[Federal Register Volume 73, Number 27 (Friday, February 8, 2008)]
[Notices]
[Pages 7539-7555]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E8-2339]


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DEPARTMENT OF ENERGY

Bonneville Power Administration


2007 Supplemental 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 (Notice). BPA File 
No.: WP-07.

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SUMMARY: The Pacific Northwest Electric Power Planning and Conservation 
Act (Northwest Power Act) provides that BPA must establish and 
periodically review and revise its rates so 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. 
BPA is reopening its WP-07 wholesale power rate proceeding, which 
established power rates for Fiscal Years (FY) 2007-2009, in order to 
respond to recent decisions from the United States Court of Appeals for 
the Ninth Circuit (Ninth Circuit or Court) and to revise rates for FY 
2009.
    This 2007 Supplemental Wholesale Power Rate Adjustment Proceeding 
(WP-07 Supplemental Proceeding) responds to the Court's remand of BPA's 
WP-02 power rates for FY 2002-2006. This proceeding also responds to a 
separate Court decision that found BPA's 2000 Residential Exchange 
Program (REP) Settlement Agreements (REP Settlement Agreements) 
contrary to law. In response, BPA proposes to determine the amounts of 
REP settlement costs improperly included in FY 2002-2008 power rates, 
recover those amounts from investor owned utility customers (IOUs) over 
time and return improperly included amounts to preference customers. 
The WP-07 Supplemental Proceeding also includes proposed revisions to 
BPA's Section 7(b)(2) Legal Interpretation and Section 7(b)(2) 
Implementation Methodology.
    Persons that previously intervened in BPA's WP-07 Wholesale Power 
Rate Adjustment Proceeding automatically continue their party status in 
the WP-07 Supplemental Proceeding. Other persons wishing to become a 
formal party 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.

DATES: Petitions to intervene must be received no later than 5 p.m., 
Pacific Standard Time, on February 18, 2008. Non-party participants may 
make written comments between February 8, 2008, and May 5, 2008. 
Comments must be received by 5 p.m., Pacific Daylight Savings Time, on 
May 5, 2008, in order to be considered in the Supplemental Record of 
Decision (Supplemental ROD). (See Part III (A) for more information.)

ADDRESSES: Petitions to intervene should be directed to Robert Welsh, 
Hearing Clerk, LP-7, Bonneville Power Administration, 905 NE 11th 
Avenue, Portland, OR 97232 or by e-mail to: [email protected]. In 
addition, a copy of the petition must be served concurrently on BPA's 
General Counsel and directed to Kurt R. Casad, LP-7, Office of General 
Counsel, Bonneville Power Administration, 905 NE 11th Avenue, Portland, 
OR 97232 or by e-mail to: [email protected]. See Part III (A) for more 
information.) Written comments by non-party participants must be 
received by 5 p.m. Pacific Daylight Savings Time, on May 5, 2008, in 
order to be considered in the Supplemental Record of Decision 
(Supplemental 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/comment, or by 
mail to: BPA Public Affairs, DKE-7, P.O. Box 14428, Portland, OR 97293-
4428. Please identify written or electronic comments as ``WP-07 
Supplemental Proceeding.'' The Supplemental ROD will consider and 
address the comments received.
    The WP-07 Supplemental Proceeding will begin with a prehearing 
conference at 9 a.m., Pacific Standard Time, on February 19, 2008, held 
in the BPA Rates Hearing Room, 2nd Floor, 911 NE 11th Avenue, Portland, 
OR. Due to increased security requirements, attendees should allow 
additional time to enter the building and complete the required 
screening process. Photo identification will be required for entry. BPA 
will release its 2007 Supplemental Wholesale Power Rate Proposal (WP-07 
Supplemental Proposal) and supporting documents at the prehearing 
conference. Compact discs (CDs) containing the WP-07 Supplemental 
Proposal will be provided to the parties at the prehearing conference. 
The WP-07 Supplemental Proposal will also be available on BPA's Web 
site at http://www.bpa.gov/corporate/ratecase.

FOR FURTHER INFORMATION CONTACT:
Ms. Heidi Helwig, Public Affairs Specialist, Public Affairs Office, 
DKE-7, P.O. Box 3621, Portland, OR 97208. Interested persons may also 
call 503-230-3458 or 1-800-622-4519 (toll-free)
Ms. Leslie M. Dimitman, Paralegal Specialist, Office of General 
Counsel, LP-7, P.O. Box 3621, Portland, OR 97208. Interested persons 
may also call Ms. Dimitman at (503) 230-5515, or the general BPA toll-
free numbers 1-800-282-3713 (answered Monday through Friday 6:30 a.m. 
to 5 p.m.) or 1-866-879-2303 (answered by voicemail)

    Information also may be obtained from:

Mr. Raymond D. Bliven, Power Rates Manager--PFR-6, P.O. Box 3621, 
Portland, OR 97208
Ms. Suzanne B. Cooper, Power Policy and Rates Manager--PF-6, P.O. Box 
3621, Portland, OR 97208
Ms. Elizabeth Evans, Policy Analysis Manager--PFB-6, P.O. Box 3621, 
Portland, OR 97208
Mr. Garry Thompson, Manager, Eastern Power Business Area; Mr. Ken 
Hustad, Senior Customer Account Executive; Ms. Carol Hustad, Customer 
Account Executive; Mr. Michael Normandeau, Customer Account Executive, 
Eastern Power Business Area--PSE, 707 W. Main, Suite 500, Spokane, WA 
99201
Mr. Scott Coe, Manager, Western Power Business Area; Mr. Charles 
Forman, Customer Account Executive; Ms. Claire Hobson, Customer Account 
Executive; Ms. Tina Ko, Customer Account Executive; Ms. Theresa 
Rockwood, Customer Account

[[Page 7540]]

Executive; 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. Larry Felton, Senior 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; Ms. Shannon Greene, Customer Account 
Executive; Ms. R. Kirsten Watts, Customer Account Executive; 909 First 
Avenue, Suite 380, Seattle, WA 98104-3636

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Introduction and Procedural Background
II. Policy Guidance and Scope of Hearing
III. Public Participation
IV. Summary of WP-07 Supplemental Proposal and Major Studies
V. Section 7(b)(2) Legal Interpretation and Implementation 
Methodology
VI. Summary of Proposal To Respond to the Court's Opinions Regarding 
BPA's 2000 REP Settlement Agreements, WP-02 Rates, and by Extension, 
WP-07 Rates
VII. 2007 Supplemental Wholesale Power Rate Case Schedules (FY 2009) 
and 2007 Supplemental General Rate Schedule Provisions (FY 2009)

Part I--Introduction and Procedural Background

A. Overview and Background to This Rate Filing

    BPA is proposing to conduct a WP-07 Supplemental Proceeding in 
order to: (1) Adjust BPA's FY 2009 power rates consistent with recent 
decisions of the Ninth Circuit regarding BPA's WP-02 power rates for FY 
2002-2006; and (2) respond to the Court's decision finding BPA's REP 
Settlement Agreements contrary to the Northwest Power Act.
    Due to the time it takes to conduct a general rate adjustment 
proceeding, BPA determined that its first opportunity to establish 
revised power rates to conform to the Court's opinions was prior to the 
one-year FY 2009 rate period. Because BPA's WP-07 rates (FY 2007-2009) 
are currently before the Federal Energy Regulatory Commission (FERC) 
for final approval, BPA asked FERC to stay its review until BPA was 
able to conduct a supplemental rate proceeding to address the issues 
noted above. This will permit FERC to review a single supplemented 
record supporting BPA's proposed rates for FYs 2007, 2008, and 2009.
    In developing BPA's WP-02 power rates, BPA's revenue requirement 
included anticipated costs of REP Settlement Agreements with six 
regional IOUs. BPA allocated the majority of these settlement costs to 
the Priority Firm Power (PF) Preference rate. Following final approval 
of BPA's WP-02 rates by FERC, a number of parties challenged the WP-02 
power rates in the Ninth Circuit. In Golden NW Aluminum, Inc. v. 
Bonneville Power Admin., 501 F.3d 1037 (9th Cir. 2007) (Golden NW), the 
Court held BPA had improperly allocated REP Settlement Agreement costs 
to BPA's rates for preference customers. During the litigation of 
Golden NW, but prior to the Court's decision, BPA conducted a 
subsequent hearing (WP-07) to establish power rates for FY 2007-2009. 
In establishing these rates, BPA allocated REP settlement costs in the 
same manner as in BPA's WP-02 rates. Because the Court held in Golden 
NW that BPA's allocation of REP settlement costs in its WP-02 rates was 
improper, BPA's allocation of such costs in the WP-07 rates is 
similarly flawed.
    In addition, the Court held that BPA's WP-02 fish and wildlife cost 
estimates, and by extension the rates set pursuant to those estimates, 
were not supported by substantial evidence. The Court indicated BPA 
relied on outdated assumptions and had not appropriately considered 
information presented regarding its fish and wildlife costs. BPA's 
subsequent approach to forecasting fish and wildlife costs in the 
development of its WP-07 rates differed from the approach BPA used in 
developing its WP-02 rates. Nonetheless, as described in more detail in 
Part II.A.5, BPA is taking steps to ensure that its final WP-07 
Supplemental rates for FY 2009 are based on the most recent projections 
of fish and wildlife costs available at the time of rate development. 
In a procedural forum separate from the WP-07 Supplemental Proceeding, 
BPA will provide opportunities for fish and wildlife managers and 
others to provide input to BPA regarding BPA's fish and wildlife 
program costs for FY 2009. Decisions made based on the information 
gained from this separate program cost review forum will be used in the 
development of BPA's final WP-07 Supplemental rates.
    In a companion case to Golden NW, the Court held that BPA's REP 
Settlement Agreements with the IOUs were contrary to the Northwest 
Power Act. Portland General Elec. Co. v. Bonneville Power Admin., 501 
F.3d 1009 (9th Cir. 2007) (PGE). Also, subsequent to the Golden NW and 
PGE decisions, the Court reviewed three petitions for review 
challenging Load Reduction Agreements (LRAs) BPA executed with two IOUs 
during the energy crisis of 2000-2001. The Court dismissed two of the 
petitions for lack of jurisdiction and one petition as moot. The Court 
also reviewed challenges to amendments to the REP Settlement Agreements 
signed in 2004. In Public Utility Dist. No. 1 of Snohomish County, 
Wash. v. Bonneville Power Admin., 506 F.3d 1145 (9th Cir. 2007) 
(Snohomish), the Court remanded the amendments and a contract provision 
establishing a Reduction of Risk Discount to BPA. BPA must respond to 
the foregoing decisions. Because the ratemaking and REP issues are 
interrelated, BPA is proposing to address its response to the Court's 
decisions in the WP-07 Supplemental Proceeding.
    In summary, this WP-07 Supplemental Proceeding is being held for 
four primary purposes: (1) To establish new power rates for FY 2009; 
(2) to determine the amount of benefits that BPA's IOU customers 
received, or would have received, from FY 2002 through FY 2008 under 
REP settlements; (3) to determine the amount of REP benefits the IOUs 
would have received in the absence of the REP settlements; and (4) to 
address any difference between these two amounts. Specifically, the 
revised power rates for FY 2009 include the PF Preference rate and the 
PF Exchange rate. The average PF Preference rate of $26.2/MWh, about a 
four percent (4%) reduction, results largely from the reduced REP 
costs. The revised PF Exchange rate is used to determine REP benefits 
in FY 2009 As part of this process, BPA is also proposing revisions to 
BPA's Section 7(b)(2) Legal Interpretation and Section 7(b)(2) 
Implementation Methodology. An introduction to BPA's WP-07 Supplemental 
Proposal is contained in Part IV of this Notice. A summary of BPA's 
proposal regarding the calculation of REP benefits for FY 2002-2008 is 
contained in Part VI.

B. Legal Requirements

    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 a notice of the proposed rates in the Federal Register; one or more 
hearings conducted as expeditiously as practicable by a Hearing 
Officer; public opportunity to provide both oral and written views

[[Page 7541]]

related to the proposed rates; opportunity to offer refutation or 
rebuttal of submitted material; and a decision by the Administrator 
based on the record. This proceeding is governed by Sec.  1010 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 DOE employees 
and contractors. 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 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 BPA is responsible for under statutes other than the ratemaking 
provisions; or (5) matters that 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 or 
about August 18, 2008.
    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 2007 Supplemental Wholesale Power Rate Schedules (FY 2009) 
and 2007 Supplemental General Rate Schedule Provisions (GRSPs) (FY 
2009), as well as the Section 7(b)(2) Legal Interpretation and Section 
7(b)(2) Implementation Methodologye, are available for viewing and 
downloading on BPA's Web site at http://www.bpa.gov/corporate/ratecase 
as discussed in Part VII of this Notice. The studies addressing the 
factors used to develop these rates are listed in Part IV and will be 
available for examination beginning February 19, 2008, 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 February 19, 2008, beginning at 9 
a.m., Pacific Standard Time, Room 223, 911 NE 11th Avenue, Portland, 
Oregon.
    Copies of the studies and documentation can be downloaded from 
BPA's Web site at http://www.bpa.gov/corporate/ratecase or can be 
requested (on a compact disc or hard copy) by calling BPA's document 
request line toll-free at: 1-800-622-4519.
    A formal evidentiary rate hearing will be conducted that is open to 
rate case parties. Interested parties that did not previously intervene 
in BPA's WP-07 power rate proceeding must file petitions to intervene 
in order to take part in the WP-07 formal hearing. A proposed schedule 
for the WP-07 Supplemental Proceeding is stated below.
    The Hearing Officer will establish a final schedule at the 
prehearing conference.

Prehearing/BPA Direct Case.....................                 02/19/08
Clarification..................................        02/27/08-02/29/08
Motions to Strike..............................                 03/07/08
Data Request Deadline..........................                 03/07/08
Answers to Motions to Strike...................                 03/14/08
Data Response Deadline.........................                 03/14/08
Spokane, WA Field Hearing......................                 03/18/08
Portland, OR Field Hearing.....................                 03/20/08
Parties file Direct Cases......................                 03/28/08
Clarification..................................        04/07/08-04/09/08
Motions to Strike..............................                 04/11/08
Data Request Deadline..........................                 04/11/08
Answers to Motions to Strike...................                 04/18/08
Data Response Deadline.........................                 04/18/08
Litigants file Rebuttal........................                 05/05/08
Close of Participant Comments..................                 05/05/08
Clarification..................................        05/12/08-05/14/08
Motions to Strike..............................                 05/15/08
Data Request Deadline..........................                 05/15/08
Answers to Motions to Strike...................                 05/22/08
Data Response Deadline.........................                 05/22/08
Cross-Examination..............................        05/27/08-05/30/08
Initial Briefs Filed...........................                 06/09/08
Oral Argument..................................        06/16/08-06/17/08
Publish Draft ROD..............................                 07/16/08
Briefs on Exceptions...........................                 07/28/08
Publish Final ROD--Final Studies...............                 08/18/08
 

    As noted above, BPA will conduct two public field hearings in 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 BPA's Web site (http://www.bpa.gov/corporate/ratecase) 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.

[[Page 7542]]



                     Public Field Hearings Schedule
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03/18/08...............  6 p.m...............  Spokane, Washington.
03/20/08...............  6 p.m...............  Portland, Oregon.
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Part II--Policy Guidance and Scope of Hearing

A. Policy Guidance

    The following policies are foundational elements that guided the 
development of major components of this supplemental rate proposal.
1. BPA's Subscription Strategy
    On December 21, 1998, BPA issued a Power Subscription Strategy and 
Record of Decision (Subscription Strategy). The Subscription Strategy 
reflected BPA's position on the equitable distribution of Federal power 
for FY 2002-2011. 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, and an outline of the contracts and pricing 
framework for those products.
    The Subscription Strategy provided a marketing framework for the 
WP-02 and WP-07 power rate cases. The WP-02 and WP-07 power rate cases 
developed the rate schedules necessary for the products and contracts 
that were developed through Subscription. The Subscription contracts, 
except for the REP Settlement Agreements, continue to be the basis for 
the contractual relationship between BPA and nearly all of its firm 
power customers. BPA is assuming for purposes of this WP-07 
Supplemental Proceeding that the IOUs, except Idaho Power Company 
(Idaho Power), would have signed Residential Purchase and Sale 
Agreements (RPSAs) in the fall of 2000 instead of the 2000 REP 
Settlement Agreements.
2. Regional Dialogue and the Near-Term and Long-Term Policies
    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 WP-07 rate 
case. Therefore, BPA determined that it would address the issues in two 
phases. The first phase of the Regional Dialogue, referred to as the 
Near-Term Policy, addressed issues that had to be resolved in order to 
replace power rates that expired in September 2006. See Bonneville 
Power Administration's Policy for Power Supply Role for Fiscal Years 
2007-2011 (February 2005). The issues in the second phase were 
addressed in BPA's Long-Term Regional Dialogue Final Policy and Record 
of Decision, which was published on July 19, 2007. The Long-Term 
Regional Dialogue Final Policy is expected to be implemented through 
new power sales contracts and a future rate case conducted before such 
contracts go into effect in FY 2012. The Long-Term Regional Dialogue 
Final Policy does not affect this WP-07 Supplemental Proceeding.
3. Service to Direct Service Industries (DSIs)
    The Near-Term Policy established parameters for service to the DSIs 
that were further 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), and Supplement to 
Administrator's Record of Decision on Bonneville Power Administration's 
Service to Direct Service Industrial (DSI) Customers for Fiscal Years 
2007-2011, Administrator's Record of Decision (May 31, 2006), (together 
the ``DSI RODs'').
    In the DSI RODs, BPA determined to offer to aluminum company DSIs 
power sales contracts for an aggregate 560 aMW of benefits at a capped 
cost of $59 million. 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 Industrial Firm Power (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 of service benefits 
to each DSI aluminum company for purposes of making an initial offer of 
service. 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 delivery mechanism would be to monetize the value 
of the below-market power sales to provide service benefits through 
cash payments.
4. Power Function Review and Other Cost Reviews
    In January 2005, BPA initiated an extensive process, known as the 
Power Function Review (PFR), to examine Power Services' (formerly known 
as Power Business Line or PBL) intended program spending levels. The 
PFR process consisted of two phases designed to give interested parties 
an opportunity to examine, understand and provide input on the cost 
projections that would form the basis for BPA's WP-07 Power Rate 
Proposal. The first phase concluded in June 2005 when BPA issued the 
PFR Final Report. At that time, BPA committed to re-examine the program 
levels prior to establishing power rates in BPA's final proposal. In 
early 2006, BPA conducted the second phase, known as PFR II, allowing 
interested parties an opportunity to review these program levels. 
Workshops were held during January through March, 2006 and in April of 
2006, BPA issued a draft closeout report for comment. After the close 
of comment, BPA reviewed all comments and issued the PFR II Final 
Closeout Report documenting BPA's decisions on June 1, 2006. These 
updated program levels were then incorporated into BPA's WP-07 Final 
Proposal.
5. Mid-WP-07 Rate Period Cost Forecast Changes
    For the WP-07 Supplemental Proceeding, BPA reviewed the FY 2009 
program levels incorporated into the WP-07 Final Proposal that were 
developed through the PFR I and II processes. BPA then evaluated 
whether these forecasts remain reasonable in light of current 
projections. From this evaluation, BPA determined that adjustments were 
needed in certain program areas to address significant changes in 
forecast program levels. Specifically, these cost areas include: The 
Residential Exchange Program; Columbia Generating Station (CGS) 
operation and maintenance; interest; amortization; depreciation; 
renewables; energy efficiency; long-term generating projects; 
augmentation; purchased power; and fish and wildlife costs. BPA 
described the nature of the non-REP cost changes to interested persons 
in a public workshop on October 10, 2007.
    In the October workshop, BPA notified attendees that it intended to 
initiate a separate public process to address possible changes to the 
fish and wildlife cost forecast for FY 2009, \1\ costs of operating the 
CGS, and other cost changes identified that are relevant to the WP-07 
Supplemental Proceeding. In

[[Page 7543]]

this separate forum, BPA will provide interested persons an opportunity 
to review and comment on any adjustments to program levels. After the 
close of comment, BPA will issue a closeout report detailing any 
necessary adjustments to program levels. These forecast costs will then 
be incorporated into BPA's final rate proposal for FY 2009.
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    \1\ Such changes could result from, for example, the issuance by 
NOAA Fisheries of a final Biological Opinion regarding the impacts 
of the mainstem Federal Columbia River Power System dams on 
threatened and endangered salmon and steelhead, and from any related 
commitments BPA may make in a long-term Memoranda of Agreement 
currently being discussed with some regional governmental entities.
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6. Post-2006 Conservation Program Structure Proposal
    The Conservation Program Structure Proposal was finalized and 
issued June 28, 2005. It describes BPA's approach to offering 
conservation programs during FY 2007 through FY 2009. The decisions of 
this post-2006 proposal were used as inputs in the development of BPA's 
WP-07 Power Rate Case Final Proposal. BPA does not propose any changes 
in this area for the WP-07 Supplemental Proceeding.
7. Transmission Rate Case
    BPA is committed to marketing its power and transmission services 
separately in a manner modeled after the regulatory initiatives adopted 
in 1996 by FERC to promote competition in wholesale power markets. 
FERC's initiatives in Orders 888 \2\ and 889 \3\ 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 FERC'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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    \2\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery 
of Stranded Costs by Public Utilities and Transmitting Utilities 
Reg-Preamble, FERC Stats & Regs 1991-96, para. 31,036 (1996).
    \3\ 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 5, 2007, BPA's Transmission Services (formerly known as 
the Transmission Business Line or TBL) initiated a rate case to 
establish transmission rates for the FY 2008-2009 transmission rate 
period. Prior to the initiation of that rate case, Transmission 
Services held several public meetings with customers from July through 
November 2006 to discuss transmission costs, revenues, and rate design 
issues for the FY 2008-2009 rate period. Customers expressed interest 
in meeting with Transmission Services to develop a settlement for the 
FY 2008-2009 rate period. Transmission Services continued meetings with 
customers between October and November 2006, resulting in the 2008 
Transmission Rate Case Settlement Agreement.
    On April 23, 2007, BPA issued the ``Final Transmission Rate 
Proposal Administrator's Record of Decision'' which adopted the 
transmission and ancillary services rates reflected in the 2008 
Transmission Rate Case Settlement Agreement. FERC granted interim 
approval to these rates on September 20, 2007. The Transmission 
Services rate case settlement established fixed rates for certain 
ancillary services and some transmission rates that incorporate 
ancillary services. The generation inputs that support the ancillary 
services and other control area services sold by Transmission Services 
are provided by Power Services. BPA is not proposing any changes to its 
generation input costs for FY 2009 except for the recognition of 
additional revenues expected from Transmission Services for Wind 
Integration.

B. Scope of the WP-07 Supplemental Proceeding

    Many of the policies that guide BPA's power marketing decisions 
have been made or will be made in other public review processes. In 
addition, many decisions about BPA's financial commitments, including 
for example, what BPA plans to spend on meeting its fish and wildlife 
obligations, are made in forums other than the rate case. 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 Expense Forecasts and Commitments
    Section 7(i) rate proceedings establish the rates applicable to 
BPA's products and services at levels set to assure recovery of BPA's 
costs in total. The section 7(i) proceeding does not establish the 
program levels to be recovered during a rate period. Instead, program 
levels (including programmatic decisions and decisions regarding 
spending commitments) are decided in various forums outside the section 
7(i) proceedings. Once set, however, program levels are taken into 
consideration when designing the rates proposed in a section 7(i) 
proceeding to ensure such costs are recovered. As described in Part 
II.A.5, BPA evaluated whether updated forecasts of program levels were 
needed for this WP-07 Supplemental Proceeding, and determined that, 
except in a few instances, they were not. Therefore, except as noted 
above in Part II.A.5 and described below, this WP-07 Supplemental 
Proceeding will not revisit the previous forecasts of program levels 
for FY 2007-2009 made in the PFR I and II processes and incorporated 
into the WP-07 Final Proposal. Nor is this WP-07 Supplemental 
Proceeding the forum to revisit or seek new decisions regarding program 
spending commitments for this period.
    To allow public review and input on program level forecasts that 
BPA has determined require updating, BPA will hold a separate process 
to address adjustments to the program level forecasts for FY 2009 
associated with CGS costs, fish and wildlife costs and any other 
necessary program categories for which significant changes have or may 
occur before BPA's final rate proposal. This separate process will 
include an opportunity for entities, such as fish and wildlife 
managers, to engage BPA on the cost assumptions made and the 
appropriateness of any proposed adjustments in forecasts. Any 
adjustments adopted by BPA to the program level forecasts for FY 2009 
as a result of this separate process will be incorporated into BPA's 
final rate proposal for FY 2009. Because discussions regarding spending 
commitments or discussions about adjustments in forecasts of costs in 
these program areas will occur in forums separate from this rate 
proceeding, pursuant to Sec.  1010.3(f) of BPA Hearing Procedures, the 
Administrator hereby directs the Hearing Officer to exclude from the 
record any materials attempted to be submitted or arguments attempted 
to be made in the proceeding that seek to address program spending 
commitment decisions, or address adjustments in the program level 
forecasts for FY 2009 for CGS costs, fish and wildlife costs, and any 
other program categories.
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 affect 
BPA's WP-07 Supplemental Proposal. Those issues include, but are not 
limited to, decisions on the availability of the lowest cost PF rate to 
public agency customers; the term of the rate period; DSI service 
options; and the availability of products for new or existing 
customers. Pursuant to Sec.  1010.3(f) of the BPA Hearing

[[Page 7544]]

Procedures, the Administrator hereby directs the Hearing Officer to 
exclude from the record any materials attempted to be submitted or 
arguments attempted to be made in the proceeding that seek to in any 
way to revisit the appropriateness or reasonableness of BPA's decisions 
made in the Near-Term Policy ROD.
3. DSI Service
    The DSI Service RODs established the manner in which BPA would 
provide service and benefits to its DSI customers during FY 2007-2011. 
Pursuant to Sec.  1010.3(f) of the BPA Hearing Procedures, the 
Administrator directs the Hearing Officer to exclude from the record 
any materials attempted to be submitted or arguments attempted to be 
made in the proceeding that seek to in any way to revisit the 
appropriateness or reasonableness of BPA's decisions made in the DSI 
RODs.
4. Transmission Acquisition Expense
    In the PFR I and II processes, BPA reviewed with interested persons 
program levels related to Power Services' transmission acquisitions. 
These program levels represent the costs 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 BPA-
owned transmission facilities; and metering and communication 
requirements. Pursuant to Sec.  1010.3(f) of BPA Hearing Procedures, 
the Administrator hereby directs the Hearing Officer to exclude from 
the record any materials 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 transmission acquisition 
program level estimates.
5. Other Transmission Issues
a. Generation Inputs
    Power Services provides a portion of the FCRPS's available 
generation to Transmission Services to enable Transmission Services to 
meet its various transmission and control area requirements. 
Transmission Services uses the generation inputs to provide ancillary 
and control area services. To recover the costs associated with 
providing these generation inputs, Power Services develops charges 
based on relevant FCRPS costs that are assessed the transmission 
function. The costs Power Services are proposing to use to determine 
the generation input costs and associated unit costs to Transmission 
Services were addressed in the BPA's WP-07 Final Proposal. Based on 
updated information, the WP-07 Supplemental Proposal will include 
revised charges for some generation inputs and these revisions are 
included within the scope of this rate proceeding. Pursuant to Sec.  
1010.3(f) of BPA's Hearing Procedures, the Administrator directs the 
Hearing Officer to exclude from the record any materials attempted to 
be submitted or arguments attempted to be made in the proceeding that 
seek in any way to revisit the appropriateness or reasonableness of any 
issues, other than the charges, related to the generation inputs. This 
exclusion includes, but is not limited to, issues regarding the level 
or quality of the generation inputs that Transmission Services requests 
from Power Services. These determinations are generally made by 
Transmission Services in accordance with industry, reliability, and 
other compliance standards and criteria, and are not matters 
appropriate for the WP-07 Supplemental Proceeding.
    In addition, BPA will conduct a section 7(i) process related to 
within-hour balancing capacity for wind generation. Pursuant to Sec.  
1010.3(f) of BPA's Hearing Procedures, the Administrator directs the 
Hearing Officer to exclude from the record any materials attempted to 
be submitted or arguments attempted to be made in the WP-07 
Supplemental Proceeding that seek in any way to address the issues 
contained within the scope of the within-hour balancing capacity for 
wind generation rate proceeding (Proposed Wind Integration--Within-Hour 
Balancing Service Rate (WI-09)), except that the appropriate treatment 
of the additional revenue resulting from this proceeding is a matter 
that is included within the scope of the WP-07 Supplemental Proceeding.
b. Transmission Rate Case
    On April 23, 2007, BPA issued the 2008 ``Final Transmission 
Proposal-Administrator's Record of Decision'' that adopted the 
transmission and ancillary services rates as reflected in the 2008 
Transmission Rate Case Settlement Agreement. FERC granted interim 
approval to these transmission rates on September 20, 2007. Pursuant to 
Sec.  1010.3(f) of BPA Hearing Procedures, the Administrator hereby 
directs the Hearing Officer to exclude from the record any materials 
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 transmission rate case. That 
proceeding addressed, among other things, transmission and ancillary 
service rate levels, redispatch costs between Transmission Services and 
Power Services related to Attachment K redispatch for FY 2008-2009, and 
the level of the GTA Delivery Charge for FY 2009.
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 materials 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 their associated expense levels through 
the Post-2006 Conservation Program Structure Proposal dated June 28, 
2005. The Hearing Officer is also directed to exclude from the scope of 
this proceeding evidence regarding BPA's portfolio of conservation 
programs, as well as their expenses, that BPA intends to pursue during 
FY 2009.
7. Federal and Non-Federal Debt Service and Debt Management
    During the PFR, and in other forums, BPA has 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 closeout 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 materials 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. Average System Cost Methodology
    Concurrent with the publication of this notice, BPA is publishing a 
separate notice in the Federal Register to commence a consultation 
proceeding to

[[Page 7545]]

develop a new Average System Cost (ASC) Methodology. Section 5(c) of 
the Northwest Power Act established the REP, which provides benefits to 
residential consumers of Pacific Northwest utilities based, in part, on 
a utility's ``average system cost'' of resources. Section 5(c)(7) of 
the Act authorizes the Administrator to consult with regional interests 
to develop an ASC methodology. The ASC Methodology prescribes which 
costs are included and excluded from a utility's ASC, as well as the 
procedural rules for filing proposed ASCs with BPA. Comments on BPA's 
proposed ASC Methodology will be submitted, reviewed and addressed 
solely in the separate consultation proceeding. For this reason, issues 
related to the proposed ASC Methodology are not within the scope of 
this proceeding. Therefore, pursuant to Sec.  1010.3(f) of BPA Hearing 
Procedures, the Administrator hereby directs the Hearing Officer to 
exclude from the record any materials attempted to be submitted or 
arguments attempted to be made in the hearing that seek to in any way 
visit the appropriateness or reasonableness of the proposed ASC 
Methodology.
9. Potential Environmental Impacts
    For the reasons stated in Section C below, the Administrator 
directs the Hearing Officer to exclude from the record all evidence and 
arguments that seek in any way to address the potential environmental 
impacts of the rates being developed in the WP-07 Supplemental 
Proceeding. Any such evidence and arguments submitted will be 
considered and addressed in the separate, concurrent process described 
in the next section.

C. The National Environmental Policy Act

    BPA is in the process of assessing the potential environmental 
effects of its WP-07 Supplemental 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. In April 2007, BPA completed and issued a Supplemental 
Analysis to the Business Plan EIS. The Supplemental Analysis found that 
the Business Plan EIS's relationship-based and policy-level analysis of 
potential environmental impacts from BPA's business practices remains 
valid, and that BPA's current business practices are still consistent 
with BPA's Market-Driven approach. The Business Plan EIS and ROD thus 
continue to provide a sound basis for making determinations under NEPA 
concerning BPA's policy-level decisions.
    Because the WP-07 Supplemental Proposal likely would assist BPA in 
accomplishing the goals identified in the Business Plan ROD, 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 Supplemental 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 Supplemental ROD that will be 
prepared for the FY 2007 Supplemental Wholesale Power Rate Proposal, 
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. During the public review and 
comment period for the WP-07 Supplemental Proposal, persons interested 
in submitting comments regarding its potential environmental effects 
may do so by submitting comments to Katherine Pierce, NEPA Compliance 
Officer, KEC-4, Bonneville Power Administration, 905 NE 11th Avenue, 
Portland, OR 97232. Any such comments received by the comment deadline 
identified in Part I will be considered by BPA's NEPA compliance staff 
in the NEPA process that will be conducted for this Proposal.

Part III--Public Participation

A. Distinguishing Between ``Participants'' and ``Parties''

    BPA distinguishes between ``participants in'' and ``parties to'' 
the section 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 participants are important to BPA. Written comments by 
participants will be included in the record if they are received by 
5:00 p.m., Pacific Daylight Savings Time, on May 5, 2008. 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 Public Affairs at the address 
listed in Paragraph 2 of the Summary. In addition, BPA will hold two 
field hearings in the Pacific Northwest region. Participants may appear 
at the field hearings and present verbal and written comments. The 
transcripts of these hearings will be part of the record upon which the 
Administrator makes his final rate decisions.
    Persons who previously intervened in BPA's 2007 Wholesale Power 
Rate Adjustment Proceeding automatically continue their party status in 
the 2007 Supplemental Proceeding. Other 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 must 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

[[Page 7546]]

Officer by 5 p.m., Pacific Standard Time, on February 18, 2008. The 
petitions should be directed as stated below or may be e-mailed to 
[email protected]: Robert Welsh, 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 February 19, 2008, 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 materials submitted by the parties, documents 
developed by BPA staff, and other materials 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 Daylight Savings 
Time, on May 5, 2008. 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 for FY 2009 
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 Supplemental 
ROD. Parties will have an opportunity to respond to the Draft 
Supplemental ROD as provided in the BPA Hearing Procedures. The 
Administrator will serve copies of the Final Supplemental ROD on all 
parties. At the conclusion of the rate proceeding, BPA will file the 
supplemental rate case record and rates for FY 2009 in a timely manner 
to receive FERC confirmation and approval effective October 1, 2008.
    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, 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--Summary of WP-07 Supplemental Proposal and Major Studies

A. Summary of Proposed 2009 Wholesale Power Rate Structure

1. List of Proposed 2009 Wholesale Power Rates
    BPA is proposing to revise several rate schedules for its 2007 
Supplemental Wholesale Power Rates to respond to the Court's recent 
opinions. The rate schedules and the GRSPs are available for viewing 
and downloading on BPA's Web site at http://www.bpa.gov/corporate/ratecase as discussed in Part VII of this Notice.
a. PF-07R 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 public 
bodies, cooperatives, and Federal agencies for resale to their regional 
consumers. This power is guaranteed to be continuously available. The 
proposed average PF Preference rate is $26.2/MWh. 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). BPA is proposing to revise the PF Exchange rate to remove the 
demand and energy rates and substitute a single annual rate. In 
addition, BPA is proposing to include utility-specific supplemental 
rate charges, consistent with section 7(b)(3) of the Northwest Power 
Act. 16 U.S.C. 839e(b)(3). These PF Exchange rates are used in 
determining REP benefits in FY 2009.
b. NR-07R 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-07R 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-07R Industrial Firm Power Rate
    The IP rate is available for discretionary firm power sales to DSI 
customers authorized by section (5)(d)(1)(A) of the Northwest Power 
Act. 16 U.S.C 839c(d)(1)(A).
d. FPS-07R Firm Power Products and Services Rate
    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 proposing only minor changes to this 
rate schedule for FY 2009.
e. GTA-07R 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. This rate was originally set in the 2006 Transmission 
Services Rate Case Settlement to mirror the Utility Delivery rate from 
October 1, 2005, through September 30, 2007. BPA's 2007 Power Rate Case 
determined that the GTA Delivery Charge would continue to mirror the 
Utility Delivery rate, which is $1.119 per kilowatt through September 
30, 2009. For FY 2009, Power Services is proposing to continue to set 
the GTA Delivery Charge to the same rate as Transmission Services' 
posted monthly Utility Delivery rate, which is $1.119 per kilowatt.

[[Page 7547]]

2. Significant Rate Development Issues
a. Residential Exchange Program Costs
    For FY 2009, BPA expects qualifying regional utilities to 
participate in the REP. BPA is concurrently developing a new ASC 
Methodology in a separate proceeding and will be offering new RPSAs to 
requesting utilities. In order to include the costs of an REP in BPA's 
FY 2009 rates, BPA is forecasting the ASCs of utilities expected to 
participate in the program. In addition, BPA is forecasting the 
expected utilities' system and exchangeable residential and small farm 
loads. However, the ASC Methodology being revised in a concurrent 
process will be used to conduct an expedited review of utilities' ASCs 
outside of this WP-07 Supplemental Proceeding. This review will 
determine the actual ASCs for eligible utilities for FY 2009. Those ASC 
determinations, when complete, will be incorporated into the final rate 
proposal and used to determine REP costs in FY 2009 rates.
b. Inter-Function Costs and Credits
    BPA is not proposing any changes to its inter-function generation 
input unit charges for FY 2009. The forecast of revenues for FY 2009 in 
the WP-07 Final Proposal will continue to be used. However, BPA will 
adjust the inter-function revenue credit to reflect the additional 
revenues that Power Services expects to receive from Transmission 
Services based on the proposed Wind Integration--Within-Hour Balancing 
Service Rate Proceeding (WI-09). Therefore, BPA is proposing to 
incorporate the forecast revenues determined in the Wind Integration 
rate case into the final rates of this proceeding.
c. DSI Service FY 2007-2011
    BPA continues to forecast no direct service sales under the IP rate 
to its DSI customers. Instead, BPA provides 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. Benefits have been 
monetized under the contacts with these companies. In addition, BPA 
provides a 17 aMW surplus firm power sales contract for Port Townsend 
Paper Company through the local public utility under the FPS rate 
schedule at a rate that is approximately equivalent to BPA's lowest-
cost PF rate.
3. Rate Design and Rate Adjustments
    Consistent with the Partial Resolution of Issues negotiated between 
BPA and rate case parties before the WP-07 Final Proposal, BPA is 
generally continuing its existing WP-07 rate design for its FY 2009 
rates, with only minor modifications listed below. In addition, BPA is 
generally continuing its existing set of rate adjustments for its FY 
2009 rates, also described below.
a. Conservation Rate Credit (CRC)
    BPA is not proposing any changes from its WP-07 Final Proposal for 
the CRC.
b. Risk Mitigation Tools
    Other than resetting the cap for the FY 2009 Cost Recovery 
Adjustment Clause (CRAC) and the thresholds for the FY 2009 CRAC and 
Dividend Distribution Clause (DDC), BPA is proposing no other changes 
to the CRAC or DDC in the WP-07 Supplemental Proposal. BPA will use the 
same technical methodology to assess risks and intends to employ the 
same risk mitigation measures as presented in the WP-07 Final \4\ 
Proposal.
---------------------------------------------------------------------------

    \4\ Accumulated Modified Net Revenue

                        Table 1.--CRAC Cap and CRAC and DDC Annual Thresholds for FY 2009
                                              [Millions of dollars]
----------------------------------------------------------------------------------------------------------------
                                                                                      Approx.
                                      AMNR                                         threshold as
                                  calculated at    CRAC or DDC     CRAC or DDC      measured in    Maximum CRAC
                                  end of fiscal    applied to      threshold in        power         recovery
                                      year         fiscal year       AMNR \4\        services'     amount  (cap)
                                                                                     reserves
----------------------------------------------------------------------------------------------------------------
CRAC...........................            2008            2009          ($81.4)            $750             $36
DDC............................            2008            2009           218.6            1,050             n/a
----------------------------------------------------------------------------------------------------------------

    BPA proposes to continue the National Marine Fisheries Service 
(NMFS) Federal FCRPS Biological Opinion (NFB) Adjustment and the 
Emergency NFB Surcharge. Although BPA expects to include the forecast 
cost of implementing the final Biological Opinion for the FCRPS in its 
final supplemental rates, litigation regarding the Biological Opinion 
may continue, so the Emergency NFB Surcharge and the NFB Adjustment 
remain appropriate. In order to balance the need to cover risk with 
overall rate levels, BPA proposes to meet its Treasury Payment 
Probability (TPP) standard through a combination of financial reserves, 
the CRAC, the NFB Adjustment, the Emergency NFB Surcharge, and the 
Flexible PF Rate Program. See Part IV.A.4.
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 no 
changes to this charge as established in the WP-07 Final Proposal.
d. Green Energy Premium (GEP)
    BPA is proposing no changes to the GEP in this Supplemental 
Proposal. The proposed GEP continues to 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 $3 million of annual revenue 
from the GEP for FY 2009, which is an increase from the WP-07 Final 
Proposal. A portion of revenues from the GEP will support BPA's 
renewable-related research, development and demonstration projects.
e. Load Variance Charge
    Except for a change in its level, consistent with the Partial 
Resolution of Issues, BPA is proposing no other changes to the Load 
Variance Charge. This proposed charge of $0.45/MWh 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 of BPA purchases due to weather, economic business cycles, 
plant energy consumptions and other reasons.
f. Low Density Discount (LDD)
    BPA is proposing no changes to the LDD as established in the WP-07 
Final

[[Page 7548]]

Proposal and as agreed to in the Partial Resolution of Issues.
g. Monthly Demand and Energy Charges
    BPA is proposing no changes to the methodology for calculating 
demand and energy charges. There will be two diurnal periods, Heavy 
Load Hour (HLH) and Light Load Hours (LLH), for each month. BPA 
continues to adopt slight changes to the definitions of HLH and LLH to 
be consistent with NERC definitions. The proposed demand and energy 
charges will be updated consistent with the Partial Resolution of 
Issues.
h. PF Targeted Adjustment Charge (PF TAC)
    BPA is proposing no changes to the Targeted Adjustment Charge from 
that established in the WP-07 Final Proposal.
i. 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 no 
changes relative to the WP-07 Final Proposal.
j. Demand Adjuster
    This is an adjustment that is made to the demand billing factor for 
certain requirements products. BPA is proposing no changes relative to 
the WP-07 Final Proposal.
k. Flexible PF and NR
    These are rate options available, at BPA's discretion, to 
purchasers under the PF and NR rate schedules. BPA is proposing no 
changes relative to the WP-07 Final Proposal.
l. Slice True-Up Adjustment
    BPA is proposing changes to the Slice True-up Adjustment process 
that are consistent with the (Slice Mediation) Settlement Agreement 
that was signed after the WP-07 Final Proposal was published. This 
Settlement Agreement provided for the Slice True-Up Adjustment Charge 
to be calculated using the average Slice Revenue Requirement for the 
rate period instead of the Slice Revenue Requirement for each 
individual year. In addition, this Settlement Agreement provided for 
changes in the treatment of certain expenses, which are incorporated in 
this proposal.
m. Value of Reserves
    Section 7(c)(3) of the Northwest Power Act, 16 U.S.C. 839e(c)(3), 
provides that the Administrator shall adjust rates to the 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 Supplemental Proposal reflects 
Stability Reserves being purchased by Transmission Services and 
addressed in Transmission Services' transmission rate case. BPA is 
proposing no changes relative to the WP-07 Final Proposal.
n. Development of IP and NR Rates
    Other than the level of the rates, BPA is proposing no changes to 
the NR or IP rates relative to the WP-07 Final Proposal.
4. Rate Methodology for FY 2009
a. Risk Mitigation Package
    Power Services is proposing to rely on a number of elements for its 
risk mitigation package in the WP-07 Supplemental Proposal. These 
include a CRAC, with the NFB Adjustment and Emergency NFB Surcharge, 
and a DDC, as well as the following:
    (1) Starting Reserves Available for Risk. The financial reserves 
available for risk that are attributable to Power Services at the start 
of the rate period provide some protection against financial 
uncertainties. Starting financial reserves available for risk include 
portions attributed to the generation function of cash in the BPA Fund 
and the deferred borrowing balance that are attributed to the 
generation function. Projections of Power Services' reserves available 
for risk at the beginning of FY 2009 range from $50 million to $2.7 
billion, with an expected value of $1.03 billion. These amounts do not 
include cash that has accumulated as a result of the suspension of 
payments under the REP Settlement Agreements.
    (2) Planned Net Revenues for Risk (PNRR). PNRR is a dollar amount 
in the generation revenue requirement that generates additional revenue 
in order to increase the generation function reserves. The anticipated 
generation function reserves available for risk, with the tools noted 
above, are sufficient for the agency to meet its financial objective of 
a 97.5 percent one-year TPP for FY 2009. As a result, BPA's proposed 
risk mitigation package will not include any PNRR.
    (3) Flexible PF Rate Program. This program is designed to provide 
$193 million of liquidity cash through an accelerated payment of 
certain participating public utilities' power bills. This accelerated 
payment will be triggered at BPA's sole discretion should the 
probability of reserves falling below a certain reserve threshold be 
greater than the acceptable probability, as decided prior to a cash 
crisis.
b. Rates Analysis Model (RAM)
    The RAM2009 model is a large Excel spreadsheet model that is 
automated with Visual Basic macros. RAM2009 has two main steps: a Rate 
Design Step and a Slice Separation Step. The RAM2009 Rate Design Step 
implements BPA's rate directives by modifying the costs associated with 
the three resource pools (Federal Base System, Residential Exchange, 
and New Resources) used to serve three rate pools (7(b) loads, 7(c) 
loads, and 7(f) and surplus loads) as developed in the Cost of Service 
Analysis (COSA). 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 Northwest Power Act. 
The RAM2009 performs these rate adjustments, and several others, 
including the 7(b)(2) rate test, in its Rate Design Step. The Rate 
Design Step of RAM2009 concludes with the calculation of proposed power 
rates. The Slice Separation Step then separates the PF Slice product 
costs 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. Major Studies in Support of WP-07 Supplemental Proposal for FY 2009 
Rates

    Because this proceeding reopens the WP-07 docket, all material 
already filed on the record remains on the record and is available to 
all parties. BPA's WP-07 Final Proposal Studies constitute the 
foundation on which the Supplemental Proposal is built. However, 
certain new information will be incorporated to form the Supplemental 
Proposal. BPA will explain and document the revisions that are 
incorporated in the Supplemental Proposal in a new set of studies. The 
studies that have been prepared to support BPA's WP-07 Supplemental 
Wholesale Power Rate Proposal are described in detail in this section:
    Supplemental Load Resource Study and Documentation;
    Supplemental Revenue Requirement Study and Documentation;
    Supplemental Market Price Forecast Study and Documentation;
    Supplemental Risk Analysis Study and Documentation;

[[Page 7549]]

    Supplemental Wholesale Power Rate Development Study and 
Documentation;
    Supplemental Section 7(b)(2) Rate Test Study and Documentation; and
    Lookback Study and Documentation for FY 2002-2008.
1. Supplemental Load Resource Study
    The Load Resource Study represents the compilation of the load and 
resource data necessary for developing BPA's wholesale power rates. The 
Study has three major interrelated components: (a) BPA's Federal system 
load forecast; (b) BPA's Federal system resource forecast; and (c) the 
Federal system load and resource balances.
    Since publication of the WP-07 Final Proposal, only a few minor 
changes have occurred. The Supplemental Load Resource Study documents 
the increase in load BPA is currently forecasting for FY 2009 relative 
to the WP-07 Final Proposal. It also recognizes some changes in Federal 
resource output for FY 2009 resulting from recent BPA acquisitions and 
contract purchases, updated assumptions for the CGS maintenance 
schedule, and revisions to BPA's hydro efficiency improvement 
estimates.
2. Supplemental 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 hydro generation; recovery of fish and 
wildlife costs 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.
    For FY 2009, BPA is forecasting that most power-related costs will 
remain at the same levels as in the WP-07 Final Proposal, with the 
exception of the costs associated with the REP. A limited number of 
additional changes is proposed for the Supplemental Proposal. Forecasts 
of operating costs for the CGS show an increase as do the costs related 
to system augmentation. Depreciation, amortization, Federal interest 
and non-Federal debt service will be updated. The proposed changes are 
presented in Table 2.

  Table 2.--Differences in Major Cost Categories Between the WP-07 Final
Proposal and the WP-07 Supplemental Proposal FY 2009 (Excluding REP Cost
                                Changes)
                          [Millions of dollars]
------------------------------------------------------------------------
                                                        Changes from WP-
                     Cost category                          07 final
                                                            proposal
------------------------------------------------------------------------
Operating Generation:
    CGS...............................................                31
    Long-term Projects................................                 6
Contracted Power Purchases:
    DSI Monetized Power Sale..........................               (4)
    Other Power Purchases (Short-term)................                11
Augmentation Power Purchases..........................                17
Renewable Generation..................................                11
Energy Efficiency.....................................                 9
Transmission Acquisition/Ancillary Services...........               (5)
EN Debt Service.......................................                 1
Depreciation..........................................               (7)
Amortization..........................................               (8)
Net Federal Interest..................................              (27)
Minimum Required Net Revenues.........................              (35)
Planned Net Revenues for Risk.........................              (11)
Total Change from WP-07 Final Proposal................              (10)
------------------------------------------------------------------------

    BPA also expects changes to the costs of its fish and wildlife 
commitments, particularly from the final FCRPS Biological Opinion, now 
expected on March 18, 2008. For reasons of efficiency and to ensure the 
most up-to-date information, BPA prefers to estimate those changes when 
the Biological Opinion is issued. If the Opinion is delayed, BPA will 
forecast those costs using the best available information. As noted 
above, BPA does not establish program levels in rate cases. BPA will 
conduct a review of changes to the power-related costs from the WP-07 
Final Proposal in a forum external to this proceeding. The results of 
that review will be incorporated into the final studies of this WP-07 
Supplemental Proceeding.
3. Supplemental Market Price Forecast Study
    The Market Price Forecast Study estimates the variable hourly cost 
of the 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. For the WP-07 Supplemental 
Proposal, BPA does not propose to change the price forecast from the 
WP-07 Final Proposal.
4. Supplemental Risk Analysis Study
    The Risk Analysis Study focuses upon two types of risks and their 
impacts on BPA's revenues and expenses. The first type 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 and market prices on net 
revenues. The second type of risks comprises non-operating risks--all 
the risks included in the rate case risk modeling other than operating 
risks. This type of non-operating risks also includes uncertainty in 
achieving cost

[[Page 7550]]

reductions identified in the Power Function Review.
    BPA subsequently evaluates the impact that different risk 
mitigation measures have on reducing net revenue risk by calculating 
the TPP. The TPP is a measure of the probability that BPA will make 
each Treasury payment on time and in full. If the TPP is below BPA's 
one-year 97.5 percent standard, the combination of risk mitigation 
tools (e.g., Cost Recovery Adjustment Clause, NFB Adjustment, Emergency 
NFB Surcharge, Dividend Distribution Clause) is modified to meet the 
TPP standard.
    BPA is proposing no changes in the form or methodology of the risk 
analysis. The Supplemental Proposal risk analysis will be updated for 
changes to input data that account for changes in BPA's loads, 
resources, costs, and financial position.
5. Supplemental Wholesale Power Rate Development Study
    The Wholesale Power Rate Development Study (WPRDS) is the primary 
source for details concerning the development of BPA's power rates. It 
reflects the results of all of the other studies and calculates the 
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-function revenues and expenses; the development of diurnal energy 
rates; the development of rates for demand, load variance, unauthorized 
increase usage, and excess load factoring; and other rate provisions 
(e.g., the Low Density Discount, Conservation Rate Credit, and 
irrigation rate mitigation). The results of the WPRDS are reflected in 
the wholesale power rate schedules.
    Because of the Ninth Circuit's decisions on the allocation of the 
costs of the REP Settlement Agreements, most of the changes in the 
Supplemental Proposal are focused on the WPRDS. With the exception of 
certain auxiliary rate provisions, the WPRDS will be reproduced to 
document fully the development of BPA's power rates for the WP-07 
Supplemental Proposal.
6. Supplemental Section 7(b)(2) Rate Test Study
    The 7(b)(2) rate test is explained below in Part V. The Section 
7(b)(2) Rate Test Study describes the application and results of the 
Section 7(b)(2) Legal Interpretation (Legal Interpretation) and Section 
7(b)(2) Implementation Methodology (Implementation Methodology). BPA is 
proposing revisions to the Legal Interpretation and Implementation 
Methodology in the WP-07 Supplemental Proceeding. See Part V below.
    The 7(b)(2) rate test triggers in this proposal, causing costs to 
be reallocated in the test period. The PF Preference rate applied to 
the general requirements of the 7(b)(2) Customers has been reduced by 
the 7(b)(3) amount. Other rates, the PF Exchange rate and the NR and IP 
rates, have been increased by an allocation of the 7(b)(3) amount.
    Because of the proposed changes to the Legal Interpretation and 
Implementation Methodology, the Section 7(b)(2) Rate Test Study is 
being fully reproduced to document the changes to the rate test and its 
inputs and assumptions.
7. Lookback Study for FY 2002-2008
    The Lookback Study for FY 2002-2008 quantifies the amounts of REP 
settlement costs improperly included in FY 2002-2008 power rates 
(Lookback Amounts) and describes how these amounts will be recovered 
over time from IOUs and returned to preference customers. These are not 
simple calculations for each year of the lookback period because of the 
need to account for Load Reduction Agreements and existing deemer 
balances. See Part VI.D. The differences are referred to as Lookback 
Amounts for FY 2002-2008. The calculation of Lookback Amounts is 
described and documented in the Lookback Study.

Part V--Section 7(b)(2) Legal Interpretation and Implementation 
Methodology

A. Background

    As explained above, section 7(b)(2) of the Northwest Power Act 
directs BPA to conduct a rate test to assure that the wholesale power 
rates for 7(b)(2) customers are no higher than the costs of power would 
be to those customers for the same time period if specified assumptions 
are made. The rate test is conducted in conformance with the Section 
7(b)(2) Legal Interpretation and Section 7(b)(2) Implementation 
Methodology.
    Issues requiring interpretation of Section 7(b)(2) of the Northwest 
Power Act were initially resolved in the Legal Interpretation of 
Section 7(b)(2) of the Pacific Northwest Electric Power Planning and 
Conservation Act. 49 FR 23,998 (June 8, 1984). The Legal Interpretation 
was developed in a public comment process.
    The methodology to implement section 7(b)(2) was developed in a 
section 7(i) proceeding that preceded BPA's 1985 rate case. The 7(i) 
process culminated in the Section 7(b)(2) Implementation Methodology 
Record of Decision (b-2-84-F-02). The 7(i) process conducted to develop 
the Implementation Methodology for section 7(b)(2) was designated as 
the first phase of BPA's 1985 rate filing. The Implementation 
Methodology prescribes in detail how the 7(b)(2) rate test is to be 
conducted. The Implementation Methodology and its ROD address the major 
issues involving the implementation of section 7(b)(2), including 
reserve benefits, financing benefits, natural consequences, and the 
rate test trigger.
    BPA is proposing revisions to the Implementation Methodology and 
the Legal Interpretation in the WP-07 Supplemental Proposal. Proposed 
changes to the Implementation Methodology will be explained in BPA's 
Supplemental Proposal testimony. Proposed changes to the Legal 
Interpretation are contained in the Legal Interpretation attached to 
this Notice. Legal arguments concerning the Legal Interpretation will 
be addressed by BPA in the WP-07 Supplemental Proposal Draft and Final 
Records of Decision. BPA expects parties to have the opportunity to 
file legal briefs or memoranda to accompany and support their rate test 
testimonies in order that their legal arguments can be reviewed by BPA 
prior to receiving the parties' initial briefs.
    In preparing for the WP-07 Supplemental Proceeding, BPA and 
interested parties explored various issues regarding the Legal 
Interpretation and Implementation Methodology through several 
workshops. In order to bring greater clarity and certainty to the 
conduct of the rate test, BPA is proposing a number of modifications to 
the Legal Interpretation and Implementation Methodology. The major 
modifications are listed below.

A. Treatment of Preference Customer Resources Used To Serve 
Requirements Loads

    The current Legal Interpretation and Implementation Methodology 
provide that preference customers' resources dedicated to serving their 
own firm loads under section 5(b) of the Northwest Power Act are not 
available to BPA in the 7(b)(2)(D) resource stack to serve 7(b)(2) 
Customer load. BPA proposes to clarify its interpretation of section 
7(b)(2)(D) to provide that preference customer resources that are used 
to serve any utility's section 5(b) load are not available in the 
7(b)(2) Case resource stack.

[[Page 7551]]

B. Treatment of BPA-Acquired Conservation

    The current Implementation Methodology provides that BPA-acquired 
conservation will be included in the section 7(b)(2)(D) resource stack 
and that 7(b)(2) Customer loads will be adjusted to remove the effects 
of the conservation. The Implementation Methodology made no provision 
for conservation that is no longer effective in reducing loads. BPA is 
proposing to revise the Methodology to remove past conservation that is 
no longer effective.

C. Identification and Use of Natural Consequences

    The current Legal Interpretation and Implementation Methodology 
provide that three natural consequences will be reflected in the rate 
test: demand elasticities amount of surplus firm power available, and 
size of nonfirm energy markets. The surplus and nonfirm consequences 
are the results of reasonable mathematical computations stemming from 
differing assumptions between the two rate test cases. Demand 
elasticities are not necessarily the result of reasonable mathematical 
computations. BPA is proposing to remove demand elasticities from the 
natural consequences listed in the Implementation Methodology.

D. Treatment of Specified 7(g) Costs

    The current Legal Interpretation provides that specified 7(g) costs 
will be removed from the Program Case, but not from the 7(b)(2) Case. 
However, this language does not conform to BPA's past practices in 
conducting the rate test. BPA proposes to change this language to 
specify that the 7(g) cost exclusion applies to both cases prior to the 
incorporation of the assumptions specified in section 7(b)(2).

E. Identification and Treatment of Resources in the 7(b)(2)(D) Resource 
Stack

    The current Implementation Methodology provides that certain 
resources taken from the resource stack would be added in discrete 
lumps. BPA proposes to remove the effects of the discrete lumps on the 
rate test by selling excess resources at the cost of the excess 
resources.

F. Treatment of REP Settlement Costs in the Rate Test

    Neither the current Legal Interpretation nor Implementation 
Methodology addresses the treatment of REP settlement costs. BPA 
proposes to add language that clarifies that REP settlement costs are 
costs that should be excluded from the 7(b)(2) Case pursuant to section 
7(b)(2)(C).

Part VI. Summary of Proposal to Respond To the Court's Opinions 
Regarding BPA's 2000 REP Settlement Agreements, WP-02 Rates, and by 
Extension, WP-07 Rates

A. Introduction

    Although BPA is proposing an approach to address the Court's 
decisions, as described in greater detail below, BPA recognizes there 
are several ways to approach this matter. For example, one element of 
BPA's proposal for calculating the Lookback Amounts limits the amounts 
retained by IOUs to the lesser of an IOU's REP settlement benefits or 
the amount the IOU would have received under the REP. The proposed FY 
2009 REP benefits to the IOUs would be significantly higher if, instead 
of proposing to limit the amounts the IOUs were entitled to in FY 2007 
and FY 2008 to the amounts they would have received under the REP 
settlements, BPA had instead proposed that the IOUs were entitled to 
the recalculated REP benefits for those years. BPA encourages parties 
to propose alternative approaches to this or other elements of BPA's 
proposal to address the Court's decisions for the agency to consider.
    This section describes, in general, BPA's proposal for responding 
to recent decisions of the Ninth Circuit noted previously. In PGE, the 
Court held that BPA's REP Settlement Agreements were inconsistent with 
the Northwest Power Act. In a companion opinion, Golden NW, the Court 
held that BPA improperly allocated REP Settlement Agreement costs to 
BPA's preference customers in its WP-02 power rates and remanded the 
rates to BPA. Although the Ninth Circuit in Golden NW also found 
infirmities in BPA's estimates of fish and wildlife costs for the WP-02 
rates, the rates nevertheless recovered all of the costs of BPA's fish 
and wildlife commitments for FY 2002-2006. BPA acknowledges that 
entities may continue to assert that BPA had not committed enough 
funding to fish and wildlife activities during this period, but as the 
Court notes, that is not a matter determined in a rate proceeding. As a 
result, BPA is not proposing any changes in the WP-07 Supplemental 
Proceeding to its fish and wildlife commitments for FY 2002-2006. As 
discussed elsewhere, BPA is proposing a specific process, external to 
the rate case, to ensure its forecasts for fish and wildlife costs are 
as up-to-date as possible for purposes of establishing rates for FY 
2009.
    In a subsequent opinion, Snohomish, the Court remanded amendments 
to the REP Settlement Agreements and a provision regarding a Reduction 
of Risk discount the Court found was based on such Agreements. Three 
memorandum opinions, released at the same time as Snohomish, dismissed 
challenges to BPA's 2001 LRAs with PacifiCorp and Puget Sound Energy.
    BPA is proposing to respond to the Court's decisions by: (1) 
Determining Lookback Amounts, which are the costs associated with the 
REP settlements that were improperly included in FY 2002-2008 rates and 
therefore should be recovered from IOUs and returned to preference 
customers; (2) recovering Lookback Amounts over time by reducing future 
REP benefits due to IOUs; and (3) concomitantly reducing preference 
customers' rates to reflect the lower REP benefit payments. Because BPA 
allocated REP settlement costs in its WP-07 power rates in the same 
manner as BPA allocated such costs in its WP-02 rates, BPA has reopened 
its WP-07 power rate proceeding to revise its power rates for FY 2009.
1. REP Settlement Agreement Background
    In 1998, BPA's Subscription Strategy proposed offering BPA's 
regional IOU customers the option of signing RPSAs to participate in a 
traditional REP or signing REP Settlement Agreements for FY 2002-2011. 
The REP Settlement Agreements were to provide power and monetary 
benefits to the IOUs' residential and small farm consumers in order to 
resolve disputes arising under BPA's implementation of the REP. Prior 
to the development of the RPSAs and REP Settlement Agreements in 2000, 
the IOUs submitted letters to BPA stating their intent to participate 
in the REP. Through negotiations and a public notice and comment 
administrative proceeding, BPA developed prototype RPSAs and REP 
Settlement Agreements. BPA issued respective records of decision on 
October 4, 2000, for the RPSAs and REP Settlement Agreements. BPA then 
offered the RPSAs and REP Settlement Agreements to the IOUs.
    All of the IOUs elected to execute the REP Settlement Agreements. 
For FY 2002-2006, the Settlement Agreements included 900 aMW of 
financial benefits and 1000 aMW of power at a cost-based rate, 
consistent with the Subscription Strategy. Subsequent to the execution 
of the REP Settlement Agreements, BPA entered into LRAs with PacifiCorp 
and Puget Sound Energy whereby BPA bought back the power component of 
the utilities' REP Settlement Agreements as part of BPA's strategy to 
limit the

[[Page 7552]]

financial impacts of the West Coast energy crisis. Through amendments 
to the REP Settlement Agreements signed in 2004, benefits for FY 2007-
2011 were set at 2200 aMW of financial benefits.
    BPA conducted the WP-02 rate proceeding to establish power rates 
for FY 2002-2006. BPA allocated the costs of the REP settlements to the 
PF Preference rate. A cost recovery adjustment clause captured the 
costs of the LRAs with PacifiCorp and Puget Sound Energy. A number of 
parties subsequently filed separate challenges to BPA's REP Settlement 
Agreements and BPA's WP-02 power rates in the Ninth Circuit. On May 3, 
2007, the Court issued the PGE and Golden NW opinions noted above.
2. Overview of Proposal
a. FY 2002-2006 Rate Period
    Together with the Court's decision in PGE, BPA interprets the 
Court's remand in Golden NW as requiring BPA to remove the cost of the 
REP settlements from the PF Preference rate. In removing these costs, 
however, the Court's decisions do not require BPA to ignore the fact 
that, in the absence of the REP Settlement Agreements, the IOUs would 
have received benefits during the FY 2002-2006 rate period under the 
traditional REP. As noted previously, prior to the development of the 
RPSAs and REP Settlement Agreements, the IOUs submitted letters to BPA 
stating their intent to participate in the REP. Consequently, absent 
BPA's offer of REP Settlement Agreements, BPA assumes that all IOUs 
except Idaho Power would have participated in the REP, the costs of 
which would have been reflected in setting BPA's power rates.
    In response to the Court's decisions, BPA proposes to determine the 
amount of benefits provided to each IOU under the REP settlements. BPA 
also proposes to calculate the amount of REP benefits each IOU would 
have received from BPA during the FY 2002-2006 rate period in the 
absence of the REP Settlement Agreements. In order to calculate such 
REP benefits, BPA proposes to remove the REP settlement costs from 
BPA's WP-02 power rates and replace them with costs associated with a 
traditional REP. This change will establish the PF Exchange rate that 
would have been used to implement the REP during the rate period. This 
approach requires BPA to review and decide a number of issues in the 
WP-02 Final Proposal that were undecided or rendered moot by the 
presence of the REP Settlement Agreements. Failure to allow parties to 
address these issues on the merits would be inequitable. In addition, 
BPA must estimate the IOUs' respective ASCs for the rate period, which 
are used in conjunction with the PF Exchange rate and the IOUs' 
residential and small farm loads to determine each IOU's respective REP 
benefits. BPA proposes to compare each IOU's REP benefits with the 
actual payments made to that IOU under the REP settlements.
    Based on the resulting differences between these two amounts, BPA 
will determine the Lookback Amounts to be recovered from each IOU and 
returned to preference customers via lower rates, as described in 
Section D below. Section E describes BPA's proposal for how the 
Lookback Amounts will be recovered over time. This approach responds to 
the Court's remand of the WP-02 rates by effectively reimbursing, 
through lower rates over time, preference customers for costs that 
should not have been included in the WP-02 preference rates during the 
FY 2002-2006 rate period.
    In constructing this approach, BPA is not proposing to recalculate 
any rates other than the PF Exchange rate for the FY 2002-2006 period. 
BPA is proposing to recalculate only the PF Exchange rate for this 
period because this is the rate necessary to calculate the REP benefits 
the IOUs would have received. Consequently, this approach does not 
require BPA to recalculate any other rates for this period.
    The determination of utility-specific Lookback Amounts is complex. 
In addition to the REP Settlement Agreements, BPA must also account for 
the Court's decision in Snohomish, which remanded to BPA the 2004 
amendments to the REP Settlement Agreements and the Reduction of Risk 
discount that the Court found was based on those Agreements. BPA also 
must consider three memorandum opinions that dismissed challenges to 
the LRAs. In addition, the operation of the REP would have accounted 
for existing deemer balances, that is, amounts accrued by exchanging 
utilities and owed to BPA that must be eliminated before REP benefits 
can be paid.
b. FY 2007-2008
    BPA is proposing to adopt a similar approach to that used for FY 
2002-2006 to address BPA's WP-07 rates for FY 2007 and FY 2008. The 
rates charged in these years, like the WP-02 rates, included REP 
settlement costs. Although the Ninth Circuit has not ruled on the 
validity of BPA's WP-07 rates, the Court's holdings in PGE, Golden NW, 
and Snohomish implicate the validity of the rates BPA established for 
these years. Rather than wait for the Court to remand these rates to 
BPA in a subsequent case, BPA proposes to remedy these problems now. 
BPA's specific proposal is to adopt a remedy similar to that described 
above; that is, BPA proposes to remove the REP settlement costs from 
power rates and replace such costs with the costs of providing benefits 
to IOUs under the REP in FY 2007 and FY 2008. BPA will then compare the 
benefits under the REP to the payments each IOU received, or would have 
received, under the REP settlements for these years, determine the 
appropriate difference, and propose how this difference should be 
returned to preference customers.
    Once again, in constructing this approach, BPA is not proposing to 
recalculate any rates other than the PF Exchange rate for the FY 2007-
2008 period. BPA is proposing to recalculate only the PF Exchange rate 
for this period because this is the rate necessary to calculate the REP 
benefits the IOUs would have received. Consequently, this approach does 
not require BPA to recalculate any other rates for this period.

B. REP Settlement Agreement Benefits Paid During FY 2002-2008

    The first step in responding to the PGE, Golden NW, and Snohomish 
decisions is to calculate the amount of benefits paid to each IOU under 
the REP settlements during FY 2002-2008. These benefits include, for 
example, the Conservation and Renewables Discount (C&RD) and 
Conservation Rate Credit (CRC), and a power sale to PGE. BPA reviewed 
its accounting records and determined the amounts paid to each IOU as 
well as the amounts that would have been paid had payments to the IOUs 
not been suspended. These amounts are detailed in the Lookback Study. 
This determination also identifies the source of the payments, i.e., 
the portion of the payments made under the REP Settlement Agreements, 
LRAs, etc. The total benefits paid were approximately $1.96 billion for 
FY 2002-2006 and $168 million for FY 2007. Benefits that would have 
been paid in the latter half of FY 2007 and in FY 2008 after the 
suspension of payments subsequent to the Court's rulings in May 2007 
would have totaled $505 million.

C. Proposal for Determining REP Benefits for FY 2002-2008

    As previously described, BPA proposes to determine the amount of 
REP benefits that would have been paid to each IOU in the absence of 
the REP settlements. These costs would have been included in the WP-02 
and WP-

[[Page 7553]]

07 power rates for FY 2002-2008 instead of the costs of the REP 
settlements. In order to make this determination, BPA must evaluate two 
key elements of the REP: (1) The WP-02 and WP-07 PF Exchange rates and 
(2) the IOUs' respective ASCs during FY 2002-2008. BPA's proposals for 
these two rate periods are described below.
1. BPA's Proposal for Calculating REP Benefits for FY 2002-2006
a. The PF Exchange Rate for FY 2002-2006
    BPA proposes to recalculate the PF Exchange rate for FY 2002-2006 
assuming that all IOUs except Idaho Power would have participated in 
the REP in the absence of the REP Settlement Agreements. To develop 
this rate, BPA proposes to return to its WP-02 Supplemental Rate 
Proposal and revise its base rates with altered input assumptions 
consistent with information available at that time and with 
reconsideration of section 7(b)(2) rate test issues that were 
previously undecided or rendered moot. The resulting PF Exchange rate 
is the rate that would have been used by BPA to calculate benefits 
under the traditional REP during FY 2002-2006.
b. IOU Average System Costs (ASC) for FY 2002-2006
    Although BPA's PF Exchange rate is a critical element of the REP, 
actual REP benefits paid to each IOU are not determined in BPA's rate 
cases. BPA's rate cases only forecast the expected levels of REP 
benefits, which comprise the expected costs that will be included in 
rates for the rate period. The actual level of REP benefits a utility 
receives is determined during the rate period as the REP is implemented 
and is based on a comparison of the PF Exchange rate and a utility's 
filed ASC, multiplied by the utility's residential and small farm 
loads. To calculate REP payments for FY 2002-2006, BPA would normally 
use filed ASCs. The IOUs, however, did not make ASC filings with BPA 
during the WP-02 period because the REP Settlement Agreements did not 
require such filings. Consequently, to calculate the REP benefits that 
would have been paid during the WP-02 rate period, BPA proposes to 
determine annual ASC for each IOU during the rate period.
    To determine these annual ASCs, BPA proposes to look to FERC Form 1 
data filed by each IOU with FERC for FY 2002-2006. From these 
historical data, BPA proposes to calculate an annual ASC for each 
utility by following the functionalization rules as set forth in the 
1984 ASC Methodology. Relying on the 1984 Methodology is a conservative 
assumption given that BPA would likely have re-opened the ASC 
Methodology had the IOUs not executed the REP Settlement Agreements. 
The imputed ASCs, in conjunction with the reconstituted PF Exchange 
rate and actual exchange loads, are used to calculate utility-specific 
amounts of REP benefits that would have been paid during the WP-02 rate 
period.
2. BPA's Proposal for Calculating REP Benefits for FY 2007-2008
    Similar to the FY 2002-2006 period, BPA's PF Preference rate for FY 
2007-2008 included REP settlement costs. To remedy this infirmity, BPA 
proposes to use a similar construct as described previously to 
determine the REP benefits the IOUs would have received for FY 2007-
2008; that is, BPA proposes to recalculate the PF Exchange rate for FY 
2007-2008 assuming an REP, and then impute annual ASCs for each IOU 
customer for FY 2007-2008 to determine the REP benefits that would have 
been paid during this period.
a. BPA's PF Exchange Rate for FY 2007-2008
    BPA is proposing to conduct the section 7(b)(2) rate test in this 
Supplemental Proposal in a manner consistent with the rate test used in 
the reformulation of the PF Exchange rate for FY 2002-2006. The results 
of the rate test, in conjunction with all other assumptions used in 
setting rates during the WP-07 rate proceeding, will be used in 
recalculating the PF Exchange rate for FY 2007-2008.
b. IOU Average System Costs for FY 2007-2008
    Consistent with BPA's proposal to determine the REP benefits IOUs 
would have received in FY 2002-2006, BPA proposes to determine IOU ASCs 
for FY 2007-2008 relying on BPA's 1984 ASC Methodology. BPA is 
proposing to use FERC Form 1 data from 2006 and a trend analysis to 
project ASCs for FY 2007-2008. BPA believes this approach approximates 
what the actual ASCs would be for FY 2007-2008. As with the FY 2002-
2006 rate period, these imputed ASCs, in conjunction with the 
reconstituted PF Exchange rate and actual and forecast exchange loads, 
are used to calculate a utility-specific amount of REP benefits that 
would have been paid for FY 2007-2008.

D. Determination of Lookback Amounts

    Determining the Lookback Amounts is not a simple proposition. A 
number of factors affect the amount of settlement benefits received by 
the IOUs and, more importantly, whether the IOUs are entitled to retain 
such benefits in the absence of the REP Settlement Agreements. For 
example, although the Court found the REP Settlement Agreements 
unlawful, the Court remanded the 2004 amendments to BPA. The Court also 
remanded the Reduction of Risk discount, also called the ``litigation 
penalty'' by some preference customers, to BPA. In addition, the Court 
issued three memorandum opinions dismissing challenges to the LRAs.
    As a result, BPA cannot simply subtract the REP benefits otherwise 
due the IOUs from the benefits paid under the REP Settlement 
Agreements, 2004 amendments, and LRAs to calculate the amount to be 
recovered from the IOUs. In addition, implementation of the traditional 
REP would have meant that the deemer balances for certain IOUs would 
have to be considered in determining the REP benefits that would have 
been paid absent the REP Settlement Agreements. This section describes 
BPA's proposal for determining the Lookback Amounts.
1. Treatment of Deemer Amounts
    RPSAs are the contracts that implement the REP. BPA's 1981 RPSA 
established what was called a ``deemer account.'' In the event that an 
exchanging utility's ASC fell below the PF Exchange rate, rather than 
pay BPA, the utility would accumulate a balance in a deemer account 
based on the difference between its ASC and the PF Exchange rate 
multiplied by the utility's eligible exchange load. The 1981 RPSA 
provided that any obligations incurred under that RPSA would continue 
until satisfied, even if the RPSA expired. The RPSA also provided that 
the utility must repay its deemer balance before receiving any positive 
REP benefits. Idaho Power, Northwestern Energy, and Avista Corporation 
(Avista) all have extant deemer balances.
    BPA proposes that its determination of the amount of REP benefits 
that would have been provided to the IOUs should account for utilities' 
deemer balances. Therefore, BPA proposes that any REP benefits 
calculated for an IOU with a deemer balance will first be used to 
extinguish its deemer balance before being compared to the REP 
settlement payments to establish a Lookback Amount for that IOU. Under 
BPA's proposal, Northwestern Energy and Avista exhaust their deemer 
balances in FY 2005 and FY 2007, respectively. Under BPA's 
determination of REP benefits, absent the REP settlements, Idaho Power 
does not qualify for REP benefits during the FY 2002-2008

[[Page 7554]]

period so there are no reductions to its deemer balance and its 
Lookback Amount is equal to the REP settlement benefits it received.
2. Cap on REP Benefits Credited Against Settlement Payments
    BPA proposes a second condition on the calculation of the amount to 
be recovered from each IOU for FY 2002-2008. In calculating this 
Lookback Amount for each utility, BPA proposes that REP benefits that 
exceed the REP settlement benefits shall not be credited to the 
Lookback Amount. Said another way, an IOU cannot receive more benefits 
under the REP than it received, or would have received, under the REP 
settlements. This condition is applied each year for FY 2002-2008.
3. Treatment of Reduction of Risk Discount and Load Reduction 
Agreements
    As previously mentioned, the LRAs with PacifiCorp and Puget Sound 
Energy are contracts wherein BPA bought back power from these two IOUs 
to limit exposure to the high and volatile market prices of the West 
Coast energy crisis. No party filed a challenge to the LRAs within the 
Northwest Power Act's 90-day statute of limitations. Two petitions for 
review were filed with the Ninth Circuit challenging BPA's unsuccessful 
attempts to develop a broad settlement of all outstanding litigation 
against BPA. The Court noted that the petitions were challenging 
actions that never occurred and dismissed the petitions for lack of 
jurisdiction. Another petition was filed that challenged the LRAs, but 
it was filed two and one half years after expiration of the 90-day 
statute of limitations. The Court noted that the only issue raised in 
the petition concerned the Reduction of Risk Discount provision of the 
LRAs. Having dealt with the Reduction of Risk Discount in Snohomish, 
the Court dismissed the petition challenging the LRAs as moot.
    In light of the Court's actions, BPA proposes to treat the LRA 
payments to PacifiCorp and Puget Sound Energy in the following manner. 
First, BPA will assume that the total REP settlement benefits paid to 
these two IOUs include the REP Settlement Agreement benefits, the LRA 
payments, and the C&RD/CRC benefits. BPA proposes that PacifiCorp and 
Puget Sound Energy (Puget) keep the lesser of the REP settlement 
benefits or the REP benefits the utilities would have received in the 
absence of the REP Settlement Agreements, but not less than the amount 
of the LRA payments. This proposal effectively treats the LRA payments 
to PacificCorp and Puget Sound Energy as ``protected'' payments that 
are not subject to recovery as part of their Lookback Amounts.
    In Snohomish, the Court held that the Reduction of Risk Discount 
was founded on the original REP Settlement Agreements and remanded the 
issue to BPA. Therefore, BPA proposes to treat the Reduction of Risk 
discount payments as suffering the same fate as the REP Settlement 
Agreement payments. Any amount paid to PacifiCorp and Puget for the 
Reduction of Risk Discount will be included in their REP Settlement 
Agreement benefits and will therefore be subject to recovery through 
the lookback process.
4. Results
    The application of the previous three sections results in annual 
Lookback Amounts for each IOU. BPA is proposing to escalate the annual 
Lookback Amounts for FY 2002-2006 to 2007 dollars to adjust for the 
effects of inflation. The resulting cumulative Lookback Amounts for 
each IOU, in 2007 dollars for FY 2002-2007 are provided in Table 3.

             Table 3.--Proposed Cumulative Lookback Amounts
                       [Millions of 2007 dollars]
------------------------------------------------------------------------
                                                               Proposed
                        Utility name                           lookback
                                                               amounts
------------------------------------------------------------------------
Avista.....................................................        $62.1
Idaho Power................................................         96.6
Northwestern Energy........................................          7.7
PacifiCorp.................................................        239.4
Portland General Electric..................................         64.1
Puget Sound Energy.........................................        150.5
                                                            ------------
  Total....................................................        620.4
------------------------------------------------------------------------

    The Lookback Amounts in Table 3 assume that BPA offers, and the 
IOUs sign, the Interim Agreements. In the absence of Interim 
Agreements, no REP benefits will be paid in FY 2008, creating an amount 
of REP benefits otherwise due to the IOUs for that year, which will be 
used to reduce accumulated Lookback Amounts by $189 million.

E. Application of the Results of the Lookback Analysis

    Because the IOUs have already passed REP Settlement and LRA 
benefits on to their residential and small farm customers for FY 2002-
2006 and part of FY 2007, BPA proposes to recover Lookback Amounts from 
the IOUs by reducing future REP benefits determined to be otherwise due 
them. The amount of the reduction in benefits due will be determined by 
the Administrator in each rate case. The reduced REP payments to IOUs 
will result in lower PF Preference rates for FY 2009 and beyond until 
Lookback Amounts are fully amortized. These lower PF rates constitute a 
portion of the compensation to preference customers for the amounts 
they overpaid in FY 2002-2008 power rates.
    An additional portion of the compensation may occur as provided in 
Standstill Payment Agreements, if offered, for those preference 
customers that sign such agreements or via customer-specific credits on 
FY 2009 power bills if such agreements are not signed.
    The reduction in the amounts of REP benefits that would have 
otherwise been due will be credited against each IOU's Lookback Amount. 
This practice will continue as needed each rate period until each IOU 
has amortized its total Lookback Amount, including interest. BPA 
proposes that unamortized Lookback balances will accrue interest. The 
proposed reduction in REP benefits for FY 2009 is an amount that is 
expected to amortize each IOU's Lookback Amount plus accrued interest 
within 20 years, with the exception of Idaho Power. The assumptions and 
proposal with regard to Idaho Power are described in more detail below.
    BPA expects that all IOUs except Idaho Power will amortize their 
respective Lookback Amounts, including interest, within 20 years based 
on a set of simple assumptions regarding the future. These assumptions 
are:
    1. The FY 2009 individual IOU REP benefits paid continue in future 
rate periods until such time each IOU fully amortizes its Lookback 
Amount;
    2. Each IOU's FY 2009 REP benefits amount (before reductions 
applied for Lookback Amounts) increases by 2.5 percent per year (as a 
consequence of growth in eligible exchange loads and/or increases in 
IOU ASCs and/or changes in PF Exchange rates, none of which is 
specifically forecasted or otherwise modeled); and
    3. Interest accrues on unamortized Lookback balances at the rate of 
5.03 percent per year.
    BPA proposes to proportionally reduce each IOU's benefits due for 
FY 2009 such that the aggregate benefit paid, before consideration of 
any deemer obligations, for all IOUs is 210 million. This amount 
represents a balance between ensuring that regional residential and 
small farm consumers receive benefits from the Residential Exchange 
Program while returning to preference customers the overpayments

[[Page 7555]]

to IOUs that occurred under the REP settlements. This aggregate benefit 
is in the middle of the $200 million to $220 million range contained in 
the Recommendations of Representatives of the Investor-Owned and 
Certain Consumer-Owned Utilities Regarding the Residential Exchange 
Benefits for Customers Served by the Pacific Northwest Investor-Owned 
Utilities dated November 7, 2007. BPA understands that this document 
enjoys broad, albeit not universal, customer support. BPA views such 
support as a measure of the reasonableness of its approach to 
recovering the Lookback Amounts over time.
    Table 4 shows FY 2009 REP benefits due and REP benefits paid before 
consideration of any deemer obligations.

   Table 4.--FY 2009 REP Benefits Due and Benefits Paid Before Deemer
                               Adjustment
                          [Millions of dollars]
------------------------------------------------------------------------
                                                FY 2009 REP  FY 2009 REP
                 Utility name                     benefits     benefits
                                                    due          paid
------------------------------------------------------------------------
Avista........................................        $27.8        $23.3
Idaho Power...................................          9.2          7.7
Northwestern Energy...........................          7.6          6.4
PacifiCorp....................................         50.8         42.7
Portland General Electric.....................         54.6         45.8
Puget Sound Energy............................        100.2         84.1
                                               -------------------------
  Total.......................................        250.2        210.0
------------------------------------------------------------------------

    BPA maintains the position that Idaho Power has a substantial 
deemer balance at the end of FY 2008. BPA is proposing to apply the 
same treatment to Idaho Power's deemer balance for FY 2009 that was 
applied when determining the Lookback Amounts for FY 2002-2008. 
Specifically, REP benefits will first be applied toward deemer 
balances. Only when Idaho Power's deemer balance is extinguished would 
REP benefits be available to apply against Lookback Amounts and to 
provide positive REP benefits to Idaho Power. Based on Idaho Power's 
current deemer balance and reasonable expectations of future REP 
benefits, Idaho Power is not expected to amortize its Lookback Amount 
by 2028. BPA acknowledges that Idaho Power disputes its current deemer 
balance and has requested to explore with BPA the possibility of 
settling this dispute.

F. Summary

    In summary, BPA's proposal responds to the Court's rulings in 
several ways to remedy the improper allocation of REP settlement costs 
to the PF Preference rate. First, the WP-07 Supplemental Proposal 
results in an average PF Preference rate of $26.2/MWh--about a four 
percent (4%) reduction from current rates. This proposed reduction 
results from several changes or revisions to the WP-07 Final Studies. 
The most significant change is a reduction in the costs of the REP for 
FY 2009 from about $336 million to $202 million, which includes $39 
million of the Lookback Amount.
    Second, BPA is determining the magnitude of the Lookback Amounts 
for FY 2002-2007 that need to be recovered from the region's IOUs and 
returned to public utilities. BPA proposes to recover this total, 
approximately $620 million, out of future REP benefits, starting with 
the $39 million for FY 2009 noted above. BPA proposes that the amount 
of future Lookback Amounts recovered, and by extension the associated 
PF rate reduction, will be decided in each subsequent rate case.
    Lastly, BPA is proposing to provide public utilities with either a 
one-time payment or a credit on their power bills for the difference 
between the REP settlements costs in power rates for FY 2007-2008, and 
the amount of FY 2007-2008 REP benefits the IOUs would be paid under 
BPA's proposal. If BPA offers, and preference customers sign, 
Standstill Payment Agreements, they will receive a portion of this 
credit in FY 2008 and the remainder in FY 2009. If they do not sign 
Standstill Payment Agreements, or the agreements are not offered, 
preference customers will receive the credit in FY 2009. BPA has the 
financial reserves to provide this FY 2008-2009 payment or credit of 
about $315 million because BPA has been collecting REP settlement costs 
in the PF Preference rate but has not been paying benefits to the IOUs 
since the Court's May, 2007, rulings.

Part VII--2007 Supplemental Wholesale Power Rate Schedules (FY 2009) 
and 2007 Supplemental General Rate Schedule Provisions (GRSPs) (FY 
2009)

    BPA's proposed 2007 Supplemental Wholesale Power Rate Schedules and 
GRSPs, as well as the Section 7(b)(2) Legal Interpretation and Section 
7(b)(2) Implementation Methodology, incorporated by reference as a part 
of this Notice, are available for viewing and downloading on BPA's Web 
site at http://www.bpa.gov/corporate/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 1st day of February, 2008.
Stephen J. Wright,
Administrator and Chief Executive Officer.
[FR Doc. E8-2339 Filed 2-7-08; 8:45 am]
BILLING CODE 6450-01-P