2)(a) of said contract.
C. Unauthorized Increase
1. Rate for Unauthorized Increase
a. 100.00 mills per kilowatt-hour during the billing months August
through March.
b. 57.40 mills per kilowatt-hour during the billing months April
through July.
2. Application of the Charge
During any billing month, BPA may assess the unauthorized increase
charge on the number of kilowatt-hours associated with the DSI Measured
Demand in any one 60-minute clock-hour, before adjustment for power
factor, that exceed the BPA Operating Level for that clock-hour,
regardless of whether such Measured Demand occurs during the Peak or
Offpeak Period.
D. Power Factor Adjustment
The adjustment for power factor, when specified in this rate
schedule or in the power sales contract, shall be made in accordance
with the provisions of both this section and section III.C.1 of the
GRSPs. The adjustment shall be made if the average leading power factor
or average lagging power factor at which energy is supplied during the
billing month is less than 95 percent.
To make the power factor adjustment, BPA shall increase the BPA
Operating Level by 1 percentage point for each percentage point or
major fraction thereof (0.5 or greater) by which the average leading
power factor or average lagging power factor is below 95 percent. BPA
may elect to waive the adjustment for power factor in whole or in part.
E. Outage Credit
Pursuant to section 7 of the General Contract Provisions, BPA shall
provide an outage credit to any DSI to whom BPA is unable to deliver
the full billing demand during that billing month due to an outage on
the facilities used by BPA to deliver Industrial Firm Power. Such
credit shall not be provided if BPA is able to serve the DSI's load
through the use of alternative facilities or if the outage is for less
than 30 minutes. The amount of the credit shall be calculated according
to the provisions of section III.C.2 of the GRSPs.
Section VII. Resource Cost Contribution
BPA has made the following determinations:
A. The approximate cost contribution of different resource
categories to the VI-95 rate is 85.8 percent Exchange and 14.2 percent
New Resources.
B. The forecasted average cost of resources available to BPA under
average water conditions is 19.80 mills per kilowatt-hour.
C. The forecasted cost of resources to meet load growth is 60.64
mills per kilowatt-hour.
Schedule SI-95
Special Industrial Power Rate
Section I. Availability
This rate schedule is available to any DSI purchaser using raw
minerals indigenous to the region as its primary resource and
qualifying for this special power pursuant to the procedures
established in section 7(d)(2) of the Northwest Power Act. This
schedule is available for the contract purchase of this special class
of industrial power and also for the purchase of Auxiliary Power if
requested by the DSI and made available by BPA. Schedule SI-95
supersedes schedule SI-93, which went into effect on October 1, 1993.
Sales under this schedule are made subject to BPA's General Rate
Schedule Provisions (GRSPs).
Section II. Rate
A separate billing adjustment for the value of the reserves
provided by purchasers of this special class of Industrial Power is not
contained in the rate schedule; the adjustment is reflected in the
Special Industrial Power Rate charges.
A. Demand Charge
1. $3.827 per kilowatt of billing demand occurring during all Peak
Period hours during a billing month.
2. No demand charge during Offpeak Period hours.
B. Energy Charge
1. 21.20 mills per kilowatt-hour of billing energy for the billing
months September through March;
2. 15.08 mills per kilowatt-hour of billing energy for the billing
months April through August.
Section III. Billing Factors
A. Billing Demand
The billing demand for power purchased under the Standard Special
Industrial Power rate shall be the BPA Operating Level during the Peak
Period as adjusted for power factor. If there is more than one BPA
Operating Level during the Peak Period within a billing month, the
billing demand shall be a weighted average of the Peak Period BPA
Operating Levels for the billing month. The BPA Operating Level is
defined in section III.A.10 of the GRSPs.
However, if BPA has agreed, pursuant to section 4 of the direct
service industrial power sales contract, to sell Special Industrial
Power on a daily demand basis (transitional service), BPA shall instead
bill the purchaser in accordance with the provisions of section V.C of
the GRSPs.
B. Billing Energy
The billing energy under the Special Industrial rate shall be the
Measured Energy for the billing month, minus any kilowatt-hours on
which BPA assesses the charge for unauthorized increase.
Section IV. Adjustments and Special Provisions
A. Curtailments
BPA shall charge the DSI for curtailments in accordance with the
[[Page 21142]] provisions of the DSI's power sales contract. Any
curtailment charge levied shall be computed using the Special
Industrial Power rate.
B. Unauthorized Increase Charge
1. Rate for Unauthorized Increase
a. 100.00 mills per kilowatt-hour during billing months August
through March.
b. 57.40 mills per kilowatt-hour during billing months April
through July.
2. Application of the Charge
During any billing month, BPA may assess the unauthorized increase
charge on the number of kilowatt-hours associated with the DSI Measured
Demand in any one 60-minute clock-hour, before adjustment for power
factor, that exceed the BPA Operating Level for that clock-hour,
regardless of whether such Measured Demand occurs during the Peak or
Offpeak Period.
C. Power Factor Adjustment
The adjustment for power factor, when specified in this rate
schedule or in the power sales contract, shall be made in accordance
with the provisions of both this section and section III.C.1 of the
GRSPs. The adjustment shall be made if the average leading power factor
or average lagging power factor at which energy is supplied during the
billing month is less than 95 percent.
To make the power factor adjustment for service under the Special
Industrial Power rate, BPA shall increase the billing demand by 1
percentage point for each percentage point or major fraction thereof
(0.5 or greater) by which the average leading power factor or average
lagging power factor is below 95 percent. BPA may elect to waive the
adjustment for power factor in whole or in part.
D. Outage Credit
Pursuant to section 7 of the General Contract Provisions, BPA shall
provide an outage credit to any purchaser for those hours for which BPA
is unable to deliver the full billing demand during that billing month
due to an outage on the facilities used by BPA to deliver Special
Industrial Power. Such credit shall not be provided if BPA is able to
serve the purchaser's load through the use of alternative facilities or
if the outage is for less than 30 minutes. The amount of the credit
shall be calculated according to the provisions of section III.C.2 of
the GRSPs.
Section V. Resource Cost Contribution
BPA has made the following determinations:
A. The SI-95 rate is not based on the cost of resources.
B. The forecasted average cost of resources available to BPA under
average water conditions is 19.80 mills per kilowatt-hour.
C. The forecasted cost of resources to meet load growth is 60.64
mills per kilowatt-hour.
Schedule CE-95
Emergency Capacity Rate
Section I. Availability
This schedule is available for the purchase of capacity provided
the purchaser requests such capacity and BPA has determined that
capacity is available for such purpose. This schedule is available
when:
A. An emergency exists on the purchaser's system, or
B. The purchaser wishes to displace higher-cost firm capacity
resources which are otherwise available to meet the purchaser's load.
This schedule supersedes Schedule CE-93 which went into effect on
October 1, 1993. Sales under this schedule are made subject to BPA's
General Rate Schedule Provisions.
Section II. Rate
A. Demand Charge
As mutually agreed by BPA and the purchaser, up to $0.321 per
kilowatt of demand per calendar day or portion thereof.
B. Intertie Charge
The demand charge specified above shall be increased by $0.044 per
kilowatt per day for capacity made available at the Oregon-California
or Oregon-Nevada border for delivery over the Pacific Northwest-Pacific
Southwest (Southern) Intertie.
Section III. Billing Factors
The billing demand shall be the maximum amount requested by the
purchaser and made available by BPA during a calendar day. If BPA is
unable to meet subsequent requests by a purchaser for delivery at the
demand previously established during such day, the billing demand for
that day shall be the lower demand which BPA is able to supply.
Section IV. Billing Period
Bills shall be rendered monthly.
Section V. Special Provision
Energy delivered with such capacity shall be returned to BPA within
7 days of the date of delivery and shall be returned at times and rates
of delivery agreed to by both the purchaser and BPA prior to delivery.
BPA may agree to accept the return energy after the normal 7 day return
period provided that such delay has been mutually agreed upon prior to
delivery.
Section VI. Resource Cost Contribution
BPA has made the following determinations:
A. The approximate cost contribution of different resource
categories to the CE-95 rate is 85.8 percent Exchange and 14.2 percent
New Resources.
B. The forecasted average cost of resources available to BPA under
average water conditions is 19.6 mills per kilowatt-hour.
C. The forecasted cost of resources to meet load growth is 55.7
mills per kilowatt-hour.
Schedule NR-95
New Resource Firm Power Rate
Section I. Availability
This schedule is available for the contract purchase of firm power
or capacity to be used within the Pacific Northwest. New Resource Firm
Power is available to investor-owned utilities (IOUs) under net
requirements contracts for resale to ultimate consumers, direct
consumption, or use in construction, test and start up, and station
service. New Resource Firm Power also is available to any public body,
cooperative, or Federal agency to the extent such power is needed to
serve any New Large Single Load. In addition, BPA may make this rate
available to those parties participating in exchange agreements that
use this rate schedule as the basis for determining the amount or value
of power to be exchanged. This schedule supersedes Schedule NR-93,
which went into effect on October 1, 1993. Sales under this schedule
are made subject to BPA's General Rate Schedule Provisions (GRSPs).
Section II. Rate
A. Demand Charge
1. $5.357 per kilowatt of billing demand occurring during all Peak
Period hours during a billing month.
2. No demand charge during Offpeak Period hours.
B. Energy Charge
1. 28.66 mills per kilowatt-hour of billing energy for the billing
months September through March.
2. 25.10 mills per kilowatt-hour of billing energy for the billing
months April through August.
Section III. Billing Factors
In this section billing factors are listed for computed
requirements purchasers [[Page 21143]] (section III.A), metered
requirements purchasers, and those purchasers not covered by section
III.A (section III.B).
A. Computed Requirements Purchasers
Purchasers designated by BPA as computed requirements purchasers
pursuant to power sales contracts shall be billed in accordance with
the provisions of this section.
1. Billing Demand
The billing demand for actual, planned, and contracted computed
requirements purchasers shall be the higher of the billing factors
``a'' and ``b,'' below:
a. The lower of:
(1) The larger of the Computed Peak Requirement or the Computed
Average Energy Requirement; or
(2) The Measured Demand, before adjustment for power factor.
b. The lower of:
(1) The Computed Peak Requirement; or
(2) 60 percent of the highest Computed Peak Requirement during the
previous 11 billing months (Ratchet Demand).
2. Billing Energy
The billing energy for actual, planned, and contracted computed
requirements purchasers shall be:
a. For the months September through March, the sum of:
(1) 55 percent of the Measured Energy; and
(2) 45 percent of the Computed Energy Maximum.
b. For the months April through August, the sum of:
(1) 43 percent of the Measured Energy; and
(2) 57 percent of the Computed Energy Maximum.
B. Metered Requirements Purchasers and Other Purchasers Not Covered by
Section III.A, Above
Purchasers designated as metered requirements customers and
purchasers taking power under this rate schedule who are not otherwise
covered by section III.A shall be billed as follows:
1. Billing Demand
The billing demand shall be the Measured Demand as adjusted for
power factor, unless otherwise specified in the power sales contract.
However, purchasers who previously used the Firm Energy rate schedule,
FE-2, either in the computation of their power bills or in the
determination of the value of an exchange account, shall not be charged
for demand under this rate schedule.
2. Billing Energy
The billing energy shall be the Measured Energy, unless otherwise
specified in the power sales contract.
Section IV. Adjustments and Special Provisions
A. Power Factor Adjustment
The adjustment for power factor, when specified in this rate
schedule or in the power sales contract, shall be made in accordance
with the provisions of both this section and section III.C.1 of the
GRSPs. The adjustment shall be made if the average leading power factor
or average lagging power factor at which energy is supplied during the
billing month is less than 95 percent.
To make the power factor adjustment, BPA shall increase the billing
demand by 1 percentage point for each percentage point or major
fraction thereof (0.5 or greater) by which the average leading power
factor or average lagging power factor is below 95 percent. BPA may
elect to waive the adjustment for power factor in whole or in part.
B. Irrigation Discount
BPA shall apply an irrigation discount, equal to 4.90 mills per
kilowatt-hour, to the charges for qualifying energy purchased under
this rate schedule. The discount shall apply only to energy purchased
during the billing months of April through October. Eligibility for the
irrigation discount and reporting requirements shall be determined
pursuant to section III.C.4 of the GRSPs.
C. Conservation Surcharge
The Conservation Surcharge shall be applied in accordance with
section III.C.6 of the GRSPs and subsequent to any other rate
adjustments.
D. Unauthorized Increase
BPA shall apply the charge for Unauthorized Increase to any
purchaser of New Resource Firm Power taking demand and/or energy in
excess of its contractual entitlement.
1. Rate for Unauthorized Increase
a. 100.00 mills per kilowatt-hour during billing months August
through March.
b. 57.40 mills per kilowatt-hour during billing months April
through July.
2. Calculation of the Unauthorized Increase
Each 60-minute clock-hour integrated or scheduled demand shall be
considered separately in determining the amount which may be considered
an unauthorized increase. BPA shall first determine the amount of
unauthorized increase related to demand and shall then treat any
remaining unauthorized increase as energy-related.
a. Unauthorized Increase in Demand
That portion of any Measured Demand during Peak Period hours,
before adjustment for power factor, that exceeds the demand which the
purchaser is contractually entitled to take during the billing month
and that cannot be assigned:
(1) To a class of power which BPA delivers on such hour pursuant to
contracts between BPA and the purchaser; or
(2) To a type of power which the purchaser acquires from sources
other than BPA and which BPA delivers during such hour, shall be
billed:
(a) In accordance with the provisions of the ``Relief from
Overrun'' exhibit to the power sales contract; or
(b) If such exhibit does not apply or is not a part of the
purchaser's power sales contract, at the rate for Unauthorized
Increase, based on the amount of energy associated with the excess
demand.
b. Unauthorized Increase in Energy
The amount of Measured Energy during a billing month that exceeds
the amount of energy which the purchaser is contractually entitled to
take during that month and that cannot be assigned:
(1) To a class of power that BPA delivers during such month
pursuant to contracts between BPA and the purchaser; or
(2) To a type of power that the purchaser acquires from sources
other than BPA and that BPA delivers during such month, shall be
billed:
(a) In accordance with the provisions of the ``Relief from
Overrun'' exhibit to the power sales contract, or
(b) As unauthorized increase if such exhibit does not apply or is
not a part of the purchaser's power sales contract.
E. Coincidental Billing Adjustment
Purchasers of New Resource Firm Power who are billed on a
coincidental basis and who have diversity charges or diversity factors
specified in their power sales contracts shall have their charges for
billing demand adjusted according to the provisions of section III.C.5
of the GRSPs. Computed requirements purchasers are not subject to the
Coincidental Billing Adjustment for scheduled power.
F. Outage Credit
Pursuant to section 7 of the General Contract Provisions, BPA shall
provide [[Page 21144]] an outage credit to any purchaser for those
hours for which BPA is unable to deliver the full billing demand during
the billing month due to an outage on the facilities used by BPA to
deliver New Resource Firm Power. Such credit shall not be provided if
BPA is able to serve the purchaser's load through the use of
alternative facilities or if the outage is for less than 30 minutes.
The amount of the credit shall be calculated according to the
provisions of section III.C.2 of the GRSPs.
G. Energy Return Surcharge
Any purchaser who preschedules in accordance with sections 2(a)(4)
and 2(c)(2) of Exhibit E of the Power Sales contract and who returns,
during a single offpeak hour, more than 60 percent of the difference
between that purchaser's billing demand and estimated computed average
energy requirement for the billing month shall be subject to the
following surcharge for each additional kilowatt-hour so returned:
1. 4.25 mills per kilowatt-hour for the months of April through
October; and
2. 1.80 mills per kilowatt-hour for the months of November through
March.
Section V. Resource Cost Contribution
BPA has made the following determinations:
A. The approximate cost contribution of different resource
categories to the NR-95 rate is 89.7 percent Exchange and 10.3 percent
New Resources.
B. The forecasted average cost of resources available to BPA under
average water conditions is 19.80 mills per kilowatt-hour.
C. The forecasted cost of resources to meet load growth is 60.64
mills per kilowatt-hour.
Schedule NF-95
Nonfirm Energy Rate
Section I. Availability
This schedule is available for the purchase of nonfirm energy to be
used both inside and outside the United States including sales under
the Western Systems Power Pool (WSPP) agreements and sales to
consumers. This schedule also applies to energy delivered for emergency
use under the conditions set forth in section V.A of the General Rate
Schedule Provisions (GRSPs). BPA is not obligated to offer nonfirm
energy to any purchaser that results in displacement of firm power
purchases under BPA's Power Sales Contracts. The offer of nonfirm
energy under this schedule shall be determined by BPA. Schedule NF-95
supersedes Schedule NF-93, which went into effect on October 1, 1993.
Sales under this schedule are made subject to BPA's GRSPs.
Section II. Rates
The average cost of nonfirm energy is 23.31 mills per kilowatt-
hour. The NF-95 rate schedule provides for upward and downward pricing
flexibility from this average nonfirm energy cost. All rates and any
subsequent adjustments contained in this rate schedule shall not exceed
in total the NF Rate Cap defined in section IV.C of the GRSPs.
A. Standard Rate
The Standard rate is any offered rate not to exceed 27.97 mills per
kilowatt-hour.
B. Market Expansion Rate
The Market Expansion rate is any offered rate below the Standard
rate in effect. BPA may have one or more Market Expansion rates in
effect simultaneously.
C. Incremental Rate
The Incremental rate is the Incremental Cost of energy plus 2.00
mills per kilowatt-hour, where the Incremental Cost is defined as all
identifiable costs (expressed in mills per kilowatt-hour) that BPA
would have avoided had it not produced or purchased the energy being
sold under this rate.
D. Contract Rate
The Contract rate is 14.83 mills per kilowatt-hour of billing
energy.
Section III. Adjustments to Rates
A. Guaranteed Delivery Surcharge
A surcharge of 2.00 mills per kilowatt-hour of billing energy is
applied to guaranteed delivery of nonfirm energy under the Standard
rate and Market Expansion rate.
B. Intertie Charge
The Intertie Charge, on rate offers under any of the rates
specified above, for sales of nonfirm energy scheduled for delivery
over the Pacific Northwest-Pacific Southwest Intertie shall be:
1. Inapplicable for rate offers of less than 23.31 mills per
kilowatt-hour;
2. At the discretion of BPA, from zero through 3.23 mills per
kilowatt-hour, for rate offers of 23.31 mills per kilowatt-hour; or
3. 3.23 mills per kilowatt-hour, for rate offers greater than 23.31
mills per kilowatt-hour.
Section IV. Billing Factors
The billing energy for nonfirm energy purchased under this rate
schedule shall be the Measured Energy unless otherwise specified by
contract.
Section V. Application and Eligibility
Any time that BPA has nonfirm energy for sale, the Standard rate,
the Market Expansion rate, the Incremental rate, the Contract rate, or
a combination of these rates may be in effect.
A. Standard Rate
The Standard rate:
1. Is available for all purchases of nonfirm energy; and
2. Applies to nonfirm energy purchased pursuant to the Relief from
Overrun Exhibit to the power sales contract.
B. Market Expansion Rate
1. Application of the Market Expansion Rate
The Market Expansion rate applies when BPA determines that all
markets at the Standard rate have been satisfied and BPA offers
additional nonfirm energy.
2. Market Expansion Rate Qualification Criteria
In order to purchase nonfirm energy at the Market Expansion rate, a
purchaser must:
a. Have a displaceable resource, displaceable purchase of
electricity, or
b. Be an end-user load with a displaceable alternative fuel source.
In addition, a purchaser must demonstrate one of the following:
a. Shutdown or reduction of the output of the displaceable resource
in an amount equal to the amount of Market Expansion rate energy
purchased; or
b. Reduction of a displaceable purchase and the output of the
resource associated with that purchase, in an amount equal to the
amount of Market Expansion rate energy purchased; or
c. Shutdown or reduction of the identified output of the
resource(s) indirectly in an amount equal to the amount of Market
Expansion rate energy purchased (for example, the purchase may be used
to run a pumped storage unit); or
d. Decrease of an end-user alternate fuel source in an amount
equivalent to the amount of Market Expansion rate energy purchased.
3. Eligibility Criteria for Market Expansion Rate
a. When only one Market Expansion rate is offered:
Purchasers qualifying under section V.B.2 who purchased nonfirm
energy directly from BPA are eligible to purchase power under the
Market Expansion rate offered if the decremental cost of the qualifying
[[Page 21145]] resource, purchase, or qualifying alternative fuel
source is lower than the Standard rate in effect plus 2.0 mills per
kilowatt-hour.
Purchasers qualifying under section V.B.2 who purchase nonfirm
energy through a third party are eligible to purchase power under the
Market Expansion rate offered if the cost of the qualifying alternative
fuel source is lower than the Standard rate in effect plus 4.0 mills
per kilowatt-hour.
b. When more than one Market Expansion rate is offered:
Purchasers qualifying under section V.B.2 who purchase nonfirm
energy directly from BPA are eligible to purchase power under the
Market Expansion rate if the decremental cost of the qualifying
resource, purchase, or qualifying alternative fuel source is lower than
the Standard rate in effect plus 2.00 mills per kilowatt-hour. The rate
applicable to a purchaser shall be the highest Market Expansion rate
offered that is below the purchaser's qualifying decremental cost minus
2.00 mills per kilowatt-hour.
Purchasers qualifying under section V.B.2 who purchase nonfirm
energy through a third party are eligible to purchase power under the
Market Expansion rate if the decremental cost of the qualifying
alternative fuel source is lower than the Standard rate plus 4.00 mills
per kilowatt-hour. The rate applicable to a purchaser shall be the
highest Market Expansion rate offered that is below purchaser's
qualifying decremental cost minus 4.0 mills per kilowatt-hour.
C. Incremental Rate
The Incremental rate applies to sales of energy:
1. That is produced or purchased by BPA concurrently with the
nonfirm energy sale;
2. That BPA may at its option not produce or purchase; and
3. That has an Incremental Cost greater than the Standard rate
(plus the Intertie Charge, if applicable) less 2.00 mills per kilowatt-
hour.
D. Contract Rate
The Contract rate applies to contracts (except power sales
contracts offered pursuant to sections 5(b), 5(c), and 5(g) of the
Northwest Power Act) that refer to the Contract rate:
1. For the sale of nonfirm energy; or
2. For determining the value of energy.
E. Western Systems Power Pool Transactions (WSPP)
BPA may make available nonfirm energy for transactions under the
WSPP agreement. WSPP sales shall be subject to the terms and conditions
specified in the WSPP agreement and shall be consistent with regional
and public preference. The rate for transactions under the WSPP
agreement is any rate within the limits specified by the Standard,
Market Expansion, and Incremental rates but may not exceed the maximum
rate specified in the WSPP Agreement. The rate for WSPP sales may
differ from the actual rate offered for non-WSPP transactions in any
hour. The rate for WSPP transactions is independent of any other rate
offered concurrently under this rate schedule outside that agreement.
F. End-User Rate
BPA may agree to a rate or rate formula for nonfirm energy
purchases by end-users. Such rate or rate formula shall be within the
limits specified for the Standard and Market Expansion rates but may
differ from the actual rates offered during any hour.
Section VI. Delivery
A. Rate of Delivery
BPA shall determine the amount of nonfirm energy to be made
available for each hour. Such determination shall be made for each
applicable nonfirm energy rate.
B. Guaranteed Delivery
1. Availability
BPA will determine the amount and duration of nonfirm energy to be
offered on a guaranteed basis. Such daily or hourly amounts may be as
small as zero or as much as all the nonfirm energy that BPA plans to
offer for sale on such days.
2. Conditions
Scheduled amounts of guaranteed nonfirm energy may not be changed
except:
a. When BPA and the purchaser mutually agree to increase or
decrease the scheduled amounts; or
b. When BPA must reduce nonfirm energy deliveries in order to serve
firm loads because of unexpected generation or transmission losses.
Section VII. Resource Cost Contribution
BPA has made the following determinations:
A. The approximate cost contribution of different resource
categories to the average cost of nonfirm energy is 92.7 percent FBS
and 7.3 percent New Resources.
B. The forecasted average cost of resources available to BPA under
average water conditions is 19.80 mills per kilowatt-hour.
C. The forecasted cost of resources to meet load growth is 60.64
mills per kilowatt-hour.
Schedule SS-95
Share-the-Savings Rate
Section I. Availability
This rate schedule is available for the contract purchase of
Nonfirm Energy under an experimental rate and is limited to the term of
the rate experiment. Nonfirm Energy will be made available under this
rate schedule for use both inside and outside the United States for the
displacement of a qualifying resource, displaceable purchase of
electricity, or end-user load that can be served with alternate fuel
sources. This rate schedule is only available to purchasers who execute
a contract with BPA specifying use of the Share-the-Savings Rate. BPA
is not obligated to offer Nonfirm Energy to any purchaser that results
in displacement of firm power purchases under BPA's Power Sales
Contracts. Schedule SS-95 supersedes Schedule SS-93, which went into
effect on October 1, 1993. Sales under this schedule are made subject
to BPA's General Rate Schedule Provisions (GRSPs).
Section II. Rate
The rate shall be a formula rate based solely or in part on
decremental cost information submitted by the purchaser. The rate
formula and decremental cost, for purposes of establishing charges
under this rate schedule, shall be defined in the applicable contract.
The rate formula agreed upon by BPA and the purchaser shall in no event
result in a rate higher than the NF Rate Cap defined in section IV.C of
the GRSPs or lower than 1.00 mill per kilowatt-hour.
Section III. Billing Factor
The billing energy for Nonfirm Energy purchased under this rate
schedule shall be the Measured Energy unless otherwise specified in the
Share-the-Savings rate contract.
Section IV. Application and Eligibility
A. General Requirements
In order to purchase Nonfirm Energy under the Share-the-Savings
Rate, the purchaser must:
1. Have executed a contract specifying application of the Share-
the-Savings Rate Schedule, and
2. Have a displaceable resource, displaceable purchase of
electricity, or be an end-user load with a displaceable alternate fuel
source. End-user loads with alternate fuel sources may not use the
Decremental Cost of a displaceable [[Page 21146]] purchase of
electricity to qualify for this rate.
B. BPA Service Priority
Offers of Nonfirm Energy under this rate schedule shall be made
pursuant to the terms and conditions set forth in the Share-the-Savings
rate contract. BPA will sell Nonfirm Energy under this rate schedule
consistent with regional and public preference.
Section V. Resource Cost Contribution
BPA has made the following determinations:
A. The SS-95 rate is not based on the cost of BPA resources.
B. The forecasted average cost of resources available to BPA under
average water conditions is 19.80 mills per kilowatt-hour.
C. The forecasted cost of resources to meet load growth is 60.64
mills per kilowatt-hour.
Schedule PS-95
Power Shortage Rate
Section I. Availability
This schedule is available inside the Pacific Northwest for the
purchase of Shortage Power to a utility when a shortage exists on its
system and the utility requests Shortage Power under this rate
schedule, or when Shortage Power is being delivered to a utility as the
result of statewide or regionwide curtailment. This schedule is also
available for sales under the Share-the-Shortage agreement, or a
similar substitute agreement.
This rate schedule is also available inside the Pacific Northwest
when BPA arranges for purchase energy at the request of a customer. BPA
is not obligated to make Shortage Power available or broker power under
this rate schedule unless specified by contract. Sales under this
schedule are made subject to BPA's General Rate Schedule Provisions.
Section II. Rates
A. Power Rate
The power rate is any offered rate not to exceed 100.00 mills per
kilowatt-hour. The offered rate may be specified as an energy charge
only or as demand and energy charges.
B. Brokering Rate
The brokering rate may be up to 1.00 mill per kilowatt-hour for
services provided when BPA arranges for energy purchases for a customer
from a seller other than BPA.
Section III. Billing Factors
The billing factors shall be:
A. Power Purchases
The factors to be used in determining the billings for power
purchases under this rate schedule are as follows:
1. Billing Demand
The billing demand shall be the Contract Demand as specified in the
contract initiating such arrangement or as mutually agreed to by the
parties. Otherwise the billing demand shall be the Measured Demand as
adjusted for power factor.
2. Billing Energy
The billing energy shall be the Contract Energy as specified in the
contract initiating such arrangement or as mutually agreed to by the
parties. Otherwise the billing energy shall be the Measured Energy.
B. Brokering Services
When BPA arranges for energy purchases at the request of a
customer, the purchaser shall be billed for such services based on the
total amount of kilowatt-hours purchased.
Section IV. Adjustments and Special Provisions
A. Power Factor Adjustment
The adjustment for power factor for BPA customers that are billed
for shortage power on metered amounts, when specified in this rate
schedule or in the contracts, shall be made in accordance with the
provisions of both this section and section III.C.1 of the GRSPs. The
adjustment shall be made if the average leading power factor or average
lagging power factor at which energy is supplied during the billing
month is less than 95 percent.
To make the power factor adjustment, BPA shall increase the billing
energy by 1 percentage point for each percentage point or major
fraction thereof (0.5 or greater) by which the average leading power
factor or average lagging power factor is below 95 percent. BPA may
elect to waive the adjustment for power factor in whole or in part.
B. Power Brokering
The charge for power brokering only applies to the service provided
by BPA of finding purchased power for a customer from a seller other
than BPA. BPA may agree to provide other services in addition to
finding purchased power, but these services shall be billed separately
at charges specified in the appropriate rate schedule(s) or
agreement(s). Such services may include, but are not limited to,
wheeling and load shaping.
C. Share-the-Shortage Transactions
In the event a Share-the-Shortage type agreement is executed, BPA
may make shortage power available to participants under such agreement.
Any transactions entered into by BPA pursuant to the Share-the-Shortage
agreement shall be subject to the terms and conditions specified in
that agreement. The PS-95 rate does not incorporate the agreement but
the agreement controls if there is any conflict between the PS-95 rate
and the agreement. The rate for transactions under the Share-the-
Shortage agreement is any rate within the limits specified by the power
rate but may not exceed the maximum rate specified in the agreement.
The rate for Share-the-Shortage transactions is independent of any rate
offered under this rate schedule for sales that do not fall under the
agreement. The PS-95 power rate shall not be available for transactions
with a party who triggers the Share-the-Shortage agreement if BPA
elects to meet its required service obligations under the agreement by
entering into an alternative agreement.
Section V. Resource Cost Contribution
BPA has made the following determinations:
A. The approximate cost contribution of different resource
categories to the PS-95 rate is based upon the BPA's highest cost
resource which currently is an FBS resource.
B. The forecasted average cost of resources available to BPA under
average water conditions is 19.80 mills per kilowatt-hour.
C. The forecasted cost of resources to meet load growth is 60.64
mills per kilowatt-hour.
Schedule RP-95
Reserve Power Rate
Section I. Availability
This schedule is available for the purchase of power:
A. In cases where a purchaser's power sales contract states that
the rate for Reserve Power shall be applied;
B. For which BPA determines no other rate schedule is applicable;
or
C. To serve a purchaser's firm power load in circumstances where
BPA does not have a power sales contract in force with such purchaser,
and BPA determines that this rate should be applied.
This rate schedule may be applied to power purchased by entities
outside the United States. This rate schedule supersedes Schedule RP-
93, which went into effect on October 1, 1993. Sales under this
schedule are made [[Page 21147]] subject to BPA's General Rate Schedule
Provisions (GRSPs).
Section II. Rate
A. Demand Charge
1. $3.640 per kilowatt of billing demand occurring during all Peak
Period hours during a billing month.
2. No demand charge during Offpeak Period hours.
B. Energy Charge
25.30 mills per kilowatt-hour of billing energy.
Section III. Billing Factors
The factors to be used in determining the billing for power
purchased under this rate schedule are as follows:
A. Billing Demand
If applicable, the billing demand shall be the Contract Demand as
specified in the power sales contract. Otherwise the billing demand
shall be the Measured Demand as adjusted for power factor.
B. Billing Energy
The billing energy shall be the Contract Demand multiplied by the
number of hours in the billing month, if use of the Contract Demand for
determining billing energy is specified in the power sales contract.
Otherwise the billing energy for such purchasers shall be the Measured
Energy.
Section IV. Power Factor Adjustment
The adjustment for power factor, when specified in this rate
schedule or in the power sales contract, shall be made in accordance
with the provisions of both this section and section III.C.1 of the
GRSPs. The adjustment shall be made if the average leading power factor
or average lagging power factor at which energy is supplied during the
billing month is less than 95 percent.
To make the power factor adjustment, BPA shall increase the billing
demand by 1 percentage point for each percentage point or major
fraction thereof (0.5 or greater) by which the average leading power
factor or average lagging power factor is below 95 percent. BPA may
elect to waive the adjustment for power factor in whole or in part.
Section V. Resource Cost Contribution
BPA has made the following determinations:
A. The RP-95 rate is not based on the cost of resources.
B. The forecasted average cost of resources available to BPA under
average water conditions is 19.80 mills per kilowatt-hour.
C. The forecasted cost of resources to meet load growth is 60.64
mills per kilowatt-hour.
D. General Rate Schedule Provisions (GRSPs)
Table of Contents
I. Adoption of Revised Rate Schedules and General Rate Schedule
Provisions
A. Approval of Rates
B. General Provisions
II. Types of BPA Service
A. Priority Firm Power
B. New Resource Firm Power
C. Industrial Firm Power
D. Special Industrial Power
E. Auxiliary Power
F. Shortage Power
G. Surplus Firm Power
H. Nonfirm Energy
I. Reserve Power
III. Billing Factors and Billing Adjustments
A. Billing Factors for Demand
B. Billing Factors for Energy
C. Billing Adjustments
D. Billing-Related Definitions
IV. Other Definitions
A. Computed Requirements Purchasers
B. Definitions Relating to Nonfirm Energy
C. NF Rate Cap
D. Determination of BPA's Average System Cost
V. Application of Rates Under Special Circumstances
A. Energy Supplied for Emergency Use
B. Construction, Test and Start-up, and Station Service
C. Application of Rates During Initial Operation Period-
Transitional Service
D. Changes in a DSI's BPA Operating Level
E. Restriction of Deliveries
VI. Billing Information
A. Determination of Estimated Billing Data
B. Load Shift and Outage Reports
C. Billing for New Large Single Loads
D. Determination of Measured Demand
E. Determination of Measured Energy
F. Billing Month
G. Payment of Bills
VII. Variable Industrial Rate Parameters and Adjustments
A. Monthly Average Aluminum Price Determination
B. Annual Adjustments to the Lower and Upper Pivot Aluminum
Prices
Section I. Adoption of Revised Rate Schedules and General Rate
Schedule Provisions
A. Approval of Rates
These 1995 rate schedules and General Rate Schedule Provisions
(GRSPs) shall become effective upon interim approval or upon final
confirmation and approval by the Federal Energy Regulatory Commission
(FERC). BPA will request FERC approval effective October 1, 1995. BPA
proposes that the following schedules, and the GRSPs associated with
these schedules, be effective for 1 year: PF-95, IP-95, VI-95, SI-95,
CE-95, NR-95, SS-95, NF-95, PS-95, and RP-95.
B. General Provisions
These 1995 rate schedules, and the GRSPs associated with these rate
schedules, supersede BPA's 1993 rate schedules (which became effective
October 1, 1993) to the extent stated in the Availability section of
each rate schedule. These schedules and GRSPs shall be applicable to
all BPA contracts, including contracts executed both prior to and
subsequent to enactment of the Northwest Power Act. All sales of power
made under these rate schedules are subject to the following acts as
amended: the Bonneville Project Act, the Regional Preference Act (Pub.
L. 88-552), the Federal Columbia River Transmission System Act, and the
Northwest Power Act.
Section II. Types of BPA Service
A. Priority Firm Power
Priority Firm Power is electric power (capacity, energy, or
capacity and energy) that BPA will make continuously available for
resale to ultimate consumers for direct consumption, construction, test
and startup, and station service by public bodies, cooperatives, and
Federal agencies. (Construction, test and start-up, and station service
are defined in section V.B of these GRSPs.)
Utilities participating in the exchange under section 5(c) of the
Northwest Power Act may purchase Priority Firm Power pursuant to their
Residential Purchase and Sale Agreements.
In addition, BPA may make Priority Firm Power available to those
parties participating in exchange agreements specifying use of the
Priority Firm rate for determining the amount or value of power to be
exchanged.
Power purchased under the rate schedule is to be used to meet the
purchaser's actual firm load within the Pacific Northwest. Such power
may be restricted in accordance with the Restriction of Deliveries
section of these GRSPs (section V.E). However, BPA shall not restrict
Priority Firm Power until Industrial Firm Power has been restricted in
accordance with the provisions of section II.C of these GRSPs.
Priority Firm Power is not available to serve New Large Single
Loads.
B. New Resource Firm Power
New Resource Firm Power is electric power (capacity, energy, or
capacity and energy) that BPA will make continuously available:
1. For any New Large Single Load,
2. For firm power purchased by investor-owned utilities (IOUs)
pursuant to power sales contracts with BPA, and [[Page 21148]]
3. For construction, test and start-up, and station service for
facilities owned or operated by IOUs.
New Resource Firm Power is to be used to meet the purchaser's
actual firm load within the Pacific Northwest. Such power may be
restricted in accordance with the Restriction of Deliveries section of
these GRSPs (section V.E). However, BPA shall not restrict New Resource
Firm Power until Industrial Firm Power has been restricted in
accordance with the provisions of section II.C of these GRSPs.
C. Industrial Firm Power
Industrial Firm Power is electric power that BPA will make
continuously available to a direct service industrial (DSI) purchaser
pursuant to the DSI's power sales contract and subject to:
1. The restriction applicable to deliveries of all firm power
pursuant to the Uncontrollable Forces and Continuity of Service
provisions of the General Contract Provisions of the power sales
contract, and
2. The restrictions given in the Restriction of Deliveries section
of the power sales contract.
D. Special Industrial Power
Special Industrial Power is electric power which BPA will make
continuously available to any DSI that qualifies for the Special
Industrial Power rate pursuant to section 7(d)(2) of the Northwest
Power Act. This power is similar in nature to Industrial Firm Power,
but is subject to greater restriction by BPA. Special Industrial Power
is made available to the qualifying DSI upon adoption of, and subject
to, an amendment modifying its power sales contract.
E. Auxiliary Power
Auxiliary Power is that power which a DSI requests and which BPA
agrees to make available to serve that portion of the DSI's load which
is in excess of the DSI's Operating Demand for Industrial Firm Power or
Special Industrial Power.
F. Shortage Power
Shortage Power is energy or energy with capacity, provided by BPA
to a purchaser to serve such purchaser's regional load under
circumstances where the purchaser is in danger of curtailing firm load
even though the purchaser is operating all available resources and
exercising all contractual rights to firm power to the maximum level
feasible. In the event of a state ordered or regionwide load
curtailment, a power deficiency is deemed to exist for those purchasers
whose power supply condition is in part causally related to the
state(s) initiated load curtailment.
G. Surplus Firm Power
Surplus Firm Power is firm energy, firm power (firm energy with
capacity), and firm capacity (capacity with energy return requirements)
in excess of the amount required to meet BPA's existing contractual
obligations to provide firm service. Surplus Firm Power may be used
either for resale or direct consumption by purchasers both inside and
outside the United States. Such power, however, may be restricted
pursuant to the Restriction of Deliveries section of these GRSPs
(section V.E).
H. Nonfirm Energy
Nonfirm Energy is supplied or made available by BPA to a purchaser
under an arrangement that does not have the guaranteed continuous
availability feature of firm power. Nonfirm energy is mostly sold under
the Nonfirm Energy rate schedule, NF-95. Nonfirm energy also may be
supplied under the Share-the-Savings rate schedule, SS-95, which is
available as an experimental rate for contract purchase.
In addition, BPA also can make nonfirm energy available under the
Nonfirm Energy rate schedule to the Western Systems Power Pool (WSPP)
subject to terms and conditions agreed upon by the members
participating in the WSPP and in accordance with BPA policy for such
arrangements.
However, Nonfirm Energy that has been purchased under a guarantee
provision in the Nonfirm Energy rate schedule shall be provided to the
purchaser in accordance with the provisions of that schedule and the
power sales contract if applicable. BPA may make Nonfirm Energy
available to purchasers both inside and outside the United States.
I. Reserve Power
Reserve Power is firm power sold to a purchaser:
1. In cases where the purchaser's power sales contract states that
the rate for Reserve Power shall be applied;
2. To provide service when no other type of power is deemed
applicable; or
3. To serve the purchaser's firm power loads under circumstances
where BPA does not have a power sales contract in force with the
purchaser.
Sales of Reserve Power are subject to the Restriction of Deliveries
section of these GRSPs (section V.E).
Section III. Billing Factors and Billing Adjustments
A. Billing Factors for Demand
1. Measured Demand
The purchaser's Measured Demand shall be determined in the manner
described in this section. Measured Demand shall be that portion of the
metered or scheduled demand that is purchased from BPA under the
applicable rate schedule. For those contracts to which BPA is a party
and that provide for delivery of more than one class of electric power
to the purchaser at any point of delivery, the portion of each 60-
minute clock-hour integrated demand assigned to any class of power
shall be determined pursuant to the power sales contract. The portion
of the total Measured Demand so assigned shall constitute the Measured
Demand for each such class of power.
The Measured Demand shall be determined from the metered demand or
the scheduled demand, as hereinafter defined. The Measured Demand shall
be determined on either a coincidental or a noncoincidental basis, as
provided in the purchaser's power sales contract.
a. Metered Demand
The metered demand in kilowatts shall be the largest of the 60-
minute clock-hour integrated demands, adjusted as specified in the
power sales contract, at which electric energy is delivered to a
purchaser:
(1) At each point of delivery for which the metered demand is the
basis for determination of the Measured Demand,
(2) During each time period specified in the applicable rate
schedule, and
(3) During any billing period.
Such largest integrated demand shall be determined from
measurements made either in the manner specified in the power sales
contract or as provided in section VI.A herein. In determining the
metered demand, BPA shall exclude any abnormal integrated demands due
to or resulting from:
(1) Emergencies or breakdowns on, or maintenance of, the Federal
system facilities; and
(2) Emergencies on the purchaser's facilities, provided that such
facilities have been adequately maintained and prudently operated, as
determined by BPA.
b. Scheduled Demand
The scheduled demand in kilowatts shall be the largest of the
hourly demands at which electric energy is scheduled for delivery to a
purchaser:
(1) To each system for which scheduled demand is the basis for
determination of the Measured Demand; [[Page 21149]]
(2) During each time period specified in the applicable rate
schedule; and
(3) During any billing period. Scheduled amounts are deemed
delivered for the purpose of determining billing demand.
2. Ratchet Demand
The Ratchet Demand in kilowatts shall be the maximum demand
established during a specified period of time either during or prior to
the current billing period. The demand on which the ratchet is based is
specified in the relevant rate schedule or in these GRSPs. For
utilities purchasing under the PF or NR rate schedules, the Ratchet
Demand is based on the highest demand during prior billing months. When
the Ratchet Demand is used as a billing factor, BPA shall have
specified in the appropriate schedules or GRSPs:
a. The period of time over which the ratchet shall be calculated;
b. The type of demand to be used in the calculation; and
c. The percentage (if any) of that demand which will be used to
calculate the Ratchet Demand.
3. Contract Demand
The Contract Demand shall be the maximum number of kilowatts that
the purchaser agrees to purchase and BPA agrees to make available,
subject to any limitations included in the power sales contract. BPA
may agree to make deliveries at a rate in excess of the Contract Demand
at the request of the purchaser, but shall not be obligated to continue
such excess deliveries. Any contractual or other reference to Contract
Demand as expressed in kilowatt-hours shall be deemed, for the purpose
of these GRSPs, to refer to the term ``Contract Energy.''
4. Computed Peak Requirement
For purchasers designated to purchase on the basis of computed
requirements, the Computed Peak Requirement shall be determined as
specified in the purchaser's power sales contract. That specification
is provided in:
a. Sections 16, 17(c), and 17(f), as adjusted by other sections of
the contract, for actual computed requirements purchasers;
b. Sections 16, 17(a), and 17(f), as adjusted by other sections of
the contract, for planned computed requirements purchasers; and
c. Sections 16 and 17(b), as adjusted by other sections of the
contract, for contracted computed requirements purchasers.
5. Computed Average Energy Requirement
For computed requirements purchasers, the Computed Average Energy
Requirement shall be determined as specified in the purchaser's power
sales contract. That specification is provided in:
a. Sections 16, 17(c), and 17(f), as adjusted by other sections of
the contract, for actual computed requirements purchasers;
b. Sections 16, 17(a), and 17(f), as adjusted by other sections of
the contract, for planned computed requirements purchasers; and
c. Sections 16 and 17(b), as adjusted by other sections of the
contract, for contracted computed requirements purchasers.
6. Operating Demand
The Operating Demand is that demand which is established by each
DSI in accordance with section 5(b) of the DSI's power sales contract.
Unless the DSI has requested, and BPA has granted, an Auxiliary Demand,
the Operating Demand establishes a limit with respect to:
a. The demand which the purchaser may impose on BPA; and
b. The total amount of energy during a billing month which the DSI
is entitled to purchase from BPA.
7. Curtailed Demand
A Curtailed Demand is the number of kilowatts of industrial power
(Industrial Firm Power or Special Industrial Power) during the billing
month which results from the DSI's request for such power in amounts
less than the Operating Demand therefor. Each purchaser of industrial
power may curtail its demand according to the terms of its power sales
contract (which permits up to three levels of Curtailed Demand each
month).
8. Restricted Demand
Restricted Demand is the number of kilowatts of industrial power
(either Industrial Firm Power or Special Industrial Power) that results
when BPA has restricted delivery of such power for one clock-hour or
more. BPA shall make such restrictions according to the terms of the
DSI's power sales contract. In a given billing month, there are as many
possible levels of Restricted Demand for a DSI as there are number of
restrictions.
9. Auxiliary Demand
Auxiliary Demand is the number of kilowatts of Auxiliary Power that
a DSI requests and that BPA agrees to make available to serve a portion
of the DSI's load during the period specified in the DSI's request. The
DSI may request up to three levels of Auxiliary Demand during a billing
month.
If BPA agrees to a request for Auxiliary Power but later becomes
unable to supply such demand, the Restricted Demand for Auxiliary Power
is deemed to be the Auxiliary Demand for such period of restriction.
Auxiliary Power may be curtailed by the DSI according to the provisions
of section 9(a) of the DSI's power sales contract.
BPA shall make Auxiliary Power available to Industrial Firm Power
purchasers under the Industrial Firm Power rate schedule at the
Standard Industrial rate. Auxiliary Power sales to DSIs electing to
purchase under the Variable Industrial Power rate schedule (VI-95)
shall be made at the rate determined pursuant to section III of the VI-
95 rate schedule. Auxiliary Power sales to DSIs purchasing under the
Special Industrial rate will be made only at the Standard Special
Industrial Power rate.
10. BPA Operating Level
The BPA Operating Level is, for the purpose of these rate schedules
and GRSPs, an hourly amount of industrial power (Industrial Firm Power
or Special Industrial Power) for a DSI that is equal to the lowest of
the following demands during that hour:
a. Operating Demand plus Auxiliary Demand, if any;
b. Curtailed Demand; or
c. Restricted Demand.
The weighted average BPA Operating Level for each DSI can be
determined by summing the hourly BPA Operating Levels and dividing by
the number of hours in the billing month.
Each DSI must request service from BPA for each billing month in
accordance with the terms of the power sales contract. The requested
level of service will be the BPA Operating Level, provided BPA does not
need to restrict the DSI and provided BPA agrees to supply any
requested Auxiliary Demand. Each requested level of service may include
a designation for both the Peak Period and the Offpeak Period. A DSI
may request and BPA may agree to a level of service for the Offpeak
Periods other than that in the Peak Period. If a DSI does not
separately designate a requested level of service for the Peak and
Offpeak Periods, the BPA Operating Level is the basis for determining
if a DSI has incurred an unauthorized increase.
Any DSI whose Measured Demand, before adjustment for power factor,
during any 1 hour exceeds the BPA Operating Level for that hour shall
be subject to unauthorized increase charges [[Page 21150]] for each
kilowatt-hour of unauthorized increase associated with each overrun.
Only the BPA Operating Level applicable during the Peak Period will
be used in determining the Billing Demand for power purchased under the
Industrial Firm Power rate schedule, the Variable Industrial Power rate
schedule, and the Standard rate under the Special Industrial rate
schedule. During the Peak Period the BPA Operating Level may be no
greater than the Operating Demand for the billing month unless the
customer has requested, and BPA has agreed to supply, the Auxiliary
Demand.
B. Billing Factors for Energy
1. Measured Energy
Measured Energy shall be that portion of the metered or scheduled
energy that is purchased from BPA under the applicable rate schedule.
For those contracts to which BPA is a party and that provide for
delivery of more than one class of electric power to the purchaser at
any point of delivery, the portion of each 60-minute clock-hour
integrated demand assigned to any class of power shall be determined
pursuant to the power sales contract. The sum of the portions of the
demands so assigned shall constitute the Measured Energy for each such
class of power.
The Measured Energy shall be determined from the metered energy or
the scheduled energy, as hereinafter defined.
a. Metered Energy
The metered energy for a purchaser shall be the number of kilowatt-
hours that are recorded on the appropriate metering equipment, adjusted
as specified in the power sales contract, and delivered to a purchaser:
(1) At all points of delivery for which metered energy is the basis
for determination of the Measured Energy, and
(2) During any billing period.
The metered energy shall be determined from measurements made
either in the manner specified in the power sales contract or as
provided in section VI.A herein.
b. Scheduled Energy
The scheduled energy in kilowatt-hours shall be the sum of the
hourly demands at which electric energy is scheduled for delivery to a
purchaser:
(1) For each system for which scheduled energy is the basis for
determination of the Measured Energy, and
(2) During any billing period.
Scheduled amounts are deemed delivered for the purpose of
determining billing energy.
2. Computed Energy Maximum
The Computed Energy Maximum equals the product of the number of
hours in the billing month and the Computed Average Energy Requirement.
3. Contract Energy
The Contract Energy shall be the maximum number of kilowatt-hours
that the purchaser agrees to purchase and BPA agrees to make available,
subject to any limitations included in the power sales contract.
C. Billing Adjustments
1. Power Factor Adjustment
The formula for determining average power factor is as follows:
[GRAPHIC][TIFF OMITTED]TN01MY95.071
The data used in the above formula shall be obtained from meters
that are ratcheted to prevent reverse registration. These data then
shall be adjusted for losses, if applicable, before determination of
the average power factor.
When deliveries to a purchaser at any point of delivery either:
a. Include more than one class of power; or
b. Are provided under more than one rate schedule and it is
impracticable to meter the kilowatt-hours and reactive
kilovoltamperehours for each class or rate schedule separately, the
average power factor of the total deliveries for the month will be
used, where applicable, as the power factor for all power delivered to
such point of delivery.
To maintain acceptable operating conditions on the Federal system,
BPA may, unless specifically otherwise agreed, restrict deliveries of
power to a purchaser with a low power factor. Such restriction may be
made to a point of delivery or to a purchaser's system at any time that
the average leading power factor or average lagging power factor for
all classes of power delivered to such point or to such system is below
75 percent.
2. Outage Credit
To the extent that BPA is unable to provide full service to a
purchaser during the billing month as a result of interruptions in
service due to reasons cited in the General Contract Provisions, BPA
shall adjust the charges for those hours for billing demand for such
purchaser to reflect BPA's inability to provide full service, provided
such adjustment is mandated by the purchaser's power sales contract.
The adjustment is provided on a point of delivery basis. To compute the
adjustment for noncoincidentally billed systems, BPA shall determine
the monthly demand charge(s) for the point(s) of delivery where the
outage(s) occurred, multiply by the number of hours of outage, and
divide by the total number of hours in the billing month. For
coincidentally billed points of delivery, the adjustment shall apply
only to those points of delivery at which BPA was unable to provide
full service. For partial outages (such as an outage on one feeder in a
substation with several feeders), BPA shall determine an equivalent
interruption in order to arrive at the number of hours to be used in
the calculation of the credit.
3. Low Density Discount (LDD)
a. Basic LDD Principles
A predetermined discount shall be applied each billing month to the
charges for all power purchased under the Priority Firm Power rate
schedule by eligible purchasers as defined in section b, below. The
discount shall be calculated on an annual basis and shall become
effective with the first billing period in the calendar year.
Retroactive billing for the LDD may be required if the data are not
available by the January billing date. The level of the discount shall
be determined from the following ratios:
(1) The purchaser's total electric energy requirements during the
previous calendar year (the purchaser's firm sales, nonfirm sales to
firm retail loads, sales for resale, and associated losses, but
excluding nonfirm sales to nonfirm retail loads, such as boiler loads
served under BPA's alternate fuel policy) divided by the value of the
purchaser's depreciated electric plant (excluding generation plant) at
the end of such year, and [[Page 21151]]
(2) The average number of consumers (annual and seasonal consumers
with residential, industrial, commercial, and irrigation accounts, but
excluding separately billed services for water heating, electric space
heating, and security lights) during the previous calendar year divided
by the number of pole miles of distribution line at the end of such
year. Distribution lines are defined as those that deliver electric
energy from a substation or metering point, at a voltage of 34.5 kV or
less, to the point of attachment to the consumer's wiring and include
primary, secondary, and service facilities.
These calculations shall be based on data provided in the
purchaser's annual financial and operating report. In calculating these
ratios, BPA shall use data pertaining to the purchaser's entire
electric utility system within the region. Results of the calculations
shall not be rounded.
Customers who have not provided BPA with all four requisite pieces
of annual data (see a.(1) and a.(2) above) by June 30 of each year
shall be declared ineligible for the LDD effective with the June
billing period for that year. BPA shall extend a customer's eligibility
from the previous year through the June billing period of the following
year and shall make any necessary retroactive adjustments once the new
data have been processed. If no data have been received by December 31
for the previous calendar year, BPA shall assume that the utility did
not qualify for an LDD for that year. LDDs issued from January 1 to
June 30 shall be assumed to have been in error, and the utility shall
be billed for any such discounts issued.
Revisions to the data used to calculate the amount of the LDD may
be made by the purchaser for a period of up to 2 years from the first
day to which the data apply. However, such revisions shall not apply to
periods when the customer was ineligible for a discount due to late
data submission.
b. Eligibility Criteria
To qualify for a discount, the purchaser must meet all six of the
following eligibility criteria:
(1) The purchaser must serve as an electric utility offering power
for resale;
(2) The purchaser must agree to pass the benefits of the discount
through to the purchaser's consumers within the region served by BPA;
(3) The purchaser's average retail rate for the reporting year must
exceed the average Priority Firm Power rate in effect for the
qualifying period by 10 percent. For Calendar Year (CY) 1995, the
average Priority Firm Power rate shall be the average of the PF-93
Preference rate for 9 months and the PF-95 Preference rate for 3
months;
(4) The purchaser's kilowatt-hour-to-investment ratio (Ratio
3.a.(1)) must be less than 100;
(5) The purchaser's consumers-per-mile ratio (Ratio 3.a.(2)) must
be less than 12; and
(6) The purchaser must qualify for a discount based on the criteria
in section c, below.
c. Discounts
The purchaser shall be awarded the greatest discount for which that
purchaser qualifies. The discounts and the qualifying criteria for
those discounts are listed below.
(1) Three percent, for any purchaser for whom:
(a) The kilowatt-hour-to-investment ratio is equal to or greater
than 25 but less than 35; or
(b) The consumers-per-mile ratio is equal to or greater than 5 but
less than 7.
(2) Five percent, for any purchaser for whom:
(a) The kilowatt-hour-to-investment ratio is equal to or greater
than 15 but less than 25; or
(b) The consumers-per-mile ratio is equal to or greater than 3 but
less than 5.
(3) Seven percent, for any purchaser for whom:
(a) The kilowatt-hour-to-investment ratio is less than 15; or
(b) The consumers-per-mile ratio is less than 3.
4. Irrigation Discount
a. Basic Irrigation Discount Principles
A discount of 4.90 mills per kilowatt-hour shall be applied to the
charges for qualifying irrigation energy purchased under the Priority
Firm Power and New Resource Firm Power rate schedules, during the
billing months of April through October. This discount shall be applied
subsequent to calculation of the LDD, if applicable. Any energy on
which the irrigation discount is claimed shall be metered separately by
the Purchaser, and used exclusively for agricultural irrigation or
drainage pumping.
b. Qualifying Energy Purchases
The qualifying irrigation energy shall be determined as follows:
(1) All irrigation energy must be used exclusively for the purpose
of irrigation and drainage pumping on agricultural land and be measured
at the end-use irrigation customer's meter. The discount shall apply to
the measured energy sales at the end-use.
(2) Energy subject to the discount must be purchased during the
billing months of April through October.
(3) Purchasers of exchange energy under the Residential Purchase
and Sale Agreement (RPSA) are eligible for the irrigation discount for
the portion of their irrigation sales qualifying for the exchange under
the RPSA contracts. However, if the purchaser also purchases energy
from BPA for general requirements, and receives an irrigation discount
on those purchases, a second irrigation discount will not be applied to
that energy through the RPSA exchange. Therefore, the irrigation
discount will not be applied to any portion of the purchaser's
irrigation sales qualifying for the RPSA exchange that receives the
discount as a general requirements purchase.
(4) General requirements customers are eligible for an irrigation
discount for a portion of their irrigation sales equal to the share of
their total sales served by BPA firm purchases (i.e., total irrigation
and drainage pumping sales multiplied by BPA billing energy for
Priority Firm or New Resources firm purchases divided by the total firm
utility system requirements for the billing month).
c. Initial Reporting Requirements
Requests for the Irrigation Discount must include the following
information:
(1) To receive an irrigation discount, a purchaser must file a
request for the discount with its local BPA regional office by April 1
each year.
(2) In the request, the purchaser must certify that the irrigation
energy is sold exclusively for use in irrigation and drainage pumping
on agricultural land and that the discount is passed, in its entirety,
to the irrigation consumer, regardless of whether the utility has
raised its rates. BPA retains the right to verify, in a manner
satisfactory to the Administrator, that the discounted energy is used
for the sole benefit of the purchaser's irrigation load.
d. Annual Reporting Requirements
Purchasers shall submit an annual irrigation report to their local
BPA regional office in order to receive the irrigation discount.
Purchasers are required to report information related to monthly
irrigation energy sales. If a utility does not read its irrigation
meters monthly, the utility must estimate its monthly irrigation sales.
These estimates shall be reviewed by BPA regional offices. Purchasers
must read their meters within 3 working days of the beginning and
ending of the irrigation discount period (April-October). In order to
qualify for the discount, the purchaser must submit all
[[Page 21152]] data to BPA by December 31 of the calendar year in which
the sales occurred. Irrigation reports to BPA shall include the
following monthly information for the reporting period:
(1) Utility name and period for which the report is being made;
(2) Total irrigation sales and total qualifying irrigation energy
sales (in kilowatt-hours) by month;
(3) Total qualifying irrigation sales (in kilowatt-hours) by month
under 400 horsepower, for exchanging utilities;
(4) Total utility firm system requirements for other than full
requirement customers by month (in kilowatt-hours);
(5) Total energy purchased from BPA under the Priority Firm or New
Resource rate by month in kilowatt-hours; and
(6) The Purchaser shall list each irrigation and drainage account
number in its annual report and whether each irrigation consumer is
billed monthly, bimonthly, or seasonally. If the Purchaser is an
exchanging utility, the Purchaser shall also identify the size (in
horsepower) of the connected load for each active account. A utility
may submit monthly reports, if it chooses. In that case, the active
list of accounts should be included in the last monthly report
submitted.
5. Coincidental Billing
Purchasers of Priority Firm Power and New Resource Firm Power shall
be billed on a noncoincidental demand basis for power purchased at each
point of delivery under the applicable rate schedule(s) unless the
power sales contract specifically provides for coincidental demand
billing among particular points of delivery. For the purpose of these
rate schedules and GRSPs, the purchaser's noncoincidental demand is the
sum of the highest hourly peak demands during the billing month for
each of the purchaser's points of delivery. The purchaser's
coincidental demand is the highest demand for the billing month
calculated by summing, for each hour of every day, the purchaser's
demands for power purchased under the applicable rate schedule at all
coincidentally billed points of delivery. See Special Provisions
Exhibits of the Power Sales Contract, GCP E 17.
6. Conservation Surcharge
The Conservation Surcharge shall be applied monthly and shall equal
10 percent of the customer's total monthly charge for all power
purchased under each rate schedule subject to the surcharge. The PF and
NR rate schedules are subject to the Conservation Surcharge. If only a
portion of the customer's service area is subject to the surcharge,
then the amount of the surcharge shall equal 10 percent of the total
charge for all power purchases multiplied by: (a) The portion of the
customer's total retail load that is subject to the surcharge, divided
by (b) the customer's total retail load.
D. Billing-Related Definitions
1. Peak Period
The Peak Period includes the hours from 7 a.m. through 10 p.m. on
any day Monday through Saturday inclusive. There are no exceptions to
this definition; that is, it does not matter whether the day is a
normal working day or a holiday. Any charges based on Peak Period hours
shall be computed starting with the 8 a.m. meter reading since this
reading applies to the 7 o'clock hour (7 a.m. to 8 a.m.). The 10 p.m.
meter reading (for the 9 p.m. to 10 p.m. period) is the last meter
reading of the day applicable to the Peak Period.
2. Offpeak Period
The Offpeak Period includes all hours which do not occur during the
Peak Period. Thus, the Offpeak Period consists of the hours from 10
p.m. to 7 a.m., Monday through Saturday and all hours on Sunday.
Section IV. Other Definitions
A. Computed Requirements Purchasers
1. Designation as a Computed Requirements Purchaser
A purchaser shall be designated as a computed requirements
purchaser if it is so designated pursuant to the provisions of its
power sales contract.
When a purchaser operates two or more separate systems, only those
systems designated by BPA will be covered by this section.
2. Purpose of the Computed Requirements Designation
Use of the computed requirements designation is intended to assure
that each purchaser who purchases power from BPA to supplement its own
firm resources will purchase amounts of firm capacity and firm energy
substantially equal to that which the purchaser would otherwise have to
provide on the basis of normal and prudent operations.
The amount of capacity and energy required for normal and prudent
operations shall be determined pursuant to the purchaser's power sales
contract.
B. Definitions Relating to Nonfirm Energy Decremental Cost
Unless otherwise specified in a contractual arrangement,
decremental cost as applied to Nonfirm Energy transactions shall be
defined as:
1. All identifiable costs (expressed in mills per kilowatt-hour)
associated with the use of a displaceable thermal resource or end-user
load with alternate fuel source to serve a purchaser's load that the
purchaser is able to avoid by purchasing power from BPA, rather than
generating the power itself or using an alternate fuel source; or
2. All identifiable costs (expressed in mills per kilowatt-hour) to
serve the load of a displaceable purchase of energy that the purchaser
is able to avoid by choosing not to make the alternate energy purchase.
All identifiable costs as used in the above definition may be
reduced to reflect costs of purchasing BPA energy such as transmission
costs, losses, or loopflow constraints that are agreed to by BPA and
the purchaser.
C. NF Rate Cap
1. Application of the NF Rate Cap
The NF Rate Cap defines the maximum nonfirm energy price for
general application. At no time shall the total price for nonfirm
energy, including any applicable service charges or rate adjustment,
sold under any applicable rate schedule exceed the NF Rate Cap. The
level of the NF Rate Cap is based on a formula tied to BPA's system
cost and California fuel costs. The NF Rate Cap applies to all sales of
nonfirm energy under any applicable rate schedule for a 12-year period
beginning October 1, 1987.
2. Monthly Notification of the NF Rate Cap
Prior to the beginning of a calendar month BPA shall perform the
calculations contained in section IV.C.3 of these GRSPs to determine
the effective NF Rate Cap for that calendar month. BPA is obligated to
provide advance notification of the NF Rate Cap level to purchasers of
nonfirm energy. BPA may waive this requirement only if BPA does not
intend to offer Nonfirm Energy at prices above BPA's Average System
Cost (BASC) at any time during a month. The notification will be given
at least 10 calendar days prior to the first day of any calendar month
in which the NF Rate Cap applies. BPA shall also maintain, on file for
public review, a record of the NF Rate Cap by month throughout the
period the cap is in effect.
3. NF Rate Cap Formula
The NF Rate Cap shall be equal to the greater of the following:
a. BASC; or [[Page 21153]]
b. BASC + .30(DEC-BASC)
Where:
BASC=BPA's average system cost, determined by dividing BPA's total
system costs by BPA's total system sales. For this rate period BASC has
been determined to be 29.41 mills per kilowatt-hour.
DEC=The Decremental Fuel Cost as determined in accordance with section
IV.C.5 of these GRSPs.
4. Determination of BASC
For purposes of determining BASC, the following definition shall
apply:
a. BPA's total system costs shall be the sum of all BPA's costs
forecasted in each general rate case for the applicable rate period,
including total transmission costs, Federal base system costs, new
resource costs, exchange resource costs, and other costs not
specifically allocated to a rate pool, such as section 7(g) costs.
b. BPA's total annual system sales shall be the sum of all BPA's
system firm and nonfirm sales forecasted each general rate case for the
applicable test period. BASC shall be redetermined in each subsequent
general rate case according to the above formula and will be in effect
for the entire rate period over which the rates are in effect.
5. Determination of Decremental Fuel Cost
The Decremental Fuel Cost shall be determined monthly by BPA. For
purposes of calculating the NF Rate Cap, a weighted average of gas and
petroleum prices for California will be used for approximating
decremental fuel costs. The monthly decremental fuel cost shall be:
a. the sum of:
(1) The average California price for gas determined by multiplying
the monthly gas use (WGU) developed pursuant to section IV.C.8.a times
the monthly California gas price (MGP) determined pursuant to section
IV.C.6 rounded to the nearest tenth of a mill; and
(2) The average California price for petroleum determined by
multiplying the monthly petroleum use (WOU) developed pursuant to
section IV.C.8.b times the monthly California petroleum price (MOP)
determined pursuant to section IV.C.7 rounded to the nearest tenth of a
mill.
b. Divided by the sum of the WGU and WOU developed in sections
IV.C.8.a and b, respectively, rounded to the nearest tenth of a mill.
6. California Gas Price
The MGP for purposes of calculating the decremental cost component
of the rate cap shall be based on the following formula:
[GRAPHIC][TIFF OMITTED]TN01MY95.077
Where:
AGP=the average gas price for California electric utility plants
expressed in cents per million Btu as reported in the most recent
monthly issue of Electric Power Monthly (EPM) published by the Energy
Information Administration (EIA), U.S. Department of Energy. Prices
shall be rounded to the nearest one-tenth of a cent.
HGP=the historical relationship between gas prices in the effective
month of the NF Rate Cap (month t) and the month in which the gas
prices are reported in EPM (month r) using the following procedures:
a. Summing all California gas prices, expressed in the nearest one-
tenth of a cent per million Btu, reported in EPM for month t for the
years beginning with calendar year 1982 up to and including the prior
calendar year. The sum of the historical monthly California gas prices
shall be divided by the number of years for which MGPs were reported
and rounded to the nearest one-tenth of a cent;
b. Summing all California gas prices, expressed in the nearest one-
tenth of a cent per million Btu, reported in EPM for month r for the
years beginning with calendar year 1982 up to and including the prior
calendar year. The sum of the historical monthly California gas prices
shall be divided by the number of years for which MGPs were reported
and rounded to the nearest one-tenth of a cent; and
c. Dividing the average monthly California gas price in a. above,
by the average monthly California gas price in b. above, and rounding
to the nearest one-tenth, or three significant places.
10=the factor for converting gas prices stated in cents per million Btu
to mills per kWh. The factor assumes a heat rate of 10,000 Btu per
kilowatt-hour.
7. California Petroleum Price
The MOP for purposes of calculating the decremental cost component
of the rate cap shall based on the following formula:
[GRAPHIC][TIFF OMITTED]TN01MY95.078
Where:
AOP=the last available average oil price for California electric
utility plants expressed in cents per million Btu reported in EPM
published by the EIA, U.S. Department of Energy. Prices shall be
rounded to the nearest one-tenth of a cent.
HOP=the historical relationship between petroleum prices in the
effective month of the NF Rate Cap (month t) and the last month in
which the petroleum prices are reported in EPM (month r) using the
following procedures:
a. Summing all California petroleum prices, expressed in the
nearest one-tenth of a cent per million Btu, reported in EPM for month
t for the years beginning with calendar year 1982 up to and including
the prior calendar year. The sum of the historical monthly California
petroleum prices shall be divided by the number of years for which
monthly petroleum prices were reported and rounded to the nearest one-
tenth of a cent;
b. Summing all California petroleum prices, expressed in the
nearest one-tenth of a cent per million Btu, reported in EPM for month
r for the years beginning with calendar year 1982 up to and including
the prior calendar year. The sum of the historical monthly California
petroleum prices shall be divided by the number of years for which
monthly petroleum prices were reported and rounded to the nearest one-
tenth of a cent; and
c. Dividing the average monthly California petroleum price in a.
above, by the average monthly California petroleum price in b. above,
and rounding to the nearest one-tenth of a percent, or three
significant places.
10=the factor for converting petroleum prices stated in cents per
million Btu to mills per kWh. The factor assumes a heat rate of 10,000
Btu per kilowatt-hour.
8. Weighting Factors
For purposes of determining California fuel prices for the month,
gas and petroleum prices will be weighted based on California's
historical use of these two alternative fuels.
a. Historical Gas Use in California. The following formula shall be
used to determine the weighting factor for gas prices (WGU):
WGU=CGU*HGU
Where:
CGU=the monthly net gas-fired generation, expressed in gigawatthours,
for California in the most recent monthly issue of EPM published by the
EIA, U.S. Department of Energy.
HGU=the historical relationship between gas consumptions in the
[[Page 21154]] effective month of the NF Rate Cap (month t) and the
month for which gas consumption is reported in EPM (month r) using the
following procedures:
(1) Summing the reported net-gas fired generation for California,
expressed in gigawatthours, from EPM for month t for the years
beginning with calendar year 1982 up to and including the prior
calendar year. The sum of California's historical monthly consumption
shall be divided by the number of years for which gas consumption was
reported and rounded to the nearest gigawatthour;
(2) Summing the reported net gas-fired generation for California,
expressed in gigawatthours, from EPM for month r for the years
beginning with calendar year 1982 up to and including the prior
calendar year. The sum of California's historical monthly consumption
shall be divided by the number of years for which gas consumption was
reported and rounded to the nearest gigawatthour; and
(3) Dividing the average consumption of gas in California for the
month t as determined in (1) above by the average consumption of gas
for the month r as determined in (2) above and rounding to the nearest
one-tenth, or three significant places.
b. Historical Petroleum Use in California. The following formula
shall be used to determine the weighting factor for petroleum prices
(WOU):
WOU=COU*HOU
Where:
COU=the monthly net petroleum-fired generation, expressed in
gigawatthours, in California in the most recent monthly issue of EPM
published by the EIA, U.S. Department of Energy.
HOU=the historical relationship between petroleum consumptions in the
effective month of the NF Rate Cap (month t) and the month for which
petroleum consumption is reported in EPM (month r) using the following
procedures:
(1) Summing the reported net-petroleum generation for California,
expressed in gigawatthours, from EPM for month t for the years
beginning with calendar year 1982 up to and including the prior
calendar year. The sum of California's historical monthly consumption
shall be divided by the number of years for which petroleum consumption
was reported and rounded to the nearest gigawatthour;
(2) Summing the reported net-petroleum generation for California,
expressed in gigawatthours, from EPM for month r for the years
beginning with calendar year 1982 up to and including the prior
calendar year. The sum of California's historical monthly consumption
shall be divided by the number of years for which petroleum consumption
was reported and rounded to the nearest gigawatthour; and
(3) Dividing the average consumption of petroleum in California for
the month t as determined in (1) above by the average consumption of
petroleum for the month r or as determined in (2) above and rounding to
the nearest one-tenth, or three significant places.
D. Determination of BPA's Average System Cost
For purposes of determining BASC, the following definitions shall
apply:
1. BPA's total system costs shall be the sum of all BPA's costs
forecasted in each general rate case for the applicable rate period,
including total transmission costs, Federal base system costs, new
resource costs, exchange resource costs, and other costs not
specifically allocated to a rate pool, such as section 7(g) costs.
2. BPA's total annual system sales shall be the sum of all BPA's
system firm and nonfirm sales forecasted in each general rate case for
the applicable test period.
BASC shall be redetermined in each subsequent general rate case
according to the above formula and will be in effect for the entire
rate period over which the rates are in effect.
Section V. Application of Rates Under Special Circumstances
A. Energy Supplied for Emergency Use
A purchaser taking Priority Firm or New Resource Firm Power shall
pay in accordance with the Nonfirm Energy rate schedule, NF-95, and
Emergency Capacity rate schedule, CE-95, for any electric energy or
capacity which has been supplied:
1. For use during an emergency on the purchaser's system, or
2. Following an emergency to replace energy secured from sources
other than BPA during such emergency.
Mutual emergency assistance may, however, be provided and payment
therefore settled under exchange agreements.
B. Construction, Test and Start-Up, and Station Service
Power for the purpose of construction, test and start-up, and
station service shall be made available to eligible purchasers under
the Priority Firm and New Resource Firm Power Rate Schedules. Such
power must be used in the manner specified below:
1. Power sold for construction is to be used in the construction of
the project.
2. Power sold for test and start-up may be used prior to commercial
operation both to bring the project on line and to ensure that the
project is working properly.
3. Power sold for station service may be purchased at any time
following commercial operation of the project. Station service power
may be used for project start-up, project shut-down, normal plant
operations, and operations during a plant shut-down period.
C. Application of Rates During Initial Operation Period--Transitional
Service
1. Eligibility for Transitional Service
For an initial operating period, as specified in the power sales
contract, beginning with the commencement of operation of a new
industrial plant, a major addition to an existing plant, or
reactivation of an existing plant or important part thereof, BPA may
agree to bill the purchaser in accordance with the provisions of this
section. This section shall apply to both:
a. DSIs having new, additional or reactivated plant facilities, and
b. Utility purchasers serving industrial purchasers with power
purchased from BPA. BPA will provide transitional service to utilities
for only those industrial loads for which the demand can be separately
metered by the utility and recorded on a daily basis.
2. Calculation of the Daily Demand
If the purchaser requests billing on a Daily Demand basis pursuant
to its power sales contract and if BPA agrees to such billing, the
billing demand for the billing month shall be the average of the Daily
Demands as adjusted for power factor.
Demand for each day shall be defined as 100 percent of the Measured
Demand for the day (regardless of whether such Measured Demand occurs
during the Peak Period or the Offpeak Period).
3. Billing for Transitional Service
Utilities receiving transitional service shall provide BPA with
Daily Demand information for the industrial consumer for whom
transitional service is provided. To compute the power bill for the
point of delivery which includes the load being served with
transitional service, BPA shall, at its discretion, either:
a. Determine the demand for the pertinent point of delivery without
the industrial load and then add the average daily demand for such
industrial load; or
b. Bill the entire point of delivery on a daily demand basis.
[[Page 21155]]
Daily demand billing shall not affect the level of any curtailment
charge or energy charge assessed by BPA.
D. Changes in a DSI's BPA Operating Level
If a DSI requests a waiver regarding the notice requirements
specified in the DSI's power sales contract for a voluntary change in
its BPA Operating Level, and if BPA does not grant the waiver, or if
the DSI fails to give notice of such a change and does not request a
waiver, the DSI shall be billed as if no notice has been provided until
such time as the number of days in the notice period have passed. If,
however, BPA agrees to waive the notice requirement, the power bill
shall reflect the requested changes as of the requested effective date
specified in the notice or, at BPA's discretion, a date of BPA's
choosing within the notice period.
E. Restriction of Deliveries
Deliveries of capacity or energy to any purchaser may be restricted
when operation of the facilities used by BPA to serve such purchaser
is:
1. Suspended,
2. Interrupted,
3. Interfered with,
4. Curtailed, or
5. Restricted by the occurrence of any condition described in the
Uncontrollable Forces or Continuity of Service sections of the General
Contract Provisions of the power sales contract.
Section VI. Billing Information
A. Determination of Estimated Billing Data
If the amounts of capacity, energy, or the 60-minute integrated
demands for energy purchased from BPA must be estimated from data other
than metered or scheduled quantities, historical patterns, and
pertinent weather data, BPA and the purchaser will agree on billing
data to be used in preparing the bill. If the parties cannot agree on
estimated billing quantities, derived by any method, a determination
binding on both parties shall be made in accordance with the
arbitration provisions of the power sales contract.
B. Load Shift and Outage Reports
Load shift and outage reports must be submitted to BPA within 4
days of the corresponding load shift or outage. Reports may be made by
telephone, mail, or other electronic processes where available. If
customer reports are not received in a timely manner, BPA has the
option to withhold load shift or outage credit.
C. Billing for New Large Single Loads
Any BPA customer whose actual firm load includes one or more New
Large Single Loads (NLSL) shall be billed for the NLSL(s) at the New
Resource Firm Power Rate. The power requirements associated with the
NLSL shall be established in a manner consistent with the provisions of
this section.
The purchaser shall warrant to BPA that NLSLs are separately
metered. The metering must include provisions for determining:
1. The NLSL demand during BPA's diurnal capacity billing periods,
2. The NLSL energy during BPA's energy billing periods, and
3. The NLSL reactive energy for the billing month.
The design for the metering equipment for the NLSL must be approved
by BPA. Testing and inspections of such metering installations shall be
as provided in the General Contract Provisions.
On a monthly basis, each purchaser of New Resource Firm Power shall
report to BPA the quantity of power used by the NLSL during the
purchaser's billing period. Data provided to BPA by the purchaser must
be submitted to BPA within 2 normal working days of the date the
purchaser reads the meters. BPA may elect to adjust the NLSL data for
losses from the point of metering to the closest BPA point of delivery
for the purchaser.
D. Determination of Measured Demand
1. For points of delivery with fully operational metering under the
Revenue Metering System (RMS), demand shall be measured from 0000 hours
on the first day of the billing period through 2400 hours on the last
day of the billing period.
2. For points of delivery that do not have RMS metering, demand
shall be measured from 0000 hours on the first complete (24 hour) day
of the available metering data through 2400 hours on the last complete
day of the available metering data. Billing demand will be determined
from the period of available metering data that most closely matches
the official billing period of the customer.
E. Determination of Measured Energy
1. For points of delivery with fully operational metering under
RMS, energy shall be measured from 0000 hours on the first day of the
billing period through 2400 hours on the last day of the billing
period.
2. For points of delivery that do not have RMS metering, measured
energy shall be the quantity of usage recorded on the meter between
meter readings.
F. Billing Month
Meters normally will be read and bills computed at intervals of 1
month. A month is defined as the interval between scheduled meter-
reading dates. The billing month will not exceed 31 days in any case.
While it may be necessary to read meters on a day other than the
scheduled meter-reading date, for determination of billing demand, the
billing month will cease at 2400 hours on the last scheduled meter-
reading date. Schedules will be predetermined. The customer must give
30 days notice to request a change to the schedule.
G. Payment of Bills
Bills for power shall be rendered monthly by BPA. Failure to
receive a bill shall not release the purchaser from liability for
payment. Bills for amounts due BPA of $50,000 or more must be paid by
direct wire transfer; customers who expect that their average monthly
bill will not exceed $50,000 and who expect special difficulties in
meeting this requirement may request, and BPA may approve, an exemption
from this requirement. Bills for amounts due BPA under $50,000 may be
paid by direct wire transfer or mailed to the Bonneville Power
Administration, P.O. Box 6040, Portland, Oregon 97228-6040, or to
another location as directed by BPA. The procedures to be followed in
making direct wire transfers will be provided by Financial Services and
updated as necessary.
1. Computation of Bills
Demand and energy billings for power purchased under each rate
schedule shall be rounded to whole dollar amounts, by eliminating any
amount which is less than 50 cents and increasing any amount from 50
cents through 99 cents to the next higher dollar.
2. Estimated Bills
At its option, BPA may elect to render an estimated bill for that
month to be followed at a subsequent billing date by a final bill. Such
estimated bill shall have the validity of and be subject to the same
payment provisions as a final bill.
3. Due Date
Bills shall be due by close of business on the 20th day after the
date of the bill (due date). This requirement holds also for revised
bills (see section 6 below). Should the 20th day be a Saturday, Sunday,
or holiday (as celebrated by the purchaser), the due date shall be the
next following business day. [[Page 21156]]
4. Late Payment
Bills not paid in full on or before close of business on the due
date shall be subject to a penalty charge of $25. In addition, an
interest charge of one-twentieth percent (0.05 percent) shall be
applied each day to the sum of the unpaid amount and the penalty
charge. This interest charge shall be assessed on a daily basis until
such time as the unpaid amount and penalty charge are paid in full.
Remittances received by mail will be accepted without assessment of
the charges referred to in the preceding paragraph provided the
postmark indicates the payment was mailed on or before the due date.
Whenever a power bill or a portion thereof remains unpaid subsequent to
the due date and after giving 30 days' advance notice in writing, BPA
may cancel the contract for service to the purchaser. However, such
cancellation shall not affect the purchaser's liability for any charges
accrued prior thereto under such contract.
5. Disputed Billings
In the event of a disputed billing, full payment shall be rendered
to BPA and the disputed amount noted. Disputed amounts are subject to
the late payment provisions specified above. BPA shall separately
account for the disputed amount. If it is determined that the purchaser
is entitled to the disputed amount, BPA shall refund the disputed
amount with interest, as determined by BPA's financial services group.
BPA retains the right to verify, in a manner satisfactory to the
Administrator, all data submitted to BPA for use in the calculation of
BPA's rates and corresponding rate adjustments. BPA also retains the
right to deny eligibility for any BPA rate or corresponding rate
adjustment until all submitted data have been accepted by BPA as
complete, accurate, and appropriate for the rate or adjustment under
consideration.
6. Revised Bills
As necessary, BPA may render a revised bill.
a. If the amount of the revised bill is less than or equal to the
amount of the original bill, the revised bill shall replace all
previous bills issued by BPA that pertain to the specified customer for
the specified billing period and the revised bill shall have the same
date as the replaced bill.
b. If a revision causes an additional amount to be due BPA or the
specified customer beyond the amount of the original bill, a revised
bill will be issued for the difference and the date of the revised bill
shall be its date of issue.
Section VII. Variable Industrial Rate Parameters and Adjustments
A. Monthly Average Aluminum Price Determination
1. Calculation of the Monthly Billing Aluminum Price
The monthly billing aluminum price shall be determined by BPA for
each billing month. For purposes of this rate schedule, the monthly
billing aluminum price shall be based on the average price of aluminum
in U.S. markets during the third calendar month prior to the billing
month. The average price of aluminum in U.S. markets shall be defined
as the average U.S. Transaction Price reported for the month by
``Metals Week,'' in cents per pound, rounded to the nearest tenth of a
cent.
2. Notification of the Monthly Average Aluminum Price
BPA shall provide, 45 days prior to the billing month, written
notification to purchasers under this rate schedule of the monthly
billing aluminum price to be used for billing purposes. Upon written
request supporting documentation shall be provided.
3. Changes in Aluminum Price Indicators
In the event that BPA determines that factors outside its control
render the monthly average U.S. Transaction Price unusable as an
approximation of U.S. market prices, BPA may develop and substitute
another indicator for prices in U.S. markets. BPA shall notify
interested parties of its intent to do so at least 120 days prior to
the billing month in which the change would become effective. In this
notification, BPA shall explain the reason for the substitution and
specify the replacement indicator it intends to use. BPA also shall
describe the methodology to determine the monthly billing aluminum
price to be used for billing purposes under this rate schedule and
shall provide the necessary data to be used in the calculation.
Interested persons will have until close of business 3 weeks from the
date of the notification to provide comments. Consideration of comments
and more current information may cause the final methodology and the
substitute aluminum price index to differ from those proposed. BPA
shall notify all affected parties, and those parties that submitted
comments, of its final determination 90 days prior to the billing month
the new indicator shall be effective.
B. Annual Adjustments to the Lower and Upper Pivot Aluminum Prices
On July 1, 1991, and every July 1, thereafter, the Lower and Upper
Pivot Aluminum Prices, as stated in section III.B of the rate schedule,
shall be subject to change for billing purposes as herein described.
The term ``annual adjustment date'' shall refer to July 1 of each year.
1. Implementation Procedures
Beginning in 1991 and every year thereafter, prior to April 1 of
that year, BPA shall provide the purchasers under this rate schedule
preliminary written estimates of proposed adjustments to the Lower and
Upper Pivot Aluminum Prices. By the last working day of the month of
April, BPA shall notify interested parties in writing of BPA's revised
determinations concerning changes to the Lower and Upper Pivot Aluminum
Prices. BPA shall describe how the adjustments were determined and
provide the data used in the calculations. In addition to written
notification, BPA may, but is not obligated to, hold a public comment
forum to clarify its determination and solicit comments. Interested
persons may submit comments on the determinations to BPA and other
parties. Comments will be accepted until close of business on the last
working Friday in May. Consideration of comments and more current
information may result in the final adjustment differing from the
proposed adjustment. By June 30 of each year, BPA shall notify all VI
purchasers, those parties that submitted comments, and parties that
requested notification, of the final determination.
2. Annual Adjustment Procedures
a. Annual Adjustment of the Lower Pivot Aluminum Price
Beginning with the July 1, 1991, annual adjustment date, for each
year that the Variable Industrial rate is in effect, the Lower Pivot
Aluminum Price as stated in section III.B.1 of the rate schedule shall
be adjusted on the July 1 annual adjustment date. The Lower Pivot
Aluminum Price shall be revised by multiplying 59 cents per pound by
the Cost Escalation Index described in section VII.B.3.b of these GRSPs
and rounded to the nearest tenth of a cent. The revised Lower Pivot
Aluminum Price shall replace the Lower Pivot Aluminum Price as stated
in section III.B.1 of the rate schedule and shall be used to determine
the energy rate in the subsequent 12 billing months.
b. Annual Adjustment of the Upper Pivot Aluminum Price
[[Page 21157]]
For each year that the Variable Industrial rate is in effect, the
Upper Pivot Aluminum Price as stated in section III.B.2 of the rate
schedule shall be adjusted on the July 1 annual adjustment date. The
Upper Pivot Aluminum Price will be adjusted such that the Average
Historical Aluminum Price described in section VII.B.4 of these GRSPs
is the midpoint between the adjusted Upper Pivot Aluminum Price and the
Average Historical Lower Pivot Aluminum Price described in section
VII.B.5 below, except as limited to the greater of 65 cents per pound
or the adjusted Lower Pivot Point for the year.
The Upper Pivot Aluminum Price shall equal the greater of:
(1) (2)*(AAP)-ALP:
where
AAP=the Average Historical Aluminum Price described in section VII.B.4
of these GRSPs.
ALP=the Average Historical Lower Pivot Aluminum Price described in
section VII.B.5 of these GRSPs.
(2) 65.0 cents per pound escalated to current dollars using the
Cost Escalator for the Upper Pivot Aluminum Price described in section
VII.B.3.c of these GRSPs.
or
(3) The adjusted Lower Pivot Aluminum Price for the year.
The revised Upper Pivot Aluminum Price shall supersede the Upper
Pivot Aluminum Price as stated in section III.B.2 of the rate schedule
and shall be used to determine the energy rate in the subsequent 12
months.
3. Cost Escalators
a. The cost indices described below shall be used in calculating
the appropriate cost escalators. Each index shall be rounded to the
nearest one-tenth of a percent, or three significant places.
(1) Electricity Cost Index
The average VI rate in mills per kilowatt-hour based on the Plateau
Energy Charge and the Discount for Quality of First Quartile Service in
effect on the April 1 preceding the annual adjustment date and a load
factor of 98.5 percent; divided by 22.8 mills per kilowatt-hour (the
average VI-86 rate assuming the plateau energy charge and the Discount
for Quality of First Quartile Service in 1986).
(2) Labor Cost Index
The annual average hourly earnings for the U.S. primary aluminum
industry (SIC 3334) over the previous complete calendar year, from the
Employment and Earnings, published by the U.S. Department of Labor,
Bureau of Labor Statistics (BLS), divided by $14.20 per hour (the value
of SIC 3334 earnings reported for 1985).
(3) Alumina Cost Index
The annual average of the monthly billing aluminum prices described
in section VII.A of the GRSPs for the previous 1-year period beginning
July 1 through June 30 divided by 50.8 cents per pound (the average
U.S. Transaction price over the period April 1985 through March 1986).
(4) Other Costs Index
The annual average GNP Implicit Price Deflator for the previous
complete calendar year, as published by the U.S. Department of
Commerce, Bureau of Economic Analysis, divided by 0.944 (the value of
the GNP Implicit Price Deflator for 1985 with 1987=1.000).
In the event the indices delineated above are discontinued or
revised in a manner that BPA determines renders them unusable for
calculating a consistent cost index, BPA will adjust or substitute
another similar price index, following advance notification and
opportunity for public comment as described in section VII.B.1 of these
GRSPs.
b. The Cost Escalator for the Lower Pivot Aluminum Price shall be a
weighted average of the four indices contained in section VII.B.3.a
above. The following weights shall be assigned each index:
Electricity Cost Index .30
Labor Cost Index .20
Alumina Cost Index .20
Other Costs Index .30
c. The Cost Escalator for the Upper Pivot Aluminum Price shall be a
weighted average of the Electricity Cost and Other Cost Escalators as
stated in sections VII.B.3.a.(1) and VII.B.3.a.(4) above. The following
weights shall be assigned each index:
Electricity Cost Index .25
Other Costs Index .75
4. Average Historical Aluminum Price
Prior to the July 1, 1991, annual adjustment date and every annual
adjustment date thereafter, an average historical aluminum price shall
be calculated for the period the VI rate has been in effect beginning
August 1986. The average historical aluminum price shall be determined
following the procedures set forth below:
a. Each monthly billing aluminum price determined pursuant to
section VII.A of these GRSPs for the period August 1, 1986, through
June 30 immediately preceding the annual adjustment date, shall be
escalated to the current year dollars using the Price Deflator
procedures described in section VII.B.6 below.
b. The sum of the escalated monthly billing aluminum prices shall
be divided by the number of months in the period and rounded to the
nearest tenth of a cent to obtain the Average Historical Aluminum
Price.
5. Average Historical Lower Pivot Aluminum Price
Prior to the July 1, 1991, annual adjustment date and every annual
adjustment date thereafter, the average of the Lower Pivot Aluminum
Prices for the period the VI rate has been in effect beginning August
1986, shall be calculated following the procedures set forth below:
a. The Lower Pivot Aluminum Price in each month for the period
August 1, 1986, through June 30 of the calendar year preceding the
annual adjustment date, shall be escalated to the current year's
dollars using the Price Deflator procedures described in section
VII.B.6 below.
b. The sum of the escalated monthly Lower Pivot Aluminum Prices
shall be divided by the number of months in the period, and rounded to
the nearest tenth of a cent to obtain an Average Historical Lower Pivot
Aluminum Price.
6. Price Deflator Procedures
For purposes of converting nominal dollars to real dollars in the
calculation of the Average Historical Aluminum Price and the Average
Historical Lower Pivot Aluminum Price, the following Price Deflator
procedures shall be used:
a. Monthly billing aluminum prices and Lower Pivot Aluminum Prices
for any calendar months July through December shall be inflated by
multiplying the price by the ratio of the GNP Implicit Price Deflator
for the calendar year prior to the annual adjustment date divided by
the Implicit Price Deflator for the calendar year in which the price
occurred.
b. Monthly billing aluminum prices and Lower Pivot Aluminum Prices
for any calendar months January through June shall be inflated by
multiplying the price by the ratio of the Implicit Price Deflator for
the calendar year prior to the annual adjustment date divided by the
Implicit Price Deflator for the calendar year prior to the year in
which the price occurred. Each price shall be rounded to the nearest
tenth of a cent.
[[Page 21158]]
V. Transmission Rate Schedules And General Transmission Rate
Schedule Provisions (GTRSPs)
Table Of Contents
Summary of Rate Schedules
Transmission Rate Schedules
FPT-95.1 Formula Power Transmission
FPT-95.3 Formula Power Transmission
IR-95 Integration of Resources
IS-95 Southern Intertie Transmission
IN-95 Northern Intertie Transmission
IE-95 Eastern Intertie Transmission
ET-95 Energy Transmission
MT-95 Market Transmission
UFT-95 Use-of-Facilities Transmission
TGT-95 Townsend-Garrison Transmission
AC-95 Southern Intertie Annual Costs Rate and Billing Provisions
General Transmission Rate Schedule Provisions
Section I Adoption of Revised Transmission Rate Schedules and
General Transmission Rate Schedule Provisions
Section II Billing Factor Definitions and Billing Adjustments
Section III Other Definitions
Section IV Billing Information
A. Summary of Rate Schedules
BPA is proposing to surcharge by 4 percent the following
transmission rate schedules: Formula Power Transmission; Integration of
Resources; Southern Intertie Transmission; Northern Intertie
Transmission; Eastern Intertie Transmission; and Energy Transmission.
Pursuant to the Settlement Agreement, BPA proposes to increase the
components of the FPT 95.3 rate by 4 percent for the October 1, 1995-
September 30, 1996 period. The increase to this rate for the 1-year
period, however, does not preclude BPA from increasing the 3-year FPT
rate, as necessary, in its 1996 rate case. BPA also is proposing
extension of the Market Transmission (MT) rate, Use of Facilities (UFT)
rate, and Townsend-Garrison Transmission (TGT) rate with no changes.
The MT rate was developed for use among Western Systems Power Pool
(WSPP) participants to allow for flexible hourly, daily, weekly, and
monthly charges. The UFT and TGT rate schedules are formula rates. The
UFT rate recovers the annual cost of identified facilities over which
specific wheeling transactions occur. The TGT rate is a contract rate
that recovers the cost of the Montana (Eastern) Intertie.
In addition, BPA is proposing the Southern Intertie Annual Costs
(AC-95) rate to be applied to owners of Pacific Northwest (PNW)
Alternating Current (AC) Intertie capacity. This rate recovers the
capacity owner's pro-rata share of actual PNW AC Intertie costs:
operations, maintenance, general plant, and other identified expenses,
as well as capital costs of replacements and reinforcements. The
proposed AC-95 rate takes the place of the AC-93 rate, which was a
``bridge'' rate until Capacity Ownership contracts were complete.
Copies of the Ownership Agreement are available for examination at
BPA's Public Information Center at the address listed at the beginning
of this notice.
B. Transmission Rate Schedules
Schedule FPT-95.1
Formula Power Transmission
Section I. Availability
This schedule supersedes schedule FPT-93.1 for all firm
transmission agreements which provide that rates may be adjusted not
more frequently than once a year. It is available for firm transmission
of electric power and energy using the Main Grid and/or Secondary
System of the Federal Columbia River Transmission System (FCRTS). This
schedule is for full-year and partial-year service and for either
continuous or intermittent service when firm availability of service is
required. For facilities at voltages lower than the Secondary System, a
different rate schedule may be specified. Service under this schedule
is subject to BPA's General Transmission Rate Schedule Provisions
(GTRSPs).
Section II. Rate
A. Full-Year Service
The monthly charge per kilowatt of billing demand shall be one-
twelfth of the sum of the Main Grid Charge and the Secondary System
Charge, as applicable and as specified in the Agreement.
1. Main Grid Charge
The Main Grid Charge per kilowatt of billing demand shall be the
sum of one or more of the following component factors as specified in
the Agreement:
a. Main Grid Distance Factor: The amount computed by multiplying
the Main Grid Distance by $0.0386 per mile
b. Main Grid Interconnection Terminal Factor: $0.28
c. Main Grid Terminal Factor: $0.46
d. Main Grid Miscellaneous Facilities Factor: $1.96
2. Secondary System Charge
The Secondary System Charge per kilowatt of billing demand shall be
the sum of one or more of the following component factors as specified
in the Agreement:
a. Secondary System Distance Factor: The amount determined by
multiplying the Secondary System Distance by $0.2895 per mile
b. Secondary System Transformation Factor: $4.26
c. Secondary System Intermediate Terminal Factor: $1.34
d. Secondary System Interconnection Terminal Factor: $0.71
B. Partial-Year Service
The monthly charge per kilowatt of billing demand shall be as
specified in Section II.A. for all months of the year except for
agreements with terms 5 years or less and which specify service for
fewer than 12 months per year. The monthly charge shall be:
1. During months for which service is specified, the monthly charge
defined in Section II.A., and
2. During other months, the monthly charge defined in Section II.A.
multiplied by 0.2.
Section III. Billing Factors
Unless otherwise stated in the Agreement, the billing demand shall
be the largest of:
A. The Transmission Demand;
B. The highest hourly Scheduled Demand for the month; or
C. The Ratchet Demand.
Schedule FPT-95.3
Formula Power Transmission
Section I. Availability
This schedule supersedes schedule FPT-91.3 for all firm
transmission agreements which provide that rates may be adjusted not
more frequently than once every 3 years. It is available for firm
transmission of electric power and energy using the Main Grid and/or
Secondary System of the Federal Columbia River Transmission System.
This schedule is for full-year and partial-year service and for either
continuous or intermittent service when firm availability of service is
required. For facilities at voltages lower than the Secondary System, a
different rate schedule may be specified. Service under this schedule
is subject to BPA's General Transmission Rate Schedule Provisions.
Section II. Rate
A. Full-Year Service
The monthly charge per kilowatt of billing demand shall be one-
twelfth of the sum of the Main Grid Charge and the Secondary System
Charge, as applicable and as specified in the Agreement.
1. Main Grid Charge
The Main Grid Charge per kilowatt of billing demand shall be the
sum of one or more of the following component factors as specified in
the Agreement: [[Page 21159]]
a. Main Grid Distance Factor: The amount computed by multiplying
the Main Grid Distance by $0.0292 per mile
b. Main Grid Interconnection Terminal Factor: $0.28
c. Main Grid Terminal Factor: $0.31
d. Main Grid Miscellaneous Facilities Factor: $1.36
2. Secondary System Charge
The Secondary System Charge per kilowatt of billing demand shall be
the sum of one or more of the following component factors as specified
in the Agreement:
a. Secondary System Distance Factor: The amount determined by
multiplying the Secondary System Distance by $0.2039 per mile
b. Secondary System Transformation Factor: $2.63
c. Secondary System Intermediate Terminal Factor: $0.87
d. Secondary System Interconnection Terminal Factor: $0.46
B. Partial-Year Service
The monthly charge per kilowatt of billing demand shall be as
specified in Section II.A. for all months of the year except for
agreements with terms 5 years or less and which specify service for
fewer than 12 months per year. The charge shall be:
1. During months for which service is specified, the monthly charge
defined in Section II.A., and
2. During other months, the monthly charge defined in Section II.A.
multiplied by 0.2.
Section III. Billing Factors
Unless otherwise stated in the Agreement, the billing demand shall
be the largest of:
A. The Transmission Demand;
B. The highest hourly Scheduled Demand for the month; or
C. The Ratchet Demand.
Schedule IR-95
Integration of Resources
Section I. Availability
This schedule supersedes IR-93 and is available for firm
transmission service for electric power and energy using the Main Grid
and/or Secondary System of the Federal Columbia River Transmission
System. The definitions of Main Grid and Secondary Systems are the same
as for the FPT-95.1 and FPT-95.3 rate schedules and are contained in
the General Transmission Rate Schedule Provisions (GTRSPs). For
facilities at voltages lower than the Secondary System, a different
rate schedule may be specified. Service under this schedule is subject
to BPA's GTRSPs.
Section II. Rate
The monthly charge shall be the sum of A and B where:
A. Demand Charge
1. $0.441 per kilowatt of billing demand; or
2. For Points of Integration (POI) specified in the Agreement as
being short distance POIs, for which Main Grid and Secondary System
facilities are used for a distance of less than 75 circuit miles, the
following formula applies: [0.2 + (0.8 * transmission distance/75)] *
($0.441 per kilowatt of billing demand)
Where:
the billing demand for a short distance POI is the demand level
specified in the Agreement for such POI, and the transmission distance
is the circuit miles between the POI for a generating resource of the
customer and a designated Point of Delivery serving load of the
customer. Short distance POIs are determined by BPA after considering
factors in addition to transmission distance.
B. Energy Charge
1.10 mills per kilowatthour of billing energy.
Section III. Billing Factors
To the extent that the Agreement provides for the customer to be
billed for transmission in excess of the Transmission Demand or Total
Transmission Demand, as defined in the Agreement, at the nonfirm
transmission rate (currently ET-95), such transmission service shall
not contribute to either the Billing Demand or the Billing Energy for
the IR rate provided that the customer requests such treatment and BPA
approves in accordance with the prescribed provisions in the Agreement.
A. Billing Demand
The billing demand shall be the largest of:
1. The Transmission Demand, except under General Transmission
Agreements where a Total Transmission Demand is defined;
2. The highest hourly Scheduled Demand for the month; or
3. The Ratchet Demand.
B. Billing Energy
The billing energy shall be the monthly sum of scheduled
kilowatthours.
Schedule IS-95
Southern Intertie Transmission
Section I. Availability
This schedule supersedes IS-93 and is available for all
transmission on the Southern Intertie. Service under this schedule is
subject to BPA's General Transmission Rate Schedule Provisions.
Section II. Rate
A. Nonfirm Transmission Rate
The charge for nonfirm transmission of non-BPA power shall be 3.23
mills per kilowatthour of billing energy. This charge applies for both
north-to-south and south-to-north transactions.
B. Firm Transmission Rate
The charge for firm transmission service shall be $0.734 per
kilowatt per month of billing demand and 1.76 mills per kilowatthour of
billing energy. Firm transmission will only be made available to
customers under this rate schedule who have executed a contract with
BPA specifying use of the Firm Transmission rate for either north-to-
south or south-to-north transactions.
Section III. Billing Factors
A. For services under Section II.A, the billing energy shall be the
monthly sum of the scheduled kilowatthours, plus the monthly sum of
kilowatthours allocated but not scheduled. The amount of allocated but
not scheduled energy that is subject to billing may be reduced pro rata
by BPA due to forced Intertie outages and other uncontrollable forces
that may reduce Intertie capacity.
The amount of allocated but not scheduled energy that is subject to
billing also may be reduced upon mutual agreement between BPA and the
customer.
B. For services under Section II.B, the billing demand shall be the
Transmission Demand as defined in the Agreement. The billing energy
shall be the monthly sum of scheduled kilowatthours, unless otherwise
specified in the Agreement.
Schedule IN-95
Northern Intertie Transmission
Section I. Availability
This schedule supersedes IN-93 and is available for all
transmission on the Northern Intertie pursuant to an Agreement. Service
under this schedule is subject to BPA's General Transmission Rate
Schedule Provisions.
Section II. Rate
The charge for transmission of non-BPA power on the Northern
Intertie shall be 0.89 mills per kilowatthour. [[Page 21160]]
Section III. Billing Factors
Billing Energy
The billing energy shall be the monthly sum of the scheduled
kilowatthours.
Schedule IE-95
Eastern Intertie Transmission
Section I. Availability
This schedule supersedes IE-93 and is available for all nonfirm
transmission on the Eastern Intertie. Service under this schedule is
subject to BPA's General Transmission Rate Schedule Provisions.
Section II. Rate
The charge for nonfirm transmission on the Eastern Intertie shall
be 2.12 mills per kilowatthour.
Section III. Billing Factors
Billing Energy
The billing energy shall be the monthly sum of the scheduled
kilowatthours.
Schedule ET-95
Energy Transmission
Section I. Availability
This schedule supersedes ET-93, unless otherwise specified in the
Agreement, with respect to delivery using Federal Columbia River
Transmission System facilities other than the Southern Intertie,
Eastern Intertie, or the Northern Intertie, and is available for firm
(of not more than 1 year duration) or nonfirm transmission between
points within the Pacific Northwest. BPA may interrupt nonfirm service
which is provided under this rate schedule. Service under this schedule
is subject to BPA's General Transmission Rate Schedule Provisions.
Section II. Rate
The charge for transmission of non-BPA power shall be 2.10 mills
per kilowatthour.
Section III. Billing Factors
Billing Energy
The billing energy shall be the monthly sum of scheduled
kilowatthours.
Schedule MT-95
Market Transmission
Section I. Availability
This schedule supersedes MT-91 and is available for Transmission
Service for transactions using Federal Columbia River Transmission
System facilities pursuant to the Western Systems Power Pool (WSPP)
Agreement. General Transmission Rate Schedule Provisions.
Section II. Rate
The charge shall be determined in advance by BPA. The charge shall
be based on the duration of the proposed transaction and shall not
exceed the following rates.
A. Hourly Rate
The maximum charge shall be 6.5 mills per kilowatthour where the
total hourly revenues from a given transaction during a calendar day
shall not exceed the product of the Daily rate and the maximum demand
scheduled during such day.
B. Daily Rate
The maximum charge shall be $.105 per kilowattday where the total
demand charge revenues in any consecutive 7-day period shall not exceed
the product of the Weekly rate and the highest demand experienced on
any day in the 7-day period.
C. Weekly Rate
The maximum charge shall be $.52 per kilowattweek.
D. Monthly Rate
The maximum charge shall be $2.27 per kilowattmonth.
Section III. Billing Factors
The billing factors shall be specified in advance by BPA, as to
representing the Transmission Service use or reservation.
Schedule UFT-95
Use-of-Facilities Transmission
Section I. Availability
This schedule supersedes UFT-83 unless otherwise provided in the
Agreement, and is available for firm transmission over specified
Federal Columbia River Transmission System facilities. Service under
this schedule is subject to BPA's General Transmission Rate Schedule
Provisions.
Section II. Rate
The monthly charge per kilowatt of Transmission Demand specified in
the Agreement shall be one-twelfth of the annual cost of capacity of
the specified facilities divided by the sum of Transmission Demands (in
kilowatts) using such facilities. Such annual cost shall be determined
in accordance with Section III.
Section III. Determination of Transmission Rate
A. From time to time, but not more often than once in each Contract
Year, BPA shall determine the following data for the facilities which
have been constructed or otherwise acquired by BPA and which are used
to transmit electric power:
1. The annual cost of the specified FCRTS facilities, as determined
from the capital cost of such facilities and annual cost ratios
developed from the Federal Columbia River Power System financial
statement, including interest and amortization, operation and
maintenance, administrative and general, and general plant costs.
2. The yearly noncoincident peak demands of all users of such
facilities or other reasonable measurement of the facilities' peak use.
B. The monthly charge per kilowatt of billing demand shall be one-
twelfth of the sum of the annual cost of the FCRTS facilities used
divided by the sum of Transmission Demands. The annual cost per
kilowatt of Transmission Demand for a facility constructed or otherwise
acquired by BPA shall be determined in accordance with the following
formula:
A
D
Where:
A = The annual cost of such facility as determined in accordance with
A.1. above.
D = The sum of the yearly noncoincident demands on the facility as
determined in accordance with A.2. above.
The annual cost per kilowatt of facilities listed in the Agreement
which are owned by another entity, and used by BPA for making
deliveries to the transferee, shall be determined from the costs
specified in the Agreement between BPA and such other entity.
Section IV. Determination of Billing Demand
Unless otherwise stated in the Agreement, the factor to be used in
determining the kilowatts of billing demand shall be the largest of:
A. The Transmission Demand in kilowatts specified in the Agreement;
B. The highest hourly Measured or Scheduled Demand for the month,
the Measured Demand being adjusted for power factor; or
C. The Ratchet Demand.
Schedule TGT-95
Townsend-Garrison Transmission
Section I. Availability
This schedule supersedes TGT-1 and shall apply to all agreements
which provide for the firm transmission of electric power and energy
over transmission facilities of BPA's section [[Page 21161]] of the
Montana [Eastern] Intertie. Service under this schedule is subject to
BPA's General Transmission Rate Schedule Provisions.
Section II. Rate
The monthly charge shall be one-twelfth of the sum of the annual
charges listed below, as applicable and as specified in the agreements
for firm transmission. The Townsend-Garrison 500-kV lines and
associated terminal, line compensation, and communication facilities
are a separately identified portion of the Federal Transmission System.
Annual revenues plus credits for government use should equal annual
costs of the facilities, but in any given year there may be either a
surplus or a deficit. Such surpluses or deficits for any year shall be
accounted for in the computation of annual costs for succeeding years.
Revenue requirements for firm transmission use will be decreased by any
revenues received from nonfirm use and credits for all government use.
The general methodology for determining the firm rate is to divide the
revenue requirement by the total firm capacity requirements. Therefore,
the higher the total capacity requirements, the lower will be the unit
rate.
If the government provides firm transmission service in its section
of the Montana (Eastern) Intertie in exchange for firm transmission
service in a customer's section of the Montana Intertie, the payment by
the government for such transmission services provided by such customer
will be made in the form of a credit in the calculation of the Intertie
Charge for such customer. During an estimated 1- to 3-year period
following the commercial operation of the third generating unit at the
Colstrip Thermal Generating Plant at Colstrip, Montana, the capability
of the Federal Transmission System west of Garrison Substation may be
different from the long-term situation. It may not be possible to
complete the extension of the 500-kV portion of the Federal
Transmission System to Garrison by such commercial operation date. In
such event, the 500/230 kV transformer will be an essential extension
of the Townsend-Garrison Intertie facilities, and the annual costs of
such transformer will be included in the calculation of the Intertie
Charge.
However, starting 1 month after extension to Garrison of the 500-kV
portion of the Federal Transmission System, the annual costs of such
transformer will no longer be included in the calculation of the
Intertie Charge.
A. Nonfirm Transmission Charge:
This charge will be filed as a separate rate schedule and revenues
received thereunder will reduce the amount of revenue to be collected
under the Intertie Charge below.
B. Intertie Charge for Firm Transmission Service:
[GRAPHIC][TIFF OMITTED]TN01MY95.073
Section III. Definitions
A. TAC = Total Annual Costs of facilities associated with the Townsend-
Garrison 500-kV
Transmission line including terminals, and prior to extension of
the 500-kV portion of the Federal Transmission System to Garrison, the
500/230 kV transformer at Garrison. Such annual costs are the total of:
(1) Interest and amortization of associated Federal investment and the
appropriate allocation of general plant costs; (2) operation and
maintenance costs; (3) allowance for BPA's general administrative costs
which are appropriately allocable to such facilities, and (4) payments
made pursuant to section 7(m) of Pub. L. 96-501 with respect to these
facilities. Total Annual Costs shall be adjusted to reflect reductions
to unpaid total costs as a result of any amounts received, under
agreements for firm transmission service over the Montana Intertie, by
the government on account of any reduction in Transmission Demand,
termination or partial termination of any such agreement or otherwise
to compensate BPA for the unamortized investment, annual cost, removal,
salvage, or other cost related to such facilities.
B. NFR = Nonfirm Revenues, which are equal to: (1) The product of
the Nonfirm Transmission Charge described in II(A) above, and the total
nonfirm energy transmitted over the Townsend-Garrison line segment
under such charge for such month; plus (2) the product of the Nonfirm
Transmission Charge and the total nonfirm energy transmitted in either
direction by the Government over the Townsend-Garrison line segment for
such month.
C. CR = Capacity Requirement of a customer on the Townsend-Garrison
500-kV transmission facilities as specified in its firm transmission
agreement.
D. TCR = Total Capacity Requirement on the Townsend-Garrison 500-kV
transmission facilities as calculated by adding (1) the sum of all
Capacity Requirements (CR) specified in transmission agreements
described in section I; and (2) the Government's firm capacity
requirement. The Government's firm capacity requirement shall be no
less than the total of the amounts, if any, specified in firm
transmission agreements for use of the Montana Intertie.
E. EC = Exchange Credit for each customer which is the product of:
(1) The ratio of investment in the Townsend-Broadview 500-kV
transmission line to the investment in the Townsend-Garrison 500-kV
transmission line; and (2) the capacity which the Government obtains in
the Townsend-Broadview 500-kV transmission line through exchange with
such customer. If no exchange is in effect with a customer, the value
of EC for such customer shall be zero.
Schedule AC-95
Southern Intertie Annual Costs Rate and Billing Provisions
Section I. Availability
This schedule is applicable to each party (Capacity Owner) that
executes a PNW AC Intertie Capacity Ownership Agreement (Agreement).
Billings pursuant to this schedule are subject to the Billing
Provisions in Exhibit B of the Agreement. This rate schedule shall be
effective on the first day of the fiscal year following the earlier of
interim or final FERC approval of this rate schedule. Unless otherwise
defined in this rate schedule, capitalized terms used in this rate
schedule shall have the respective definitions set forth in section 1
of this Agreement.
Section II. Rate
A. Operations
The monthly charge equals:
[[Page 21162]]
[GRAPHIC][TIFF OMITTED]TN01MY95.074
Where
``Months'' is equal to 12, or, if the Operating Plan has, during
the fiscal year to which such Operating Plan pertains, been amended
with respect to Operations Cost, the number of full months remaining in
the fiscal year after such amended Operating Plan becomes effective for
which Capacity Owners have not been billed.
``Operations Cost'' means, upon and after the effective date of
Exhibit B pursuant to this Agreement, for any fiscal year any Allocated
Direct Costs for Bonneville's PNW AC Intertie, operations Indirect
Costs for Bonneville's PNW AC Intertie, and operations Overhead Costs
for Bonneville's PNW AC Intertie for such fiscal year, each being
determined in accordance with section I of Exhibit I.
``Capacity Ownership Percentage'' is as defined in subsection 1(k)
of each Capacity Owner's Agreement.
The monthly charge for the Operations rate shall be calculated
using the forecast Operations Cost in the Operating Plan in effect
during the month for which the monthly charge is calculated; provided,
however, if the Operating Plan is amended during the fiscal year to
which such Operating Plan pertains, the monthly charge for Operations
Cost shall be calculated using the forecast Operations Cost less the
Operations Cost already billed for such fiscal year for the remaining
months of the fiscal year following such amendment.
B. Maintenance
The monthly charge equals:
[GRAPHIC][TIFF OMITTED]TN01MY95.075
Where
``Months'' is equal to 12, or, if the Operating Plan has, during
the fiscal year to which such Operating Plan pertains, been amended
with respect to Maintenance Cost, the number of full months remaining
in the fiscal year after such amended Operating Plan becomes effective
for which Capacity Owners have not been billed.
``Maintenance Cost'' means, upon and after the effective date of
Exhibit B pursuant to this Agreement, for any fiscal year any
maintenance Direct Costs for Bonneville's PNW AC Intertie, maintenance
Indirect Costs for Bonneville's PNW AC Intertie, and maintenance
Overhead Costs for Bonneville's PNW AC Intertie for such fiscal year,
each being determined in accordance with section II of Exhibit I.
``Capacity Ownership Percentage'' is as defined in subsection 1(k)
of each Capacity Owner's Agreement.
The monthly charge for the Maintenance rate shall be calculated
using the forecast Maintenance Cost in the Operating Plan in effect
during the month for which the monthly charge is calculated; provided,
however, if the Operating Plan is amended during the fiscal year to
which such Operating Plan pertains, the monthly charge for Maintenance
Cost shall be calculated using the forecast Maintenance Cost less the
Maintenance Cost already billed for such fiscal year for the remaining
months of the fiscal year following such amendment.
C. General Plant
The monthly charge equals:
[GRAPHIC][TIFF OMITTED]TN01MY95.078
Where
``Months'' is equal to 12, or, if the Operating Plan has, during
the fiscal year to which such Operating Plan pertains, been amended
with respect to General Plant Cost, the number of full months remaining
in the fiscal year after such amended Operating Plan becomes effective
for which Capacity Owners have not been billed.
``General Plant Cost'' means, upon and after the effective date of
Exhibit B pursuant to this Agreement, for any fiscal year any costs
(including direct costs, indirect costs, overhead costs, and AFUDC) for
Bonneville's general plant investment for such fiscal year. The method
for determining General Plant Cost is set forth in section IV of
Exhibit I.
``Capacity Ownership Percentage'' is as defined in subsection 1(k)
of each Capacity Owner's Agreement.
The monthly charge for the General Plant rate shall be calculated
using the General Plant Cost in the Operating Plan in effect during the
month for which the monthly charge is calculated; provided, however, if
the Operating Plan is amended during the fiscal year to which such
Operating Plan pertains, the monthly charge for General Plant Cost
shall be calculated using the General Plant Cost less the General Plant
Cost already billed for such fiscal year for the remaining months of
the fiscal year following such amendment.
D. Other Costs
The monthly charge equals:
[GRAPHIC][TIFF OMITTED]TN01MY95.079
Where
``Months'' is equal to 12, or, if the Operating Plan has, during
the fiscal year to which such Operating Plan pertains, been amended
with respect to Other Cost, the number of full months remaining in the
fiscal year after such [[Page 21163]] amended Operating Plan becomes
effective for which Capacity Owners have not been billed.
``Other Costs'' means, upon and after the effective date of Exhibit
B pursuant to this Agreement, Bonneville's other costs for Bonneville's
PNW AC Intertie described in and determined pursuant to section V of
Exhibit I.
``Capacity Ownership Percentage'' is as defined in subsection 1(k)
of each Capacity Owner's Agreement.
The monthly charge for the Other Costs rate shall be calculated
using the forecast Other Costs in the Operating Plan in effect during
the month for which the monthly charge is calculated; provided,
however, if the Operating Plan is amended during the fiscal year to
which such Operating Plan pertains, the monthly charge for Other Costs
shall be calculated using the forecast Other Costs less the Other Costs
already billed for such fiscal year for the remaining months of the
fiscal year following such amendment.
E. Contracts and Rates
The monthly charge equals:
[GRAPHIC][TIFF OMITTED]TN01MY95.080
Where
``Months'' is equal to 12, or, if the Operating Plan has, during
the fiscal year to which such Operating Plan pertains, been amended
with respect to Contracts and Rates Cost, the number of full months
remaining in the fiscal year after such amended Operating Plan becomes
effective for which Capacity Owners have not been billed.
``Contracts and Rates Costs'' means, upon and after the effective
date of Exhibit B pursuant to this Agreement, for any fiscal year
Bonneville's total contracts and rates costs (as described in section
VI of Exhibit I) for such fiscal year as functionalized and allocated
in accordance with section VI of Exhibit I to determine Contracts and
Rates Costs for Bonneville's PNW AC Intertie.
``Capacity Ownership Percentage'' is as defined in subsection 1(k)
of each Capacity Owner's Agreement.
Contracts and Rates Cost is determined in accordance with section
VI of Exhibit I as of the Effective Date. If Exhibit I is amended
pursuant to subsection 19(k) of the Agreement to provide that the
Contracts and Rates Cost determined in accordance with section VI of
Exhibit I (and reflected in the Operating Plan for the fiscal year to
which such Operating Plan pertains) is directly assigned to the
Capacity Owners pursuant to such amended Exhibit I (and reflected in
the Operating Plan for the fiscal year to which such Operating Plan
pertains), the Capacity Ownership Percentage in the monthly charge
calculation for such fiscal year shall be replaced by the ratio of (a)
each Capacity Ownership Share to (b) the sum of all Capacity Ownership
Shares.
The monthly charge for the Contracts and Rates rate shall be
calculated using the forecast Contracts and Rates Costs in the
Operating Plan in effect during the month for which the monthly charge
is calculated; provided, however, if the Operating Plan is amended
during the fiscal year to which such Operating Plan pertains, the
monthly charge for Contracts and Rates Cost shall be calculated using
the forecast Contracts and Rates Cost less the Contracts and Rates Cost
already billed for such fiscal year for the remaining months of the
fiscal year following such amendment.
F. Power Scheduling
The monthly charge equals:
[GRAPHIC][TIFF OMITTED]TN01MY95.081
Where
``Months'' is equal to 12, or, if the Operating Plan has, during
the fiscal year to which such Operating Plan pertains, been amended
with respect to Power Scheduling Cost, the number of full months
remaining in the fiscal year after such amended Operating Plan becomes
effective for which Capacity Owners have not been billed.
``Power Scheduling Costs'' means, upon and after the effective date
of Exhibit B pursuant to this Agreement, Bonneville's total power
scheduling costs (as described in section VII of Exhibit I) as
functionalized and allocated in accordance with section VII of Exhibit
I to determine Power Scheduling Costs for Bonneville's PNW AC Intertie.
``Capacity Ownership Percentage'' is as defined in subsection 1(k)
of each Capacity Owner's Agreement.
Power Scheduling Cost is determined in accordance with section VII
of Exhibit I as of the Effective Date. If Exhibit I is amended pursuant
to subsection 19(k) of the Agreement to provide that the Power
Scheduling Cost determined in accordance with section VII of Exhibit I
(and reflected in the Operating Plan for the fiscal year to which such
Operating Plan pertains) is directly assigned to the Capacity Owners
pursuant to such amended Exhibit I (and reflected in the Operating Plan
for the fiscal year to which such Operating Plan pertains), the
Capacity Ownership Percentage in the monthly charge calculation for
such fiscal year shall be replaced by the ratio of (a) each Capacity
Ownership Share to (b) the sum of all Capacity Ownership Shares.
The monthly charge for the Power Scheduling rate shall be
calculated using the forecast Power Scheduling Costs in the Operating
Plan in effect during the month for which the monthly charge is
calculated; provided, however, if the Operating Plan is amended during
the fiscal year to which such Operating Plan pertains, the monthly
charge for Power Scheduling Cost shall be calculated using the forecast
Power Scheduling Cost less the Power Scheduling Cost already billed for
such fiscal year for the remaining months of the fiscal year following
such amendment.
G. End of Term
The monthly charge equals:
[[Page 21164]]
[GRAPHIC][TIFF OMITTED]TN01MY95.082
Where
``Months'' is equal to 12, or, if the Operating Plan has, during
the fiscal year to which such Operating Plan pertains, been amended
with respect to End of Term Costs, the number of full months remaining
in the fiscal year after such amended Operating Plan becomes effective
for which Capacity Owners have not been billed.
``End of Term Costs'' means, upon and after the effective date of
Exhibit B pursuant to this Agreement, Bonneville's costs associated
with decommissioning the PNW AC Intertie determined in accordance with
section VIII of Exhibit I.
``Capacity Ownership Percentage'' is as defined in subsection 1(k)
of each Capacity Owner's Agreement.
The monthly charge for the End of Term rate shall be calculated
using the forecast End of Term Costs in the Operating Plan in effect
during the month for which the monthly charge is calculated; provided,
however, if the Operating Plan is amended during the fiscal year to
which such Operating Plan pertains, the monthly charge for End of Term
Costs shall be calculated using the forecast End of Term Costs less the
End of Term Cost already billed for such fiscal year for the remaining
months of the fiscal year following such amendment.
H. Replacements and Reinforcements
1. For each Replacement, the charge equals: Replacement Cost *
Capacity Ownership Percentage.
2. For each Reinforcement, the charge equals: Reinforcement Cost *
Capacity Ownership Percentage.
Where
``Replacement Cost'' means, upon and after the effective date of
Exhibit B pursuant to this Agreement, for any Replacement, the Direct
Costs, Indirect Costs, Overhead Costs, and AFUDC for such Replacement,
all capitalized to plant-in-service together with (1) simple interest
on the foregoing costs accrued from the date on which Bonneville stops
accruing AFUDC on the foregoing costs until the due date of the bill to
Capacity Owner for the foregoing costs pursuant to subparagraph
9(b)(2)(B) and (2) the costs of removal and any salvage credit
associated with removal or replacement of existing facilities.
Replacement Cost does not include capitalized general plant cost. The
method for determining Replacement Costs for Bonneville's PNW AC
Intertie is set forth in section III of Exhibit I.
``Reinforcement Cost'' means, upon and after the effective date of
Exhibit B pursuant to this Agreement, for any Reinforcement, the Direct
Costs, Indirect Costs, Overhead Costs, and AFUDC for such
Reinforcement, all capitalized to plant-in-service together with (1)
simple interest on the foregoing costs accrued from the date on which
Bonneville stops accruing AFUDC on the foregoing costs until the due
date of the bill to Capacity Owner for the foregoing costs pursuant to
subparagraph 9(b)(2)(B) and (2) the costs of removal and any salvage
credit associated with removal or replacement of existing facilities.
Reinforcement Cost does not include capitalized general plant cost. The
method for determining Reinforcement Costs for Bonneville's PNW AC
Intertie is set forth in section III of Exhibit I.
``Capacity Ownership Percentage'' is as defined in subsection 1(k)
of each Capacity Owner's Agreement.
The charge for the Replacements and Reinforcements rate shall use
the actual Replacement Cost and Reinforcement Cost in the Operating
Plan.
Section III. Adjustments
If an amendment to the Operating Plan results in a net amount that
Bonneville owes the Capacity Owners pursuant to sections II.A-G or
pursuant to section II.H, Bonneville shall refund such net amount
pursuant to paragraph 9(f)(4) of the Agreement.
The monthly charges assessed Capacity Owners under sections II.A-G
shall be adjusted, and payment or refund made with interest, pursuant
to paragraph 9(b)(2) or 9(f)(4) of the Agreement, to reflect amendments
to the Operating Plan that occur after the year to which such Operating
Plan pertains. A Capacity Owner's share of the adjustment shall be
determined using the same Capacity Ownership Percentage used in the
billings under sections II.A-G during the fiscal year that such
Operating Plan is effective.
Annual Costs Rate
Billing Provisions
I. General Provisions
A. Approval of Rates
The annual costs rate shall become effective upon interim approval
or upon final confirmation and approval by FERC. Bonneville will
request FERC approval of such rate schedule effective on the first day
of a Bonneville fiscal year.
B. Application of Billing Provisions
These Billing Provisions shall apply to bills rendered by
Bonneville pursuant to the annual costs rate.
C. Definition of Terms
The meaning of terms used in the annual costs rate shall be as
defined in the Agreement or, if no definition is provided by the
Agreement, such terms shall be defined according to applicable Federal
law.
II. Billing Information
Payment of Bills
Charges pursuant to the annual costs rate shall be included in
Bonneville's monthly power bill to Capacity Owner. Failure to receive a
power bill shall not release Capacity Owner from liability for payment.
Power bills for amounts due of $50,000 or more must be paid by direct
wire transfer. If Capacity Owner anticipates special difficulties in
meeting this requirement, Capacity Owner may request and Bonneville may
approve an exemption from this requirement. Power bills for amounts due
Bonneville under $50,000 may be paid by direct wire transfer or mailed
to the Bonneville Power Administration, P.O. Box 6040, Portland, Oregon
97228-6040, or to another location as directed by Bonneville. The
procedures to be followed in making direct wire transfers will be
provided by Bonneville's Financial Services Group and updated as
necessary.
A. Computation of Bills
1. Bonneville shall bill Capacity Owner in accordance with the
annual costs rate.
2. Capacity Owner shall provide necessary information to Bonneville
for any computation required to determine proper charges pursuant to
the Agreement and shall cooperate with Bonneville in the exchange of
additional information which may be reasonably useful for respective
operations.
3. Bills rendered pursuant to this Agreement shall be rounded to
whole dollar amounts, by eliminating any amount which is less than 50
cents and increasing any amounts from 50 cents to 99 cents to the next
higher whole dollar.
B. Billing Month
For charges pursuant to the annual costs rate the billing month
shall be the [[Page 21165]] same as for the power bill rendered by
Bonneville to Capacity Owner.
C. Due Date
Charges pursuant to the annual costs rate shall be included in the
power bill rendered by Bonneville to Capacity Owner and shall be due as
part of the power bill when such power bill is due.
D. Late Payment
The penalties for failure to pay a bill in full on or before close
of business on the due date shall be the same as those contained in the
late payment provisions in Bonneville's General Rate Schedule
Provisions in effect on the date of the bill; provided, however, that
no other provision of any such General Rate Schedule Provisions,
including, but not limited to, provisions regarding cancellation,
termination, or suspension of service, shall have application with
respect to the payment of any rate or charge pursuant to the annual
costs rate set forth in Exhibit B. Bonneville's right to suspend
service for late payment under the Agreement shall be pursuant to
paragraph 9(e)(1) of this Agreement, which right shall in no way be
limited by this section.
E. Disputed Bills
In the event of a disputed bill, full payment shall be rendered to
Bonneville and the disputed amount noted. Disputed amounts are subject
to the late payment provisions specified in section II(4) of the
Billing Provisions of this Exhibit B. Bonneville shall separately
account for the disputed amount. If it is determined that Capacity
Owner is entitled to the disputed amount, Bonneville shall refund the
disputed amount with interest, such interest to be determined by
Bonneville's Financial Services Group. In the event that Bonneville and
Capacity Owner do not resolve such dispute, Capacity Owner shall not be
prevented by this section II(5) of the Billing Provisions of this
Exhibit B from initiating arbitration pursuant to and to the extent
allowed by section 15 of this Agreement.
F. Revised Bills
If Bonneville determines that it has over- or under-charged
Capacity Owner due to a computational error or because of an amendment
to the Operating Plan in any given billing month, Bonneville may render
to Capacity Owner a revised bill.
1. If the amount of the revised bill is less than or equal to the
amount of the original bill for such billing month, the revised bill
shall replace the original bill issued by Bonneville. The revised bill
shall have the same date as the original bill.
2. If the amount of the revised bill is greater than the amount of
the original bill for such billing month, a new bill will be issued for
the difference between the revised bill and the original bill. The date
of the new bill shall be its date of issuance, and Capacity Owner shall
make payment to Bonneville as specified in the Billing Provisions of
this Exhibit B.
C. General Transmission Rate Schedule Provisions (GTRSPs)
Table of Contents
I. Adoption of Revised Transmission Rate Schedules and General
Transmission Rate Schedules Provision
A. Approval of Rates
B. General Provisions
C. Interpretation
II. Billing Factor Definitions and Billing Adjustments
A. Billing Factors
B. Billing Adjustments
III. Other Definitions
A. Agreement
B. Eastern Intertie
C. Electric Power
D. Federal Columbia River Transmission System
E. Firm Transmission Service
F. Integrated Network
G. Main Grid
H. Main Grid Distance
I. Main Grid Interconnection Terminal
J. Main Grid Miscellaneous Facilities
K. Main Grid Terminal
L. Nonfirm Transmission Service
M. Northern Intertie
N. Point of Integration (POI)
O. Point of Delivery (POD)
P. Secondary System
Q. Secondary System Distance
R. Secondary System Interconnection Terminal
S. Secondary System Intermediate Terminal
T. Secondary Transformation
U. Southern Intertie
V. Transmission Service
IV. Billing Information
A. Payment of Bills
V. Charges Under the Amended and Integrated Pacific Northwest
Coordination Agreement
A. Interchange Energy Imbalances
B. Interchange Energy Service Charge
C. Interchange Capacity Imbalances
D. Transfers Due to Forced Outages
E. Holding Interchange Energy Service Charge
F. Stored Energy Service Charge
G. Transfers to Avoid Spill
H. Transmission Service Charges
I. Special Storage Agreements
Section I. Adoption of Revised Transmission Rate Schedules and General
Transmission Rate Schedule Provisions (GTRSPs)
A. Approval of Rates
These rate schedules and GTRSPs shall become effective upon interim
approval or upon final confirmation and approval by FERC. BPA will
request FERC approval effective October 1, 1995.
B. General Provisions
These 1995 Transmission Rate Schedules and associated GTRSPs
supersede BPA's 1993 Transmission Rate Schedules and GTRSPs (which
became effective October 1, 1993) but do not supersede prior rate
schedules required by agreement to remain in force.
Transmission service provided shall be subject to the following
Acts, as amended: the Bonneville Project Act, the Regional Preference
Act (Pub. L. 88-552), the Federal Columbia River Transmission System
Act, and the Pacific Northwest Electric Power Planning and Conservation
Act, and the Energy Policy Act of 1992, Pub. L. 102-486, 106 Stat. 2776
(1992).
The meaning of terms used in the transmission rate schedules shall
be as defined in agreements or provisions which are attached to the
Agreement or as in any of the above Acts.
C. Interpretation
If a provision in the executed Agreement is in conflict with a
provision contained herein, the former shall prevail.
Section II. Billing Factor Definitions and Billing Adjustments
A. Billing Factors
1. Scheduled Demand
The largest of hourly amounts wheeled which are scheduled by the
customer during the time period specified in the rate schedules.
2. Metered Demand
The Metered Demand in kilowatts shall be the largest of the 60-
minute clock-hour integrated demands measured by meters installed at
each POD during each time period specified in the applicable rate
schedule. Such measurements shall be made as specified in the
Agreement. BPA, in determining the Metered Demand, will exclude any
abnormal readings due to or resulting from: (a) emergencies or
breakdowns on, or maintenance of, the FCRTS; or (b) emergencies on the
customer's facilities, provided that such [[Page 21166]] facilities
have been adequately maintained and prudently operated as determined by
BPA. If more than one class of power is delivered to any POD, the
portion of the metered quantities assigned to any class of power shall
be as agreed to by the parties. The amount so assigned shall constitute
the Metered Demand for such class of power.
3. Transmission Demand
The demand as defined in the Agreement.
4. Total Transmission Demand
The sum of the transmission demands as defined in the Agreement.
5. Ratchet Demand
The maximum demand established during the previous 11 billing
months. Exception: If a Transmission Demand or Total Transmission
Demand has been decreased pursuant to the terms of the Agreement during
the previous 11 billing months, such decrease will be reflected in
determining the Ratchet Demand.
B. Billing Adjustments
Average Power Factor
The adjustment for average power factor, when specified in a
transmission rate schedule or in the Agreement, shall be made in
accordance with the average power factor section of the General
Wheeling Provisions.
To maintain acceptable operating conditions on the Federal system,
BPA may restrict deliveries of power at any time that the average
leading power factor or average lagging power factor for all classes of
power delivered to such point or to such system is below 85 percent.
Section III. Other Definitions
Definitions of the terms below shall be applied to these provisions
and the Transmission Rate Schedules, unless otherwise defined in the
Agreement.
A. Agreement
An agreement between BPA and a customer to which these rate
schedules and provisions may be applied.
B. Eastern Intertie
The segment of the FCRTS for which the transmission facilities
consist of the Townsend-Garrison double-circuit 500 kV transmission
line segment including related terminals at Garrison.
C. Electric Power
Electric peaking capacity (kW) and/or electric energy (kWh).
D. Federal Columbia River Transmission System
The transmission facilities of the Federal Columbia River Power
System, which include all transmission facilities owned by the
government and operated by BPA, and other facilities over which BPA has
obtained transmission rights.
E. Firm Transmission Service
Transmission service which BPA provides for any non-BPA power
except for transmission service which is scheduled as nonfirm. If the
firm service is provided pursuant to the Agreement, the terms of the
Agreement may further define the service.
F. Integrated Network
The segment of the FCRTS for which the transmission facilities
provide the bulk of transmission of electric power within the Pacific
Northwest, excluding facilities not segmented to the network as shown
in the Wholesale Power Rate Development Study used in BPA's rate
development.
G. Main Grid
As used in the FPT and IR rate schedules, that portion of the
Integrated Network with facilities rated 230 kV and higher.
H. Main Grid Distance
As used in the FPT rate schedules, the distance in airline miles on
the Main Grid between the POI and the POD, multiplied by 1.15.
I. Main Grid Interconnection Terminal
As used in the FPT rate schedules, Main Grid terminal facilities
that interconnect the FCRTS with non-BPA facilities.
J. Main Grid Miscellaneous Facilities
As used in the FPT rate schedules, switching, transformation, and
other facilities of the Main Grid not included in other components.
K. Main Grid Terminal
As used in the FPT rate schedules, the Main Grid terminal
facilities located at the sending and/or receiving end of a line
exclusive of the Interconnection terminals.
L. Nonfirm Transmission Service
Interruptible transmission service which BPA may provide for non-
BPA power.
M. Northern Intertie
The segment of the FCRTS for which the transmission facilities
consist of two 500 kV lines between Custer Substation and the United
States-Canadian border, one 500 kV line between Custer and Monroe
Substations, and two 230 kV lines from Boundary Substation to the
United States-Canadian border, and the associated substation
facilities.
N. Point of Integration (POI)
Connection points between the FCRTS and non-BPA facilities where
non-Federal power is made available to BPA for wheeling.
O. Point of Delivery (POD)
Connection points between the FCRTS and non-BPA facilities where
non-Federal power is delivered to a customer by BPA.
P. Secondary System
As used in the FPT and IR rate schedules, that portion of the
Integrated Network facilities with operating voltage of 115 kV or 69
kV.
Q. Secondary System Distance
As used in the FPT rate schedules, the number of circuit miles of
Secondary System transmission lines between the secondary POI and the
Main Grid or the secondary POD, or the Main Grid and the secondary POD.
R. Secondary System Interconnection Terminal
As used in the FPT rate schedules, the terminal facilities on the
Secondary System that interconnect the FCRTS with non-BPA facilities.
S. Secondary System Intermediate Terminal
As used in the FPT rate schedules, the first and final terminal
facilities in the Secondary System transmission path exclusive of the
Secondary System Interconnection terminals.
T. Secondary Transformation
As used in the FPT rate schedules, transformation from Main Grid to
Secondary System facilities.
U. Southern Intertie
The segment of the FCRTS for which the major transmission
facilities consist of two 500 kV AC lines from John Day Substation to
the Oregon-California border; a portion of the 500 kV AC line from
Buckley Substation to Summer Lake Substation; when completed, the Third
AC facilities, which include Captain Jack Substation and the Alvey-
Meridian 500 kV AC line; one 1,000 kV DC line between the Celilo
Substation and the Oregon-Nevada border; and associated substation
facilities.
V. Transmission Service
As used in the MT rate schedule, Transmission Service is as defined
in [[Page 21167]] the Western Systems Power Pool Agreement.
Section IV. Billing Information
A. Payment of Bills
Bills for transmission service shall be rendered monthly by BPA.
Failure to receive a bill shall not release the customer from liability
for payment. Bills for amounts due of $50,000 or more must be paid by
direct wire transfer; customers who expect that their average monthly
bill will not exceed $50,000 and who expect special difficulties in
meeting this requirement may request, and BPA may approve, an exemption
from this requirement. Bills for amounts due BPA under $50,000 may be
paid by direct wire transfer or mailed to the Bonneville Power
Administration, P.O. Box 6040, Portland, Oregon 97228-6040, or to
another location as directed by BPA. The procedures to be followed in
making direct wire transfers will be provided by the Office of
Financial Management and updated as necessary.
1. Computation of Bills
The transmission billing determinant is the electric power
quantified by the method specified in the Agreement or Transmission
Rate Schedule. Scheduled power or metered power will be used.
The transmission customer shall provide necessary information to
BPA for any computation required to determine the proper charges for
use of the FCRTS, and shall cooperate with BPA in the exchange of
additional information which may be reasonably useful for respective
operations.
Demand and energy billings for transmission service under each
applicable rate schedule shall be rounded to whole dollar amounts, by
eliminating any amount which is less than 50 cents and increasing any
amounts from 50 cents through 99 cents to the next higher dollar.
2. Estimated Bills
At its option, BPA may elect to render an estimated bill to be
followed at a subsequent billing date by a final bill. The estimated
bill shall have the validity of and be subject to the same payment
provisions as a final bill.
3. Billing Month
For charges based on scheduled quantities, the billing month is the
calendar month. For charges based on metered quantities, the billing
month is defined as the interval between scheduled meter-reading dates.
The billing month will not exceed 31 days in any case. While it may be
necessary to read meters on a day other than the scheduled meter-
reading date, for determination of billing demand, the billing month
will cease at 2400 hours on the last scheduled meter-reading date.
Schedules will be predetermined. The customer must give 30 days notice
to request a change to the schedule.
4. Due Date
Bills shall be due by close of business on the 20th day after the
date of the bill (due date). Should the 20th day be a Saturday, Sunday,
or holiday (as celebrated by the customer), the due date shall be the
next following business day.
5. Late Payment
Bills not paid in full on or before close of business on the due
date shall be subject to a penalty charge of $25. In addition, an
interest charge of one-twentieth percent (0.05 percent) shall be
applied each day to the sum of the unpaid amount and the penalty
charge. This interest charge shall be assessed on a daily basis until
such time as the unpaid amount and penalty charge are paid in full.
Remittances received by mail will be accepted without assessment of
the charges referred to in the preceding paragraph provided the
postmark indicates the payment was mailed on or before the due date.
Whenever a power bill or a portion thereof remains unpaid subsequent to
the due date and after giving 30 days' advance notice in writing, BPA
may cancel the contract for service to the customer. However, such
cancellation shall not affect the customer's liability for any charges
accrued prior thereto under such agreement.
6. Disputed Billings
In the event of a disputed billing, full payment shall be rendered
to BPA and the disputed amount noted. Disputed amounts are subject to
the late payment provisions specified above. BPA shall separately
account for the disputed amount. If it is determined that the customer
is entitled to the disputed amount, BPA shall refund the disputed
amount with interest, as determined by BPA's Office of Financial
Management.
BPA retains the right to verify, in a manner satisfactory to the
Administrator, all data submitted to BPA for use in the calculation of
BPA's rates and corresponding rate adjustments. BPA also retains the
right to deny eligibility for any BPA rate or corresponding rate
adjustment until all submitted data have been accepted by BPA as
complete, accurate, and appropriate for the rate or adjustment under
consideration.
7. Revised Bills
As necessary, BPA may render a revised bill.
a. If the amount of the revised bill is less than or equal to the
amount of the original bill, the revised bill shall replace all
previous bills issued by BPA that pertain to the specified customer for
the specified billing period and the revised bill shall have the same
date as the replaced bill.
b. If a revision causes an additional amount to be due BPA or the
specified customer beyond the amount of the original bill, a revised
bill will be issued for the difference and the date of the revised bill
shall be its date of issue.
V. Charges Under The Amended and Integrated Pacific Northwest
Coordination Agreement
The Pacific Northwest Coordination Agreement (PNCA) is an agreement
for planned operations among the utilities and other entities that
operate the major electric generating facilities and systems in the
Pacific Northwest. The parties jointly and cooperatively plan and
coordinate their combined generation facilities so as to produce the
optimum firm load carrying capability (FLCC) of the coordinated system.
FLCC is the firm load that could be carried under coordinated operation
with critical streamflow conditions and with the use of all reservoir
storage.
In order to coordinate operations, and so that each party can meet
its individual FLCC, the PNCA provides for exchanges of energy and
capacity among the parties. The agreement sets up charges for each form
of exchange. The parties are negotiating a successor agreement to the
PNCA, and have agreed on charges to apply under the new agreement.
All terms contained herein have the meaning accorded them in the
Amended and Integrated Pacific Northwest Coordination Agreement. These
rates are to be effective on the date on which rates are effective
under the Amended and Integrated Pacific Northwest Coordination
Agreement, as provided in such Agreement. They will remain in effect
until revised rates are approved.
A. Interchange Energy Imbalances
1. Initial Deliveries of Interchange Energy
[[Page 21168]]
[GRAPHIC][TIFF OMITTED]TN01MY95.083
Heat rate = 10,000 BTU/kWh
Fuel price = Average mainline interruptible or spot market natural gas
price at Sumas, Washington, in $/MMBTU (dollars per million BTUs), for
the twelve months ending the immediately preceding June 30, as
published in Inside FERC, or, in the event that Inside FERC is no
longer published, a similar replacement publication.
Adder = 4.75 mills/kWh, adjusted each August 1 beginning August 1,
1997, by the change in the Consumer Price Index (for all urban
consumers as published by the Bureau of Labor Statistics) for Portland,
Oregon, for the twelve-month period ending the immediately preceding
June 30.
2. Return of Interchange Energy
The Energy Charge for Return of Interchange Energy shall be the
charge in effect for initial deliveries of Interchange Energy at the
time the energy being delivered as Return of Interchange Energy was
delivered as an initial delivery of Interchange Energy.
B. Interchange Energy Service Charge
1. No charge for energy returned between 7:00 a.m. and 10:00
p.m., Monday through Saturday.
2. 2.50 mills per kilowatthour of energy returned at other
hours, unless such energy was supplied during such other hours, or
its return during such other hours was requested, in either of which
events there shall be no charge.
C. Interchange Capacity Imbalances
$2.00 per kilowatt week of demand.
D. Transfers Due to Forced Outage
1. Transfer Due to Loss of Thermal Capability
$2.00 per kilowatt week of demand plus the greater of (a) the
charge for Interchange Energy Imbalances and (b) the incremental costs
of operating the resource used to supply the requested energy plus an
adder of 4.00 mills per kilowatthour. The adder shall be adjusted each
August 1 beginning August 1, 1997 by the change in the Consumer Price
Index (for all urban consumers as published by the Bureau of Labor
Statistics) for Portland, Oregon, for the twelve-month period ending
the immediately preceding June 30.
2. Transfer of Emergency Capacity
$2.00 per kilowatt week of demand plus the greater of (a) the
charge for Interchange Energy Imbalances and (b) the incremental costs
of operating the resource used to supply the requested energy. In the
event that BPA requires the receiving party to return the energy
associated with the transfer of emergency capacity, only the demand
charge shall apply.
E. Holding Interchange Energy Service Charge
1. Basic Charge
2.00 mills per kilowatthour of Holding Interchange Energy on
delivery to BPA and 1.50 mills per kilowatthour of Holding Interchange
Energy on return from BPA (3.50 mills per kilowatthour total). A loss
of Holding Interchange Energy because of spill will result in a refund
of 2.00 mills per kilowatthour of Holding Interchange Energy that is
converted to Stored Energy and spilled.
2. Reshaping Charge
2.50 mills per kilowatthour of energy. This charge shall apply, in
each Light Load Hour during which the energy delivered or returned is
greater than the average hourly amount of energy delivered or returned
that day, to the amount of energy delivered or returned during such
hour that exceeds the daily hourly average. This charge applies in
addition to the basic charge.
F. Stored Energy Service Charge
For the purposes of this rate, light load hours and heavy load
hours shall not include any hours designated by the reservoir party as
peak load hours.
1. Charges Paid on Delivery of Energy to a Reservoir Party
a. 2.00 mills per kilowatthour of energy delivered to BPA on Light
Load Hours.
b. 1.00 mill per kilowatthour of energy delivered to BPA on Heavy
Load Hours.
c. No charge for energy delivered to BPA on Peak Load Hours.
2. Charges Paid on Return of Energy Stored Less Than Two Weeks
a. 1.00 mill per kilowatthour of energy returned from BPA on Light
Load Hours.
b. 3.50 mills per kilowatthour for energy returned from BPA on
Heavy Load Hours.
c. 5.00 mills per kilowatthour for energy returned from BPA on Peak
Load Hours.
3. Charges Paid on Return of Energy Stored for Two Weeks or More
a. No charge for energy returned from BPA on Light Load Hours.
b. 2.50 mills per kilowatthour for energy returned from BPA on
Heavy Load Hours.
c. 4.00 mills per kilowatthour for energy returned from BPA on Peak
Load Hours.
4. Charges Paid on Return of Energy in Cases of Imminent Spill
a. No charge for energy returned from BPA on Light Load Hours.
b. 2.50 mills per kilowatthour for energy returned from BPA on
Heavy Load Hours.
c. 2.50 mills per kilowatthour for energy returned from BPA on Peak
Load Hours.
5. Refund of Storage Charges in Cases of Spill
In the event that stored energy is not returned to a party because
of spill on BPA's system, or in the event that BPA transfers the stored
energy to another Reservoir Party to avoid spill and the transferred
energy is later spilled, BPA will refund the charges paid under section
F.1. in an amount equal to the charges paid under such section, divided
by the kilowatthours of energy delivered to BPA, multiplied by the
kilowatthours of stored energy that is spilled.
G. Transfers To Avoid Spill
1. No charge for stored energy transferred by a Reservoir Party to
BPA in order to avoid spill.
2. The applicable Stored Energy Service charge shall apply in the
event that BPA accepts the transfer of stored energy to avoid spill and
then returns the stored energy to the original delivering party.
H. Transmission Service Charges
In any energy or capacity transaction that utilizes BPA
transmission facilities where BPA acts solely as a transferor the
following charges shall apply to both delivery and return of the
energy, if applicable:
1. 1.60 mills per kilowatthour of Interchange Energy or Generation
Impact Replacement Energy paid by the receiving party.
2. 1.75 mills per kilowatthour of Holding Interchange and Storage
Energy paid by the party requesting the return.
3. No charge for In Lieu Energy, except when the supplying or
receiving [[Page 21169]] party requires BPA, under the terms of the
PNCA, to provide transmission, in which case the charge shall be 2.00
mills per kilowatthour of In Lieu Energy paid by the party requiring
BPA to provide such transmission.
4. 2.00 mills per kilowatthour of Provisional Energy paid by the
Reservoir Party.
5. 2.00 mills per kilowatthour of energy associated with Transfers
Due to Cross-Border Flow Deviations paid by the party receiving the
transfer.
6. 2.00 mills per kilowatthour of energy associated with
Interchange Capacity and FOR Capacity paid by the party requesting the
delivery.
I. Special Storage Arrangements
1. Suggested Rate
a. 1.00 mills per kilowatthour for energy returned during Light
Load Hours.
b. 3.00 mills per kilowatthour for energy returned during other
hours.
2. Flexible Rate
The charges for special storage arrangements may be specified at a
higher rate as mutually agreed between the party requesting the special
storage arrangement and BPA.
Issued in Portland, Oregon, on April 17, 1995.
Randall W. Hardy,
Administrator and Chief Executive Officer.
[FR Doc. 95-10065 Filed 4-28-95; 8:45 am]
BILLING CODE 6450-01-P
