[Federal Register Volume 70, Number 215 (Tuesday, November 8, 2005)]
[Notices]
[Pages 67685-67697]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 05-22233]


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

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.

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

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: <a href="/cdn-cgi/l/email-protection#4e243d2f202a2b3c3d0e2c3e2f60292138"><span class="__cf_email__" data-cfemail="701a03111e14150203301200115e171f06">[email protected]</span></a>, 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:<a href="/cdn-cgi/l/email-protection#123d3d6565653c6278706760757760527062733c757d64">//<span class="__cf_email__" data-cfemail="027575752c7268607770656770426072632c656d74">[email protected]</span></a>. (See Part III (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: www.bpa.gov/comment, 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 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 (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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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: <a href="/cdn-cgi/l/email-protection#18726b79767c7d6a6b587a6879367f776e"><span class="__cf_email__" data-cfemail="422831232c26273031022032236c252d34">[email protected]</span></a>: 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 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 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 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 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

[[Page 67696]]

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

[[Page 67697]]

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 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


</pre><script data-cfasync="false" src="/cdn-cgi/scripts/5c5dd728/cloudflare-static/email-decode.min.js"></script></body>
</html>