[Federal Register: November 8, 2005 (Volume 70, Number 215)]
[Notices]
[Page 67685-67697]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr08no05-31]
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DEPARTMENT OF ENERGY
Bonneville Power Administration
[BPA File No.: WP-07]
2007 Wholesale Power Rate Adjustment Proceeding; Public Hearings,
and Opportunities for Public Review and Comment
AGENCY: Bonneville Power Administration (BPA), Department of Energy
(DOE).
ACTION: Notice of proposed wholesale power rates.
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SUMMARY: The Pacific Northwest Electric Power Planning and Conservation
Act (Northwest Power Act), 16 U.S.C. 839, 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.
ADDRESSES: 1. Persons wishing to become formal parties to the
proceeding must file a petition to intervene notifying BPA in writing
of their intention to do so in conformance with the requirements stated
in this notice. Petitions to intervene should be directed to Jennifer
Sanders, Hearing Clerk, LP-7, Bonneville Power Administration, 905 NE
11th Avenue, Portland, OR 97232 or may be e-mailed to the following e-
mail address:
jsanders@bpa.gov, and must be received no later than 5
p.m., Pacific Standard Time, on November 17, 2005. In addition, a copy
of the petition must be served concurrently on BPA's General Counsel
and directed to Peter J. Burger, LP-7, Office of General Counsel,
Bonneville Power Administration, 905 NE 11th Avenue, Portland, OR 97232
or be e-mailed to the following e-mail address: http://www.pjburger@bpa.gov">
http://www.pjburger@bpa.gov. (See Part III (A) for more information.)
(A) for more information.)
2. Non-party participants may submit written comments between
November 21, 2005, and February 13, 2006. Comments must be received no
later than 5 p.m., Pacific Standard Time, on February 13, 2006, in
order to be considered in the draft Record of Decision (ROD). Written
comments may be made as follows: in person at the field hearings (see
schedule and locations in Part I of this Notice), online at BPA's Web
site: http://www.bpa.gov/commentation.), or by mail to: BPA Communications, DKP-7,
P.O. Box 14428, Portland, OR 97293-4428. Please
[[Page 67686]]
identify written or electronic comments as ``FY 07-09 Power Rate
Case.'' BPA will consider and address the comments received in the
draft ROD.
3. The rate adjustment proceeding will begin with a prehearing
conference at 9 a.m., Pacific Standard Time on November 21, 2005, held
in the BPA Rates Hearing Room, 2nd Floor, 911 NE 11th Avenue, Portland,
OR. BPA will release its 2007 Wholesale Power Rate Case Initial
Proposal (WP-07 Initial Proposal) and supporting documents at this
prehearing conference. Compact discs (CDs) containing the WP-07 Initial
Proposal documents, in PDF format, will be provided to the parties at
the prehearing conference. The WP-07 Initial Proposal documents will
also be available on BPA's Web site http://www.bpa.gov/power/rates. Due to
increased security, attendees should allow additional time to enter the
building and sign in at the security desk where photo identification
will be required for entry.
FOR FURTHER INFORMATION CONTACT: Ms. Jamae Hilliard Creecy, Public
Affairs Specialist, Public Affairs Office, DKP-7, P.O. Box 14428,
Portland, OR 97293-4428. Interested persons may also call (503) 230-
4328 or 1-800-622-4519 (toll-free). Information also may be obtained
from:
Ms. Kimberly Leathley, Manager, Financial Management, Rates, and
Planning--PF-6, P.O. Box 3621, Portland, OR 97208.
Ms. Elizabeth Evans, Acting Rates Manager--PFR-6, P.O. Box 3621,
Portland, OR 97208.
Mr. Garry Thompson, Hub Manager, Mr. Ken Hustad, Senior Customer
Account Executive, or Ms. Carol Hustad, Customer Account Executive,
Eastern Power Business Area-PSE, 707 W. Main, Suite 500, Spokane, WA
99201.
Mr. John Lebens, Hub Manager, Western Power Business Area--PSW-6, P.O.
Box 3621, Portland, OR 97208.
Mr. Larry King, Customer Account Executive, 2700 Overland, Burley, ID
83318.
Mr. C. T. Beede, Customer Account Executive, P.O. Box 40, Big Arm, MT
59910.
Mr. Dan Bloyer, Customer Account Executive, 1011 SW Emkay Drive, Suite
211, Bend, OR 97702.
Mr. Edward Brost, Senior Customer Account Executive, Kootenai Building,
Room 215, N. Power Plant Loop, Richland, WA 99352-0968.
Mr. Stuart Clarke, Senior Customer Account Executive, Mr. George Reich,
Senior Customer Account Executive, or Ms. R. Kirsten Watts, Customer
Account Executive, 909 First Avenue, Suite 380, Seattle, WA 98104-3636.
Responsible Official: Ms. Elizabeth Evans, Acting Rates Manager, 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. 2007 Wholesale Power Rate Case Schedules and General Rate
Schedule Provisions
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 this notice of the proposed rates in the Federal Register (Notice);
one or more hearings conducted as expeditiously as practicable by a
Hearing Officer; public opportunity to provide both oral and written
views; data requests and responses and argument related to the proposed
rates; and a decision by the Administrator based on the record. This
proceeding is governed by Sec. 1010, et seq., of BPA's Rules of
Procedure Governing Rate Hearings, 51 FR 7611 (1986) (BPA Hearing
Procedures). These procedures implement the statutory Section 7(i)
requirements.
Section 1010.7 of the BPA Hearing Procedures prohibits ex parte
communications. The ex parte rule applies to all BPA and all DOE
employees. Except as provided below, any outside communications with
BPA and/or DOE personnel regarding BPA's rate case by other Executive
Branch agencies, Congress, existing or potential BPA customers
(including tribes), and nonprofit or public interest groups are all
considered outside communications and are subject to the ex parte rule.
The general rule does not apply to communications relating to (1)
Matters of procedure only (the status of the rate case, for example);
(2) exchanges of data in the course of business or under the Freedom of
Information Act; (3) requests for factual information; (4) matters for
which BPA is responsible under statutes other than the ratemaking
provisions; or (5) matters which all parties agree may be made on an ex
parte basis. The ex parte rule remains in effect until the
Administrator's final ROD is issued, which is scheduled to occur on
July 7, 2006.
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 certain other costs and
expenses incurred by the Administrator.
BPA's initial proposed 2007 Wholesale Power Rate Schedules and
General Rate Schedule Provisions (GRSPs) are available for viewing and
downloading on PBL's Web site at http://www.bpa.gov/power/ratecase as
discussed in Part V of this Notice. The studies addressing the factors
used to develop these rates are listed in Part IV and will be available
for examination on November 21, 2005, at BPA's Public Information
Center, BPA Headquarters Building, 1st Floor, 905 NE 11th Avenue,
Portland, Oregon, and will be provided to parties at the prehearing
conference to be held on November 21, 2005, beginning at 9:00 am,
Pacific Standard Time, Room 223, 911 NE 11th Avenue, Portland, Oregon.
You may download copies of the studies and documentation from BPA's
Web site at http://www.bpa.gov/power/ratecase or request them (on a CD
or hard copy) by calling BPA's document request line toll-free at: 1-
800-622-4519.
BPA will release its WP-07 Initial Proposal and supporting
documents on November 21, 2005, and expects to publish a final ROD on
July 7, 2006. BPA will be conducting a formal evidentiary rate hearing
attended by rate case 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.
November 21, 2005; BPA files Direct Case/Prehearing Conference
December 5-9, 2005; Clarification
December 9, 2005; Data Request Deadline
December 9, 2005; Motions to Strike
December 15, 2005; Data Response Deadline
December 15, 2005; Answers to Motions to Strike
January 6, 2006; Parties file Direct Cases
January 17-20, 2006; Clarification
January 24, 2006; Data Request Deadline
January 24, 2006; Motions to Strike
January 30, 2006; Data Response Deadline
[[Page 67687]]
January 30, 2006; Answers to Motions to Strike
February 13, 2006; Close of Participant Comments
February 13, 2006; Litigants File Rebuttal Testimony
February 16-17, 2006; Clarification
February 17, 2006; Data Request Deadline
February 17, 2006; Motions to Strike
February 23, 2006; Data Response Deadline
February 23, 2006; Answers to Motions to Strike
March 6-17, 2006; Cross-Examination
April 14, 2006; Initial Briefs Filed
April 26-27, 2006; Oral Argument before Administrator
May 26, 2006; Draft ROD issued
June 9, 2006; Briefs on Exceptions
July 7, 2006; Final ROD--Final Studies
BPA will also be conducting six public field hearings in cities
throughout the Pacific Northwest. 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 have been scheduled to take place at the locations, dates, and
times specified below. The hearing dates also will be posted on the
rate case Web site (http://www.bpa.gov/power/rates) and through announcements
in local newspapers. Any changes to the scheduled public hearings will
be available on the rate case Web site. The BPA Public Affairs Office
also may be contacted for this information at the telephone number
previously listed.
Public Field Hearings Schedule
November 29, 2005; Springfield, Oregon
November 30, 2005; Kalispell, Montana
December 1, 2005; Spokane, Washington
December 5, 2005; Idaho Falls, Idaho
December 6, 2005; Tacoma, Washington
December 7, 2005; Portland, Oregon
Part II--Purpose and Scope of Hearing
A. The Overview and Background to this Rate Filing
The WP-07 rate proceeding is designed to establish rates to replace
existing rate schedules and GRSPs. One existing rate schedule, the Firm
Power Products and Services rate schedule, was established for 10 years
in the 1996 Wholesale Power Rate and Transmission Rate Adjustment
Proceeding (WP-96/TR-96) and amended in the 1996 Firm Power Products
and Services Rate Schedule Correction Proceeding (FPS-96R). The
remaining power rate schedules and GRSPs were established in BPA's 2002
Wholesale Power Rate Adjustment Proceeding (WP-02). All of BPA's power
rate schedules expire on September 30, 2006. Accordingly, BPA must
conduct a rate case, pursuant to the 7(i) process, in order to comply
with its statutory obligations to establish rates to market the power
of the FCRPS.
The General Transfer Agreement (GTA) Delivery Charge, was
established in the 2006 Transmission Rate Case (TR-06) for the period
of October 1, 2005, through September 30, 2007. This power rate case
will establish the General Transfer Agreement Delivery Charge for the
period of October 1, 2007, through September 30, 2009.
1. Subscription
On December 21, 1998, BPA issued the Power Subscription Strategy
and Record of Decision (Subscription Strategy). The Subscription
Strategy reflected BPA's position on the equitable distribution of
Federal power for the Fiscal Year (FY) 2002-2011 period. The
Subscription Strategy was the culmination of a multi-year public
process that established BPA's plan for the availability of Federal
power post-2001, the products from which customers could choose, along
with an outline of the contracts and pricing framework for those
products.
The Subscription Strategy provided a marketing framework for the
WP-02 power rate case. The WP-02 power rate case developed the rates
and rate schedules necessary for the products and contracts that were
developed through Subscription. However, the rates established in the
WP-02 power rate proceeding applied only to the first five years of the
10-year Subscription contracts. As noted above, the WP-02 power rates
applicable to the Subscription contracts are set to expire on September
30, 2006, and must be replaced. The Subscription contracts continue to
be the basis for the contractual relationship between BPA and nearly
all of its firm power customers.
2. Firm Power Products and Services Rate Schedule
In addition to revising the rates for the Subscription contracts,
BPA is proposing the successor to the Firm Power Products and Services
(FPS) rate schedule. The FPS rate schedule is available for the
purchase of surplus firm power and other products and services for use
inside and outside the Pacific Northwest. The FPS rate schedule and
associated GRSPs were established for a 10-year period running from
October 1, 1996, to September 30, 2006. The rate schedule and GRSPs
were slightly modified in 2000 through a 7(i) process (FPS-96R). The
FPS rate schedule is used primarily for the sale at negotiated and/or
posted rates of surplus firm power and related products. Unless
replaced, BPA would lack a rate schedule to sell surplus power in the
West Coast wholesale energy markets.
3. Regional Dialogue and the Policy for Power Supply Role for Fiscal
Years 2007-2011 (Near-Term Policy)
The Regional Dialogue process began in April 2002 when a group of
BPA's Pacific Northwest electric utility customers submitted a ``joint
customer proposal'' to BPA that addressed both near-term and long-term
contract and rate issues. Since then, BPA, the Northwest Power and
Conservation Council (Council), customers, and other interested parties
have worked on these near- and long-term issues. Considering the depth
and complexity of many of these issues, BPA concluded it was not
practical to resolve all issues before the start of the 2007 rate
period. Therefore, BPA determined that it would address the issues in
two phases. The first phase of the Regional Dialogue addresses issues
that had to be resolved in order to replace power rates that will
expire in September 2006. The second phase is expected to be
implemented through new power sales contracts and in a future rate case
before new power sales contracts go into effect.
BPA issued the Near-Term Policy and Record of Decision on February
4, 2005. The Near-Term Policy has resolved some outstanding issues
prior to the start of the 2007 rate period. Those issues include, but
are not limited to, the following:
a. FY 2007-2011 Rights to Lowest-Cost Priority Firm (PF) Rate
BPA will apply the lowest-cost PF rates to its public agency
customers whose contracts contain the lowest-cost PF rate guarantee
throughout the remaining term of the Subscription power sales
contracts.
b. Term of the Next Rate Period
BPA will limit the duration of the next rate period to three years,
from FY 2007 through FY 2009.
c. Five-Year Contract Holders
Public customers whose contracts do not contain a guarantee of the
lowest cost-based PF rates for FY 2007-2011 will receive the same rate
treatment in the FY 2007-2011 period as customers whose contracts
contain this guarantee, so long as such customers signed a new
[[Page 67688]]
contract or amendment by June 30, 2005, extending the term of the
agreement through 2011.
d. Product Availability
Any new or existing public customer whose contract expires in 2006
may select from any of the standard products except Complex Partial
(Factoring), Block with Factoring, or Slice. In addition, BPA resolved
not to offer contract amendments that would allow changes in the power
products and services purchased under a customer's 10-year Subscription
contract.
e. Service to Residential and Small-Farm Consumers of Investor-Owned
Utilities (IOUs)
BPA's Subscription contracts with the region's six IOUs require the
agency to provide 2,200 aMW of power or financial benefits to the
residential and small-farm consumers of these customers during FY 2007-
2011. BPA signed agreements in late May 2004, with all six regional
IOUs that provide certainty in the amount and manner that benefits will
be provided to their residential and small-farm consumers under their
Subscription contracts for 2007-2011. These agreements provide
certainty by defining benefits based on a methodology that uses
independent market-prices in calculating the financial benefits, and
establishing a floor of $100 million and a cap of $300 million per year
for the financial benefits.
f. Service to Direct Service Industries (DSIs)
BPA determined that it will provide eligible Pacific Northwest DSIs
some level of Federal power service benefits, at a known quantity and
capped cost, in the FY 2007-2011 period. In the Near-Term Policy, BPA
decided that for the FY 2007-2011 period it would continue the ramp-
down in DSI service by providing eligible DSI customers some level of
service benefits, at a known quantity and capped cost, at rates no
lower than rates paid by BPA's public customers, and under contractual
terms no better than those offered to other customers. In order to
provide an opportunity for additional dialogue with (and among)
customers in the hope of achieving consensus for a balanced and durable
solution for service to the DSIs, BPA noted in the Near-Term Policy
that it reserved for later decision: (1) The actual level of service
benefits it would provide; (2) the eligibility criteria it would apply
in determining which DSIs would qualify for such service benefits; and
(3) the mechanism or mechanisms it would use to deliver those service
benefits. See Section 4, below, for a description of that later
decision.
4. Service to DSIs
The Near-Term Policy established parameters for service to the DSIs
which were addressed in Bonneville Power Administration's Service to
DSI Customers for Fiscal Years 2007-2011 Administrator's Record of
Decision (DSI ROD) (June 30, 2005).
In the DSI ROD, BPA determined to offer the aluminum company DSIs
power sales contracts for an aggregate 560 aMW of benefits at a capped
$59 million cost. In addition, BPA offered a 17 aMW surplus firm power
sales contract for Port Townsend Paper Company through the local public
utility under the FPS rate (or the IP rate if viable) at a price
approximately equivalent to, but in no case less than, its lowest-cost
PF rate.
BPA decided to allocate a share of the 560 aMW service benefits to
each DSI aluminum company for purposes of making an initial offer of
service, but the creditworthiness of each DSI, on a prospective basis,
will determine whether BPA executes a contract with that company. In
addition, each DSI aluminum company must demonstrate that it is
operational. Because of the financial risks inherent in providing
actual power and in order to meet the known and capped cost
prerequisite, BPA determined that the default delivery mechanism would
be to monetize the value of the below-market power sales to provide
service benefits through cash payments. However, BPA retains an option
to provide actual power in-lieu of monetizing the transaction.
5. Power Function Review
In January 2005, BPA initiated an extensive and in depth process to
examine the PBL's program levels. This Power Function Review (PFR)
provided customers and constituent's significant opportunity to provide
input into the policy choices that drive program cost projections to be
used in BPA's initial power rate proposal. The PFR focused on nine
major cost areas:
a. Army Corps of Engineer and Bureau of Reclamation operation and
maintenance costs and capital investments;
b. Columbia Generating Station operation and maintenance costs and
capital investments;
c. Conservation program costs;
d. Fish and wildlife program expenses and capital investments;
e. Internal operations costs charged to power rates;
f. Renewable program costs;
g. Transmission acquisition costs;
h. Risk mitigation packages and tools; and
i. Federal and Non-Federal debt service and debt management.
Two main areas, (1) debt service and debt management and (2) risk
mitigation, were discussed but not decided in the PFR. The PFR involved
technical staff meetings, management level discussions, and regional
public meetings. In total, BPA held seven technical meetings, five
formal discussion sessions with utility managers and five regional
public meetings that involved general managers representing public
customers, and customer representatives representing customers and
constituent groups. During this five-month review, interested persons
submitted a total of 94 written comments to BPA about the issues under
discussion. At the close of the comment period, BPA issued a draft
close-out letter with proposed program cost levels, delineated the
consequences and opportunities of further reductions, and sought
comment on those proposed levels. BPA received a number of additional
written comments on the draft close-out letter. A final close-out
letter was issued June 24, 2005. The PFR resulted in $96 million in
reductions per year in forecasted program level cost estimates.
In the close-out letter, BPA responded to the comments provided on
the draft and laid out the program level cost estimates that would be
used in BPA's WP-07 Initial Proposal. In addition, BPA committed to
revisit many of the program areas when more information is known. BPA
will hold discussions separately from the rate case proceedings to
share the updated forecasts, define associated policy choices, and
solicit feedback from customers and constituents before they are
incorporated into the final rates.
6. Post-2006 Conservation Program Structure Proposal
In the fall of 2004, BPA established a post-2006 conservation
workgroup. The conservation workgroup was composed of over 65 utility
representatives and conservation stakeholders. The purpose of the
workgroup was to discuss and develop BPA's conservation program for the
post-2006 time frame. In January 2005, the workgroup provided BPA with
recommendations and comments on how BPA should design its conservation
program.
On March 28, 2005, BPA issued its Post-2006 Conservation Program
Structure Proposal for review and a 30-day comment period. BPA received
56 comments on the proposal. On June 28,
[[Page 67689]]
2005, BPA issued its response to the comments along with its final
decision on the design and scope of the Post-2006 proposal.
The proposal described the approach of the conservation programs
that BPA will offer during the FY 2007 through 2009 timeframe. The
decisions in the Post-2006 proposal have been used as inputs in the
development of BPA's WP-07 Initial Proposal.
7. Transmission Rate Case
BPA is committed to marketing its power and transmission services
separately in a manner that is modeled after the regulatory initiatives
adopted in 1996 by FERC to promote competition in wholesale power
markets. The Commission's initiatives in Orders 888 \1\ and 889 \2\
directed public utilities regulated under the Federal Power Act to
separate their power merchant functions from their transmission
reliability functions; unbundle transmission and ancillary services
from wholesale power services; and set separate rates for wholesale
generation, transmission, and ancillary services. Although BPA is not
required by law to follow the Commission's regulatory directives that
promote competition and open access transmission service, BPA elected
to separate its power and transmission operations and unbundle its
rates in a manner consistent with the directives concerning open access
transmission service. BPA develops its transmission rates in separate
proceedings from its power rates.
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\1\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Pubic Utilities; Recovery of
Stranded Costs by Public Utilities and Transmitting Utilities Reg-
Preamble, FERC Stats & Regs 1991-96, para. 31,036 (1996).
\2\ Open Access Same-Time Information System (formerly Real-Time
Information Networks) and Standards of Conduct, Reg-Preamble, FERC
Stats & Regs 1991-96, para. 31,035 (1996).
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On February 2, 2005, BPA's Transmission Business Line (TBL)
initiated a rate case to establish transmission rates for the FY 2006-
2007 transmission rate period. Prior to the initiation of that rate
case, TBL held several public meetings with customers over the period
July through September 2004 to discuss transmission costs, revenues,
and rate design issues for the FY 2006-2007 rate period. The customers
expressed interest in meeting with TBL to develop a settlement for the
FY 2006-2007 rate period. TBL continued meetings with customers between
October and early December 2004, resulting in a Settlement Agreement.
TBL's initial rate proposal reflected the terms of the Settlement
Agreement.
On June 20, 2005, BPA issued the Final Transmission Proposal-
Administrator's Record of Decision that adopted the transmission and
ancillary services rates as reflected in the Settlement Agreement.
Final approval of these TBL rates was issued by FERC on September 29,
2005. The TBL rate case settlement established formula rates for
ancillary services and some transmission rates that incorporate
ancillary services. For FY 2007, these formula rates will be affected
by the pricing of generation inputs to ancillary services that will be
determined in this PBL rate case. The pricing of generation inputs to
ancillary services determined in this rate case also will be a factor
in TBL's rates in FY 2008-2009.
B. Scope of the 2007 Rate Case
Many of the decisions that guide BPA's power 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 of the rate case, and those that are outside
the scope.
1. Program Level Expenses Decided in the PFR
As described above, the program level expense estimates, except
those decided elsewhere, have already received extensive public review
and comment in the PFR process. Pursuant to Sec. 1010.3(f) of BPA
Hearing Procedures, the Administrator hereby 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 appropriateness or reasonableness of BPA's
decisions on spending levels, as included in BPA's revenue requirements
for FYs 2007 through 2009. However, as noted above, BPA did commit to
revisit many of the program areas where final results were not known at
the time the final report was issued and will hold discussion
separately from the rate case proceeding to share the updated
forecasts, define associated policy choices, and solicit feedback from
customers and constituents before they are incorporated into the final
rates. Excepted from this direction due to their variable nature,
dependency on BPA's rate case models, and/or timing, are: (1) Forecasts
of short-term purchase power costs; (2) capital recovery matters such
as interest rate forecasts, scheduled amortization, depreciation,
replacements, and interest expense; and (3) risk mitigation packages
and tools.
2. Near-Term Policy Decisions
As detailed above, BPA issued the Near-Term Policy on February 4,
2005. The Policy resolved a number of policy decisions that impact the
design and features of BPA's WP-07 Initial Proposal. Those issues
include but are not limited to, decisions on the availability of the
lowest cost PF rate to public customers, term of the rate period, IOU
and DSI service options, and the availability of products for new or
existing customers. Pursuant to Sec. 1010.3(f) of BPA Hearing
Procedures, the Administrator hereby 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 appropriateness or reasonableness of BPA's decisions made
in the Near-Term Policy ROD.
3. DSI Service
The DSI Service decisions finalized and established the manner and
method by which BPA would provide service and benefits to its DSI
customers. The decisions in that ROD resolved the method and level of
service to be provided DSIs in the FY 2007-2011 period. Pursuant to
Sec. 1010.3(f) of BPA Hearing 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 revisit the appropriateness or reasonableness of
BPA's decisions made in the DSI ROD.
4. Transmission Acquisition Expense
In addition to the program cost decisions, the PFR close-out letter
also included transmission acquisition program cost level decisions.
This program represents the cost associated with services necessary to
deliver energy from generating resources to markets and loads. These
costs include: transmission expenses; ancillary services; real power
losses; generation integration costs associated with the U.S. Army
Corps of Engineers and Bureau of Reclamation transmission facilities;
and metering and communication requirements. In addition to these
decisions, BPA determined the mechanism for modeling the variability in
transmission expenses for the upcoming rate period.
Pursuant to Sec. 1010.3(f) of BPA Hearing Procedures, the
Administrator hereby 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
[[Page 67690]]
appropriateness or reasonableness of BPA's transmission acquisition
program level estimates or the modeling used to calculate the
variability of the transmission expense.
The only issue associated with the transmission acquisition program
within the scope of this rate case is the risk analysis associated with
modeling the transmission expense. In the PFR close-out letter, BPA
agreed to model the transmission expense based on the full distribution
of secondary sales rather than the average transmission expense. This
issue will be addressed in the risk analysis portion of the rate case.
5. Other Transmission Issues
a. Generation Inputs
BPA's Power Business Line (PBL) provides a portion of the FCRPS's
available generation to the TBL to enable TBL to meet its various
transmission requirements. TBL uses the generation inputs to provide
ancillary and control area services. To recover the costs associated
with providing these generation inputs, PBL assigns a portion of the
FCRPS costs to the transmission function. The cost allocations PBL is
proposing to use to determine the generation input costs and associated
unit costs to the TBL is a matter that is included within the scope of
this rate proceeding.
Pursuant to Sec. 1010.3(f) of BPA Hearing 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 that seek in any way to revisit the appropriateness
or reasonableness of any other issues related to the generation inputs.
This includes, but is not limited to, issues regarding the level or
quality of the generation inputs that TBL requests from PBL. These
determinations are generally made by TBL in accordance with industry,
reliability, and other compliance standards and criteria, and are not
matters appropriate for the rate case.
b. Transmission Rate Case
On June 20, 2005, BPA issued the Final Transmission Proposal ROD in
TBL's rate case, which received final approval on September 29, 2005.
Pursuant to Sec. 1010.3(f) of BPA Hearing Procedures, the
Administrator hereby 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 in any way to revisit the
appropriateness or reasonableness of issues determined in the TBL rate
case. That proceeding addressed, among other things, transmission and
ancillary service rate levels, the $1.5 million payment from TBL to PBL
for Attachment K redispatch for FY 2006-2007, and the GTA Delivery
Charge for FY 2007.
6. Post-2006 Conservation Program Structure Proposal
Through the post-2006 workgroup collaboration, customers and
constituents provided input on the development of BPA's post-2006
conservation approach. Pursuant to Sec. 1010.3(f) of BPA Hearing
Procedures, the Administrator hereby directs the Hearing Officer to
exclude from the record any material attempted to be submitted or
arguments attempted to be made in the hearing that seek to in any way
revisit the appropriateness or reasonableness of BPA's conservation
programs and establishment of expense levels through the Post-2006
Conservation Program Structure Proposal dated June 28, 2005. The
Hearing Officer is directed to exclude from the scope of this
proceeding evidence regarding BPA's portfolio of conservation programs
and the expenses BPA intends to pursue during the upcoming rate period.
7. Federal and Non-Federal Debt Service and Debt Management
During the PFR, and in other forums, BPA provided background
information on its internal Federal and non-Federal debt management
policies and practices. The discussions of these topics in the PFR and
other forums were not intended to seek input from customers and
constituents regarding BPA's debt management policies and practices.
Rather, these discussions were intended to merely inform interested
parties about these matters so that they would better understand BPA's
debt structure. Although the PFR close-out letter did not make any
decisions regarding BPA's debt management policies and practices, these
remain outside the scope of the rate case. Therefore, pursuant to Sec.
1010.3(f) of BPA Hearing Procedures, the Administrator hereby 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
debt management policies and practices.
8. Potential Environmental Impacts
The Administrator directs the Hearing Officer to exclude from the
record all evidence and argument that seek in any way to address the
potential environmental impacts of the rates being developed in the
2007 Wholesale Power Rate Case. See Section C, below.
C. The National Environmental Policy Act
BPA is in the process of assessing the potential environmental
effects of its WP-07 Initial Proposal, consistent with the National
Environmental Policy Act (NEPA). BPA's Business Plan Environmental
Impact Statement (Business Plan EIS), completed in June 1995, evaluated
the environmental impacts of a range of business plan alternatives that
could be varied by applying policy modules, including one for rates.
Any combination of alternative policy modules should allow BPA to
balance its costs and revenues. The Business Plan EIS also addressed
response strategies, including adjusting rates that BPA could pursue if
BPA's costs exceeded its revenues. In August 1995, the BPA
Administrator issued a Record of Decision (Business Plan ROD) that
adopted the Market-Driven Alternative from the Business Plan EIS. This
alternative was selected because, among other reasons, it allows BPA
to: (1) Recover costs through rates; (2) competitively market BPA's
products and services; (3) develop rates that meet customer needs for
clarity and simplicity; (4) continue to meet BPA's legal mandates; and
(5) avoid adverse environmental impacts. BPA also committed to apply as
many response strategies as necessary when BPA's costs and revenues do
not balance. Because the WP-07 Initial Proposal likely would assist BPA
in accomplishing these goals, the proposal appears consistent with
these aspects of the Market-Driven Alternative. In addition, this rate
proposal is similar to the type of rate designs evaluated in the
Business Plan EIS; thus implementation of this rate proposal would not
be expected to result in significantly different environmental impacts
from those examined in the Business Plan EIS. Therefore, BPA expects
that this WP-07 Initial Proposal will fall within the scope of the
Market-Driven Alternative that was evaluated in the Business Plan EIS
and adopted in the Business Plan ROD.
As part of the Administrator's ROD that will be prepared regarding
this 2007 Wholesale Power Rate Case, BPA may tier its decision under
NEPA to the Business Plan ROD. However, depending upon the ongoing
environmental review, BPA may, instead, issue another appropriate NEPA
document.
[[Page 67691]]
Part III--Public Participation
A. Distinguishing Between ``Participants'' and ``Parties''
BPA distinguishes between ``participants in'' and ``parties to''
the 7(i) hearing process. Apart from the formal hearing process, BPA
will accept comments, views, opinions, and information from
``participants'' who are defined in the BPA Hearing 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 a part of the official record and considered by
the Administrator when making his decision. 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.
The views of the participants are important to BPA. Written
comments by participants will be included in the record if they are
received by 5 p.m. on February 13, 2006. 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 Communications at the address listed in Section 2
of this Notice. In addition, BPA will hold six field hearings in the
Pacific Northwest region. Participants may appear at the field hearings
and present oral statements. The transcripts of these hearings will be
part of the record upon which the Administrator makes his final rate
decisions.
Persons wishing to become a party to BPA's rate proceeding must
notify BPA in writing and file a Petition to Intervene with the Hearing
Officer. 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 Office by 5 p.m. on November 17, 2005. The petitions should
be directed as stated below or may be e-mailed to the following e-mail
address: jsanders@bpa.gov: Jennifer Sanders, Hearing Clerk--LP-7,
Bonneville Power Administration, 905 NE 11th Avenue, P.O. Box 3621,
Portland, OR 97208-3621.
Petitioners must explain their interests in sufficient detail to
permit the Hearing Officer to determine whether they have a relevant
interest in the proceeding. Pursuant to Sec. 1010.1(d) of BPA Hearing
Procedures, BPA waives the requirement in Sec. 1010.4(d) that an
opposition to an intervention petition must be filed and served 24
hours before the November 21, 2005, 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.
B. Developing the Record
The record will comprise, among other things, verbal and written
comments made by participants, including 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. Written comments by participants will be included in
the record if they are received by 5 p.m., Pacific Standard Time, on
February 13, 2006. The Hearing Officer will then review the record,
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, which includes the record certified by the Hearing
Officer, as described above. 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
Hearing 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 at least 60 days
prior to October 1, 2006.
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 the
prescribed notice of meetings involving rate case issues in order to
permit the opportunity for participation by all rate case parties.
These meetings may be held on very short notice. Consequently, the
parties should be prepared to devote the necessary resources to
participate fully in every aspect of the rate proceeding and attend
meetings any day during the course of the rate case.
Part IV--Major Studies and Summary of Proposal
A. Summary of Proposed 2007 Wholesale Power Rate Structure
1. List of Proposed 2007 Wholesale Power Rates
BPA is proposing five different rate schedules for its 2007
Wholesale Power Rates. The actual rate schedules and the GRSPs are
available for viewing and downloading on PBL's Web site at http://www.bpa.gov/power/ratecase
as discussed in Part V of this Notice.
a. PF-07 Priority Firm Power Rate
The PF rate schedule is comprised of two rates: the PF Preference
rate and the PF Exchange 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 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.
839c(c).
b. NR-07 New Resource Firm Power Rate
The New Resource Firm Power (NR) rate applies to net requirements
power sales to IOUs for resale to ultimate consumers for direct
consumption, construction, test, and start-up, and for station service.
NR-07 firm power is also available to public utility customers for
serving New Large Single Loads. This rate applies to the following
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
c. IP-07 Industrial Firm Power Rate
The IP rate is available for discretionary firm power sales to DSI
[[Page 67692]]
customers authorized by Section (5)(d)(1)(A) of the Northwest Power
Act, 16 U.S.C. 839c(d)(1)(A).
d. FPS-07 Firm Power Products and Services Rate Schedule FPS
The FPS rate schedule is available for the purchase of Firm Power,
Capacity Without Energy, Supplemental Control Area Services, Shaping
Services, and Reservation and Rights to Change Services for use inside
and outside the Pacific Northwest. The rates for these products are
posted and/or negotiated. BPA is not obligated to enter into agreements
to sell products and services under this rate schedule.
e. GTA-07 General Transfer Agreement Delivery Charge
The GTA Delivery Charge applies to customers who purchase Federal
power that is delivered over non-Federal low voltage transmission
facilities. The rate was set in the 2006 TBL Rate Case Settlement and
approved by FERC on September 29, 2005, to mirror the Utility Delivery
rate from October 1, 2005, through September 30, 2007. The 2006 TBL
Rate Case Settlement set the GTA Delivery Charge at $1.119 per
kilowatt-month through September 30, 2007. For the period of October 1,
2007 through September 30, 2009, PBL is proposing to continue to set
the GTA Delivery Charge to the same rate as TBL's posted Utility
Delivery rate. As adjustments are made to the Utility Delivery rate in
future TBL rate cases, PBL proposes to reflect these changes in the GTA
Delivery Charge.
2. Significant Rate Development Issues
a. Risk Mitigation
Several factors present new challenges for BPA to keep its power
rates low while fulfilling its mission and meeting its obligations to
the U.S. Treasury consistent with sound business principles. Increased
market price volatility and six consecutive years of below-average
runoff have significantly changed the landscape of risk and uncertainty
facing BPA and its stakeholders.
The uncertainty and volatility of market prices are greater today
than they have been in the past. As a consequence, the cost of covering
the risk BPA faces in crediting a large portion of secondary revenues
to power rates before receiving those uncertain funds is now greater.
BPA also faces uncertainty around the operational costs for fish
programs in FY 2006 and in the FY 2007-2009 rate period. A new
Biological Opinion or possible court-ordered change to river operations
would directly affect BPA's net revenues. In addition, enhanced risk
management practices resulted in analysis that accounts for operational
risks not previously modeled as well as a more comprehensive analysis
of non-operating risks. Finally, the $325 million Fish Cost Contingency
Fund (FCCF) was fully depleted in FY 2003 resulting in the loss of a
risk tool that was available to mitigate dry year impacts on fish
operations.
These changes create greater risk for BPA, reduce BPA's ability to
absorb those risks, increase the costs of managing risks, and/or more
fully reflect the costs of managing them. If rates were designed using
a traditional approach of adding Planned Net Revenues for Risk (PNRR),
these changes would require that power rates be set to recover a much
larger ``risk premium'' than ever before in order to meet the Treasury
Payment Probability (TPP) standard which, if this was the sole approach
to managing risk, would result in a relatively high rate. Additional
cash reserves and/or a more comprehensive risk mitigation package, such
as the cost recovery adjustment clauses implemented in the FY 2002-2006
rates, are necessary to address these risks and ensure that BPA can
maintain its minimum TPP standard of 92.6% \3\ for the rate period.
---------------------------------------------------------------------------
\3\ 92.6% TPP for a three-year rate period is equivalent to
BPA's TPP standard of 95% applied to a two-year rate period. Two
years were assumed to be the length of rate periods when the TPP
standard was set.
---------------------------------------------------------------------------
As noted above, BPA faces a level of uncertainty regarding its
assumption concerning river operations as well as direct program costs
for fish and wildlife due to the ongoing issues surrounding BPA fish
and wildlife obligations. To mitigate against this risk, BPA has
proposed a specific rate adjustment (NFB adjustment). In order to
balance the need to cover risk with overall rate levels, BPA is
proposing to meet its TPP standard through a combination of PNRR, cost
recovery adjustment charges, the NFB adjustment and a dividend
distribution clause. See Sections 3 and 4, below.
BPA has been meeting with customers and the parties over the last
year to explore alternative means of managing risk that would allow the
TPP standard to be met with lower rates. BPA has committed to continue
these discussions over the next several months in properly noticed
meetings to continue to pursue the viability of these options in order
to include them in the final studies.
b. Residential Exchange Program Settlement Benefits
Under Residential Exchange Program (REP) settlement agreements
executed by BPA and the IOUs in 2000, BPA originally provided the IOUs
1,000 aMW of power benefits and 900 aMW of monetary benefits for the FY
2002-2006 period. Power sales were originally made at the Residential
Load (RL) Firm Power Rate and the PF Exchange Subscription rate.
Monetary benefits were originally calculated based on the difference
between BPA's RL rate and BPA's then-current rate case 5-year flat
block price forecast. The benefits increase to 2,200 aMW for the FY
2007-2011 period either in the form of power or monetary benefits, at
BPA's discretion. Based on amendments of the REP settlement agreements
in 2004, and the Near-Term Policy, however, BPA will not sell power to
the IOUs during FY 2007-2011. BPA therefore is not proposing to
establish an RL rate or a PF Exchange Subscription rate for IOU power
sales in the WP-07 rate case. Instead, all IOU Settlement benefits for
the FY 2007-2011 period are monetary benefits calculated based on the
difference between an independent determination of a forecast of a
forward flat block market price and BPA's flat PF rate, consistent with
the IOU contracts.
c. Inter-Business Line Calculations
BPA is addressing certain inter-business line issues in this 2007
Power Rate Case. These include the generation inputs for: generation
supplied reactive and voltage support; operating reserves; regulating
reserves; generation and energy imbalance; generation dropping for
remedial action schemes; and station service. Segmentation of the Corps
of Engineers (COE) and the Bureau of Reclamation (Reclamation)
facilities will also be addressed. BPA is proposing methodologies to
calculate the costs of these services, and forecast revenues, in order
to determine BPA's power revenue requirement to be recovered through
power rates. These generation costs, or associated unit costs, will be
allocated to TBL to support TBL's ancillary services and other
operations. Relevant transmission and ancillary service rates for FY
2006-2007 include formulas that allow for the costs and charges
developed in this power rate case to be factored into the transmission
and ancillary service rates. BPA is also proposing to set a GTA
Delivery Charge as determined by the 2006 Transmission rate settlement.
This power rate proceeding will establish the GTA Delivery Charge for
FY 2008 and 2009.
[[Page 67693]]
d. DSI Service 2007-2011
Consistent with the DSI ROD, BPA is not forecasting direct service
under the IP rate to the DSI customers. Instead, BPA plans to offer the
DSI aluminum smelters 560 aMW of surplus firm power service benefits
for the FY 2007-2011 period at a capped cost of $59 million per year.
BPA will offer Port Townsend Paper Company 17 aMW of surplus firm power
service benefits, whereupon its local utility will provide power at a
utility rate expected to be approximately equivalent to, but in no case
lower than, BPA's PF rate. With the DSI aluminum companies,
creditworthiness standards must be met or acceptable credit assurances
must be provided by those companies qualifying for benefits. In
addition, benefits can be monetized under the proposed contracts with
these companies, but BPA will retain the right to provide physically
delivered surplus power, subject to long-term interruption rights, in
lieu of a financial transaction.
3. Changes in Rate Design
BPA is continuing, in general, its existing rate design for its FY
2007-2009 rates, with some changes and modifications as described
below. Complete details on these changes are available for viewing and
downloading on PBL's Web site at http://www.bpa.gov/power/ratecase as
discussed in Part V of this Notice.
a. Conservation Rate Credit (CRC)
BPA is proposing to replace the Conservation and Renewables (C&R)
Discount with a Conservation Rate Credit (CRC) program. The CRC will
retain many of the features of the C&R Discount including: (1) The
credit will remain at 0.5 mills per kWh; (2) monthly bill credits; (3)
no decrement to customers' net requirements for CRC participation
(including Slice customers); (4) customer flexibility in choosing
between several eligible conservation and renewable energy measures;
and (5) funding under the CRC for customer renewable resource
activities is limited to $6 million annually.
b. Dividend Distribution Clause (DDC)
BPA is proposing to continue the DDC with a modification to the
Threshold. BPA proposes that there will be a DDC if Accumulated
Modified Net Revenues (AMNR) reach the equivalent of $800 million in
reserves attributable to PBL.
c. Excess Factoring Charge
This is a charge that applies to purchasers of the Complex Actual
Partial Service Product under the PF rate schedule. BPA is proposing
minor changes to eliminate references to the California Power Exchange.
d. Green Energy Premium
BPA is proposing to continue the Green Energy Premium (GEP),
available to customers purchasing firm power. The GEP is an adjustment
to the PF rate 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 mills per kWh depending on the
specific products and associated costs selected by each customer. BPA
forecasts an average of $1.4 million of annual revenue from the GEP
over the rate period. Revenues from the GEP will support BPA renewable
resource facilitation and research and development.
e. Load-Based Cost Recovery Adjustment Charge (LB CRAC) True-Up
BPA is not proposing to continue the existing LB CRAC in the FY
2007-2009 rate period. However, the LB CRAC contemplates an after-the-
fact true-up as soon as the necessary actual data is available after
each sixth-month LB CRAC period. The final LB CRAC True-Up is
anticipated to occur in December 2006, after the expiration of BPA's
current rates on September 30, 2006. Therefore, BPA is proposing to
carry over the LB CRAC True-Up provisions in the GRSPs for the FY 2007-
2009 rate period to allow for the final True-Up. Implementation will be
limited to the true-up for the final 6 months (LBCRAC10 period) of the
2002-2006 rate period. True-Up billing adjustments will be made over
twelve months starting in early 2007.
f. Load Variance Charge
BPA is proposing to continue the Load Variance Charge. This charge
covers BPA's cost of meeting 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 forecast BPA purchases due to weather, economic business
cycles, plant energy consumptions and other reasons. The method for
setting the Load Variance charge in this rate proposal differs from the
WP-02 rate-setting process. It is no longer based on the cost of put or
call options. Instead, load growth is forecast, and the cost is
estimated based on a forecast of future market prices. The cost of
forecast error is estimated based on an assumption of a two percent
forecast error and a forecast of future market prices. The charge is
set at 0.53 mills per kWh and is charged against the customer's Total
Retail Load.
g. Low Density Discount (LDD)
BPA is proposing four changes to the LDD: (1) BPA proposes to
change the eligibility criteria to account for BPA's separation of
power and transmission rates which first occurred in 1996, and also to
ensure that customers with very low retail rates will not qualify for
the LDD; (2) one of the measures used in calculating the LDD is
proposed to use ``consumers per mile'' instead of ``meters per mile''
to ensure consistency and equity; (3) the term ``average retail rate''
has been clarified for simplification of the LDD administration; and
(4) BPA proposes to amend LDD to ensure it only applies to the
qualifying Slice purchaser's net requirements.
h. Monthly Demand and Energy Charges
BPA is not proposing changes to the methodology for calculating
energy charges. There will be two diurnal periods, Heavy Load Hour
(HLH) and Light Load Hours (LLH), for each month. BPA is proposing
slight changes to the definitions of HLH and LLH to be consistent with
NERC definitions. BPA is proposing to revise the definition of HLH and
LLH included in the 2006 Transmission General Rate Schedule Provisions
for FY 2007 to be consistent with NERC and BPA's proposed definitions
in the GRSPs for the power rates. The actual energy charges will be
updated consistent with the method used in WP-2002.
BPA is proposing a minor modification to the methodology for
calculating the demand charge. There will continue to be 12 monthly
demand charges, but the average rate will decrease from $2.00 per kW-
month to $1.05 per kW-month. This change is to better reflect the
market price for demand with energy.
i. PF Targeted Adjustment Charge (PF TAC)
BPA is continuing the Targeted Adjustment Charge, with some
proposed modifications. BPA proposes to exempt PF TAC loads from the PF
TAC in any year of the three years of the rate period that the load
subject to the TAC is less than 1 aMW. The TAC will apply to the entire
load if it exceeds the minimum. Also, the calculation of the PF TAC
rate will be based on monthly availability of the Federal Base System
(FBS), rather than an annual calculation.
[[Page 67694]]
j. Unauthorized Increase Charges (UAI) for Power Sales
These are penalty charges for Unauthorized Increases in Energy and
Unauthorized Increases in Demand for deliveries that exceed contractual
entitlements for energy and demand, respectively. BPA is proposing
minor changes to the UAI to eliminate references to the California
Power Exchange.
4. New Adjustments in Rates
BPA is proposing a number of new adjustments and continuing some
existing adjustments. Complete details of these adjustments are
available for viewing and downloading on PBL's Web site at http://www.bpa.gov/power/ratecase
as discussed in Part V of this Notice.
a. Operating Reserves
BPA is proposing changes in how it handles its forecasted revenues
from providing operating reserves to the TBL. BPA's Open Access
Transmission Tariff requires transmission customers serving load with
generation located in the Transmission Provider's Control Area to
acquire Operating Reserves from the Transmission Provider, from a third
party, or by self-supply. The 2002 power rate case estimated total
revenue recovered by PBL selling Operating Reserves generation inputs
to TBL, assuming all customers purchased Operating Reserves from TBL.
The expected revenue from the sale of Operating Reserves was deducted
from the overall revenue requirement when determining the cost of the
Federal system which is the basis for calculating power rates. During
this current rate period, some customers began self-supplying Operating
Reserves, and TBL has purchased less generation inputs from PBL.
Therefore, PBL did not fully recover expected revenues. To avoid this
under-recovery in the FY 2007-2009 rate period and to ensure that
revenues are allocated equitably, PBL is proposing to estimate total
revenues from the sale of generation inputs to TBL and give a 0.89
mills per kWh credit on the power bills of customers that elect to
purchase Operating Reserves from TBL. This will prevent both under-
recovery and over-recovery. While BPA proposes not to allocate these
revenues or credits to those customers that self-supply Operating
Reserves or acquire Operating Reserves from a third party, BPA will
consider alternatives to this proposal that address BPA's concerns
regarding the proper allocation of costs and revenues.
b. Cost Recovery Adjustment Clause (CRAC)
Prior to the beginning of each fiscal year of the rate period
(i.e., FY 2007-2009), a forecast of the previous year's end-of-year
AMNR will be completed. If the AMNR at the end of the forecast year
falls below the defined CRAC Threshold for that fiscal year, the CRAC
will trigger, and a rate increase will go into effect beginning in
October of the upcoming fiscal year. Any such increase in a fiscal
year's rates would remain in effect through September of the following
year. This adjustment could occur as early as August 2006 for the rates
in effect for FY 2007. The amount of the rate increase is limited to
the lower of the annual Maximum Planned Recovery Amount of $300 million
or the amount by which AMNRs under run the threshold.
CRAC Annual Thresholds and Caps
(Dollars in millions)
----------------------------------------------------------------------------------------------------------------
Approx.
CRAC applied threshold as Maximum CRAC
AMNR calculated at end of fiscal year to fiscal year CRAC threshold measured in recovery
PBL reserves amount (cap)*
----------------------------------------------------------------------------------------------------------------
2006............................................ 2007 -$193 $470 $300
2007............................................ 2008 -36 500 300
2008............................................ 2009 -45 500 300
----------------------------------------------------------------------------------------------------------------
c. The NFB Adjustment (National Marine Fisheries Service (NMFS) Federal
Columbia River Power System (FCRPS) Biological Opinion (BiOp)
Adjustment)
The NFB adjustment results in an upward adjustment to the CRAC
Maximum Planned Recovery Amount (Cap) for any year in the rate period
if unforeseen fish and wildlife costs arise from a predetermined set of
circumstances. The NFB Adjustment calculation will result in an
increase in the annual CRAC maximum recovery amount defined in Table A
for the next fiscal year following the year the NFB Adjustment was
triggered. The NFB Adjustment is applicable to FY 2007--2009. The NFB
Adjustment will address increases in financial impacts to the
anadromous fish portion of the Fish and Wildlife program only when
those impacts result from changes in FCRPS Endangered Species Act (ESA)
compliance as required by a court order (including court-approved
agreements), an agreement related to litigation, a new NMFS FCRPS BiOp,
or Recovery Plans under the ESA. Financial impacts include foregone
revenue, power purchases, direct program expense, fish credits, COE and
BOR O&M, and capital repayment. Financial impacts will be calculated
net of forecast 4(h)(10)(C) credits. This adjustment would be
calculated at the same time that the calculation of the CRAC would be
made.
5. Rates With No Proposed Changes
The following is a list of rates or adjustments that BPA proposes
to continue with no changes from current rates. Complete details on the
rates or adjustments are available for viewing and downloading on PBL's
Web site at http://www.bpa.gov/power/ratecase as discussed in Part V of this
Notice.
a. Demand Adjuster
This is an adjustment that is made to the demand billing factor for
certain requirements products.
b. Flexible PF and NR
These are rate options available, at BPA's discretion, to
purchasers under the PF and NR rate schedules.
c. Slice True-Up Adjustment
BPA is not proposing any changes to the methodology used to conduct
the Slice True-up. However, BPA does clarify in its proposal how
certain costs are treated with the Slice Rate and True-up. These
include debt optimization, bad debt expenses, augmentation expenses,
Conservation Augmentation, IOU and DSI benefits, and Slice
implementation expenses.
d. Value of Reserves
Section 7(c)(3) of the Northwest Power Act, 16 U.S.C. 839e(c)(3),
[[Page 67695]]
provides that the Administrator shall adjust rates to the DSI 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 WP-07 Initial Proposal reflects Stability
Reserves being purchased by the TBL and addressed in TBL's transmission
rate case.
The PBL is proposing in this rate case to continue the approach to
procure Supplemental Reserves developed in the WP-02 Rate Case. The PBL
will purchase the most cost-effective Supplemental Reserves or provide
those reserves itself. No Supplemental Reserves are explicitly forecast
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 maximum amount PBL may
pay is $6.96 per kW-month.
6. Rates and Adjustments Proposed To Be Discontinued
The following are rates and adjustments that BPA is proposing to
discontinue.
a. Cost-Based-Indexed IP Rate
BPA does not forecast any sales under this product.
b. Cost-Based-Indexed PF Rate
BPA does not forecast any sales under this product.
c. Financial-Based Cost Recovery Adjustment Clause (FB CRAC)
BPA is not proposing a FB CRAC for this rate period. See Section
4.b., above, for BPA's risk mitigation.
d. Flexible IP
BPA is not proposing a flexible IP rate in the IP rate schedule as
BPA does not forecast any sales under the IP rate schedule.
e. Industrial Power Targeted Adjustment Charge
BPA is not proposing to continue the industrial power targeted
adjustment charge as BPA does not forecast any sales under the IP rate
schedule.
f. Nonfirm Energy Rate Schedule
BPA is proposing to discontinue the NF rate in this rate proposal
as it is no longer used.
g. Residential Load Firm Power Rate (RL)
BPA is proposing to discontinue the RL rate in this rate proposal
as it is no longer necessary. See Section 2.b. above.
h. Safety Net Cost Recovery Adjustment Clause (SN CRAC)
BPA is not proposing a SN CRAC for this rate period. See Section
4.b., above, for BPA's risk mitigation.
i. Stepped Rates
BPA is not proposing stepped rates in this rate proposal because
this is only a 3-year, not a 5-year, rate period.
j. Stepped Up Multi-Year (SUMY) Block Charge
BPA is not proposing a SUMY block charge in this rate proposal.
7. Development of IP Rate/7(c)(2) Adjustment
The IP-07 rate applies to discretionary firm power sales to BPA's
DSI customers who purchase under Section 5(d) of the Northwest Power
Act, 16 U.S.C. 839c(d). In this rate proposal, BPA is not forecasting
any sales to DSIs under the IP rate but, for various reasons, the IP
rate is nonetheless being 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, DSI rates will
be set ``at a level which the Administrator determines to be equitable
in relation to the retail rates charged by the pubic 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 IP rate is 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 IP rate is 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 credit.
Continuing past practice and given current circumstances, BPA will not
propose a uniform value of reserves credit to be applied against the IP
rate. Thus, the IP rate will 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 rate design.
The typical Industrial Margin is 0.573 mills per kWh. As stated
above, a zero value of reserves credit is being forecast in this rate
case. Thus, the net margin of 0.573 mills per kWh is added to the
seasonal and diurnal PF energy charges to produce the initial IP rate
charges.
BPA conducts a Section 7(b)(2) rate test as part of its ratemaking
process and if the test ``triggers,'' the initial IP rate charges are
increased. In the current rate case, the 7(b)(2) rate test does trigger
and additional costs are allocated to the IP rate pool, substantially
increasing the IP rate charges above their initial PF-plus margin
level.
In addition, Section 7(c)(2) of the Northwest Power Act requires
that IP rates in the post-1985 period ``shall in no event be less than
the rates in effect for the contract year ending on June 30, 1985.'' 16
U.S.C. Sec. 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 IP rate to recover
revenues that would be generated by application of the floor rate.
Other customer classes are then credited with the increased revenue
generated by application of the floor rate test and any resulting
adjustment of the IP rate. If the IP 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 2007-2009) 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 continues to conduct 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 20.97 mills per kWh. Because
the proposed IP rate revenues are greater than the floor rate revenues,
no adjustment was necessary.
8. Rate Design and Methodology
a. Risk Mitigation Package
PBL is proposing to rely on a number of elements for its risk
mitigation package in its WP-07 Initial Proposal. These include a Cost
Recovery Adjustment Clause (CRAC), with the
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NFB Adjustment and a DDC, as described above, as well as the following:
(1) Starting Reserves. The financial reserves attributable to PBL
at the start of the rate period provide some financial protection
against the financial uncertainties it faces. Starting financial
reserves include the portions attributed to the generation function of
cash in the BPA Fund and the deferred borrowing balance. The expected
value for starting reserves is currently $381 million at the beginning
of FY 2007.
(2) Other Agency Reserves Temporarily Available for Rate-Setting
Purposes. BPA will assume that other agency reserves above the level
required to meet the transmission function TPP for FY 2006-2007 can be
considered for PBL rate-setting purposes to be temporarily available to
PBL in FY 2007 only. BPA will ensure that this will not harm the
interests of TBL or its customers.
(3) PNRR. The anticipated generation function reserves, with the
tools noted above, are not sufficient for the agency to meet its
financial objective of a 92.6 percent TPP. As a result, BPA's risk
mitigation package includes some PNRR. PNRR is a dollar amount in the
generation revenue requirement that generates additional revenue in
order to increase the generation function reserves.
b. Rates Analysis Model (RAM)
The RAM2007 model is a large Excel spreadsheet model that is
automated with Visual Basic macros. RAM2007 has three main steps: a
Rate Design Step; a Subscription Step; and a Slice Separation Step. The
RAM2007 Rate Design Step follows BPA's rate directives by determining
the costs associated with the three resource pools (FBS resources,
Residential Exchange resources, and new resources) used to serve sales
load, and then allocates those costs to the rate pools (PF, IP, and
NR). After the initial allocation of costs, the Northwest Power Act
requires that some rate adjustments be made, such as those described in
Section 7(b) and Section 7(c) of the Act. The RAM2007 performs these
rate adjustments including the 7(b)(2) rate test in its Rate Design
Step. The Rate Design Step of the RAM2007 concludes with the
calculation of the ``Rate Design Step'' rates. At this point in the
modeling, all posted rates are still preliminary except for the PF
Exchange rate which is set and is then used to calculate the net cost
of any public utility exchange. The Subscription Step calculates rates
that will include the costs of the IOU Residential Exchange Program
(REP) settlement. The Subscription Step section takes the rates
resulting for the Rate Design Step and adjusts them by first
subtracting any net cost of the traditional REP for the IOUs that have
been included in the Rate Design Step rates, and then adding the costs
of the IOU REP settlement. In the Rate Design and Subscription steps,
costs were allocated to the various rate pools, including the PF
Preference rate pool that contained all firm PF Preference loads. The
Slice Separation Step separates out the PF Slice product revenues and
firm loads from the overall PF Preference rate pool, leaving the costs
that must be covered by the remaining non-Slice product PF Preference
load.
B. Studies in Support of WP-07 Initial Proposal
The studies that have been prepared to support BPA's 2007 Initial
Wholesale Power Rate proposal are described in detail in this section:
Load Resource Study and Documentation (Study about 35 pages,
documentation about 120 pages);
Revenue Requirement Study and Documentation (Study about 200 pages,
documentation about 450 pages);
Market Price Forecast Study and Documentation (Study about 25
pages, documentation about 400 pages);
Risk Analysis Study and Documentation (Study about 75 pages,
documentation about 175 pages);
Wholesale Power Rate Development Study and Documentation (Study
about 120 pages, documentation about 600 pages); and
Section 7(b)(2) Rate Test Study and Documentation (Study about 20
pages, documentation about 120 pages).
1. Load Resource Study
The Load Resource Study represents the compilation of the load and
resource data necessary for developing BPA's wholesale 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 forecast is composed of customer and group sales
forecasts for public utilities and Federal agencies, IOUs, and other
BPA contractual obligations.
The Federal system resource forecast includes power generated by
both Federal and non-Federal hydro projects, return energy associated
with BPA's existing capacity-for-energy exchanges, contracted
resources, and other BPA hydro related contracts. The Federal system
hydro resource estimates are derived from a hydro regulation study that
estimates generation under 50 water years 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 Fiscal Years
2007-2009 (October 2007-September 2009) 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 production, acquisition, marketing, and conservation of
electric power. Generation revenue requirements include: Recovery of
the Federal investments in hydrogeneration, fish and wildlife recovery,
and energy conservation; Federal agencies' operations and maintenance
expenses allocated to power; capitalized contract expenses associated
with such non-Federal power suppliers as Energy Northwest; 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 the results of the Power Function Review and
certain components of the Subscription Strategy. The repayment studies
reflect updated actual and projected repayment obligations and
accommodate the on-going implementation of BPA's Debt Optimization
Program. All new capital investments are assumed to be financed from
debt or appropriations. The adequacy of projected revenues to recover
rate test period revenue requirements and to recover the Federal
investment over the prescribed repayment period is tested and
demonstrated for the generation function.
3. Market Price Forecast Study
The Market Price Forecast Study estimates the variable hourly cost
of the
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marginal resource for transactions in the wholesale energy market. The
specific market used in this analysis is the Mid-Columbia trading hub
in the State of Washington.
The Market Price Forecast is used for two purposes in BPA's rate
case. First, it is the basis for approximating the prices BPA may
experience when selling to or buying from the wholesale power market.
The Market Price Forecast estimates are therefore used to inform, but
not directly set, the price used in BPA's surplus or net secondary
revenue forecast. Second, the Market Price Forecast represents BPA's
marginal cost in acquiring new energy, or the opportunity cost BPA may
see in selling wholesale energy. The Market Price Forecast is therefore
used in rate design and to send market-based price signals.
The Market Price Forecast uses a production cost model, AURORA, to
estimate a market clearing price for wholesale energy. The fundamental
assumption underlying AURORA modeling is the existence of a competitive
wholesale energy pricing structure in the Western Electricity
Coordinating Council Region. 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. The study will also forecast independent market-price
forecasts used for IOU and DSI benefits.
4. Risk Analysis Study
The Risk Analysis Study focuses upon two types of risks and their
impacts on BPA's revenues and expenses. The first class of risks is
comprised of operating risks such as variations in economic conditions,
load, and generation resource capability. These operating risks include
the impacts of water supply conditions, alternative hydro operations,
and market prices on net revenues. These operating risks are modeled in
the Risk Analysis Model (RiskMod). The second class of risks comprises
non-operating risks--all the risks included in the rate case risk
modeling other than operating risks. This class of non-operating risks
also includes uncertainty in achieving cost reductions identified in
the Power Function Review. These risks are modeled in the Non-Operating
Risk Model (NORM). The outputs from RiskMod and NORM are combined to
develop the distribution of net revenues and cash flows that are
required as input by the ToolKit Model.
BPA subsequently evaluates the impact that different risk
mitigation measures have on reducing net revenue risk by calculating
the TPP. The ToolKit Model assesses the impact that the net revenue
deviations have on cash reserve levels, calculates the probability that
BPA will make each Treasury payment on time and in full. If the TPP is
below BPA's three-year 92.6 percent TPP standard, analysts change the
combination of risk mitigation tools (e.g., Cost Recovery Adjustment
Clauses, Planned Net Revenues for Risk, Dividend Distribution Clause,
etc.) to meet the TPP standard. The amount of PNRR calculated in the
ToolKit Model is included in revenue requirements and, thus, affects
the level of the rates calculated in the rates analysis model below.
5. Wholesale Power Rate Development Study
The Wholesale Power Rate Development Study (WPRDS) is the primary
source for details concerning BPA's power rates. It reflects the
results of all of the other studies, documents the Rates Analysis
Model, and documents the development of rates for BPA's wholesale power
products and services. The WPRDS documents the allocation and recovery
of Federal power costs, development of the Slice cost table; the
development and forecast of inter-business line revenues and expenses
(including Generation Input of Ancillary Services, segmentation of COE/
Reclamation Transmission Facilities and GTA Delivery Charge), the
development of charges for demand, load variance, unauthorized increase
usage, excess load factoring, numerous rate provisions (e.g. the low-
density discount, conservation and renewable discount, and rate
mitigation), and the development of diurnal energy charges. Notably,
one chapter of the WPRDS discusses BPA's risk mitigation package (i.e.,
the CRAC, NFB Adjustment, and DDC). The 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 period,
plus the ensuing four years (in total, this is known as the test
period), are no higher than the costs of power would be to those
customers for the same time period if specified assumptions are made.
The effect of the rate test is to protect the 7(b)(2) Customers'
wholesale firm power rates from certain costs resulting from provisions
of the 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
partially reduced by the 7(b)(2) amount. Other rates, including the PF
Exchange Program rate applied to customers purchasing under the REP and
the IP rate to be charged to any DSI taking direct service from BPA
during the rate period, have been increased by an allocation of the
7(b)(2) amount. Because, after allocation of the 7(b)(2) amount, there
are no REP loads, no power sales to IOUs, and no direct power sales to
DSIs, remaining 7(b)(2) amount costs were allocated to the PF
Preference rate. This is required by Section 7(a)(1) of the Northwest
Power Act, which provides that BPA's power rates must recover BPA's
power costs.
V. 2007 Wholesale Power Rate Schedules and General Rate Schedule
Provisions (GRSPs)
BPA's proposed 2007 Wholesale Power Rate Schedules and GRSPs are
available for viewing and downloading on PBL's Web site at http://www.bpa.gov/power/ratecase.
A copy of the proposed rate schedules and GRSPs are
also available for viewing in BPA's Public Reference Room at the BPA
Headquarters, 1st Floor, 905 NE 11th Avenue, Portland, OR.
Issued this 26th day of October, 2005.
Stephen J. Wright,
Administrator and Chief Executive Officer.
[FR Doc. 05-22233 Filed 11-7-05; 8:45 am]
BILLING CODE 6450-01-P