[Federal Register Volume 64, Number 156 (Friday, August 13, 1999)]
[Notices]
[Pages 44318-44361]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 99-20805]
[[Page 44317]]
_______________________________________________________________________
Part III
Department of Energy
_______________________________________________________________________
Bonneville Power Administraiton
_______________________________________________________________________
2002 Proposed Wholesale Power Rate Adjustment, Public Hearing, and
Opportunities for Public Review and Comment and Proposed Correction of
Errors in the Firm Power Products and Services Rate Schedule (FPS-96):
Clarifying the Applicability of the FPS-96 Contract Rate to Certain
Capacity With Energy Return Contracts, Public Hearing, and Opportunity
for Public Review and Comment: Notices
Federal Register / Vol. 64, No. 156 / Friday, August 13, 1999 /
Notices
[[Page 44318]]
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DEPARTMENT OF ENERGY
Bonneville Power Administration
2002 Proposed Wholesale Power Rate Adjustment, Public Hearing,
and Opportunities for Public Review and Comment
AGENCY: Bonneville Power Administration (BPA), Department of Energy
(DOE).
ACTION: Notice of Proposed Wholesale Power Rates and Proposed
Resolution of Certain Transmission-Related Issues.
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SUMMARY: BPA requests that all comments and documents intended to
become part of the Official Record in this process contain the file
number designation WP-02. The Pacific Northwest Electric Power Planning
and Conservation Act (Northwest Power Act), provides that BPA must
establish and periodically review and revise its rates so that they are
adequate to recover, in accordance with sound business principles, the
costs associated with the acquisition, conservation, and transmission
of electric power, and to recover the Federal investment in the Federal
Columbia River Power System (FCRPS) and other costs incurred by BPA.
By this notice, BPA announces its proposed 2002 wholesale power
rates, a proposed methodology for treatment and allocation of inter-
business line costs, and a cost allocation proposal for non-Federal
transmission for Federal and non-Federal power purchases for BPA's
current General Transfer Customers, to be effective on October 1, 2001.
The rate case proceedings also include BPA's proposal to revise the
Priority Firm Power (PF-96) rate schedule by applying a Targeted
Adjustment Charge for Uncommitted Loads, to be effective January 1,
2001.
DATES: Written comments by participants must be received by November 5,
1999, to be considered in the Record of Decision (ROD).
ADDRESSES: Written comments should be submitted to the Manager,
Corporate Communications--CK; Bonneville Power Administration; P.O. Box
12999; Portland, Oregon 97212.
FOR FURTHER INFORMATION CONTACT: Mr. Michael Hansen, Public Involvement
and Information Specialist, at the address listed above. Interested
persons may also call (503) 230-4328 or call toll-free 1-800-622-4519.
Information also may be obtained from:
Mr. Allen L. Burns, Group Vice President, Power Business Line--PS-6,
P.O. Box 3621, Portland, OR 97208
Mr. Stephen R. Oliver, Bulk Power Marketing--PSB-6, P.O. Box 3621,
Portland, OR 97208
Mr. Richard J. Itami, Eastern Power Business Area--PSE, 707 W. Main,
Suite 500, Spokane, WA 99201
Mr. John Elizalde, Western Power Business Area--PSW-6, P.O. Box 3621,
Portland, OR 97208
Responsible Official: Ms. Diane Cherry, Manager for Power Products,
Pricing and Rates, is the official responsible for the development of
BPA's wholesale power rates.
SUPPLEMENTARY INFORMATION:
Table of Contents
I. Introduction and Procedural Background
II. Purpose and Scope of Hearing
III. Public Participation
IV. Major Studies and Summary of Proposal
V. 2002 Wholesale Power Rate Schedules
A. Introduction
B. Summary of 2002 Wholesale Power Rate Schedules, 2002 GRSPs,
and New 1996 GRSPs
Part I--Introduction and Procedural Background
Section 7(i) of the Northwest Power Act, 16 U.S.C. 839e(i),
requires that BPA's rates be established according to certain
procedures. These procedures include, among other things, publication
of notice of the proposed rates in the Federal Register; one or more
hearings conducted as expeditiously as practicable by a hearing
officer; public opportunity for both oral presentation and written
submission of views; data questions and argument related to the
proposed rates; and a decision by the Administrator based on the
record. This proceeding is governed by Section 1010.9 of BPA's
Procedures Governing Bonneville Power Administration Rate Hearings, 51
FR 7611 (1986) (Procedures). These Procedures implement the statutory
section 7(i) requirements. Section 1010.7 of the Procedures prohibits
ex parte communications.
The Bonneville Project Act, 16 U.S.C. 832, the Flood Control Act of
1944, 16 U.S.C. 825s, the Federal Columbia River Transmission System
Act, 16 U.S.C. 838, and the Northwest Power Act, 16 U.S.C. 839, provide
guidance regarding BPA ratemaking. The Northwest Power Act requires BPA
to set rates that are sufficient to recover, in accordance with sound
business principles, the cost of acquiring, conserving, and
transmitting electric power, including amortization of the Federal
investment in the FCRPS over a reasonable period of years, and the
other costs and expenses incurred by the Administrator. In addition,
rates for the Federal Energy Regulatory Commission (FERC)-ordered
transmission service, including ancillary services, must satisfy
section 212(i) of the Federal Power Act, 16 U.S.C. 824k(i). Such rates
must also satisfy the comparability standard for the open access tariff
reciprocity compliance requirements of FERC Order 888.\1\ The inter-
business line and General Transfer Agreement (GTA) issues discussed
below will be used to develop ancillary service and transmission rates
in the subsequent transmission rate case.
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\1\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Order No. 888, FERC Stats. & Regs para. 31,036 (1996).
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BPA's initial proposed 2002 Wholesale Power Rate Schedules and
General Rate Schedule Provisions are published in Part V below. The
studies addressing the factors used to develop these rates are listed
in Part IV and will be available for examination on August 24, 1999, at
BPA's Public Information Center, BPA Headquarters Building, 1st Floor;
905 NE. 11th, Portland, Oregon, and will be provided to parties at the
prehearing conference to be held on August 24, 1999, from 9 a.m. to 12
p.m., Room 223, 911 NE. 11th, Portland, Oregon.
To request any of the studies by telephone, call BPA's document
request line: (503) 230-4328 or call toll-free 1-800-622-4519. Please
request the document by its listed title. Also state whether you
require the accompanying documentation (these can be quite lengthy);
otherwise the study alone will be provided. The studies and
documentation will also be available on BPA's website at www.bpa.gov/
power/ratecase.
BPA will release its 2002 initial wholesale power rate proposal on
August 24, 1999, and expects to publish a final ROD on April 7, 2000.
BPA will be conducting a formal evidentiary rate hearing attended by
regional parties. Interested parties must file petitions to intervene
in order to take part in the formal hearing. A proposed schedule for
the formal hearing is stated below. A final schedule will be
established by the Hearing Officer at the prehearing conference.
August 24, 1999: BPA files Direct Case/Prehearing Conference
October 14, 1999: Parties file Direct Cases
November 5, 1999: Close of Participant Comments
December 8, 1999: Litigants file Rebuttal Testimony
January 13, 2000: Cross-Examination
February 10, 2000: Initial Briefs Filed
[[Page 44319]]
February 17, 2000: Oral Argument before the Administrator
March 10, 2000: Draft ROD issued
March 24, 2000: Briefs on Exceptions
April 7, 2000: Final ROD--Final Studies
BPA will also be conducting eight public field hearings in cities
throughout the region. Public field hearings are an opportunity for
persons who are not parties in the formal rate hearing to have their
views included in the official record. Written transcripts will be made
at all of the field hearings. The field hearings are scheduled to begin
at 6 p.m. Following are the tentative dates and locations for the field
hearings. Confirmation of these hearing dates will be made through
mailings and public advertising or by calling BPA Corporate
Communications at the telephone number listed above. Announcements will
also be posted on BPA's wholesale power rate case website at
www.bpa.gov/power/ratecase.
September 30, 1999: Idaho Falls, Idaho
October 4, 1999: Pasco, Washington
October 5, 1999: Missoula, Montana
October 6, 1999: Spokane, Washington
October 7, 1999: Everett, Washington
October 12, 1999: Olympia, Washington
October 13, 1999: Eugene, Oregon
October 14, 1999: Portland, Oregon
Part II--Purpose and Scope of Hearing
A. Overview of the Market
The wholesale electricity market facing BPA today is different from
1996, when BPA last set rates, although BPA anticipated that the market
would become increasingly competitive. External influences such as the
national and state-by-state deregulation of the power markets, changes
in market price expectations, and continuing concerns about the
environment are factors that BPA must take into account when
establishing rates.
In 1996, it appeared that BPA's rates could exceed market prices
and BPA was not sure it could sell all its power at rates that would
recover its costs. By 2002, however, BPA's rates are anticipated to be
lower than market prices through cost cutting and careful management,
as well as an expectation that market prices could increase. Thus,
customers have now indicated an interest in purchasing more power than
BPA can produce from the FCRPS.
Despite customers' changed perceptions of the value of BPA power,
BPA's business requirements are fairly constant and are dictated by
legislation. BPA is required to sell power at a price that recovers all
costs. These costs are determined by a number of factors, including,
among other things, the cost of generating power; the costs of
protecting, mitigating, and enhancing fish and wildlife; the costs of
investing in public purposes; and the costs of repaying the Treasury
for the capital investment in the hydro system. BPA has addressed these
legislative requirements with policies that implement the statutory
directives.
The major goal for many of BPA's policies, as stated in BPA's
Subscription Strategy, is to promote the spread of the benefits of the
FCRPS as broadly as possible, with special attention given to the
residential and rural customers of the region. Due to the changing
market, BPA must balance the competing demands for its low cost power.
Public agency customers, known as preference customers, continue to
have first priority to this low cost power. For this group, BPA
proposes to sell Subscription power below market, with no increase in
the average Priority Firm Power (PF) rate from BPA's 1996 rates. BPA's
initial rate proposal also implements the Subscription Strategy plan to
offer a combination of power and financial benefits to regional
investor-owned utilities (IOUs) for the benefit of their residential
and small farm customers. BPA's rate proposal also responds to the
viability concerns of BPA's direct service industrial customers (DSIs)
by offering power below market prices.
In addition to supplying low cost power to its customer groups, BPA
policies also spread the benefits of the FCRPS to other stakeholders.
BPA uses its funds to support its share of a wide range of activities
designed to address fish and wildlife concerns by keeping open all the
options for future fish alternatives. Finally, BPA protects the
interests of the U.S. Treasury and Federal taxpayers by maintaining a
high probability of making Treasury payments on time and in full.
BPA's major Subscription goal is supported by the other three goals
of the Subscription Strategy. The second Strategy goal is to avoid rate
increases through a creative and businesslike response to markets and
additional aggressive cost reductions. By avoiding rate increases, BPA
believes that it contributes to a stable customer base comprised of all
customer groups. A stable customer base leads in turn to a stable
revenue stream which enables BPA to cover its share of fish and
wildlife and conservation costs in this rate period and in future rate
periods. BPA has committed to pursue a number of financial strategies
through rates and contracts that will allow it to meet its goal of
avoiding rate increases, such as following the recommendations of a
regional public process known as the Cost Review (described below) to
reduce costs.
The third goal of BPA's Subscription Strategy was to allow BPA to
fulfill its fish and wildlife obligations while assuring a high level
of Treasury payment. There are a wide range of options currently under
discussion for these fish and wildlife obligations. The options have
different costs associated with them, so BPA's financial tools include
methods to ensure that there will be sufficient money to meet the
costs, such as risk mitigation measures in the event that future
revenues are not as high as anticipated. BPA measures its ability to
meet its obligations by setting an 88 percent probability goal of
making its U.S. Treasury payment on time and in full. By setting a high
Treasury Payment Probability (TPP), BPA assures that all other
obligations are met before the Treasury payment is made.
BPA's Subscription Strategy has a final goal of continuing to
support its important role of being a leader in the regional effort to
capture the value of conservation and renewable resources. BPA intends
to provide market incentives for these and other emerging technologies.
BPA's Subscription goal of spreading the benefits of the FCRPS
through low cost power, as well as BPA's other goals, are reflected in
all of BPA's actions. The rate case provides only one part of
implementing BPA's goals--through rate levels and rate designs. Many
actions, such as contract negotiations and setting spending levels,
occur outside of the ratemaking process.
BPA has conducted a number of public processes over the last five
years to gain public input into how to balance these major goals. Now
it is about to start another one, the ratemaking process. Following is
a list of the other important public processes that BPA has used to
involve its customers and stakeholders in the important decisions of
how BPA will continue to provide service to the citizens of the Pacific
Northwest.
B. An Overview of the Public Processes
This section describes four major public review processes that BPA
has undertaken in the last five years. Many important policy decisions
were made in these processes. The ratemaking process is one vehicle to
implement some of the decisions made in these other processes.
1. Business Plan Public Review Process
In 1995, BPA prepared a draft and final Business Plan, including a
draft and final Environmental Impact
[[Page 44320]]
Statement (EIS). In the Business Plan, BPA announced its response to a
changing market. For the first time, BPA's costs appeared to exceed
market prices, so BPA found itself in a more competitive environment.
It responded in 1996 with products and services that were competitively
priced and that included more flexible terms. BPA began to change how
it sold power, establishing posted prices for core requirements
products, while selling other unbundled products and energy services at
negotiated prices reflecting the true costs of providing services. The
goal of these early changes was to give customers lower prices,
stability, and flexible new choices, while giving BPA greater certainty
about its expected loads and revenues. Unbundling products allowed
customers to pay for only those products and services that they needed.
Decisions made during the 1995 Business Plan process will not be
revisited in this rate case.
The rate design in the current proposal continues the basic goals
of the Business Plan, with some added features designed to allow BPA
the flexibility of passing to customers the incremental cost of
unanticipated expenses.
2. Cost Review Public Review Process
In September 1997, BPA and the Northwest Power Planning Council
initiated a process called the Cost Review of the Federal Columbia
River Power System (Cost Review). The primary objective of the Cost
Review was to ensure that BPA's long-term power and transmission costs
would be as low as possible, consistent with sound business practices,
so that BPA could maximize its ability to fully recover costs through
power rates that are at or below market prices.
The Cost Review process began with the establishment of a panel of
five executives with considerable experience managing large
organizations during periods of downsizing and competitive transition.
The panel focused on costs to be recovered through power rates for the
initial Subscription period, fiscal years (FY) 2002 through 2006. Costs
associated with fish and wildlife recovery efforts were excluded from
the scope of the Cost Review, while the following costs were recognized
as subject to significant change in the rate development process:
Short-term power purchases,
Residential Exchange Program,
General Transfer Agreements,
Federal interest and depreciation, and
Inter-business line expenses.
A draft of the panel's recommendations was circulated throughout
the region, and public comments were received during a month-long
period that included public meetings and briefings with various
interest groups. Based on comments received during this public
consultation process, the draft recommendations were modified and
presented to the Administrator, the region's Governors, the Northwest
Congressional delegation, and the U.S. House and Senate Committees on
Appropriations in March 1998.
Additionally, both the recommendations and implementation plans
were a subject of ``Issues '98,'' a public comment process conducted by
BPA in summer 1998. A key purpose of Issues '98 was to decide how the
Cost Review recommendations would be implemented.
This rate proceeding will not revisit the methodology used to
develop the Cost Review recommendations, the policy merits or wisdom of
the specific recommendations, or BPA's implementation plans. For
informational purposes only, the history of the Cost Review and
implementation of the final recommendations will be summarized in the
Revenue Requirement Study, WP-02-E-BPA-02.
3. Subscription Strategy Public Review Process
As noted previously, one of BPA's goals is to encourage the widest
possible diversified use of electric energy while recovering costs. To
define this broad concept in greater detail for the post-2001 period,
BPA engaged in a multiyear process that culminated in BPA's
Subscription Strategy.
In 1996, a regional effort began with the Comprehensive Review of
the Northwest Energy System. In December 1996, the Final Report of the
Comprehensive Review recommended that BPA capture and deliver the low-
cost benefits of the Federal hydropower system to Northwest energy
customers through a Subscription-based power sales approach.
A public process to develop a Subscription Strategy began in 1997.
This process brought together all the regional stakeholders in an
ongoing series of workgroups and meetings. BPA issued a final
Subscription Strategy and Record of Decision in December 1998.
The Subscription Strategy provides a marketing policy framework for
the power rate case. It reflects agency decisions on equitable
distribution of the electric power generated by the FCRPS to BPA's
customers within the framework of existing law. Although it did not
establish any rates or rate designs, it suggested general rate design
approaches to be considered in the formal ratemaking process.
The Subscription Strategy also provided a framework for the
bilateral negotiations with each customer that will reflect the
specific business relationships between BPA and that customer. Those
contracts will be negotiated outside this rate case.
The Subscription Strategy recognized that the FCRPS is a regional
resource, limited in size, and valued by the citizens of the Northwest.
The Strategy seeks to balance potentially competing demands on the
system, as described in the key marketing goals above. It guides the
distribution of power among competing demands, while balancing the
goals of avoiding PF rate increases, meeting fish and wildlife
obligations, and funding public purposes.
After going through an extensive public process, BPA stated in its
Subscription Strategy that it planned to offer 1,800 average megawatts
(aMW) worth of benefits for the residential and small farm consumers of
IOUs while meeting all public agency net firm load requirements. The
Strategy also stated that BPA expected to be able to meet all loads
that DSI customers asked BPA to serve. This rate case consists of the
rates to serve all BPA customers.
4. Fish and Wildlife Obligations Public Review Process
Another important public review process has occurred since BPA's
last ratemaking process in 1996. In late 1995, the Clinton
Administration and the Northwest Congressional delegation agreed to
stabilize BPA's fish and wildlife funding obligations over a six-year
period, FY 1996 through FY 2001. In September 1996, the Secretaries of
Energy, Commerce, Army and Interior signed a Memorandum of Agreement
(MOA) on behalf of five Federal agencies--BPA, the National Marine
Fisheries Service (NMFS), the U.S. Army Corps of Engineers, the U.S.
Fish and Wildlife Service (USF&W), and the Bureau of Reclamation. The
MOA represents a multiagency commitment to stable BPA funding for fish
and wildlife through FY 2001.
The MOA divides BPA's financial obligations for fish and wildlife
into two major categories: (1) The financial impacts of the system
operations called for in the 1995 Biological Opinions on the operation
of the FCRPS issued by NMFS and the USF&W, as well as certain other
operational measures specified in the MOA; and (2) a commitment of an
average of $252 million per year for capital costs,
[[Page 44321]]
operation and maintenance of fish and wildlife facilities, and
implementation of the Northwest Power Planning Council's Fish and
Wildlife Program.
In addition, the Administration committed to provide cost-sharing
assistance pursuant to section 4(h)(10)(C) of the Northwest Power Act,
16 U.S.C. Section 839b(4)(h)(10)(C), on a permanent basis for BPA's
direct fish and wildlife expenses, and also to provide section
4(h)(10)(C) credits for BPA's power purchase costs related to its fish
and wildlife programs through FY 2001. The Administration also
established a Fish Cost Contingency Fund (FCCF) consisting of U.S.
Treasury payment credits associated with section 4(h)(10)(C) that BPA
has not yet exercised. The FCCF balance of $325 million in U.S.
Treasury payment credits will be available to BPA in the case of low
water years and under certain other conditions to defray fish and other
water-related costs. Further, the Administration acknowledged that, to
the extent necessary, BPA would reduce its build-up of cash reserves in
FY 1996-2001. This action could make it more likely that BPA would have
to reschedule a portion of its annual U.S. Treasury payments in future
years.
In June 1997, all eight Senators representing the Northwest sent a
letter to Vice President Gore requesting that the Administration work
with the Northwest Congressional delegation and the four Northwest
Governors through the Governors' Transition Review Board to develop a
proposal for extending the MOA beyond FY 2001 to enable BPA to proceed
with a Subscription process for post-FY 2001 power sales. As described
above, the Subscription concept was created in 1996, during the year-
long Comprehensive Review of the Northwest Energy System. The
Comprehensive Review was sponsored by the four Northwest Governors and
studied how the region's electricity system should be structured in the
deregulated wholesale electricity market.
In the absence of a consensus on a post-FY 2001 fish and wildlife
recovery strategy by mid-1998, concerned Federal agencies and regional
stakeholders agreed that a strategy and mechanism were needed to
establish post-FY 2001 fish and wildlife funding assumptions for
Subscription and ratemaking purposes. This strategy is directed at
``keeping the options open'' for future decisions on long-term
configuration of the FCRPS, including the potential drawdown of
reservoirs behind the four Lower Snake River projects and John Day Dam
on the mainstem of the Columbia. Without such a strategy and mechanism,
BPA could not proceed with its Subscription process for post-FY 2001
power sales or its FY 2002-2006 power rates process because BPA could
not provide the necessary cost certainty to its potential post-FY 2001
power sales customers nor assure adequate funding for fish and wildlife
recovery efforts.
The Fish and Wildlife Funding Principles (Principles) were
developed in consultation with constituents, customers, other Federal
agencies, the Northwest Congressional delegation, and Columbia Basin
Tribes in an extensive public involvement process. The parties focused
on guidelines for structuring BPA's approach to Subscription and FY
2002-2006 power rates to ensure that BPA could meet its financial
obligations, including those for fish and wildlife, given
hydroconditions, market prices, fish recovery costs, and other
uncertainties. The Principles specify that BPA will take into account
the full range of potential fish and wildlife costs, as reflected in 13
long-term alternatives for configuration of the FCRPS, with each
alternative assumed to be equally likely to occur.
The Principles also state that BPA will set rates to achieve a high
probability that U.S. Treasury payments will be made in full and on
time over the five-year rate period, and that BPA will adopt rates and
contract strategies that are easy to implement and administer and that
will minimize rate impacts on Pacific Northwest power and transmission
customers. The contract strategies may include sales of Subscription
products on staggered contract terms, a Cost Recovery Adjustment Clause
(CRAC) in power sales contracts, and cost-based indexed pricing for
some Subscription products.
The Principles also commit the Administration to extend the
availability of section 4(h)(10)(C) U.S. Treasury payment credits and
any remaining FCCF funds through FY 2006 under the same terms as those
established for FY 1996 through FY 2001, and to support BPA's efforts
to implement the Cost Review recommendations.
The Principles have been reviewed by the Office of Management and
Budget and are consistent with the Administration's principles and
priorities. These Principles were published on September 16, 1998, in a
document entitled ``Fish and Wildlife Funding Principles for Bonneville
Power Administration Rates and Contracts.'' Vice President Gore
announced the establishment of the Principles on September 21, 1998.
These Principles differ significantly from the MOA. BPA and the
other participants are not establishing a budget for the FY 2002
through FY 2006 period. In fact, final decisions and approvals on a
fish and wildlife recovery strategy and funding are not expected during
this rate proceeding. Because rates are being set before decisions and
approvals are made, the Principles take into account the broad range of
potential costs associated with the hydrosystem configuration
alternatives under consideration at the time the Principles were
adopted. The Principles are intended to ensure that BPA's rates and
power sales contracts yield a very high probability of meeting all
post-FY 2001 financial obligations, including BPA funding obligations
for the fish and wildlife recovery strategy that is eventually adopted.
A number of fish and wildlife initiatives are currently being
developed, analyzed, and reviewed in the region. These include: (1) the
1999 decision on long-term configuration of the FCRPS called for in the
1995 NMFS Biological Opinion and the NMFS recovery plan for listed
salmon and steelhead; (2) the Columbia Basin Forum ``Four H'' process,
which focuses on development of a regional fish and wildlife plan
through a broad ecosystem approach that takes into consideration the
hydrosystem, habitat, hatcheries, and harvest; (3) the Multi-Species
Framework initiated by the Northwest Power Planning Council and NMFS,
in consultation with the region's Indian Tribes, to establish a
coherent array of scientifically based options for the Columbia Basin;
and (4) proposed revisions to the Northwest Power Planning Council's
Fish and Wildlife Program. BPA believes that the range of costs
associated with the 13 alternatives is sufficiently broad to cover any
eventual decision made on potential activities to be undertaken, or any
outcome reached through these other processes.
In December 1998, BPA published its implementation plan for the
Principles. This document is entitled ``How BPA's Subscription Strategy
Implements the Fish and Wildlife Funding Principles.'' See Revenue
Requirement Study Documentation, WP-02-E-BPA-02A, Volume 1, Chapter 13.
C. Scope of the 2002 Rate Case
Many of the decisions that guide BPA's marketing policies have been
made or will be made in other public review processes. This section
provides guidance to the Hearing Officer as to those matters that are
within the scope
[[Page 44322]]
of the rate case, and those that are outside the scope.
1. Spending Levels
As described above, the Cost Review recommendations and BPA's
planned implementation of those recommendations have already received
extensive public review. Pursuant to section 1010.3(f) of BPA's
Procedures, the Administrator directs the Hearing Officer to exclude
from the record any material attempted to be submitted or arguments
attempted to be made in the hearing which seek to in any way visit the
appropriateness or reasonableness of BPA's decisions on spending
levels, as included in BPA's test period revenue requirement for FYs
2002 through 2006. If, and to the extent, any re-examination of
spending levels is necessary, that re-examination will occur outside of
the rate case. Excepted from this direction on account of their
variable nature, dependency on BPA's rate case models, or timing, are:
(1) forecasts of Residential Exchange benefits; (2) forecasts of short-
term purchase power costs; (3) capital recovery matters such as
interest rate forecasts, scheduled amortization, depreciation,
replacements, and interest expense; (4) inter-business line expenses;
and (5) General Transfer Agreements.
2. Subscription Strategy
As noted above, the Subscription Strategy has already received
extensive public review and was accompanied by a Final ROD in December
1998. BPA's Subscription Strategy states that BPA will negotiate new
power sales contracts with the DSIs but make the actual level of
service under such contracts contingent on the availability of power
remaining after the close of the Subscription window. The Subscription
Strategy also notes that BPA was not prepared at the time of issuing
the Strategy to make any final decisions regarding augmentation in
order to serve DSI load. Since then BPA has decided to propose serving
approximately 1,440 aMW of DSI load. BPA does not intend to conduct a
separate public process to take comments on this proposal. Therefore,
parties to the rate case may raise and discuss any issues regarding
BPA's proposal to serve the DSIs, including any issues regarding the
potential effects of this proposal on BPA's rates.
BPA's Subscription Strategy also provides that BPA will offer the
equivalent of 1,800 aMW of Federal power to regional IOUs for the FY
2002-2006 period as a proposed settlement of the Residential Exchange
Program. BPA has recently received a suggestion to increase the amount
of power provided to regional IOUs from 1,800 aMW to 1,900 aMW for the
FY 2002-2006 period. While the Subscription Strategy accurately
reflects BPA's settlement proposal, any decision by BPA to change the
amount of power offered to the IOUs will be made outside of this rate
case. Parties to the rate case, however, may raise and discuss any
issues regarding the potential effects of such an increase on BPA's
rates.
BPA has developed the Conservation and Renewables (C&R) Discount
over the past year based on public comment. The range of public opinion
regarding the discount was discussed in the Subscription ROD. Working
from the ROD, BPA has included the following proposal as part of the
rate case. The C&R Discount will apply to all customers served under
requirements rates including the Priority Firm Power rate (PF), the
Industrial Firm Power rate (IP), the New Resource Firm Power rate (NR),
the Residential Load Firm Power rate (RL), and Slice. The total
eligibility for each customer will equal .5 mills per kilowatthour
(kWh) based on Subscription loads. Customers will be accountable for
demonstrating compliance with their expenditure target at the end of
the contract term. The discount will be applied automatically on each
customer's monthly bill. If a dividend is declared, based on better
than expected revenues, the first $15 million will be disbursed to
customers actively pursuing C&R Discount programs.
Also based on the Subscription ROD, BPA is addressing the following
issues outside the rate case. Recommendations for measures that will be
eligible for the C&R Discount will be submitted to BPA by the Regional
Technical Forum. BPA will go through a separate public process to
review and adopt these recommendations before the new rates go into
effect. BPA will conduct a separate process in the fall of 1999 to
discuss simplified eligibility criteria for small utilities and other
administrative details.
The Administrator directs the Hearing Officer to exclude from the
record any material attempted to be submitted or arguments attempted to
be made in the hearing which seek to in any way revisit decisions that
were made in BPA's Subscription Strategy, including the ROD for the
Strategy.
3. Fish and Wildlife Funding Principles
The Administrator directs the Hearing Officer to exclude from the
record any material attempted to be submitted or arguments attempted to
be made in the hearing which seek to in any way revisit the policy
merits or wisdom of the strategy to ``keep the options open'' or of the
Fish and Wildlife Funding Principles. The Principles were developed
through extensive public involvement and comment processes, and have
been adopted as policy at the highest levels of the Administration. The
rate proceeding will, however, address implementation of the Principles
in the Revenue Requirement Study (including repayment studies and risk
mitigation), the Risk Analysis Study, the Loads and Resources Study,
and the Wholesale Power Rate Development Study (including rate design,
cost allocation, and revenue forecast).
Fish and wildlife issues that will be addressed in this rate
proceeding include: (1) how the terms of access to the FCCF are modeled
in the rate proposal and their impact on TPP and rates; (2) how section
4(h)(10)(C) credits are modeled in the rate proposal and their impact
on TPP and rates; (3) the calculation and treatment of operations and
maintenance and capital investment in repayment studies and the revenue
requirement; (4) the selection, design, terms and conditions,
assumptions, treatment, and impact of planned net revenues for risk,
CRAC, indexed power sales contracts, stepped rates, and targeted
adjustment charge; (5) the RiskMod, NORM, and Tool Kit model design,
operation, inputs and outputs, and use of results; (6) the level of TPP
that is targeted, from the range of potential TPP targets established
in the Principles; and (7) the design, terms and conditions,
assumptions, and treatment of the Dividend Distribution Clause (DDC),
including the threshold for triggering a dividend distribution, the
conditions under which a dividend is distributed, and the mechanism
used to distribute dividends to certain power customers.
Included among the policy decisions, commitments, and assumptions
that are not at issue in this rate proceeding are: (1) The
Administration's decision to extend the existing terms of access to the
FCCF and to roll over the existing formula for calculating section
4(h)(10)(C) credits from the current rate period to FY 2006; (2) the
content, merits, or level of costs for the fish and wildlife recovery
strategies reflected in each of the 13 alternatives; (3) the decision
to include the full range of costs for all 13 alternatives for the
purposes of BPA's repayment study, revenue requirement, revenue
forecast, and risk management studies and strategies; (4) the TPP goal
of 88 percent over the 5-year rate period with a ``floor'' of 80
percent; (5) the policy
[[Page 44323]]
objective that rates and contracts be designed to position BPA to
achieve similarly high TPP post-FY 2006; (6) the incorporation of the
full range of costs using the same probabilistic method BPA uses for
other cost and revenue uncertainties in its ratemaking; (7) the
assumption that all 13 alternatives are equally likely to occur; (8)
the assumption that BPA's annual fish and wildlife operations and
maintenance costs have an equal probability of falling anywhere within
the range of $100 million and $179 million; (9) the adoption of a
flexible approach in order to respond to a variety of different fish
and wildlife cost scenarios, and in particular, the 35 to 45 percent
goal of total post-FY 2001 sales in contract-term lengths of three
years or less, in short-term surplus sales, and/or in cost-based
indexed sales; and (10) the goals of adopting rates and contract
strategies that are easy to implement and administer.
4. Transmission Related Issues
In setting rates for the period beginning October 1, 2001, BPA is
bifurcating its general rate proceeding into separate power and
transmission rate proceedings. BPA has voluntarily committed to
marketing its power and transmission services in a manner modeled after
the regulatory initiatives articulated by FERC in Order Nos. 888 and
889.\2\ In Order No. 888, FERC directed public utilities regulated
under the Federal Power Act to functionally unbundle transmission and
ancillary services from their wholesale power services, and to
establish separate rates for wholesale generation, transmission, and
ancillary services. Establishing BPA's power and transmission and
ancillary services rates in separate rate cases is consistent with
FERC's unbundling paradigm because it will separately resolve power and
transmission issues in the different rate cases.
---------------------------------------------------------------------------
\2\ Open Access Same-Time Information System (Formerly Real-Time
Information Networks) and Standards of Conduct (Order 889), FERC
Stats, & Regs para. 31,035 (1996).
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The proposal for new and revised wholesale power rates, the
methodology for the treatment and allocation of inter-business line
costs, and the proposed cost allocation for non-Federal transmission
costs for the Federal and non-Federal power purchases of GTA customers
are discussed below. The Administrator will decide the inter-business
line and GTA issues as part of the wholesale power rate case and will
not revisit the decision on these issues in the subsequent transmission
rate case. In addition, the scope of the wholesale power rate case does
not include the merits of the business line separation or BPA's rates
for transmission and ancillary services that will be marketed by the
Transmission Business Line (TBL). All transmission and ancillary
service rates and rate design issues will be addressed in the
subsequent transmission rate case. A notice of BPA's transmission and
ancillary services rate proposals will be announced and published in
the Federal Register at a later date.
In BPA's 2002 power rate case, BPA will decide the appropriate
treatment of costs that mutually affect both of its power and
transmission business lines, or that assess costs from one business
line to the other. The treatment of these ``inter-business line''
issues will determine whether the costs are recovered through power,
transmission, or ancillary services rates. BPA plans to address in this
power rate case: functionalization of corporate overhead costs;
treatment of generation-integration and generation step-up transformer
costs; determination of the generation input costs or unit costs that
will become the basis for certain ancillary services rates; and
determination of the costs of generation services used by the TBL,
including Remedial Action Schemes and station service.
The other transmission-related issues to be proposed in the power
rate case include all GTAs and GTA replacement costs for Federal power
deliveries and for non-Federal power deliveries, and PBL
responsibility, if any, for Delivery Segment costs. Resolution of the
GTA issues for Federal and non-Federal power deliveries will allow GTA
customers to make informed power purchase decisions and will affect the
level of the power revenue requirement.
The Administrator directs the Hearing Officer to exclude from the
record any material attempted to be submitted or arguments attempted to
be made in the hearing which seek to in any way address those
transmission items which are not within the scope of this rate case as
noted above.
5. Adjustment to PF-96 Rate: Targeted Adjustment Charge for Uncommitted
Loads
This rate case also includes a proposal to establish a charge in
the PF-96 rate schedule for customer loads that were uncommitted during
the 1996 rate case but return to BPA as firm requirements load prior to
September 30, 2001. There are no other changes to the PF-96 rate
schedule proposed in this rate case.
The Administrator directs the Hearing Officer to exclude from the
record any material attempted to be submitted or arguments attempted to
be made in the hearing on any issue regarding the proposed adjustment
of the PF-96 rate schedule other than the Targeted Adjustment Charge
for Uncommitted Loads.
D. The National Environmental Policy Act
BPA's initial rate proposal falls within the scope of the Final
Business Plan EIS, completed in June 1995. The analysis in the EIS
includes an evaluation of the environmental impacts of rate design
issues for BPA's power products and services. Comments on the Business
Plan EIS were received outside the formal rate hearing process, but
will be included in the rate case record and considered by the
Administrator in making a final decision establishing BPA's 2002 rates.
Part III--Public Participation
A. Distinguishing Between ``Participants'' and ``Parties''
BPA distinguishes between ``participants in'' and ``parties to''
the hearings. Apart from the formal hearing process, BPA will receive
comments, views, opinions, and information from ``participants,'' who
are defined in the BPA Procedures as persons who may submit comments
without being subject to the duties of, or having the privileges of,
parties. Participants' written and oral comments will be made part of
the official record and considered by the Administrator. Participants
are not entitled to participate in the prehearing conference; may not
cross-examine parties' witnesses, seek discovery, or serve or be served
with documents; and are not subject to the same procedural requirements
as parties.
Written comments by participants will be included in the record if
they are received by November 5, 1999. This date follows the
anticipated submission of BPA's and all other parties' direct cases.
Written views, supporting information, questions, and arguments should
be submitted to BPA's Manager of Corporate Communications at the
address listed in the ADDRESSES Section of this Notice. In addition,
BPA will hold several field hearings in the Pacific Northwest region.
Participants may appear at the field hearings and present oral
testimony. The transcripts of these hearings will be a part of the
record upon which the Administrator makes her final rate decisions.
Persons wishing to become a party to BPA's rate proceeding must
notify BPA
[[Page 44324]]
in writing. Petitioners may designate no more than two representatives
upon whom service of documents will be made. Petitions to intervene
shall state the name and address of the person requesting party status
and the person's interest in the hearing.
Petitions to intervene as parties in the rate proceeding are due to
the Hearing Officer by 9 a.m. on August 24, 1999. The petitions should
be directed to: Christopher Jones, Hearing Clerk--LP, Bonneville Power
Administration, 905 NE. 11th Ave., P.O. Box 12999, Portland, Oregon
97212.
Petitioners must explain their interests in sufficient detail to
permit the Hearing Officer to determine whether they have a relevant
interest in the hearing. Pursuant to Rule 1010.1(d) of BPA's
Procedures, BPA waives the requirement in Rule 1010.4(d) that an
opposition to an intervention petition be filed and served 24 hours
before the prehearing conference. Any opposition to an intervention
petition may instead be made at the prehearing conference. Any party,
including BPA, may oppose a petition for intervention. Persons who have
been denied party status in any past BPA rate proceeding shall continue
to be denied party status unless they establish a significant change of
circumstances. All timely applications will be ruled on by the Hearing
Officer. Late interventions are strongly disfavored. Opposition to an
untimely petition to intervene shall be filed and received by BPA
within two days after service of the petition.
B. Developing the Record
The record will include, among other things, the transcripts of all
hearings, any written material submitted by the parties, documents
developed by BPA staff, BPA's environmental analysis and comments
accepted on it, and other material accepted into the record by the
Hearing Officer. The Hearing Officer then will review the record, will
supplement it if necessary, and will certify the record to the
Administrator for decision.
The Administrator will develop final proposed rates based on the
entire record, including the record certified by the Hearing Officer,
comments received from participants, other material and information
submitted to or developed by the Administrator, and any other comments
received during the rate development process. The basis for the final
proposed rates first will be expressed in the Administrator's Draft
ROD. Parties will have an opportunity to respond to the Draft ROD as
provided in BPA's Procedures. The Administrator will serve copies of
the Final ROD on all parties. At the conclusion of the rate proceeding,
BPA will file its rates with FERC for confirmation and approval.
BPA must continue to meet with customers in the ordinary course of
business during the rate case. To comport with the rate case procedural
rule prohibiting ex parte communications, BPA will provide necessary
notice of meetings involving rate case issues for participation by all
rate case parties. Parties should be aware, however, that such meetings
may be held on very short notice and they should be prepared to devote
the necessary resources to participate fully in every aspect of the
rate proceeding. Consequently, parties should be prepared to attend
meetings every day during the course of the rate case.
Part IV--Major Studies and Summary of Proposal
A. Summary of Proposed 2002 Wholesale Power Rate Structure
1. List of Proposed 2002 Wholesale Power Rates
BPA is proposing five different rate schedules for its 2002
Wholesale Power Rates. All of these rate schedules are discussed in
more detail in Part V of this Notice.
a. PF-02: Priority Firm Power Rate
The PF rate schedule is comprised of three rates: the PF Preference
rate, the PF Exchange Program rate, and the PF Exchange Subscription
rate.
The PF Preference rate applies to BPA's firm power sales to be used
within the Pacific Northwest by public bodies, cooperatives, and
Federal agencies. This power is guaranteed to be continuously
available. The rate applies to the following products:
Full Service Product
Actual Partial Service Product--Simple
Actual Partial Service Product--Complex
Block Product
Block Product with Factoring
Block Product with Shaping Capacity
Slice Product
The PF Exchange Program rate applies to sales of power to regional
utilities that participate in the Residential Exchange Program
established under section 5(c) of the Northwest Power Act, 16 U.S.C.
Section 839c(c).
The PF Exchange Subscription rate applies to sales of power to
regional IOUs that participate in a settlement of the Residential
Exchange Program. This proposed settlement was established in BPA's
Subscription Strategy and includes a power sale component and a
financial component. The Strategy noted that power sales under the
settlement might be in the form of ``in lieu'' power sales under
section 5(c) of the Northwest Power Act or requirements sales under
section 5(b) of the Act. The PF Exchange Subscription rate applies to
``in lieu'' sales under the settlement.
b. RL-02: Residential Load Firm Power Rate
The RL rate applies to sales of power to regional investor-owned
utilities that participate in a settlement of the Residential Exchange
Program. As noted above, the Subscription Strategy indicated that power
sales under the settlement might be in the form of ``in lieu'' power
sales under section 5(c) of the Northwest Power Act or requirement
sales under section 5(b) of the Act. The Residential Load rate applies
to requirements sales under the settlement.
c. NR-02: New Resource Firm Power Rate
The NR rate applies to net requirements power sales to IOUs for
resale to ultimate consumers for direct consumption, for construction,
test, and start-up, and for station service. NR-02 firm power is also
available to public utility customers for serving New Large Single
Loads. This rate covers seven products:
New Large Single Loads
Full Service Product
Actual Partial Service Product--Simple
Actual Partial Service Product--Complex
Block Product
Block Product with Factoring
Block Product with Shaping Capacity
d. IP-02: Industrial Firm Power Rate
The IP rate applies to firm power sales to BPA's DSI customers. The
IP rate applies to the firm take-or-pay Block Product for DSI customers
that purchase under 2002 Industrial Firm Power Contracts. The IP-02
rate includes Targeted Adjustment Charges.
e. NF-02: Nonfirm Energy Rate
The NF rate applies to energy sold under an arrangement that does
not have the guaranteed continuous availability of firm power. The rate
provides for upward and downward pricing flexibility from an average
cost. Any time that BPA has nonfirm energy for sale, any combination of
the following rates may apply:
Standard Rate
Market Expansion Rate
Incremental Rate
Contract Rate
Western Systems Power Pool Transactions
[[Page 44325]]
End-user Rate
2. Rate Development Issues
a. Inter-Business Line Calculations
BPA is addressing certain inter-business line issues that must be
resolved in order to determine BPA's power revenue requirement and to
forecast associated revenues. In its power rate case, BPA is proposing:
a methodology for functionalizing corporate overhead costs; unit costs
for generation inputs for operating reserves and regulation ancillary
services; the generation input cost for the reactive ancillary service;
and the costs of station service and remedial action schemes needed by
the TBL. In addition, BPA is proposing an allocation of generation
integration and generation step-up transformer costs to the business
lines. BPA does not propose to recover any Delivery Segment costs
through wholesale power rates. BPA's proposal for treatment of Delivery
Segment costs will be resolved in the separate transmission rate case.
b. Rate Mitigation Costs
The average proposed PF Preference rate is about the same as in
1996. However, due to rate design changes, some utilities will
experience a rate increase and some will experience a rate decrease
based on their individual usage.
BPA has proposed to mitigate rate impacts in a number of ways.
These include modifying the monthly demand charge, capping the Load
Variance Charge, and continuing the Low Density Discount. These items
are described below. In addition, BPA proposes to have $4 million
available each year to mitigate remaining impacts on certain customers.
c. System Augmentation Costs
Under the Subscription Strategy, BPA expects to be obligated to
serve more firm load than is forecasted to be produced by the Federal
Base System (FBS) under critical water conditions. Additional firm
power will be needed to augment the FBS. For ratemaking purposes, this
firm power will be defined as FBS replacements. The costs associated
with this FBS replacement power will be allocated to power rate pools
as specified by the rate directives in the Northwest Power Act.
Power purchases for system augmentation are distinguished from
balancing power purchases by their longer duration. Balancing power
purchases are shorter-term purchases needed to serve daily and monthly
load obligations within the annual load/resource balance. System
augmentation purchases are for a year or longer, and are needed on an
annual basis to produce an annual load/resource balance.
BPA's initial proposal contains a provision that requires
purchasers of the Slice product to pay their share of the net costs of
system augmentation purchases. The net costs are the actual costs of
the system augmentation purchases minus the revenue BPA derives from
selling the equivalent amount of power at posted rates. The initial
proposal also frees Slice purchasers from paying for shorter-term
balancing purchases. These elements of the Slice product were designed
at a time when the amount of purchases necessary to augment the system
was anticipated to be relatively small.
The anticipated amount of power necessary to augment the system has
increased significantly since Slice was initially proposed. Because of
the increased augmentation purchases, the risks associated with having
Slice purchasers only obligated to share the net costs of system
augmentation may no longer be consistent with the underlying principle
of the Slice product that there would be ``no cost shifts.'' BPA
intends to examine this issue in the rate case to ensure that having
Slice purchasers share only the net costs of system augmentation does
not create a cost shift.
d. Exchange Settlement Methodology
The Subscription Strategy proposes a settlement of the Residential
Exchange Program with regional IOUs that includes both power and
monetary benefits. The total package is valued at 1800 aMW at the RL-02
or PF Exchange Subscription rate. BPA will supply at least 1000 aMW at
the RL-02 or PF Subscription rate. In addition, the remaining 800 aMW
will be provided either in the form of monetary benefits or as physical
power at BPA's discretion. For purposes of the rate case this 800 aMW
of benefits will be calculated as the difference between a market
forecasted price for power and the RL-02 or PF Exchange Subscription
rate.
BPA does not know if the IOUs will accept the proposed settlement.
(The IOUs have the choice of accepting this RL settlement or
participating in the Residential Exchange Program.) Therefore, rates
that will apply to the settlement, the RL-02 and PF Exchange
Subscription rates, as well as a rate that will apply to the
traditional Residential Exchange Program, the PF Exchange Program rate,
must be established in the rate case.
3. Changes in Rate Design
BPA redesigned its rates in BPA's 1996 rate case to send price
signals that reflected the market estimated at that time. BPA is
generally continuing the same rate design for its 2002 rates, with some
changes described below to account for current market and hydro
conditions.
The major change that BPA has made in designing its rates is to add
a ``Subscription Settlement'' step, which serves as the basis for
calculating the RL and PF Exchange Subscription rates and for
developing targeted adjustment charges for the IP and PF rates. More
detail on this change is described later in this Notice under Rates
Analysis Model.
a. Load Variance Charge
In this rate case BPA is eliminating the Load Shaping Charge and
replacing it with a Load Variance Charge. The Load Variance Charge
covers BPA's cost of standing ready to meet customers' load growth for
reasons other than annexation or retail access load gain or loss. In
addition, it provides Full and Partial Service purchasers the right to
deviate from their monthly forecasted BPA purchases due to weather,
economic business cycles, or plant energy consumption. The charge is
set at 0.80 mill per kWh and is charged against the customer's Total
Retail Load. Further details on these charges are found in the General
Rate Schedule Provisions (GRSPs) (Part V of this Notice).
b. Stepped Up Multi-Year (SUMY) Block Charge
An additional adjustment is proposed by BPA to recover the added
cost of serving a block purchase that increases over time. This is to
compensate BPA for the incremental cost of serving an additional amount
of load above first year loads.
c. Monthly Demand and Energy Charges
BPA is proposing to set monthly energy and demand charges for the
FY 2002-2006 rate period. BPA's Marginal Cost Analysis shows
substantial monthly differentiation in predicted energy rates for this
period. In setting monthly charges for energy and demand, BPA is moving
away from the six seasonal period energy charges and the annual demand
charge used in BPA's 1996 rate case.
d. Demand Adjuster
In addition to the change in the development of the demand charge,
BPA is making a change in the measurement of a customer's peak
[[Page 44326]]
demand. BPA will continue measuring Full Service customers' peak demand
coincidental to BPA's generation peak. However, Partial Service
customers' demand entitlement is measured on their system peak, and
adjusted through a Demand Adjuster to compensate for the different
demand billing basis compared to the demand billing basis of a Full
Service customer.
e. Stepped Rates
A major change in BPA's proposal is the posting of Stepped Rates.
The Rates Analysis Model (RAM) calculates an average five-year rate,
however, rates that customers pay will be differentiated between the
first three years and the last two years of the rate period. The rates
for the FY 2002 to 2004 period will be 0.6 mills per kWh below the
average five-year rate. The rates for the FY 2005 to 2006 period will
be 0.9 mills per kWh above the average five-year rate. The effective
differential is 1.5 mills per kWh.
4. New Adjustments to Rates
BPA is proposing a number of new adjustments and continuing some
existing adjustments. These adjustments are listed alphabetically and
are discussed in greater detail in Part V of this Notice.
a. Conservation and Renewables (C&R) Discount
BPA has included a C&R Discount in this rate case. In setting power
rates, BPA has included the cost of this discount by applying 0.5 mills
per kWh to loads served by posted rates and the Slice product. Within
the PBL billing process, customers will receive a C&R Discount to
encourage investment in qualifying new conservation and renewables. BPA
and its customers will reconcile the actual conservation and renewable
investments and C&R Discount eligibility. BPA is assumed to remain
revenue neutral in this program. While IP-02 rate customers are
eligible for the C&R Discount, the discount cannot be used to lower the
IP rate below the DSI Floor Rate.
b. Cost Recovery Adjustment Clause (CRAC)
BPA is including a CRAC in its rate proposal as one of the risk
mitigation tools intended to address the wide range of financial
uncertainty BPA is facing in the FYs 2002-2006 rate period. The CRAC
would cause posted power rates to be adjusted upward for one year if
actual accumulated net revenues (AANR) fall below a threshold level: -
$350 million for FYs 2001 and 2002 and $200 million for FYs 2003, 2004,
and 2005. These levels of AANR are equivalent to reserve levels of $300
million for FYs 2001 and 2002, and $500 million for FYs 2003, 2004, and
2005. In the event that AANR falls below the threshold level for any of
the years from FYs 2001-2005, rates will be increased for a 12-month
period beginning with power deliveries in the following April. (In FY
2006, rates will only be increased for six months, through the end of
FY 2006.) The CRAC is intended to generate additional revenue of up to
$125 million, $135 million, $150 million, $150 million, and $87.5
million if the threshold levels are crossed for FYs 2001, 2002, 2003,
2004, or 2005, respectively. The CRAC is projected to have an average
of about a 12 percent chance of triggering.
c. Cost-Based Indexed IP Rate
BPA is proposing a variable rate for the direct service aluminum
companies in this rate filing. It will be a rate that is adjusted
higher or lower to reflect the aluminum price forecast. The rate is
designed to go no lower than 19 mills per kWh, with an upper ceiling of
28.5 mills per kWh. The variable rate will be designed to yield an
average rate of 23.5 mills for those DSI customers that will be offered
an Industrial Power Targeted Adjustment Charge (IP TAC) rate of 23.5
mills, and 25 mills for those DSI customers that will be offered an IP
TAC rate of 25 mills.
d. Cost-Based Indexed PF Rate
This rate is designed to provide a market based alternative rate to
all firm load requirements customers that wish to diversify their power
portfolios. Customers can choose to convert their applicable PF rate to
a market indexed or floating price adjusted for BPA's risk. The
customer and BPA will choose a mutually agreeable reference point for
the index, and the index price will be based on a current market
forecast of the index selected.
e. Dividend Distribution Clause (DDC)
Because of a wide range of financial uncertainties, there is the
potential that net revenues will accumulate in excess of what will be
needed to ensure recovery of costs over time. BPA is proposing to
distribute ``dividends'' if an accumulated net revenue threshold is
exceeded and if a five-year net revenue forecast and risk analysis show
that an 88 percent Treasury Payment Probability would still be met.
The DDC proposes criteria and process requirements that the
Administrator will follow in determining the total amount of annual
dividends. BPA intends to conduct a separate public consultation
process before the beginning of the rate period to establish criteria
for apportioning the amount of annual dividends among BPA stakeholders.
f. Excess Factoring Charges
Part of the rate design in this rate case includes the
establishment of a Factoring Product and an Excess Factoring Charge.
Factoring for purposes of the Core Subscription Products is
specifically defined as the BPA service of shaping a given quantity of
megawatt-hours among hours during certain periods to follow load.
Factoring charges will be applied to Excess Load Factoring that exceeds
the benchmark limits. The Factoring Charge is limited to customers that
have dispatchable resources and that have purchased the Actual Partial
Product or the Block Product with the Factoring Product.
g. Green Energy Premium
The Green Energy Premium (GEP) will be available to customers
purchasing firm power. The GEP will be charged when a customer chooses
to designate any portion (up to 100 percent) of its Subscription
purchase as Environmentally Preferred Power.
The GEP will range from zero to $40/megawatthour depending on the
specific products and associated costs selected by each customer.
h. Industrial Power Targeted Adjustment Charge (IP TAC)
BPA is proposing to apply a TAC to all IP sales to cover the
incremental costs that it incurs from purchasing power to serve loads
beyond the amount of firm inventory in the augmented FBS. It will apply
to sales at both 23.5 mills and 25 mills. The IP TAC will prevent the
transfer of these incremental costs to other customers. It is designed
to recover costs to keep BPA whole, and is not designed to discourage
purchases from BPA.
i. Low Density Discount (LDD)
BPA is continuing to offer the LDD to utilities with low system
densities, such as rural electric cooperatives with high distribution
costs resulting from sparsely populated service areas. The LDD
principles, eligibility criteria, and discount calculation table appear
in the GRSPs.
j. PF Targeted Adjustment Charge (PF TAC)
The purpose of the PF TAC is to allow BPA the flexibility of
passing to customers the incremental cost of unanticipated or
additional loads that are not embedded in the posted rates for
[[Page 44327]]
the FYs 2002-2006 rate period. The Subscription Strategy indicated that
BPA would have inventory available during the Subscription window for
customers. After the window closes, all ``late signers'' or public
utilities with new or annexed load, including retail access load gain
or returning load, will be subject to a PF TAC. The PF TAC also applies
to requests for requirements service for customer loads previously
served by a customer's own resources. If inventory is available to
serve the request, the PF TAC is the PF rate. If BPA must buy power to
serve the load, an adjustment charge reflecting the differences between
PF-02 and BPA's cost to buy power is added to the PF rate.
BPA will provide limited exemptions from the PF TAC for those
customers requesting requirements load previously served by renewable
resources. In developing the posted rates, BPA is not forecasting that
it will receive revenues under the PF TAC.
k. Slice True-Up Adjustment
Under the Subscription Strategy, BPA decided to offer a Slice
product. Each year, BPA will calculate the difference between the Slice
Revenue Requirement's audited actual expenses and credits and the
expenses and credits that are forecast in this rate case. The true-up
will be a charge to the Slice customer's bill.
l. Unauthorized Increase Charges for Power Sales
This rate proposal includes separate penalty charges for
Unauthorized Increases in Energy and Unauthorized Increases in Demand.
These charges will be applied to deliveries that exceed contractual
entitlements for energy and demand, respectively. Further details on
these charges are found in the GRSPs (Part V of this Notice).
m. Value of Reserves
Section 7(c)(3) of the Northwest Power Act, 16 U.S.C. 839e(c)(3),
provides that the Administrator shall adjust rates to the direct
service industrial customers ``to take into account the value of power
system reserves made available to the Administrator through his rights
to interrupt or curtail service to such direct service industrial
customers.'' The DSIs may provide two types of reserves: Supplemental
Contingency Reserves and Stability Reserves. The Initial Rate proposal
assumes that Stability Reserves will be purchased by the TBL and
addressed in TBL's transmission rate case.
The PBL is proposing a new approach to procuring Supplemental
Reserves in this rate case. The PBL will purchase the most cost-
effective Supplemental Reserves or provide those reserves itself. No
Supplemental Reserves are explicitly forecasted to be provided by the
DSIs in this rate case. Any payment to the DSIs for Supplemental
Contingency Reserves will be negotiated within a specified range on an
individual customer basis rather than a credit applied to some or all
of BPA's DSI load. The range is stated in the IP rate schedule (see
Part V of this Notice).
5. Development of IP Rate/7(c)(2) Adjustment
The IP-02 rate applies to firm power sales to BPA's DSI customers,
including the firm take-or-pay Block Product for DSIs that purchase
power under 2002 Industrial Firm Power contracts. Rates for the DSIs
are set according to the rate directives contained in section 7(c) of
the Northwest Power Act, 16 U.S.C. 839e(c). Section 7(c)(1)(B) provides
that after July 1, 1985, the DSI rates will be set ``at a level which
the Administrator determines to be equitable in relation to the retail
rates charged by the public body and cooperative customers to their
industrial consumers in the region.'' 16 U.S.C. 839e(c)(1)(B). Pursuant
to section 7(c)(2), the DSI rates are to be based on BPA's ``applicable
wholesale rates'' to its preference customers and the ``typical
margins'' included by those customers in their retail industrial rates.
16 U.S.C. 839e(c)(2). Section 7(c)(3) provides that the DSI rates are
also to be adjusted to account for the value of power system reserves
provided through contractual rights that allow BPA to restrict portions
of the DSI load. 16 U.S.C. 839e(c)(3). This adjustment is typically
made through a value of reserves (VOR) credit. As described above, for
this rate case BPA is not proposing a uniform VOR credit to be applied
against DSI rates. Thus, the DSI rates shall be set equal to the
applicable wholesale rate, plus a typical margin, subject to the floor
rate test. As a final step in rate design, BPA develops monthly and
diurnally differentiated energy charges and monthly differentiated
demand charges based on allocated costs and scaled based on the results
of BPA's Marginal Cost Analysis.
The typical Industrial Margin is 0.46 mills per kWh. As stated
above, a zero VOR credit is being forecast in this rate case. Thus, the
net margin of 0.46 mills per kWh is added to the seasonal and diurnal
PF energy charges.
Section 7(c)(2) of the Northwest Power Act requires that the DSI
rates in the post-1985 period ``shall in no event be less than the
rates in effect for the contract year ending June 30, 1985.'' 16 U.S.C.
839e(c)(2). Accordingly, a floor rate test is performed to determine if
the IP rate has been set at a level below the floor rate. If so, an
adjustment is made that raises the DSI rate to recover revenues at the
floor rate and credits other customers with the increased revenue from
the DSIs. If the DSI rate has been set at a level above the floor rate,
no floor rate adjustment is necessary.
The first step in calculating the floor rate is to apply the IP-83
Standard rate charges to test period (FY 2002--2006) DSI billing
determinants. The resulting revenue figure is then divided by total IP
test period loads to arrive at an average rate in mills per kWh. This
rate is reduced by an Exchange Cost Adjustment and a deferral that were
included in the IP-83 rate. Both adjustments are made on a mills per
kWh basis.
BPA is conducting separate rate cases for power and transmission.
Therefore, BPA has removed all transmission costs from the IP-83 rate
to make a power-only floor rate comparison. These calculations result
in a DSI floor rate of 20.98 mills per kWh. Because the proposed IP
rate revenues are below the floor rate revenues, an adjustment was
necessary. Therefore, the IP rate becomes the floor rate.
6. Changes in Methodology
a. AURORA Model
AURORA is a model used to estimate the variable cost of the
marginal resource in a competitively priced energy market. In
competitive market pricing, the marginal cost of production is
equivalent to the market clearing price, which is the basis for
determining BPA's bulk power revenues in the rate case.
AURORA models wholesale energy transactions within a competitive
market pricing system. AURORA uses a demand forecast and supply cost
information to estimate marginal cost. To determine the marginal cost
in a given hour, AURORA models the dispatch of electric generating
resources in least cost order to meet the load (demand) forecast. The
price in the given hour is equal to the variable cost of the marginal
resource. Over time, AURORA adds new resources and retires old
resources based on the net present value of the resource.
b. Risk Mitigation
This rate proposal implements the TPP standard that all payments to
Treasury of the power function be
[[Page 44328]]
recovered through power rates on time and in full over the 5-year rate
period with 88 percent probability. Payments to Treasury are the lowest
priority in BPA's priority of payments. For this reason, TPP measures
the ability to recover costs in a timely fashion.
BPA has identified and analyzed its power risks and is proposing to
implement several risk mitigation tools that, taken together, achieve
an 88 percent TPP: access to the Fish Cost Contingency fund; starting
FY 2002 financial reserves; a CRAC that adjusts posted rates upward as
frequently as each year of the five-year rate period if actual
accumulated net revenues attributable to the generation function fall
below an accumulated net revenue threshold; and Planned Net Revenues
for Risk, a component of the revenue requirement that is added to
planned expenses.
c. Rates Analysis Model (RAM)
The RAM has been modified to have two steps. The first is the Rate
Design Step, which uses the Northwest Power Act's rate directives to
calculate posted rates, including the NR-02 rate and the PF Exchange
Program rate. In this first step, BPA calculates rates by: (1)
allocating costs to rate pools as noted in the Cost of Service Analysis
(COSA); (2) adjusting these results to reflect revenue credits and
statutory rate directives; and (3) using the marginal cost of power
values to shape the annual costs into energy rates across months and
time-of-day. In the second step, the Subscription Step, BPA adjusts the
rates calculated from the first step to reflect the Subscription
Strategy and to produce Subscription power rates.
7. Adjustment to PF-96: Targeted Adjustment Charge for Uncommitted
Loads
The Targeted Adjustment Charge for Uncommitted Loads (TACUL)
applies to purchases from BPA to serve customer loads that were
uncommitted during the 1996 rate case due primarily to the
diversification of customer loads. Uncommitted loads returning to BPA
firm power requirements service from January 2001, through to the
beginning of the 2002 rate period, will be subject to TACUL. The TACUL
will prevent the erosion of reserves that could occur from additional
costs of power purchases that may be required to meet customer returned
load.
BPA is currently facing an energy deficit during the time period
January 2001 to September 2001, and could face even greater deficits
should BPA receive additional requests by customers to serve returning
uncommitted load. These incremental loads will be charged the PF
Preference (PF-96) rate, plus the TACUL, which is an adjustment charge
reflecting the difference between the PF-96 rate and BPA's cost to
supply this power. BPA will calculate the cost for the TACUL at the
time a customer requests power or requests BPA to price power already
purchased under this schedule. The TACUL will be finalized prior to
signing of the final contract or before initial delivery. The TACUL
will expire with the PF-96 rate schedule.
8. Payment of Non-Federal Transmission Costs for GTA Customers' Federal
and Non-Federal Power Purchases
BPA's PBL and TBL are proposing to pay the non-Federal transmission
cost for customers' Federal and non-Federal power purchases,
respectively. PBL's and TBL's proposals are separate and distinct from
one another.
PBL proposes to continue existing GTA service to current loads for
delivery of Federal power through the FY 2001-2006 rate period.
Continuation of GTA service for Federal power deliveries is consistent
with BPA's historical practice and helps promote the widespread use of
Federal power. The GTA costs associated with delivery of Federal power
will be borne by PBL and are estimated to be around $42 million per
year through the rate period.
TBL proposes to pay up to $6.5 million annually for non-Federal
transmission to allow preference and DSI customers who have
historically been served by GTAs to avoid ``pancaked'' transmission
rates when serving their loads with non-Federal power. BPA proposes
that the forecasted non-Federal transmission cost (up to the cap of
$6.5 million) for GTA customers' non-Federal power purchases will be
included in cost of the Network segment, or its successor, when it
develops its transmission rate proposal. This rate treatment is
included in the power rate case to resolve all issues that affect GTA
customers and to enable GTA customers to make informed power purchase
decisions.
B. Studies in Support of Initial Proposal
The studies that have been prepared to support BPA's 2002 Initial
Wholesale Power Rate proposal are described in detail in this section.
Loads and Resources Study and Documentation (Study about 100 pages,
documentation about 500 pages)
Revenue Requirement Study and Documentation (Study about 250 pages,
documentation about 700 pages)
Risk Analysis Study and Documentation (Study and documentation are
combined, approximately 130 pages)
Marginal Cost Analysis Study and Documentation (Study about 50 pages,
documentation about 400 pages)
Wholesale Power Rate Development Study and Documentation (Study about
175 pages, documentation about 700 pages)
Section 7(b)(2) Rate Test Study and Documentation (Study about 50
pages, documentation about 350 pages)
1. Loads and Resources Study
The Loads and Resources Study represents the compilation of the
load and resource data necessary for developing BPA's wholesale power
rates. The Study has three major interrelated components: (a) BPA's
Federal system load forecast; (b) BPA's Federal system resource
forecast; and (c) the Federal system load and resource balances.
The Federal system load forecast is composed of customer group
sales forecasts for public utilities and Federal agencies, DSIs, IOUs,
and other BPA contractual obligations.
The Federal system resource forecast includes power generated by
both Federal and non-Federal hydroprojects, return energy associated
with BPA's existing capacity-for-energy exchanges, contracted
resources, and other BPA hydrorelated contracts. The Federal system
hydroresource estimates are derived from a hydroregulation study that
estimates generation under 50 water conditions using the operating
provisions of the Pacific Northwest Coordination Agreement. The
seasonal shape and magnitude of the Federal system hydro generation
depends on availability of all regional resources and coordination of
those resources to meet regional loads.
The projections of Federal system resources are compared with
projected Federal system firm loads for each month of Operating Years
2002-2007 (August 2001-July 2007) under 1937 water conditions. The
resulting load and resource balances yield the firm energy surplus or
deficit of the Federal system resources. Similarly, firm capacity
surpluses and deficits are determined for the same period.
2. Revenue Requirement Study
The purpose of the Revenue Requirement Study is to establish the
level of revenues from wholesale power rates necessary to recover, in
accordance with sound business principles, the FCRPS costs associated
with the
[[Page 44329]]
production, acquisition, marketing, and conservation of electric power.
Power revenue requirements include recovery of the Federal investment
in hydrogeneration, fish and wildlife recovery, and conservation;
Federal agencies' operations and maintenance expenses allocated to
power; capitalized contract expenses associated with such non-Federal
power suppliers as Energy Northwest (formerly known as the Supply
System); other purchase power expenses, such as short-term power
purchases; power marketing expenses; cost of transmission services
necessary for the sale and delivery of FCRPS power; and all other
power-related costs incurred by the Administrator pursuant to law.
Cost estimates reflect implementation of Cost Review
recommendations, the Principles, and certain components of the
Subscription Strategy. No change in repayment policy or practice is
proposed. The repayment study reflects actual implementation of the
Appropriations Refinancing Act and a number of updates to actual and
projected new repayment obligations. All new capital investments are
assumed to be financed with debt or appropriations. The study includes
a substantial level of planned net revenues to mitigate financial risk.
This risk mitigation tool, in combination with other risk mitigation
tools such as starting financial reserves, CRAC, and access to the
FCCF, is designed to achieve the 88 percent TPP standard. The adequacy
of projected revenues to recover test period revenue requirements and
to meet repayment period recovery of the Federal investments is tested
and demonstrated for the generation function.
3. Risk Analysis Study
The Risk Analysis Study evaluates both operational and non-
operational risks. The portion addressing operational risks evaluates
impacts of economic and generation resource capability variations on
BPA's ability to meet its annual U.S. Treasury payment during the rate
test period. The portion addressing non-operational risks evaluates the
impacts of uncertainties in cost projections in the revenue
requirement. The results are used to support the amount of planned net
revenues for risk that are included in the revenue requirement. The
risk variations are tested through the use of several risk simulation
models including RiskMod, which quantifies net revenue risk; RevSim, a
revenue and expense estimation model; RiskSim, a data management model;
and the Non-Operating Risk Model (NORM), which quantifies the non-
operating risks. The Risk Analysis, through the use of these models,
captures the range of ordinary risks that BPA could reasonably expect
to face during the rate test period. The models do not attempt to
capture and measure the effects of extraordinary and/or unquantifiable
risks such as State or Federal electricity deregulation legislation.
The Risk Analysis Study, with input from the Marginal Cost Analysis
(MCA), is also used for estimating purchase power expense and secondary
revenues.
4. Marginal Cost Analysis (MCA)
The MCA estimates the hourly variable cost of the marginal resource
for transactions in wholesale energy market. The specific market used
in this analysis is at the Mid-Columbia trading hub in the State of
Washington.
The MCA is used for two purposes in the BPA rate case. First, the
MCA is the basis for approximating the prices BPA may experience in the
bulk power market. The MCA estimates are therefore used to inform, but
not to directly set, the price used in BPA's bulk revenue forecast.
Second, the MCA represents BPA's marginal cost in acquiring new energy,
or the opportunity cost BPA may see in selling wholesale energy. The
MCA is therefore used in rate design to send market based price
signals.
The MCA uses a production cost model, AURORA, to estimate a market
clearing price for wholesale energy. The fundamental theory behind this
model is based on a competitive wholesale energy pricing structure. The
model dispatches resources in a least cost order to meet a specified
demand. Short-term prices are set at the variable cost of the marginal
generator. Long-term capital investment decisions are based on economic
profitability in an unregulated environment.
5. Wholesale Power Rate Development Study
The Wholesale Power Rate Development Study (WPRDS) is the primary
source for details of the rates, reflecting the results of all the
other studies. It documents the Rates Analysis Model and designs rates
for BPA's wholesale power products and services. The WPRDS documents
the development of Slice costs; the development and forecast of inter-
business line revenues and costs; the development of charges for
demand, load variance, unauthorized increase charges, and excess
factoring charges, and the development of the three and two year rates.
The end results of the WPRDS are the wholesale power rate schedules.
6. Section 7(b)(2) Rate Test Study
Section 7(b)(2) of the Northwest Power Act directs BPA to assure
that the wholesale power rates effective after July 1, 1985, to be
charged its public body, cooperative, and Federal agency customers (the
7(b)(2) Customers) for their general requirements for the rate test
period, plus the ensuing four years, are no higher than the costs of
power to those customers 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) Implementation
Methodology.
The Section 7(b)(2) rate test triggers in this proposal, causing
costs to be reallocated in the test period. The PF Preference rate
applied to the general requirements of the 7(b)(2) Customers has been
reduced by the 7(b)(2) amount while other rates, including the PF
Exchange Program rate applied to customers purchasing under the
Residential Exchange Program, have been increased by an allocation of
the 7(b)(2) amount.
Part V--2002 Wholesale Power Rate Schedules
A. Introduction
BPA's 2002 Wholesale Power Rate Schedules cover five different
rates:
PF-02: Priority Firm Power Rate
RL-02: Residential Load Firm Power Rate
NR-02: New Resource Firm Power Rate
IP-02: Industrial Firm Power Rate
NF-02: Nonfirm Energy Rate
The following section (Part B below) contains BPA's proposed 2002
wholesale power rate schedules, BPA's proposed 2002 GRSPs for power
rates, and the new 1996 GRSP for the Targeted Adjustment Charge for
uncommitted loads.
The proposed wholesale power rate schedules were prepared in
accordance with BPA's statutory authority to develop rates, including
the Bonneville Project Act of 1937, as amended, 16 U.S.C. 832 (1982);
the Flood Control Act of 1944, 16 U.S.C. 825s (1982); the Federal
Columbia River Transmission System Act (Transmission System Act), 16
U.S.C. 838 (1982); and the Northwest Power Act, 16 U.S.C. 839 (1982).
[[Page 44330]]
BPA's 2002 proposed wholesale power rate schedules and the GRSPs
associated with those rate schedules will supersede BPA's 1996 rate
schedules, except for the FPS-96 rate schedule. The FPS-96 rate
schedule continues in effect as modified in Docket No. FPS-96R. BPA
proposes that its wholesale power rate schedules, including the GRSPs
associated with these rate schedules, become effective upon interim
approval or upon final confirmation and approval by FERC. BPA currently
anticipates that it will request FERC approval of its revised rates
effective October 1, 2001.
B. Summary of 2002 Wholesale Power Rate Schedules, 2002 GRSPs, and New
1996 GRSPs
Schedule PF-02
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; and
for Construction, Test and Start-Up, and Station Service. Rates in this
schedule are in effect beginning October 1, 2001, and are available for
purchase under requirements Firm Power sales contracts for a three or
five-year period. The Slice Product is only available for public bodies
and cooperatives. Utilities participating in the Residential Exchange
Program under section 5(c) of the Northwest Power Act may purchase
Priority Firm Power pursuant to the Residential Exchange Program.
Utilities participating in settlement of the Residential Exchange
Program may purchase Priority Firm Power pursuant to their Subscription
settlement agreement. Rates under contracts that contain charges that
escalate based on BPA's Priority Firm Power rates shall be based on the
five-year rates listed in this rate schedule in addition to applicable
transmission charges.
Sales under the PF Exchange Subscription rate will be delivered in
equal hourly amounts over the rate period. The consumer bills of
participating IOUs should designate ``Benefits of the Federal Columbia
River Power System (FCRPS)'' to describe the amount of benefits each
consumer receives. Only the block product is available under this rate
schedule.
This rate schedule supersedes the PF-96 rate schedule, which went
into effect October 1, 1996. Sales under the PF-02 rate schedule are
subject to BPA's 2002 General Rate Schedule Provisions (2002 GRSPs).
Products available under this rate schedule are defined in the 2002
GRSPs. For sales under this rate schedule, bills shall be rendered and
payments due pursuant to BPA's 2002 GRSPs and billing process.
Section II. Rates Tables
The rates in this section apply to PF products. The PF Exchange
Program rates and the PF Exchange Subscription rates are shown in
Section III.
A. Demand Rate
1. Monthly Demand Rate for FY 2002 Through FY 2006
1.1 Applicability
These rates apply to customers purchasing Firm Power for three or
five years. These rates are also used to implement the Pre-Subscription
Contracts.
1.2 Rate Table
------------------------------------------------------------------------
Rate (kW-
Applicable months mo)
------------------------------------------------------------------------
January...................................................... $2.14
February..................................................... 2.06
March........................................................ 1.96
April........................................................ 1.37
May.......................................................... 1.32
June......................................................... 1.69
July......................................................... 2.12
August....................................................... 2.44
September.................................................... 2.28
October...................................................... 1.90
November..................................................... 2.31
December..................................................... 2.40
------------------------------------------------------------------
B. Energy Rate
1. Monthly Energy Rates for FY 2002 Through FY 2004
1.1 Applicability
These rates apply to customers purchasing power in the first three
years of the rate period.
1.2 Rate Table
------------------------------------------------------------------------
HLH rate LLH Rate
Applicable months (mills/ (mills/
kWh) kWh)
------------------------------------------------------------------------
January........................................... 19.06 13.45
February.......................................... 17.95 12.84
March............................................. 17.18 12.09
April............................................. 11.64 8.55
May............................................... 11.21 7.02
June.............................................. 14.51 8.61
July.............................................. 18.85 15.60
August............................................ 29.24 19.23
September......................................... 20.09 19.40
October........................................... 16.68 13.35
November.......................................... 20.56 17.77
December.......................................... 21.40 17.67
------------------------------------------------------------------------
2. Monthly Energy Rates for FY 2005 Through FY 2006
2.1 Applicability
These rates apply to purchases during the last two years of the
rate period for customers purchasing for all five years of the rate
period.
2.2 Rate Table
------------------------------------------------------------------------
HLH rate LLH Rate
Applicable months (mills/ (mills/
kWh) kWh)
------------------------------------------------------------------------
January........................................... 20.56 14.95
February.......................................... 19.45 14.34
March............................................. 18.68 13.59
April............................................. 13.14 10.05
May............................................... 12.71 8.52
June.............................................. 16.01 10.11
July.............................................. 20.35 17.10
August............................................ 30.74 20.73
September......................................... 21.59 20.90
October........................................... 18.18 14.85
November.......................................... 22.06 19.27
December.......................................... 22.90 19.17
------------------------------------------------------------------------
3. Monthly Energy Rates for FY 2002 Through FY 2006
3.1 Applicability
These rates are used to implement the Pre-Subscription Contracts.
These rates are also available to customers purchasing for all five
years of the rate period under this rate table.
3.2 Rate Table
------------------------------------------------------------------------
HLH rate LLH Rate
Applicable months (mills/ (mills/
kWh) kWh)
------------------------------------------------------------------------
January........................................... 19.66 14.05
February.......................................... 18.55 13.44
March............................................. 17.78 12.69
April............................................. 12.24 9.15
May............................................... 11.81 7.62
June.............................................. 15.11 9.21
July.............................................. 19.45 16.20
August............................................ 29.84 19.83
September......................................... 20.69 20.00
October........................................... 17.28 13.95
November.......................................... 21.16 18.37
December.......................................... 22.00 18.27
------------------------------------------------------------------------
C. Load Variance Rate
The Load Variance rate for FY 2002 through FY 2006 applies to all
customers purchasing power under this rate schedule unless specifically
excluded in Section IV below. The rate for Load Variance is 0.8 mills/
kWh.
D. Slice Rate
The monthly rate for the Slice Product is $1,381,390 per 1 percent
of the Slice System.
[[Page 44331]]
Section III. PF Exchange Rate Tables
The rates in this section apply to sales under the Residential
Exchange Program and the Subscription settlements of the Residential
Exchange Program.
A. Demand Rate
1. Monthly Demand Rate for FY 2002 Through FY 2006
1.1 Applicability
These rates apply to customers purchasing power for all five years
of the rate period under the Residential Exchange Program and to
customers purchasing power for all five years of the rate period under
Subscription settlements of the Residential Exchange Program.
1.2 Rate Table
------------------------------------------------------------------------
Rate kW-
Applicable months mo
------------------------------------------------------------------------
January...................................................... $2.14
February..................................................... 2.06
March........................................................ 1.96
April........................................................ 1.37
May.......................................................... 1.32
June......................................................... 1.69
July......................................................... 2.12
August....................................................... 2.44
September.................................................... 2.28
October...................................................... 1.90
November..................................................... 2.31
December..................................................... 2.40
------------------------------------------------------------------------
B. Energy Rate
1. PF Exchange Program Energy Rates for FY 2002 Through FY 2006
1.1 Applicability
These rates apply to customers purchasing power for all five years
of the rate period under the Residential Exchange Program.
1.2 Rate Table
------------------------------------------------------------------------
Energy
Applicable months rate
mills/kWh
------------------------------------------------------------------------
January...................................................... 30.11
February..................................................... 28.67
March........................................................ 27.52
April........................................................ 19.68
May.......................................................... 18.14
June......................................................... 22.80
July......................................................... 31.49
August....................................................... 45.01
September.................................................... 35.08
October...................................................... 27.78
November..................................................... 34.58
December..................................................... 35.43
------------------------------------------------------------------------
2. PF Exchange Subscription Energy Rates for FY 2002 Through FY 2006
2.1 Applicability
These rates apply to eligible customers purchasing power under
Subscription settlements of the Residential Exchange Program for all
five years of the rate period.
2.2 Rate Table
------------------------------------------------------------------------
HLH Rate LLH rate
Applicable months mills/kWh mills/kWh
------------------------------------------------------------------------
January........................................... 19.66 14.05
February.......................................... 18.55 13.44
March............................................. 17.78 12.69
April............................................. 12.24 9.15
May............................................... 11.81 7.62
June.............................................. 15.11 9.21
July.............................................. 19.45 16.20
August............................................ 29.84 19.83
September......................................... 20.69 20.00
October........................................... 17.28 13.95
November.......................................... 21.16 18.37
December.......................................... 22.00 18.27
------------------------------------------------------------------------
C. Load Variance Rate
The Load Variance rate for FY 2002 through FY 2006 applies to all
customers purchasing power under this rate schedule unless specifically
excluded in Section IV.H below. The rate for Load Variance is 0.8
mills/kWh.
Section IV
The rates described above apply to the following:
Section IV.A. Full Service Product
Section IV.B. Actual Partial Service Product--Simple
Section IV.C. Actual Partial Service Product--Complex
Section IV.D. Block Product
Section IV.E. Block Product with Factoring
Section IV.F. Block Product with Shaping Capacity
Section IV.G. Slice Product
Section IV.H. Customers who purchase under the Residential Exchange
Program or Subscription settlements of the Residential Exchange Program
1. Priority Firm Exchange Program Power
2. Priority Firm Exchange Subscription Power
A. Full Service Product
Purchases of the core Subscription Full Service Product are subject
to the charges specified below.
1. Priority Firm Power
1.1 Demand Charge
The charge for Demand will be:
The Purchaser's Measured Demand on the Generation System Peak as
specified in the contract multiplied by the Demand Rate from Section
II.A.
1.2 Energy Charge
The total monthly charge for energy will be the sum of (1) and (2):
(1) The Purchaser's HLH Energy Entitlement as specified in the contract
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract
multiplied by the LLH Energy Rate from Section II.B.
1.3 Load Variance Charge
The charge for Load Variance will be:
The Purchaser's Total Retail Load for the billing period multiplied by
the Load Variance Rate from Section II.C.
2. Adjustments, Charges, and Special Rate Provisions
Adjustments, Charges, and Special Rate Provisions are described in
the 2002 GRSPs. Relevant sections are identified below.
------------------------------------------------------------------------
Adjustments, charges, and special rate
provisions 2002 GRSP section
------------------------------------------------------------------------
Conservation and Renewables Discount........ II.A.
Conservation Surcharge...................... II.B.
Cost-Based Indexed PF Rate.................. II.D.
Cost Contributions.......................... II.E.
Cost Recovery Adjustment Clause............. II.F.
Dividend Distribution Clause................ II.H.
Flexible PF Rate Option..................... II.L.
Green Energy Premium........................ II.M.
Low Density Discount........................ II.P.
Rate Melding................................ II.Q.
Targeted Adjustment Charge.................. II.U.
Unauthorized Increase Charge................ II.V.
------------------------------------------------------------------------
B. Actual Partial Service Product--Simple
Purchases of the core Subscription Actual Partial Service Product--
Simple are subject to the charges specified below.
1. Priority Firm Power
1.1 Demand Charge
The charge for Demand will be:
(the Purchaser's Demand Entitlement multiplied by a Demand Adjuster) as
specified in the contract multiplied by the Demand Rate from Section
II.A.
1.2 Energy Charge
The total monthly charge for energy will be the sum of (1) and (2):
(1) The Purchaser's HLH Energy Entitlement as specified in the contract
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract
multiplied by the LLH Energy Rate from Section II.B.
1.3 Load Variance Charge
The charge for Load Variance will be:
[[Page 44332]]
The Purchaser's Total Retail Load for the billing period multiplied by
the Load Variance Rate from Section II.C.
2. Adjustments, Charges, and Special Rate Provisions
Adjustments, Charges, and Special Rate Provisions are described in
the 2002 GRSPs. Relevant sections are identified below.
------------------------------------------------------------------------
Adjustments, charges, and special rate
provisions 2002 GRSP section
------------------------------------------------------------------------
Conservation and Renewables Discount........ II.A.
Conservation Surcharge...................... II.B.
Cost-Based Indexed PF Rate.................. II.D.
Cost Contributions.......................... II.E.
Cost Recovery Adjustment Clause............. II.F.
Dividend Distribution Clause................ II.H.
Flexible PF Rate Option..................... II.L.
Green Energy Premium........................ II.M.
Low Density Discount........................ II.P.
Rate Melding................................ II.Q.
Targeted Adjustment Charge.................. II.U.
Unauthorized Increase Charge................ II.V.
------------------------------------------------------------------------
C. Actual Partial Service Product--Complex
Purchases of the core Subscription Actual Partial Service Product--
Complex are subject to the charges specified below.
1. Priority Firm Power
1.1 Demand Charge
The charge for Demand will be:
(The Purchaser's Demand Entitlement multiplied by a Demand Adjuster) as
specified in the contract multiplied by the Demand Rate from Section
II.A.
1.2 Energy Charge
The total monthly charge for energy will be the sum of (1) and (2):
(1) The Purchaser's HLH Energy Entitlement as specified in the contract
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract
multiplied by the LLH Energy Rate from Section II.B.
1.3 Load Variance Charge
The charge for Load Variance will be:
The Purchaser's Total Retail Load for the billing period multiplied by
the Load Variance Rate from Section II.C.
2. Adjustments, Charges, and Special Rate Provisions
Adjustments, Charges, and Special Rate Provisions are described in
the 2002 GRSPs. Relevant sections are identified below.
------------------------------------------------------------------------
Adjustments, charges, and special rate
provisions 2002 GRSP Section
------------------------------------------------------------------------
Conservation and Renewables Discount........ II.A.
Conservation Surcharge...................... II.B.
Cost-Based Indexed PF Rate.................. II.D.
Cost Contributions.......................... II.E.
Cost Recovery Adjustment Clause............. II.F.
Dividend Distribution Clause................ II.H.
Excess Factoring Charge..................... II.I.
Flexible PF Rate Option..................... II.L.
Green Energy Premium........................ II.M.
Low Density Discount........................ II.P.
Rate Melding................................ II.Q.
Targeted Adjustment Charge.................. II.U.
Unauthorized Increase Charge................ II.V.
------------------------------------------------------------------------
D. Block Product
Purchases of the core Subscription Block Product are subject to the
charges specified below.
1. Priority Firm Power
1.1 Demand Charge
The charge for Demand will be:
The Purchaser's Demand Entitlement as specified in the contract
multiplied by the Demand Rate from Section II.A.
1.2 Energy Charge
The total monthly charge for energy will be the sum of (1) and (2):
(1) The Purchaser's HLH Energy Entitlement as specified in the contract
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract
multiplied by the LLH Energy Rate from Section II.B.
1.3 Load Variance Charge
Not applicable to Block purchases unless the customer is also
purchasing another product to which Load Variance is applicable as
specified by contract.
2. Adjustments, Charges, and Special Rate Provisions
Adjustments, Charges, and Special Rate Provisions are described in
the 2002 GRSPs. Relevant sections are identified below.
------------------------------------------------------------------------
Adjustments, charges, and special rate
provisions 2002 GRSP section
------------------------------------------------------------------------
Conservation and Renewables Discount........ II.A.
Conservation Surcharge...................... II.B.
Cost-Based Indexed PF Rate.................. II.D.
Cost Contributions.......................... II.E.
Cost Recovery Adjustment Clause............. II.F.
Dividend Distribution Clause................ II.H.
Flexible PF Rate Option..................... II.L.
Green Energy Premium........................ II.M.
Low Density Discount........................ II.P.
Rate Melding................................ II.Q.
Stepped Up Multiyear Block (SUMY)........... II.S.
Targeted Adjustment Charge.................. II.U.
Unauthorized Increase Charge................ II.V.
------------------------------------------------------------------------
E. Block Product With Factoring
Purchases of the core Subscription Block Product with Factoring are
subject to the charges specified below.
1. Priority Firm Power
1.1 Demand Charge
The charge for Demand will be:
(The Purchaser's Demand Entitlement multiplied by a Demand Adjuster) as
specified in the contract multiplied by the Demand Rate from Section
II.A.
1.2 Energy Charge
The total monthly charge for energy will be the sum of (1) and (2):
(1) The Purchaser's HLH Energy Entitlement as specified in the contract
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract
multiplied by the LLH Energy Rate from Section II.B.
1.3 Load Variance Charge
Not applicable to Block purchases unless the customer is also
purchasing another product to which Load Variance is applicable as
specified by contract.
2. Adjustments, Charges, and Special Rate Provisions
Adjustments, Charges, and Special Rate Provisions are described in
the 2002 GRSPs. Relevant sections are identified below.
------------------------------------------------------------------------
Adjustments, charges, and special rate
provisions 2002 GRSP section
------------------------------------------------------------------------
Conservation and Renewables Discount........ II.A.
Conservation Surcharge...................... II.B.
Cost-Based Indexed PF Rate.................. II.D.
Cost Contributions.......................... II.E.
Cost Recovery Adjustment Clause............. II.F.
Dividend Distribution Clause................ II.H.
Excess Factoring Charge..................... II.I.
Flexible PF Rate Option..................... II.L.
Green Energy Premium........................ II.M.
Low Density Discount........................ II.P.
Rate Melding................................ II.Q.
Stepped Up Multiyear Block (SUMY)........... II.S.
Targeted Adjustment Charge.................. II.U.
Unauthorized Increase Charge................ II.V.
------------------------------------------------------------------------
F. Block Product With Shaping Capacity
Purchases of the core Subscription Block Product with Shaping
Capacity
[[Page 44333]]
are subject to the charges specified below.
1. Priority Firm Power
1.1 Demand Charge
The charge for Demand will be:
The Purchaser's Demand Entitlement as specified in the contract
multiplied by the Demand Rate from Section II.A.
1.2 Energy Charge
The total monthly charge for energy will be the sum of (1) and (2):
(1) The Purchaser's HLH Energy Entitlement as specified in the contract
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract
multiplied by the LLH Energy Rate from Section II.B.
1.3 Load Variance Charge
Not applicable to Block purchases unless the customer is also
purchasing another product to which Load Variance is applicable as
specified by contract.
2. Adjustments, Charges, and Special Rate Provisions
Adjustments, Charges, and Special Rate Provisions are described in
the 2002 GRSPs. Relevant sections are identified below.
------------------------------------------------------------------------
Adjustments, charges, and special rate
provisions 2002 GRSP section
------------------------------------------------------------------------
Conservation and Renewables Discount........ II.A.
Conservation Surcharge...................... II.B.
Cost-Based Indexed PF Rate.................. II.D.
Cost Contributions.......................... II.E.
Cost Recovery Adjustment Clause............. II.F.
Dividend Distribution Clause................ II.H.
Flexible PF Rate Option..................... II.L.
Green Energy Premium........................ II.M.
Low Density Discount........................ II.P.
Rate Melding................................ II.Q.
Stepped Up Multiyear Block (SUMY)........... II.S.
Targeted Adjustment Charge.................. II.U.
Unauthorized Increase Charge................ II.V.
------------------------------------------------------------------------
G. Slice Product
Purchases of the Subscription Slice Product are limited to Public
Body Customers and are subject to the charges specified below.
1. Slice Product Charge
The charge for the Slice Product will be:
The elected Slice Percentage expressed as a decimal (.01 = 1%)
multiplied by 100 multiplied by the Slice Rate in Section II.D.
2. Adjustments, Charges, and Special Rate Provisions
Adjustments, Charges, and Special Rate Provisions are described in
the 2002 GRSPs. Relevant sections are identified below.
------------------------------------------------------------------------
Adjustments, charges, and special rate
provisions 2002 GRSP section
------------------------------------------------------------------------
Conservation and Renewables Discount........ II.A.
Cost-Based Indexed PF Rate.................. II.D.
Cost Contributions.......................... II.E.
Low Density Discount........................ II.P.
Slice True-Up Adjustment.................... II.R.
Unauthorized Increase Charge................ II.V.
------------------------------------------------------------------------
H. Customers Who Purchase Under Residential Exchange Program or
Subscription Settlements of the Residential Exchange Program
The PF Exchange rates include: (1) the PF Exchange Program rate;
and (2) the PF Exchange Subscription rate.
1. Priority Firm Exchange Program Power
This PF Exchange Program rate applies to the traditional
implementation of the Residential Exchange Program.
a. Priority Firm Exchange Program Power Charges
1.1 Demand Charge
The charge for Demand will be:
(The Purchaser's Billing Demand, which is calculated by applying the
load factor, determined as specified in the Residential Exchange
Program agreement, to the Billing Energy for each billing period)
multiplied by the Demand Rate from Section III.A.
1.2 Energy Charge
The monthly charge for energy will be:
(The Purchaser's Billing Energy, which is the energy associated with
the utility's residential load for each billing period computed in
accordance with the provisions of the Purchaser's Residential Exchange
Program agreement) multiplied by the Energy Rate from Section III.B.1.
1.3 Load Variance Charge
The charge for Load Variance is embedded in the energy charge.
b. Transmission Charges
Customers purchasing under this rate schedule are charged for
transmission services under the NT rate schedule or its successor.
Customers purchasing under this rate schedule are charged for Load
Regulation under the applicable charge established by the TBL or its
successor.
c. Adjustments, Charges, and Special Rate Provisions
------------------------------------------------------------------------
2002
Adjustments, charges, and special rate provisions GRSP
section
------------------------------------------------------------------------
Conservation and Renewables Discount......................... II.A.
Conservation Surcharge....................................... II.B.
Cost Contributions........................................... II.E.
Cost Recovery Adjustment Clause.............................. II.F.
Dividend Distribution Clause................................. II.H.
Green Energy Premium......................................... II.M.
Low Density Discount......................................... II.P.
Unauthorized Increase Charge................................. II.V.
------------------------------------------------------------------------
2. Priority Firm Exchange Subscription Power
This PF Exchange Subscription rate applies to sales under section
5(c) of the Northwest Power Act to investor-owned utilities (IOU) that
participate in a settlement of the Residential Exchange Program as
described in BPA's Subscription Strategy.
a. Priority Firm Exchange Subscription Power Charges
1.1 Demand Charge
The charge for Demand will be:
The Purchaser's Contract Demand multiplied by the Demand Rate from
Section III.A.
1.2 Energy Charge
The total monthly charge for energy will be the sum of (1) and (2):
(1) The Purchaser's HLH Contract Energy multiplied by the HLH Energy
Rate from Section III.B.2.
(2) The Purchaser's LLH Contract Energy multiplied by the LLH Energy
Rate from Section III.B.2.
1.3 Load Variance Charge
Not applicable.
b. Adjustments, Charges, and Special Rate Provisions
------------------------------------------------------------------------
2002
Adjustments, charges, and special rate provisions GRSP
section
------------------------------------------------------------------------
Conservation and Renewables Discount......................... II.A.
Conservation Surcharge....................................... II.B.
Cost-Based Indexed PF Rate................................... II.D.
Cost Contributions........................................... II.E.
Cost Recovery Adjustment Clause.............................. II.F.
Dividend Distribution Clause................................. II.H.
Green Energy Premium......................................... II.M.
Low Density Discount......................................... II.P.
Unauthorized Increase Charge................................. II.V.
------------------------------------------------------------------------
Section IV. Transmission
All customers will need to obtain transmission for delivery of
products
[[Page 44334]]
listed under this rate schedule, except for the exchange product listed
under Section IV.H.1.
Schedule RL-02
Residential Load Firm Power Rate
Section I. Availability
This schedule is available for the contract purchase of Firm Power
to be used within the Pacific Northwest. The Residential Load (RL) Firm
Power Rate is available to investor-owned utilities (IOUs) under net
requirement contracts for resale to ultimate residential consumers for
direct consumption. Further, in order to purchase under this rate, the
IOU must agree to waive its right to request benefits under section
5(c) of the Northwest Power Act for the term of the contract. Each IOU
will be able to purchase a specified amount of Firm Power at the RL-02
rate. Additional sales of requirements power to IOUs will be made at
the NR-02 rate.
The product will be delivered in equal hourly amounts over the rate
period. The consumer bills of participating IOUs should designate
``Benefits of the Federal Columbia River Power System (FCRPS)'' to
describe the amount of benefits each consumer receives.
Rates in this schedule are available for purchases under
requirements sales contracts for a five-year period. Only the block
product is available under this rate schedule. Sales under this
schedule are subject to BPA's 2002 General Rate Schedule Provisions
(2002 GRSPs) and billing process.
Section II. Rates Tables
The rates for the RL Firm Power product are identified below.
A. Demand Rate
1. Monthly Demand for FY 2002 through FY 2006
1.1 Applicability
These rates apply to eligible customers purchasing power for five
years.
1.2 Rate Table
------------------------------------------------------------------------
Rate (kW-
Applicable months mo)
------------------------------------------------------------------------
January...................................................... $2.14
February..................................................... 2.06
March........................................................ 1.96
April........................................................ 1.37
May.......................................................... 1.32
June......................................................... 1.69
July......................................................... 2.12
August....................................................... 2.44
September.................................................... 2.28
October...................................................... 1.90
November..................................................... 2.31
December..................................................... 2.40
------------------------------------------------------------------------
B. Energy Rate
1. Monthly Energy Rates for FY 2002 Through FY 2006
1.1 Applicability
These rates apply to eligible customers purchasing power for all
five years of the rate period.
1.2 Rate Table
------------------------------------------------------------------------
HLH rate LLH rate
Applicable months (mills/ (mills/
kWh) kWh)
------------------------------------------------------------------------
January........................................... 19.66 14.05
February.......................................... 18.55 13.44
March............................................. 17.78 12.69
April............................................. 12.24 9.15
May............................................... 11.81 7.62
June.............................................. 15.11 9.21
July.............................................. 19.45 16.20
August............................................ 29.84 19.83
September......................................... 20.69 20.00
October........................................... 17.28 13.95
November.......................................... 21.16 18.37
December.......................................... 22.00 18.27
------------------------------------------------------------------------
C. Load Variance Rate
Not applicable.
Section III. Billing Factors and Adjustments
Eligible customers purchasing power under a contract implementing
Subscription settlements of the Residential Exchange Program are
subject to the charges specified below.
1. Residential Load Firm Power
1.1 Demand Charge
The charge for Demand will be:
The Purchaser's Contract Demand multiplied by the Demand Rate from
Section II.A.
1.2 Energy Charge
The total monthly charge for energy will be the sum of (1) and (2):
(1) The Purchaser's HLH Contract Energy multiplied by the HLH Energy
Rate from Section II.B; and
(2) The Purchaser's LLH Contract Energy multiplied by the LLH Energy
Rate from Section II.B.
2. Adjustments, Charges, and Special Rate Provisions
Adjustments, Charges, and Special Rate Provisions are described in
the 2002 GRSPs. Relevant sections are identified below.
------------------------------------------------------------------------
2002
Adjustments, charges, and special rate provisions GRSP
section
------------------------------------------------------------------------
Conservation and Renewables Discount......................... II.A.
Conservation Surcharge....................................... II.B.
Cost Contributions........................................... II.E.
Cost Recovery Adjustment Clause.............................. II.F.
Dividend Distribution Clause................................. II.H.
Green Energy Premium......................................... II.M.
Low Density Discount......................................... II.P.
Unauthorized Increase Charge................................. II.V.
------------------------------------------------------------------------
Section IV. Transmission
All customers will need to obtain transmission for delivery of
products listed under this rate schedule unless BPA's Power Business
Line (PBL) and the customer negotiate otherwise at time of sale.
Schedule NR-02
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 (IOU) under net
requirements contracts for resale to ultimate consumers; for direct
consumption; and for 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 (NLSL), as defined by the Northwest
Power Act. That portion of the utility's load placed on BPA that is
attributable to the NLSL will be billed under this rate schedule.
Rates in this schedule are available for purchases under contracts
for which power deliveries begin on or after October 1, 2001 (2002
Contract), for a three or five-year period. Products available under
this rate schedule are defined in BPA's 2002 General Rate Schedule
Provisions (2002 GRSPs).
This rate schedule supersedes the NR-96 rate schedule, which went
into effect October 1, 1996. Sales under the NR-02 rate schedule are
subject to BPA's 2002 GRSPs and billing process.
Section II. Rates Tables
The rates in this section apply to NR products.
A. Demand Rate
1. Monthly Demand Rate for FY 2002 Through FY 2006
1.1 Applicability
These rates apply to eligible customers purchasing power for three
or five years.
[[Page 44335]]
1.2 Rate Table
------------------------------------------------------------------------
Rate (kW-
Applicable months mo)
------------------------------------------------------------------------
January...................................................... $2.14
February..................................................... 2.06
March........................................................ 1.96
April........................................................ 1.37
May.......................................................... 1.32
June......................................................... 1.69
July......................................................... 2.12
August....................................................... 2.44
September.................................................... 2.28
October...................................................... 1.90
November..................................................... 2.31
December..................................................... 2.40
------------------------------------------------------------------------
B. Energy Rate
1. Monthly Energy Rates for FY 2002 Through FY 2004
1.1 Applicability
These rates apply to eligible customers purchasing power in the
first three years of the rate period.
1.2 Rate Table
------------------------------------------------------------------------
HLH rate LLH rate
Applicable months (mills/ (mills/
kWh) kWh)
------------------------------------------------------------------------
January........................................... 40.75 29.41
February.......................................... 38.50 28.19
March............................................. 36.96 26.68
April............................................. 25.76 19.52
May............................................... 24.88 16.41
June.............................................. 31.56 19.64
July.............................................. 40.34 33.76
August............................................ 61.32 41.09
September......................................... 42.83 41.44
October........................................... 35.94 29.22
November.......................................... 43.78 38.15
December.......................................... 45.47 37.95
------------------------------------------------------------------------
2. Monthly Energy Rates for FY 2005 Through FY 2006
2.1 Applicability
These rates apply to purchases during the last two years of the
rate period for eligible customers purchasing for all five years of the
rate period.
2.2 Rate Table
------------------------------------------------------------------------
HLH rate LLH rate
Applicable months (mills/ (mills/
kWh) kWh)
------------------------------------------------------------------------
January........................................... 42.25 30.91
February.......................................... 40.00 29.69
March............................................. 38.46 28.18
April............................................. 27.26 21.02
May............................................... 26.38 17.91
June.............................................. 33.06 21.14
July.............................................. 41.84 35.26
August............................................ 62.82 42.59
September......................................... 44.33 42.94
October........................................... 37.44 30.72
November.......................................... 45.28 39.65
December.......................................... 46.97 39.45
------------------------------------------------------------------------
3. Monthly Energy Rates for FY 2002 Through FY 2006
3.1 Applicability
These rates apply to eligible customers purchasing for all five
years of the rate period under this rate table.
3.2 Rate Table
------------------------------------------------------------------------
HLH rate LLH rate
Applicable months (mills/ (mills/
kWh) kWh)
------------------------------------------------------------------------
January........................................... 41.35 30.01
February.......................................... 39.10 28.79
March............................................. 37.56 27.28
April............................................. 26.36 20.12
May............................................... 25.48 17.01
June.............................................. 32.16 20.24
July.............................................. 40.94 34.36
August............................................ 61.92 41.69
September......................................... 43.43 42.04
October........................................... 36.54 29.82
November.......................................... 44.38 38.75
December.......................................... 46.07 38.55
------------------------------------------------------------------------
C. Load Variance Rate
The Load Variance rate for FY 2002 through FY 2006 is applicable to
all customers purchasing power under this rate schedule unless
specifically excluded in Section III below. The rate for Load Variance
is 0.8 mills/kWh.
Section III. Billing Factors, and Adjustments for Each NR Product
This rate schedule contains seven subsections, corresponding to the
products to which this rate schedule applies. The following seven
products are available to serve NLSLs, or other loads served at the NR-
02 rate.
Section III.A. New Large Single Load
Section III.B. Full Service Product
Section III.C. Actual Partial Service Product--Simple
Section III.D. Actual Partial Service Product--Complex
Section III.E. Block Product
Section III.F. Block Product with Factoring
Section III.G. Block Product with Shaping Capacity
A. New Large Single Load (NLSL) Service Product
Purchases of New Resource Firm Power to serve a NLSL are subject to
the charges specified below.
1. New Resource Firm Power
1.1 Demand Charge
The charge for Demand will be:
The NLSLs Demand Entitlement as specified in the contract multiplied by
the Demand Rate from Section II.A.
1.2 Energy Charge
The total monthly charge for energy will be the sum of (1) and (2),
unless BPA and the Purchaser agree to bill based on a contract amount
of energy.
(1) The NLSLs HLH Energy Entitlement as specified in the contract
multiplied by the HLH Energy Rate from Section II.B.
(2) The NLSLs LLH Energy Entitlement as specified in the contract
multiplied by the LLH Energy Rate from Section II.B.
1.3 Load Variance Charge
The charge for Load Variance will be:
The NLSLs Measured Energy for the billing period as specified in the
contract multiplied by the Load Variance Rate from Section II.C.
If the customer is already paying the Load Variance Charge on the
NLSL load through this or another rate schedule, this charge does not
apply.
2. Adjustments, Charges, and Special Rate Provisions
Adjustments, Charges, and Special Rate Provisions are described in
the 2002 GRSPs. Relevant sections are identified below.
------------------------------------------------------------------------
2002
Adjustments, charges, and special rate provisions GRSP
section
------------------------------------------------------------------------
Conservation and Renewables Discount......................... II.A.
Conservation Surcharge....................................... II.B.
Cost Contributions........................................... II.E.
Cost Recovery Adjustment Clause.............................. II.F.
Dividend Distribution Clause................................. II.H.
Flexible NR Rate Option...................................... II.K.
Green Energy Premium......................................... II.M.
Low Density Discount......................................... II.P.
Rate Melding................................................. II.Q.
Targeted Adjustment Charge................................... II.U.
Unauthorized Increase Charge................................. II.V.
------------------------------------------------------------------------
B. Full Service Product
Purchases of the core Subscription Full Service Product are subject
to the charges specified below.
1. New Resource Firm Power
1.1 Demand Charge
The charge for Demand will be:
The Purchaser's Measured Demand on the Generation System Peak as
specified in the contract multiplied by the Demand Rate from Section
II.A.
1.2 Energy Charge
The total monthly charge for energy will be the sum of (1) and (2):
(1) The Purchaser's HLH Energy Entitlement as specified in the contract
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract
multiplied by the LLH Energy Rate from Section II.B.
[[Page 44336]]
1.3 Load Variance Charge
The charge for Load Variance will be:
The Purchaser's Total Retail Load for the billing period multiplied by
the Load Variance Rate from Section II.C.
2. Adjustments, Charges, and Special Rate Provisions
Adjustments, Charges, and Special Rate Provisions are described in
the 2002 GRSPs. Relevant sections are identified below.
------------------------------------------------------------------------
2002
Adjustments, charges, and special rate provisions GRSP
section
------------------------------------------------------------------------
Conservation and Renewables Discount......................... II.A.
Conservation Surcharge....................................... II.B.
Cost Contributions........................................... II.E.
Cost Recovery Adjustment Clause.............................. II.F.
Dividend Distribution Clause................................. II.H.
Flexible NR Rate Option...................................... II.K.
Green Energy Premium......................................... II.M.
Low Density Discount......................................... II.P.
Rate Melding................................................. II.Q.
Targeted Adjustment Charge................................... II.U.
Unauthorized Increase Charge................................. II.V.
------------------------------------------------------------------------
C. Actual Partial Service Product--Simple
Purchases of the core Subscription Actual Partial Service Product--
Simple are subject to the charges specified below.
1. New Resource Firm Power
1.1 Demand Charge
The charge for Demand will be:
(The Purchaser's Demand Entitlement multiplied by a Demand Adjuster) as
specified in the contract multiplied by the Demand Rate from Section
II.A.
1.2 Energy Charge
The total monthly charge for energy will be the sum of (1) and (2):
(1) The purchaser's HLH Energy Entitlement as specified in the contract
multiplied by the HLH Energy Rate from Section II.B.
(2) The purchaser's LLH Energy Entitlement as specified in the contract
multiplied by the LLH Energy Rate from Section II.B.
1.3 Load Variance Charge
The charge for Load Variance will be:
The purchaser's Total Retail Load for the billing period multiplied by
the Load Variance from Section II.C.
2. Adjustments, Charges, and Special Rate Provisions
Adjustments, Charges, and Special Rate Provisions are described in
the 2002 GRSPs. Relevant sections are identified below.
------------------------------------------------------------------------
2002
Adjustments, charges, and special rate provisions GRSP
section
------------------------------------------------------------------------
Conservation and Renewables Discount......................... II.A.
Conservation Surcharge....................................... II.B.
Cost Contributions........................................... II.E.
Cost Recovery Adjustment Clause.............................. II.F.
Dividend Distribution Clause................................. II.H.
Flexible NR Rate Option...................................... II.K.
Green Energy Premium......................................... II.M.
Low Density Discount......................................... II.P.
Rate Melding................................................. II.Q.
Targeted Adjustment Charge................................... II.U.
Unauthorized Increase Charge................................. II.V.
------------------------------------------------------------------------
D. Actual Partial Service Product--Complex
Purchases of the core Subscription Actual Partial Service Product--
Complex are subject to the charges specified below.
1. New Resource Firm Power
1.1 Demand Charge
The charge for Demand will be:
(The Purchaser's Demand Entitlement multiplied by a Demand Adjuster) as
specified in the contract multiplied by the Demand Rate from Section
II.A.
1.2 Energy Charge
The total monthly charge for energy will be the sum of (1) and (2):
(1) The Purchaser's HLH Energy Entitlement as specified in the contract
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract
multiplied by the LLH Energy Rate from Section II.B.
1.3 Load Variance Charge
The charge for Load Variance will be:
The Purchaser's Total Retail Load for the billing period multiplied by
the Load Variance Rate from Section II.C.
2. Adjustments, Charges, and Special Rate Provisions
Adjustments, Charges, and Special Rate Provisions are described in
the 2002 GRSPs. Relevant sections are identified below.
------------------------------------------------------------------------
2002
Adjustments, charges, and special rate provisions GRSP
section
------------------------------------------------------------------------
Conservation and Renewables Discount......................... II.A.
Conservation Surcharge....................................... II.B.
Cost Contributions........................................... II.E.
Cost Recovery Adjustment Clause.............................. II.F.
Dividend Distribution Clause................................. II.H.
Excess Factoring Charge...................................... II.I.
Flexible NR Rate Option...................................... II.K.
Green Energy Premium......................................... II.M.
Low Density Discount......................................... II.P.
Rate Melding................................................. II.Q.
Targeted Adjustment Charge................................... II.U.
Unauthorized Increase Charge................................. II.V.
------------------------------------------------------------------------
E. Block Product
Purchases of the core Subscription Block Product are subject to the
charges specified below.
1. New Resource Firm Power
1.1. Demand Charge
The charge for Demand will be:
The Purchaser's Demand Entitlement as specified in the contract
multiplied by the Demand Rate from Section II.A.
1.2. Energy Charge
The total monthly charge for energy shall be the sum of (1) and
(2):
(1) The Purchaser's HLH Energy Entitlement as specified in the contract
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract
multiplied by the LLH Energy Rate from Section II.B.
1.3 Load Variance Charge
Not applicable to Block purchases unless the customer is also
purchasing another product to which Load Variance is applicable as
specified by contract.
2. Adjustments, Charges, and Special Rate Provisions
Adjustments, Charges, and Special Rate Provisions are described in
the 2002 GRSPs. Relevant sections are identified below.
------------------------------------------------------------------------
2002
Adjustments, charges, and special rate provisions GRSP
section
------------------------------------------------------------------------
Conservation and Renewables Discount......................... II.A.
Conservation Surcharge....................................... II.B.
Cost Contributions........................................... II.E.
Cost Recovery Adjustment Clause.............................. II.F.
Dividend Distribution Clause................................. II.H.
Flexible NR Rate Option...................................... II.K.
Green Energy Premium......................................... II.M.
Low Density Discount......................................... II.P.
Rate Melding................................................. II.Q.
Stepped Up Multiyear Block (SUMY)............................ II.S.
Targeted Adjustment Charge................................... II.U.
Unauthorized Increase Charge................................. II.V.
------------------------------------------------------------------------
F. Block Product With Factoring
Purchases of the core Subscription Block Product with Factoring are
subject to the charges specified below.
[[Page 44337]]
1. New Resource Firm Power
1.1. Demand Charge
The charge for Demand will be:
(the Purchaser's Demand Entitlement multiplied by a Demand Adjuster) as
specified in the contract multiplied by the Demand Rate from Section
II.A.
1.2. Energy Charge
The total monthly charge for energy will be the sum of (1) and (2):
(1) The Purchaser's HLH Energy Entitlement as specified in the contract
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract
multiplied by the LLH Energy Rate from Section II.B.
1.3 Load Variance Charge
Not applicable to Block purchases unless the customer is also
purchasing another product to which Load Variance is applicable as
specified by contract.
2. Adjustments, Charges, and Special Rate Provisions
Adjustments, Charges, and Special Rate Provisions are described in
the 2002 GRSPs. Relevant sections are identified below.
------------------------------------------------------------------------
2002
Adjustments, charges, and special rate provisions GRSP
section
------------------------------------------------------------------------
Conservation and Renewables Discount......................... II.A.
Conservation Surcharge....................................... II.B.
Cost Contributions........................................... II.E.
Cost Recovery Adjustment Clause.............................. II.F.
Dividend Distribution Clause................................. II.H.
Excess Factoring Charge...................................... II.I.
Flexible NR Rate Option...................................... II.K.
Green Energy Premium......................................... II.M.
Low Density Discount......................................... II.P.
Rate Melding................................................. II.Q.
Stepped Up Multiyear Block (SUMY)............................ II.S.
Targeted Adjustment Charge................................... II.U.
Unauthorized Increase Charge................................. II.V.
------------------------------------------------------------------------
G. Block Product With Shaping Capacity
Purchases of the core Subscription Block Product with Shaping
Capacity are subject to the charges specified below.
1. New Resource Firm Power
1.1. Demand Charge
The charge for Demand will be:
The Purchaser's Demand Entitlement as specified in the contract
multiplied by the Demand Rate from Section II.A.
1.2. Energy Charge
The total monthly charge for energy shall be the sum of (1) and
(2):
(1) The Purchaser's HLH Energy Entitlement as specified in the contract
multiplied by the HLH Energy Rate from Section II.B.
(2) The Purchaser's LLH Energy Entitlement as specified in the contract
multiplied by the LLH Energy Rate from Section II.B.
1.3 Load Variance Charge
Not applicable to Block purchases unless the customer is also
purchasing another product to which Load Variance is applicable as
specified by contract.
2. Adjustments, Charges, and Special Rate Provisions
Adjustments, Charges, and Special Rate Provisions are described in
the 2002 GRSPs. Relevant sections are identified below:
------------------------------------------------------------------------
2002
Adjustments, charges, and special rate provisions GRSP
section
------------------------------------------------------------------------
Conservation and Renewables Discount......................... II.A.
Conservation Surcharge....................................... II.B.
Cost Contributions........................................... II.E.
Cost Recovery Adjustment Clause.............................. II.F.
Dividend Distribution Clause................................. II.H.
Flexible NR Rate Option...................................... II.K.
Green Energy Premium......................................... II.M.
Low Density Discount......................................... II.P.
Rate Melding................................................. II.Q.
Stepped Up Multiyear Block (SUMY)............................ II.S.
Targeted Adjustment Charge................................... II.U.
Unauthorized Increase Charge................................. II.V.
------------------------------------------------------------------------
Section IV. Transmission
All customers will need to obtain transmission for delivery of
products listed under this rate schedule unless BPA's Power Business
Line (PBL) and the customer negotiate otherwise at time of sale.
Regulation and Frequency Response may have to be purchased for NLSLs.
IP-02
Industrial Firm Power Rate
Section I. Availability
This schedule is available, in conjunction with the IPTAC, to BPA's
direct service industrial (DSI) customers for Firm Power to be used in
their industrial operations. DSIs that purchase power under contracts
for which power deliveries begin on or after October 1, 2001 (2002
Contracts), are eligible to purchase under this rate schedule for up to
a five-year period.
This rate schedule supersedes the IP-96 rate schedule, which went
into effect October 1, 1996. Sales under the IP-02 rate schedule are
subject to BPA's 2002 General Rate Schedule Provisions (2002 GRSPs) and
billing process.
Section II. Rates Tables
The rates for the IP Firm Power product are identified below.
A. Demand Rate for All IP/IPTAC Products
1. Flat Rate Demand for FY 2002 through 2006
1.1 Applicability
These rates apply to eligible customers purchasing power for all
five years of the rate period.
1.2 Rate Table
------------------------------------------------------------------------
Rate (kW-
Applicable months mo)
------------------------------------------------------------------------
January...................................................... $2.14
February..................................................... 2.06
March........................................................ 1.96
April........................................................ 1.37
May.......................................................... 1.32
June......................................................... 1.69
July......................................................... 2.12
August....................................................... 2.44
September.................................................... 2.28
October...................................................... 1.90
November..................................................... 2.31
December..................................................... 2.40
------------------------------------------------------------------------
B. Energy Rate
1. Monthly Energy Rates for FY 2002 Through FY 2006
1.1 Applicability
These energy rates are to be combined with one of the two IP
Targeted Adjustment Charges specified in Section 2.2 or 3.2 below.
1.2 Rate Table
------------------------------------------------------------------------
HLH rate LLH rate
Applicable months (mills/ (mills/
kWh) kWh)
------------------------------------------------------------------------
January........................................... 21.49 15.87
February.......................................... 20.37 15.27
March............................................. 19.61 14.52
April............................................. 14.07 10.98
May............................................... 13.63 9.44
June.............................................. 16.93 11.04
July.............................................. 21.28 18.03
August............................................ 31.66 21.65
September......................................... 22.51 21.83
October........................................... 19.10 15.78
November.......................................... 22.99 20.20
December.......................................... 23.82 20.10
------------------------------------------------------------------------
2. Monthly Energy Rates for FY 2002 Through FY 2006 for IPTAC (23.5
mills)
2.1 These rates apply to the eligible customers purchasing power
under this rate schedule for all five years of the rate period.
2.2 A charge of 2.02 mills shall be added to each IP energy rate
in the Rate Table in 1.2 above.
[[Page 44338]]
3. Monthly Energy Rates for FY 2002 Through FY 2006 for IPTAC (25.0
mills)
3.1 These rates apply to the eligible customers purchasing power
under this rate schedule for all five years of the rate period.
3.2 A charge of 3.52 mills shall be added to each IP energy rate
in the Rate Table in 1.2 above.
C. Load Variance Rate
The Load Variance rate for FY 2002 through FY 2006 applies to all
customers purchasing power under this rate schedule unless specifically
excluded in Section III below. The rate for Load Variance is 0.8 mills/
kWh.
Section III. Billing Factors and Adjustments for Each IP Product
This rate schedule contains two subsections, corresponding to the
products to which this rate schedule applies. Only the firm take-or-pay
Block Product is available under these rate schedules.
SECTION III.A. DSI Customers Who Purchase Under 2002 Industrial Firm
Power (IP) Contracts
SECTION III.B. DSI Customers Who Purchase Under 2002 Industrial Firm
Power Targeted Adjustment Charge (IPTAC) Contracts
A. DSI Customers Who Purchase Under 2002 Industrial Firm Power (IP)
Contracts
Purchases of power under a 2002 IP contract are subject to the
charges specified below.
1. Industrial Firm Power
1.1 Demand Charge
The charge for Demand will be:
The Purchaser's monthly Contract Demand multiplied by the Demand Rate
from Section II.A.
1.2 Energy Charge
The Total monthly charge for energy will be the sum of (1) and (2):
(1) The Purchaser's monthly HLH Contract Energy multiplied by the HLH
Energy Rate from Section II.B; and
(2) The Purchaser's monthly LLH Contract Energy multiplied by the LLH
Energy Rate from Section II.B.
1.3 Load Variance Charge
Not applicable to Block purchases unless the customer is also
purchasing another product to which Load Variance is applicable as
specified by contract.
2. Adjustments, Charges, and Special Rate Provisions
Adjustments, Charges, and Special Rate Provisions are described in
the 2002 GRSPs. Relevant sections are identified below:
------------------------------------------------------------------------
2002
Adjustments, charges, and special rate provisions GRSP
section
------------------------------------------------------------------------
Conservation and Renewable Discount.......................... II.A.
Conservation Surcharge....................................... II.B.
Cost Contributions........................................... II.E.
Cost Recovery Adjustment Clause.............................. II.F.
Dividend Distribution Clause................................. II.H.
Green Energy Premium......................................... II.M.
Rate Melding................................................. II.Q.
Supplemental Contingency Reserves Adjustment................. II.T.
Unauthorized Increase Charge................................. II.V.
------------------------------------------------------------------------
B. DSI Customers Who Purchase Under 2002 Industrial Firm Power Targeted
Adjustment Charge (IPTAC) Contracts
Purchases of power under a 2002 IPTAC contract are subject to the
charges specified below.
1. Industrial Firm Power
1.1 Demand Charge
The charge for Demand will be:
The Purchaser's monthly Contract Demand multiplied by the Demand Rate
from Section II.A.
1.2 Energy Charge
Energy charges will be calculated pursuant to the GRSPs IPTAC at
the time of contract negotiations.
1.3 Load Variance Charge
Not applicable to Block purchases unless the customer is also
purchasing another product to which Load Variance is applicable as
specified by contract.
2. Adjustments, Charges, and Special Rate Provisions
Adjustments, Charges, and Special Rate Provisions are described in
the 2002 GRSPs. Relevant sections are identified below:
------------------------------------------------------------------------
2002
Adjustments, charges, and special rate provisions GRSP
section
------------------------------------------------------------------------
Conservation and Renewable Discount.......................... II.A.
Conservation Surcharge....................................... II.B.
Cost-Based Indexed IP Rate................................... II.C.
Cost Contributions........................................... II.E.
Cost Recovery Adjustment Clause.............................. II.F.
Dividend Distribution Clause................................. II.H.
Flexible IP Rate Option...................................... II.J.
Green Energy Premium......................................... II.M.
Industrial Firm Power Targeted Adjustment Charge............. II.O.
Rate Melding................................................. II.Q.
Supplemental Contingency Reserves Adjustment................. II.T.
Unauthorized Increase Charge................................. II.V.
------------------------------------------------------------------------
Section IV. Transmission
All customers will need to obtain transmission for delivery of
products listed under this rate schedule unless BPA's Power Business
Line (PBL) and the customer negotiate otherwise at time of sale.
NF-02
Nonfirm Power 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. The offer of nonfirm energy under this schedule shall be
determined by BPA.
This rate schedule supersedes the NF-96 schedule, which went into
effect on October 1, 1996. Sales under the NF-02 rate schedule are
subject to BPA's 2002 General Rate Schedule Provisions (2002 GRSPs).
For sales under this rate schedule, bills shall be rendered and
payments due pursuant to BPA's 2002 GRSPs and billing process.
Section II. Rates, Billing Factors, and Adjustments
The average cost of nonfirm energy is 24.98 mills/kWh. The NF-02
rate schedule provides for upward and downward pricing flexibility from
this average nonfirm energy cost.
A. Rates for Nonfirm Energy
1. Standard Rate
The Standard rate is any offered rate not to exceed 29.98 mills/
kWh.
2. Market Expansion Rate
The Market Expansion rate is any offered rate below the Standard
rate in effect. BPA may have one or more Market Expansion rates in
effect simultaneously.
3. Incremental Rate
The Incremental Rate is the Incremental Cost of energy plus 2.00
mills/kWh, where the Incremental Cost is defined as all identifiable
costs (expressed in mills/kWh) that BPA would have avoided had it not
produced or purchased the energy being sold under this rate.
4. Contract Rate
The Contract Rate is 24.98 mills/kWh.
B. Billing Factor for Nonfirm Energy
The billing factor for nonfirm energy purchased under this rate
schedule shall be the Measured Energy unless otherwise specified by
contract.
[[Page 44339]]
C. Adjustments for Nonfirm Energy
All adjustments are described in the 2002 GRSPs. The applicable
sections are identified for each adjustment.
------------------------------------------------------------------------
2002
Adjustments, charges, and special rate provisions GRSP
section
------------------------------------------------------------------------
Cost Contributions........................................... II.E.
Unauthorized Increase Charge................................. II.V.
------------------------------------------------------------------------
Section III. Determination of the Applicable NF Rate
Any time that BPA has nonfirm energy for sale, the Standard rate,
the Market Expansion rate, the Incremental rate, the Contract rate, or
any combination of these rates may be in effect.
A. Standard Rate
The Standard rate is available for all purchases of nonfirm energy.
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
associated with that purchase, in an amount equal to the amount of
Market Expansion rate energy purchased; or
b. Reduction of a displaceable purchase and the output of the
resource associated with that purchase, in an amount equal to the
amount of Market Expansion rate energy purchased; or
c. Shutdown or reduction of the identified output of the
resource(s) indirectly in an amount equal to the amount of Market
Expansion rate energy purchased (for example, the purchase may be used
to run a pumped storage unit); or
d. Decrease of an end-user alternate fuel source in an amount
equivalent to the amount of Market Expansion rate energy purchased.
3. Eligibility Criteria for Market Expansion Rate
a. When only one Market Expansion rate is offered:
Purchasers satisfying the Market Expansion Rate Qualifying Criteria
specified in Section III.B.2 above, who purchased nonfirm energy
directly from BPA, are eligible to purchase power under the Market
Expansion rate offered if the decremental cost of the qualifying
resource, purchase, or qualifying alternative fuel source is lower than
the Standard rate in effect plus 2.00 mills/kWh.
Purchasers qualifying under Section III.B.2 who purchase nonfirm
energy through a third party are eligible to purchase power under the
Market Expansion rate offered if the cost of the qualifying alternative
fuel source is lower than the Standard rate in effect plus 4.00 mills/
kWh.
b. When more than one Market Expansion rate is offered:
Purchasers qualifying under Section III.B.2 who purchase nonfirm
energy directly from BPA are eligible to purchase power under the
Market Expansion rate if the decremental cost of the qualifying
resource, purchase, or qualifying alternative fuel source is lower than
the Standard rate in effect plus 2.00 mills/kWh. The rate applicable to
a purchaser will be the highest Market Expansion rate offered that is
below the purchaser's qualifying decremental cost minus 2.00 mills/kWh.
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) minus 2 mills.
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 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 will 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 the agreement.
F. End-User Rate
BPA may agree to a rate formula for nonfirm energy purchases by
end-users. Such rate or rate formula will be within the limits
specified for the Standard and Market Expansion rates but may differ
from the actual rates offered during any hour.
Section IV. Delivery
A. Rate of Delivery
BPA shall determine the amount of nonfirm energy to be made
available for each hour. Such determination shall be made for each
applicable nonfirm energy rate.
B. Guaranteed Delivery
1. Availability
BPA will determine the amount and duration of nonfirm energy to be
offered on a guaranteed basis. Such daily or hourly amounts may be as
small as zero or as much as all the nonfirm energy that BPA plans to
offer for sale on such days.
2. Conditions
Scheduled amounts of guaranteed nonfirm energy may not be changed
except:
a. When BPA and the purchaser mutually agree to increase or
decrease the scheduled amounts; or
b. When BPA must reduce nonfirm energy deliveries in order to serve
firm loads.
Section V. Transmission
All customers will need to obtain transmission for delivery of
products listed under this rate schedule unless BPA's Power Business
Line (PBL) and the customer negotiate otherwise at time of sale.
BPA'S 2002 General Rate Schedule Provisions for Power Rates
Index General Rate Schedule Provisions
Section I: Adoption of Revised Rate Schedules and General Rate
Schedule Provisions
A. Approval of Rates
B. General Provisions
[[Page 44340]]
C. Late Payment Provisions
D. Notices
Section II: Adjustments, Charges, and Special Rate Provisions
A. Conservation and Renewables Discount (C&R Discount)
B. Conservation Surcharge (PF/NR only)
C. Cost-Based Indexed IP Rate
D. Cost-Based Indexed PF Rate
E. Cost Contributions
F. Cost Recovery Adjustment Clause (CRAC)
G. Demand Adjuster
H. Dividend Distribution Clause (DDC)
I. Excess Factoring Charges
J. Flexible IP Rate Option
K. Flexible NR Rate Option
L. Flexible PF Rate Option
M. Green Energy Premium
N. Guaranteed Delivery Charge (NF Only)
O. Industrial Firm Power Targeted Adjustment Charge (IPTAC)
P. Low Density Discount
Q. Rate Melding
R. Slice True-Up Adjustment
S. Stepped Up Multiyear Block (SUMY)
T. Supplemental Contingency Reserves Adjustment (SCRA)
U. Targeted Adjustment Charge
V. Unauthorized Increase Charge
Section III: Definitions
A. Power Products and Services Offered By the Power Business Line of
BPA
1. Actual Partial Service Product--Simple/Complex
2. Block Product
3. Block Product with Factoring
4. Block Product with Shaping Capacity
5. Construction, Test and Start-Up, and Station Service
6. Core Subscription Products
7. Customer System Peak (CSP)
8. Full Service Product
9. Industrial Firm Power
10. Load Variance
11. New Resource Firm Power
12. Nonfirm Energy
13. Priority Firm Power
14. Regulation and Frequency Response
15. Residential Exchange Program Power
16. Slice Product
B. Definition of Rate Schedule Terms
1. 2002 Contract
2. Annual Billing Cycle
3. Billing Demand
4. Billing Energy
5. California Independent System Operator (California ISO)
6. California ISO Spinning Reserve Capacity
7. California ISO Supplemental Energy
8. California Power Exchange (California PX)
9. Contract Demand
10. Contract Energy
11. Control Area
12. Decremental Cost
13. Delivering Party
14. Demand Entitlement
15. Discount Period
16. Dow Jones Mid-C Indexes (DJ Mid-C Indexes)
17. Electric Power
18. Energy Entitlement
19. Federal System
20. Firm Power (PF-02, IP-02, NR-02, RL-02)
21. Full Service Customer
22. Generation System Peak
23. Heavy Load Hours (HLH)
24. Inventory Solution Costs
25. Light Load Hour (LLH)
26. Measured Demand
27. Measured Energy
28. Metered Demand
29. Metered Energy
30. Mid-Columbia Bus (Mid-C Bus)
31. Monthly Federal System Peak Load
32. NP15
33. NW1 (California-Oregon Border)
34. NW3 (Nevada-Oregon Border)
35. Partial Service Customer
36. Point of Delivery (POD)
37. Point of Integration (POI)
38. Point of Interconnection (POI)
39. Points of Metering (POM)
40. Pre-Subscription Contract
41. Purchaser
42. Receiving Party
43. Retail Access
44. Scheduled Demand
45. Scheduled Energy
46. Slice Administrative Costs
47. Slice Revenue Requirement
48. Subscription
49. Subscription Contract
50. System Obligations
51. Total Plant Load
52. Total Retail Load (TRL)
53. Utility Distribution Company
General Rate Schedule Provisions
Section I. Adoption of Revised Rate Schedules and General Rate Schedule
Provisions
A. Approval of Rates
These 2002 Wholesale Power Rate Schedules and General Rate Schedule
Provisions (2002 GRSPs) shall become effective upon interim approval or
upon final confirmation and approval by the Federal Energy Regulatory
Commission (FERC). Bonneville Power Administration (BPA) has requested
that FERC make these rates and 2002 GRSPs effective on October 1, 2001,
for customers who are billed by BPA on a calendar month basis and on
the first day of the first billing month following that date for all
other customers. All rate schedules shall remain in effect until they
are replaced or expire on their own terms.
B. General Provisions
These 2002 Wholesale Power Rate Schedules and the 2002 GRSPs
associated with these schedules supersede BPA's 1996 rate schedules
(which became effective October 1, 1996) to the extent stated in the
Availability section of each rate schedule. These schedules and 2002
GRSPs shall be applicable to all BPA contracts, including contracts
executed both prior to, and subsequent to, enactment of the Pacific
Northwest Electric Power Planning and Conservation Act (Northwest Power
Act). All sales under these rate schedules are subject to the following
acts as amended: The Bonneville Project Act, the Regional Preference
Act (P.L. 88-552), the Federal Columbia River Transmission System
(FCRTS) Act (P.L. 93-454), the Northwest Power Act (P.L. 96-501), and
the Energy Policy Act of 1992 (P.L. 102-486).
These 2002 rate schedules do not supersede any previously
established rate schedule which is required, by agreement, to remain in
effect.
If a provision in an executed agreement is in conflict with a
provision contained herein, the former shall prevail.
C. Late Payment Provisions
Bills not paid in full on or before close of business on the due
date shall be subject to an interest charge of one-twentieth percent
(0.05 percent) applied each day to the unpaid amount. This interest
charge shall be assessed on a daily basis until such time as the unpaid
amount is paid in full.
Remittances will be accepted without assessment of the charges
referred to in the preceding paragraph provided payment was received on
or before the due date. The due date is the 20th day after the issue
date of the bill unless the 20th day is a Saturday, Sunday, or Federal
holiday, in which case the due date is the next business day. 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
previously accrued charges under such contract.
D. Notices
For the purpose of determining elapsed time from receipt of a
notice applicable to rate schedule and GRSP administration, a notice
shall be deemed to have been received at 0000 hours on the first
calendar day following actual receipt of the notice.
Section II. Adjustments, Charges, and Special Rate Provisions
A. Conservation and Renewables Discount (C&R Discount)
1. Description of the Discount
To encourage and support the development of conservation projects
and renewable resources in the Pacific Northwest, BPA is offering a
Conservation and Renewables Discount (C&R Discount) to customers
purchasing
[[Page 44341]]
under the Priority Firm (PF-02), New Resources (NR-02), and Residential
Load (RL-02) rate schedules. Customers purchasing under the Industrial
Firm Power Rate (IP-02) will be eligible to the extent that the C&R
Discount does not reduce their effective rate below the DSI floor rate.
Regional public agency customers with Pre-Subscription contracts with
collared pricing provisions may be eligible for the C&R Discount
subject to contract provisions. The amount of the Discount will be a
fixed monthly amount based on the customer's forecasted purchases from
BPA under its Subscription contract. Following the end of the Discount
Period (which is the end of the rate period or the customer's contract
term, whichever comes first), BPA will evaluate the customer's
investments in eligible conservation and renewable resource projects
during the Discount Period. Any customer that has not spent at least as
much money on eligible activities as the cumulative discount received
from BPA must reimburse the difference to BPA.
2. Calculation and Application of the Discount
a. Overview of the Discount
The C&R Discount will be included as a fixed dollar credit in the
monthly power bill of each participating customer. The credit will
equal the customer's forecasted average monthly Subscription contract
(in megawatts) multiplied by the unit discount. (Because the average
contract is used, the discount does not vary by month).
b. Determination of the ``Unit Discount''
The unit discount will equal 0.5 mills per kilowatthour (kWh).
c. Determination of Individual Customer Discounts
For a participating customer buying power from BPA under a
Subscription contract for the entire five-year rate period, BPA will
determine the monthly dollar discount by multiplying the customer's
forecasted average monthly power consumption over the rate period by
the unit discount.
d. Annual Review of Individual Customer Discounts
At least 30 days prior to the start of each fiscal year, customers
will submit adjustments to the section c monthly discounts based on
changes to the customers load as specified in their BPA contract.
e. Application of the Discount
The C&R Discount will be applied after BPA has determined all other
charges and credits on the participating customer's power bill.
BPA will provide the discount even in those months when the
discount amount is larger than the customer's total power bill amount.
3. Qualifying Expenditures
Participating customers shall record all qualifying expenditures to
ensure full credit for their conservation and renewable resource
activities. Qualifying expenditures are those that meet technical
standards developed by the Regional Technical Forum as approved by BPA.
Although BPA will provide the credit on a monthly basis, the
customer has no obligation to adhere to any particular expenditure
pattern. To retain the full discount provided by BPA, the participating
customer must make qualifying expenditures during the Discount Period
in an amount equal to, or exceeding, the cumulative C&R Discount
received from BPA during the Discount Period.
4. Reporting
a. Interim Conservation and Renewable Reports
Participating customers shall submit to BPA annual Interim
Conservation and Renewable Reports at the end of each fiscal year of
the rate period (i.e., 10/01/01 to 9/30/02; 10/01/02, to 9/30/03;
etc.). The Interim Report shall show the customer's cumulative
discounts received to date and their cumulative qualifying
expenditures. If the report shows that the customer's qualifying
expenditures are less than or equal to its discount receipts by 5
percent or more, the customer must indicate in its report how it plans
to adjust its expenditures to ensure that it will retain the full
discount after the Discount Period.
b. Final Reconciliation Reports
At the end of the Discount Period the participating customer shall
prepare a Final Reconciliation Report. This report shall be submitted
and received by BPA one month after the end of the Discount Period
(November 1, 2006, for participating customers' purchasing power from
BPA for the full five-year rate period).
This report shall identify:
i. The cumulative C&R Discount that the customer has received from
BPA during the Discount Period, and
ii. The total qualifying expenditures that the customer has made
during the Discount Period segregated into the following four
categories:
I. Incremental Conservation
II. Renewable Resources
III. Low Income Weatherization
IV. Support Activities (i.e., administrative, advertising, R&D, and
evaluation
c. Certification of Incremental Spending
Each Interim Report and the Final Reconciliation Report shall
include language certifying the participating customer's actual
incremental spending, such as:
``[Customer] certifies that the expenditures documented in this
report are incremental increases in this organization's budget for the
current operating year beyond what we planned to spend absent the
discount.''
d. Exemption Language for State and Municipal Initiatives
If States, municipalities, or other governmental bodies in the BPA
service territory require, by law or regulation, that a utility, which
is a participating customer in the C&R Discount, to acquire or invest
in new conservation and/or a new renewable resource project, then such
acquisitions and investments will be deemed as incremental budget
increases for the purposes of section 4.c. above.
5. Reimbursement
a. Customers Whose Expenditures Exceed the Threshold
No reimbursements are required of any participating customer whose
total expenditures over the Discount Period equal or exceed the total
cumulative C&R Discount received from BPA.
b. Customers Whose Expenditures Fall Below the Threshold
If a participating customer's Final Reconciliation Report shows
that the cumulative discount received from BPA exceeds the customer's
total qualifying expenditures, the customer may take an additional
month (for a total of two months after the end of the Discount Period)
to make the necessary qualifying expenditures and prepare a Revised
Final Reconciliation Report. The final report is due to BPA within two
months of the end of the Discount Period (December 1, 2006, for the
five-year customers). If the customer's qualifying expenditures still
do not equal or exceed its cumulative discount, the customer must
reimburse the difference to BPA. Such reimbursement shall be made
within the same two-month grace period and shall be made using the same
payment method as the customer uses for paying its wholesale bill.
BPA will not assess interest on any reimbursement paid within the
two-month window. However, any payment received after the due date
(December 1, 2006, the five-year customers) shall be
[[Page 44342]]
subject to a late payment charge as described in their Subscription
contract.
6. Revenue Dividends
a. Implementation
If BPA declares that there is a dividend during this rate period,
the first $15 million will be allocated to conservation and renewable
resource development. BPA will distribute the C&R portion of any
declared dividend in the same manner outlined in this section with the
following modifications:
1. In order to receive their portion of the C&R dividend, customers
must be actively participating in the basic C&R Discount effort; and
2. Participating customers must spend two dollars on eligible
activities to receive one dollar of their dividend share (i.e., any C&R
dividend will be leveraged on a 2 for 1 basis).
3. The unit discount for participating customers receiving the
dividend will set at $0.75 per MWh during the months the dividend is in
effect.
B. Conservation Surcharge (PF/NR Only)
The Conservation Surcharge, where implemented shall be applied in
accordance with relevant provisions of the Northwest Power Act, BPA's
current conservation surcharge policy, and the customer's power sales
contract with BPA. The PF and NR rate schedules are subject to the
Conservation Surcharge.
C. Cost-Based Indexed IP Rate
The Cost-Based Indexed IP Rate option shall be offered at BPA's
discretion to a DSI Purchaser who makes a contractual commitment to
purchase power for all five years of the rate period from BPA that is
subject to the IP Targeted Adjustment Charge (IPTAC). The charges and
billing factors under this option shall be specified by BPA at the time
the Administrator offers to make power available to a Purchaser under
this option. The actual charges and billing factors will be mutually
agreed to by BPA and the Purchaser. The following criteria will be used
in establishing any flexible rate:
1. Equivalent Net Present Value Revenues: Forecasted revenues from
a Purchaser under this rate option must be equivalent to or greater
than, on a net present value basis, the revenues BPA would have
received had the IPTAC specified in the IP-02 rate schedule been
applied to the same sales.
2. Risk Adjustments: Risk, both credit risk associated with
individual customers and price risk associated with power and commodity
prices, will be factors in establishing any flexible rate option.
Creditworthiness will be determined by BPA consistent with prevailing
business standards, and applied consistently to each customer. Such
credit risks will be dealt with through a ``margin deposit'' expense
charge built into the rates, or other methods acceptable to BPA.
3. Industry Index: The Cost-Based Indexed IP Rate will be adjusted
on a regular basis consistent with a negotiated cash or financial
index. Adjusting the price of the Cost-Based Indexed IP Rate with the
fluctuations in a world aluminum price index would be one use of an
industry index.
4. Lower Rate Limit and Upper Rate Limit: A lower and upper rate
limit will bound the Cost-Based Index and establish the minimum and
maximum prices to be charged during the contract period.
D. Cost-Based Indexed PF Rate
The Cost-Based Indexed PF Rate will be offered to all firm load
requirements customers who wish to convert their applicable PF rate
under their contracts to a market-indexed or floating price adjusted
for BPA's risk. The following are features of this rate:
1. BPA and the customer will choose during contract negotiations a
mutually agreed reference point and sponsor for the index used. For
example, the California-Oregon border (location) and the Dow Jones cash
or the New York Mercantile Exchange futures (sponsor), or some other
combination to arrive at an agreed upon index.
2. BPA will base the index pricing on a current market forecast of
the market index referenced. The expected Net Present Value (NPV)
revenue of the forecast index prices will be adjusted by a HLH and a
LLH Market Index Monthly Adjustment (MIMA) to equal the expected NPV of
the applicable PF rates. The MIMA reflects BPA's PF equivalent expected
revenues at the time the contract is signed, including an insurance
premium to ensure revenue sufficiency.
3. Customers must select this rate for the term of their
Subscription contract that the 2002-2006 rate period covers. Customers
who choose a contract length of less than five years and wish to renew
will be subject to rates established under a new rate case.
4. Billing will be based on the index's average of the last 15 days
of closing or posted daily prices at the reference point. The MIMA will
be calculated as follows:
Index = average of last 15 days of closing or posted daily prices at
the reference point.
PF = monthly PF HLH or LLH energy rate
Cost of Insurance = The premium on a physical and financial
instrument used to mitigate the risk.
MIMA = Index-PF+Cost of Insurance
E. Cost Contributions
BPA has made the following resource cost determinations:
1. The forecasted average cost of resources available to BPA under
average water conditions is 19.12 mills/kWh.
2. The approximate cost contribution of different resource
categories to each rate schedule is as shown in Table A:
Table A
----------------------------------------------------------------------------------------------------------------
Resource cost contribution
-----------------------------------------------
Rate schedule Federal base
system* Exchange* New resources*
----------------------------------------------------------------------------------------------------------------
PF.............................................................. 100 0 0
IP.............................................................. 52.86 43.66 3.48
NR.............................................................. 52.86 43.66 3.48
----------------------------------------------------------------------------------------------------------------
* In percent.
F. Cost Recovery Adjustment Clause (CRAC)
The CRAC is an upward adjustment to posted power rates for
Subscription sales on a temporary basis if Actual Accumulated Net
Revenues (AANR) in the generation function fall below a threshold
level.
The CRAC applies to power customers under these firm power rate
schedules: Priority Firm Power [Preference (PF excluding Slice),
Exchange Program, and Exchange
[[Page 44343]]
Subscription], IP-02, including under the IPTAC and Cost-Based Index
Rate, RL-02 including the financial portion of any Residential Exchange
Settlement under this rate schedule, NR-02, and Subscription purchase
under FPS. The CRAC does not apply to Pre-Subscription rates or Slice
purchases.
1. Formula for the Calculation of the Revenue Amount and CRAC
Percentage
If the AANR in any fiscal year 2001 through 2004 falls below the
CRAC Threshold for that same fiscal year, the CRAC triggers, and rates
will be increased for a 12-month period beginning the following April.
The Revenue Amount will be determined by the following formula:
Revenue Amount is the lower of:
CRAC Threshold--AANR; or
The annual Maximum Planned Recovery Amount, shown in Table B below.
Where Revenue Amount is the amount of additional revenue that an
increase in rates under CRAC is intended to generate during the period
that the rate increase is effective.
Where CRAC Threshold is the ``trigger point'' for invoking a rate
increase under the CRAC. The threshold is pre-specified for the end of
fiscal years 2001, 2002, 2003, 2004, and 2005 in Table B.
Where AANR is generation function net revenues, as accumulated
since 1998, at the end of each of the fiscal years 2001 through 2005.
Net revenues for any given fiscal year are accrued revenues less
accrued expenses, in accordance with Generally Accepted Accounting
Practices. Only generation function revenues and expenses, which is to
say accrued revenues and accrued expenses that are associated with the
production, acquisition, marketing, and conservation of electric power,
will be included in determinations under the CRAC. Accrued revenues and
expenses of the transmission function are excluded. The determination
of AANR will be confirmed by BPA's independent auditing firm.
Where Maximum Planned Recovery Amount is the maximum amount planned
to be recovered through the CRAC beginning in April following the end
of a fiscal year in which the AANR falls below the CRAC Threshold.
If the AANR in fiscal year 2005 falls below the CRAC Threshold, the
CRAC triggers, and rates will be increased for a six-month period
beginning the following April. The Revenue Amount will be determined by
the following formula:
Revenue Amount is the lower of:
(CRAC Threshold-AANR) divided by 2; or $87.5 million ($175 million
divided by 2)
Table B
------------------------------------------------------------------------
Maximum planned
CRAC threshold recovery amount
Fiscal year (AANR, $ (beginning
millions) following
April)
------------------------------------------------------------------------
2001................................... -350 125
2002................................... -350 135
2003................................... -200 150
2004................................... -200 150
2005................................... -200 87.5
------------------------------------------------------------------------
Once the Revenue Amount is determined, that amount will be
converted to the CRAC Percentage. The CRAC Percentage is the percentage
increase in each of the firm power rate schedules listed above. This
percentage will be applied for a period of time to generate the
additional (CRAC) revenue. The CRAC Percentage will be determined by
the following formula:
CRAC Percentage =
Revenue Amount
Divided by
CRAC Revenue Basis,
Where CRAC Revenue Basis is the total generation revenue for the
loads subject to CRAC, plus any Slice loads, for the fiscal year in
which the CRAC implementation begins, based on the then most current
revenue forecast.
Each non-Slice product's total charge for energy, demand and load
variance will be increased by this CRAC Percentage amount.
2. CRAC Adjustment Timing
In January of each year of the rate period, the Administrator will
determine whether the AANR at the end of the preceding fiscal year fell
below the CRAC Threshold. If the AANR is below the CRAC Threshold, the
Administrator will propose, in January, to increase applicable rates
effective in the following April. The adjustment is applied to power
deliveries beginning April 1. Any such increase beginning in fiscal
years 2002-2005 remains in effect through March of the following year.
An increase beginning in the final fiscal year of the rate period
(2006) will remain in effect through September 2006.
3. CRAC Notification Process
BPA shall follow the following notification procedures:
a. Financial Performance Status Reports
By no later than August 31 of each year, BPA shall post on its
electronic information access site (World Wide Web) a forecast of AANR
attributable to the generation function for the fiscal year ending
September 30. By no later than December 1 of each year, BPA shall also
post on its World Wide Web site the unaudited AANR.
b. Notice of CRAC Trigger
BPA shall notify all customers and rate case parties on or about
January 15 in each of the fiscal years 2002-2006, if the AANR fell
below the CRAC Threshold for that fiscal year and rates will be
adjusted under the CRAC. (If the December unaudited AANR report for the
generation function indicated that the CRAC Threshold might be reached,
and the audited actuals show that it has not triggered, customers and
rate case parties will be so notified.) Notification will include the
audited AANR for the prior fiscal year, the calculation of the Revenue
Amount, and the estimated CRAC Percentage. The notice shall also
describe the data and assumptions relied upon by BPA. Such data,
assumptions and documentation, if non-proprietary and/or non-
privileged, shall be made available for review at BPA upon request. The
notice shall also contain the tentative schedule for the remainder of
the CRAC implementation process.
On or about February 1 of any of the fiscal years 2002-2006 in
which the AANR falls below the CRAC Threshold,
[[Page 44344]]
BPA staff shall conduct a public forum to explain the AANR result, the
calculation of the Revenue Amount and the CRAC Percentage, and
demonstrate that the CRAC has been implemented in accordance with the
GRSPs. The forum will provide an opportunity for public comment.
On or about March 1 of any of the fiscal years 2002-2006 in which
the AANR falls below the CRAC Threshold, the BPA Administrator shall
notify all customers to whom the CRAC applies of the final calculation
of the adjustment and the resulting rate increase (as a percentage)
applicable to each rate schedule.
G. Demand Adjuster
The Demand Adjuster is applied to a customer's demand billing
factor. It is a number less than or equal to one calculated by dividing
the customer's Total Retail Load on the Generation System Peak by the
customer's Total Retail Load on their system peak. The minimum Demand
Adjuster is 0.6 (six tenths). The Demand Adjuster is used with the
demand billing factor for the Actual Partial Service Products, and with
the demand billing factor for the Block with Factoring.
H. Dividend Distribution Clause (DDC)
The DDC is a clause establishing criteria and public process
requirements that the Administrator will use to decide whether
dividends should be distributed and the amount that should be
distributed. The DDC enables BPA to distribute dividends to customers
and other stakeholders. The DDC also establishes the mechanism to be
used to make a distribution to certain firm power customers.
The DDC applies to power customers under these firm power rate
schedules: Priority Firm Power [Preference (PF excluding Slice),
Exchange Program, and Exchange Subscription], IP-02 including under the
IPTAC and Cost-Based Index Rate, RL-02 including the financial portion
of any Residential Exchange Settlement under this rate schedule, NR-02,
and Subscription purchases under FPS. The DDC does not apply to Pre-
Subscription rates or Slice purchases, unless those customers
participate in the C&R Discount and a distribution is made to eligible
participants of that program.
The DDC does not apportion, or establish criteria for apportioning,
dividends to customers under the above firm power rate schedules other
than to qualifying power customers participating in the C&R Discount,
or to other customers and stakeholders.
``Stakeholders'' are groups that have a fundamental policy or
financial interest in BPA's generation function. These groups include,
but are not limited to, customers subject to the posted firm power rate
schedules cited above. A full identification of stakeholders will be
provided for comment in the public consultation process.
1. Formula for the Calculation of the Dividend Distribution Amount
The DDC process will be implemented if audited actual accumulated
net revenues for the end of any of the fiscal years 2001-2005 are above
the DDC Threshold value.
Actual Accumulated Net Revenues (AANR) are generation function net
revenues, as accumulated since 1998, at the end of each of the fiscal
years 2001 through 2005. Net revenues are accrued revenues less accrued
expenses, in accordance with Generally Accepted Accounting Practices.
Only generation function revenues and expenses, which is to say accrued
revenues and accrued expenses that are associated with the production,
acquisition, marketing, and conservation of electric power, are
included in determinations under the DDC; accrued revenues and expenses
of the transmission function are excluded. The determination of AANR
will be confirmed by BPA's independent outside auditing firm.
DDC Threshold is the minimum level of AANR that must be realized
before a dividend distribution is considered. The DDC Threshold is $500
million for the end of fiscal years 2001, 2002, 2003, 2004, and 2005.
DDC Amount is the aggregate amount that is available to be
distributed to customers and stakeholders. The DDC Amount may be equal
to zero and will be determined by the following formula:
DDC Amount is the lower of:
AANR-DDC Threshold; or
Cash in excess of that needed to meet the Treasury Payment Probability
(TPP) Standard, based on the Five-Year Forecast
Where the TPP Standard is an 88 percent probability that all
planned payments to the U.S. Treasury will be paid on time and in full
over the Five-Year Forecast period (or equivalent financial criterion
in the event that BPA replaces its TPP Standard); and
Where the Five-Year Forecast is the forecast of accrued revenues
and expenses, and the risk analysis and assessment of TPP or any
replacement financial criterion, for the current year and subsequent
four years that the Administrator prepares and subjects to public
review and comment if the DDC Threshold has been met.
The portion of the DDC Amount allocated to power customers (the
Power Customers DDC Amount) will be determined according to a plan to
be adopted in a public process BPA will conduct (see Section 3 below).
The Power Customer DDC Amount will be converted to a percentage (the
Power Customer DDC Percentage), which will be applied to all power
customer rates subject to the DDC to arrive at the amount to be rebated
on power bills for each of the included power customers.
The Power Customer DDC Percentage will be determined by the
following formula:
Power Customer DDC Percentage equals: Power Customer DDC Amount,
Divided by the DDC Revenue Basis
Where DDC Revenue Basis is the total generation revenue for the
loads subject to the DDC for the fiscal year in which the DDC
implementation begins, based on the then most current revenue forecast.
Each covered power customer will receive a rebate equal to the
Power Customer DDC Percentage applied to their total charge for energy,
demand and load variance. For any customer or stakeholder entitled to a
dividend who is not a power customer, the Administrator will convert
the DDC Percentage to a dollar figure.
2. Determination and Timing of a Dividend Distribution
On or about January 15 of each year of the rate period (FY 2002-
2006), the Administrator will determine whether the AANR exceeds the
DDC Threshold. If the AANR exceeds the DDC Threshold: (1) Customers and
rate case parties will be so notified; and (2) the Administrator will
prepare a Five-Year Forecast. On or about March 1, the Administrator
will propose to distribute or not distribute dividends. The
Administrator will issue a final decision on the proposal on or about
April 15.
Dividends distributed to customers are included in energy
deliveries beginning May 1, and, for any fiscal year 2002-2005, remain
in affect for 12 months; i.e., through April 30 of the following year.
In the last year of the rate period (FY 2006), the rebate would expire
on September 30, 2006.
3. Determining How the Distribution is Allocated
The first $15 million of the DDC Amount, if the DDC Amount exceeds
$15 million, or the entire DDC Amount if it equals $15 million or less,
will be allocated to qualifying customers participating in the
Conservation and Renewables Discount Program (C&R
[[Page 44345]]
Discount). The C&R Discount is a rate mechanism designed to encourage
incremental conservation and renewable resource development by BPA's
power purchasers under PF, IP, RL, and NR rate schedules. See
Conservation and Renewables Discount GRSP, Section II.A.
BPA intends to conduct a separate public consultation process by
October 1, 2001, to develop the criteria for allocating any remaining
DDC Amount (exceeding the $15 million for the C&R Discount) among
customers and stakeholders.
4. Dividend Distribution Notification Process
BPA shall follow the following notification procedures:
a. Financial Performance Status Reports
By no later than August 31 of each year, BPA shall post on its
electronic information access site (World Wide Web) a forecast of AANR
attributable to the generation function for the fiscal year ending
September 30. By December 1 of each year, BPA shall post on its World
Wide Web site the unaudited AANR.
b. Notice of DDC Trigger
On or about January 15 in each of the fiscal years 2002-2006, BPA
will notify all power customers and rate case parties if the AANR
exceeds the DDC Threshold. (If the December unaudited AANR report for
the generation function indicated that the DDC Threshold might be
exceeded, and the audited actuals show that it was not exceeded,
customers will also be notified). Notification will include the AANR
for the prior fiscal year, the DDC Amount, the calculation of the DDC
Amount, and the estimated resulting Power Customer DDC Percentage for
each applicable rate schedule. The notice shall also describe the data
and assumptions relied upon by BPA. Such data, assumptions, and
documentation, if non-proprietary and/or non-privileged, shall be made
available for review at BPA upon request. The notice shall also contain
the tentative schedule for the remainder of the DDC implementation
process.
(1) On or about March 1 of any of the fiscal years 2002-2006 in
which the AANR exceeds the DDC Threshold, the Administrator will post
the Five-Year Forecast on BPA's World Wide Web site and will propose to
distribute or not distribute dividends. During March, BPA will conduct
a public review and comment process on the proposal.
(2) On or about April 15 of any of the fiscal years 2002-2006 in
which the AANR exceeds the DDC Threshold, BPA shall notify customers to
which the DDC applies of the decision on the proposal, the final
calculation of the DDC Amount, the allocation of the DDC Amount, and,
if applicable, the resulting level of the Power Customer DDC Percentage
to be applied to each applicable firm power rate schedule.
I. Excess Factoring Charges
1. Excess Within-Day Factoring Charge
The within-day factoring test compares the hour-by-hour shape of
the customer's load to the customer's hour-by-hour energy take from BPA
within a day. This test identifies whether or not the hour-by-hour
shape of the customer's take from BPA has used more within-day
factoring service, measured in kilowatthours, than the underlying load
would have used.
Excess Within-Day Factoring Charge, for any hour(s) in the month,
applies to that amount of hourly energy in excess of the authorized
maximum energy amounts defined by the customer's within-day load shape.
The total amount of Excess Within-Day Factoring Charge during the
HLH's of the month shall be billed the greater of:
a. Five (5) mills/kWh;
b. Among all HLH periods of the billing month, the maximum within-
day difference between the highest hourly HLH California ISO
Supplemental Energy price (NP15) and the lowest hourly HLH California
ISO Supplemental Energy price (NP15).
The total amount of Excess Within-Day Factoring Charge during the
LLH's of the month shall be billed the greater of:
a. Five (5) mills/kWh;
b. Among all LLH periods of the billing month, the maximum within-
day difference between the highest hourly LLH California ISO
Supplemental Energy price (NP15) and the lowest hourly LLH California
ISO Supplemental Energy price (NP15).
In the event that the index for ISO Supplemental Energy expires,
that index will be replaced for the purpose of deriving Excess Within-
Day Factoring Charges by another hourly energy index, such as the
California PX (NW1 or NW 3), at a hub at which Northwest parties can
trade.
2. Excess Within-Month Factoring Charges
The within-month factoring test compares the day-by-day shape of
the customer's load to the customer's day-to-day energy take from BPA
within a month. This test identifies whether the day-to-day shape of
the customer's take from BPA used more within-month factoring service
than the underlying load would have used. The within-day factoring test
(see above) is not equipped to identify a factoring service issue if,
for example, the customer resource deliveries were zero for a
particular day. The within-month factoring test is equipped to address
that type of instance. The within-month factoring test establishes an
upper and lower boundary for each diurnal period of the day. Excess
within-month factoring for each diurnal period is the greater of: (1)
the sum of the amounts greater than the upper boundary; or (2) the sum
of the amounts less than the lower boundary.
Excess Within-Month Factoring Charge applies to that amount of
energy take that either exceeds or falls short of a range defined by:
(1) a flat load placement on BPA; and (2) a load placement that follows
the customer's actual load shape.
The Excess Within-Month Factoring quantities are reduced by any
Unauthorized Increase Energy amounts in the like diurnal period, and
only the residual is charged the Excess Within-Month Factoring Charge.
The Excess Within-Month Factoring during the HLH's of the month
shall be billed the greater of:
a. Five (5) mills/kWh.
b. The highest peak DJ Mid-C Index price for firm power during the
month LESS the lowest peak DJ Mid-C Firm Index price for firm power
during the month.
c. The highest average HLH California ISO Supplemental Energy price
(NP15) (average of hours 7 through 22, excluding Sundays) during the
month LESS the lowest average HLH California ISO Supplemental Energy
price (NP15) for the same period.
The Excess Within-Month Factoring during the LLH's of the month
shall be billed the greater of:
a. Five (5) mills/kWh.
b. The highest offpeak DJ Mid-C Index price for firm power during
the month LESS the lowest offpeak DJ Mid-C Index price for firm power;
c. The highest average LLH California ISO Supplemental Energy price
(NP15) (average of hours 1 through 6, and 23, and 24 Monday through
Saturday; average of hours 1 through 24 Sunday) during the month LESS
the lowest average LLH California ISO Supplemental Energy price (NP15)
for the same month in the same time period.
In the event that the index for ISO Supplemental Energy or DJ Mid-C
Index expires, that index will be replaced for the purpose of deriving
Excess Within-
[[Page 44346]]
Month Factoring Charges by another hourly or diurnal energy index, such
as the California PX (NW1 or NW3), at a hub at which Northwest parties
can trade.
J. Flexible IP Rate Option
The Flexible IP rate option will be offered at BPA's discretion to
purchasers who make a contractual commitment to purchase under this
option for all five years of the rate period. The charges and billing
factors under this option will be specified by BPA at the time the
Administrator offers to make power available to a Purchaser under this
option. The actual charges and billing factors will be mutually agreed
to by BPA and the Purchaser subject to satisfying the following
condition:
Equivalent Net Present Value Revenues: Forecasted revenues from a
Purchaser under the Flexible IP rate option must be equivalent, on a
net present value basis, to the revenues BPA would have received had
the appropriate charges specified in the IP rate schedule Section II
been applied to the same sales.
The Flexible IP rate contract may establish a limit on the amount
of power purchased at the Flexible IP rate. In this case, purchases
beyond the contractual limit will be billed at the Demand and Energy
charges specified in the IP rate schedule Section II unless such power
would be charged as an Unauthorized Increase.
Risk Adjustments: Credit risk associated with individual customers
will be a factor in establishing any flexible rate option.
Creditworthiness will be determined by BPA consistent with prevailing
business standards, and applied consistently to each customer. Such
credit risks will be dealt with through a ``margin deposit,'' expense
charge, built into the rates, or other methods acceptable to BPA.
K. Flexible NR Rate Option
The Flexible NR rate option will be offered at BPA's discretion to
purchasers who make a contractual commitment to purchase under this
option. The charges and billing factors under this option shall be
specified by BPA at the time the Administrator offers to make power
available to a Purchaser under this option. The customers purchasing
under the Flexible NR rate option purchase the same set of power
products and services that they would otherwise purchase under the rate
schedule. The actual charges and billing factors will be mutually
agreed to by BPA and the Purchaser subject to satisfying the following
condition:
Equivalent Net Present Value Revenues: Forecasted revenues from a
Purchaser under the Flexible NR rate option must be equivalent, on a
net present value basis, to the revenues BPA would have received had
the appropriate charges specified in the NR rate schedule Section II
been applied to the same sales.
The Flexible NR rate contract may establish a limit on the amount
of power purchased at the Flexible NR rate. In this case, purchases
beyond the contractual limit will be billed at the Demand and Energy
(and Load Variance and SUMY, if appropriate) charges specified in the
PF rate schedule Section II, unless such power would be charged as an
Unauthorized Increase.
The Flexible NR rate option is only available for development of an
energy rate that is stepped up in FY 2005 and 2006.
L. Flexible PF Rate Option
The Flexible PF rate option will be offered at BPA's discretion to
purchasers who make a contractual commitment to purchase under this
option. The charges and billing factors under this option shall be
specified by BPA at the time the Administrator offers to make power
available to a Purchaser under this option. The customers purchasing
under the Flexible PF rate option purchase the same set of power
products and services that they would otherwise purchase under the rate
schedule. The actual charges and billing factors will be mutually
agreed to by BPA and the Purchaser subject to satisfying the following
condition:
Equivalent Net Present Value Revenues: Forecasted revenues from a
Purchaser under the Flexible PF rate option must be equivalent, on a
net present value basis, to the revenues BPA would have received had
the appropriate charges specified in the PF rate schedule Section II
been applied to the same sales.
The Flexible PF rate contract may establish a limit on the amount
of power purchased at the Flexible PF rate. In this case, purchases
beyond the contractual limit will be billed at the Demand and Energy
(and Load Variance, and SUMY if appropriate) charges specified in the
PF rate schedule Section II, unless such power would be charged as an
Unauthorized Increase.
The Flexible PF rate option is only available for development of an
energy rate that is stepped up in FY 2005 and 2006.
M. Green Energy Premium
1. Overview of the Premium
The Green Energy Premium (GEP) is a premium ranging from zero to
$40/megawatthour (MWh) that a customer elects to pay BPA to ensure that
BPA is producing some system power from Environmentally Preferred Power
(EPP) resources. The GEP is the difference between the customer's
applicable average annual energy charge under the PF-02, RL-02, NR-02,
and IP-02 rates and the total cost of the EPP resource selected by the
customer. The GEP is applied to the number of EPP MWhs that the
customer has elected to purchase. BPA guarantees the customer paying
the premium that BPA will produce an amount of EPP equal to the amount
of energy subject to this adjustment. The GEP will be charged in a line
item on the monthly power bill of each participating.
The costs to be considered in determining the applicable GEP
include, but are not limited to:
Costs of existing EPP resources, over and above the cost
of BPA system resources.
Costs of new EPP resources, over and above the cost of BPA
system resources.
Costs of BPA system resources.
Endorsement fees for specific EPP resources.
Market purchases of EPP resources.
Transmission and other services required to integrate EPP
resources into the BPA system.
2. Calculation and Application of the Premium
a. Determination of the Premium
For a customer buying power from BPA under a requirements firm
power sales contract, the amount of EPP and the premium will be
determined as part of the product selection process and will be
completed as part of the power sales contract negotiation during the
Subscription window. The charge will not exceed $40 per MWh and may be
as low as zero. The premium will be zero if the unit cost of the GEP
resource(s) dedicated to the customer is equal to, or less than, the
energy charge of the applicable rate. The premium will be equal to the
average unit cost of the GEP resource(s) minus the applicable average
PF-02, RL-02, NR-02, and IP-02 energy charge.
b. Determination of Individual Customer GEP
(1) During the Subscription window, customers will be provided
notice of the availability of specific GEP products and associated
premiums. The total GEP
[[Page 44347]]
for the customer will be based on the customer's elections of product
amounts and content.
(2) The average annual energy charge will be calculated as the
average per kilowatthour (kWh) charge for an annual flat undelivered
product using the energy charges applicable to the customer. Where
customers are purchasing under more than one rate schedule, the average
energy charge will be calculated using expected loads and applicable
rate schedules.
(3) The individual customer GEP for billing will be the total cost
of the product selected by the customer minus the average annual energy
charge.
c. Application of the GEP
The GEP will be applied after BPA has determined all other charges
and credits except the Conservation and Renewables Discount line item,
on the participating customer's power bill.
d. Billing for the Premium
The customer's bill will include a line item showing the kWh amount
of EPP purchased times the GEP for the products elected and the total
cost. The calculation will appear as:
(EPP amount) kWh * GEP mills/kWh = $XXXXX
N. Guaranteed Delivery Charge (NF only)
A surcharge of 2.00 mills/kWh of Billing Energy is applied whenever
BPA guarantees delivery of nonfirm energy to a Purchaser under the NF
Standard rate or Market Expansion rate.
O. Industrial Firm Power Targeted Adjustment Charge (IPTAC)
1. Availability
The Industrial Firm Power Targeted Adjustment Charge (IPTAC)
pertains to the IP rate schedule. The IPTAC will be applied to Firm
Power requirements service of DSIs who take service from a combination
of Federal inventory and power purchased from the market during the
2002 rate period.
The maximum total requirements service the IPTAC will be developed
for, and applied to, is 1,440 aMW (flat, annual block). The total
inventory used to provide this requirement service will be composed of
990 aMW from Federal inventory and 450 aMW of market purchases.
There will be two rates for the IPTAC product. 1210 aMW will be
sold at $23.50 per MWh, and 230 aMW sold at $25 per MWh.
P. Low Density Discount
1. Application and Definitions
For eligible Purchasers as defined in section 2 below, a discount
shall be applied each billing month to BPA's charges for the following
components of Priority Firm Power, New Resources Firm Power and
Residential Load Firm Power service: (1) Demand; (2) HLH purchases; (3)
LLH purchases; and (4) Load Variance. The Low Density Discount (LDD)
shall not be applied to Unauthorized Increase Charges, Excess Factoring
Charges, transmission charges or any other charges. The discount shall
be revised annually based on data supplied by June 30 of each Calendar
Year (CY) for the previous CY and shall become effective on the
upcoming October 1.
a. The Kilowatthour/Investment Ratio
The kWh/Investment (K/I) ratio is calculated annually based on the
data supplied by June 30 for the previous CY. The K/I ratio is
calculated by dividing the Purchaser's Total Retail Load during the CY
by the value of the Purchaser's depreciated electric plant (excluding
generation plant) at the end of the CY.
b. The Consumers/Mile of Line Ratio
The Consumers/Mile of Line (C/M) ratio is determined annually using
the data supplied by June 30 for the previous CY. The C/M ratio is
calculated by dividing the maximum number of consumers on the
distribution system, in any one month during the CY, by the end of CY
number of pole miles of distribution.
Consumer means every billed consumer regardless of usage.
Separately billed services for water heating and security lights are
not counted as an additional billed consumer.
The number of pole miles of distribution line means the end of CY
pole miles. Distribution lines are defined as lines that deliver
electric energy from a substation or metering point, at a voltage of
34.5 kilovolt or less, to the point of attachment to the consumer's
wiring and include primary, secondary, and service facilities. (Service
drops are considered service facilities.)
These calculations shall be based on CY data provided from the
Purchaser's annual financial and operating reports. The Purchaser shall
certify that the data submitted is correct and that no loads gained as
provided in section 6, Retail Access Exclusion, are receiving LDD
benefits.
In calculating these ratios, BPA shall compile the data submitted
by the Purchaser based on the Purchaser's entire electric utility
system in the Pacific Northwest (PNW). For Purchasers with service
territories that include any areas outside the PNW, BPA shall compile
data submitted by the Purchaser separately on the Purchaser's system in
the PNW and on the Purchaser's entire electric utility inside and
outside the PNW. BPA will apply the eligibility criteria and discount
percentages to the Purchaser's system within the PNW and, where
applicable, also to its entire system inside and outside the PNW. The
Purchaser's eligibility for the LDD will be determined by the lesser
amount of discount applicable to its PNW system or to its combined
system inside and outside the PNW. BPA, in its sole discretion, may
waive the requirement to submit separate data for the Purchaser with a
small amount of its system outside the PNW. Results of the calculations
shall not be rounded.
A Purchaser who has not provided BPA with the requisite pieces of
data needed to calculate the K/I and C/M ratios by June 30 of each
year, for the prior CY, shall be declared ineligible for the LDD,
effective the upcoming October 1.
If a Purchaser's data was submitted on time and a revision is
necessary to the data, the revised data must be resubmitted no later
than 12 months after the original submission date to be considered for
an adjustment.
2. Eligibility Criteria
To qualify for a discount, the Purchaser must meet all five of the
following eligibility criteria:
a. The Purchaser must serve as an electric utility offering power
for resale;
b. The Purchaser must agree to pass the benefits of the discount
through to the Purchaser's eligible consumers within the region served
by BPA;
c. The Purchaser's average retail rate for the reporting year must
exceed the Purchaser's average cost of BPA power purchases under the
applicable rate for the qualifying period by at least 10 percent. For
CY 2001, the Purchaser's average cost of BPA power purchases under the
applicable rate shall be under the applicable 1996 rate for the first
nine months and under the applicable 2002 rate for the last three
months. For CY 2002 and beyond, the Purchaser's average cost of BPA
power purchases under the applicable rate shall be under the applicable
rate for all 12 months;
d. The Purchaser's K/I ratio must be less than 100; and
e. The Purchaser's C/M ratio must be less than 12.
[[Page 44348]]
3. Discounts
The Purchaser shall be awarded the following discount beginning
October 1, 2001, in accordance with section 4 below. The discount will
be the sum of the two potential discounts for which the Purchaser
qualifies, based on the following Table C. The discount shall not
exceed 7 percent.
Table C.--LDD Percentage Discount Table
------------------------------------------------------------------------
Applicable range Applicable range
Percentage discount for KWh/investment for consumers/mile
(K/I) ratio (C/M) ratio
------------------------------------------------------------------------
0.0............................. 35.0 X 12.0 X
0.5............................. 31.5 X 10.8 X
< 35.0 < 12.0
1.0............................. 28.0 X 9.6 X
< 31.5 < 10.83
1.5............................. 24.5 X 8.4 X
< 28.0 < 9.6
2.0............................. 21.0 X 7.2 X
< 24.5 < 8.4
2.5............................. 17.5 X 6.0 X
< 21.0 < 7.2
3.0............................. 14.0 X 4.8 X
< 17.5 < 6.0
3.5............................. 10.5 X 3.6 X
< 14.0 < 4.8
4.0............................. 7.0 X 2.4 X
< 10.5 < 3.6
4.5............................. 3.5 X 1.2 X
< 7.0 < 2.4
5.0............................. X 3.5 X < 1.2
------------------------------------------------------------------------
4. LDD Phase-Out Adjustment
If the Purchaser satisfies the eligibility criteria (2. a. through
e.), and the calculated discount differs from the existing discount by
more than one-half of 1 percent, the applicable discount will be:
a. The existing discount plus \1/2\ percent if the calculated
discount exceeds the existing discount; or
b. The existing discount minus \1/2\ percent if the calculated
discount is less than the existing discount.
The foregoing formula will be applied each October 1 until the
then-current calculated discount is fully phased out.
The Purchaser is not eligible to receive any discount, effective
each October, if the Purchaser fails to meet the eligibility criteria
in section 2. a. through e.
5. Benefits Legislation Exclusion
If the Federal government or a State, or local government adopt(s)
a law, regulation or other provision that establishes benefits for low
density and/or rural electric systems that are similar to benefits
provided by BPA's LDD, then the Purchaser's service territory within
that jurisdiction shall no longer be eligible to receive the LDD. The
effective date for discontinuation of the LDD and the Phase-Out
Adjustment shall be the implementation date of the jurisdiction's
benefits provision legislation. BPA will evaluate new provisions and
determine, in BPA's judgment, whether they provide benefits similar to
the LDD. If BPA concludes that the benefits are similar, BPA will
conduct a public comment process before issuing a final decision.
6. Retail Access Exclusion
Load that is gained by a Purchaser as a direct result of retail
access rights established by Federal, State, or local legislation, and
that would not otherwise have been gained absent such legislation, is
not eligible to receive the benefits provided by the LDD. The Purchaser
shall not pass the benefits of the LDD to its gained load consumers.
Q. Rate Melding
BPA's rate proposal allows the customers more than one rate choice.
Separately tracking and administering the customer's rate choices and
maintaining the distinction would increase BPA's overall cost of
providing rate choices. For administrative simplicity upon mutual
agreement between BPA and the customer, BPA may offer to meld the
customer's rate choices into a single composite set of rates that
reflects the specific choices made by the customer. BPA will ensure
that this melded set of rates will result in a bill that is nearly
mathematically equivalent to applying the customer's individual choices
throughout the rate period. BPA will provide the affected customer the
calculations it used to establish the melded rates and provide 30 days
for the customer to review and accept the melding calculation before it
implements the melded rates. Melded rates established by BPA will
continue until one of the customer's rate choices expires, or a rate
adjustment occurs that is provided for under the chosen rate schedules
(e.g., Cost Recovery Adjustment Clause), or a significant change in the
loads applicable to the rates occurs.
R. Slice True-Up Adjustment
By March 31 of each year, BPA will calculate the final true-up for
the previous fiscal year based on the difference between the Slice
Revenue Requirement's audited actual expenses (and credits) and those
expenses (and credits) forecasted in the 2002 rate case (except for the
Inventory Solution which is billed based on the estimate from the 2002
rate case). This true-up will be the True-Up Adjustment Charge and will
be applied to the customer's May bill. In addition, an interim true-up
adjustment procedure to allow for an intermediate true-up prior to
March 31, will be developed in the power sales contracts with the
customers.
S. Stepped Up Multiyear Block (SUMY)
The SUMY Block charge applies to Block purchases if the annual
amounts increase (i.e., step up) over multiple years of a purchase
commitment term due to increases in customer net requirement which are
not subject to a Targeted Adjustment Charge (TAC).
The cost for the SUMY Block service is the difference between PF-02
rates and the AURORA On-and Off-Peak market price forecast in the final
rate proposal.
The starting basis for computing the SUMY Block quantities will be
the purchaser's subscribed block amount for the period October 2001
through September 2002. Costs will be computed for 24 monthly blocks
(12 HLH and 12 LLH) for each year of the rate period. Each year's
monthly amount above the base year's monthly amount is the stepped up
quantity. Total cost is the sum of each month's HLH and LLH stepped up
quantities times each month's HLH and LLH costs.
The SUMY charge is the total cost of the SUMY Block service divided
by the total Block energy purchase including stepped up amounts. The
charge is in addition to the PF and NR energy and demand rates that the
customer will pay for these power purchases.
BILLING CODE 6450-01-P
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[GRAPHIC] [TIFF OMITTED] TN13AU99.554
BILLING CODE 6450-01-C
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Formula for Calculating a Charge for SUMY Block Service
Step 1: Determine HLH MWh of SUMY Block. October 2002 HLH Block minus
October 2001 HLH Block = HLH MWh of SUMY Block for October 2002
Step 2: Determine LLH MWh of SUMY Block. October 2002 LLH Block minus
October 2001 LLH Block = LLH MWh of SUMY Block for October 2002
Step 3: Determine Cost of HLH SUMY Block service. HLH MWh of SUMY Block
* (Aurora October 2002 On-Peak Market Price minus October 2002 PF HLH
energy and demand rate) = Total Cost of October 2002 HLH SUMY Block
service.
Step 4: Determine Cost of LLH SUMY Block service. LLH MWh of SUMY Block
* (Aurora October 2002 Off-Peak Market Price minus October 2002 PF LLH
energy rate) = Total Cost of October 2002 LLH SUMY Block service.
Step 5: Determine Cost for all months of the rate period by repeating
Steps 1-4 for each month of the remaining purchase period always
calculating the MWh difference from the first year and corresponding
month. Calculate the price difference using that year's and month's
market price and PF rate.
Step 6: Custom Charge: Divide the Net Present Value (NPV) of the stream
of costs derived from Steps 1-5 by the NPV of the total block purchase
including SUMY Block in MWh for the five-year period. The NPV uses a
6.8 percent discount rate and is present valued to October 2001.
Step 7: Billing Determinant: Custom charge is applied to each MWh of
block purchase including the SUMY Block amounts.
T. Supplemental Contingency Reserves Adjustment (SCRA)
The energy charges stated in the IP-02 rate schedule will be
adjusted to reflect the negotiated SCRA adjustment. PBL will negotiate
with any DSI interested in providing Supplemental Contingency Reserves
(Supplemental Reserves). Supplemental Reserves refers to generating
capacity, and associated energy, fully available within 10 minutes
notice of a system disturbance. PBL has established a flexible rate
with a cap that will permit BPA to negotiate a price according to the
quality of reserves provided. The maximum amount PBL may pay for
Supplemental Reserves from a DSI is capped at $5.92/kW-mo.
The suitability and quality of the Supplemental Reserves will be
measured by whether they have certain characteristics, some of which
are required and others optional. Any Supplemental Reserves purchased
by PBL must be consistent with NERC, WSCC, and NWPP criteria:
1. The interruptible load must be offline within five minutes after
a call by BPA;
2. In the event of a system disturbance, the interruptible load
must be accessible prior to a request for reserves from other NWPP
parties;
3. The interruptible load must be available to be offline for up to
60 minutes.
In addition to these required characteristics, the issues
identified below will help define when PBL may pay the maximum value
for Supplemental Reserves:
1. The extent to which PBL has the discretion when and how to use
all operating reserves and to determine what resources to call on in
the event of a system disturbance;
2. Whether there are limitations on the number of times or total
minutes the reserves may be utilized.
U. Targeted Adjustment Charge
1. Availability
The Targeted Adjustment Charge (TAC) pertains to the PF rate
schedule, except for PF exchange program and PF exchange Subscription
rates. The TAC applies to firm power requirements service to regional
firm load that results in an unanticipated increase in BPA's projected
loads within the rate period. The TAC will be applied to the applicable
rate for requirements service requested after the Subscription window
closes.
TAC will also apply to subsequent requests made by a customer under
a Subscription contract for requirements service for such customer's
load(s) that had been previously served by that customer's 5(b)(1)(A)
or 5(b)(1)(B) resources.
If a public agency customer that requests requirements service from
BPA is annexing or otherwise taking on the obligation of load from
another public agency customer and the request to annex or take on load
obligation and the reduction in obligation are equal amounts such that
BPA's total load obligation does not increase, BPA may exempt the newly
acquired load from the TAC and apply PF-02. The TAC will apply if the
annexed requirements service has been previously served by that
customer's 5(b)(1)(A) or 5(b)(1)(B) resources.
Where a public agency customer annexes residential and small farm
load previously served by an IOU and such load was receiving BPA power
or financial benefits through Subscription, the public agency customer
will receive through assignment the right to the IOUs power and/or
financial benefits applicable to the annexed load. BPA will deliver the
same amount of firm power that was assigned by the IOU to the annexing
public agency customer at the PF-02 rate. Power provided by BPA to the
public agency customer to meet the remaining annexed load not covered
by the power assigned from the IOU will be subject to the TAC.
The TAC will apply for the duration of the Customer's contract or
until 2006, whichever occurs first. For five-year contracts that
guarantee rates for a multitude of periods (for example, contracts that
have both three-year and five-year components) the TAC applies until
the end of the five-year rate period. If a new public requests service,
the TAC, if any, must apply until 2006.
If a PF Preference customer is serving a portion of its load with a
certifiable renewable resource eligible for the C&R Discount, or
contract purchases of certified renewable resource power eligible for
the C&R Discount for a period less than the term of the customer's BPA
requirements firm power contract, then the customer may request, during
the 2002 to 2006 rate period, requirements firm power service for such
load at the end of the specified contract period at PF Preference (PF-
02) without being subject to the TAC. This limited exception applies to
the first 200 aMW in any contract year, or to amounts that BPA
specifies in accordance with its Policy on the Determination of Net
Requirements.
2. Energy Charge
The TAC is a monthly mills/kWh adjustment to the HLH and LLH energy
rates specified in the 2002 rate schedule, and is applied to that
portion of the Purchaser's load that is subject to the TAC. The TAC
rate adjustment will be established based on the following formula:
TAC = [(Incr $ * Incr Amt)--(Rate $ * Incr Amt)]/TAC Amt
Where:
TAC Amt = The amount of load subject to the TAC, determined monthly.
Rate $ = The monthly PF energy rate shown in the applicable rate
schedule.
Inventory Amt=Amount of energy in inventory available to serve this
load based on average annual Federal system firm resource capability,
[[Page 44354]]
estimated using critical water excluding balancing purchases and
purchases for system augmentation, from the 2002 rate case with updates
if BPA determines that is necessary.
Incr $=Monthly cost to BPA, including a handling fee, of incremental
power purchases expressed in mills/kWh. These costs also may include,
where applicable, wheeling, ancillary, and other charges BPA may incur
in purchasing power from other entities such as, but not limited to,
the California ISO or the California PX.
Incr Amt=Amount of incremental power required, determined monthly and
defined as the TAC Amt minus the Inventory Amt. (If there is no
available Inventory Amt, the Incr Amt will equal the TAC Amt).
Incr $ is greater than Rate $ (If Incr $ is less than Rate $, the TAC
is 0 mills/kWh).
TAC is the monthly rate adjustment in mills/kWh. BPA will calculate
the cost (Incr $) per month in mills/kWh of the additional power per
month (Incr Amt) for a specific customer request. BPA will establish
the cost of the additional power by the following methods:
BPA will establish the price based on BPA's monthly cost
to purchase the incremental load by purchases of resources at market.
V. Unauthorized Increase Charge
1. Charge for Unauthorized Increase in Demand
The amount of Measured Demand during a billing hour that exceeds
the amount of demand the purchaser is contractually entitled to take
during that hour shall be billed at the greater of:
a. Three (3) times the applicable monthly demand charge;
b. The sum of hourly California ISO Spinning Reserve Capacity
prices for all HLHs in the month, at path NW1 (COB); or
c. The sum of hourly California ISO Spinning Reserve Capacity
prices for all HLHs in the month, at path NW3 (NOB).
In the event that the hourly California ISO Spinning Reserve
Capacity market expires, the Unauthorized Increase Charge for demand
shall be the greater of:
a. Three (3) times the applicable monthly demand charge;
b. The sum of hourly or diurnal prices for all HLHs in the month,
at a hub at which Northwest parties can trade, established between
October 1, 2001, and September 30, 2006.
2. Charge for Unauthorized Increase in Energy
The amount of Measured Energy during a diurnal period of a billing
month, day, or hour that exceeds the amount of energy the purchaser is
contractually entitled to take during that period shall be billed the
greater of:
a. One hundred (100) mills/kWh; or
b. For the month in question, the greater of:
(1) the highest diurnal DJ Mid-C Index price for firm power; or
(2) the highest hourly ISO California Supplemental Energy price
(NP15).
In the event that either the ISO California Supplemental Energy
price index or the DJ Mid-C Index expires, the index will be replaced
for purposes of the Unauthorized Increase Charge for energy by:
(1) The highest price experienced for the month at the California
PX, NW1 (COB);
(2) The highest price experienced for the month at the California
PX, NW3 (NOB); or
(3) The highest price experienced for the month from any applicable
new hourly or diurnal energy index at a hub at which Northwest parties
can trade, established between October 1, 2001, and September 30, 2006.
Section III. Definitions
A. Power Products and Services Offered By the Power Business Line of
BPA
1. Actual Partial Service Product--Simple/Complex
The Actual Partial Service Products are core Subscription products
that are available to purchasers who have a right to purchase from BPA
for their requirements. These products are intended for customers who
have contractual or generating resources with firm capabilities and
therefore require a product other than Full Service. The Simple and
Complex versions of this product category differ in that the Complex
version is subject to the Factoring Benchmark tests in the billing
process and to potential Excess Factoring Charges. The Simple version
encompasses several possible approaches to customer resource
declaration, all of which obviate the need for the Factoring Benchmark
tests.
2. Block Product
The Block Product is a core Subscription product that is available
to purchasers who have a right to purchase from BPA for their
requirements. This product is available in HLH and LLH quantities per
month, with the hourly amount flat for all hours in such periods.
3. Block Product with Factoring
The Block Product with Factoring is a combination of the Block
Product with the core Subscription staple-on product for Factoring
Service. Factoring provides the service of distributing Block energy to
follow Purchaser hourly load needs to the extent of such Block energy.
4. Block Product With Shaping Capacity
The Block Product with Shaping Capacity is a combination of the
Block HLH energy product and the core Subscription staple-on product
for Shaping capacity. Shaping capacity allows the customer to
preschedule Block energy with some limited shape among HLHs within a
contractually specified bandwidth.
5. Construction, Test and Start-Up, and Station Service
Power for the purpose of Construction, Test and Start-Up, and
Station Service for a generating resource or transmission facility
shall be made available to eligible purchasers under the Priority Firm
Power (PF-02), New Resources Firm Power (NR-02), and Firm Power
Products and Services (FPS-96), rate schedules. Such power is not
available for the PF Exchange Program rate, the PF Exchange
Subscription rate, and the Residential Load rate.
Construction, Test and Start-Up, and Station Service power must be
used in the manner specified below:
a. Power sold for construction is to be used in the construction of
the project.
b. Power sold for test and start-up may be used prior to commercial
operation, both to bring the project online and to ensure that the
project is working properly.
c. Power sold for station service may be purchased at any time
following commercial operation of the project. Once the project has
been energized for commercial operation, the Purchaser may use station
service power for start-up, shutdown, normal operations, and operations
during a shutdown period.
d. Power sold for Construction, Test and Start-Up, and Station
Service is not available for replacement of lost generation for forced
or planned outages or resource underperformance.
6. Core Subscription Products
BPA's Core Subscription Products are described in the BPA Product
Catalog. Core Subscription Products are available at the posted rates
for customers who have a right to purchase them.
The core products are:
Actual Partial Service Product--Simple/Complex
Block Product
Block Product with Factoring
Block Product with Shaping Capacity
[[Page 44355]]
Full Service Product
7. Customer System Peak (CSP)
Customer System Peak (CSP) is the largest measured HLH Total Retail
Load (TRL) amount in kilowatts for the billing period.
8. Full Service Product
Full Service is a core Subscription product that is available to
purchasers who have a right to purchase from BPA for their
requirements. This product is available to customers who either have no
resources or whose resources meet the criteria for small, non-
dispatchable resources.
9. Industrial Firm Power
Industrial Firm Power is electric power that BPA will make
continuously available to a direct-service industrial (DSI) purchaser
subject to the terms of the Purchaser's power sales contract with BPA.
Deliveries may be reduced or interrupted as permitted by the terms of
the Purchaser's power sales contract with BPA. Adjustments as provided
in the Purchaser's power sales contract shall be made for power
restricted to provide reserves.
10. Load Variance
For core Subscription products, Load Variance is defined as the
variability in monthly energy consumption within the BPA customer's
system. Through the Load Variance charge under the Full and Actual
Partial Service Products, the customer's billing factors will follow
actual consumption. Load Variance is not applicable to Block Product
purchases. For purposes of pricing and rate tests under Pre-
Subscription contracts, the Load Variance charge is deemed to
correspond to the PF-96 Load Shaping charge.
11. New Resource Firm Power
New Resource Firm Power is electric power (capacity, energy, or
capacity and energy) that BPA will make continuously available:
a. For any New Large Single Load (NLSL); and
b. For Firm Power purchased by IOUs pursuant to power sales
contracts with BPA.
New Resource Firm Power is to be used to meet the Purchaser's firm
power load within the PNW. Deliveries of New Resource Firm Power may be
reduced or interrupted as permitted by the terms of the Purchaser's
power sales contract with BPA.
New Resource Firm Power is guaranteed to be continuously available
to the Purchaser during the period covered by its contractual
commitment, except for reasons of certain uncontrollable forces and
force majeure events. New Resource Firm Power is power where BPA agrees
to provide operating reserves in accordance with the standards
established by the NERC, WSCC, and the NWPP.
12. Nonfirm Energy
Nonfirm Energy is energy that is supplied or made available by BPA
to a Purchaser under an arrangement that does not have the guaranteed
continuous availability feature of Firm Power. Nonfirm energy is sold
primarily under the Nonfirm Energy rate schedule, NF-02. Nonfirm energy
also may be supplied under the NF-02 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. 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.
13. Priority Firm Power
Priority Firm Power is electric power (capacity, energy, or
capacity and energy) that BPA will make continuously available for
direct consumption or resale by public bodies, cooperatives, and
Federal agencies. Utilities participating in the Residential Exchange
under section 5(c) of the Northwest Power Act may purchase Priority
Firm Power pursuant to their Residential Exchange contracts with BPA.
Priority Firm Power is not available to serve NLSLs. Deliveries of
Priority Firm Power may be reduced or interrupted as permitted by the
terms of the Purchaser's power sales contract with BPA.
Priority Firm Power is guaranteed to be continuously available to
the Purchaser during the period covered by its contractual commitment,
except for reasons of certain uncontrollable forces and force majeure
events. Priority Firm Power is power where BPA agrees to provide
operating reserves in accordance with the standards established by the
NERC, WSCC, and NWPP.
14. Regulation and Frequency Response
Regulation and frequency response is the generating capacity of a
power system that is immediately responsive to AGC control signals
without human intervention. Regulation and frequency response is
required to provide AGC response to load and generation fluctuations in
an effective manner and to maintain desired compliance with NERC AGC
Control Performance
15. Residential Exchange Program Power
Residential Exchange Program Power is power BPA sells to a
Purchaser pursuant to the Residential Exchange Program. Under section
5(c) of the Northwest Power Act, BPA ``purchases'' power from PNW
utilities at a utility's Average System Cost (ASC). BPA then offers, in
exchange, to ``sell'' an equivalent amount of electric power to that
customer at BPA's PF rate applicable to exchanging utilities. The
amount of power purchased and sold is equal to the utility's eligible
residential and small farm load. Benefits must be passed directly to
the utility's residential and small farm customers.
16. Slice Product
The Slice product is a power sale based upon an eligible customer's
annual net firm requirements load and is shaped to BPA's generation
from the Federal system resources over the year. Slice purchasers are
entitled to a fixed percentage of the energy generated by the FCRPS.
The Slice purchaser's percentage entitlements are set by contract. The
Slice product includes both service to net requirements firm load as
well as an advance sale of surplus power.
B. Definition of Rate Schedule Terms
1. 2002 Contract
A 2002 contract is a contract for service in the FY 2002 through
2006 rate period that is signed after January 1, 1999.
2. Annual Billing Cycle
The Annual Billing Cycle is the 12 months beginning with the
customer's first monthly power bill for deliveries in the first billing
month starting on or after October 1.
3. Billing Demand
The Purchaser's Billing Demand is the amount of capacity to which
the demand charge specified in the rate schedule is applied. When the
rate schedule includes charges for several products, there may be a
Billing Demand quantity for each product. The calculation of Billing
Demand is described in the customer's contract.
4. Billing Energy
The Purchaser's Billing Energy is the amount of energy to which the
energy
[[Page 44356]]
charge specified in the rate schedule is applied. When the rate
schedule includes charges for several products, there may be a Billing
Energy quantity for each product. Billing Energy is divided into HLH
and LLH for this rate period.
5. California Independent System Operator (California ISO)
The FERC regulated control area operator of the ISO transmission
grid. Its responsibilities include providing non-discriminatory access
to the transmission grid, managing congestion, maintaining the
reliability and security of the grid, and providing billing and
settlement services. The ISO has no affiliation with any market
participant.
6. California ISO Spinning Reserve Capacity
The portion of unloaded synchronized generating capacity,
controlled by the California ISO, which is capable of being loaded in
10 minutes, and which is capable of running for at least two hours.
7. California ISO Supplemental Energy
Energy from generating units and other resources which have
uncommitted capacity following finalization of the hour-ahead schedules
and for which scheduling coordinators have submitted bids to the
California ISO at least 30 minutes before the commencement of the
settlement period.
8. California Power Exchange (California PX)
An independent agency responsible for conducting an auction for the
generators seeking to sell energy and for loads which are not otherwise
being served by bilateral contracts. The California PX is responsible
for scheduling generation in its scheduling (e.g., day-ahead) markets,
for determining hourly market clearing prices for its market, and for
settlement and billing for suppliers and Utility Distribution Company's
(UDC) using its market.
9. Contract Demand
The Contract Demand is the maximum number of kilowatts that the
Purchaser agrees to purchase and BPA agrees to make available, subject
to any limitations included in the applicable contract between BPA and
the Purchaser.
10. Contract Energy
Contract Energy is the maximum number of kilowatthours that the
Purchaser agrees to purchase and BPA agrees to make available, subject
to any limitations included in the applicable contract between BPA and
the Purchaser.
11. Control Area
A Control Area is the electrical (not necessarily geographical)
area within which a controlling utility operating under all NERC
standards has the responsibility to adjust its generation on an
instantaneous basis to match internal load and power flow across
interchange boundaries to other Control Areas.
12. Decremental Cost
Unless otherwise specified in a contractual arrangement,
Decremental Cost as applied to Nonfirm Energy transactions is defined
as:
a. All identifiable costs (expressed in mills/kWh) associated with
the use of a displaceable thermal resource or end-use load with
alternate fuel source to serve a purchaser's load that the purchaser is
able to avoid by purchasing power from BPA, rather than generating the
power itself or using an alternate fuel source; or
b. All identifiable costs (expressed in mills/kWh) 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.
13. Delivering Party
The entity supplying the capacity and/or energy to be transmitted
at Point(s) of Interconnection.
14. Demand Entitlement
For purchases made under contracts for core Subscription products,
Demand Entitlement is the largest HLH amount of power in kilowatts that
the purchaser is entitled to receive from BPA during the billing period
as specified in the contract.
15. Discount Period
The end of the rate period or the customer's contract term,
whichever comes first.
16. Dow Jones Mid-C Indexes (DJ Mid-C Indexes)
Peak and offpeak price indexes for sale of firm and nonfirm power
traded at the Mid-Columbia Bus.
17. Electric Power
Electric Power is electric peaking capacity (kilowatts) and/or
electric energy (kilowatthours).
18. Energy Entitlement
For purchases made under contracts for core Subscription products,
HLH and LLH Energy Entitlement is the sum in kilowatthours of amounts
for HLH and LLH energy respectively, that the purchaser is entitled to
receive from BPA as specified in the contract.
19. Federal System
The Federal System is the generating facilities of the FCRPS,
including the Federal generating facilities for which BPA is designated
as marketing agent; the Federal facilities under the jurisdiction of
BPA; and any other facilities:
a. From which BPA receives all or a portion of the generating
capability (other than station service) for use in meeting BPA's loads
to the extent BPA has the right to receive such capability. ``BPA's
loads'' do not include any of the loads of any BPA customer that are
served by a non-Federal generating resource purchased or owned directly
by such customer which may be scheduled by BPA;
b. Which BPA may use under contract or license; or
c. To the extent of the rights acquired by BPA pursuant to the 1961
U.S.-Canada Treaty relating to the cooperative development of water
resources of the Columbia River Basin.
20. Firm Power (PF-02, IP-02, NR-02, RL-02)
Firm Power is electric power (capacity and energy) that BPA will
make continuously available under contracts executed pursuant to
Section 5 of the Northwest Power Act.
21. Full Service Customer
A Full Service customer is one who is purchasing power from BPA
through the Full Service Product.
22. Generation System Peak
The Generation System Peak is the hour of the largest HLH output of
the Federal System that occurs during the customer's billing period.
23. Heavy Load Hours (HLH)
Heavy Load Hours (HLH) are all those hours in the peak period hour
ending 7 a.m. to the hour ending 10 p.m., Monday through Saturday,
Pacific Prevailing Time (Pacific Standard Time or Pacific Daylight
Time, as applicable). There are no exceptions to this definition; that
is, it does not matter
[[Page 44357]]
whether the day is a normal working day or a holiday.
24. Inventory Solution Costs
Costs associated with BPA's potential actions to supplement the
capability of the Federal System Resources, as a result of BPA's
Subscription process. It is currently not known whether an Inventory
Solution will be necessary, or what form the Inventory Solution will
take.
25. Light Load Hours (LLH)
Light Load Hours (LLH) are all those hours in the offpeak period
hour ending 11 p.m. to the hour ending 6 a.m., Monday through Saturday
and all hours Sunday, Pacific Prevailing Time (Pacific Standard Time or
Pacific Daylight Time, as applicable).
26. Measured Demand
The Purchaser's Measured Demand is that portion of its Metered or
Scheduled Demand provided by BPA to the Purchaser. If more than one
class of power is delivered to any point of delivery, the portion of
the measured quantities assigned to any class of power shall be as
specified by contract. Any delivery of Federal power not assigned to
classes of power delivered under other agreements shall be included in
the Measured Demand for PF, NR, or IP power as applicable. The portion
of the total Measured Demand so assigned shall constitute the Measured
Demand for each such class of power. Any residual quantity, after
determination of the Purchaser's contractual entitlement at a
particular rate, is considered ``unauthorized.'' Unauthorized increases
are billed in accordance with the provisions of these GRSPs.
In determining Measured Demand for any Purchaser who experiences an
outage as defined pursuant to the Purchaser's agreement with BPA, BPA
shall adjust any abnormal Integrated Demand due to, or resulting from:
a. Emergencies or breakdowns on, or maintenance of, the Federal
System Facilities; and
b. Emergencies on the Purchaser's facilities to the extent BPA
determines that such facilities have been adequately maintained and
prudently operated. BPA will follow its billing process in establishing
the Billing Demand should an outage cause an unusual Billing Demand
quantity. BPA will not give outage credits for demand.
27. Measured Energy
The Purchaser's Measured Energy is that portion of its Metered or
Scheduled Energy that is provided by BPA to the Purchaser during a
particular diurnal period (HLH or LLH) in a billing period. If more
than one class of power is delivered to any point of delivery, the
portion of the measured quantities assigned to any class of power shall
be as specified by contract. Any delivery of Federal power not assigned
to classes of power delivered under other agreements shall be included
in the Measured Energy for PF, NR, or IP power as applicable. The
portion of the total Measured Energy so assigned shall constitute the
Measured Energy for each such class of power. Any residual quantity,
after determination of the Purchaser's contractual entitlement at a
particular rate, is considered ``unauthorized.'' Unauthorized increases
are billed in accordance with the provisions of these GRSPs.
28. Metered Demand
The Metered Demand in kilowatts shall be the largest of the 60-
minute clock-hour Integrated Demands at which electric energy is
delivered to a purchaser:
a. At each point of delivery for which the Metered Demand is the
basis for determination of the Measured Demand;
b. During each time period specified in the applicable rate
schedule; and
c. During any billing period.
Such largest Integrated Demand shall be determined from
measurements made in accordance with the provisions of the applicable
contract and these GRSPs. This amount shall be adjusted as provided
herein and in the applicable agreement between BPA and the Purchaser.
29. Metered Energy
The Metered Energy for a purchaser shall be the number of
kilowatthours that are recorded on the appropriate metering equipment,
adjusted as specified in the applicable agreement and delivered to a
Purchaser:
a. At all points of delivery for which metered energy is the basis
for determination of the Measured Energy; and
b. during any billing period.
30. Mid-Columbia Bus (Mid-C Bus)
The switchyards associated with five non-Federal hydroelectric
projects, including Rocky Reach, Priest Rapids, Wanapum, Douglas, and
McKenzie. The following Federal switchyards which are operated by BPA
and interconnected with the non-Federal switchyards are also included:
Valhalla, Columbia, Midway, Sickler, and Vantage.
31. Monthly Federal System Peak Load
Monthly Federal System Peak Load is the peak load on the Federal
System during a customer's billing month, determined by the largest
hourly integrated demand produced from system generating plants in
BPA's control area and scheduled imports for BPA's account from other
control areas.
32. NP15
The portion of the California ISO's control area north of
transmission path 15.
33. NW1 (California-Oregon Border)
California PX and California ISO designation for delivery at COB
(Captain Jack/Malin).
34. NW3 (Nevada-Oregon Border)
California PX and California ISO designation for delivery at NOB.
35. Partial Service Customer
A Partial Service customer is any customer that is not a Full
Service customer.
36. Point of Delivery (POD)
A Point of Delivery is the contractual interconnection point where
power is delivered to the customer. Typically, a point of delivery is
located at a substation site, but it could be located at the change of
ownership point on a transmission line.
37. Point of Integration (POI)
A Point of Integration is the contractual interconnection point
where power is received from the customer. Typically a point of
integration is located at a resource site, but it could be located at
some other interconnection point to receive system power from the
customer.
38. Point of Interconnection (POI)
A Point of Interconnection is a point where the facilities of two
entities are interconnected.
39. Points of Metering (POM)
The Points of Metering (POM) shall be those points specified in the
contract at which TRL and Metered Amounts are measured.
40. Pre-Subscription Contract
A contract for service in the FY 2002 through 2006 rate period that
was signed prior to January 1, 1999, is a Pre-Subscription Contract.
41. Purchaser
Pursuant to the terms of an agreement and applicable rate
schedule(s), a Purchaser contracts to pay BPA for providing a product
or service.
[[Page 44358]]
42. Receiving Party
The entity receiving the capacity and/or energy transmitted by BPA
to a Point(s) of Delivery.
43. Retail Access
Retail Access is nondiscriminatory retail distribution access
mandated either by Federal or State law which grants retail electric
power consumers the right to choose their electricity supplier.
44. Scheduled Demand
For purposes of applying the rates herein to applicable purchases
by the Purchaser, the Scheduled Demand in kilowatts is the largest of
the hourly demands at which electric energy is scheduled by BPA for
delivery to a purchaser:
a. To each system for which Scheduled Demand is the basis for
determination of the Measured Demand;
b. During each time period specified in the applicable rate
schedule; and
c. During any billing period.
Scheduled Demand is deemed delivered for the purpose of determining
Billing Demand.
45. Scheduled Energy
For purposes of applying the rates herein to applicable purchases
by the Purchaser, Scheduled Energy in kilowatthours shall be the sum of
the hourly demands at which electric energy is scheduled by BPA for
delivery to a purchaser:
a. For each system for which Scheduled Energy is the basis for
determination of the Measured Energy; and
b. During any billing period.
Scheduled Energy is deemed delivered for the purpose of determining
Billing Energy.
46. Slice Administrative Costs
All overhead costs incurred by BPA that are attributable to the
implementation of the Slice product.
47. Slice Revenue Requirement
The Slice Revenue Requirement is comprised of all the line items in
BPA's PBL revenue requirement as identified in all of the PBL's rate
cases that are effective during the term of the Slice Purchaser's
contract except for the following items: (1) transmission costs (other
than those associated with the fulfillment of System Obligations); (2)
power purchase costs (with the exception of those net costs incurred as
part of the ``Inventory Solution''); and (3) planned net revenues for
risk.
See Table E for Slice Product Costing Table.
48. Subscription
Subscription refers to the Power Subscription Strategy issued by
BPA on December 21, 1998, which is BPA's policy power sales beginning
FY 2002.
49. Subscription Contract
See 2002 Contract.
50. System Obligations
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System Obligations include, but are not limited to, the
transmission costs associated with the return of the Canadian
Entitlement, and transactions related to the Pacific Northwest
Coordination Agreement, Mid-Columbia Hourly Coordination, and the
Canadian Non-Treaty Storage Agreement.
51. Total Plant Load
Total Plant Load means a DSI customer's total electrical energy
load at facilities eligible for BPA service during any given time
period whether the customer has chosen to serve its load with BPA power
or non-Federal power.
52. Total Retail Load (TRL)
Total Retail Load is all electric power consumption including
distribution system losses, within a utility's distribution system as
measured at metering points, adjusted for unmetered loads or
generation. No distinction is made between load that is served with BPA
power and load that is served with power from other sources. For DSIs,
Total Retail Load is called Total Plant Load.
53. Utility Distribution Company
A company that owns and maintains the distribution facilities used
to serve end-use customers.
BPA's New 1996 General Rate Schedule Provisions for Power Rates
A. Targeted Adjustment Charge for Uncommitted Loads
1. Availability
The Targeted Adjustment Charge for Uncommitted Loads (TACUL)
pertains to the PF rate schedule. The TACUL applies after December 7,
2000, to purchases to serve customer loads that were uncommitted during
the 1996 rate case which are returned to BPA firm power requirements
service during a period prior to FY 2002. Customers subject to the
TACUL are those that reduced their purchases from BPA by adding firm
resources to serve load under: (1) 1981 power sales contracts that
expire on or before July 31, 2001, as may be amended; (2) Amendatory
Agreement No. 7 (AA7) to the 1981 power sales contracts, or new
``1996'' power sales contracts where the customer provides BPA notice
after December 7, 1998, consistent with the terms of the customer's
power sales contract, for requirements service for the period prior to
FY 2002. This charge will be in effect through September 30, 2001.
This rate schedule amends the PF-96 rate schedule, which went into
effect October 1, 1996.
2. Energy Charge
The TACUL is a monthly mills/kWh adjustment to the HLH and LLH
energy rates specified in the 1996 rate schedule, and is applied to
that portion of the customer's load that is subject to the TACUL. The
TACUL rate adjustment will be established based on the following
formula:
TACUL = [(Incr $ * Incr Amt)-(Rate $ * Incr Amt)]/TACUL Amt
Where:
TACUL Amt = The amount of load subject to the TACUL, determined
monthly.
Rate $ = The monthly PF energy rate shown in the applicable rate
schedule.
Inventory Amt = Amount of energy available to serve this load based on
an annual energy Federal system firm resource capability as defined in
the Loads and Resources Study, and updated if BPA determines that is
necessary.
Incr $ = Monthly cost to BPA, plus a handling fee, of incremental power
for HLH and LLH expressed in mills/kWh (see below). These costs also
may include where applicable, wheeling, ancillary, and other charges
BPA may incur in purchasing power from other entities such as, but not
limited to, the California ISO or the California PX.
Incr Amt = Amount of incremental power required, determined monthly and
defined as the TACUL Amt minus the Inventory Amt. (If there is no
available Inventory Amt, the Incr Amt will equal the TACUL Amt).
Incr $ is greater than Rate $ (If Incr $ is less than Rate $, the
TACUL is 0 mills/kWh).
TACUL is the monthly rate adjustment in mills/kWh. BPA will
calculate the cost (Incr $) per month in mills/kWh of the additional
power per month (Incr Amt) for a specific Customer request. BPA will
establish the cost of the additional power by the following methods:
a. BPA will establish the price based on BPA's monthly cost to
purchase the incremental load by purchases of resources at market, or
the monthly cost of BPA recallable power contracts, averaged, whichever
is less.
b. A price plus handling fee calculated based on the following
index.
BPA will calculate the price per month for HLH and LLH, based on an
index calculated according to the following:
Price of HLH = \1/3\ HLH (DJ Mid C) + \1/3\ HLH (California PX) + \1/3\
(NYMEX Mid C)
Price of LLH = \1/2\ LLH (DJ Mid C) + \1/2\ LLH (PX)
Where the California PX basis is adjusted to DJ Mid C
Where:
DJ Mid C = Dow Jones Firm On-peak (HLH) and Firm Off-peak (LLH) Mid-
Columbia Electricity Price Index
California PX = California Power Exchange Day-Ahead Zonal Prices
(Constrained)--the average of NW1 (Captain Jack/Malin--COB) and NW3
(NOB) for HLH and LLH
NYMEX Mid C = the New York Mercantile Exchange Futures Electricity
Closing Price at Mid-C for the applicable month
California PX prices will be adjusted for basis difference between COB/
NOB and the Mid-C using the IS/PTP Rates contained in BPA's 1996
Transmission Rate Schedules.
Issued in Portland, Oregon, on July 30, 1999.
Jack Robertson,
Deputy Administrator.
[FR Doc. 99-20805 Filed 8-12-99; 8:45 am]
BILLING CODE 6450-01-P