Federal Register / Vol. 73, No. 27 / Friday, February 8, 2008 / Notices 7539 

Department’s program, financial and 

procurement personnel to evaluate 

proposals and administer contracts. 

These collections are used to exercise 

management oversight and control of 

the Department’s management 

contractors operating the Department’s 

major facilities and other contractors 

furnishing goods and services; (5) 

Respondents: 7,539; (6) Estimated 

Number of Burden Hours: 896,209. 

Statutory Authority: Section 644 of 

the Department of Energy Organization 

Act, 42 U.S.C. 7254, and section 205(c) 

of the Federal Property and 

Administrative Services Act, 40 U.S.C. 

486(c). 

Issued in Washington, DC on February 1, 

2008. 

Edward R. Simpson, 

Director, Office of Procurement and 

Assistance Management. 

[FR Doc. E8–2341 Filed 2–7–08; 8:45 am] 

BILLING CODE 6450–01–P 

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. 

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: 

wp07rate@bpa.gov. 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 email to: krcasad@bpa.gov. 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 (tollfree) 

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 


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7540 Federal Register / Vol. 73, No. 27 / Friday, February 8, 2008 / Notices 

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 


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Federal Register / Vol. 73, No. 27 / Friday, February 8, 2008 / Notices 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 § 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. 


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7542 Federal Register / Vol. 73, No. 27 / Friday, February 8, 2008 / Notices 

1Such 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. 

PUBLIC FIELD HEARINGS SCHEDULE

03/18/08 ... 6 p.m. .. Spokane, Washington. 

03/20/08 ... 6 p.m. .. Portland, Oregon. 

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 post2001, 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 


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Federal Register / Vol. 73, No. 27 / Friday, February 8, 2008 / Notices 7543 

2Promoting 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). 

3Open 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). 

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. 

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. 

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 § 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 § 1010.3(f) of the BPA Hearing 


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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 

§ 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 § 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 § 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 withinhour balancing capacity for wind 

generation. Pursuant to § 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 ProposalAdministrator’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 § 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 

§ 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 

§ 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 


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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 § 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 


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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 

wp07rate@bpa.gov: 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 § 1010.1(d) 

of BPA Hearing Procedures, BPA waives 

the requirement in § 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. 


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4Accumulated Modified Net Revenue 

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 interfunction 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. 

TABLE 1.—CRAC CAP AND CRAC AND DDC ANNUAL THRESHOLDS FOR FY 2009 

[Millions of dollars] 

AMNR calculated at end 

of fiscal year 

CRAC or DDC 

applied to 

fiscal year 

CRAC or DDC 

threshold in 

AMNR 4

Approx. 

threshold as 

measured in 

power services’ reserves 

Maximum 

CRAC recovery amount 

(cap) 

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 


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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; 


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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 nonFederal 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] 

Cost category 

Changes from 

WP–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-todate 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 MidColumbia 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 


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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. 


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B. Treatment of BPA-Acquired 

Conservation 

The current Implementation 

Methodology provides that BPAacquired 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 


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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–


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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 


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7554 Federal Register / Vol. 73, No. 27 / Friday, February 8, 2008 / Notices 

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] 

Utility name 

Proposed 

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 


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Federal Register / Vol. 73, No. 27 / Friday, February 8, 2008 / Notices 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] 

Utility name 

FY 2009 

REP benefits due 

FY 2009 

REP benefits 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 

ENVIRONMENTAL PROTECTION 

AGENCY 

[ER–FRL–6695–7] 

Environmental Impacts Statements; 

Notice of Availability 

Responsible Agency: Office of Federal 

Activities, General Information (202) 

564–7167 or http://www.epa.gov/ 

compliance/nepa/ 

Weekly receipt of Environmental Impact 

Statements 

Filed 01/28/2008 through 02/01/2008 

Pursuant to 40 CFR 1506.9 

EIS No. 20080035, Draft EIS, IBR, WA, 

Yakima River Basin Water Storage 

Feasibility Study, Create Additional 

Water Storage, Benton, Yakima, 

Kittitas Counties, WA, Comment 

Period Ends: 03/31/2008, Contact: 

David Kaumheimer 509–575–5848 

Ext. 612. 

EIS No. 20080036, Final EIS, GSA, CO, 

Denver Federal Central Site Plan 

Study, Master Site Plan, 

Implementation, City of Lakewood, 

Jefferson County, CO, Wait Period 

Ends: 03/10/2008, Contact: Lisa D. 

Morpurgo 303–236–8000 Ext. 5039. 

EIS No. 20080037, Draft EIS, AFS, ID, 

Yakus Creek Project, Proposes Timber 

Harvest, Watershed Improvement, and 

Access Management Activities, 

Lochsa Ranger District, Clearwater 

National Forest, Idaho County, ID, 

Comment Period Ends: 03/24/2008, 

Contact: Craig Trulock 208–926–4274. 

EIS No. 20080038, Draft EIS, BLM, WY, 

West Antelope Coal Lease 

Application (Federal Coal Lease 

Application WYW163340), 

Implementation, Converse and 

Campbell Counties, WY, Comment 

Period Ends: 04/08/2008, Contact: 

Sarah Bucklin 307–261–7587. 

EIS No. 20080039, Final EIS, BLM, NV, 

Kane Springs Valley Groundwater 

Development Project, To Construct 

Infrastructure Required to Pump and 

Convey Groundwater Resources, 

Right-of-Way Application, Lincoln 

County Water District, Lincoln 

County, NV, Wait Period Ends: 03/10/ 

2008, Contact: Penny Wood 775–861–

6466. 

EIS No. 20080040, Draft EIS, IBR, NV, 

Folsam Lake State Recreation Area & 

Folsam Powerhouse State Historic 

Park, General Plan/Resource 

Management Plan, Implementation, El 


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